Fundamentals of Sustainable Drilling Engineering [1 ed.] 0470878177, 9780470878170

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Fundamentals of Sustainable Drilling Engineering

Scrivener Publishing 100 Cummings Center, Suite 541J Beverly, MA 01915-6106

Publishers at Scrivener Martin Scrivener ([email protected]) Phillip Carmical ([email protected])

Fundamentals of Sustainable Drilling Engineering

M. Enamul Hossain, PhD Abdulaziz Abdullah Al-Majed, PhD

Copyright © 2015 by Scrivener Publishing LLC. All rights reserved. Co-published by John Wiley & Sons, Inc. Hoboken, New Jersey, and Scrivener Publishing LLC, Salem, Massachusetts. Published simultaneously in Canada. No part of this publication may be reproduced, stored in a retrieval system, or transmitted in any form or by any means, electronic, mechanical, photocopying, recording, scanning, or otherwise, except as permitted under Section 107 or 108 of the 1976 United States Copyright Act, without either the prior written permission of the Publisher, or authorization through payment of the appropriate per-copy fee to the Copyright Clearance Center, Inc., 222 Rosewood Drive, Danvers, MA 01923, (978) 750-8400, fax (978) 750-4470, or on the web at www.copyright.com. Requests to the Publisher for permission should be addressed to the Permissions Department, John Wiley & Sons, Inc., 111 River Street, Hoboken, NJ 07030, (201) 748-6011, fax (201) 748-6008, or online at http://www.wiley.com/go/permission. Limit of Liability/Disclaimer of Warranty: While the publisher and author have used their best eforts in preparing this book, they make no representations or warranties with respect to the accuracy or completeness of the contents of this book and speciically disclaim any implied warranties of merchantability or itness for a particular purpose. No warranty may be created or extended by sales representatives or written sales materials. he advice and strategies contained herein may not be suitable for your situation. You should consult with a professional where appropriate. Neither the publisher nor author shall be liable for any loss of proit or any other commercial damages, including but not limited to special, incidental, consequential, or other damages. For general information on our other products and services or for technical support, please contact our Customer Care Department within the United States at (800) 762-2974, outside the United States at (317) 572-3993 or fax (317) 572-4002. Wiley also publishes its books in a variety of electronic formats. Some content that appears in print may not be available in electronic formats. For more information about Wiley products, visit our web site at www.wiley.com. For more information about Scrivener products please visit www.scrivenerpublishing.com. Cover design by Kris Hackerott Library of Congress Cataloging-in-Publication Data: ISBN 978-0-470-87817-0

Printed in the United States of America 10 9 8 7 6 5 4 3 2 1

Dedicated with love to the blessed soul of the irst author’s Late mother, Azizun Nesa (1951 – 1981) Late grandmother, Hazera Khatun (1922 – 1992) whose devotion and afection never ceases and whose beautiful memories are ever lasting. and dedicated to the second author’s wife and children for their understanding and support.

Contents Foreword Preface Acknowledgements Summary 1

2

xix xxi xxiii xxv

Introduction 1.1 Introduction 1.2 Introduction of Drilling Engineering 1.3 Importance of Drilling Engineering 1.4 Application of Drilling Engineering 1.5 History of Oil Discovery 1.6 An Overview of Drilling Engineering 1.6.1 Licensing, Exploration and Development 1.6.2 Role of Drilling during Field Development 1.6.3 Types of Drilling Wells 1.6.4 Sequences of Drilling Operations 1.7 Organization Chart and Manpower Requirements during Drilling Operations 1.8 Aspect of Sustainability in Drilling Operations 1.9 Summary References

12 13 15 16

Drilling Methods 2.1 Introduction 2.2 Types of Drilling Methods 2.2.1 Cable Tool Drilling 2.2.2 Rotary Drilling 2.3 Rotary Drilling Rig and its Components 2.4 Drilling Process 2.4.1 Power System 2.4.2 Hoisting System

17 17 18 18 19 20 22 23 28

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1 1 1 2 2 3 5 5 7 7 9

viii Contents 2.4.3 Circulation System 2.4.4 Rotary System 2.5 Types of Rotary Drilling Rigs 2.6 Nature and Need for Sustainable Drilling Operations 2.7 Current Practice in the Industries 2.7.1 Derrick and Substructure 2.7.2 Hoisting System 2.7.3 Pressure Control System 2.8 Future Trend in Drilling Methods 2.9 Summary 2.10 Nomenclature 2.11 Exercise Appendix 2A Rig Floor (Conventional Rotary Rig) Rig Floor (Top Drive) Blowout Preventer Stack And Wellhead Drilling Fluid Equipment References 3 Drilling Fluids 3.1 Introduction 3.2 Drilling Fluid Circulating System 3.3 Classiication of Drilling Fluids 3.3.1 Water-base Mud 3.3.2 Oil-based Mud 3.3.3 Air or Gas-base Mud 3.3.4 Foam 3.3.5 Special Types of Muds 3.4 Composition of Drilling Fluids 3.5 Mud Additives 3.5.1 Chemical Additives 3.5.2 Additives for Water-based Mud 3.5.3 Additives for Oil-based Mud 3.6 Measurement of Drilling Fluids Properties 3.6.1 Mud Density 3.6.2 Mud Viscosity 3.6.3 Gel Strength 3.6.4 pH Determination 3.6.5 Filtration Tests 3.6.6 Sand Content 3.6.7 Determination of Liquid and Solids Content 3.6.8 Alkalinity 3.6.9 Water Hardness

40 49 50 57 58 59 59 61 61 62 62 63 65 65 65 66 66 71 73 73 74 76 77 77 79 80 80 82 84 84 85 90 101 102 103 112 113 115 117 117 119 119

Contents ix 3.6.10 Water Analysis 3.6.11 Chemical Analysis 3.6.12 Chloride Concentration 3.6.13 Cation Exchange Capacity of Clays 3.6.14 Electrical Properties 3.7 New Drilling Mud Calculations 3.8 Design of Mud Weight 3.9 Current Developments in Drilling Fluids 3.9.1 Formulation of WBM 3.9.2 Formulation of OBM 3.9.3 Formulation of Gas-based Mud 3.9.4 Development of Environment-Friendly Mud System 3.9.5 Application of Nanotechnology 3.9.6 Application of Biomass 3.10 Future Trend on Drilling Fluids 3.10.1 Cost Analysis 3.10.2 Development of Environment Friendly Mud Additives 3.10.3 Sustainability 3.10.4 Development of Mud and/or Additives for HTHP Applications 3.11 Summary 3.12 Nomenclature 3.13 Exercises References 4 Drilling Hydraulics 4.1 Introduction 4.2 Types of Fluids 4.2.1 Newtonian Fluid 4.2.2 Non-Newtonian Fluid 4.3 Flow Regimes 4.3.1 Laminar Flow 4.3.2 Turbulent Flow 4.3.3 Transitional Flow 4.4 Hydrostatic Pressure Calculation 4.4.1 Liquid Columns 4.4.2 Gas Columns 4.5 Fluid Flow through Pipes 4.6 Fluid Flow through Drill Bits 4.7 Pressure Loss Calculation of the Rig System 4.7.1 Pipe Flow 4.7.2 Annular Flow 4.7.3 Bit Flow 4.7.4 Pump Calculations

120 120 121 121 123 124 125 128 128 129 129 130 131 131 131 131 132 132 133 133 133 135 136 141 141 142 142 143 156 156 156 160 162 162 166 169 171 173 174 175 176 182

x Contents 4.8

Current Development on Drilling Hydraulics 4.8.1 Drilling Hydraulics Optimization 4.8.2 Down-hole Motor Technology 4.8.3 Drilling Hydraulics for the Aerated “Foam” Fluids 4.8.4 Drilling Hydraulics of Aerated luids for Vertical Wells 4.8.5 Drilling Hydraulics of Aerated luids for Deviated, Horizontal and ERD Wells 4.8.6 Drilling Hydraulics for Coiled Tubing Drilling 4.9 Future Trend on Drilling Hydraulics 4.9.1 Hydraulics of Dual Gradient Drilling 4.9.2 Enlargement of Hydraulics Operating Window 4.9.3 Introducing New Hole Cleaning Devices 4.10 Summary 4.11 Nomenclature 4.12 Exercise References 5 Well Control and Monitoring Program 5.1 Introduction 5.2 Well Control System 5.2.1 Well Control Principles 5.3 Warning Signals of Kicks 5.3.1 Primary Indicators 5.3.2 Secondary Indicators 5.4 Control of Inlux and Kill Mud 5.4.1 Analysis of Shut-in-Pressure 5.4.2 Type of Inlux and Gradient Calculation 5.4.3 Kill Mud Weight Calculation 5.4.4 Kick Analysis 5.4.5 Shut-in Surface Pressure 5.5 BOP Equipment for Well Control System 5.5.1 Kick Detection Equipment 5.5.2 Kick Management Equipment 5.6 Well Monitoring System 5.7 Current Practice in Well Control and Monitoring 5.7.1 Managed Pressure Drilling 5.7.2 Real Time Data Analysis with Dynamic Neural Network 5.8 Future Trend on Well Control and Monitoring System 5.8.1 Real Time Vibration Measurement 5.9 Summary 5.10 Nomenclature 5.11 Exercise References

183 183 184 185 188 188 190 192 193 193 194 195 195 197 199 205 205 206 207 211 212 213 214 214 217 217 221 225 227 227 230 238 240 242 244 244 245 247 247 248 249

Contents xi 6 Formation Pore and Fracture Pressure Estimation 6.1 Introduction 6.2 Geological Aspects of Rock Mechanics in Drilling 6.2.1 Rock Mechanical Properties 6.2.2 Underground Stresses 6.2.3 Formation Pressure 6.2.4 Overburden Pressures 6.2.5 Pore Pressure Estimation 6.2.6 Fracture Pressure 6.2.7 Methods for Estimating Fracture Pressure 6.3 Current Development on Formation Pore and Fracture Pressure 6.4 Future Trend on Formation Pore and Fracture Pressure 6.5 Summary 6.6 Nomenclature 6.7 Exercise References

251 251 252 252 253 254 268 274 294 296

7 Basics of Drill String Design 7.1 Introduction 7.2 Drill String Components 7.2.1 Kelly 7.2.2 Drill Pipe 7.2.3 Tool Joint 7.2.4 Heavy Wall Drill Pipe 7.2.5 Bottomhole Assembly 7.3 Drilling Bit 7.3.1 Types of Drilling Bits 7.4 Drill String Design 7.4.1 Collapse Load 7.4.2 Tension Load 7.4.3 Other Design Factors 7.5 Bit Design 7.5.1 Roller Cone Bits 7.5.2 PDC Bits 7.6 Drilling Bit Selection 7.6.1 Situation-1: When Bit Records are Not Available 7.6.2 Situation-2: When Bit Records are Available 7.7 Drilling Bit Performance 7.7.1 Roller Cone Bits 7.7.2 PDC Bit

321 321 322 322 322 326 327 328 334 334 344 346 348 356 364 364 365 366 367 368 368 368 371

312 313 314 314 317 318

xii Contents 7.8

Drilling Optimization Techniques 7.8.1 History of Drilling Optimization 7.8.2 Parameters for Drilling Optimization 7.8.3 Factors Afecting the Drilling Operations 7.8.4 How to Optimize the Drilling Operations 7.8.5 Traditional Optimization Process 7.9 Factors Afecting Rate of Penetration 7.10 Rate of Penetration Modelling 7.10.1 Established Models for Rate of Penetration 7.10.2 Optimization of the Penetration Rate 7.11 Current Development on Drill String and Bottomhole Assembly Design 7.12 Future Trend on Drill String and Bottomhole Assembly Design 7.13 Summary 7.14 Nomenclature 7.15 Exercise References 8 Casing Design 8.1 Introduction 8.2 Importance of Casing String 8.3 Types of Casing String 8.3.1 Stove Pipe and Riser 8.3.2 Conductor Pipe 8.3.3 Surface Casing 8.3.4 Intermediate Casing 8.3.5 Production Casing 8.3.6 Liners 8.4 Components of Casing String 8.5 Classiication and Properties of Casing 8.5.1 Casing Size 8.5.2 Range of Length 8.5.3 Casing Grade 8.5.4 Casing Weight 8.5.5 Casing Connections 8.6 Manufacturing of Casing 8.6.1 Seamless Process 8.6.2 Electric-resistance Welding 8.6.3 Electric-lash Welding 8.7 Rig-site Operation 8.7.1 Handling Procedures 8.7.2 Running Procedures 8.7.3 Landing Procedures

371 373 374 374 376 377 379 392 394 412 416 423 424 424 427 428 433 433 434 435 435 437 438 438 440 440 441 442 443 443 444 445 445 446 446 446 447 447 448 450 451

Contents xiii 8.8

Casing Design and Selection Criteria 8.8.1 Factors Inluencing Casing Design 8.8.2 Design Criteria 8.8.3 Approaches of Casing Design 8.9 Current Development in Casing Technology 8.9.1 Casing Material Development to Protect the Corrosion 8.9.2 Development in Casing Connections 8.10 Discussions on Some Case Studies 8.11 Future Trend on Casing Design Development 8.12 Summary 8.13 Nomenclature 8.14 Exercises References

9 Cementing 9.1 Introduction 9.2 Applications of Oil Well Cements 9.2.1 Cement Applications 9.2.2 Variables Afecting Zonal Isolation 9.3 Cement Production 9.3.1 Production Process 9.3.2 Cement Components 9.4 Classiications of Oil Well Cements 9.5 Cement Properties 9.5.1 Density 9.5.2 Fluid Loss 9.5.3 hickening Time 9.5.4 Viscosity and Yield Point 9.5.5 Permeability 9.5.6 Compressive Strength 9.5.7 Soundness 9.5.8 Fineness 9.5.9 Hydration of Cement Slurries 9.6 Types of Cementing 9.6.1 Primary Cementing 9.6.2 Squeeze Cementing 9.6.3 Plug Cementing 9.6.4 Liner Cementing 9.7 Oil Well Cement Additives 9.7.1 Accelerators 9.7.2 Retarders 9.7.3 Fluid Loss Agent 9.7.4 Extenders

451 452 454 454 477 478 480 490 497 498 498 499 500 503 503 504 506 508 508 508 509 510 513 514 515 515 517 518 519 520 520 521 522 523 524 526 527 528 530 530 530 530

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9.8

9.9

9.10

9.11 9.12

9.13 9.14 9.15 9.16

9.7.5 Anti-foaming Agent 9.7.6 Free Water Control Additives 9.7.7 Lost Circulation Control Agents 9.7.8 Weighing Agent 9.7.9 Dispersants 9.7.10 Strength Retrogression Agents Cementing Design Process 9.8.1 Planning Cement Job 9.8.2 Factors Afecting Cement Job Design Laboratory Tests on Cements Slurry 9.9.1 Well Speciications 9.9.2 Cement Slurry Design 9.9.3 Materials 9.9.4 Cement Slurry Preparation 9.9.5 hickening Time Test 9.9.6 Density of OWC Slurries 9.9.7 Free Water Contents 9.9.8 Fluid Loss Test 9.9.9 Rheological Properties 9.9.10 Compressive Strength of Cement 9.9.11 Particles Settling Test 9.9.12 Permeability and Porosity Tests 9.9.13 Micro Structural Analysis Mechanics of Cementing 9.10.1 Cementing Equipment 9.10.2 Cementing Processes Cement Job Evaluation Cement Volume Calculation 9.12.1 Slurry Requirement 9.12.2 Number of Sacks 9.12.3 Mixwater Needed 9.12.4 Additives Needed 9.12.5 Displacement Volume Required 9.12.6 Duration of Pumping Practical Calculations Recommendations for Successful Cementing Current Development on Cementing Future Trend on Cementing 9.16.1 Depleted Reservoirs 9.16.2 HTHP Reservoirs 9.16.3 Corrosive Environment 9.16.4 Deep Waters

530 530 531 531 531 531 531 532 532 534 535 535 537 537 539 540 541 541 541 542 546 548 548 549 550 551 555 557 557 557 558 558 558 558 558 564 564 565 565 566 566 566

Contents xv 9.17 Summary 9.18 Nomenclature 9.19 Exercises References

566 567 568 570

10 Horizontal and Directional Drilling 10.1 Introduction 10.2 Functions 10.3 Basic Terminologies 10.4 Types of Directional Drilling 10.4.1 Horizontal Drilling 10.4.2 Multilateral Drilling 10.4.3 Extended Reach Drilling (ERD) 10.4.4 Coiled Tubing Drilling (CTD) 10.5 Well Planning Trajectory 10.5.1 Directional Patterns 10.6 Directional Drilling Tools 10.6.1 Drill Collars (DC) 10.6.2 Heavy Weight Drill Pipe (HWDP) 10.6.3 Stabilizer 10.6.4 Roller Reamers 10.6.5 Key-Seat Wiper 10.6.6 Cross-over Sub 10.6.7 Drilling Jars 10.6.8 Deviating Tools 10.7 Well Survey 10.7.1 Survey Tools 10.7.2 Survey Calculation 10.8 Geo-steering 10.9 Current Trends in Directional Drilling 10.10 Future Trends in Directional Drilling 10.11 Summary 10.12 Nomenclature 10.13 Exercise References

571 571 572 576 580 580 583 585 587 594 594 599 599 599 599 602 602 603 603 603 616 617 625 635 636 637 639 639 640 642

11 Well Drilling Cost Analysis 11.1 Introduction 11.2 Variables Related to Drilling Costs 11.3 Types of Well Drilling Costs 11.3.1 Rig Costs 11.3.2 Tangible Costs 11.3.3 Service Costs

643 643 644 645 646 646 646

xvi Contents 11.4 Brake Down of Total Well Drilling Cost 11.5 Authorisation for Expenditure 11.6 Drilling Cost Estimation 11.7 Well Drilling Time Estimation 11.7.1 Drilling Time Estimation 11.7.2 Trip Time Estimation 11.7.3 Number of Bit Estimation 11.7.4 Connection Time Estimation 11.7.5 Coring Cost Estimation 11.8 Time Value of Investment 11.8.1 Future Value Estimation 11.9 Price Elasticity 11.10 Current Trend on Drilling Cost Analysis 11.11 Future Trend on Drilling Cost Analysis 11.12 Summary 11.13 Nomenclature 11.14 Exercise References 12 Well Completion 12.1 Introduction 12.2 History of Well Completion 12.3 Requirements for Well Completion 12.4 Types of Well Completion 12.4.1 Open-hole Completion 12.4.2 Uncemented Liner Completions 12.4.3 Cased and Cemented Completions 12.4.4 Perforated Completion 12.4.5 Multi-Zone Completions 12.5 Factors Inluencing Well Completion Design 12.6 Completion Equipment and Materials 12.6.1 Casing 12.6.2 Cement 12.6.3 Perforating and Sand or Gravel Packs 12.6.4 Production Equipment 12.6.5 Landing Nipple 12.6.6 Downhole Gauges 12.6.7 Perforated Joint 12.6.8 Formation Isolation Valve 12.6.9 Centralizer 12.6.10 Wireline Entry Guide 12.6.11 Tubing Hanger 12.6.12 Electrical Submersible Pump

647 647 649 656 660 662 662 664 664 668 668 669 670 672 673 673 674 677 679 679 680 680 683 684 685 688 688 693 695 697 697 698 698 700 705 705 706 706 706 706 706 706

Contents xvii 12.6.13 Wellhead Equipment and Completion 12.6.14 Downhole Safety Valve 12.6.15 Subsurface Safety Valves 12.6.16 Completion Fluids 12.6.17 Casing Perforation 12.6.18 Filters and Drains for Solid Transport Control 12.6.19 Well Stimulation 12.6.20 Tubing String and Accessories 12.7 Sand Control 12.8 Remedial Cementing 12.9 Corrosion and Corrosion Prevention 12.10 Current Development on Well Completion 12.11 Future Trend on Well Completion 12.12 Summary References Index

706 707 709 710 712 714 715 717 719 721 724 729 733 735 735 737

Foreword Albert Einstein famously said, “I was originally supposed to become an engineer but the thought of having to expend my creative energy on things that make practical everyday life even more reined, with a loathsome capital gain as the goal, was unbearable to me.” Engineers are faced with solving problems that few dare approaching. hey do so for a “loathsome capital gain” yet they remain responsible for making things practical and eicient. Drilling into a formation that is thousands of meters underground is a daunting task. To make that process sustainable is nothing short of a miracle. Promises of such miracles are an act of a magician unless backed by a solid scientiic foundation. his book addresses a problem that only a few years ago was deemed to be an impossible task, and it does so with a solid scientiic foundation, yet with utmost clarity. Engineering is an art that needs conscious participation and skillful mentoring. he best way to learn how to handle an engineering problem is to sit down next to a friendly, patient, experienced practitioner and work through problems together, step-by-step. his book will give the readers similar learning experience. he chapters are organized in a very logical fashion. he book is easy to understand even though it is a product of extensive research in fundamentals of drilling engineering and is enhanced with new knowledge and the most up-to-date information. Such a hands-on approach cannot be found in any other textbook in engineering. his textbook promotes the concept of true paradigm shit in the topic of drilling engineering that remains one of the most complex yet least understood subjects of the modern era. It is no secret that no single current drilling engineering book is adequate in explaining natural phenomena. When it comes to challenging tasks, such as environmental sustainability, the inadequacy becomes even more pronounced and has caused tremendous frustration in the current energy management schemes. While everyone seems to have a solution, it is increasingly becoming clear that these options are not moving our environment to any cleaner state. Few have ventured into proposing a solution that would question the foundation of conventional thinking. his book takes that necessary step and ofers something that can only be characterized as groundbreaking. his textbook ofers some of the advanced and recent achievements related to drilling operations in addition to fundamentals of diferent drilling areas and sustainable operations. It breaks out of conventional practices of using prior knowledge as a basis. It takes a bold step of going to the root of

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xx Foreword the current practices and challenges in the area. By doing so, this textbook creates a true knowledge for undergraduate students to strengthen their basics of drilling engineering and researchers who need guidelines for further improvement in the area. One application is the use of basics of drilling engineering along with more workout examples and exercises at the end of each chapter. his book puts forward a guideline how to handle the inherent complexity of recent challenges that are being faced by the industry. Many people feel the petroleum industry has not been as good as others in propagating sustainable activities for enterprise applications. Even researchers simplify and oten marginalize the inherent complexity of drilling operations, especially the drilling luid properties toward sustainability considering assumptions in an unjustiied way. As the technology becomes more capable and sophisticated, it becomes more important to understand how to use it well. his unique book is a valuable step in advancing that understanding. In my view, this book is a must for any student, practicing engineer, expert, researcher, and academic who aspires to understand the complex process involved in drilling engineering. Professor M. R. Islam Former Killam Chair in Petroleum Engineering, Dalhousie University, Canada President, Emertec Research and Development Ltd., Halifax, NS, Canada

Preface Sustainable Drilling Engineering? I have heard sustainable used in conjunction with “green” energy sources such as wind or solar. I have heard sustainable with respect to agriculture. But using sustainable with respect to drilling? Isn’t that an oxymoron such as “jumbo shrimp” or “accurate rumors?” Doesn’t drilling have to do with oil and gas, a inite resource? Yes, it does. But it is more than that. Drilling is the process of accessing resources below the surface of a planet such as Earth. hese resources include oil and gas, naturally. But consider one of the most critical resources mankind needs: water. In many places, the only source of that precious resource is underground. How about various minerals? Gold and silver come to mind; but more important to us are iron, aluminum, and the many rare earths needed by our electronic devices. he initial discovery of these resources is oten at the end of a drill bit. How about geothermal energy? hat is a potential source of energy that is limitless, and it takes a borehole drilled into the ground to access it. How about learning science? We study the geology of the Earth. We look at the past climates with ice cores in Antarctica. We determine the low of contaminates underground. We look for life on other worlds. Drilling is not only for oil and gas; it is needed for any access to the natural resources and knowledge found below the surface of our (or any other) planet. Sustainable means to be able to be maintained at a certain rate or level or to be upheld or defended. In the case of this book, I consider both deinitions to be an accurate description of the text. Drilling operations are expensive, time consuming, and potentially dangerous to people and the environment. One must maintain a high level of engineering and operational skill that mitigates any potential harm to anyone or anything. It is the drilling engineering and the process of drilling that is sustainable. herefore, the title of this book is accurate. It is drilling engineering that is sustainable. Drs. Hossain and Al-Majed have written a book on sustainable drilling engineering. In it, they describe the many aspects of the drilling engineer’s practice. In some work I did with the United States’ National Aeronautics and Space Administration some years ago, the Jet Propulsion Laboratory engineers and my Colorado School of Mines team reduced drilling wellbores into three categories: penetrate the rock, remove the rock, and keep the wellbore open. his book explains it all. hey start with an introduction to the profession of drilling engineering and the people that are involved in making drilling sustainable. he authors then go on to describe and explain the machinery of the drilling rig that enables people to drill wells. Towards the end

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of the book, they discuss how to inish a well, called well completions and detail how to determine the economics of drilling and completing wellbores in a chapter on cost analysis. You have to penetrate the rock. he authors launch into drill string design from the top drive/kelly through the drill pipe and bottom hole assembly to the drill bit. hey explain how to choose the bit and operate the rig at peak capability. hey also discuss in another chapter how to direct the wellbore trajectory in the process called directional drilling. his includes the process of horizontal drilling that is a remarkable process for opening up oil and gas resources that were never considered a resource just a decade ago. You have to remove the rock. he authors describe drilling luids and the hydraulics derived from their low. hey continue in logical sequence to well control issues and methods; and, on to the prediction processes not only for the source of well control problems, pore pressures; but also to the bane of well control, fracture gradients and the loss of luids. You have to support the borehole. One way to stop wellbores from collapsing or to control pressures is to run steel pipe. his is called casing and its design is the subject of a chapter in the book. his is followed by the illing of the ring shaped area (called the annulus) between the rock walls and the casing with cement, the most common way to prevent the migration of luids from one formation to another. he casing and cement helps to maintain the borehole. All of this knowledge goes into making drilling and the engineering required be sustainable. his book is the start in learning how to make drilling engineering sustainable. Dr. Alfred William Eustes III, Ph.D., P.E. Colorado School of Mines Petroleum Engineering Department Golden, Colorado 80401, USA

Acknowledgements he authors would like to acknowledge the inancial support provided by the Deanship of Scientiic Research (DSR) at King Fahd University of Petroleum & Minerals (KFUPM) for funding this book writing grant through project number IN101017. he authors are also grateful for the support received from the department of Petroleum Engineering at KFUPM. he irst author acknowledges the support of his family members that provided him with full support during the book writing. he dedication of Dr. Hossain’s wife gave him the feelings of heavenly environment and continuous mental support under all circumstances. During this long journey, the sacriice of the children, Ijlal Hossain, Ryyan Hossain, Omar Mohammed Ali-Hossain and Noor Hossain remained the most important source of inspiration. he second author acknowledges the support of his family members and friends whose understanding and support made it possible for him to accomplish the demanding undertaking of writing a book. he authors would like to thank Dr. Abdullah Sultan for his support to assign graduate students to work in this project. he authors would like also to thank Dr. Kalim Urahman for his support during writing the cementing chapter. It is also acknowledged the contributions of our graduate students, Mr. Abdul Rauf Adebayo, Murtaza Mobeen, and Waqas Ahmed Khan who assisted in the literature survey of some chapters. Appreciation goes to Mr. Mohammad Hussain Khan Niazi for his support in drawing igures as a dratsman. In addition, there are many more friends, colleagues, stafs and secretaries who have dedicated time for this book.

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Summary Drilling Engineering is one of the oldest technologies on earth and the technological advancement in this area is well recognized by the scientists, engineers, researchers, and the petroleum industry. However, the hydrocarbon extraction industry is still unmoved by attempts of alternative energy sources to displace it as the primary source of energy for the foreseeable future. In this information era, the key to success in the drilling industry has been the results of utilization of technological advancement. Knowledge gaps have been created in drilling technologies because of the challenges that face the oil companies in the exploration for oil and gas in areas which is remote, deep and diicult to reach, whether on land or ofshore areas. he scientiic and technological advancement could not reduce the level of risks and data uncertainties in the drilling operations to the desired level since performing drilling operations in a sustainable fashion does not have the priority in an era of continuously increasing demand for oil and gas, and increasing costs of projects. Unfortunately, the petroleum industry is still perceived as one of the expensive branches of modern industries. To date there are very few textbooks that explain the sustainable drilling operations with fundamentals of drilling engineering. As the irst and only complete guide for petroleum engineers on basic drilling engineering and a milestone book for environmentalist and researchers, this is a best choice to have for the drilling community. his textbook explains how the drilling technology can be operated in a sustainable fashion. However, the main focus is given on drilling luid because lot more researches are needed to green the mud technology for a stainable drilling operation. he book also covers the fundamental issues for the beginners who are interested in learning drilling engineering. he textbook explains the concepts of the basic subject matter clearly and presents the existing knowledge ranges from history of drilling technology to well completion. he book presents the engineering terminologies in a clear manner so that the beginner of the drilling engineering would be able to understand the drilling concepts with minimum eforts. In addition, each chapter contains some workout examples and exercises for a comprehensive understanding of the subject. his will make the reader interested in reading the book. For the potential researchers, the book outlines related issues and covers gaps in knowledge. It also outlines how the industry can plan the rig operations in a sustainable manner. he book explains the concepts in a readable fashion very clearly. It includes all the basic aspects of drilling engineering including rig operations, drilling hydraulics, cementing jobs, drilling luids, drillstring, bit and casing design, and horizontal and directional drilling. In addition, the book talks about the sustainable petroleum operations and points out topics that deserve further research. However, we believe that each chapter deserves to be a short

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Summary

book and we tried to focus the most important concepts and main topics of the subject matter. he textbook is a foundation and resourceful guide, and an excellent resource for petroleum engineering students, drilling engineers, supervisors and managers, researchers, and environmental scientists. he speciic topics of the drilling engineering that are covered in this book include the following chapters: Chapter 1 – Introduction: his chapter introduces the fundamental features of the drilling. It discusses some of the core issues related to drilling engineering, activities need to be completed before starting drilling operations, etc. Finally, the concepts of sustainable drilling operations are introduced. Chapter 2 – Drilling Methods: his chapter discusses all characteristics related to drilling rig and its components. he chapter focuses on the drilling methods used for hydrocarbon exploitation and covers the cable tool drilling rig, rotary drilling rig and its components, rotary rig systems, types of rigs, current advancement of rig systems, and the knowledge gap that needs to be illed in drilling. Chapter 3 – Drilling Fluids: he chapter covers almost all the fundamental and basic ideas of mud engineering including an extensive literature survey on the drilling luid. he chapter presents the current trend and the future challenges of the technology and also identiies where the R&D personals need to focus their attention toward the sustainable mud engineering. Chapter 4 – Drilling Hydraulics: Drilling hydraulics plays an essential role while drilling activities continue to operate. To understand and properly design the hydraulic system, it is important to discuss hydrostatic pressure, types of luid low, criteria for type of low, and types of luids commonly used in the various operations at the drilling industry. In addition, it covers the type of luids; pressure losses in the surface connections, pipes, annulus, and the bit; jet bit nozzle size selection; surge pressures due to vertical pipe movement; optimization of bit hydraulics, and carrying capacity of drilling luid. he current and future trends of the hydraulic system are also discussed in the last sections of the chapter. Chapter 5 – Well Control and Monitoring Program: he chapter discusses well control and monitoring system in general. It covers how a well can be controlled in a sequential and safe way in addition to its diferent control devices used in any well control and monitoring system. his chapter covers the whole range of real-time monitoring system and discusses the current practices in the industry and the future trend of the well control and monitoring system in general. Chapter 6 – Formation Pore and Fractures Pressure Estimation: his chapter deals with the formation luid pressure and fracture pressure, understanding of the variation of these two parameters with depth, and rock mechanical properties including geological aspects of rock mechanics. he development of underground stresses and the related formation pressure, fracture pressure are also outlined in this chapter. he diferent causes of abnormal pressure with detailed detection and prediction techniques are the main focus of the chapter. Finally, the current state-of-the-art on formation pore pressure and fracture pressure along with the fracture gradient are elaborated in this chapter. Chapter 7 – Basics of Drillstring Design: he chapter covers the basic drillstring and bottom-hole assembly (BHA) design including drill bit. he diferent types of drill bit and their applications are outlined in detail. he ROP optimization and the factors that inluence the ROP are discussed and the existing ROP models are explained. he current

Summary

xxvii

development in the area and the future trend of drill string and BHA are also presented in the chapter. Chapter 8 – Casing Design: his chapter focuses the types of casing, diferent components of casing and landing procedures including the manufacturing of casing, rig side operations, handling procedure, casing design, and selection criteria. Finally, the current practice and the future trend of the casing for the oil industry are discussed. Chapter 9 – Cementing: his chapter discusses how the well cementing plays a vital role by providing the diferent functions throughout the life of a well. It explains the cement slurry design process which covers the parameters those afect the cementing process during and ater placement of cement slurry in the annulus. he chapter also discusses lab testing and the rheological properties of cement slurry. he current developments and future challenges faced by oil well cementing industry are outlined at the end of the chapter. Chapter 10 – Horizontal and Directional Drilling: his important chapter discusses the fundamental concepts related to horizontal and directional drilling including well survey, other forms of directional drilling technologies such as horizontal wells, extended reach wells, multilateral wells, slim hole drilling, and coiled tubing drilling. Future trends in directional drilling are also discussed on a separate subsection in addition to the current trend of the directional drilling technology. Chapter 11 – Well Drilling Costs Analysis: his chapter focuses the factors afecting the drilling costs, types of costs, and variables that inluence the well drilling costs. Some typical examples are set to enhance the drilling costs estimation. he purpose of the chapter is to review the primary methods used to assess drilling cost and complexity. he foundational basis of each approach is described and a critical assessment of model assumptions is provided. Chapter 12 – Well Completion: his chapter addresses the needs for well completion and focuses on building the current foundation of engineers on completion techniques. It further provides practical exercises and industrial applications on the key decisions needed to be made during the completion processes. In addition, an in-depth discussion on the emerging technologies and methodologies on well completion is covered. he current trend and practices of the well completion along with its future trend are also identiied in the chapter. Dr. M. Enamul Hossain and Dr. Abdulaziz Al-Majed

1 Introduction 1.1 Introduction his chapter introduces the fundamental aspects of the drilling. It covers the basic deinitions related to drilling engineering, importance and the procedure for drilling operations. he applications and history of drilling are also outlined. he systematic approach and the introduction to casing sets are discussed. Finally, the aspects of sustainable drilling operations will be introduced.

1.2 Introduction of Drilling Engineering Some scholars consider petroleum hydrocarbons to be the lifeblood of modern civilization. he life cycle of petroleum operations includes exploration and development, production, reining, marketing, transportation/distribution to the end user, and inal utilization. he drilling technology has been developed through the eforts of many individuals, professionals, companies, and organizations. his technology is a necessary step for petroleum exploration and production. Drilling is one of the oldest technologies in the world. Drilling engineering is a branch of knowledge where the design, analysis, and implement procedure are completed to drill a well as sustainably as possible. In a word, it is the technology used to utilize crude oil and natural gas reserves. he responsibilities of a drilling engineer are to facilitate the eicient penetration of

1

2

Fundamentals of Sustainable Drilling Engineering

the earth by wellbore and to facilitate cementing operations from the surface to an optimum target depth that prevents any situation that may jeopardize the environment.

1.3 Importance of Drilling Engineering It is well known that the petroleum industry drives the energy sector, which in turn drives the modern civilization. It is not unlikely that every day human beings are getting beneits out of the petroleum industry. he present modern civilization is based on energy and hydrocarbon resources. he growth of human civilization and necessities of livelihood with time inspired human beings to bore a hole for diferent reasons (such as drinking water, agriculture, hydrocarbon extraction for lighting, power generation, to assemble diferent mechanical parts, etc.). here is no surface hydrocarbon resource; rather, all resources are underground on this globe. To keep serving the whole civilization, drilling engineering has a signiicant role in this issue. Moreover, the world’s energy sector is dependent on the drilling engineering. Without drilling a hole, how are we going to extract the hydrocarbon from underground to the surface of the earth? To the best of our knowledge, right now, there is no alternative technology available to extract hydrocarbon without drilling a hole. If the petroleum industry falls down, the whole civilization will probably collapse. herefore, for the survival of our existence, we need to know and keep updating our knowledge, especially on the technology, of drilling engineering. Based on this motivation, human necessities of drilling a hole by excavation on earth have motivated the researchers to develop diferent sophisticated technologies for drilling engineering. In a word, we can say, drilling engineering has a vital role in our daily life, economy, society, and even in national and international politics.

1.4 Application of Drilling Engineering By the development of human civilization with time, human beings have needed to make a hole in diferent objects for diferent purposes. It ranges from just a childhood playing game/toy, to modern drilling of a hole for the purpose of any scientiic and technological usage. Humans have been using this technology for underground water withdrawal since ancient times. Drilling technology is a widely used expertise in the applied sciences and engineering, such as manufacturing industries, pharmaceutical industries, aerospace, military defense, research laboratories, and any small-scale laboratory to a heavy industry like petroleum. Modern cities and urban areas use the drilling technology to get the underground water for drinking and household use. he underground water extraction by boring a hole is also used agricultural irrigation purposes. herefore, there is no speciic ield of application for this technology. It has been used for a widespread ield based on its necessity. As this textbook is only focusing on drilling a hole with the hope of hydrocarbon discovery, here, the drilling engineering application means a shat-like tool (i.e., drilling rig) with two or more cutting edges (i.e., drill bit) for making holes toward the underground hydrocarbon formation through the

Introduction 3 earth layers, especially by rotation. Hence, the major application of drilling engineering is to discover and produce redundant hydrocarbon from a potential oil ield.

1.5 History of Oil Discovery Geology and time have created large deposits of crude oil in various parts of the earth. Until the mid-1800s, this vast untapped wealth lay mostly hidden below the surface of the earth. Some oil seeped naturally to the earth’s surface, and formed shallow pools. hese oil seeps had long been known and were used for medicinal purposes, to caulk boats and buildings, and to lubricate machinery. Ancient people were using oil mainly as medicine. So, the use of oil is not new in human history. he irst oil discovery in human life was in Babylon (Current Iraq) as oil pits in 450 BC. hen, the second discovery was in Macedonia in 325 BC, and this oil was being used by Alexander the Great. he third discovery of oil was in Kirkuk, Iraq. However, according to Wikipedia, the earliest known oil wells were drilled in China in 347. he Chinese were using bamboo as modern drill pipe to extract oil. hey were able to drill at a depth of about 800 feet using bits attached with bamboo poles. he use of oil was limited to evaporating brine, producing salt, and for lighting and heating. he petroleum industry in Middle East was established by the eighth century. his was due to the use of tar at the street lights in Baghdad. However, some people believe that in the ninth century, oil ields were developed in Baku, Azerbaijan to produce naphtha. he Persian alchemist, Mohammad ibn Zakariya Razi, produced kerosene from petroleum using the distillation process in the ninth century. Kerosene was used mainly as kerosene lamps. he distillation process of crude oil was also carried out by Arab and Persian chemist to produce lammable products for military purposes. By the twelth century, distillation process became available in Western Europe through Islamic Spain. History says Baku was the place where shallow pits were dug to facilitate collecting oil. he hand-dug holes, which were up to 115 feet deep, were in use by 1594. In fact, these holes were essentially oil wells and produced about 28,000 barrels of oil so far. he irst break through in the oil industry’s drilling history was the year 1849, when Russian engineer F.N. Semyenov used a cable tool to drill an oil well on the Apsheron Peninsula. In the west, Canada was the irst place of commercial oil production, when James Williams drilled the irst oil well in North America in 1857. Later, in 1859, the irst well in the USA was drilled near Titusville, Pennsylvania under the supervision of Colonel Edwin L. Drake, and it was about 69 feet deep. Table 1.1 shows the oil discovery in the diferent places around the world as an example case. he irst commercial oil well was situated in the southwestern Ontario town of Oil Springs. Williams acquired some property that was known to have oil gum beds. He dug through the gum beds in search of the source of the oily deposits, and discovered crude oil. his irst oil well was simply a hole in the ground, with oil rising up close to the surface. With the use of hand pumps, the oil was extracted at a rate of 37 barrels of oil per day. Williams built and operated a local distillery from which he reined and sold kerosene. Ontario’s irst oil boom—relected in town names such as Petrolia—paralleled

4

Fundamentals of Sustainable Drilling Engineering

Table 1.1 First discovery of oil in diferent places in the world for commercial production. Serial No.

Name of the Country

First Discovery of Oil

01

Oil pits near Babylon

450BC

02

Macedonia

325BC

03

Kirkuk (Iraq)

100

04

China (used bamboo for extract oil)

347

05

Azerbaijan (For medicine)

1264

06

Poland

1500

07

Russia

1597

08

Australia

1800

09

Romania

1857

10

Ontario, Canada

1858 (First Commercial use)

11

Pennsylvania, USA

1859

12

Lake Maracaibo, Venezuela

1878

13

Sumatra, Indonesia

1885

14

Norway/Netherland

1885

15

Nigeria

1907

16

Iran

1908

17

Tampico, Mexico

1910

18

Bahrain

1932

19

Saudi Arabia

1933

20

Kuwait

1938

21

Qatar

1939

22

Brazil

1939

23

Algeria

1956

24

United Arab Emirates

1960

25

Oman

1967

26

United Kingdom

1969

27

Sudan

1979

a larger oil boom in northern Pennsylvania, where energy dynasties were beginning to  emerge. Oil was not being used widely in commercial basis before middle of the nineteenth century. Oil had been used as medicine, laming torches, and for lighting purposes before that. Now a day’s oil is the backbone of nation’s economy and the heart of modern civilization.

Introduction 5

1.6 An Overview of Drilling Engineering A multitude of issues are needed to be resolved even before the consultants or engineers ever see the prospect of the project. Most importantly, these phases of works are being completed before any drilling operation. Here, the principal party is called the operator. his operator is normally the “Oil Company,” who is a well-known major company or an independent. he operator employs the drilling consultant to protect and negotiate the operator’s interest. Meanwhile, the operator also engages geologists to locate the area where s/he feels to have a good prospect for hydrocarbon reserve. he geologists may recommend drilling a wildcat well (a small exploratory oil well drilled in land not known to be an oil field to get the geological information ) into an untested ield, or s/he may recommend a development well (a well drilled in a proved production fi eld or area to extract natural gas or crude oil) to get the desired information about the formation. he operator’s next objective is to hire a landman to acquire drilling rights. he oil companies normally have a paid staf of geologists and landmen. he main responsibility of landman is to determine who is going to own the minerals rights in the area to be drilled. He also tries to acquire lease rights from the landowner through a document which is called an “oil and gas lease.” So, the landman is the representative of the operator who takes care of all of the negotiation parts with landowner so that the terms and conditions would be acceptable for the operator. Ater getting the lease and approval of license, the operator then hires the drilling contractor (a contractor who owns the drilling rig and employs the crew to drill the well ). At this stage, operator hires the specialist consultants (normally service companies) to conduct other rig side jobs, such as casing, cementing, logging, perforating, fracturing, acidizing, lost tool recovery, drilling luid preparations, etc. he geologists and reservoir engineers are again engaged to analyze the drilling results and to determine which zones, if any, are worth producing. If there are one or more potential zones, the well would be completed for production. On the other hand, if there are no formation zones, the well would be plugged and abandoned in accordance with the regulations that protect the water zones drilled through. he operator cannot just pick up the rig and leave the hole open. Finally, the operator is responsible for producing and selling the hydrocarbons from its proven zones.

1.6.1 Licensing, Exploration and Development Petroleum and mineral resources are usually owned of by the government of the host country. Normally, the ministry of petroleum/oil and gas (diferent names in diferent countries) is empowered on behalf of the government to invite companies to apply for exploration and production licenses within the country. Exploration licenses may be awarded at any time based on company’s reputation and terms and conditions. Exploration licenses do not allow a company to drill any deeper than certain depth and are used primarily to enable a company to acquire seismic data from a given area. Production licenses allow licensees to drill for, develop and produce hydrocarbons from whatever depth is necessary. Costs of ield development are so huge that major oil companies normally form partnerships to share the expenses. Typically, oil companies

6

Fundamentals of Sustainable Drilling Engineering

operate in joint ventures to reduce their individual risk as well. One of the companies within the joint venture is designated and empowered to act as an operator that actually supervises the work. As long as the governments of most nations issue licenses to explore, develop, and produce its oil and gas resources, the company needs to obtain a production license even before drilling an exploration well. Prior to applying for a production license, however, they will conduct an “investigation” exercise, in which they will analyze any seismic data they have acquired, analyze the regional geology of the area, and inally take into account any available information on producing ields or well tests performed in the vicinity of the prospect they are considering. Based on the above, and a general look at the exploration and development costs, the pricing, and tax regimes, the company will decide whether it would be worth developing the ield (if a discovery were made)or not. If the project is considered worth exploring further, the company will try to acquire a production license and continue with the “exploration” phase of the ield. his will allow the company to drill wells in the area of interest. It will in fact commit the company to drill one or more wells in the area. he exploration phase of the ield development may begin with the company shooting extra seismic lines in a closer grid pattern than it had done previously. his will provide more detailed information about the prospect and will assist in the deinition of an optimum drilling target. Despite improvements in seismic techniques the only way of conirming the presence of hydrocarbons is to drill an exploration well (the well that helps to determine the presence of hydrocarbons ). Drilling is very expensive, and if hydrocarbons are not found, there is no return on the investment, although valuable geological information may be obtained. With only limited information available, a large risk is involved (on average, only one in eight North Sea exploration wells are successful). If the company decides to go ahead for hydrocarbon presence, an exploration well proposal is drawn up to drill in the most likely position on the reservoir. he length of the exploration phase will depend on the success. here may be a single well or many wells drilled on a prospect in the exploration phase. If a viable discovery is made on the prospect then the company enters the “Appraisal” phase of the ield. During this phase more seismic lines may be shot and more wells will be drilled to establish the extent of the reservoir. hese appraisal wells (a well that is drilled to establish the extent (size) of reservoir ) will yield further information, on which future plans will be based. he information provided by the appraisal wells will be combined with all of the previously collected data. Engineers will investigate the most cost-efective manner through which they can develop the ield. If the prospect is deemed to be economically attractive, this development design will culminate in the production of a ield development plan. his plan will be submitted for approval. If approval of the development is received, then the company will commence drilling development wells (a well that is drilled in a proved production fi eld or area to extract natural gas or crude oil ) and construction of production facilities according to the development plan. Once the ield is “on-stream,” the companies’ commitment continues in the form of maintenance of both the wells and all of the production facilities. Ater many years of production, it may be found that the ield is yielding more or possibly less hydrocarbons than initially anticipated at the development planning stage, and the company may undertake further appraisal and subsequent drilling in the ield.

Introduction 7 Once the ield is no longer producing economically, the company will be required to abandon the ield in a sustainable (i.e., safe and environmentally acceptable) fashion.

1.6.2 Role of Drilling during Field Development he role of drilling during, or even before, the ield development is enormous. here are some step-by-step works that are normally followed by the operators during the development phase of an oil ield. Figure 1.1 shows a complete loop for diferent phases of the development works related to drilling engineering. In addition, to understand the process well, the following steps are mentioned while drilling an oil/gas well continued: 1. 2. 3. 4. 5. 6. 7. 8. 9. 10. 11. 12.

Complete or obtain seismic, log, scouting information, or other data Lease the land or obtain concession Calculate reserves or estimate from best data available If reserve estimates show payout, proceed with well Obtain permits from various government authorities Prepare drilling and completion program Ask for bids on footage, day work, or combination from selected drilling contractors based on drilling program If necessary, modify program to it selected contractor equipment Construct road, location/platforms and other marine equipment necessary for access to site Gather all personnel concerned for meeting prior to commencing drilling (pre-spud meeting) If necessary, further modify program Drill well for production

Once a decision is made to drill a well, then the drilling engineer’s role comes into play. In this long process, a drilling engineer plays a vital role during drilling operations, including planning, design, and supervision. he following are some of the important responsibilities that are accomplished by the drilling engineer: • • • • • •

1.6.3

Well planning before drilling Monitor drilling operations including mud luid Managing rig side people (i.e., management job) Ater drilling, review drilling results and recommend future improvements Prepare report General duties

Types of Drilling Wells

If the subsurface hydrocarbon formations are identiied from primary seismic survey, a decision is made to either develop the ield to get more information from exploration, or to declare the ield as abandoned. If the ield is decided as a potential area of hydrocarbon production, actual drilling of one or more wells is necessary to determine whether or not suicient accumulations of hydrocarbon exist as commercial quantities.

8

Fundamentals of Sustainable Drilling Engineering Geological and Geophysical Analysis

Seismic Survey

Drill Exploration Well Drill Appraisal Well Mud Logging (Lithological and textural description of formation from drill cutting, hydrocarbon shows)

Coring (Lithological and textural description from massive sample. Samples used for lab analysis – porosity, permeability, capillary pressure etc.) Well Logging (Electrical, Radioactive and Sonic tools provide quantitative assessment of luid types and distribution)

Well Testing (Following the well allows large representative samples of the reservoir luid to be recovered. Pressure response of reservoir allows extent, producibility and drive mechanisms of the reservoir to be evaluated.) Evaluated Information Gathered Above

From exploration and appraisal well information, compile geological model

Compile Economic Model

Drill Development Wells

Figure 1.1 Role of drilling during ield development.

Based on these strategic decisions and primary outcomes, drilling wells can be categorized into four types, such as exploration well, appraisal well, development well, and abandonment well. An exploration drilling well is oten called a Wildcat well. It is drilled during the initial phases of exploration. he drilling is completed with the hope of getting the information whether the reservoir rocks contain any oil or gas. he main objectives of this drilling well are to determine the presence of hydrocarbons, to provide a geological data (such as cores, logs) for evaluation, conduct low test through the well to determine its production potential, and to obtain the luid samples for laboratory

Introduction 9 analysis. Once hydrocarbons are discovered, more drilling is done to test if the i eld is commercially viable or not. So, appraisal wells are those wells that are used to establish the extent (size) of the reservoir. his well helps in gathering information such as whether there is a suicient amount of oil and gas to justify investing money in infrastructure to recover oil/gas to scales. he development wells are sometime called production wells . his well is drilled in a proved production ield/area to extract hydrocarbons (i.e., natural gas/crude oil). h is drilling well is done to create a low path from the reservoir to the surface, and then through the production facility. Finally, if no hydrocarbon discovery is found, the well that was drilled to gather the information needs to be closed to prevent possible environmental disaster. he well that is sealed and closed is called an abandonment well. his well can be an exploration or appraisal well.

1.6.4 Sequences of Drilling Operations he sequences of drilling operations can be categorized into three major steps. he irst step is to initiate and accelerate the drilling of a hole on the earth’s surface for hydrocarbon extraction, the second step is the casing operations, and the third step is the completion of well. However, the second and third steps are basically needed to support drilling operations in a sustainable manner. When drilling operations continue, the second step needs to be accomplished simultaneously with drilling. he third step comes once drilling operations reach their target level. In general, several casing steps are completed to avoid blowout or any other consequences during drilling operations. However, when a well is drilled in high pressured zones, weak and fractured formations, unconsolidated formations, or sloughing shales, the second step must be completed without any excuse to avoid substantial destruction at the rig-side. Diferent casing sizes are required for diferent depths. In general, ive diferent casing sizes are used to complete a well. Figure 1.2 shows the diferent casings, such as outmost casing (or conductor pipe), surface casing, intermediate casing, production casing, and liner. As shown in Figure 1.2, these pipes are run to diferent depths, and one or two of them may be omitted, depending on the drilling condition. However, they may also be used as liners, or in combination with liners. Based on the above casing concept, the sequences of the drilling operations are outlined, considering an onshore oil ield. Once the location is inalized, depending on primary seismic survey, a large diameter hole (normally 36 ) is drilled using a truck mounted mobile rig. his hole is only drilled to a shallow depth. It varies from 40 – 500 in length at onshore, and up to 1000 at ofshore. However, the conventional depth is 100 and normal range is 50 – 150 . he hole must be lined with steel pipe or casing (usually called conductor pipe). his is the outmost casing string. he main purpose of this casing is to hold back the unconsolidated surface formations and prevent them from falling into the hole. he conductor pipe is cemented back to the surface, and it is either used to support subsequent casing and wellhead equipment, or the pipe is cut of at the surface ater setting the surface casing. Once the conductor is in place, the drilling rig is brought on to the site and set up for the next stage. A 30 casing shoe is used in this example (Figure 1.2).

10

Fundamentals of Sustainable Drilling Engineering 36" 4 12

Production Tubing

Cement Surface casing

30" Casing shoe (Conductor pipe)

Production casing

6000'

2000'

100'

Outmost casing string or Conductor pipe

20" Casing shoe (Surface casing)

Intermediate casing 13 38 " Casing shoe (Intermediate casing) 12.25" Casing shoe (Liner)

Liner Production tubing Reservoir formation

Packer

9 58 " Production casing

Figure 1.2 Typical casing program showing diferent casing sizes and their setting depths.

A smaller diameter bit must be used to drill the next section below the conductor. If the conductor is 30 diameter, a 26 bit may be used. his 26 hole may be drilled down to 2000 (normal range: 300 – 5000 ) through unconsolidated formations, which may cave in. he hole must be lined with another string of casing (surface casing) which may be up to 20 diameter as an example (Figure 1.2). he size of the surface casing normally varies from 7 – 16 in diameter and the most common sizes are 103⁄4 and 133⁄8 . he main functions of the surface casing string are to hold back unconsolidated shallow formations that can slough into the hole and cause problems, isolate freshwater formations, and to serve as a base on which to set the blowout preventers. he casing is lowered into the hole joint by joint, and then cemented in place. he intermediate or protective casing is set at a depth between the surface and production casings. he main reason for setting intermediate casing is to case of the formations that prevent the well from being drilled to the total depth. It is also used to counter balancing the formation pressure. It varies in length

Introduction 11 from 5000 – 15,000 and 7 and 113⁄4 in outside diameter. In such case, a 171⁄2 bit is used to drill the hole down to 6000 . In case some of the formations in this section prove troublesome (e.g., sloughing shales), another string of casing (133⁄8 intermediate casing) must be run and cemented in place. he next bit size is 121⁄4 and drilling proceeds as before. By this time, we may be approaching the oil bearing formation zone. Any hydrocarbons can be detected by examining the rock cuttings, and if this proves favorable, we may want to evaluate the formation more fully. he drill string is pulled out, and electric logs run on wire line are lowered into the hole. We may also want to take core samples, using a special bit which will allow recovery of a section of rock. A DST (drill-stem test) may be carried out to gain further data. Once all of the test data indicates the positive results, suspended pipes are run from the bottom of the next largest casing string, which is called a liner. Liners are the pipes that do not usually reach the surface. here are several types of liners, such as drilling liner, production liner, tie-back liner, scab liner, and scab tie-back liner. he major advantages of liners are that the reduced length and smaller diameter of the casing results in a more economical casing design than would otherwise be possible, and that they reduce the necessary suspending capacity of the drilling rig. However, possible leaks across the liner hanger, and the diiculty in obtaining a good primary cement job due to the narrow annulus, must be taken into consideration in a combination string with an intermediate casing and a liner. Before production casing or liner, if all the indications from the above tests are negative or show only slight indications of oil, the well will be abandoned. However, if positive results come, production casing is set through the prospective productive zones, except in the case of open-hole completions. It is usually designed to hold the maximal shut-in pressure of the producing formations. It is also designed to withstand stimulating pressures during completion and workover operations. Production casing provides protection for the environment in the event of failure of the tubing string during production operations, and allows for the production tubing to be repaired and replaced. Production casing varies from 41⁄2 and 95⁄8 in diameter, and is cemented far enough above the producing formations to provide additional support for subsurface equipment and to prevent casing buckling. Production casing goes up to the formation zone. So, there is no speciic length for this casing. It varies well to well, depending on the depth of formation zones. Finally, production tubing is place for hydrocarbon production (Figure 1.2). he third or inal stage of the drilling sequences is the completion phase. As mentioned earlier, the completion of the well involves running the production casing (95⁄8 ) at total depth (TD) to seal of the oil producing zone (temporarily). Another string of pipe known as tubing (41⁄2 diameter) is now run with a packer on the outside. When packer is positioned just above the pay zone (Figure 1.2), its rubber seals are expanded to seal of the annulus between tubing and 95⁄8 casing. A set of valves is initiated on the top of the casing to control the low of oil once it reaches the surface. To initiate the production, a perforating gun is run down the tubing on wireline, and is positioned adjacent to the pay zone. Holes are shot through the casing and cement into the formation. he hydrocarbons low into the wellbore and up the tubing to the surface.

12

Fundamentals of Sustainable Drilling Engineering

1.7 Organization Chart and Manpower Requirements during Drilling Operations Drilling requires many diferent skills and involves many diferent companies. he manpower needed to complete the drilling operations is normally engaged from three separate organizations. he organizations, such as drilling contractor, well operator, and drilling services companies, work together and provide manpower as required and requested. A typical drilling organization chart is shown in Figure 1.3. he oil company seeking to exploit the petroleum reserves is known as the “Well Operator.” he operator bears overall responsibility for drilling operations. he company representative makes the rig-side spot decisions based on the well plan for drilling operations and other services if necessary. he planning of the well is usually done by the operator’s staf engineers working at headquarters/control oice in town. hey draw up a drilling program that must be followed as the well is being drilled. Usually the operator will have a representative on the rig (sometimes called the “company man”). His job is to ensure that drilling operations go ahead as planned, to make decisions afecting progress of the well, and to organize supplies of equipment. Any consumable items (i.e., drilling bit, drill pipe,

Oil Company (Well Operator)

Geology Department

Drilling Engineering

Formation Evaluation

Company Representative

Operators

Accounting Department

Drilling Superintendent

Reservoir Engineering

Other Wells in Progress

Production Engineering Land Department

Drillng Contractor Accounting Department

Drilling Superintendent

Drilling Services Companies Rig Design & Maintenance

Mud Engineering Cementing

Other Rigs

Tool Pusher

Drilling Bits

Driller

Drilling Fluid

Rig Crew

Blowout Prevention Field Representatives

Surveying Well Monitoring Well Casing Formation Evaluation Directional Drilling Well Completion Equipment’s Miscellaneous

Figure 1.3 Drilling rig organizational chart.

Introduction 13 cement, etc.) must be provided by the operator. He will be in daily contact with his drilling superintendent in the main control oice in town. here may also be a drilling engineer and/or a geologist on the rig employed by the operator. he oil company usually employs a “Drilling Contractor” to actually drill the well. he contractor provides the rig and the crew to operate it. he drilling contractor is responsible for maintaining the rig and the associated equipment. he rig operation and rig personnel supervision are the responsibilities of drilling contractor. he drilling contractor will have a tool pusher in overall charge of the rig. He is responsible for all rig loor activities, and coordinates with the company man to ensure progress is satisfactory. Since drilling continues twenty-four hour a day, there are usually two drilling crews. Each crew works under the direction of the driller (or tool pusher). he crew will generally consists of a derrick man (who will also be liable for the pump while drilling continues), three roughnecks (working on the rig loor), plus a mechanic, an electrician, a crane operator, and roustabouts (general laborers). During the course of the well, certain specialized skills or equipment may be necessary (i.e., logging, surveying, etc.). he jobs are done by the appointed service companies. he service companies are employed by the operator. hey provide all the specialized logistic supports and rig-side services. he service company’s personnel work on the rig as and when required. Sometimes they are employed on a long-term basis (e.g., mud engineer), or only for a few days (e.g., casing crews), based on demand at rig-side.

1.8 Aspect of Sustainability in Drilling Operations Drilling is a necessary step for petroleum exploration and production. he conventional rotary drilling technique falls short, since it is costly and contaminates surrounding rock and water due to the use of toxic components in the drilling luids. Conventional rotary drilling has been the main technique used for drilling in the oil and gas industry. However, this method has showed its limits regarding the depth of the wells drilled, in addition to the use of toxic components in drilling luids. he success of a high risk hydrocarbon exploration and production depends on the use of appropriate technologies. herefore, to overcome the limitations of conventional rotary drilling technique, we need to look for other environmentally friendly drilling technologies which may lead to a sustainable drilling operation. Generally, a technology is selected based on criteria such as technical feasibility, cost efectiveness, regulatory requirements, and environmental impacts. Recently, Khan and Islam (2006) introduced a new approach in technology evaluation based on the novel sustainability criterion. In their study, they not only considered the environmental, economic, and regulatory criteria, but investigated sustainability of a technology. ‘Sustainability’ or ‘sustainable technology’ has been using in many publications, company brochures, research reports, and government documents which do not necessarily gives a clear direction. Sometimes, these conventional approaches/deinitions mislead to achieve true sustainability. Figure 1.4 shows the directions of true sustainability in technology devolvement. It shows the direction of nature-based, inherently sustainable technology, as contrasted with an unsustainable technology. he path of sustainable technology is its long-term durability and environmentally wholesome impact, while

14

Fundamentals of Sustainable Drilling Engineering Beneicial Inherently Sustainable Technology privileges the long-term. )

Beneit

( t

t Unsustainable Technology privileges the very short-term. ( t 0)

Harmful

Figure 1.4 Direction of sustainable and unsustainable technology (Khan and Islam, 2006; Hossain et al., 2009).

unsustainable technology is marked by Δt approaching 0. Presently, the most commonly used theme in technology development is to select technologies that are good for t = right now , or Δt = 0. In reality, such models are devoid of any real basis (termed “aphenomenal” by Khan et al., 2005), and should not be applied in technology development if we seek sustainability for economic, social, and environmental purposes. In addition to technological details of an appropriate drilling technology, the sustainability of this technology is evaluated based on the model proposed by Khan and Islam. Figure 1.5 shows the detailed steps for its evaluation. he irst step of this method is to evaluate a sustainable technology based on time criterion (Figure 1.5). If the technology passes this stage, it would be evaluated based on criteria such as environmental, economic, and social variants. According to Khan and Islam’s method, any technology is considered sustainable if it fulills the environmental, economic, and social conditions (Cn + Ce + Cs) ≥ constant for any time, t, provided that, dCnt ⁄ dt ≥ 0, dCet ⁄ dt ≥ 0, dCst ⁄ dt ≥ 0. To evaluate the environmental sustainability, a proposed drilling technique is compared with the conventional technology. he current drilling technologies are considered to be the most environmentally concerning activities in the whole petroleum operations. he current practices produce numerous gaseous, liquid, and solid wastes and pollutants, none of which have been completely remedied. herefore, it is believed that conventional drilling has negative impacts on habitat, wildlife, isheries, and biodiversity. For analyzing the environmental consequences of drilling, conventional drilling practices need to be analyzed, which will be continued, chapter by chapter, in this book on sustainability. In conventional drilling, diferent types of rigs are used. However, the drilling operations are similar. he main tasks of a drill rig are completed by the hosting, circulating, and rotary system, backed up by the pressure-control equipment. A drill bit is attached at the end portion of a drill pipe. Motorized equipment rotates the drill pipe to make it cut into rocks. During drilling, many pumps and prime movers circulate drilling luids from tanks through a standpipe into the drill pipe and drill collar to the

Introduction 15 New Technology

Is

Yes

Accepted for EES test

No

t

Yes

Is there scope to improve?

Yes

Yes

d Cnt ≥ 0? dt

No

Improve the step...

No

No

Improve the step...

No

No

Improve the step...

No

Yes

d Cet ≥ 0? dt

Yes

d Cst ≥ 0? dt

Yes

Technology Unsustainable

Technology Sustainable

Figure 1.5 Flowchart of sustainability analysis of a drilling technology (redrawn from Khan and Islam, 2008; Hossain et al., 2009).

bit. he muds low out of the annulus above the blowout preventer over the shale shaker (a screen to remove formation cutting), and back into the mud tanks. Drilling muds are composed of numerous chemicals, some of which are toxic, and which are harmful to the environment and its lora and fauna. hese issues will be discussed in the drilling mud chapter. he conventional practice in the oil industry is to use diferent drilling techniques, where huge capital is involved, and which create huge environmental negative impacts. he technology is also more complicated to handle. herefore, sustainable petroleum operation is one of the important keys for our future existence in this planet.

1.9 Summary his chapter discusses some of the core issues related to drilling engineering. Even before starting drilling operations, many activities need to be completed to fulill the diferent

16

Fundamentals of Sustainable Drilling Engineering

parties’ requirements, which are well-covered here. Moreover, this chapter addresses issues such as the deinition of drilling engineering, diferent terminologies related to drilling operations, licensing, development plan, work sequences, and responsibilities of drilling engineers and diferent companies. his chapter covers almost all aspects of drilling management. Finally, the benchmark of sustainability is also discussed in the chapter.

References Appleton, A.F., 2006. “Sustainability: A practitioner’s relection,” Technology in Society: in press. Canada Nova Scotia Ofshore Petroleum Board, 2002. Environmental Protection Board. White Page. http://www.cnsopb.ns.ca/Environment/evironment.html (Cited: April 21, 2002). EPA, 2000. “Development document for inal eluent limitations guidelines and standards for synthetic-based drilling luids and other non-aqueous drilling luids in the oil and gas extraction point source category.” United States Environmental Protection Agency. Oice of Water, Washington DC 20460, EPA-821-B-00-013, December 2000. Holdway, D.A., 2002. “he Acute and Chronic Efects of Wastes Associated with Ofshore Oil and Gas Production on Temperature and Tropical Marine Ecological Process.” Marine Pollution Bulletin , Vol. 44: 185–203. Hossain, M.E., Khan, M.I., Ketata, C. and Islam, M.R., 2009. “Sustainable Waterjet Drilling.” Journal of Nature Science and Sustainable Technology, article in press. Khan, M.I, and Islam, M.R., 2003a. “Ecosystem-based approaches to ofshore oil and gas operation: An alternative environmental management technique.” SPE Conference, Denver, USA. October 6–8, 2003. Khan, M.I, and Islam, M.R., 2003b. “Wastes management in ofshore oil and gas: A major Challenge in Integrated Coastal Zone Management.” ICZM, Santiago du Cuba, May 5–7, 2003. Khan, M.I., and Islam, M.R. 2005. “Assessing Sustainability of Technological Developments: An Alternative Approach of Selecting Indicators in the Case of Ofshore Operations.” ASME Congress, 2005, Orlando, Florida, Nov 5–11, 2005, Paper no.: IMECE2005-82999. Khan, M.I., and Islam, M.R., 2006. Achieving True Sustainability in Technological Development and Natural Resources Management. Nova Science Publishers, New York, USA, pp. 381. Khan, M.I., and Islam, M.R., 2008. Petroleum Engineering Handbook: Sustainable Operations. Gulf Publishing Company, Texas, USA, pp. 461. Khan, M.I, Zatzman, G., and Islam, M.R., 2005. “New sustainability criterion: development of single sustainability criterion as applied in developing technologies.” Jordan International Chemical Engineering Conference V, Paper No.: JICEC05-BMC-3-12, Amman, Jordan, 12–14 September 2005. Patin, S., 1999. Environmental impact of the offshore oil and gas industry . EcoMonitor Publishing, East Northport, New York. 425 pp. Veil, J.A., 2002. “Drilling Waste Management: past, present and future.” SPE paper no. 77388. Annual Technical Conference and Exhibition, San Antonio, Texas, 29 September–2 October. “Waste Management Practices in the United States,” prepared for the American Petroleum Institute, May 2002.

2 Drilling Methods 2.1 Introduction Drilling is one of the oldest technologies. Man used to dig a hole for diferent purposes. Until internal combustion engines were developed in the late 19th century, the main method for drilling rock was a muscle power of man or animal. Rods were turned by hand, using clamps attached to the rod. he rope and drop method was invented in Zigong, China where they used a steel rod or piston raised and dropped vertically via a bamboo rope. hese Chinese wells were drilled using bamboo derricks and reached depths of up to 4800 t. he irst rotary drilling rig was developed in France in the 1860’s. However, it was seldom used because it was erroneously believed that most hydrocarbons were under hard-rock formations that could be easily drilled with cabletool rigs. he rotary drilling system that circulates luid to remove the rock cuttings were successfully used in Corsicana, Texas in 1880’s where drillers searching for water, and fortunately they discovered oil. Since then, drilling rigs underwent a revolution of improvement in terms of drilling a well in good, safe and economic manner. here are four main procedures on how to select the appropriate drilling: i) wells design for the same ield, ii) the expected loads during drilling, iii) testing and any other related operations, and iv) compare the expected loads with the existing rigs and select the best rig and its appropriate components. Now days, there are a lot of types of drilling rigs classiied into two major types based on the drilling area environment which will be discussed in this chapter. his

17

18

Fundamentals of Sustainable Drilling Engineering

chapter focuses on the drilling methods used for hydrocarbon exploitation. his chapter covers the cable tool drilling rig, rotary drilling rig and its components, diferent rotary rig systems, types of rigs, current advancement of rig systems, and the knowledge gap that needs to be illed in this area. In all drilling methods a downward force has to be applied on the tool that breaks the rock, and therefore it is an important parameter for an efective drilling operation. In rotary drilling the cutting tool is the bit and the downward force is the weight of the drill string assembly applied on the bit. he conventional practice in the oil industry is to use heavy drill string assembly for which large capital expenses are required.

2.2 Types of Drilling Methods here are two basic methods to drill a hole for hydrocarbon withdrawal from an underground system. hese are: i) cable tool drilling, and ii) rotary drilling.

2.2.1 Cable Tool Drilling Cable tool drilling is deined as a drilling procedure in which a sharply pointed bit attached to a cable and is repeatedly lited and dropped into the borehole. In cable-tool drilling, a heavy carbide tipped drill bit (i.e. along with drill string) is suspended in the hole by a rope or cable. A powered walking beam is operated by a steam engine through which the cable and attached bit assembly are lowered and raised. his upward and downward motion is repeated again and again. he drill bit chisels through the rock by inely pulverizing the subsurface materials. Each time the bit drops it and hits the bottom of the hole and thus cuts the rock. However, the basic principles employed in all cable tool drilling operations virtually have been unchanged since the Chinese irst drilled shallow wells for salt water in the ancient days. he irst oil well in the United States was drilled with cable tools in 1859 to a depth of 65 feet located near Titusville, Pennsylvania. hen, it was widely used from about 1870 onward. he cable-tool drilling method was in common use until the 1920’s. Now days, cable tool is a traditional way of drilling water wells in diferent places on earth. he majority of the large diameter water supply wells are completed using this technique. While this drilling method has been replaced in recent years by modern rotary drilling, it is still the most practicable drilling method for large diameter, deep bedrock wells, and in widespread use for small rural water supply wells. A schematic diagram of cable tool rig is shown in Figure 2.1. he basic components of the cable tool rigs consist of the engine and boiler, the derrick and crown block, the bull wheel and drilling cable, the sand wheel and sanding line for the bailer, the vertical band wheel with a center crank, drill string and the walking beam supported by the Samson post. Band wheels are basically large pulleys (usually 8–10 t in diameter) driven by a belt from the engine, which reduces the engine RPMs and increases power. A crank on the band wheel’s axle imparts up-and-down motion (via a pitman) to the walking beam. he other end of the band wheel is connected to the drilling cable by the temper screw. he walking beam alternately raises and loweres the drilling

Drilling Methods 19 Crown Block Derrick

Drilling Cable Bailer Bull Wheel

Engine

Sand Reel

Calf Reel

Stem Bit

Figure 2.1 A conventional cable tool rig.

tools. Walking beams is typically 26' 12" 24 " in size. Bull wheels and sand wheels are spools for the drilling cable and sanding (or bailing) line, respectively. Additionally, ishing tools, various hand tools, wrenches, and forge tools are required for the drilling process. he drill string consists of the upper drill rods, a set of jars, and the drill bit. During the drill process, the drill string is periodically removed from the borehole and a bailer is lowered to collect the drill cuttings. Since the drill string must be lowered and raised to advance the boring, casing is typically used to hold back upper soil materials and stabilize the borehole. his technology has achieved vast improvements in rig mechanisms and labor-saving devices. Some of the examples are modern rotary drilling rigs, powered with an internal combustion engine, electric motor, or steam engine and most sophisticated rig related equipment/tools. However, there are two major disadvantageous of the cabletool method; irst, the drilling has to be stopped oten and the bit pulled up so that cuttings of chipped rock could be removed; second, this system has a hard time in drilling sot rock formations. he other disadvantages are: it is very slow, it does not efectively control subsurface pressures, and blowouts are common in cable tool operations.

2.2.2 Rotary Drilling Rotary drilling is a complex mechanical technique in which a drill bit is attached to the bottomhole assembly where rotational motion is applied to cut the rock in a forward direction. Rotary drilling is new as compared to cable tool drilling. he irst rotary drilling rig was developed in France in the 1860’s. At the time, it was believed that most hydrocarbons were under hard-rock formations that could be easily produced by the cable-tool rigs. he irst rotary drilling rigs were introduced in 1890 to cut sot formations where cable-tool drilling was extremely ineicient due to caving. However, the rotary drilling system that circulates luid to remove the rock cuttings was irst successfully used in Corsicana, Texas in the early 1900 to get water. he irst major success for rotary drilling was at Spindletop, Texas in 1901 where oil was discovered at a depth of 1020 t and produced about 100,000 bbl/day. With time, the improvement of design of

20

Fundamentals of Sustainable Drilling Engineering

(a) A picture of an onshore rotary rig

(b) A picture of an onshore rotary rig

Figure 2.2 A conventional rotary drilling rig.

rotary drilling system made it easy to bore a hole up to a depth of 30,000 t. he conventional rotary drilling rigs for an onshore (Figure 2.2a) and an ofshore (Figure 2.2b) are shown in Figure 2.2. In the rotary drilling method, a large, heavy drill bit is attached to the tip of the bottomhole assembly where a downward force is applied. he bit is rotated by a drill string composed of high quality drill pipe and drill collar. New sections of drill pipe assembly are added at the top of the hole as drilling progresses. he taller the rig structure, the longer the drill pipe sections that can be strung together. When it is time to replace the drill bit, the whole drill string must be pulled out of the hole. Each pipe is unscrewed and stacked on the rig loor. he cuttings are lited from the bore hole by injecting drilling luids (drilling mud) through drill pipe and bit nozzles. he drilling luid is collected at the surface and passes through diferent tanks and separators to treat the mud properly. Once the mud is ready, the cycle repeats again.

2.3 Rotary Drilling Rig and its Components A drilling rig is a complex assembly of large heavy anchored to a mechanical structure (Figure 2.3). he igure shows the diferent components of the rig above the ground level. Its basic function is relatively simple. he rig structure is a giant crane for liting and lowering drill pipe, with a rotary table to rotate the drill pipe. he function of rig is to rotate a string of drill pipe and drill a hole in the ground. It must also pull the drill pipe out of the hole for drill bit changes and run the pipe back into the hole. he drilling rig must be able to perform some other functions such as circulating drilling luid to clean the well bore and support the weight of the drill string so that the weight on the bit can be controlled (Figure 2.4a and b). he igure shows the diferent components that are underneath the rotary table along with other components above the rotary

Drilling Methods 21 Crown Block Runaround

Gin Pole Monkey Board Jack Knife Derrick Traveling Block Hook Swivel Bail

Gooseneck Rotary Hose Stand Pipe

Swivel Drilling Line

Kelly

A-Frame

Cat Head Rotary Table Rotary Drive Derrick Floor Hydromatic Brake Compound

Draw Works Dog House Draw Works Drive Diesel Engine Pump Drive Substructure Mud Pump

Shale Shaker Mud Tanks

Figure 2.3 A conventional rotary drilling rig with diferent components.

Crown Block

Crown Block Derrick

Safety Platform

Drilling Line

Block & Tackle Monkey Board

Stand Pipe Traveling Block Hook Swivel

Mud Hose

Suction Pipe Vibrating Screen

Mud Returns

Mud Ditch

Mud Pump Draw Works

Stand Pipe

Kelly Weight Recorder Bell Nipple Rotary Table Blowout Derrick Floor Blow-Out Prevent Preventer Cellar Emergency Flow Line Conductor Cement

Engine House

Suction Pit

Rotary Hose Swivel

Bore Hole

Mud Pump

Drill Pipe

Conductor Casing Annulus

Downward Mudstream Drilling Pipe Drill Collars

Rising Mudstream Bit

(a)

Earth Pit

Bit

(b)

Figure 2.4 A conventional rotary drilling rig showing diferent components under rotary table.

22

Fundamentals of Sustainable Drilling Engineering 1. 2. 3. 4. 5. 6. 7. 8. 9. 10. 11. 12. 13. 14. 15. 16. 17.

Crown Block Assembly Catline Boom and Hoist Line Drilling Line Monkey Board Traveling Block Top Drive (Power Swivel) Mast Drill Pipe Doghouse Blowout Preventer Control Unit (Accumulator) Water Tank Electric Cable Tray Engine-Generator Sets Fuel Tank 10 Mud Pump Mud Tank Pit Reserve Pit

18. 19.

1

2 4

3

5

6

13

9

12

8

20

19

46 46. 47. 48. 49. 50.

22 17

48 49

Degasser Desander Desilter Centrifugal Pumps Mud Agitators

16

21

26

47

18 15

11

23

50

14

7

25 24

20. 21. 22. 23. 24. 25. 26.

Electrical Control (SCR) House Bulk Mud component Tanks (P-Tanks) Mud-Gas Separator Shale Shakers Choke Manifold Pipe Ramp Catwalk Pipe Rack Pipe on Rack

32 31

33 27 28

27. 28. 29. 30. 31. 32. 33.

Hook Swivel Kelly Rotary Table Assembly Drawworks Stand pipe Rotary (Kelly) House

29 30

Figure 2.5 A modern rotary drilling rig and its components.

table. In general, the equipment that are used to drill and complete a hydrocarbon well are usually quite simple. Whether the drilling rig is ofshore or onshore, they all have the same basic structure and use the same equipment. A detail rotary rig devices and its diferent components are illustrated in Figure 2.5. Almost all the parts of a modern rig are leveled in Figure 2.5. A detail rig components names and their description are shown in this igure separately. he deinitions and their descriptions are illustrated in Appendix 2A at the end of this chapter.

2.4

Drilling Process

When all the necessary equipment and the drilling rig are in place, the drilling processes start on for drilling activities. he drilling process entails several diferent systems which are interconnected and drives the whole drilling operations. he process can be categorized as i) power system, ii) hoisting system, iii) circulation system,

Drilling Methods 23 and iv) rotary system. Sometime these systems are called drilling process subsystem. Most of rig components are engaged with one or more of these systems that are shown in Figure 2.5. his igure show the conventional rotary drilling process along with associated rig components related to the diferent systems.

2.4.1 Power System he major components of the power system are the drawworks, mud pumps and rotary table are shown in the rig system (Figure 2.6). he individual components of the circulating system are shown in Figure 2.7. he diesel engine set is shown in Figure 2.8 which transmits power to the three major systems of the rig. Most of the rig power is consumed by the hoisting and circulating system. he other rig systems (such as rotary rig etc.) have much less power consumptions. he hoisting and circulating systems do not generally work at the same time. Power is supplied by large internal combustion engines (prime over) fueled by diesel. Depending on its size and capacity, the rig may

Block & Tackle

Traveling Block Hook Swivel Kelly

Engine House

Rotary Table

Mud Pump Drawworks

Drilling Pipe

Bit

Figure 2.6 Major components of power system shown in the rig system.

Drawworks

Rotary table

Mud Pump

Figure 2.7 Major components of power system.

24

Fundamentals of Sustainable Drilling Engineering Diesel Engines Provide Power for the Rig

Diesel Engines

Figure 2.8 he generator set for power system.

have up to 4 prime movers which deliver more than 3,000 hp. A typical prime mover with generating set is shown in Figure 2.8. he diesel engines drive large electric generators. Electricity is then supplied to electric motors connected to the Drawworks, rotary table and mud pumps. Steam power and mechanical transmission systems were used on the early drilling rigs. Steam power and mechanical transmission systems were being used by the older rigs. Nowadays, modern rigs are powered by internal combustion diesel engines and the modern electric transmission enables the driller to apply power more smoothly and hence it avoids shock and vibration of the rigs. Total power requirements for most of the modern rigs are from 1,000 to 3,000 hp. Generally, the characteristics of power system performance are stated in terms of output horsepower, torque, and fuel consumption for various engine speeds. he heating values of various fuels for internal combustion engines are shown in Table 2.1. A typical arrangement of an engine with lywheel and pulley system is shown in Figure 2.9. he shat power developed by an engine can be obtained by the following equation:

Ps

T

(2.1)

where; Ps = Shat power developed by an IC engine, hp T = Output torque, ft lb f = Angular velocity of the shat, rad/min Equation (2.1) can be written in terms of revolution per minute, weight on pulley and distance travel by the weight with velocity vector. In terms of revolution per minute, Eq. (2.1) can be written as:

Ps

T

2 N

WrFW

2 rFW NW

(2.2)

In terms of velocity vector and if we consider frictionless pulley system, Eq. (2.1) can be written as:

v

2 rFW N

(2.3)

Drilling Methods 25 Table 2.1 Heating values of various fuels. Fuel Type

Density lbmgal

Heating value (btu/lbm)

Natural gas

1.07

1,030 btu/t3

Propane

4.22

2,500 btu/t3

Methane

3.54

24,000 (or 1,000 btu/t3)

Landill gas

–

500 btu/t3

Butane

4.7

21,000 (or 3,200 btu/t3)

Methanol

6.63

57,000 btu/gal

Ethanol

6.61

76,000 btu/gal

Kerosene

6.68

135,000 btu/gal

Diesel

7.2

19,000 (or 138,500 btu/gal)

Gasoline

6.6

20,000 (or 125,000 btu/gal)

Frictionless Pulley

Fly wheel

I C Engine

r

Engine Stand W Weight

Figure 2.9 A typical IC engine power output.

We know that power is the product of force and velocity. So, power of shat can again be written as:

Ps

Wd t

W.v

where; d = distance travel by the weight on pulley, t N = revolution per minute, rpm t = time required to travel the distance, d, min W = Weight on pulley, lb f

(2.4)

26

Fundamentals of Sustainable Drilling Engineering v = velocity vector, t/min rFW = Radius of ly wheel, t

If we use the Eq. (2.3) into Eq. (2.4), the resultant equation turns to Eq. (2.2). he overall engine power eiciency is determined as the power output by power input. Mathematically, it can be written as: ps

Power output Power input

Ps Qi

Ps wf Hf

(2.5)

where; ps = Overall engine eiciency of the power system Qi = power input to the IC engine, hp w f = the rate of fuel consumption by the engine, lbm / min H f = heating value of fuel used in the engine, Btu / lbm Example 2.1: An internal combustion engine is run by diesel fuel in a rig side to generate power for the system. It gives an output torque of 1,600 ft lb f at an engine speed of 1,150 rpm. he engine consumes fuel at a rate of 30 gal/hr. Calculate the wheel angular velocity, power output, overall eiciency of the IC engine. Solution: Given data: T = Output torque = 1,600 ft lb f N = revolution per minute = 1,150 rpm w f = the rate of fuel consumption by the engine = 30 gal/hr Required data: = Angular velocity of the shat i.e. wheel angular velocity, rad/min Ps = Shat power developed by an IC engine i.e. power output, hp ps = Overall engine eiciency of the power system i.e. IC engine, % he angular velocity can be calculated by using the given equation:

2 N =2

1,150 = 7,225.68 rad/min

he power output can be calculated using Eq. (2.1) as:

Ps

T

7,225.68 rad / min

1,600 ft lb f

33,000 ft lb f / min

350.34 hp

hp (Note: 1hp 33,000 ft lb f / min) is 7.2 Since the engine is run by diesel fuel, therefore from Table 2.1, the density lbm / gal and the heating value H f is 19,000 Btu / lbm. herefore the fuel consumption rate w f can be obtained by unit conversion as:

Drilling Methods 27

wf

30 gal / hr

1hr 60 minute

7.2 lbm / gal

3.6 lbm / min

herefore, the total heat energy consumed by the IC engine i.e. input power can be calculated by using input power part of Eq. (2.5) as:

Qi

3.6 lbm / min

wf Hf

19,000 Btu / lbm

779 ft lb f / Btu

33,000 ft lb f / min hp = 1,614.65 hp

(Note: 1 Btu 779 ft lb f ) hus, the overall eiciency of the IC engine is obtained by using the Eq. (2.5) as: ps

Power output Power input

Ps Qi

350.34 1,614.65

0.2168 or 21.68%

Example 2.2: A diesel engine was running at a speed of 1250 rpm at the drilling operations side. he driller noticed that the engine shat output is 360 hp. He was trying to pull a drillstring of 600,000 lb f . he engine was running for one hour. Calculate the wheel angular velocity, torque developed by the engine, the drillstring velocity, distance travelled by the drillstring. Solution: Given data: N = revolution per minute = 1,250 rpm W = Weight on pulley = 600,000 lb f Ps = Shat power developed by an IC engine i.e. power output = 360 hp t = time required to travel the distance, d = 1 week Required data: = Angular velocity of the shat i.e. wheel angular velocity, rad/min T = Output torque, ft lb f v = the drillstring velocity i.e. velocity vector, t/min d = distance travel by the weight on pulley, t he angular velocity can be calculated by using the given equation:

2 N =2

1,250 = 7,854 rad/min

he torque output is obtained using Eq. (2.1) as:

T

Ps

360 hp

33,000 ft lb f / min / hp 7,854 rad / min

1,512.61 ft lb f

28

Fundamentals of Sustainable Drilling Engineering

(Note: we know that 1hp 33,000 ft lb f / min) he drillstring velocity can be calculated using the Eq. (2.4) as:

v

360 hp

Ps W

33,000 ft lb f / min / hp 600,000 lb f

= 19.8 t/min

As the engine was running for one hour, so the total distance traveled by the drill string within one hour is obtained by using Eq. (2.4) as:

Wd t

W.v ;

d t

vt

19.8 ft / min

v

So,

d

1 hr 60 min

1188 t

2.4.2 Hoisting System Hoisting system is deined as a system which works as a complex pulley system to raise the travelling block and remove the drill pipe and allows adding an extra length of pipe or a new drill bit. he main function of the hoisting system is to lower or lit the drillstring, casing string, and other subsurface equipment into or out of the hole. In addition, making a connection (i.e. the periodic process of adding a new joint of drill pipe as the hole deepens), and making a trip (i.e. the process of removing the drillstring from the hole to change a portion of the downhole assembly and then lowering the drillstring back to the hole bottom) are the two regular tasks that need to be done by hoisting system. he main components of hoisting system are derrick (i.e. steel tower/ mast) and substructure, drawworks, and block & tackle. he assembly and components of a hoisting system are shown in Figure 2.10. Derrick Crown Block

Drum

Drilling Line (8 lines are Strung

Dead Line

Fast Line

Traveling Block

Drawworks

Dead Line Anchor

Hook Drum Break

Load Indicator

Figure 2.10 Diferent components of hoisting system.

Storage Reel

Drilling Methods 29

Derrick: Derrick is the steel structure part of a rig. It provides vertical height required to raise pipe sections (Figure 2.11). It must have suicient height and strength to perform its functions. Derrick is rated according to its ability to withstand compressive loads & wind loads. he compressive load of a derrick is calculated as the sum of the strengths of the four legs. Each leg is considered as a separate column and its strength is calculated at the weakest section. he wind load is speciied in two ways, namely with or without pipe setback based on API derricks. he wind load can be calculated as:

Ww

0.004 V 2

(2.6)

where; 2 Ww = wind load, lb f / ft V = wind velocity, mph he total compressive load on derrick can be calculated using the block and tackle arrangement as shown in Figure 2.12. If the system has frictionless pulley, the following relationship is evident:

WD

n 2 Whl n

(2.7) Crown Block

Drilling Line

Fast Line

Derrick

Deadline

Traveling Block Hook

Drawworks

Deadline Anchor

Storage Reel

Figure 2.11 Derrick load system using block and tackle.

30

Fundamentals of Sustainable Drilling Engineering

Derrick Leg Tf Fast Line

Td Tf

Draw Works

Dead Line

Anchor D

whl

A

C

B

Figure 2.12 Derrick/mast of the hoisting system.

where; WD = total compressive load on the derrick, lb f n = number of drilling lines through the travelling block Whl = hook load, lb f Example 2.3: During a drilling rig structure fatigue test, the operator measured the wind load of 0.5 psi. he rig has ten lines which are strung through the travelling block. A hook load of 250,000 lbf is being hoisted. According to the API standard, calculate the wind velocity, and the total compressive load. Solution: Given data: Ww = wind load = 0.5 psi Whl = hook load = 250,000 lb f n = number of drilling lines through the travelling block = 10 Required data: V = wind velocity, mph T = total compressive load on the derrick, lb f he wind velocity can be obtained using Eq. (2.6) as:

V

2

Ww 0.004

0.5 lb f / in2

144 in2 /1 ft 2 0.004

Drilling Methods 31 (Note: we know that 1 ft 2 144 in2 ) herefore,

V

134 mph

he total compressive load on the derrick is obtained using the Eq. (2.4) is:

WD

n 2 Whl n

10 2

250,000 10

= 300,000 lb f

he load imposed on the derrick i.e. the total compressive load on derrick is greater than the hook load due to the arrangement of lines on the block and tackle (Figure 2.12). herefore, using the fast line and dead line tension, the derrick load can also be calculated by:

Derrick load = hook load + Fast line load + dead line load WD

Whl T f

(2.8)

Td

where; T f = tension (i.e. load) in the fast line, lb f Td = tension (i.e. load) in the dead line, lb f In practical situation, the total derrick load is not distributed equally over all four derrick legs due to the placement of drawworks. Figure 2.12 shows that the tension in the fast line is distributed over only two of the derrick legs (i.e. legs A and C) and the dead line afects only Leg D due to its attachment with this leg only. Table 2.2 shows the load distribution for each leg where it is assumed that the four legs of the derrick are in equal distance.

Table 2.2 Derrick leg load distribution. Load on each derrick leg Load source

Total load

Leg A

Leg B

Leg C

Leg D

Hook load

Whl

Whl /4

Whl /4

Whl /4

Whl /4

Fast line

Tf

T f /2

–

T f /2

–

Dead line

Td

–

–

–

Td

Total load on each derrick leg

Whl /4

T f /2

Whl /4

Whl /4

T f /2

Whl /4 Td

32

Fundamentals of Sustainable Drilling Engineering

he distribution of total load on each leg shows that leg D has more load as compared to the other three legs. It is evident that if one leg fails, the entire derrick also fails, therefore, it is necessary to deine a maximum equivalent derrick load WDmax as the load which is equal to four times the maximum leg load. So, the maximum equivalent derrick load can be written as:

WDmax

Whl / 4 Td

4

(2.9)

Sometimes, a parameters named as derrick eiciency, is used to evaluate various drilling line arrangements. Derrick eiciency is deined as the ratio of the actual derrick load to the maximum equivalent load given by Eq. (2.9) which is written as: D

WD WDmax

WD Whl / 4 Td

4

(2.10)

Drawworks: A powerful drawworks and a pulley system attached to the derrick are used to continue its smooth operations. It is essentially a large winch that spools of or takes in the drilling line. he main function of the drawworks is to provide the hoisting and braking power required to raise or lower the heavy strings of pipe (drill pipe, casing pipe etc.). he main components of drawworks are drum, break, transmission, and cathead (Figure 2.13). he large revolving drum transmits torque required for hoisting and breaking. It also rolls the drill line (a wire rope). It has a catshat where the catheads

Figure 2.13 Drawworks assembly

Drilling Methods 33 Derrick Drilling Line (8 lines are Strung) Fast Line

Crown Block Dead Line nTf n=4

Drum

Traveling Block Dead Line Anchor

Storage Reel

Hook Whl Drum Break Drawworks Load Indicator

Figure 2.14 Block & tackle arrangement for the hoisting system.

are mounted. he driller controls the drawworks by applying a main brake as well as auxiliary brakes to assist during drilling operations.

Block & tackle: Components of block & tackle are crown block, traveling block, and drilling Line (Figure 2.14). he crown block is a large set of pulleys (sheaves) ixed to the top of the derrick (Figure 2.15a). he drilling line is threaded over the crown block down to another set of pulleys that are known as the travelling block (Figure 2.15b). Travelling block suspends a large hook with a snap shut locking device (Figure 2.14). his hook accepts the bail of the swivel when the rig is in drilling operations. In addition, it takes the weight of the drill string. he elevators are also attached to the travelling block. hese synchronizing components are used when drill string is running in or pulling out of the hole. A set of clamps are fastened around the drill pipe below a tool joint. Once the elevators are latched, the drill string can be raised by pulling three joints of drill pipe at a time. One end of the drilling line is secured to an anchorage point somewhere below the rig loor (Figure 2.14). his drilling line is called deadline since it does not move. he other end of the drilling line is wound on to the drawworks and is called the fast line (Figure 2.14). he drilling line is usually rolled several times around the blocks to take heavy loads (eight or ten lines are in common). he wire rope does not wear uniformly over its entire length. he most severe wear occurs at the pickup points, where the rope passes over the top of the crown block sheaves during trips. To maintain the drilling line in good condition a slip and cut program is regularly carried out. his is done by unclamping the deadline anchor, removing some line from the drawworks, replacing it with some line led through from the reserve drum. To assess the amount of wear on the drilling line a Ton-miles calculation is made. he stands must be racked by the derrick man standing on the monkey board about 95 t above the rotary table. he selection of suitable rig generally involves matching derrick strength and the capacity of the

34

Fundamentals of Sustainable Drilling Engineering

(a) Crown block

(b) Travelling block

Figure 2.15 Crown block and travelling block for the hoisting system. n Tf

Drilling line n=4

Travelling block Hook

Whl

Figure 2.16 Travelling block diagram for force analysis.

hoisting gear. Consideration must also be given to mobility and climate conditions. he standard derrick measures 140 t high, 30 t square base, and is capable of supporting 1,000,000 lbs of weight. he main function of block & tackle is to provide the mechanical advantage which allows drillers to handle a large amount of loads easily. It is deined as the load supported by the travelling block to the load imposed on the drawworks. As Figure 2.16 shows the hook load is completely carried over by the travelling block, and the load imposed on the drawworks is equal to the tension in the fast line, therefore mathematically the mechanical advantage can be written as:

Madv

Whl Tf

(2.11)

where; Madv = mechanical advantage he ideal mechanical advantage that assumes no friction in the block and tackle can be determined from a force analysis of the travelling block (Figure 2.16). If it is assumed that there is no friction in the system, the tension in the drilling line would remain same all through block – pulley – drawworks. hus the forces acting on the travelling block can be written as:

forces Tf

0 or, Whl nTf Whl n

0 (2.12)

Drilling Methods 35 where; n = number of lines strung through the travelling block Now, the ideal mechanical advantage can be derived using the Eq. (2.12) into Eq. (2.11) yielding:

Whl Whl / n

Miadv

(2.13)

n

Equation (2.13) shows that ideal mechanical advantage is equal to the number of drilling lines strung to the travelling block and crown block. he use of six, eight, ten and twelve lines is common, depending on the loading condition. he power of the block and tackle can be deined as the work done per unit time. hus, the input power of the block and tackle is measured as the drawworks load (i.e. fast line tension) multiplied by the fast line velocity, mathematically:

Pibt

(2.14)

Tf v f

where; Pibt = input power of the block and tackle, hp v f = velocity of the fast line, ft / min Accordingly, the output power or hook power can be measured as the traveling block load (i.e. hook load) times the velocity of the traveling block.

Poutbt

(2.15)

Whl vbt

Where; Poutbt = output power of the block and tackle, hp vbt = velocity of the traveling block, ft / min Equation (2.12) shows that Whl T f n for a frictionless block and tackle. Since the unit distance movement of the fast line tends to shorten each of the lines strung between the crown block and traveling block only by 1/ n times the unit distance, then the traveling block velocity can be calculated using the following relation:

vbt

vf

(2.16)

n

Now the eiciency of the frictionless block and tackle can be obtained as the ratio of output power to input power. hus, dividing Eq. (2.15) by Eq. (2.14) and substituting Eq. (2.16) and hook load, the following unity of eiciency is obtained:

Poutbt bt

Pibt

Whl vbt Tf v f

Tf n Tf v f

vf n

1

(2.17)

36

Fundamentals of Sustainable Drilling Engineering

However, in practical situation, there is no such frictionless system and there is always some loss of power due to friction. he approximate block and tackle eiciency can be characterized by a relationship, bt e n 0.98n. herefore, the actual block and tackle eiciency can be obtained using the actual tension in the fast line for a given hook load. As a result, the following mathematical relationship is obtained:

Poutbt bt

Whl

Whl vbt Tf v f

Pibt

vf n

Whl Tf n

Tf v f

(2.18)

Equation (2.18) lead to ind out the fast line tension in terms of hook load and block and tackle eiciency as:

Whl bt n

Tf

(2.19)

Equation (2.19) can be used to select drilling line size. Since there is a line wear and shock loading condition, a safety factor is needed to be considered. he tension in the deadline can be obtained by Td Whl / n because the friction in the stacks will not afect the deadline. Substituting Eq. (2.19) and Td in Eq. (2.8), the following relationship is obtained:

WD

Whl

1

Whl Whl n bt n

bt bt

bt

n

(2.20)

Whl

n

Again the maximum derrick load can be obtained by substituting Td Whl / n in Eq. (2.9) yield:

WDmax

Whl 4

Whl n

4

n 4 Whl n

(2.21)

Again substituting Eq. (2.20) and Eq. (2.21) in Eq. (2.10), the derrick eiciency becomes:

1 D

WD WDmax

bt bt

bt

n

n

n 4 Whl n

Whl

n 1

bt bt

n 4

1

(2.22)

Example 2.4: he total weight of 9,000 t of 9 5/8-inch casing for a deep well is determined to be 400,000 lbs. Since this will be the heaviest casing string run, the maximum mast load must be calculated. Assuming that 10 lines run between the crown and the traveling blocks and neglecting buoyancy efects, calculate the maximum load. Solution: Given data: Whl = hook load = 400,000 lb f

Drilling Methods 37 Lc = length of casing = 9,000 t ODc = outer diameter of casing = 9 5/8 in n = number of drilling lines through the travelling block = 10 Required data: WDmax = Maximum derrick load, lb f If frictionless pulley and block and tackle system is used, the fast line tension can be calculated using Eq. (2.12) as:

Tf

400,000 lb f 10

40,000 lb f

If we consider that the deadline has also the same tension, the maximum derrick load can be obtained using the Eq. (2.9) or Eq. (2.21) as: Eq. (2.9): WD

max

Eq. (2.9): WDmax

Whl / 4 Td

n 4 Whl n

4

400,000 40,000 4

10 4 10

4

560,000 lbf

400,000 lb f = 560,000 lbf

his example demonstrates two additional points – the marginal decrease in mast load decreases with additional lines, and the total mast load is always greater than the load being lited. Example 2.5: he hoisting system of a rig derrick has a load of 350,000 lb f . he input power of the drawworks for the rig can be a maximum of 530 hp. Eight drilling lines are strung between the crown block and traveling block. Assume that the rig loor is arranged as shown in Fig. 2.9. Consider there is some loss of power due to friction within the hoisting system. Compute (1) the static tension in the fast line when upward motion is impending (2) the mechanical advantage of the block and tackle (3) the maximum hook horsepower available (4) the maximum hoisting speed (5) if a 90 t stand is required to be pulled, what should be the required time (6) the actual derrick load (7) the maximum equivalent derrick load (8) the derrick eiciency factor. Solution: Given data: Whl = hook load = 350,000 lb f Pibt = input power of the block and tackle = 530 hp n = number of drilling lines through the travelling block = 8 Ls = length of stand = 90 t Required data: Tf = tension (i.e. load) in the fast line, lb f Madv = mechanical advantage Poutbt = output power of the block and tackle, hp

38

Fundamentals of Sustainable Drilling Engineering vbt t WD WDmax D

= velocity of the traveling block, ft / min = time, min = actual load on the derrick, lb f = Maximum derrick load, lb f = derrick eiciency, %

(1). As the system is not frictionless, then irst we need to calculate the hoisting eiciency for eight numbers of drilling lines. he approximate block and tackle eiciency can be characterized by the following relationship:

0.98n 0.988

en

bt

0.851

herefore, the static tension in the fast line can be obtained using Eq. (2.19):

Whl bt n

Tf

350,000 lb f 0.851 8

51,410 lbf

(2). he mechanical advantage of the block and tackle is given by Eq. (2.11) as: Madv

350,000 lb f

Whl Tf

51, 410 lb f

6.81

(3). he maximum hook horsepower available can be obtained applying Eq. (2.17) as:

Poutbt

bt

Pibt

0.851 530 = 451.03 hp

(4). he maximum hoisting speed is the maximum velocity of the block and tackle that can be attained by the available hook power. herefore the maximum velocity can be obtained by using Eq. (2.15) as:

vbt

33,000 ft lb f / min

451.03 hp

Poutbt

hp 350,000 lb f

Whl

= 42.53 ft /min

(5). To pull a 90 t long stand, the time required can be estimated using the deinition of speed as:

t

Ls vbt

90 ft = 2.12 min 42.53 ft / min

(6). he actual derrick load is given by Eq. (2.20):

WD

1

bt bt

bt

n

n

Whl

1 0.851 0.851 8 0.851 8

350,000 lb f

Drilling Methods 39

= 445,160.1 lb f (7). he maximum derrick load can be obtained by using Eq. (2.21) as:

n 4 Whl n

WDmax

8 4 8

350,000 lb f = 525,000 lbf

(8). he derrick eiciency is given by Eq. (2.22): D

WD WDmax

445,160.1 lb f 525,000 lb f

= 0.8479 = 84.8%

Example 2.6: A diesel engine is run to generate power for the rig system. It gives an output torque rating of 1,500 ft lb f at an engine speed of 1,170 rpm. Consider that there is a friction loss in the pulley and block and tackle system. he hook load of the rig is 580,000 lb f and there are ten drilling lines strung on the system. Find the output power of the engine, velocity of the fast line, tension of the fast line, velocity of the travelling block, power output of the block and tackle, eiciency of block and tackle. Solution: Given data: T = Output torque = 1,500 ft lb f N = revolution per minute = 1,170 rpm Whl = hook load = 580,000 lb f n = number of drilling lines through the travelling block = 10 Required data: Ps = Shat power developed by an IC engine i.e. power output, hp T f = tension (i.e. load) in the fast line, lb f v f = velocity of the fast line, ft / min vbt = velocity of the traveling block, ft / min Poutbt = output power of the block and tackle, hp = eiciency of the block and tackle, % bt he angular velocity can be calculated by using the given equation: 2 N =2

1,170 = 7,351.34 rad/min

he power output can be calculated using Eq. (2.1) as:

Ps

T

7,351.34 rad / min

1,500 ft lb f

33,000 ft lb f / min

334.15 hp

hp (Note: 1hp 33,000 ft

lb f /min)

If we consider that this engine power output will be only engaged by the hoisting system and there is no friction loss on the pulley, this engine power output would be

40

Fundamentals of Sustainable Drilling Engineering

considered as the power input for the block and tackle (Pibt ). So, Pibt = 334.15 hp. Tension in the fast line can be obtained using Eq. (2.12) as:

Tf

580,000 lb f

Whl n

= 58,000 lb f

10

Using Eq. (2.14), the velocity of the fast line can be obtained as:

vf

Pibt

334.15 hp

33,000 ft lb f /min hp

= 190.12 ft /min

58,000 lb f

Tf

Equation (2.16) is used to calculate the velocity of travelling block as; vf

vbt

190.12 ft / min = 19.0 ft /min 10

n

he output power or hook power can be measured as the traveling block load (i.e. hook load) times the velocity of the traveling block i.e. using Eq. (2.15) as: Poutbt

580,000 lb f

Whl vbt =

19.0 ft / min

33,000 ft lb f / min

= 333.94 hp

hp he eiciency of the block and tackle can be given by Eq. (2.18) as: Poutbt bt

Pibt

333.94 hp = 0.99 = 99% 334.15 hp

Just to cross check, if we use the relationship as bt en 0.98n 0.9810 0.817 81.7%

bt

en

0.98n for the eiciency, it becomes

2.4.3 Circulation System he circulating system is like a close loop electric circuit through which drilling luid (i.e. mud) can travel from surface to all the way down hole and back to its initial point (i.e. mud pit). It goes from the mud pits to main rig pumps (i.e. mud pump), and then major components including surface piping, standpipe, kelly hose, swivel, kelly, drill pipe, drill collar, bit nozzles, the various annular geometries (annulus means space between drill pipe and hole) of the open hole and casing strings, low line, mud cleaning equipment, mud tanks, and again the mud pit/mud pump (Figure 2.17). It is obvious that the rock cuttings must be removed from the borehole to allow drilling to proceed. his is done by pumping drilling luid down the drillstring, through the bit and up the annulus. he cuttings are then separated from the mud, which is then recycled. he circulating system (i.e. drilling luid) also enables to clean the hole of cuttings made by the bit; to exert a hydrostatic pressure suicient to prevent formation luids entering the borehole; and to maintain the stability of the hole by depositing a

Drilling Methods 41 thin mud-cake on the sides of the hole. he main components related to the circulating system are mud pumps, mud pits, mud mixing equipment and contaminantremoval equipment (Figure 2.18). he detail equipment list for this system is shown in Figure 2.17 and Figure 2.18. Drilling luid is usually a mixture of water, clay, weighting material (barite) and chemicals. A variety of mud are now widely used (i.e. oil base, invert oil emulsion). he mud must be mixed and conditioned in the mud pits, and then circulated by large pumps i.e. sludge pumps (Figure 2.19). A schematic diagram illustrating a typical rig circulating system along with its low direction is depicted in Figure 2.20. he mud is pumped through whole cycle as mentioned in the Figure 2.20. Once the mud comes back to the surface again, the solids must be removed and the mud is conditioned prior to being re-circulated. hese solids and some other contaminants are removed using shale shaker, desander, desilter, and degasser (Figure 2.21). he mud pit is usually a series of large steel tanks, all interconnected and itted with agitators to maintain solids in suspension (Figure 2.22). Some pits are used for circulating (i.e. suction pit) and others for mixing and storing fresh mud. Most modern rigs have equipment for storing and mixing bulk additives (i.e. barite) as well as chemicals (both granular and liquid). he mixing pumps are generally high volume, low discharge centrifugal pumps (Figure 2.18). At least two sludge pumps are installed on the rig. At shallow depths they are usually connected in parallel to deliver high low rates.

Swivel

CIRCULATION SYSTEM

Rotary House

Stand Pipe Discharge Line

Mud Tank

Kelly

Suction Line

Drill Pipe

Degasser

Mud Pump

Desilter Return Line

Desander

Annulus Shale Shaker

Steel Tank

Drill Collar Drill Bit

Figure 2.17 Diferent components showing rig circulating system.

42

Fundamentals of Sustainable Drilling Engineering Bulk Storage Mixing Hopper Mud Pump Centrifugal Pump

Desilter Desander

Standpipe

Degasser Chemical Tank

Swivel Earthen Pits

Drill String

Shale Shaker

Steel Tank Annulus Bit

Figure 2.18 Diferent components showing rig circulating system with cleaning equipment.

Figure 2.19 A typical mud pump.

Positive displacement pumps are used (reciprocating pistons) to deliver high volumes at high discharge pressures. he discharge line from the mud pumps is connected to the standpipe, a steel pipe mounted vertically on one leg of the derrick. A lexible rubber hose (i.e. kelly hose) connects the top of the stand pipe to the swivel via the gooseneck (Figure 2.3). Once the mud has been circulated round the system it will contain suspended solids, perhaps some gas and other contaminants. hese must be removed before the mud is recycled. he mud passes over a shale shaker, which

Drilling Methods 43

Mud Pump

Mud Tank Degasser

Rotary Hose

Desilter

Stand Pipe

Desander

Earthen Pit

Bell Nipple Blowout Preventer Emergency Flow Line

Shale Shaker Conductor Casing

Annulus Drill Pipe Drill Collars

Figure 2.20 A complete rig circulating system with rig itself.

Desander Shale Shaker

Desilter

Degasser

Figure 2.21 A typical photograph of shale shaker, desander, desilter, and degasser.

44

Fundamentals of Sustainable Drilling Engineering

Figure 2.22 A typical photograph of mud tank.

is basically a vibrating screen. his removes the larger particles, while allow the residue (underlow) to pass into settling tanks. he iner material can be removed using desanders, degassers, and centrifuges. If the mud contains gas from the formation it can be passed through a degasser which operates a vacuum, thereby separating the gas from the liquid mud. Having passed through all the mud processing equipment the mud is pumped to settling traps prior to being returned to the mud tanks for recycling. Another tank which is useful for well monitoring is the possum belly tank. his is calibrated to measure the luid displaced from hole while running in. If the level varies signiicantly from the expected level a pressure control problem can be identiied and necessary actions take place.

Mud pumps: As mentioned above, mud circulating pumps are used to circulate drilling luid at the desired pressure and volume. With some exception, mud pumps always have reciprocating positive–displacement pistons. Figure 2.19 depicts the conventional mud pumps used in the oil ield application. Two types of pumps are commonly used during rig operations based on site are duplex (two cylinder) and triplex (three cylinder) pumps. he duplex pumps are normally double action that pump on both forward and backward piston strokes and are generally used in onshore rigs. he triplex pumps are generally single action that pump only on forward piston strokes and are usually used in ofshore rig operations. A comparison of both duplex and triples pumps is shown in Table 2.3. he table shows that triplex pumps are more suitable than duplex pump. herefore majority of pumps used are in triplex type. he choice of reciprocating positive displacement pistons gives some additional advantages – it has ability to move high solids-content luids; ability to pump large particles; ease of operation and maintenance; reliability; ability to operate over wide range of pressures and low rates by changing diameters of the pump liners (compression cylinders) and diameter of pistons. However, the main disadvantage of these pumps is that the discharge low is pulsating, which causes periodic impact loads on discharge lines. his efect is minimized by air illed surge chambers located on the discharge line. Mud

Drilling Methods 45 Table 2.3 A comparison between duplex and triplex pumps. Duplex pump

Triplex pump

Heavy

Light

Bulky

More compact

High output pressure

Lower output pressure

More o/p pulsation

Less o/p pulsation

More maintenance

Less maintenance

Costlier to operate

Cheaper to operate

1" 18" 2 1" mud pump means that the pump has a piston diameter of (i.e. liner size) of 6 and 2 a stroke length of 18". In general, two circulating pumps are installed on the rig. For

pumps are commonly categorized by bore and stroke. As an example, an 6

the large hole sizes used on the shallow portion of most wells, both pumps can be used operated in parallel to deliver the large low rates required. On the deeper portions of the well, only one pump is required, and the second pump serves as a standby for use when pump maintenance is required. he overall eiciency of a mud-circulating pump can be calculated as the product of the mechanical eiciency and the volumetric eiciency. Mechanical eiciency Pmech is usually assumed as 90% which is related to the eiciency of the prime over itself and the linkage to the pump drive system. On the other hand, volumetric eiciency Pvol is usually as high as 100% if the suction of the pump is adequately charged. Most manufacturer speciications show that Pmech is 90% and Pvol is 100%. Figure 2.23 depicts the valve and cylinder arrangement of a double acting (Figure 2.23a) and a single acting (Figure 2.23b) pumps. he development of the theoretical performance of pumps is extremely important because proper pump selection and utilization is imperative to the over-all eiciency of drilling operations. he circulation requirements in the area of use should be carefully analyzed before the inal selection is made. Typical hydraulic calculations which emphasize this point will be discussed in Chapter 4. he theoretical displacement from a double-acting pump is a function of the piston diameter, the liner diameter, and the stroke length. herefore, on the forward stroke of each piston and liner system, the volume of liquid displaced is obtained by (Figure 2.23a):

VF 1

4

dl2 Ls

where, VF 1 = volumetric displacement of liquid for a forward stroke with one piston, dl = liner diameter, inch

(2.23) in3 stroke

Fundamentals of Sustainable Drilling Engineering Discharge P2

Discharge P2

Piston

Discharge P2

Piston Rod

dl

Piston

46

Piston Rod

dl

dpr Ls

Ls P1

P1

Suction

P1 Suction

Suction (a) Double acting pump

(b) Single acting pump

Figure 2.23 Valve and liner arrangement of mud circulating pumps

Ls = stroke length, inch Similarly, on the backward stroke of each piston and liner system (Figure 2.23a), the volume of liquid displaced is calculated by the following formula where the piston diameter circumferential volume is subtracted.

VB1

4

dl2 Ls

d 2pr Ls

4

4

dl2 d 2pr Ls

(2.24)

where, VB1 = volumetric displacement of liquid for a backward stroke with one piston, in3 stroke

d pr

= piston diameter, inch

herefore, for a double acting (duplex) pump having two cylinders, the total volumetric displacement of liquid per complete pump cycle is given by combining Eq. (2.23) and Eq. (2.24) as:

qD

VF 1 VB1

2

4

dl2 Ls

4

dl2 d 2pr Ls

Ls 2

2dl2 d 2pr

(2.25)

If the volumetric eiciency of pump ( p ) is considered, the total volumetric displacement per cycle can be written using Eq. (2.25) as:

qD

Ls 2

2dl2 d 2pr

p

(2.26)

Sometimes, the volumetric displacement per cycle is called pump factor. For N number of pump cycle, Eq. (2.26) can be written as:

qDN where,

Ls 2

p

2dl2 d 2pr

N

(2.27)

Drilling Methods 47 N = number of pump cycle i.e. revolutions per minute of crank =

piston strokes / min 4

Since both pistons make a stroke in each direction for each revolution of the crank, there are four individual piston strokes per crank revolution. herefore, for N revolution, Eq. (2.27) can be obtained as:

Ls

qDN

p

2dl2 d 2pr

2

4N

(2.28)

Now, pumps are commonly rated by hydraulic horsepower. If we assume that suction pressure is atmospheric, then work done per piston stroke can be calculated as:

WP

Pd

4

dl2 d 2pr

where, WP = work done per piston stroke, lb f Pd = discharge pressure, psig

Ls 12

(2.29)

ft

Since both pistons make a stroke in each direction for each revolution of the crank, there are four individual piston strokes per crank revolution. herefore, for N revolution, Eq. (2.29) can be obtained as:

WPN

Pd

4

Ls 12

dl2 d pr2

Where, WPN = work done per complete stroke, lb f

4N

(2.30)

ft

he power output for pump then can be obtained as:

Pd Pout p

4

dl2 d pr2

Ls 12

4N

Pd dl2 d pr2 Ls N 126050.4

33,000 ft lb f / min hp

(2.31)

mp

mp

Where, WPN = work done per complete stroke, lb f ft Pout p = output power for the duplex pump, hp mp = mechanical eiciency of the duplex pump, % For a mechanical eiciency of 85%, Eq. (2.31) can be reduced to the following equation:

Pout p

Pd dl2 d pr2 Ls N 107143

(2.32)

In general, pumps are rated for hydraulic horse power, maximum pressure, and maximum low rate. he following equation is used to calculate the pump horse power.

48

Fundamentals of Sustainable Drilling Engineering

Php

pq 1714

(2.33)

Where, Php = pump horse power, hp p = increase in pressure, psi, which cannot be more than 3,500 psi. q = low rate, gal/min As shown in Figure (2.23b) for a single acting pump (triplex), there is only one suction and delivery valve which means there is no backward displacement. herefore, the volumetric displacement by each piston stroke during one complete cycle is given by

qS

4

dl2 Ls

(2.34)

hus the volumetric displacement per cycle for a single-acting pump having three cylinders with volumetric eiciency becomes as: qST

3 2 d L 3 l s

(2.35)

p

For N number of pump cycle, Eq. (2.35) can be written as:

qSTN

3 2 dL 3 l s

p

(2.36)

N

Example 2.6: Calculate the liner size required for a double-acting duplex pump where rod diameter is 2.5 in, stroke length is 22 in stroke, pump speed is 70 strokes/min. In addition the maximum available pump hydraulic horsepower is 1200 hp. For optimum hydraulics, the pump recommended delivery pressure is 3,000 psi. Assume the volumetric eiciency of pump is 98%. Solution: Given data: d pr = piston rod diameter, inch = 2.5 in Ls = stroke length, inch = 22 in 4N = revolutions per minute of crank = piston strokes / min = 70 strokes/min Pout p = output power for the duplex pump, hp = 1200 hp Pd = discharge pressure, psig = 3,000 psi (here it is p for the pump) = volumetric eiciency of pump = 0.98 p Required data: dl = liner diameter, inch Using Eq. (2.26), the pump displacement for a duplex pump is given by

qD

Ls 2

2dl2 d 2pr

p

(22 in) 2

2dl2

2.5 in

2

0.98,

in3 stroke

Drilling Methods 49

33.85

2dl2

2.5 in

2

in3 stroke

1 gal 231in3

2dl2

2.5 in 6.82

2

,

gal stroke

(Note: 1 gal 231 in3 ) Using Eq. (2.28), the pump displacement for a duplex pump operating at 60 strokes/ min is given by

qDN

Ls

p

2dl2 d 2pr

2 17.6 dl2 55 gpm

2dl2

4N

2.5 in

2

,

6.82

gal stroke

60

stroke min

Equation (2.33) gives the pump displacement as

Php

pq 1714

1,200 hp

3,000 psi q 1714

q

685.6 gpm

heoretically, these two pump displacement is equal therefore,

qDN

q

17.6 dl2 55

685.6

d l = 6.49 in

2.4.4 Rotary System A rotary system is designed to give the continuous rotation from the surface to the drill string assembly to achieve bit rotation. his system includes all of the equipment used to attain bit rotation. here is a rotating machine (rotary table) on the rig loor, through which drillpipe is run. he drilling bit is screwed on (or made up) to the end of the drillpipe and lowered into the hole. As the hole gets deeper more sections of drillpipe are added to the drill string on surface. When the rotary table is engaged it rotates the pipe and the bit, which cuts away the rock at the bottom of the hole. A schematic diagram of diferent components of rotary system is shown in the Figure 2.24. he main components of rotary system include 1) swivel, 2) kelly, 3) rotary table 4) rotary drive, 5) drill pipe, and 6) drill collars. here are some other related components such as kelly bushing, kelly hose and bit etc. A set of slips is used to suspend pipe in the rotary table when making or breaking a connection. Slips are usually designed to have three hinged segments, which have a tapered inish outside. he inside has an uneven surface which grips the pipe. Two large wrenches (tongs) are used to break a connection. A stand of pipe is raised up into the derrick until the lowermost tool joint appears. he roughnecks drop in the slip to wedge and support the rest of the string. he breakout tongs are latched above the connection, the makeup tongs below the connection. Both tongs are usually connected by a chain to their respective catheads (the makeup cathead is usually on the driller’s side of the drawworks). With the makeup tong held in position, the driller operates the breakout tong and breaks the connection. To make a connection the makeup tong is put above, and the breakout tong below the connection. his time the breakout tong is ixed, and the driller pulls on the makeup

50

Fundamentals of Sustainable Drilling Engineering Drilling Line Traveling Block

Hook Hose Elevator

Goose Neck Swivel Kelly

Kelly Bushing Master Bushing

Figure 2.24 Diferent components of rotary system.

cathead until the connection is tight. Although the tongs are used to break or tighten up a connection to the required torque, other means are available to screw up the two joints prior to torquing up: • For making up the kelly the lower tool joint is ixed by a tong while kelly is rotated by a kelly spinner, using compressed air. • A tong may be clamped around the top tool joint while the table is rotated clockwise to unscrew the connection. • A drillpipe spinner (power tong) may be used to make up or backof a connection (powered by compressed air). • For making up some subs or special tools (i.e. MWD subs) a chain tong is oten used.

2.5 Types of Rotary Drilling Rigs A drilling rig is a steel structure with other equipment and rig components. here are many types and designs of drilling rigs based on equipment usages, geographical location of well, position and height of derrick, type of pipe used, and method of rotation. Drilling rigs can be classiied using any of the features. Broadly, it can be categorized as cable tool rig and rotary drill rig based on geographical location uses (Figure 2.25). Rotary drilling rigs can be further classiied into two broad categories as ofshore (i.e. marine) and onshore (i.e. land) rigs. Figure 2.25 depicts a more detailed classiication of the rigs that are used currently in drilling operations based on site. A schematic view of marine and land rigs are shown in Figure 2.26 and Figure 2.27. he primary purpose of ofshore rig is to set a well in the ofshore area. he key design features of ofshore rigs are portability and maximum water depth of operation. For an ofshore rig, the structure upon which wells produce is called as production platform.

Drilling Methods 51 Drilling rigs

Cable tool rigs

Rotary drilling rigs Onshore

Ofshore

Fixed platforms/ Bottom support

Floating

Conventional rigs

Mobile rigs

Jacknife Barge

Jackup Selfcontained

Platform

Semi-submersible Tendered

Figure 2.25 Diferent types of rotary drilling rigs.

Figure 2.26 Ofshore rigs.

Figure 2.27 Onshore rigs.

Drillship

Portable mast

52

Fundamentals of Sustainable Drilling Engineering

Figure 2.28 Structure rigs.

A ixed platform or structured rig is an immobile of shore structure from which development wells are drilled and produced (Figure 2.28). It is mounted on ixed platform where drilling equipment are secured on the deck. Platform rigs may be built of steel or concrete and may be either rigid or compliant. Rigid platform rigs, which rest on the sealoor, are the caisson-type platform, the concrete gravity platform, and the steeljacket platform. hese are capable of being set in water depths of 10' 850'. hese types of ixed platforms are used to drill development (directional) wells from one location. he loating type rig is a loating vessel upon which a drilling rig sits where sometime a semi-submersible rig or drillships take the place for ofshore drilling. he jack-up rig is a type of mobile platform for ofshore drilling which is capable of standing on sea loor (Figure 2.29). It is also supported by the mat and provides a stable base for drilling of oil and gas exploration and production wells. It can have several supporting legs such as three, four or more. In general, four suction piles are located at corners of the mat to restrict the movement of the rig and maintain positioning during strong current lows and wave impacts. It can be towed on location and few are self-propelled. It is capable of working in water depths of 30' 350' with a drilling depth of up to 9500'. A Tension Leg Platform (TLP) or Extended Tension Leg Platform (ETLP) is a vertically moored loating platform held in place by an anchor system (Figure 2.30). he TLP’s are similar to conventional ixed platforms except that the platform is maintained on location through the use of moorings held in tension by the buoyancy of the hull. TLP is used where water depths DW are within the range of 1000' DW 4,900' . he anchor system is a set of tension legs (also called set of tethers) or tendons attached to the platform of TLP. hese legs are connected to a template or foundation on the sealoor. he template is held in place by piles driven into the sealoor. his method restricts the vertical motion of the platform. On the other hand, it allows for horizontal movements. he topside facilities (processing facilities, pipelines, and surface trees) of

Drilling Methods 53

Figure 2.29 Jackup rigs.

the TLP and most of the daily operations are the same as for a conventional platform. TLPs have been used since the early 1980s. he irst TLP was built for Conoco’s Hutton ield in the North Sea in the early 1980s. Semisubmersible drilling rig is a loating ofshore drilling unit (Figure 2.31). It has pontoons and columns that help to lood which causes the unit to submerge in ' water to a predetermined depth. It is capable of drilling in water depths of 20 7000' or more. he necessary oice space, limited residential space and storage etc. are reassembled on the deck. his rig is either self-propelled or towed to a drilling site and either anchored or dynamically positioned over the sea. However, the rig itself remains stationary at well location by a series of anchors. Drillship is a self-propelled loating ofshore drilling vessel (Figure 2.32). he vessel is constructed in such a way so that it can drill from its base. Drillship is capable of drilling in water depths more than 10,000 t. However, it is not as stable as semisubmersible. here are two basic types of drill ships – positions itself with anchors, and uses dynamic positioning (GPS-Global Positioning System). Land rigs are primarily used in land. In the early stage of rotary drilling operations, drilling rigs were semi-permanent in nature which were built on site and let in place ater the completion of the well. hese days, the drilling rigs are becoming more and more expensive due to the addition of numerous automatic and advanced technologies on the rig components. Most land rigs have to be transported to location in sections, some are self-contained, permanently mounted on trucks. herefore, now there is an option to carry the rigs from well to well. Land rigs are capable of drilling holes to a depth of more than 30,000 feet. Some light-duty drilling rigs are similar in nature to a mobile crane. Larger land rigs are dismantled into multiple sections and loads in order to move to a new location. Jackknife rig is a drilling rig that has jack-knife mast instead of a standard derrick (Figure 2.33). he jackknife rigs are assembled on the ground with

54

Fundamentals of Sustainable Drilling Engineering

SUBSEA FIXED COMPLETIONS PLATFORMS (SS) (FP) FP CT

COMPLIANT TOWERS (CT)

FPS

FLOATING TENSION LEO PRODUCTION PLATFORMS (TLP) SYSTEM (FPS)

TLP SS 1000 2000 3000 4000 5000 6000 7000

Water Depth - Feet

Skiddable Platform Rig Production Facilities Mooring Systems

Hull

3,275” Tendons (Steel Pipe) Production Riser / Wells 1,454”

555’

Washington Monument

1,615”

697’

One Shell Square

Sears tower

Bullwinkle 1,353’ WD

Anger 2,860’ WD

Direct Tendon / Pile Connection Piles Wells

Tension leg Platform

Figure 2.30 Floating Production Systems (FPS) & Tension Leg Platforms (TLPs).

pins and then raised as a unit using the rig-hoisting equipment. When the rig is needed to move some other places, it is lowered or laid down intact and transported by truck. he portable mast rig is supported by legs like conventional derrick and hinged at the base (Figure 2.34). his rig is suitable for moderate-depth wells, usually is mounted on wheeled trucks or trailers that incorporate the hoisting machinery, engines, and derrick as a signal unit. Beyond the above classiication, rigs can also be classiied based on: i)

Power used • electric - rig is connected to a power grid usually produced by its own generators • mechanic - rig produces power with its own (diesel) engines

Drilling Methods 55

Figure 2.31 Semisubmersible rigs.

Figure 2.32 Drillship rigs.

56

Fundamentals of Sustainable Drilling Engineering

Figure 2.33 Jack-knife mast rig.

Figure 2.34 Portable mast rig.

ii)

• hydraulic - most movements are done with hydraulic power • pneumatic - pressured air is used to generate small scale movements Pipe used • cable - a cable is used to slam the bit on the rock (used for small geotechnical wells)

Drilling Methods 57 • conventional - uses drill pipes • coil tubing - uses a giant coil of tube and a downhole drilling motor iii) Height • single - can drill only single drill pipes, has no vertical pipe racks (most small drilling rigs) • double - can store double pipe stands in the pipe rack • triple - can store stands composed of three pipes in the pipe rack (most large drilling rigs) • quad - can store stands composed of four pipes in the pipe rack iv) Method of rotation • no rotation (most service rigs) • rotary table - rotation is achieved by turning a square pipe (i.e. kelly) at drill loor level. • top-drive - rotation and circulation is done at the top of the drillstring, on a motor that moves along the derrick. v) Position of derrick • conventional – derrick is vertical • slant - derrick is at an angle (this is used to achieve deviation without an expensive downhole motor)

2.6 Nature and Need for Sustainable Drilling Operations According to the World Petroleum Congress, and the World Summit on sustainable development, sustainable development can be deined as the “development that meets the needs of the present without compromising the needs of future generations”. hen the questions come such as: “Will the world let us produce oil and gas? Will we be allowed to play? Can we change?” he answer yielded has been: “If we don’t, we won’t be allowed to operate. here is no alternative. We are going into a new century of corporate social responsibility. In order to be able to expand business, one needs to have a license to operate, not one given by the government, but which lies in the public’s willingness to accept us”. he petroleum industry must pay their attention in inding solutions to environmental problems and try to get the answers of the above. Otherwise the environmental organization and summit will not allow exploring and producing in undeveloped areas worldwide in the near future. he industry is facing external pressure to reduce emissions of carbon dioxide and other greenhouse gases. It is also hoped to work collectively on global climate change. Recently, the concept and practice of environmental management and sustainable development have changed quickly within industrial organizations. To some extent, this has been a reaction to public concerns and to the obligations of increasingly stringent environmental regulations. In general, the government is gradually strengthening its environmental laws, not only in response to public opinion, but also as a result of the Country’s obligations as a member of the United Nations (UN). he long-term commitment to sustainability and ethical behavior should be the core where the industry has to stand for as an organization. In general, most of the giant

58

Fundamentals of Sustainable Drilling Engineering

oil companies are operating as global companies where they should act in a socially responsible manner. he values start with sustainability where it is believed that any organization will be successful when they put health and safety irst and subsequently are environmentally responsible, and support the communities in which they should operate for stakeholders. he overarching goal for environmental management is to minimize, and where possible eliminate, any impact of the operations on the environment. he experts recognize that the eicient and responsible use of natural resources is critical to the sustainability of the environment. Sustainable development should be the core to petroleum business strategy where it needs to be integrated health, safety, environmental, social and economic factors into the decision-making. Any sustainable business will be successful when the industry provides lasting social, environmental and economic beneits to society. It is well-known fact that the oil & gas exploration pose long and short-term environmental risks. hese risks are primarily associated with (a) contamination due to drilling wastes (muds, produced waters, byproducts, etc.); emissions from drilling sites and potential runofs, (b) natural gas/oil leaks and spills, and (c) direct efects on human health. he drilling luids circulated through the circulating system which contains toxic materials (including oil/grease, arsenic, chromium, cadmium, lead, mercury, & naturally occurring radioactive materials). he composition of drilling muds and produced waters varies widely depending on location and depth of well; and type of drilling luid. Produced waters potentially impacting the surface or groundwater are typically disposed of in a deep aquifer, but there is still the threat of accidental release from temporary storage. Contributing to air pollution are also the potential emissions of hydrogen sulide present in natural gas deposits. Its short and long-term direct efect on human health could be severe, from unconsciousness to death within a few breaths. Statistically, 0.5–1% of exploratory wells result in blowout, causing harmful emissions. Additionally, pressurized contents of a geologic formation literally explode out of the new well, severely impacting environment and the project economics. Some researchers present guidelines and economically feasible options to minimize risks to environment and human health (see references). hey also provide an overview of the environmental concerns, project economics and sustainability issues. As a result, the current industrial trend is toward the development of sustainable technologies, and environmentally-friendly chemicals that might be used to enhance the drilling activities. his is due to the fact that petroleum industry is regarded as one of the hazardous and risky industries. he current research trend is deeply involved toward inding and developing a mud system which will satisfy both technical and environmental requirements and thus bridging the gap between WBMs and OBMs.

2.7 Current Practice in the Industries Most of the development and improvement in the rig equipment and component are occurred for the ofshore drilling where the operator are moving forward to the deep water environment. Now ofshore operations are exeeding the depth of 10,000 feet for the water level which required the drilling contractors to follow the rapid demand for new improvement and technology. he most important development are the rig capacity to sustain drilling and casing string while run in and pull from the hole. he other

Drilling Methods 59 Rig

Maersk Developer

Type

Semisubmersible

Design

DSS21

Year Built Class Station Keeping Water Depth Cap., ft Drilling Depth. ft Quarters Diamentions Drawworks Derrick Activity Derrick #1 Cap. Derrick #2 Cap. Top Drive system Pipe handling system

2009 ABS Dynamic position 10,000 ft 40,000 ft 180 259 ft X 258 ft 6000 hp (main) Dual 2500 klbs 1500 klbs 2,000 klbs (main) 2 X Hydroracker

Figure 2.35 Maersk developer semisubmersible speciication.

important development is the strong well control equipment that can work at such harsh environment. Most of the conventional and current practices are already outlined in the previous sections. he current trend in deveeloping rig component to suit the above situation and what have been achieved till now are mentioned in this section.

2.7.1 Derrick and Substructure Based on the current demand, Maersk Drilling company designed a large and most sophisticated built-for-Purpose rig that can work in water depth up to 10,000 feet and can drill up to 40,000 feet. he rig is dynamically positioned and povides living quarter of 180 workers. his rig has dual derricks, 6000 hp drawworks and hydraulic pipe handling to handle the tubulars easily and safely. he derrick and drawworks are capable to lit and run loads up to 2,000,000 pounds of tubulars which is the heaviest load recoreded currently. Figure 2.35 shows the detailded speciication.

2.7.2 Hoisting System Due to the heaviest load in drilling operations, this load is coming from the casing string speacially if the depth is deep. As a result, the hoisting system was based mainly on the maximum expected casing string load. Modiications of the hoisting system that used to support 2,000,000 pound was consist of the following: a Casing system comprised of a 1.5 million pound casing handling seal assembly running tool “CHSART” and dual subsea release “SSR”. b Landing string comprised of 6 5/8 OD 0.938 wall V-150 6 5/8 FH landing string with a heavy-wall slip section “HWSS” and dual diameter tool joints, a multi-opening diverter tool, a single joint of landing string pipe, and pup joint. c Top drive system consists of a 1000 MT top drive, a spacer sub, an upper IBOP, a lower IBOP, and a saver sub.

60

Fundamentals of Sustainable Drilling Engineering

• 1,000 ton Hydraulically Actuated Slip Assembly

• 1,000 ton Hydraulically Actuated Elevator

Figure 2.36 Slip and elevator systems. Reduced tool joint diameter for reduced make-up torque requirements Extended length, thicker wall slip section for increased slip crushing capacity Internal and external upset (IEU) Double diameter box tool joint

Tungsten carbide free hardbanding to protect riser/casing

Increased elevator diameter for increased hoisting requirements

High strength grade tube of reduced wall thickness Pin wall thickness to provide connection tensile capacity

Figure 2.37 6-5/8 OD 0.9338 Wall Slip-Proof® landing string.

On top of the above, the hoisting system and casing handling equipment also included 1000 ton hydraulic actuated elevators, 1000 ton hydraulic actuated slips, and bails (Figure 2.36). In addition, special drill pipes were manufactured to withstand these heavy loads (Figure 2.37). he speciications for the tubulars consist of the following: a) Pipe body of higest speciied minimum yield strength (SMYS) of 150 ksi and even 165 ksi grades which can be produced with minimum toughnes greater than API S-135, b) heavy wall slip section to protec the pipe from crushing efect when suspend the string at the rotary. c) Dual tool joint to provide a sacriicial wear pad for the installation of casing-friendly hardband material. his speciications is mainly to maximize the fatigue resistance, torsional balance and the elevator capacity. d) Extra long tool joints with extended tong space which provide additional repair or rethreading. e) internal plastic coating which mitigates corrosion of internal pipe from drilling luid and will also facilitate reduced friction low. In addition, the top drive system that has an upper & lower IBPO, and saver sub is manufactured. his hoisting and handling TDS can handle up to one thousand tons (Figure 2.38).

Drilling Methods 61

Traveling Block Becket Integrated Swivel

Running and building stan • Run singles • Run stands

Top Drive

• Build stands and run single

Pipe Handler

Figure 2.38 Travelling block and Top drive section components.

2.7.3 Pressure Control System Due to widening the ofshore drilling operations to reach 10,000 t deep water environment, the need to have an eicient and strong pressure control equipment (PCE) became a reality. he irst 10,000 t deep PCE was deployed in Brazil in 2004 with a surface activation equipment. he system consits of surface BOP, a 13 3/8” casing riser and subsea disconnecting system “SDS”. he surface BOP is connected to the riser tensioner system which transmits the riser tension to the BOP stack. Riser tensioner rods are coupled to a split load ring via 6 shakles. An anti-recoil system is also incorporated with shut-of valves on each cylinder. his enabled the surface BOP and the 13 3/8 riser load to be landed into the existing rig tension ring by the insertion of a simple adapter. he SDS consists of 5 pipe rams and shear ram. In this respect, the SDS gives shear and disconnect functionality equivelent to a ive cavity conventional subsea BOP stack. he system has a stand-alone control system connected subsea equipment and surface BOP to the surface accumulated banks.

2.8 Future Trend in Drilling Methods here are lots of components that can be further developed and improved to insure achieving the drilling goals. As drilling is going deeper and deeper, the need for the powerful rig in terms of hoisting system is required to support the heaviest loads of the tubulars. Also the hydraulic circulating system needs to be iproved to meet the required circulating parameters. As the operators are now focusing on deep seas, the subsea equipment also needs to be modiied to suit the new water depths. Currently the manufacturers are looking to use a strong drill pipes but at the same time lighter weight such as titanium drill pipe. Titaium drill pipes are proved to decrease the hook load by 40% as compared with the steel drill pipes using drilling program simulator. his type of drill pipe will be very helpful for the extended reach drilling operations where the well TMD is large. Another future development is reelwell drilling

62

Fundamentals of Sustainable Drilling Engineering

methods (RDM) which can solve a lot of cleaning and weight-on bit control for coiled tubing drilling applications. his methods consists of two concentric tubular string, rotating control device (RCD) and dual loat valve. he annular of the outer string is used to pump the mud down the well while the inner string is used to pump the mud with cuttings out the well. By doing this, the well annulus will be isolated. In general, solving a lot of hydraulic problems while drilling will also be a challenge. It may also be a challenge to have the automation of all drilling operations. Currently there are lots of rigs that have automation in most of their operating system that can ease the drilling. But the future envelope for development is still open for more active research and development.

2.9 Summary his chapter discusses the all aspects related to drilling rig and its components. he diferent drilling rig systems are explained in addition to classiications of rig. he different components or devices names with complete igures are shown in this chapter. he pump rating, capacity and design of pumps are also stated here.

2.10 Nomenclature d dl d pr Hf Ls Madv n

= distance travel by the weight on pulley, t = liner diameter, inch = piston diameter, inch = heating value of fuel used in the engine, Btu / lbm = stroke length, inch = mechanical advantage = number of lines strung through the travelling block

N

= number of pump cycle i.e. revolutions per minute of crank, piston strokes / min rpm = 4 = number of drilling lines through the travelling block = discharge pressure, psig = pump horse power, hp = input power of the block and tackle, hp = output power of the block and tackle, hp = Shat power developed by an IC engine, hp = output power for the duplex pump, hp = low rate, gal/min = power input to the IC engine, hp = Radius of ly wheel, t = Output torque, ft lb f = time required to travel the distance, d, min

n Pd Php Pibt Poutbt Ps Pout p q Qi rFW T t

Drilling Methods 63 Tf Td V

= tension (i.e. load) in the fast line, lb f = tension (i.e. load) in the dead line, lb f = wind velocity, mph

VB1

= volumetric displacement of liquid for a backward stroke with one piston, in3 stroke = velocity of the traveling block, ft /min = volumetric displacement of liquid for a forward stroke with one piston, in3 stroke = velocity vector, t/min = velocity of the fast line, ft / min = Weight on pulley, lb f = the rate of fuel consumption by the engine, lbm / min = wind load, lb f / ft 2 = total compressive load on the derrick, lb f = hook load, lb f = work done per piston stroke, lb f ft = work done per complete stroke, lb f ft = increase in pressure, psi, which cannot be more than 3,500 psi. = Angular velocity of the shat, rad/min = mechanical eiciency of the duplex pump, % = Overall engine eiciency of the power system

vbt VF 1

v vf W wf Ww WD Whl WP WPN p mp ps

2.11 Exercise E2.1: A diesel engine gives an output torque of 1,740 t-lbf at an engine speed of 1,200 rpm. If the fuel consumption rate was 31.5 gal/hr, what is the output power and overall eiciency of the engine? Ans. 397.5 hp; 23.4% E2.2: An internal combustion engine is run by diesel fuel which gives an output torque of 1,300 ft lb f at an engine speed of 1,000 rpm. he engine consumes fuel at a rate of 25 gal/hr. Calculate the wheel angular velocity, power output, overall eiciency of the IC engine. Ans. E2.3: A diesel engine runs at a speed of 1,100 rpm and its engine power output 300 hp. If the system uses frictionless pulley, the drawworks can handle to lower a drillstring of 500,000 lb f . he drilling operations engine was continuing for three days. Calculate the wheel angular velocity, torque developed by the engine, the drillstring velocity, distance travel by the drillstring, power input, and overall eiciency of the engine. Ans. E2.4: For a series of engine operations, the following data were obtained. he fuel used for running the engine was gasoline. Compute power output or break horsepower, overall engine eiciency for each engine speed, fuel consumptions in gal/day for 1,000 rpm and 850 rpm considering 8 hrs a day. Ans.

64

Fundamentals of Sustainable Drilling Engineering Engine speed (rpm)

Torque ft - lbf

Fuel consumption (gal/hr)

1,350

1,500

27.0

1,150

1,650

20.0

1,000

1,700

18.0

850

1,750

15.5

700

1,800

13.0

E2.5: A drilling rig has a hook load of 300,000 lbf , which has eight number of drilling lines. A wind velocity of 100 mph is felt by the derrick. he rig has ten lines which are strung through the travelling block. A hook load of is being hoisted. According to the API standard, calculate the wind load and total compressive load. Assume that the block and tackle has the frictionless pulley. Ans. E2.6: he total weight of 8,000 t of 9 5/8-inch casing for a deep well is determined to be 344,000 lbs. Since this will be the heaviest casing string run, the maximum derrick load must be calculated. Assuming that 12 lines run between the block and tackle and neglecting buoyancy efects and friction, calculate the maximum derrick load. Also calculate each derrick leg load. Ans. E2.7: he total casing weight is determined 440,000 lbf for a 11,000 t of 8 5/8-inch casing during a deep well casing operation. Assume that 14 lines are run with the hoisting system. As this casing string operation is the heaviest run, the maximum derrick load is needed to be calculated. Assume that there is a friction loss with the hoisting system and neglecting buoyancy efect, calculate the maximum derrick load. Also calculate each derrick leg load. Ans. E2.8: he hoisting system of a rig derrick has a load of 440,000 lb f . he input power of the drawworks for the rig can be a maximum of 560 hp. Fourteen drilling lines are strung between the crown block and traveling block. Assume that the rig loor is arranged as shown in Fig. 2.9. Consider there is some loss of power due to friction within the hoisting system. Compute (1) the static tension in the fast line when upward motion is impending (2) the mechanical advantage of the block and tackle (3) the maximum hook horsepower available (4) the maximum hoisting speed (5) if a 60 t stand would require to pull, what should be required time (6) the actual derrick load (7) the maximum equivalent derrick load (8) the derrick eiciency factor. E2.9: Calculate the liner size required for a triplex pump where rod diameter is 2.0 in, stroke length is 20 in stroke, pump speed is 80 strokes/min. In addition the maximum available pump hydraulic horsepower is 1000 hp and the delivery pressure is 3,000 psi. Assume the volumetric eiciency of pump is 98%. E2.10: Calculate the liner size required for a double-acting duplex pump where rod diameter is 2.2 in, stroke length is 24 in stroke, pump speed is 75 strokes/min. In addition the maximum available pump hydraulic horsepower is 1300 hp. For optimum hydraulics, the pump recommended delivery pressure is 2,500 psi. Use the formula for calculating the volumetric eiciency of pump.

Drilling Methods 65

APPENDIX 2A 1. Shale shakers 2. Choke manifold 3. Pipe ramp 4. Catwalk 5. Pipe rack 6. Pipe on rack 7. Crown block assembly 8. Catline boom and hoist line 9. Drilling line 10. Monkey board 11. Travelling block 12. Top drive (power swivel) 13. Mast 14. Drill pipe 15. Doghouse 16. Blowout preventer control unit (Accumulator) 17. Water tank 18. Electric cable tray 19. Engine-generator set 20. Fuel tank 21. Electrical control (SCR house) 22. Mud pumps 23. Bulk mud component tanks (P-tanks) 24. Mud tanks (Pits) 25. Reserve pits 26. Mud-gas separator

RIG FLOOR (CONVENTIONAL ROTARY RIG) 27. Hook 28. Swivel 29. Kelly 30. Rotary table assembly 31. Drawworks 32. Standpipe 33. Rotary (Kelly) hose

RIG FLOOR (TOP DRIVE) 34. Driller’s console 35. Iron roughneck

66

Fundamentals of Sustainable Drilling Engineering 36. Tongs 37. Slips 38. Air hoist

BLOWOUT PREVENTER STACK AND WELLHEAD 39. Annular blowout preventer 40. Ram blowout preventer 41. Substructure 42. Cellar 43. Conductor casing 44. Drill string 45. Bit

DRILLING FLUID EQUIPMENT 46. Degasser 47. Desander 48. Desilter 49. Centrifugal pumps 50. Mud agitators Accumulator is a storage device for nitrogen pressurized hydraulic luid, which is used in operating the blowout preventers. Air hoist is a hoisting device of a liting tackle which is constructed by a cylinder, piston, and piston-rod for a reciprocating motion. It is operated by compressed air to complete the heavy duty works in the rig site. Annulus is the space around a pipe in a well bore between the outer wall of the drill pipe and the wall of either the bore hole or the casing. It is also called as annular space. Blowout preventer control unit (Accumulator) is a large valve usually installed above the ram preventers. It forms a seal in the annular space between the pipe and well bore. If there is no pipe existence, it is installed on the wellbore itself. Bulk mud component tanks (P-tanks) are hopper type tanks for storage of drilling luid components. he BHA is made up of a drill bit, drill collar and stabilizer. A blowout preventer (BOP) is a large valve installed at the wellhead to control the rig pressures in the annular space between the casing and drill pipe during drilling, cementing and completions. It is also called an annular blowout preventer. Ram-type preventers have interchangeable ram blocks to accommodate diferent O.D. drill pipe, casing, or tubing. Cellar is a pit in the ground to provide additional height between the rig loor and the well head. he space allows to install the blowout preventers, ratholes, mouseholes, and so forth. It also collects drainage water and other luids for disposal. Catwalk is a ramp at the side of the drilling rig where pipe is laid to be lited to the derrick loor by the catline or by an air hoist.

Drilling Methods 67 Crown block assembly is a stationary steel beam joined to the top of the derrick posts of an oil well to support the pulleys or sheaves through which the drill line (i.e. wire rope) passes. It helps to raise and lower the drill string, bottomhole assembly, etc. (item 1 of Figure 2.3). Catline boom and hoist line is a structural framework upright near the top of the derrick for liting material. Choke manifold is an arrangement of piping and special valves which is called chokes. Drilling mud is circulated through this arrangement when the blowout preventers are closed. Choke manifold is used to control the pressures encountered during a kick. Conductor casing is the irst casing needed to be run in a well. his is done ater spudding-in so a blowout preventer can be installed before drilling is started. It is the largest diameter casing and the topmost length of casing. It is relatively short and encases the topmost string of casing. Drill string is an assembly (i.e. column or string) of drill pipe, drill bit, drill collars that transmits drilling mud and give the rotational power to the drill bit. he drill string is hollow so that drilling luid can be pumped down through it and can be circulated back through the annulus. he drill string is typically made up of four sections such as bottom hole assembly (BHA), transition pipe (i.e. heavyweight drill pipe), drill pipe and drill stem subs. Each section of drill string is made up of several components. hey are joined together using special threaded connections known as tool joints. Drilling mud agitator is an equipment for oilield drilling mud tanks and is usually driven by electric power. It is used to agitate drilling mud in the mud tanks and is widely used in oilield mud puriication system. Drill stem subs are used to connect drill string elements. Degasser is an equipment used to remove unwanted gas from drilling luid. Desander is a centrifugal device used in drilling rig to remove sand from drilling luid. his action prevents pump abrasion. It may be operated mechanically or by a fastmoving stream of luid inside a special cone-shaped vessel, in which case it is sometimes called a hydrocyclone. Desilter is a centrifugal device, similar to a desander, used to remove very ine particles, or silt, from drilling luid. his keeps the amount of solids in the luid to the lowest possible level. Drill bit is the cutting or boring element used to break up the rock formation in drilling oil and gas wells. Most bits used in rotary drilling are roller-cone bits. he bit consists of the cutting elements and the circulating element. he circulating element permits the passage of drilling luid and uses the hydraulic force of the luid stream to improve drilling rates. Drill collar is a heavy, thick-walled tubular usually made up of steel. It is used to apply weight to the drill bit so that the bit can drill the rock formation. It places between the drill pipe and the bit in the drill stem. Drill pipe is heavy seamless tubing used to rotate the drill bit and through which drilling luid is circulated. hirty feet long drill pipes are coupled together with tool joints. he Purpose of the drill pipe is to rotate the bit and provide downward passage for drilling luid.

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Fundamentals of Sustainable Drilling Engineering

Figure 2.3 A modern rotary drilling rig and its components.

Drawworks or hoist is the key piece of equipment and is the hoisting mechanism on a rotary drilling rig. It is essentially a large winch that spools of or takes in the drilling line and thus raises or lowers the drill stem and bit. he principal parts of the drawworks are the drum, breaks, transmission, and clutches. It has also some other parts such as chains, sprockets, engine throttles, and other controls which enable the rig power to be diverted to the particular operation at hand. Driller’s console is the control panel, located on the platform, where the driller controls drilling operations. Doghouse is a small enclosed space (room) on the rig loor used as an oice for the driller or as a storehouse for small objects. Drilling line is a wire rope hoisting line, reeved on sheaves of the crown block and traveling block (in efect a block and tackle). he functions of drilling line are to hoist or lower drill pipe or casing from or into a well. It is also used to support the drilling tools. Electric cable tray is a steel structure which supports the heavy electrical cables. his cable supplies the power from the control panel to the rig motors. Engine-generator set produces power for the drilling rig. It has an engine driven by diesel, Liqueied Petroleum Gas (LPG), natural gas, or gasoline along with a mechanical transmission and generator. Electrical control (SCR house) is a panel that controls the power supply. In the rig site, the generator produces electricity that lows through cables to electric switches and control equipment enclosed in a control cabinet or panel. Fuel tanks are used to store fuel for the power generating system.

Drilling Methods 69 Hook is a large, hook-shaped device from which the elevator bails or the swivel is suspended. It is designed to carry maximum loads ranging from 100 to 650 tons and turns on bearings in its supporting housing. Iron roughneck is a mechanical device that is used to make and break the connections. his machine can be easily set away when it is not in use. Its mobility allows it to carry out mousehole connections when the roads are correctly positioned. he device consists of a spinning wrench and torque wrench which are both hydraulically operated. he advantages of this device include controlled torque, minimal damage to threads (thereby increasing the service life of drill pipe) and reducing crew fatigue. Kelly is the heavy square or hexagonal steel member suspended from the swivel through the rotary table. It is the irst section of a heavy steel pipe below the Swivel, normally about 40’ long, with an outside hexagonal cross section. It is suspended from the swivel. It is connected to the topmost joint of drill pipe to turn the drill stem as the rotary table turns. It must have this hexagonal (or sometimes square) shape to transmit rotation from the rotary table to the drillstring. he kelly has the right hand thread connection on the lower [pin] end, and a let hand thread connection on the upper [box] end. Kelly-saver-sub is a short connection between the kelly and the irst joint of drillpipe. his inexpensive short section of pipe is used to prevent wear on the kelly threads. It can be easily replaced. Kelly cocks are valves installed at either end of the kelly to isolate high pressures and prevent backlow from the well. he purpose of the Kelly is to transmit torque through kelly bushings. Monkey board is a platform where derrickman works. It is located at a height in the derrick equal to two, three or four lengths of drill pipe respectively. Mast is a portable derrick capable of being vertical as a unit. It is notable from a standard derrick, which cannot be raised to a working position as a unit. Mud pumps are the large reciprocating pumps used to circulate the mud (drilling luid) on a pumps drilling rig. Mud tanks (Pits) are a series of open tanks, usually made of steel plates, through which the drilling mud is cycled to allow sand and sediments to settle out. Additives are mixed with the mud in the pit, and the luid is temporarily stored there before being pumped back into the well. Mud pit compartments are also called shaker pits, settling pits, and suction pits, depending on their main purpose. Mousehole is a shallow bore under the rig loor. It is usually wrinkled with pipe in which joints of drill pipe are temporarily suspended for later connection to the drill string. Mud pump is a large reciprocating pump used to circulate the mud (drilling luid) on a drilling rig. Mud-gas separator is a device that removes gas from the mud coming out of a well when a kick is being circulated out. Pipe ramp is an angled ramp for dragging drill pipe up to the drilling platform or bringing pipe down of the drill platform. Pipe rack is a horizontal support where drill pipes are stacked. Reserve pit is a mud pit in which a supply of drilling luid is stored. It is also called waste pit, usually an excavated, earthen-walled pit. It may be lined with plastic to prevent soil contamination.

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Rotary table assembly is the principal component of a rotary or rotary machine. It is used to turn the drill stem and support the drilling assembly. It has a beveled gear arrangement to create the rotational motion and an opening into which bushings are itted to drive and support the drilling assembly. he purpose of the rotary drive is to provide the power to turn the rotary table and power sub can be used to connect casing. Rotary table is located on the drill loor and can be turned in both clockwise and anti-clockwise directions, controlled from the driller’s console. he rotating top has a square recess into which its the master bushing having a circular recess into which its the Kelly bushing. he Kelly bushing has four pins to it into the rotary table. When the rotary is engaged, the torque is transmitted from the rotating table on the Kelly via the Kelly bushing. Rotary hose is the hose on a rotary drilling rig that conducts the drilling luid from the mud pump and standpipe to the swivel and Kelly. It is also called the mud hose or the kelly hose. Rathole is a hole in the rig loor 30 to 35 feet deep, lined with casing that projects above the loor. he kelly is placed in the rathole when hoisting operations are in progress. Shale shaker is a series of trays with sieves or screens. he vibrating motion of the shale shaker helps to remove cuttings from drilling mud. Sieve size of the tray is selected based on formation cuttings. Swivel is a mechanical device that suspends the weight of the drill pipe, provides for the rotation of the drill pipe beneath it while keeping the upper portion stationary, and permits the low of drilling mud from the standpipe without leaking. It is a tool that is hung from the rotary hook to suspend and permit free rotation of the drill stem. Swivel also provides a connection for the hose and a passage for the low of drilling luid into the drill stem. he bail of the swivel is attached to the hook of the travelling block, and the gooseneck of the swivel provides a connection for the kelly hose. Standpipe is a vertical pipe rising along the side of the derrick or mast. It joins the discharge line leading from the mud pump to the rotary hose and through which mud is pumped going into the hole. Slips are a pipe gripping devices, with wedge-shaped pieces of metal with teeth or other gripping elements. hese are used to prevent drill string from slipping down into the hole or to hold pipe in place. heir purpose is to prevent the drill string from falling down in the well and provide link to hang drill string from the rotary table. Rotary slips it around the drill pipe and wedge against the master bushing to support the pipe. Power slips are pneumatically or hydraulically actuated devices that allow the crew to dispense with the manual handling of slips when making a connection. Packers and other down hole equipment are secured in position by slips that engage the pipe by action directed at the surface. Stabilizer is a device which keeps the drilling assembly centered in the hole. Substructure is the foundation on which the derrick or mast and usually the drawworks sit. It has space for storage and well control equipment. Travelling block is an arrangement of pulleys or sheaves through which drilling cable is reeved. It moves up and/or down in the derrick or mast. Top drive (power swivel) rotates the drill bit without the use of a kelly and rotary table. he top drive is operated from a control console on the rig loor.

Drilling Methods 71 Transition pipe is the heavyweight drill pipe (HWDP) normally used to make the transition between the drill collars and drill pipe. he function of the HWDP is to provide a lexible transition between the drill collars and the drill pipe. his helps to reduce the number of fatigue failures seen directly above the BHA. HWDP is also used to add additional weight to the drill bit. Drill pipe makes up the majority of a drill string. Tongs are the large wrenches used for turning when making up or breaking out drill pipe, casing, tubing, or other pipe; variously called casing tongs, rotary tongs, and so forth according to the speciic use. Power tongs are pneumatically or hydraulically operated tools that spin the pipe up and, in some instances, apply the inal makeup torque. Water tank is a container used to store water. his water is used for mixing mud, cement and cleaning the rig.

References J.N. Brock, R. Brett Chandler, NOV Grant Pridco; C. Maersk Drilling USA; J. Dugas, W. White, Quail Tools; M. Vasquez, A. Johnalagadda, Statoil. Innovative Tubular, Hoisting, and Deepwater Rig Design Extend Hook Load Envelope to 2,000,000 Pounds. Paper IADC/SPE 151140 presented in San Diego, California, USA, 6–8 March 2012. R. Brett Chandler, SPE/IADC, Grant Pridco; Michael J. Jellison, SPE/IADC, Grant pridco; Michael L. Payne, SPE, BP America; Jef S. Shepard, IADC, GlobalSantaFe. Performance Driven Drilling Tubular Technologies. Paper SPE/IADC 79872 presented in Amsterdam, he Netherlands, 19–21 Feb 2003. T.S Burns, R&B Falcon Corporation, and W.T Bennett, Bennett & Associates LLC. Rapid Evolution of Ultra-Deep Water Drilling Rig Designs. Paper OTC 8749 presented on Ofshore Technology Conference in Houston, Texas, USA, 4–7 May 1998. Jackie E. Smith, SPE, Grant Prideco; R. Brett Chandler, SPE, Grant Prideco; Patric L. Boster, SPE, RTI Energy Systems. Titanium Drill Pipe for ultra-Deep Directional Drilling. SPE/ IADC 67722 paper presented at the drilling conference held in Amsterdam, he Netherlands, 27th Feb–1st Mar 2001. Graham Brunt; Stena Drilling, Scott Elson, Nautronix, Tim Newman; Shell international E.P. Inc., Paul Toudouze; Cameron project management. Surface BOP: Equipment Development for Extending the Water Depth Capability of a D.P. Semisubmersible to 10,000 t and beyond. SPE/IADC 87109 paper presented at the drilling conference held in Dallas, Texas, 2–4 March 2004. M.D. Dunn, Phoenix Alaska Technology; P.J. Archey, BP; E.A. opstad, Phoenix Alaska Technology; M.E. Miller, BP; T. Otake, NI Energy Development Inc. (Subsidary of Nisso Iwai). Design, Speciication, and Construction of a Light, Automated Drilling System (LADS). SPE/IADC 74451 paper presented at the drilling conference in Dallas, Texas, 26–28 Feb 2002. P. Girde, Maharashtra Inst. Of Technology. Advanced Drilling using a Spiral Kelly. SPE 99284 STU (Student3) paper presented at the international student paper context in Dallas, Texas, 9–12 Oct 2005. M. Mir Rajibi, SPE, A.I. Nergard, SPE, University of Stavanger; O. Hole, SPE, O. M. Vestavik, SPE, Reelwell AS. A New Riserless Method Enable Us to Apply Managed pressure Drilling in Deepwater Environment. SPE/IADC 125556 paper presented at the Drilling technology Conference in Manama, Bahrain, 26–28 Oct 2009.

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Zengxuan Yan, Hongwei Xu, Guanghui Liu, Qinghong Li, Jianhong Wang, Xianping Ma, Feng Zhao, Qingyu Li, Shinguan Yang and Lin Sun, Qinghai Drilling Company of CNPC Xibo Drilling Engineering Company Limited. Design and Application of 735 hp (4000m) Plateau Mountain Rig. SPE/IADC 155886 paper presented at the Asia Paciic Drilling conference in Tianjin, China, 9–11 July 2012. http://homepage.ntlworld.com/leslie.foster/drilling_history. htm, accessed on November, 18, 2009 Oil tools: http://www.welong-oiltools.com/technical/29.htm, accessed on November 19, 2009. http://www.osha.gov/SLTC/etools/oilandgas/drilling/maintenance_activities.html#mud_circulating_system, accessed on January 23, 2010 Brighenti, G., Macini, P. and Mesini, E. Environment and Sustainable Management of Oil and Gas Reservoirs in Italy, SPE 80608-MS, SPE/EPA/DOE Exploration and Production Environmental Conference, 10–12 March 2003, San Antonio, Texas, USA. Rana, S. Facts and Data On Environmental Risks - Oil & Gas Drilling Operations. SPE 114993MS. SPE Asia Paciic Oil and Gas Conference and Exhibition, 20–22 October 2008, Perth, Australia. Arthur, J.D., Coughlin, B.J. and Bohm, B.K. Summary of Environmental Issues, Mitigation Strategies, and Regulatory Challenges Associated With Shale Gas Development in the United States and Applicability to Development and Operations in Canada. SPE 138977-MS, presented at the Canadian Unconventional Resources and International Petroleum Conference, 19–21 October 2010, Calgary, Alberta, Canada. Rana, M.S., Environmental Risks - Oil & Gas Operations Compliance and Cost Control Using Smart Technology. SPE 121595-MS. Asia Paciic Health, Safety, Security and Environment Conference, 4–6 August 2009, Jakarta, Indonesia. Al-Majed, A.A., Adebayo, A.R. and Hossain, M.E., “A Novel Sustainable Oil Spill Control Technology”, Environmental Engineering and Management Journal, accepted for publication on May 16, 2012, Tracking No. 201_Aziz_11, (2012), in press. Hossain, M.E. and Apaleke, A.S., “An Overview of Mud Technology and Challenges Toward Greening of Drilling Fluid”, Environmental Engineering and Management Journal, accepted for publication on November 19, 2012, Tracking No. 314_Hossain_11, (2012), in press. Apaleke, A.S., Al-Majed, A. and Hossain, M.E., “Drilling Fluid: State of the Art and Future Trend”, Paper ID: SPE- 149555, presented at 2012 SPE North Africa Technology Conference and Exhibition (NATC), 20–22 February 2012 in Cairo, Egypt, 2012. Apaleke, A.S., Al-Majed, A. and Hossain, M.E., “State of the Art and Future Trend of Drilling Fluid: An Experimental Study”, Paper ID: SPE- 153676, presented at the 2012 SPE Latin America and Caribbean Petroleum Engineering Conference, 16–18 April 2012 in Mexico City, Mexico, 2012.

3 Drilling Fluids 3.1 Introduction Drilling luid (also called drilling mud) is an essential part of the rotary drilling system. Most of the problems encountered during the drilling of a well are directly or indirectly related to the mud. he successful completions of a hydrocarbon well and its cost depend on the properties of the drilling luid to some extent. he cost of the drilling mud itself is not very high. However, the cost increases abruptly for the right choice, and to keep the proper quantity and quality of luid during the drilling operations. he correct selection, properties and quality of mud is directly related to some of the most common drilling problems such as rate of penetration, caving shales, stuck pipe and loss circulation etc. In addition, the mud afects the formation evaluation and the subsequent eiciency of the well. More importantly, some toxic materials are used to improve the particular quality of the drilling luid, which is a major concern of the environmentalist. his addition of toxic materials contaminates the underground system as well as the surface of the earth. herefore, the selection of a suitable drilling luid and routine control of its properties are the concern of the drilling operations related individuals. he drilling and production personnel do not need a detailed knowledge of drilling luids, but they should understand the basic principles governing their behavior, and the relation of these principles to drilling and production performance. hey should have a clear vision about the objectives of any mud program, which are: 1) to allow the target depth to be reached, 2) minimize well

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costs, 3) maximize production from the pay zone. In mud program, factors that need to be considered are the location of well, expected lithology, equipment required, and mud properties. Hence, this chapter deals with the basic components of mud, its functions, diferent measuring techniques, mud design and calculations, the updated knowledge in the development of drilling luid and future trend of the drilling luid.

3.2 Drilling Fluid Circulating System In rotary drilling process, luid circulation system plays a vital role where drilling luid is very important as a major part. In reality, without circulating the drilling luid, no one could successfully drill most wells with the rotary method. What’s more, the success or failure of the mud program can largely determine whether the drilling contractor can drill the well to the operator’s speciications in a safe and economical way. Diferent parts of rig are involved to complete the luid low channel. Figure 3.1 shows a complete lowchart of diferent components that are involved with circulating system. he mud, water and other necessary chemicals, and solids are mixed through the mud-mixing tank. hen mud goes to the fresh mud pit from where it is pumped to the bottomhole assembly. Mud passes through the standpipe, hose and swivel, kelly and then the drill pipe, drill collar to drilling bit. On the return, mud with cuttings passes through the annulus, BOP, channel, shale shaker, desander to desilter to again at the mud pit in surface. he use of mud during the drilling operations is very crucial. As a result, water was used as the irst drilling luid in France in 1845. he purpose of this use was to bring the cuttings from the borehole to the surface. However, the diverse applications of drilling luid make it prime requirement for the rotary drilling. he primary functions of the drilling luid are to: i.

i. ii. iii. iv. v. vi. vii.

Remove and transport cuttings from bottom of the hole to the surface through the annulus (i.e. clean the borehole from cuttings and removal of cuttings). Exert suicient hydrostatic pressures to reduce the probability of having a kick (i.e. control of formation pressure) Cool and lubricate the rotating drill string and drilling bit Transmit hydraulic horsepower to the bit Form a thin, low permeable ilter cake to seal and maintain the walls of the borehole and prevent formation damage (i.e. seal the thief zones) Suspend drill cuttings in the event of rig shutdown so that the cuttings do not fall to the bottom of hole and stick the drill pipe Support the wall of the borehole Maintain wellbore stability (i.e. keep new borehole open until cased)

In addition to the above functions, there are some other secondary functions such as suspending the cuttings in the hole and dropping them in surface disposal areas, improving sample recovery, controlling formation pressures, minimizing drilling luid losses into the formation, protecting the soil strata of interest (i.e. should not damage formation), facilitating the freedom of movement of the drill string and casing, and

Drilling Fluids 75 BULK STORAGE

Mud

Details of Mud Mixing System

Clay & other solid additives

Water

Mixing Hopper Channel Shale Shaker

BOP

Standpipe Hose & Swivel

Annulus

Kelly Drill Pipe

Degasser

Mud Pump

Bit Desander

Mud Mixing

Mud Pit

Desilter

Figure 3.1 A block diagram for drilling luid circulating system.

Swivel

p Mud Pum

Drill Pipe

Mud Tank/Pit (Suction) Cuttings

Drill Stem

Drill Collar

Rotary Hose

Mud Tank/Pit (Settling) Reserve Pit

Kelly

Annulus

BIT

Figure 3.2 Diferent functions of drilling luid.

reducing wear and corrosion of the drilling equipment, and provide logging medium. It is noted that the follwing side efects must be minimized to achieve the above functions. i. i. ii. iii.

Damage to subsurface formation, especially those that may be productive Loss of circulation Wash and circulation pressure problems Reduction of penetration rate

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Fundamentals of Sustainable Drilling Engineering iv.

v. vi. vii. viii.

Swelling of the sidewalls of the borehole creating tight spots and/or hole swelling shut Erosion of the borehole Attaching of the drill pipe against the walls of the hole Retention of undesirable solids in the drilling luid Wear on the pump parts

Figure 3.1 depicts some of the functions of drilling luid with a complete circle of the mud circulating system.

3.3 Classiication of Drilling Fluids Drilling luids are generally classiied according to their base composition. It may be broadly classiied as liquid, gases, and liquid-gas mixtures. Although pure gas or gasliquid mixtures are used, they are not as common as the liquid based systems. A detailed classiication of drilling mud is shown in Figure 3.3. Drilling luids can also be broadly categorized as compressed air, foam, clear water, water-based mud and oil-in-water emulsion or oil-based mud. In addition to the above, additives must oten be added to these luids to overcome speciic downhole problems. A freshwater or saltwater based drilling luid with additives is commonly called drilling mud. Based on some speciic requirements and functions, some special types of drilling luids are made which will be discussed as a separate subsection below. Air and water generally satisfy the primary functions of a drilling luid. In addition, chemical additives are used for speciic purposes. he main factors that govern the selection of drilling luids are 1) formation type to be drilled, 2) the range of formation data i.e. pressure, temperature, permeability, saturation and strength, 3) the formation evaluation procedure used, 4) the water quality available i.e. fresh or saline water and 5) ecological and environmental considerations i.e. sustainability analysis. However, the drilling luid that yields the lowest drilling cost in an area must be determined by trial and error. he following sections describe the diferent drilling luids in detail.

Liquids

Gases

Liquid & Gases Mixtures

Water base

Fresh water

Oil base mud

Inhibited

Low Solids

Foam mostly

Full Oil

Aerated Water

Invert Emulsions

less than 5% 5 - 50% Water Content Water content

Figure 3.3 Classiication of diferent drilling luids.

Air

Natural Gas

Pseudo oil-based mud

Drilling Fluids 77

3.3.1

Water-based Mud

Water is the most common luid. When the solids are entrained in the water it makes it a natural mud. Water-based mud (WBM) is deined as a drilling mud in which the continuous phase is water. WBM is the most commonly used drilling luids worldwide; although in the North Sea oil based muds are the most widely used type of mud. WBM are those drilling luids in which the continuous phase of the system is water. WBM has some advantages: 1) Some clays hydrate readily in water and due to clay hydrating in water, the viscosity of the mud greatly increases, which helps carry the rock cuttings to the surface 2) clay particles form mud cake which reduces water loss (less lost circulation), and prevents the wall from caving into the hole (by forming a mud cake i.e. less formation damage, and 3) less mud cost (mud cost = 10% of well cost). However, there are some disadvantages as well: 1) reduction in penetration rate 2) increase in pressure loss due to friction. In small holes, the disadvantages may be more than the advantages. herefore, equipment to remove inely divided solids must be used to prevent the formation of natural clays. here are two types of water, saltwater and freshwater, that are used as base compositions for WBM. A freshwater mud is one in which the continuous liquid phase of the system is freshwater. Saltwater drilling luids are prepared from brine water, seawater and dry sodium chloride or other salts such as potassium chloride. hese luids have a chloride content of 6,000 mg/lt to less than 189,000 mg/lt. he commonly used products are attapulgite, PAC, CMC and starch to increase viscosity and FCLS, caustic lignite to control gel strength and iltrate loss. An inhibited mud is a mud with salt or calcium to reduce active clays hydration. An inhibited mud is one where the reactivity of the water phase within the mud system with active clays within the formation is greatly reduced. he distinction between fresh-water and inhibited muds is based on salt concentration. Inhibited muds are used when a problem arises during drilling with fresh mud (sloughing clays). Freshwater muds are those having less than 3000 ppm Na+ ions. It is used to drill shale and clay formations. Low solids muds are those where solid contents are less than 5%.

3.3.2

Oil-based Mud

Oil-based mud (OBM) is deined as the drilling mud made with oil as the solvent carrier for the solids content. OBM is a drilling luid in which oil is the continuous phase and where water content is less than 2% to up to 5%. his water is spread out, or dispersed, in the oil as small droplets. In general, diesel, kerosene and fuel oils are used as base luid. OBMs are used for a variety of applications where luid stability and inhibition are necessary such as high-temperature (> 2000F), and deep (> 16,000 t) wells, salt and unconsolidated formation and sot shale formation where sticking and hole stabilization is a problem. Using OBM results in fewer drilling problems and causes less formation damage than WBMs and they are therefore very popular in certain areas. OBM is normally used in extremely hot formations and when water-based muds adversely afect formation. In general, OBMs are applied in directional wells and horizontal wells. It is also used to drill and core (i.e. collection of samples for analysis) pay zones, to drill troublesome formations (i.e. shale) and to reduce corrosion.

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OBMs consist of three types – i) invert emulsion oil-based mud, ii) pseudo oil-based mud and iii) full oil mud. he ratio of oil to water or brine is 50:50 to 80:20. Various chemicals, such as surfactants, organic clay and asphalt are used to control rheological, iltration and emulsion stability. OBMs are formulated with only oil as the liquid phase and water content is less than 5%. hese types are used as coring luid or for a hostile environment. OBMs require higher additional gelling agents for viscosity, such as emulsiiers and wetting agents. OBMs are however more expensive and require more careful handling (i.e. pollution and toxicity control) than WBMs. hey are useful in drilling certain formations that may be diicult or costly to drill with water-based mud. OBMs have some advantages and disadvantages that are as follows: Advantages: 1. 1. 2. 3. 2.

Good rheological properties at temperatures as high as 500 °F More inhibitive than inhibitive water-based muds Efective against all types of corrosion Superior lubricating characteristics Permits mud densities as low as 7.5 lbm/gal

Disadvantages: 1. 1. 2. 3. 2.

Generally more expensive and higher initial cost Require more stringent pollution-control procedures Reduced efectiveness of some logging tools Remedial treatment for lost circulation is more diicult Detection of gas kicks is more diicult because of gas solubility in diesel oil

i) Invert emulsion oil-based mud: Invert emulsion drilling luids are water in oil emulsion, typically with CaCl2 brine as the emulsiied phase and mineral oil as the continuous phase. he basic components of a typical low toxicity invert emulsion luid are base oil, water, emulsiier, wetting agents, organophillic clay, and lime. Only low toxic base oil should be used within the range as mentioned earlier. his is the external emulsion phase. Water is used as an internal emulsion phase, which gives the oil/water ratio (OWR). OWR gives the percentage of each part as a total of the liquid phase. Generally, a higher OWR is used for drilling troublesome formations. he salinity of the water phase can be controlled by the use of dissolved salts, usually calcium chloride. Control of salinity in invert oil muds is necessary to tie up free water molecules and prevents any water migration between the mud and the open formation such as shale. ii) Pseudo oil-based mud: A biodegradable synthetic based oil mud. he developments such mud has been made to help the environmental problem of low toxicity oil based muds and their low biodegradability. A system that uses synthetic base oil is called a pseudo oil-based mud (SOB). Synthetic oil-based mud is deined as a mud with the oil component replaced by lower toxicity oil such as mineral oil. It is designed to behave as close as possible to low toxic oil based mud (LTOBM). It is built in a way similar to normal oil-based luids using modiied emulsiiers. SOB muds are expensive systems and should only be considered in drilling hole sections that cannot be drilled using water-based muds

Drilling Fluids 79 without the risk of compromising the well objectives. he base oils that are being used in this type of mud are the Detergent Alkalates, Synthetic Hydrocarbon, Ether and Ester. Synthetic base luids include Linear Alpha Oleins (LAO), Isomerised Oleins (IO), and normal alkanes. Other synthetic base luids have been developed and discarded such as ethers and benzene based formulations. Esters are non-petroleum oils and are derived from vegetable oils. hey contain no aromatics or petroleum-derived hydrocarbons. he primary advantage of an ester-based luid is that it biodegrades readily, either aerobically or, more importantly, from a mud cuttings disposal viewpoint, anaerobically. iii) Full-oil mud: his mud has very low water content ( 2000

Coarse

10

2000 – 250

Intermediate

60

250 – 74

Medium

200

74 – 44

Fine

325

44 – 2

Ultra-ine

–

2–0

Colloidal

–

96

Fundamentals of Sustainable Drilling Engineering 0.01 2

0.1 4 68 2

1 4 68

10 2

Dispersed Bentonite

4 68

100 4 68 2

2

1 mm 1,000 4 68 2

1cm 10,000 4 68

Barite Drilled Solids

Desilter Underlow

Centrifuge Overlow

200 mesh discard 100 mesh 60 mesh 20 mesh Fine Sand

Silt Tobacco Smoke

Milled Flour

Setting velocity in water Barite at 68° F ft/min Drilled Solids

Gravel

Course Sand

Beach Sand

0.01

0.1

0.01

1

0.1

10 1

100 10

30

50 90

Figure 3.7 Particle size for solids-control devices (Redrawn form Mitchell and Miska, 2011).

Degasser

Stand Trap

Overlow

Shale shakers

Mud Cleaner suction

Pump

Under low

Degasser Suction

Under low

Discard

Pump Suction

Under low

Flow Line

Hopper

Centrifuge suction

Centrifuge

Mud cleaner

Liquid returns

Pump Screen

Pump Screened liquid returned

Coarse solids discarded

Figure 3.8 Complete solid control system with mud cleaner and centrifuge.

Dry solids discarded

Drilling Fluids 97

Figure 3.9 Typical shale shaker (Source: http://www.slb.com/services/miswaco).

loaded with solids passes over the vibrating shaker where the liquid part of mud and small solids pass through the shaker screens. he drill cuttings are then collected at the bottom of the shaker. If the correct type of shaker is used and runs in an eicient manner, the shale shaker and scalper screens (Gumbo shakers) can efectively remove up to 80% of all solids from a drilling luid. Shale shakers are classiied into two types based on its motion: a) circular or elliptical motion, and b) linear motion. Circular or elliptical motion shakers are also known as rumba shakers. Elliptical rollers are used to generate a circular rocking motion to provide better solids removal through the screen. A linear-motion shaker uses a straight back-and-forth rocking motion to keep the luid circulating through the screens. Field experience indicates that elliptical shakers work better with water-based muds and linear-motion shakers are more suitable for oilbased muds. An absolute minimum of three shale shakers is recommended to have an eicient separation of solids. ii) Settling separation: A low-cost solids control method is to allow time for the drilling luid to settle down. In this case, the contaminated mud needs to circulate through a settling pit. hese settling control pits work on an overlow principle. he sand trap is the irst one (Figure 3.8), which is fed by the screened mud from the shale shakers. here should not be any agitation from suction discharge lines or paddles. Any large heavy solids will settle out here and will not be carried on into the other pits. Particles above colloidal size will eventually settle out in a slow condition. However, the smaller the particle, the longer it will take to settle. In some cases, for silt-sized particles, it may take days. Basically the solids will settle out more readily when a) the solid particles are large and heavy, b) the mud is light and has a low viscosity, and c) the gravitational force can be increased by mechanical means. Particle-settling velocities are given in Figure 3.7. iii) Gas removal: he trapped gas in mud must be removed in order to maintain the desired density to a level needed to control downhole formation pressures. Figure 3.10 shows a typical degasser, which is used to remove gases from mud. here are also some simple equipment such as a vacuum pump and a loat assembly. he vacuum pump creates

98

Fundamentals of Sustainable Drilling Engineering

Figure 3.10 A typical vacuum degasser (Source: http://www.udpf.com/).

a low internal pressure that allows gas-cut mud to be drawn into the degasser vessel. It is then allowed to low in a thin layer over an internal bale plate. he combination of low internal pressure and thin liquid ilm causes gas bubbles to expand in size, which rise to the surface of the mud inside the vessel. As a result, the gas breaks down from the mud. As the gas moves toward the top of the degasser it is removed by the vacuum pump. he removed gas is routed away from the rig and is then either vented to atmosphere or lared. iv) Forced settling: Desanders and desilters are similar devices, which are called hydrocyclones. hey work on the principle of separating solids from a liquid by creating centrifugal forces inside the hydrocyclone. Mud is injected tangentially into the hydrocyclone and the resulting centrifugal forces drive the solids to the walls of the hydrocyclone. Finally hydrocyclone discharges the solids from the apex with a small volume of mud (Figure 7.11). he luid portion of mud leaves the top of the hydrocyclone as an overlow and is then sent to the active pit to be pumped downhole again. Hydrocyclones come in various sizes and shapes and usually speciied by the particle sizes they are designed to remove. In general, there are four types of hydrocyclones: a) desanders, b) desilters, c) mud cleaners, and d) centrifuges. (a) Desanders: Desanders are hydrocyclones with 6-inch inner diameters or larger (Figure 3.12). he primary use of desanders is in the top-hole sections when drilling with water-based mud to help maintain low mud weights. Use of desanders prevents overload of the desilter cones and increases their eiciency by reducing the mud weight and solids content of the feed inlet. Desanders should be used if the sand content of the mud rises above 0.5% to prevent abrasion of pump liners. Desanders should never be used with oil-based muds because of its very wet solids discharge. he desander makes a cut in the 40 to 45 micron size range. With a spray discharge, the underlow weight should be between 2.5 to 5.0 ppg heavier than the input mud.

Drilling Fluids 99 Overlow opening (Liquid discharge) Vertex inder

Hydrocyclone Liquids and ine solids

Feed chamber (actual hydro cyclone size is inside diameter of cone at this point) Pressurized mud mixture enters tangentially here

Whole mud in

Slurry rotation develops centrifugal forces in cyclone. Feed inlet

Liquid moves inward and upward as a spiraling vortex

Solid are driven to the wall and are moved downward in an accelarating spiral

Apex Underlow opening (solid discharge)

Coarse solids

Figure 3.11 Principle of hydrocyclones (redrawn from Mitchell and Miska, 2011).

Figure 3.12 A typical desander (http://www.pyzyrsd.com).

(b) Desilters: Desilters are the hydrocyclones made up of large number of small diameter cones (i.e. < 6 in inner diameter). Figure 3.13 shows a typical desilter arrangement. Desilters along with desanders should be used to process low mud weights that are used to drill top-hole sections (Figure 3.14). If the mud weight needs to rise, adding the barites must do this. Low gravity solids should not be allowed in such case. Desilters are designed to remove silt-sized particles. (c) Mud Cleaners: Mud cleaners are the combination of a ine-screened (roughly 320 mesh) shale shaker under a desilter and are placed above a high energy vibrating screen (Figure 3.15). hey are used for weighed muds because barite tends to be removed with silt-sized particles. By using a mud cleaner, barite can be recovered and reused. Mud

100 Fundamentals of Sustainable Drilling Engineering

Figure 3.13 A typical desilter.

Figure 3.14 A typical desander and desilter. (Source: http://www.pyzyrsd.com)

Fine mesh screen Overlow (clean mud)

Desilting hydrocyclone Discard (sand, some silt and some barite)

Feed

Return to pit

Liquid, ines, most barite

Figure 3.15 A mud cleaner.

Drilling Fluids 101 Bowl rotation Drying zone

Liquid zone

Feed Whole mud feed

Pool Liquid return to active

Overlow liquid discharge

Beach Solids discharge

(a) Decanting centrifuge with a horizontal slender conical steel bowl

Under low coarse solids discharge

(b) Decanting centrifuge with cylinder (Mitchell and Miska, 2011)

Figure 3.16 A typical decanting centrifuge.

cleaners must be used when it becomes impossible to maintain low mud weights by use of the shale shakers alone. It is far more eicient to use desilters and process the underlow with a centrifuge than to use the screens of a mud cleaner. he use of mud cleaners with oil-based muds should be minimised because experience has shown that mud losses of 3 to 5 bbls/hr being discharged are not uncommon. (d) Centrifuges: Centrifuges use centrifugal forces to remove heavy solids from the liquid and lighter components of the mud. Figure 3.16a shows a decanting centrifuge, which consists of a horizontal conical steel bowl rotating at a high speed. he bowl contains a double-screw type conveyor that rotates in the same direction as the steel bowl at a slightly lower speed (Figure 3.16a). Normally, the decanter centrifuge involves slender cylindrical- or conical-bowl sections with a relatively large aspect ratio (Figure 3.16b). Typical bowl speeds are 1,800 to 4,000 rev/min. When mud enters the centrifuge, the centrifugal force developed by the bowl holds the mud in a pond against the walls of the pond. In this pond the silt and sand particle settle against the walls and the conveyor blade scrapes and pushes the settled solids towards the narrow end of the bowl where they are collected as damp particles with no free liquid. he liquid and clay particles are collected as overlow from ports at the large end of the bowl. Centrifuge eiciency is afected predominantly by the feed low rate. However, it is also afected by the operating parameters such as bowl speed (rpm), bowl conveyer diferential speed (rpm), and pool depth.

3.6 Measurement of Drilling Fluids Properties he API has recommended a drilling luid testing practice. hese are routine tests that are needed to ensure the quality of drilling luids. Certain tests can be carried out by the mud engineer to determine the properties of the drilling luid and ensure that it will fulill the functions described earlier. By carrying out these tests at regular intervals any deterioration in mud quality can be identiied before it causes any problems in the downhole. he following tests are normally conducted to check the quality of the drilling luids. i. ii. iii. iv.

Mud density Mud viscosity Gel strength pH determination

v. Filtration test vi. Sand content vii. Determination of liquid and solids content (mud retort)

102 Fundamentals of Sustainable Drilling Engineering viii. ix. x. xi.

Alkalinity Water hardness Water analysis Chemical analysis

xii. Chloride concentration xiii. Cation exchange capacity of clays xiv. Electrical properties

3.6.1 Mud Density he density of mud weight is an important parameter which determines the hydrostatic pressure exerted by the mud column. It is determined by weighing a precise volume of mud and dividing the weight by the volume and is expressed as m. A sample of mud is weighed in a measuring tool called a mud balance (Figure 3.17). It is a device that is used to measure the density (weight) of mud. Sometimes mud balance is used to measure cement or other liquid or slurry. A mud balance consists of a ixed-volume mud cup with a cap on one end of a graduated beam and a counterweight on the other end. A sliderweight can be moved along the beam. here is a bubble that indicates neutral level of the beam. Density is read at the point where the slider-weight sits on the beam at a neutral level. he accuracy of mud weight is normally tried to keep within +/- 0.1lbm / gal 3 (+/- 0.01 g / cm ). he mud balance provides the most suitable means of inding an accurate volume. herefore, the density of drilling muds is normally measured with a mud balance in the rig side area. However, densities of the lowing slurries can be measured by a gamma ray densitometer (Guest and Zimmerman, 1973). he procedure for the mud balance is to ill the cup with mud, put on the lid, wipe of excess of mud from the lid, move the rider along the arm till a balance is obtained, and read the density at the side of the rider toward the knife edge. hese instruments are rugged, easily calibrated, and lend themselves to ield use. A mud balance is calibrated with water or another liquid of known density by adjusting the counter weight. Normally, calibration is performed by using freshwater, having a known density in pounds per gallon i.e. lbm / gal (also known as ppg). he reading of the mud balance should be 8.33 lbm / gal, 62.3 lbm / ft 3, or 1.0 SG for freshwater mud. Weight is reported in other units such as lbm / ft 3 ; kg / m3 ; lbm / in2 / ft or psi / ft ; pptf or psi /1000 ft , kg / L, and kg / cm3 (also called speciic gravity or SG) are commonly used. Mud Density is the key to control the formation kick. High mud weight is needed i) to avoid an inlux of formation luids that can cause mud contamination, corrosion and kicks or blowouts and ii) to support the walls of the hole for borehole stability. balance arm Lid

Rider

Level glass

Knife edge Fulcrum Base

(a) Description of mud balance

(b) Mud balance

(c) Pressurized density balance

Figure 3.17 A typical mud balance (courtesy from KFUPM PETE laboratory).

Drilling Fluids 103 On the other hand, low mud weight can permit faster drilling, avoid lost circulation and combat diferential pressure sticking. Mud density is controlled by adding Barite, Hematite to increase density and water is added to reduce density. he conversion factors for mud density can be written as 3 Speciic Gravity (SG) = gm / cm

Mud gradient (MGFPS) in psi / ft

lbm / gal 8.33

lbm / gal 19.24

lbm / ft 3 62.3

lbm / ft 3 144

SG 0.433

Mud gradient (MGMKS ) in kg / cm2 / m = SG 0.1

(3.3) (3.4) (3.5)

Example 3.3: A mud engineer measured the density of the drilling luid as 10 ppg in the rig side area. Calculate the speciic gravity in gm / cm3, mud gradient in psi / ft and kg / cm2 / m. Solution: Given data: = mud density = 10 ppg m Required data: SG = speciic gravity, gm / cm3 MGFPS = mud gradient, psi / ft MGMKS = mud gradient, kg / cm2 / m he speciic gravity of the mud in gm / cm3 can be calculated by using the Eq. (3.3) as:

SG =

lbm / gal 8.33

10 8.33

1.2 gm / cm 3

he mud gradient (MGFPS) in psi / ft can be calculated using Eq. (3.4) as: MGFPS

lbm / gal 19.24

10 19.24

0.5197 psi / ft

OR MGFPS

SG 0.433 1.2 0.433 0.5196 psi / ft

he mud gradient (MGMKS ) in kg / cm2 / m can be calculated using Eq. (3.5) as: MGMKS = SG 0.1 = 1.2 0.1 = 0.12 kg / cm 2 / m

3.6.2 Mud Viscosity he term viscosity is a measure of a liquid’s resistance to low. It is a property of drilling luids and/or slurries that indicates their resistance to low. Viscosity is deined as the ratio of shear stress to shear rate. Sometime, it is called dynamic viscosity. Figure 3.18

104 Fundamentals of Sustainable Drilling Engineering Moving Plate F

V V

L

fixed Plate V=0

Shearing stress or pressure

Figure 3.18 A typical mud balance.

B

, Bingham yield point

Plastic luids

Transition from plug to laminar low Plug low Newtonian luids

, true yield point

TB

Rate shear or velocity

Figure 3.19 Flow behavior of luids.

shows the conventional explanation of the stress-strain relationship for viscosity. Mathematically viscosity can be expressed as: Shearing stress rate of shearing strain Here, A l F v s

dv dl

s

F/A dv / dl

(3.6)

= cross-sectional area = layer thickness = force = velocity = dynamic viscosity of the luid between the plate = shear stress = shear rate = velocity gradient along l-direction

he dimensions of dynamic viscosity are obtained using the Eq. (3.6), which is MLt 2 / L2 M . he unit of viscosity is poise (dyne-sec/cm2). For a mud viscosity meaL /t / L Lt surement, centipoise (cp) is used because one poise is a high viscosity which is hundred times larger than centipoise. One centipoise equals one millipascal-second. Viscosity must have a shear rate to be meaningful otherwise it would be indeterminate. A general behavior of plastic and Newtonian luids is shown in Figure 3.19. It is noted that a

Drilling Fluids 105 certain value of stress (true yield point) must be exceeded in order to initiate movement for plastic low. A transition zone of decreasing slope in which the low pattern changes from plug to viscous low follows this. he viscosity of a true (Newtonian) liquid is constant and equal to the slope of the depicting its stress-strain behavior. herefore, if the viscosity of a plastic luid is measured in a conventional manner, i.e., the ratio of shearing stress to rate of shearing strain, the value obtained will depend on the rate of shear at which the measurements were taken. Example 3.4: A moving plate with a velocity of 20 cm/s having a cross-sectional area of 10 cm2 is placed 2 cm above a ixed plate. A force of 250 dynes is required to move the upper plate. Calculate the viscosity of the luid. Solution: Given data: v = velocity = 20 cm/s = cross-sectional area = 10 cm2 A = layer thickness = 2 cm l = force = 250 dynes F Required data: = dynamic viscosity of the luid between the plate, cp he viscosity of the luid can be calculated using Eq. (3.6) as: F/A dv / dl

250 dyne / 10 cm2 20 cm / s / 2 cm

2.5

dyne s cm2

25 cp

It is well known that Newton’s law of viscosity is the most commonly used model for studying the luid low in various applications including drilling luid. he Newton model considers the parallel plate concept in luid low. It is based on a linear relationship between the viscous stress and the rate of strain. A luid that satisies this law is called the Newtonian luid. he coeicient of proportionality is known as the viscosity that depends only on temperature and pressure and also the chemical composition of the luid if the luid is not a pure substance. For a Newtonian luid, the viscosity does not depend on the forces acting upon it at all shear strain rate. Water, some lighthydrocarbon oils, air and other gases are Newtonian luids. However, water, the most abundant luid on earth, has been considered for centuries as an ideal example of a Newtonian luid. Li et al. (2007) discovered that when water molecules are forced to move through a small gap (in nanoscale) of two solid surfaces (hydrophilic/wetting), its viscosity increases by a factor of 1000 to 10,000, resulting in a behavior similar to molasses. During their experiment on hydrophobic surfaces, they did not observe such an increase in viscosity. heir indings are in good agreement with the molecular dynamics simulation results that show a dramatically decreased mobility for sub-nanometer thick water ilms under hydrophilic coninement. hey concluded that water has viscous and solid-like properties at its molecular level and is organized into layers. At the nanometer scale, water is a viscous luid and could be a much better lubricant. his study received much attention from the general scientiic community as well as the

106 Fundamentals of Sustainable Drilling Engineering general public because of its potential applications to nanotechnology (Mauk, 2007). However, the fact that any luid behaves diferently under molecular constrains from larger scale has been known for some time. he slow-moving low of a thin ilm of liquid is a ubiquitous phenomenon. his low exists in nature such as in lava lows, the linings of mammalian lungs, tear ilms in the eye, and in artiicial instances such as microchip fabrication, tertiary oil recovery as well as in many coating processes (Perazzo and Gratton, 2003). herefore, the natural phenomena, for which viscous luid low exists, are normally non-Newtonian type of low (Perazzo and Gratton, 2003; Arratia et al., 2005). In general most of the drilling luids are either emulsions or/and colloids that behaves as plastic or non-Newtonian luids (Hossain et al., 2007 and Hossain and Islam, 2009). hey also mentioned that almost all the underground hydrocarbons behave as non-Newtonian luids. In response to the above considerations, Hossain et al. (2007) developed a new stress-strain relationship, which can be written as: t

sT

T T D Ma

0

2

t 1

p d x

0.5

0.5

6K

0

p x

e

E RT

dux dy

(3.7)

Here E K Ma p R T t

= activation energy for viscous low, KJ/mol = operational parameter = Marangoni number = pressure of the system, N/m2 = universal gas constant, KJ/mol – k = temperature, °K = time, s = a dummy variable for time i.e. real part in the plane of the integral ux = luid velocity in porous media in the direction of x axis, m/s y = distance from the boundary plan, m = surface tension, N/m = fractional order of diferentiation, dimensionless = thermal difusivity, m2/s D T = TT To =temperature diference between a temperature and a reference temperature, °K = luid dynamic viscosity, Pa-s = luid dynamic viscosity at reference temperature T0, Pa-s o = shear stress at temperature T, Pa sT = ratio of the pseudopermeability of the medium with memory to luid m3 s1 viscosity, kg dux = velocity gradient along y-direction, 1/s dy T

= the derivative of surface tension with temperature and can be positive or negative depending on the substance, N/m-K

Drilling Fluids 107 It should be mentioned here that the irst part of Eq. (3.7) is the efect of surface tension, the second part is the efect of luid memory with time and the pressure gradient, the third part is the efect of pressure, viscosity, pseudo-permeability, the fourth part is the efect of temperature on the stress-strain equation and the ith part is the velocity gradient in the y-direction which is called the rate of velocity change i.e. rate of shear strain. he second part is in a form of convolution integral that shows the efect of the luid memory during the low process. his integral has two variable functions and 2 p / x where the irst one is a continuous changing function and of t is an overlapping function the second one is a ixed function. his means that t x in the mathematical point of view. hese two funcon the other function, 2 p / tions depend on the space, time, pressure, and a dummy variable. In the original reference, there is a negative sign with a power of 0.5, which indicates the direction of low. herefore, it is not shown here. Interested readers might refer to references of the irst author of the book including Hossain et al. (2009).

3.6.2.1

Measurement of Mud Viscosity

Mud viscosity is diicult to measure. In general several measuring devices are used. Further complication generally arises due to the diferent value given by diferent methods. here are two common methods used to measure viscosity at drilling rig area – i) Marsh Funnel, and ii) Rotational viscometer. i) Marsh Funnel: Marsh Funnel viscometer is a very quick test that only gives as indication of viscosity and not an absolute result. Measuring viscosity by a Marsh Funnel is useful as a comparative value and is recorded in seconds. It is a conical-shaped funnel itted with a small bore tube on the bottom end through which mud lows by the action of gravity force (Figure 3.20). his test is one of the earliest mud viscosity measurements for ield applications. It is a simple device to measure the viscosity and is used by mud engineers to check the quality of drilling mud. he funnel consists of a cone of 12 in long, and 6 in diameter at the top; and 2 in long tube at the bottom with 3/16 in internal diameter. A 1/8 in mesh screen is ixed near the top across half the cone to block the solid particles existence of the mud if any. During the measurement of viscosity, a Marsh Funnel is put vertically and the end of the tube is closed with a inger. A mud sample is poured through the mesh to the funnel and it ends when the mesh is reached. his gives a volume inside of about 1.5 liters. To take the measurement, the inger is 6 in. 1

/8-in. mesh screen 12 in.

Copper tube drilled 3/16 in.

Figure 3.20 Viscosity measuring device: Marsh Funnel and mud measuring cup.

2 in.

108 Fundamentals of Sustainable Drilling Engineering released and a stopwatch is started. As a result, the liquid starts to run into a measuring container or cup. he time in seconds is recorded for one quart (946 ml) to low out into a measuring cup as a measure of the viscosity. So, funnel viscosity is reported in seconds of a quart, which is referred to as MF ignoring the unit “seconds”. he quart Marsh Funnel time is 34 – 50 seconds for typical drilling muds. However, mud mixtures may have a time of 100 or more seconds to cope with some geological conditions. he measuring technique is simple, quick and foolproof. It still serves as a useful indicator of change in the mud by comparing mud-in and mud-out sample funnel viscosities. However, since the low rate varies throughout this test it cannot give a true viscosity. Moreover, the Marsh Funnel is not a rheometer because it only provides one measurement under one low condition. he funnel viscosity may be used for checking any radial changes in mud viscosity. Further tests must be carried out before any treatment can be recommended. Normally most of the drilling luids are non-Newtonian in nature and exhibit different viscosities at diferent low rates. Pitt (2000) introduced a new formula to measure the efective viscosity by Marsh Funnel. He showed the low behavior of a Marsh Funnel that is numerically simulated to get a general picture of the meaning of the Marsh Funnel time. He developed a correlation allowing this to be converted into a value for efective viscosity. For ield use, the following equation is obtained as e

M

tM

(3.8)

25

Here e

tM M

= the efective viscosity, cp = the Marsh Funnel (quart) time, s = density of mud, g/cm3

Example 3.5: A Marsh Funnel is used to measure the density of the drilling luid which is 1.2 g/cm3 in 50 seconds. Calculate the efective viscosity using Marsh Funnel equation. Solution: Given data: = mud density = 1.2 g/cm3 M = time = 50 sec Required data: = efective viscosity, cp e he efective viscosity of the mud in cp can be calculated by using the Eq. (3.8) as: e

M

tM

25

1.2 50 25

30 cp

ii) Rotational Viscometer: A viscometer is an instrument used to measure the viscosity of a luid, which is also called viscosimeter. It gives a more meaningful measure of viscosity. A typical Stormer Viscometer is shown in Figure 3.21a. Normally a rheometer is used for those liquids where viscosities vary with low conditions. In general, either the luid remains stationary and an object moves through it, or the object is stationary and

Drilling Fluids 109 the luid moves through it. he drag caused by relative motion of the luid and a surface is a measure of the viscosity. he low conditions must have a suiciently small value of Reynolds number for there to be laminar low. A sample of mud is sheared at a constant rate between a rotating outer sleeve and an inner bob. he test is conducted at a range of diferent speeds such as 600 rpm, 300 rpm, and 100 rpm etc. (laboratory models can operate at 6 diferent speeds). he standard procedure is to lower the instrument head into the mud sample until the sleeve is immersed up to the scribe line. he rotor speed is set at 600 rpm and ater waiting for a steady dial reading this value is recorded (degrees). he weight or driving force in grams is then used with a calibration chart to obtain the mud viscosity. his value is the apparent viscosity of the mud measured at a rate of shear corresponding to 600 rpm of the instrument. he speed is then changed to 300 rpm and again the reading is recorded. his is repeated until all of the required dial readings have been recorded. he results can be plotted as shown in Figure 3.21b. Only two standard speeds are possible on most models designed for ield use. During the measurement of apparent viscosity in centipoise, the dimensions of the bob and rotor are chosen so that the dial reading is equal to the apparent viscosity at a rotor speed of 300 rpm. Now, the apparent viscosity at any other speeds, N is given by: 300 N

app

N

(3.9)

Here N

N app

= torque reading from the dial at a speed N, rpm = rotor speed, rpm = apparent viscosity at a speed N rpm, cp

Example 3.6: A mud sample in a rotational viscometer gives a dial reading of 450 at 600 rpm and a dial reading of 260 at 300 rpm. Compute the apparent viscosity of the mud at each rotor speed. Solution: Given data: = torque reading from the dial = 450 for 600 rpm N = 260 for 300 rpm N = rotor speed = 600 and 300 rpm Required data: app = apparent viscosity at 600 rpm and 300 rpm, cp he apparent viscosity of the mud in cp can be calculated by using the Eq. (3.9) as: app

app _ 600

app _ 300

300 N N 300 45 22.5 cp 600 300 27 27 cp 300

110 Fundamentals of Sustainable Drilling Engineering CALIBRATION CURVE FOR STORMER VISCOCIMETER

Vicosity in centipoises

120 100 80 60 40 20 0 0

40 80 120 160 200 240 280 320 360 400 Driving force in grams for 600 rpm

(a) Stormer viscosimeter

(b) Calibration chart

Figure 3.21 Viscosity measuring device.

he viscometer can also be used to determine rheological parameters such as plastic viscosity and yield point that describe non-Newtonian luid behavior. he other kind of viscometer, a Fann V-G (viscosity-gel) meter is a multispeed measuring device which measures the rheological parameters (Figure 3.22a). he high pressure and high temperature (HPHT) viscometer is also shown in Figure 3.22b. In principle, a Fann meter is like the Stormer where the basic measurement is the torque necessary to revolve an inner rotor in a stationary, mud-illed test-cup. he spindle is driven by a two-speed synchronous motor. Torque readings are obtained directly from a dial on the instrument. he instrument constants are adjusted so that the slop of the linear portion of the low curve may be obtained as the diference between the 600 and 300-rpm torque readings. his slope is deined as plastic viscosity (rigidity) and is given by centipoise (Figure 3.23). Plastic Viscosity is thought of as that part of the low resistance caused by mechanical frictions (i.e. solid content). It is due to the friction between solid particles in the mud and the viscosity of the dispersed phase (base liquid). It is dependent on solid content. he plastic viscosity is normally computed using the below relationship: p

600

300

(3.10)

Here 300 600 p

= torque reading from the dial at a speed of 300 rpm, rpm = torque reading from the dial at a speed of 600 rpm, rpm = plastic viscosity, cp

he yield point can be computed using the following formula as: B

Here B

= the Bingham yield point,

300

lb f 100 ft 2

p

(3.11)

Drilling Fluids 111

(a) Fann V-G meter

(b) HTHP Pressure Viscometer

Figure 3.22 Viscosity measuring device, courtesy from KFUPM PETE laboratory.

600

Dial delection,

Slope proportional to plastic viscosity 300

Slope proportional to apparent (600 rpm) viscosity B

0

300 Setting, rpm

600

Figure 3.23 Measurement of plastic low properties with the Fann V-G meter.

From Eq. (3.10) and Eq. (3.11), yield point can be calculated as: 600

B

2

(3.12)

p

In Eq. (3.9), using the dial delection for 600 rpm, the apparent viscosity becomes: 300 600 600

app

1 2

600

(3.13)

he use of Eq. (3.13) forms the Eq. (3.12) as: B

2

app

p

(3.14)

True yield point can be deined using Figure 3.19 for plastic or Bingham luids as: 3 4

TB

Here TB

= true Bingham yield point,

lb f 100 ft 2

B

(3.15)

112 Fundamentals of Sustainable Drilling Engineering In summary, diferent viscosity measuring devices give diferent viscosity of the drilling luid. he Marsh Funnel gives the viscosity, which is useful as a comparative value and is recorded in seconds. Stormer viscosity provides the apparent viscosity that is expressed in centipoise. However, it has limited value since it is valid at only one rate of shear. he Fann V-G meter measures the viscosity, which is called the plastic viscosity and represents the rate of change of shearing stress with respect to shearing strain over the linear portion of the consistency curve. Finally, yield point is calculated which is useful in hydraulic calculations. Example 3.7: Using the data of Example 3.5, compute the plastic viscosity yield point and true yield point of the mud sample. Solution: Given data: = torque reading from the dial = 450 for 600 rpm N = 260 for 300 rpm N = rotor speed = 600 and 300 rpm Required data: = plastic viscosity, cp p = Bingham yield point, lb f /100 ft 2 B = true yield point, lb f /100 ft 2 T he plastic viscosity of the mud in cp can be calculated by using the Eq. (3.10) as: 600

p

300

45 26 19 cp

he yield point of the mud can be calculated by using the Eq. (3.11) as: 300

B

p

26 19 7 lb /100 ft

he true yield point of the mud can be calculated by using the Eq. (3.15) as: T

3.6.3

3 4

B

3 7 4

5.25 lb f /100 ft 2

Gel Strength

Most drilling luids are either colloids or emulsions, which behave as plastic or nonNewtonian luids. Some muds are thixotropic too. hey form gelled structures when stagnant and liquefy when sheared. he low characteristics of these muds difer from Newtonian luids (i.e. water, light oils, etc.) and their viscosities vary with the rate of shear, as shown in Figure 3.19. Apart from the two parameters (i.e. plastic viscosity and yield point) of a Bingham plastic luid as discussed before, a third non-Newtonian rheological parameter is called get strength. he gel strength is a function of the inter-particle forces. Gel strength can be deined as a measure of the ability of a colloidal dispersion to develop and retain a gel form based on its resistance to shear. It is a measure of the shearing stress necessary to initiate a inite rate of shear. In other word, it can be stated as the gel, or shear strength of a drilling mud, which determines its ability to hold solids in

Drilling Fluids 113 suspension. It is the ability or a measure of its ability to form gels. Sometimes bentonite and other colloidal clays are added to drilling luid to increase its gel strength. As gel strength is directly related to shear stress, it is related to the viscosity of luid. herefore, the viscosities of plastic luids depend on the rate of shear at which the measurements are normally taken. Hence, these measurements are normally taken and reported as initial gel strength and inal gel strength. Fundamentally, for Bingham luids initial gel strength and true yield value should be the same. Figure 3.24 depicts that the speciic gel strength of a drilling luid is described as low-lat (most desirable), progressive or high-lat (both undesirable) according to its measured gel strength versus time, as shown on this plot. Gel strength can be measured using the viscometer. he Baroid Rheometer is also used to determine the gel strength of a mud in lb f /100 ft 2 . Ater the mud has remained static for some time (10 sec) the rotor is set at a low speed (3 rpm) and the delection is noted. his is reported as the “initial 10-second gel”. he same procedure is repeated ater the mud remains static for 10 minutes, to determine the “10-minute gel”. Both gels are measured in the same units as yield point. Gel strength measurement gives an indication of the amount of gelation that will occur ater circulation ceased and the mud remains static. he more the mud gels during shutdown periods, the more pump pressure will be required to initiate circulation again. Gel strength usually appears on the mud report as two igures (example: 18/26). he irst igure indicates the initial gel and the second one indicates as the 10-minute gel.

3.6.4

pH Determination

he pH of a drilling luid is a measure of the acidity or alkalinity of the mixing water. he pH of a solution is the logarithm of the reciprocal of the H concentration in grams moles per liter, which can be mathematically expressed as: log

pH

1

(3.16)

log H

H

Diferent types of gel strengths in muds esirable) High-flat (und

0.80

0.60

Pr og (u nd ress i es ira ve bl e)

Gel strength (lb/100 ft2)

0.70

0.50 0.40 0.30 0.20

Low-flat (desirable)

0.10 0

0

10

20

30

40 50 60 Time (min)

70

80

90

Figure 3.24 Variation of gel strength with time for drilling muds (redrawn from oil glossary).

114 Fundamentals of Sustainable Drilling Engineering

pOH

1

log

(3.17)

log OH

OH

Where (H+) and (OH–) are the hydrogen and hydroxyl ion concentration in moles/ liter. he acidity and the alkalinity of the drilling luid can be measured by the concentration of the [H+] ion in the luid. As for instance, if [H+] is large (1 10 1), then the [OH–] concentration is very low (1 10 13 ), the solution is strongly acidic. If the [OH–] concentration is (1 10 1) very high then [H+] concentration is very low then the solution is strongly alkaline. For example, for pure water, pH is equal to 7 where both [H+] and [OH–] concentrations are same. Since the product {[H+][OH–]} must remain constant for any aqueous solution, an increase in [H+] requires a corresponding decrease in [OH–]. herefore, a solution in which [OH–] > [H+] is said to be alkaline, and a solution in which [H+] > [OH–] is said to be acidic. In general, if the pH of a drilling luid drops from 7.0 to 6.0, the number of [H+] ions increases ten times. In contrary, if the pOH of a drilling luid drops from 7.0 to 6.0, the number of [OH–] ions decreases ten times. he pH of a mud is seldom below 7 and in most cases, falls between 8 and 12.5 depending upon the type of mud. he unbalanced pH of the muds afects the rate of mud mixing, borehole stability, mud properties, corrosiveness, viscosity, gel development, and iltration control. pH is also important because it afects the solubility of certain organic thinners and the dispersion of clays present in the mud. Corrosion rates are suppressed in muds with pH above 10. herefore, the best desired operating pH for drilling mud is generally 8.5 to 9.5. Sometimes, pH is kept slightly above 11 if hydrogen sulide (H2S), a poisonous gas, is suspected in the mud. However, very high pH (above 11.5) should be avoided, because it is detrimental to most organic additives and causes locculation of clay. Example 3.8: Find out the pH of an aqueous solution where both [H+] and [OH–] ions are same and equal to 1 10 7. Find out the pOH also. Solution: Given data: = hydrogen ion concentration = 1 10 7m/l [H+] [OH–] = hydroxyl ion concentration = 1 10 7m/l Required data: pH = pH of drilling mud, m/l pOH = pOH of drilling mud, m/l he pH of the mud in m/l can be calculated by using the Eq. (3.16) and Eq. (3.17) as: pH

log

pOH

log

1 H

log

1 1 10

log 1 10

7

7

7

7.00

and 1 OH

log

1 1 10

7

log 1 10

7

7

7.00

Drilling Fluids 115

Figure 3.25 Methods of measuring pH Hydrion pH Dispensers (let) and Digital pH Meter (center and right), courtesy from KFUPM PETE laboratory.

he pH test is used to express the concentration of hydrogen ions in an aqueous solution. his can be done either by pH paper (example: hydrion paper) or by a special meter. pH paper strips have dyes absorbed onto the paper, which display certain colors in certain pH ranges (Figure 3.25). It is a useful, inexpensive method to determine pH in freshwater muds. he main disadvantage is that high concentrations of salts (10,000 ppm chloride) will alter the color change and cause inaccuracy. Figure 3.25 shows a digital pH meter, which is an electrometric device utilizing glass electrodes to measure pH. It is a controlled microprocessor and provides very accurate and reliable measurements with a resolution of 0.01 pH over a full range of 0–14 pH. It also displays temperature and mV readings simultaneously, on an LCD screen. he device has the Automatic Temperature Control (ATC) probe in the range of 0 to 100°C, which automatically adjusts the readout to measure temperature variations in the luid. he pH readings when the ‘READY’ indicator is displayed are recorded. his shows that the readings are stable within a range of 0.01 pH.

3.6.5 Filtration Tests he iltration properties of a luid determine its ability to form a controlled ilter cake on the sidewalls of the borehole. In a drilling mud, the iltration properties afect borehole stability, smooth movement of the drill string, formation damage, and development time. he ilter cake should not exceed a sixteenth of an inch in thickness and should be easily removable with the back low. he ilter cake, formed from the solid constituents in the drilling luid, controls the loss of liquid from a mud due to iltration. he test in the laboratory consists of measuring the volume of liquid forced through the mud cake into the formation in a 30-minute period under given pressure and temperature conditions using a standard size cell. here are two commonly determined iltration rates used which are as the low-pressure low-temperature and the high-pressure high-temperature. Controlled high iltrate will minimize chip hold down and provide for faster drilling. Low iltrate may be desired to combat a tight hole caused by thick ilter cake, diferential pressure sticking, and the formation of productivity damage. In terms of rheology, high viscosity and gel strength may be desired to combat high torque bridging, drag, and ill caused by borehole cleaning, and to provide good suspension of weight material. Low viscosity and gel strength result in faster drilling and the more eicient separation of drilled solids. It has been found in early work that the volume of luid lost is roughly proportional to the square root of the time for iltration, i.e. v t. his procedure is based on the observation as well.

116 Fundamentals of Sustainable Drilling Engineering “T” scrow

Top cap

Top bar

Rubber gasket

Air hose Pressure inlet Mud cup Frame Center bar Graduated cylinder Support rod Thumb screw Support

Cell Rubber gasket Fillter paper Screen Rubber gasket Base cap with iltrate tube Filtrate tube

Figure 3.26 Standard API Filter Press, courtesy from KFUPM PETE laboratory.

Figure 3.27 High Temperature High Pressure Filter Press, courtesy from KFUPM PETE laboratory.

he ilter press instrument consists of a mud cell, pressure assembly and iltering device etc. (Figure 3.26). he low-pressure test is conducted using a standard cell under the API speciication of 100 + 5 psi for 30 minutes at room temperature. Filter press used for iltration tests that consists of four independent ilter cells mounted on a common frame. Each cell has its own valve such that any or all the cells could be operational at the same time. Toggle valve on the top of each cell could be operated independently for the supply of air for each individual cell. Figure 3.27 depicts a special cell, which must be used to measure iltration rate at high pressure and temperature (500 psi, 300°F). Special high pressure and high temperature iltration tests are run in the laboratory simulating formation temperature and formation back- pressure. he cell is closed at the bottom by a lid that is itted with a screen. On top of the screen is placed a ilter paper, which is pressed up against an O-ring seal. A graduated cylinder is placed under the screen to collect the iltrate. he pressure of 100 psi is applied for a period of 30 minutes and the volume of the iltrate can then be measured in cm3. When the pressure is bled of the cell can be opened and the ilter paper is examined. he thickness of the ilter cake is measured in 1/32’s of an inch. It is noted that this type of test does not simulate downhole conditions in that only static iltration is being measured. In the wellbore, iltration is occurring under dynamic conditions with the mud lowing past the wall of the hole.

Drilling Fluids 117

3.6.6 Sand Content he sand content of a drilling luid is deined as any particle larger than 74 microns in size, which is measured by using a 200-mesh sieve and a sand content kit. For example, the Baroid sand content set consists of a 200-mesh sieve, funnel, and a glass measuring tube calibrated from 0 to 20% to read directly the percentage sand by volume. Figure 3.28 shows the sand content test equipment. he test may be performed on low solids muds as well as on weighed muds. Periodic sand content determination of drilling luid is important. Excessive sand may result in the deposition of a thick ilter cake on the wall of the hole. It may settle back into the hole when circulation is stopped. High sand content also may cause excessive abrasion of pump parts and pipe connections and interferes with drilling tools and the setting of casing. Elutriation, settling, or sieve analysis determines sand content. Of the three methods, sieve analysis is preferred because of reliability of test and simplicity of equipment. he volume of sand, including void spaces between grains, is usually measured and expressed as percentage by volume of the mud. he glass-measuring tube is illed with mud up to the scribe line. Water is then added up to the next scribe line. he luids are mixed by shaking and then poured through the sieve. he sand retained on the sieve should be washed thoroughly to remove the remaining mud. A funnel is itted to the top of the sieve and the sand is washed into the glass tube by a ine spray of water. Ater allowing the sand to settle, the sand content can be read of directly as a percentage.

3.6.7 Determination of Liquid and Solids Content Knowledge of the liquid and solid content of a drilling luid is necessary for better control of the mud properties. Such information will oten explain poor performance of the mud and indicate whether the mud can best be conditioned by the addition of water or whether treatment with chemical thinner or the removal of the contaminant is required. Similarly, proper control of an oil-emulsion mud depends upon knowledge of the oil content. For muds containing only water and solids, the quantity of each can be determined from the mud density and from the evaporation of a weighed sample of mud. Oil and water content can also be obtained measuring the liquid fraction. he latter method is only applicable to oil emulsion muds. Baroid Oil and Water Retort Kit are used to determine the amount and type of solids and liquids presence in a drilling mud sample (Figure 3.29).

Sand ilters

Measuring cylinder Solids scale

Figure 3.28 Sand Content Set.

118 Fundamentals of Sustainable Drilling Engineering

Figure 3.29 Oil/Water Retort Kit. (Courtesy from KFUPM PETE laboratory)

A carefully measured sample of mud is placed in the steel container and then heated in a retort until the liquid components are vaporized. he vapor is passed through a condenser in which it is cooled and then collected in the measuring glass (i.e. graduated cylinder). he volume of liquids (oil and/or water) is measured as a fraction of the total mud volume. he volume of solids (suspended and dissolved) is found by subtracting from 100%. For accurate results a true mud density should be used for calculations. An accurate air free sample must be used and a volume correction factor should be determined for oil content if it is present in the mud. he solids volume fraction of mud can be mathematically obtained as fs Here Cf fo fs fw

1 fw C f

fo

(3.18)

= volume increase factor due to the loss of dissolved salt during retorting = volume fraction of oil phase in the mud system, vol/vol = volume fraction of solids in the drilling mud, vol/vol = volume fraction of water phase in the mud system, vol/vol

Example 3.9: A 11 lbm/gal saltwater mud is retorted and found to contain 8% oil and 72% water. If the chloride test shows the mud to have a chloride content of 79,000 mg Cl / L, Find out the solid fraction of the mud? Assume that the mud is a sodium chloride mud. he solution has 12% salinity and NaCl has a volume increase factor of 1.045. Solution: Given data: fw = water volume fraction of drilling mud = 0.76 fo = oil volume fraction of drilling mud = 0.08 Cf = volume increase factor due to the loss of dissolved salt during retorting = 1.045 Required data: fs = solids volume fraction of drilling mud, vol/vol

Drilling Fluids 119 he solid volume fraction can be calculated by using the Eq. (3.18) as: fs

1 fw C f

fo

1

0.76

1.045

0.08 0.1258

3.6.8 Alkalinity Although pH gives an indication of alkalinity, it has been observed that the characteristics of a high pH mud can vary considerably despite constant pH. A further analysis of the mud is usually carried out to assess the alkalinity. herefore, an alkalinity test is essential to keep the quality of drilling mud. Alkalinity is an indication of the acid neutralizing power of a substance. Alkalinity measurements in drilling luid testing may be made on the whole mud (designated with a subscript m) or on the iltrate (designated with a subscript f). he data collected can also be used to estimate the concentrations of hydroxyl (OH–), carbonate (CO3-2) and bicarbonate (HCO3–) ions in the drilling luid. Knowledge of the mud and iltrate alkalinity is important in many drilling operations. Mud additives, particularly some organic delocculants, require an alkaline environment in order to function properly. Alkalinity arising from hydroxyl ions is generally accepted as being beneicial while alkalinities resulting from carbonates or bicarbonates may be detrimental to mud performance. he ions that are primarily responsible for iltrate alkalinity are the hydroxyl (OH–), carbonate (CO3-2) and bicarbonate (HCO3–) ions. he carbonates can change from one form to another by changing the pH of the solution. Other inorganic ions such as borate’s, silicates, sulides and phosphates may also contribute to the alkalinity. It is important to realize the following calculations are only estimates of the concentrations of the reported ionic species based on theoretical chemical equilibrium reactions. he composition of mud iltrates is oten so complex that the interpretation of alkalinities may be misleading. Any particular alkalinity value represents all of the ions that will react with the acid within the pH range over which that particular value was tested. Anionic organic thinners and iltrate reducers contribute to a large portion of the Mf alkalinity value and may also mask the endpoint color change and render the test highly inaccurate in muds treated with organic thinners. For simple bentonite-based mud systems containing no organic thinners, the Phenolphthalein (Pf) and the methyl orange (Mf) alkalinities may be used as guidelines to determine the presence of carbonate/bicarbonate contamination and the treatment necessary to alleviate the problem. If organic thinners are present in large amounts, the conventional Pf/Mf test is suspect, and the P1/P2 method should be used instead.

3.6.9

Water Hardness

Water hardness of drilling luid is due principally to the calcium (Ca2+) and magnesium (Mg2+) ions present in the water. So, hard water has a high mineral content (in contrast with sot water). he minerals of hard water primarily consist of Ca2+, Mg2+, and sometimes other dissolved compounds such as bicarbonates (HCO3 ) and sulfates 2 (SO4 ). Calcium usually enters the water as either calcium carbonate (CaCO3), in the form of limestone and chalk, or calcium sulfate (CaSO4), in the form of other mineral deposits. he predominant source of magnesium is dolomite (CaMg(CO3)2). Water is an excellent solvent and readily dissolves minerals when it comes in contact with them.

120 Fundamentals of Sustainable Drilling Engineering Table 3.9 Classical water hardness scale for drilling muds. Water Hardness Scale Classiication

mg/l or ppm

Grains/gal (gpg)

0 – 17.1

0 – 1.0

Slightly hard

17.1 – 60.0

1 – 3.5

Moderately hard

60.0 – 120.0

3.5 – 7.0

Hard

120.0 – 180.0

7.0 – 10.5

> 180.0

> 10.5

Sot

Very hard

As water moves through a formation of soil and rock, it dissolves very small amounts of minerals and holds them in solution. During the circulation of drilling luid while drilling operations continue, calcium and magnesium dissolved in water and thus makes water “hard”. Table 3.9 shows the diferent level of hardness scale of water based on the total concentrations of Ca2+ and Mg2+ iron. Determination of water hardness (i.e. Ca2+ content) involves a titration of a prepared solution, sometimes called wet titration. he hardness of water can be estimated by three types of measurements; i) milligrams per liter (mg/l), ii) parts per million (ppm), and iii) grains per gallon (i.e. one grain of hardness equals 17.1 mg/L). Usually, hardness is measured in terms of ppm of CaCO3 or Ca2+ and sometimes weight/volume (mg/l) of Ca2+. It means that total water ‘hardness’ (including both Ca2+ and Mg2+ ions) is read as ppm or mg/l of CaCO3 in the water. Although water hardness usually measures only the total concentrations of Ca2+ and Mg2+ iron, aluminium, and manganese may also be present at elevated levels in some geographical locations. Soda ash (i.e. Na2CO3) is used in water-based muds as a source of carbonate ions to precipitate calcium, increase pH or locculate spud muds. It is a weak base that is soluble in water and dissociates into sodium (Na ) and carbonate (CO3 2 ) ions in solution. he chemical reaction of calcium/ magnesium precipitation can be described as: Ca 2 or Ma

2

Na2CO3

CaCO3 or (MaCO3 )

Na

(3.19)

3.6.10 Water Analysis Water analysis of mud is necessary because the existence of chemical content may afect the selection of the mud type. he invasion of water and soluble salts may change the properties of the mud in drilled formations. Usually the simple tests for alkalinity, chloride and hardness serve to identify any objectionable contaminants from water. Occasionally, a more detailed analysis is needed that are available in literature.

3.6.11 Chemical Analysis he chemical analysis is an important test to ind out the concentration of diferent ions that exist in drilling mud. hese analyses may be used for formation identiication,

Drilling Fluids 121 compatibility studies, quality control, or evaluation of pollution problems. he concentration of hydroxyl (OH–), chloride (Cl–), sulides (S–2), potassium (K+), formaldehyde (CH2O), etc. are required to control for mud quality, which is an API standard. he test kits contain all chemicals, equipment and glassware for measurement in the ield. For results of these analyses to be accurate and reliable, care must be exercised in taking the drilling luid samples. Most chemical analyses are performed on the drilling luid iltrate rather than the drilling luid. To obtain a sample of drilling luid iltrate, the drilling luid is iltered using a standard API, 100 psi (690 kPa) ilter press or a high temperature high pressure ilter press. his operation removes all solids but leaves the dissolved salts. Some iltrates are so darkly colored the iltration endpoints cannot be seen. Literature shows that certain chemical analyses are useful in the control of mud performance. For example, an increase in chloride content may adversely afect mud properties unless the mud has been designed to withstand contamination by salt. he detail analysis is available in API RP 13B.

3.6.12 Chloride Concentration he amount of chloride (Cl–) in the mud is a measure of the salt contamination from the formation. Chloride concentration increases due to the entrance of salt and subsequently contaminates the mud system. his situation arises when a salt formation is drilled or saline formation water enters the wellbore. he Cl– concentration is determined by titration with silver nitrate (AgNO3) solution. his procedure results the Cl– to be removed from the solution as AgCl, a white precipitate. he chemical reaction is obtained as: Ag

Cl

AgCl

(3.20)

he endpoint of the titration is identiied using a potassium chromate K 2CrO4 indicator. he excess Ag+ present ater all Cl– has been removed from solution reacts with the chromate (CrO4 2) to form Ag 2CrO4 which is an orange red precipitate. he chemical reaction is obtained as: Ag

CrO4 2

Ag 2CrO4

(3.21)

he above procedure involves taking a small sample of iltrate, adding phenolphthalein and titrating with acid until the color changes. Add 25 – 50 ml of distilled water and a small amount of potassium chromate solution. Stir continuously while silver nitrate is added drop by drop. he end point is reached when the color changes. he chloride content is calculated from: Cl content in ppm

ml of AgNO3 ml of filtrate sample

(3.22)

3.6.13 Cation Exchange Capacity of Clays he clay content of a drilling luid has the ability to exchange free cations located in the aqueous solution. A well-known application of the ion exchange reaction is the sot ening of water. Ion exchange reactions in the drilling luids are important because the

122 Fundamentals of Sustainable Drilling Engineering ability of the clay particles to hydrate depends greatly on the presence of free cations. he ability of one cation to replace another depends on the nature of the cations and their relative concentrations. he common cations will replace each other when present in the same concentration in the order as shown by Eq. (3.23): Al 3

Ba2

Mg 2

Ca2

H

K

(3.23)

Na

However the order, as shown in Eq. (3.23), can be changed by increasing the concentration of the weaker cation presence. Many organic compounds also absorb in clay structures. Methylene blue is a dye. If it is allowed to dry on glassware or other laboratory equipment, it will cause a stain that is diicult or impossible to remove. herefore, it is recommended i) to avoid spilling methylene blue, ii) thoroughly wash and dry all laboratory equipment and glassware immediately ater use, and iii) make sure methylene blue bottles are closed tightly ater use. he methylene blue dye test (MBT) is used to determine the cation exchange capacity of the solids present in a drilling mud. he methylene blue capacity gives an estimate of the total cation exchange capacity of the solids in the drilling luid. he methylene blue capacity of a drilling luid is an indication of the amount of reactive clays (i.e. bentonite or drilled solids) present as determined by the methylene blue test. Only the reactive portions of the clays present are involved in the test. Materials such as barite, carbonates and evaporites do not afect the results of the test since these materials do not adsorb methylene blue. he methylene blue capacity and the cation exchange capacity are not necessarily same. It is normally somewhat less than the actual cation exchange capacity. Methylene blue solution is added to a sample of drilling luid that has been treated with hydrogen peroxide and acidiied until saturation is noted by the formation of a “dye halo” around a drop of solids placed on ilter paper. Drilling luids frequently contain substances in addition to reactive clays that also absorb methylene blue dye. Pretreatment with hydrogen peroxide removes these efects from organic materials such as lignosulfonates, lignites, cellulosic polymers and polyacrylates, etc. he methylene blue capacity is measured by Eq. (3.24) as: Methylene Blue in ml Drilling Fluid or mud sample in ml

Methylene Blue Capacity

(3.24)

he methylene blue capacity may also be reported as pounds per barrel of equivalent bentonite, based on bentonite with a cation exchange capacity using Eq. (3.24) and which is by Eq. (3.25) and Eq. 3(26). Bentonite equivalent, Bentonite equivalent,

lbm bbl

kg m3

5 Methylene Blue Capacity 2.85 Bentonite equivalent in

lbm bbl

(3.25) (3.26)

Figure 3.30 shows the methylene blue test kit model of 425. Fann Instrument Company ofers a complete methylene blue test kit containing all reagents, glassware and hardware required to perform the methylene blue test according the API recommended

Drilling Fluids 123

(a) Model 425 test kit

(b) Model 168-00/168-00-1(OFI Testing Equipment, Inc.)

Figure 3.30 Methylene blue test kit.

practice. All items are neatly packaged in a rugged stainless steel carrying case. hey also ofer the replacement parts and reagents including methylene blue solutions in varying container sizes.

3.6.14 Electrical Properties Mud resistivity is one of the most important electrical properties of the mud. i) Mud Resistivity: is the resistance to low of electrical current through mud sysm) . Drilling mud is inluenced by tem. he resistivity is measured in ohm-m ( the dissolved salts (in ppm or gpg) and the insoluble solid material contained in the water portion. he resistivity of mud is inversely proportional to the dissolved salt concentration i.e. the greater the concentration of dissolved salts, the lower resistivity of the solution. herefore, freshwater muds usually have high resistivity and saltwater muds have low resistivity. Unlike metals, the resistivity of a solution decreases as temperature increases. It is necessary to measure resistivity because the mud, mud cake, mud iltrate resistivity exert a strong efect on the electric logs taken in that mud. he mud resistivity varies greatly from the actual resistivity values due to the various factors encountered in the actual operation. A system for measuring resistivity of the formation is attached at the lower end of a casing string while drilling operations continue. he drilling assembly includes all the necessary equipment (explained in Chapter 2), where the motor and bit are electrically isolated from the casing string. Formation resistivity measuring device is provided in the assembly. A data transmission mechanism is provided for encoding the resistivity data and transmitting it through the drilling luid to the surface location of the wellbore. Figure 3.31 shows the analog and digital resistivity meters. his testing equipment is the Baroid or Fann Resistivity Meter.

124 Fundamentals of Sustainable Drilling Engineering

Figure 3.31 Analog (let) and digital (right) resistivity meters. (Courtesy from KFUPM PETE laboratory)

3.7 New Drilling Mud Calculations he most common mud engineering calculations are those concerned with the changes of mud volume and density caused by the addition of various solids or liquids to the system. For mud calculations, the irst step is to calculate the system volume, which is the sum of the mud in the hole and surface pits. While the surface volume is readily obtained from the pit size, the downhole volume is diicult to determine. Boreholes are not always cut to gauge (the same size as bit) and unless a caliper log is available, which is unusual at the time of drilling, the true hole size must be estimated. here are two basic assumptions during drilling mud calculations: i) the volumes of each material are additive. his may immediately raise a question concerning bentonite and water mixtures since it is known that bentonite swells when wet. his expansion is due, however, to the adsorption of water, hence the clay volume increase is at the expense of water volume, and the total volume (clay plus water) is, for practical purposes, unchanged, ii) the weights of each material are additives. Solid content of the mud can be calculated using the following equations. Vsc Vm1 Vm2

(3.27)

Here Vm1 = volume of initial mud (or any liquid) in mud calculation, bbl, cc Vm2 = volume of new mixture in mud calculation, bbl, cc Vsc = volume of solids in mud calculation, bbl, cc scVsc

m1Vm1

m2 Vm2

Here sc m1 m2

= density of solids, gm/cc = density of initial mud, gm/cc = density of new/inal mud (i.e. freshwater and clay), gm/cc

(3.28)

Drilling Fluids 125 Equation (3.27) and (3.28) can be solved for solid volume and product of solid volume and density as: Vsc

Vm2

m2

m1

(3.29)

m2

sc

Equation (3.29) is not very useful because the net volume of a powdered solid is not readily measureable. However, the corresponding weight to add is: scVm 2

scVsc

m2

m1

(3.30)

m2

sc

In terms of volume percentage, Eq. (3.29) can be written as: Vsc Vm2

m2

m1

sc

m1

(3.31)

100

Example 3.10: A 10.0 lbm/gal mud contains clay of speciic gravity of 2.5 and freshwater. Compute volume percentage and weight percentage of clay in this mud. Solution: Given data: = density of solids (i.e. clay) = 2.5 x 8.33 = 20.825 gm/cc sc = density of initial mud (i.e. freshwater) = 8.33 gm/cc m1 = density of inal mud (i.e. freshwater and clay) = 10.0 gm/cc m2 Required data: Vsc = volume in percentage Vm2 scVsc = weight in percentage scVm2 he solid volume in percentage can be calculated by using the Eq. (3.31) as: Vsc Vm2

m2

m1

sc

m1

100

10.0 8.33 20.825 8.33

100 13.37%

he solid weight in percentage can be calculated as: scVsc

sc

m2Vm2

m2

Vsc Vm2

sc

m2

m2

sc

m1 m2

100

20.825 10.0 8.33 100 27.83% 10 20.825 8.33

3.8 Design of Mud Weight In general drilling mud is composed of four major components – i) water or brine phase, ii) an oil phase, iii) low density solids, and iv) high density solids. hese four components are immiscible i.e. no component dissolves in any other component to

126 Fundamentals of Sustainable Drilling Engineering any signiicant degree. his means that the four components form an ideal mixture. Mathematically, the sum of the four components volumes equals the total volume of the inal mixture. Vmix Here Vmix Vw Vo Vls Vhs

(3.32)

Vw Vo Vls Vhs

= volume of inal mixture i.e. mud = volume of the water phase in the mud system = volume of oil phase in mud the mud system = volume of the low density solid in the mud system = volume of the high density solid in the mud system

Employing Eq. (3.32), the total weight of the luid mixture is simply the sum of the weights of the components. he conservation of mass ensures that the total weight calculation is always correct. mixVmix

mmix

wVw

oVo

lsVls

hsVhs

(3.33)

Here mmix = mass of inal mixture i.e. mud mix = overall density of luid mixture i.e. mud = density of water phase in the mud system w = density of oil phase in the mud system o = density of the low density solid in the mud system ls = density of the high density solid in the mud system hs From Eq. (3.33) the overall density of the luid mixture (i.e. mud) can be written as: mix

w

Vw Vmix

o

Vo Vmix

ls

Vls Vmix

hs

Vhs Vmix

(3.34)

In terms of volume fraction, Eq. (3.34) can be written as: mix

w

fw

o

fo

ls

f ls

f hs

f ls

hs

f hs

(3.35)

where, fw Here fw fo f ls f hs

fo

1

(3.36)

= volume fraction of water phase in the mud system = volume fraction of oil phase in the mud system = volume fraction of low density solid in the mud system = volume fraction of high density solid in the mud system

he speciic gravities of typical drilling luid solids are illustrated in Table 3.10. he density changes in temperature and pressure will change the volumes of the components. Literature shows that mud compositions including solids might have a signiicant change due to the changes of pressure and temperature.

Drilling Fluids 127 Table 3.10 Speciic gravity of solids in drilling luids Drilling luid component

Speciic gravity

Drilling luid component

Attapulgite

2.89

Cuttings

Barite

4.2

Galena

Bentonite

2.6

Calcium chloride

1.96

Speciic gravity

Drilling luid component

Speciic gravity

Limestone

2.8

7.50

Sand

2.63

Hematite

5.05

Siderite

3.08

Ilmetite

4.6

Sodium chloride

2.16

2.6

Example 3.11: A well is drilled to a depth of 8000 t. he top of the oil formation is at 7600 t. and the bottom is at 8000 t. he pore pressure at 7600 t. is 3600 psi. Calculate the following: a. b. c. d.

Calculate the mud weight in pcf to balance the pore pressure at 7600 t. What mud weight should be used to over balance the pore pressure by 300 psi? What the over balance pressure if 10.6 ppg mud is used? If the fracture gradient of the formation at 7600 t.is 0.75 psi/t, what is the bottomhole pressure that will fracture the formation? e. What is the surface pressure that will fracture the formation at 7600 t.if the hole is full of water? Solution: Given data: hTVD = total vertical depth = 8,000 t hot = top of oil formation at a depth = 7,600 t. hob = bottom of oil formation at a depth = 8,000 t. PTVD = pressure at a depth 7,600 t.= 3,600 psi Required data: P x 144 a) L P x 144 b) L c)

Ph

L 144

3600 x 144

73.89 pcf 7600 10.6 x 7.48 7600 4184 psi 144

Overbalance

4184 3600 584 psi

d)

Fracturing pressure

e)

Ps

Ph

Pb

Ps

Pb

Ph 62.4 x 7600

5700

68.21 pcf

7600 3900 x 144

= 7600 x 0.75 = 5700 psi @ 7600

144 5700 3293 2406 psi

128 Fundamentals of Sustainable Drilling Engineering

3.9 Current Developments in Drilling Fluids In its endeavor to provide a sustainable low of hydrocarbon energy, the petroleum industry has been recognized by the general public as an industry that has negatively impacted the environment as a result of using either harmful materials or risky practices. his leads the industry to continuously invest in R&D to develop environmentally friendly technologies and products. For any new technology or product, the current R&D trend is toward the development of sustainable practices and expertise. As we know, drilling luids are necessary for drilling oil and gas wells. Unfortunately, drilling luids have become increasingly more complex in order to satisfy the various operational demands and challenges. he materials used in the process to improve the quality and functions of the drilling luids, contaminates the subsurface and underground systems, landills, and surrounding environment. Due to the increasing environmental awareness and pressure from environmental agencies throughout the world, it is very important to look back at the drilling luid technology to reassess its progress while it tries to take steps forward to improve the petroleum industry’s position as an environmentally friendly industry. Recently, Apaleke et al. (2012a and 2012b) conducted an extensive review on the current development of mud system.

3.9.1

Formulation of WBM

he water-based drilling luids, which simulate the performance of oil-based drilling luids, are commonly referred to as high-performance water-based muds (HPWBM) (Morton, 2005; West and Morales, 2006; Dye, 2006; Patel, 2007; Marin et al, 2009). he main beneits of HPWBM include the reduction of environmental impacts, and lower down costs associated with cuttings and luids disposal. Reid et al. (1992) evaluated a novel inhibitive water-based luid for tertiary shale that was formulated primarily from tetra-potassium pyrophosphate. hey observed that the formulation was considerably more inhibitive than other mud systems (even approached the level of that observed with OBM). Kjosnes et al. (2003) designed a water-based mud from a mixture of potassium chloride and polymers such as polyanionic celluoses/xathan gum. When this mud is applied, they observed that the formulation resulted in improved hole cleaning optimization, and hole stability. Al-Ansari et al. (2005) formulated a HPWBM comprising of partially hydrolyzed polyacrylamide (PHPA, for cutting encapsulation) and polyamide derivatives (for suppressing the hydration and dispersion tendency of reactive clays). hey concluded that the formulation which had been used successfully to drill several wells in the Arabian Gulf is an environmentally friendly and performance driven alternative to OBM. Young and Ramses (2006) developed a unique water-based luid by blending a hydration suppressant, a dispersion suppressant, a rheology controller (xathan gum), a iltration controller, and an accretion suppressant. he formulation according to them delivered an invert emulsion-like drilling performance. Ramirez et al. (2007) developed an aluminum-based HPWBM that was used successfully to drill an exploratory well in the Magellan Strait, Argentina. hey claimed that the HPWBM not only replaced the oil-based mud, it was also environmentally friendly. Marin et al. (2009) formulated a HPWBF from a blend of salt and polymers at diferent mud weights. hey

Drilling Fluids 129 recommended the inclusion of sized calcium carbonate if drilling through high permeability sands.

3.9.2

Formulation of OBM

OBM is the most efective drilling luid when drilling or exploring for oil in frontier areas where extremely high geothermal gradients are a major challenge. However, recently, there have been concerns about the restrictions of its use globally due to stifer government regulations, the very high cost of disposal and treatment of cuttings from the use of OBM. Nowadays, the costs of formulation have received more attention from researchers than improved formulations (Oakley et al., 1991). Miller (1950) reported that muds containing air blown asphalt were the most efective due in part to their superior plastering properties and lexibility of temperature range. Oakley et al. (1991) designed an oilbased mud based on oil-soluble polymers (amidoamines and imidazolines) that would reduce the oil on drill cuttings. Based on the results from their laboratory tests, they concluded that oil on cuttings can be reduced by up to 30% on current 50:50 oil-water ratio. Herzhet al. (2003) studied the inluence of temperature and clay/emulsion microstructure on oil-based mud of low shear rate rheology. hey concluded that organophilic clays, in interaction with the emulsion droplets, are responsible for the low shear rate. Chen et al. (2004) formulated an oil-based mud system using VERSA, LLD, BOO, and NOVA (emulsifying and oil-wetting agents) to study the efects of OBM invasion on irreducible water saturation. heir experimental indings show that originally strong water-wet Berea and limestone cores were altered to become intermediate-wet or oil-wet by OBM surfactants thus faulting the assumption of water-wetness by the NMR T2 cutof model which generally underestimates the value of irreducible water saturation (Swir). hey proposed that the magnitude of underestimation depends on the type of OBM surfactants, their concentration in the lushing luid, and the lushing time. hey suggested that the efects of OBM invasion on the NMR misinterpret the real drilling process when wettabilty alteration occurs. Controlling the invasion volume and the concentration of OBM surfactants in the invasion luid can minimize this efect.

3.9.3

Formulation of Gas-based Mud

Most of the technological improvements seen in the drilling of well with air have come from the mining industry, which is primarily associated with shallow large bore wells. he oil and gas industry has failed to make the same technological advancement in air drilling compared to wells drilled with liquid or mud systems (Mellot, 2008). However, the followings are some of the current trends in the use of air for drilling: Foam: his involves the injection of a dilute solution of a suitable foaming into the air stream. Foam efectively removed cuttings at lower annular velocities that was possible with air alone (Mellot, 2008). Aerate Mud: his involves the direct injection of compressed air from a 3-stage compressor through the standpipe into the mud system. A special check valve is placed in the drill string one joint below the Kelly to prevent the problem of mud spray when making connections (Kenneth et al., 2007).

130 Fundamentals of Sustainable Drilling Engineering Gel Foam and Stif Foam: Basically, this is the use of prepared a slurry consisting of (by weight) 98% water; 0.3% soda ash; 3.5% bentonite; 0.17% guar gum; and 1% volume of a suitable commercially available foaming agent. In recent formulations, guar gum has been substituted by other polymers and bentonite by other clays (Crews, 1964).

3.9.4 Development of Environment-Friendly Mud System he current trend in drilling luid development is to come up with novel environmentally friendly drilling luids that will rival the OBM in terms of low toxicity level, performance, eiciency, and cost. Several researchers have come up with formulations for drilling luids with minimal but not zero environmental impact. E Van Dort et al. (1996) formulated an improved water-based drilling luid based on soluble silicates capable of drilling through heaving shale, which is environmentally friendly. However, this is not recommended because silicate has the potential to damage the formation. Shake et al. (1999) suggested the use of micro-sized spherical mono-sized polymer beads as a blend to WBM to improve lubrication. haemlitz et al. (1999) formulated a new environmentally friendly and chromium-free drilling luid for HPHT drilling based on only two polymeric components. Brady et al. (1998) came up with a polyglycol enriched waterbased drilling luid that will provide high level of shale inhibition in freshwater and low salinity water-based drilling luid. However, this formulation has a defect. here must be a presence of electrolytes in the mud system to get the optimum performance. Nicora et al. (1998) developed a new generation dispersant for environmentally friendly drilling luids based on zirconium citrate. he zirconium citrate is used to improve the rheological stability of conventional water-based luids at high temperature. However, this formulation has a limitation in that the concentration of zirconium citrate may be depleted in the drilling luid due to solids absorption. To avoid some of the above mentioned problems, Sharm et al. (2001) developed an environmentally friendly drilling luid which can efectively replace oil-based drilling luid by using eco-friendly polymers derived from tamarind gum and tragacanth gum. Tamarind gum is derived from tamarin seed while tragacanth gum is from astragalus gummiier. his formulation is also cheaper and has less damaging efect on the formation. Hector et al. (2002) developed a formulation with a void toxicity based on a potassium-silicate system. he advantage of this formulation apart from being environmentally friendly is that cuttings from the use of this drilling luid can be used as fertilizer. Warren et al. (2003) developed a formulation based on water-soluble polymer amphoteric cellulose ether (ACE), which is cheaper, low in solids content, environmentally friendly but with some potential to damage the formation. Davidson et al. (2004) developed a drilling luid system that is environmentally friendly. It also removes free hydrogen sulphide, which may be encountered while drilling based on ferrous iron complex with a carbohydrate derivative (ferrous gluconate). Ramirez et al. (2005) formulated a biodegradable drilling luid. It maintains hole stability and also enables drilling through sensitive shale based on an aluminum hydroxide complex (AHC). his formulation contains some blown asphalt and therefore possesses some environmental problems. Dosunmu et al. (2010) developed an oil-based drilling luid based on vegetable oil derived from palm oil and groundnut oil. he luid did not only satisfy environmental standards, it also improved crop growth when discharged onto farmlands.

Drilling Fluids 131 he eforts of all these researchers brought drilling luid technology to a more responsible position, which is to some extent environmentally friendly and cost efective. However, these formulations still do not have zero environmental impact. h is leads to the question, is the development of a zero impact environmentally friendly drilling luid possible?

3.9.5 Application of Nanotechnology Nano-Silica, nano-graphene, and other nano-based materials have been proposed for use as alternative mud additives. A nanomaterial based mud system is deined as that mud containing at least one additive with particle size in the range of 1–100 nanometers (Amanullah et al., 2009). It is based on the number of nano-sized additives in the mud system. Mud systems can be classiied as simple nano-mud system or advanced nano-mud system. Nanomaterials in mud systems are expected to reduce the total solids and/or chemical content of such mud systems and hence reducing the overall cost of mud system development.

3.9.6 Application of Biomass Cellulose is the main component on the cell walls of trees and other plants. Its purest form is called nanocrystalline cellulose (NCC), which is treated as a strengthener and stifener of materials. Currently, a number of oil companies in Canada have teamed up to conduct research into the possibility of using NCC as an alternative drilling luid additive toward the development of a sustainable mud system.

3.10 Future Trend on Drilling Fluids here are challenges to further improve mud engineering technology. hose challenges need to be fulilled by the researchers in future. Recently, Apaleke et al. (2012a and 2012b) conducted an extensive review on the future development of drilling luid as challenges and trend of the mud engineering.

3.10.1 Cost Analysis he cost of developing environmentally friendly OBM for ield application is a future challenge because of its high cost. he future of research in drilling luid development should be directed towards the formulation of an environmentally friendly drilling luid with zero impact on the environment. his is pertinent because incidents of environmental pollution due to the discharge of oil-based drilling wastes into the environment keep increasing, while the regulations set by the government agencies and NGOs of diferent countries are restricting the use of OBMs. herefore, the use of OBM is becoming stricter. To solve the stringent pollutant contents from mud systems, Ammnullah (2010) proposed the use of waste vegetable oil in the formulation of environmentally friendly OBM. Ogunrinde and Dosunmu (2010) suggested the use of palm oil. A major multinational oil company for ofshore drilling operations had used highly

132 Fundamentals of Sustainable Drilling Engineering de-aromatized aliphatic solvents to formulate low toxicity mud system. Although these formulations have zero environmental impact, they are very expensive. As a result, bringing their cost of formulation down so that overall cost of drilling becomes cheaper is deinitely a challenge.

3.10.2 Development of Environment Friendly Mud Additives he hazardous efects of additives such as defoamers, descalers, thinners, viscosiiers, lubricants, stabilizers, surfactants and corrosion inhibitors on marine and human life had been reported. Efects range from minor physiological changes to reduced fertility and higher mortality rates. For example, Jonathan et al. (2002) reported that ferro-chrome lignosulfonate (a thinner and delocculant) afected the survival and physiological responses of ish eggs and fry. he iltration control additive CMC (carboxymethylcellulose) causes the death of ish fry at high concentrations (1000–2000 mg/ml) and physiological changes start the level of at 12–50 mg/ml. On the other hand, corrosion inhibitors such as phosphoxit-7, EKB-2-2, and EKB-6-2 cause genetic and teratogenic damages in humans. Another example of the use of toxic additive in OBM formulation was the dumping of 896 tons of drilling mud containing SOLTEX that damaged the coast of Great Britain. When questioned, both the company and the government body overseeing the industry provided only the trade name of the active additive in the dumped drilling mud as SOLTEX with no reference to the fact that SOLTEX contained potentially toxic heavy metals as revealed by Greenpeace in a publication in 1995. Information provided in the product data sheet of some additives has revealed that these additives can cause cancer in an individual if he/she is exposed to them. It is well recognized that toxic additives are the high performers. So, how will they be replaced? Answering this question obviously is one of the future challenges researchers will have to contend with.

3.10.3 Sustainability Drilling luid’s position is still in a challenging environment if its status is analyzed based on sustainability, though there is a tremendous advancement in this technology. It is due to the complex formulation of the mud system, which is needed to meet the diferent desired properties for smooth functioning while drilling. In addition, mud system’s sustainability has to do with two issues: 1) Ensuring the continuous availability of the base oils used in the formulation of environmentally friendly mud systems, 2) Executing a complete drilling program in a safe and environmentally friendly manner. hese two issues put forward a challenging environment to the researchers. Recently, Hossain (2011) proposed a sustainable drilling pathway. He also proposed a diagnostic test procedure toward the greening of the drilling luid system. Following up on his proposed protocol is a real challenge for the petroleum industry because of cost, the need for technological advancement, and availability of the innovative sustainable chemical additives. he initial steps should come considering the environmentally friendly base oils with zero toxicity as opposed to the use of conventional base oil. he sources are from plants where there is no use of toxic or unhealthy materials during the entire process. hese objectives provide researchers a challenging situation for achieving their goals. Ensuring resource availability in a timely manner is also a big challenge.

Drilling Fluids 133

3.10.4 Development of Mud and/or Additives for HTHP Applications In extremely high-temperature and high-pressure (HTHP) situations, mud systems formulated with macro- and micro-based materials (chemicals and polymers) become drastically altered (Amanullah et al., 2009). his is due to the breakage or association of polymer chains and branches by vibration, Brownian motion and thermal stress causing a drastic reduction in gelling and viscous properties. To solve this problem, nanos with excellent thermal stability and with extreme pressure consistency should be developed.

3.11 Summary he chapter covers almost all the fundamental and basic components of mud engineering. However, the industry and laboratory practices are not covered extensively in the chapter because it is available in any drilling luid manual and scope of the book. A state-of-the-art literature review on drilling luid has been completed, in order to give an idea about overall mud engineering. he chapter presents the current trends and the future challenges of the technology and also identiies where R&D personnel need to focus their attention. In addition, future research guidelines are presented focusing on the development of environmentally friendly drilling luids with zero impact on the environment. Eforts should be intensiied to develop alternatives that will transform current mud technology into a more sustainable industry. In drilling luid technologies, two main trends are currently being practiced: i) the search for new additives to increasing the performances of WBM and ii) the development and introduction of new combinations and ingredients for OBM.

3.12 Nomenclature A dB Cf E K F f ls f hs fo fs fw l p Ma mmix N R

= cross-sectional area = bit diameter = volume increase factor due to the loss of dissolved salt during retorting = activation energy for viscous low, KJ/mol = operational parameter = force = volume fraction of low density solid in the mud system, vol/vol = volume fraction of high density solid in the mud system, vol/vol = oil volume fraction of drilling mud, vol/vol = solids volume fraction of drilling mud, vol/vol = water volume fraction of drilling mud, vol/vol = layer thickness = pressure of the system, N/m2 = Marangoni number = mass of inal mixture i.e. mud = rotor speed, rpm = universal gas constant, kj/mole – k

134 Fundamentals of Sustainable Drilling Engineering = rate of penetration of the bit, t/hr = temperature, °K = time, s = the Marsh Funnel (quart) time, s = luid velocity in porous media in the direction of x axis, m/s = velocity Vls = volume of the low density solid in the mud system, bbl, cc Vhs = volume of the high density solid in the mud system, bbl, cc Vmix = volume of inal mixture i.e. mud, bbl, cc Vm1 = volume of initial mud (or any liquid) in mud calculation, bbl, cc Vm2 = volume of mixture in mud calculation, bbl, cc Vs = solid volume of rock fragments entering the mud i.e. volume of cuttings, bbl/hr Vsc = volume of solids in mud calculation, bbl, cc Vw = volume of the water phase in the mud system, bbl, cc Vo = volume of oil phase in mud the mud system, bbl, cc y = distance from the boundary plan, m = fractional order of diferentiation, dimensionless = thermal difusivity, m2/s D = density of the low density solid in the mud system, g/cm3 ls = density of the high density solid in the mud system, g/cm3 hs = density of mud, g/cm3 M m1 = density of initial mud, gm/cc m2 = density of inal mud (i.e. freshwater and clay), gm/cc 3 mix = overall density of luid mixture i.e. mud, g/cm = density of water phase in the mud system, g/cm3 w = density of oil phase in the mud system, g/cm3 o = density of solids, gm/cc sc = average formation porosity A N = torque reading from the dial at a speed N, rpm 300 = torque reading from the dial at a speed of 300 rpm, rpm 600 = torque reading from the dial at a speed of 600 rpm, rpm = viscosity of the luid between the plate = shear stress s = shear rate = a dummy variable for time i.e. real part in the plane of the integral = surface tension, N/m T = TT To =temperature diference between a temperature and a reference temperature, °K = luid dynamic viscosity, Pa-s app = apparent viscosity at a speed N rpm, cp = the efective viscosity, cp e = luid dynamic viscosity at reference temperature T0, Pa-s o = plastic viscosity, cp p lb f = the Bingham yield point, B 100 ft 2

RROP T t tM ux

Drilling Fluids 135

TB sT

= the true Bingham yield point,

lb f

100 ft 2 = shear stress at temperature T, Pa = ratio of the pseudopermeability of the medium with memory to luid viscosity, m3 s1 kg

dux = velocity gradient along y-direction, 1/s dy dv = velocity gradient along l-direction dl T

= the derivative of surface tension with temperature and can be positive or negative depending on the substance, N/m-K

3.13 Exercises E3.1: For a typical US Gulf Coast area, it is given that the diameter of the bit is 15 in, rate of penetration is 100 t/hr, and the average porosity is 25%. Find out the volume of cuttings in bbl/hr and tons/hr. 3 E3.2: he density of the drilling mud is measured as 80 lbm / ft in the rig side area. Calculate the speciic gravity in gm / cm3, mud gradient in psi / ft and kg / cm2 / m. Ans. 3 E3.3: A mud engineer measured the density of the drilling luid as 75 lbm / ft in 3 the rig side area. Calculate the speciic gravity in gm / cm , mud gradient in psi / ft and kg / cm2 / m. Ans. E3.4: During the drilling of hazardous formation, the mud engineer was trying to keep up the quality of drilling luid. At certain time, he measured the density of the drilling luid as 12 ppg in the rig side area. Calculate the speciic gravity in gm / cm3, mud gradient in psi / ft and kg / cm2 / m. Ans. E3.5: A Marsh Funnel is used to measure the density of the drilling luid which is 1.1 g/cm3 in 40 seconds. Calculate the efective viscosity using Marsh Funnel equation. Ans. E3.6: A Marsh Funnel is used for 45 seconds to to measure the density of the drilling luid which is 1.3 g/cm3. Calculate the efective viscosity using Marsh Funnel equation. Ans. E3.7: A mud sample in a rotational viscometer gives a dial reading of 460 at 600 rpm and a dial reading of 280 at 300 rpm. Compute the apparent viscosity of the mud at each rotor speed. E3.8: Using the data of Exercise 3.6, compute the plastic viscosity and yield point of the mud sample. Ans. E3.9: To calculate the diferent viscosity of a mud sample, a Fann V-G meter is used and the data measurements are 600 250 and 300 180. Calculate i) plastic viscosity, ii) apparent viscosity, iii) Bingham yield point, and true yield point. Ans. E3.10: Find out the pH of a aqueous solution where both [H+] and [OH–] ions are 1 10 2 and 1 10 12 respectively. Ans. E3.10: Find out the pH of both [H+] and [OH–] ions if an aqueous solution has the concentration of 1 10 9 for [H+] and 1 10 5 for [OH–] ions respectively. Ans.

136 Fundamentals of Sustainable Drilling Engineering E3.11: A 13 lbm/gal drilling mud is retorted and found to contain 9% oil and 75% water. If the chloride test shows the mud to have a chloride content of 150,000 mg Cl / L, Find out the solid fraction of the mud? Assume that the mud is a calcium chloride mud. he solution has 14% salinity and CaCl2 has a volume increase factor of 1.037. Ans. E3.12: A 10 lbm/gal drilling mud is retorted and found to contain 12% oil and 70% water. If the chloride test shows the mud need to have chloride content, Find out the solid fraction of the mud? Assume that the mud is a sodium chloride mud. he solution has 18% salinity and NaCl has a volume increase factor of 1.075. Ans. E3.13: A 20-in bit is used to drill a hole at a rate of 70 t/hr where the porosity of the formation is 25%. Calculate the solid volume generated this drilling operation. If the density of the solid is 910 lbm/bbl, calculate the solid generation in tons/hr also. Ans. E3.14: For a typical North Sea well, a 26-in bit is used to drill a hole at a rate of 60 t/hr where the porosity of the formation is 25%. Calculate the solid volume generated this drilling operation. If the density of the solid is 910 lbm/bbl, calculate the solid generation in tons/hr also. Ans.

References Amanullah Md., Ashraf, M., and Al-Tahini. Nano-Technology-Its Signiicance in Smart Fluid Development and Gas Field Applications. 2009, SPE Saudi Arabia Technical Symposium and Exhibition, Al-Khobar, Saudi Arabia. Annie Audibert-Hayet, Lionel Rousseau, William M. McGregor, and Luigi F. Nicora,” Novel hydrophobically modiied natural polymers for non-damaging Fluids”, SPE 56965, 1999. Apaleke, A.S., Al-Majed, A. and Hossain, M.E. (2012), Drilling Fluid: State of the Art and Future Trend”, Paper ID: SPE- 149555, presented at 2012 SPE North Africa Technology Conference and Exhibition (NATC), 20–22 February 2012 in Cairo, Egypt, 2012. Apaleke, A.S., Al-Majed, A. and Hossain, M.E. (2012), State of the Art and Future Trend of Drilling Fluid: An Experimental Study”, Paper ID: SPE- 153676, presented at the 2012 SPE Latin America and Caribbean Petroleum Engineering Conference, 16–18 April 2012 in Mexico City, Mexico, 2012. Arratia, P.E., Shinbrot, T. Alvarez, M.M. and Muzzio, F.J. 2005. Mixing of non-Newtonian luids in steadily forced system. Physical Review Letters, PRL 94(084501), pp. 1–4 Beart, R. Apparatus for Boring in the Earth and in Stone. England, Patent No. 10,258 (Jan. 11, 1845). Brantly, J.E. History of Oil Well Drilling. Gulf Publishing Co., Houston, 1971. p.3, 38, 39. Brantly, J.E. History of Petroleum Engineering. Cater, D.V., ed. Boyed Printing Co. Dallas, 1961. pp. 277, 278 Bureau of Ocean Energy Management, Regulation and Enforcement, U.S. Department of Interior, “Cases of Drilling Fluid discharges into the marine environment in the Gulf of Mexico in some months of 2005”. C.J. haemlitz, A.D. Patel, George Coin, and Lee Conn, “New Environmentally Safe High Temperature Water-Based Drilling Fluid System”, SPE 57715, 1999. Caraway, W.H. (1953). Domestic Subtitutes for Quebracho in Oilwell Drilling Fluids. Petrol Engineering. Carter, T.S., “Planning Ofshore Drilling Fluid Programs,” Drilling (May, 1977). Chen, J., Hirasaki, G.J., and Flaum, M., (2004): “Efects of OBM Invasion on Irreducible Water Saturation: Mechanisms and Modiications of NMR Interpretation”, SPE 90141 presented

Drilling Fluids 137 at the SPE Annual Technical Conference and Symposium, Houston, Texas, U.S.A., 26–29 September, 2004. Crews, S.H., (1964): “Big Hole Drilling Progress Keyed to Engineering”, Petrol Engineering, October, 1964. pp. 104–114. Dosunmu and Ogunrinde, “Development of Environmentally Friendly Oil Based Drilling Mud using Palm-oil and Groundnut-oil”, SPE 140720, 2010 Dye, W., Augereau, K.D., Hansen, N., Otto, M., Shoults, L., Leaper, R., Clapper, D., and Xiang, T., (2006): “New Water-based Mud balances High Performance Drilling and Environmental Compliance”, SPE 92367 presented at the SPE/IADC Drilling Conference, Amsterdam, February 23–24. E. Van Oort, D. Ripley, I. Ward, and J.W. Chapman “Silicate-Based Drilling Fluids: Components, Cost-efective and Benign Solutions to Wellbore Stability Problem” IDAC/SPE, 1996. E. van Oort, J. Lee, J. Friedheim, and B. Toups,” New Flat-Rheology Synthetic Based Mud for Improved Deep-Water Drilling”, SPE 90987, 2004. Eric Davidson, John Hall, and Colin Temple, (2004): “An Environmentally Friendly, Highly Efective Hydrogen Sulphide Scavenger for Drilling Fluids”, SPE 84313. F.B. Growcock, G.W. Curtis, B. Hoxha, W.S. Brooks, and J.E. Canon “Designing Invert Drilling Fluids to Yield Environmentally Friendly Drilled Cuttings”, IADC/SPE 74474,2002. Fairfax Water: http://www.fcwa.org/water/hardness.htm, accessed on July 24, 2010-07-25. Fauvelle, M. (1846). A new Method of Boring for Artesian Springs. J. Franklin Inst., vol. 12, 3 series. pp. 369–371. Fertl, W.H., and Chilingarian, G.V., “Importance of Abnormal Formation Pressures”, J. Petroleum Technology. (April, 1977). Foran, E.V., (1934), “Pressure Completion of Wells in West Texas”, API Drilling and Production Practices (1934). pp.48–54. GESAMP (imo/fao/unesco/wmo/who/iaea/unep). Joint Group of Experts on the Scientiic Aspects of Marine Pollution (1993). Impacts of Oil and Related Chemicals and Wastes on the Marine Environment. GESAMP Reports and Studies No. 50. International Maritime Organization, London. Gouoqiang Chen, and David Burnett, “Improving Performance of Low Density Drill in Fluid with Hollow Glass Spheres”, SPE 82276 Gray, G.R., and Young, F.S., Jr., “25 Years of Drilling Technology-A Review of Signiicant Accomplishments,” J. Petrol Technology. Dec., 1973). Greaves, L.A., Eisen, E.A., Smith, T.J., Pothier, L.J., Kriebel., Woskie, S.R., Kennedy, S.M., Shalat, S., and Monson, R.R. (1997). Respiratory Health of Automobile Workers Exposed to Metal Working Fluid Aerosols. American Journal of Industrial Medicine. Grinsfelder, S., and Law, J., (1938): “Recent Pressure Drilling at Dominguez”, API Drilling and Production Practices, (1938). pp.74–79. Guest, R.J. and Zimmerman, C.W. (1973). Compensated Gamma Ray Densimeter Measures Slurry Densities in Flow. Petroleum Engineering, September, pp. 80–87. Hayes, C.W., and Kennedy, W. (1903). Oil ields of the Texas-Louisiana Gulf Coast Plain. U.S. Geol. Survey Bull, 212. p. 167. Herzhat, B., Rousseau, L., Neau, L., Moan, M., and Bossard, F., (2002): “Inluence of Temperature and Clays/Emulsion Microstructure on Oil-Based Mud Low Shear Rate Rheology”, SPE 86197 presented at the 2002 SPE Annual Technical Conference and Exhibition, San Antonio, Texas, 29 September–2 October. Hollis, W.T., (1953): “Gas Drilling in San Juan Basin of New Mexixon”, API Drilling and Production Practises. pp. 310–312. Hossain, M.E. (2011). “Development of a Sustainable Diagnostic Test for Drilling Fluid”, Paper ID – 59871, Proc. of the International Symposium on Sustainable Systems and the Environment (ISSE) 2011, American University of Sharjah, Sharjah, UAE, March 23–24, 2011.

138 Fundamentals of Sustainable Drilling Engineering Hossain, M.E., Liu, L. and Islam, M.R. (2009). Inclusion of the Memory Function in Describing the Flow of Shear-hinning Fluids in Porous Media. International Journal of Engineering (IJE), 3(5), pp. 458–477. Hossain, M.E., Mousavizadegan, S.H. and Islam, M.R. (2009). Efects of Memory on the Complex Rock-Fluid Properties of a Reservoir Stress-Strain Model. Petroleum Science and Technology, 27 (10), pp. 1109–1123. Hossain, M.E., Mousavizadegan, S.H. Ketata, C. and Islam, M.R. (2007). A Novel Memory Based Stress-Strain Model for Reservoir Characterization. Journal Nature Science and Sustainable Technology, 1(4), pp. 653–678 Kenneth, P.M., George, H.M, and Stone, C.R., (2007): “Air Drilling in the Presence of Hydrocarbons: A Time for Pause” IADC/SPE paper 108357 presented at the IADC/SPE Managed Pressure Drilling and Underbalance Operations Conference and Exhibition, Galveston, Texas, 28–29 March, 2007. Khan, M.I. and Islam, M.R. (2007). he Petroleum Engineering Handbook: Sustainable Operations. Gulf Publishing Company, Hous Knapp, I.N. (1916): “he use of Mud-Laden Water in Drilling Wells”, Trans. AIME, vol. 51. pp. 571–586. Lawton, H.C., Ambrose, H.A., Loomis, A.G. (1932). Chemical Treatment of Rotary Drilling Fluids. Physics Journal. Le Blanc, L., “How to Design a Money-saving Solids Control System”, World Oil, (Oct., 1978). Li, T., Gao, J. Szoszkiewicz, R., Landman, U. and Riedo, E. 2007. “Structured and viscous water in subnanometer gaps”. Physical Review B, 75(115415), March 15, 1–6. Luigi F. Nicora, and Giovanni Burrafato,” Zirconium Citrate: A New Generation Dispersant for Environmentally Friendly Drilling Fluids”, SPE 47832. M.J. Pitt (2000). he Marsh Funnel and Drilling Fluid Viscosity: A New Equation for Field Use. SPE Drilling and Completion, 15(1), March, pp. 3–6. M.A. Ramirez, D.K. Clapper, G. Sanchez, and E. Luna, “Aluminum-Based HPWBM Successfully Replaces Oil-Based Mud to Drill Exploratory Wells in Environmentally Sensitive Area”, SPE-94437. Mandujano, S.H., Ramirez, L.R., Perez, P.H., “Novel Application of Ecological System Drilling Fluid Accomplishes Signiicant Advances in the Hole Stability Problems”, SPE 74378, 2002. Marsh, H. (1931). Properties and Treatment of Rotary Mud. Petroleum Development and Technology, Transactions of the AIME, pp. 234–251. Mauk, B. 2007. Water Discovered to Flow Like Molasses. Special to Liver Science, May 11, (Link: http://www.livescience.com/technology/070511_small_water.html, accessed on June 10, 2007). Mellot, J. (2008): “Technical Improvements in Wells Drilled with a Pneumatic Fluid” SPE paper 99162, presented at the SPE/IDAC drilling Conference, Miami, Florida, USA, February 21–23, 2208. Miller, G. (1942). New Oil Base Drilling Fluid Facilitates Well Completion. Petrol Eng. pp.104–106. Oakley, D.J., James, S.D., and Clife, S., (1991): “he Inluence of Oil-Based Drilling Fluid Chemistry and Physical Properties on Oil Rertained on Cuttings”, SPE 23060 presented at the Ofshore Europe Conference, Aberden, 3–6 September, 1991. OWTG (Ofshore Waste Treatment Guidelines), (2002). National Energy Board, CanadaNewfoundland Ofshore Petroleum Board, Canada-Nova Scotia Ofshore Petroleum Board. ISBN 0-921569-40-8, Released on January 9, 2002. P. Skalle, K.R. Backe, S.K. Lyomov, L. Kilaas, A.D. Dyrli, and J. Sveen, “Microbeads as Lubricants in Drilling Muds”, SPE 56562, 1999.

Drilling Fluids 139 Parsons, C.P. (1932). Sealing Efect of Rotary Mud on Productive Sands in the Mid-Continent District. API. Prod. Bull. 209. pp. 52–58. Patin, S. (1999). Environmental Impact of the Ofshore Oil and Gas Industry. EcoMonitor Publishing, East Northport, New York. Pennington, J.W. he History of Drilling Technology and Its Prospects. Proc. API, Sect. IV, Prod. Bull. 235 (1949). p. 481. Perazzo, C.A. and Gratton, J. 2003. hin ilm of non-Newtonian luid on an incline”. Physical Review E, 67(016307), pp. 1–4. Randall, B.V., and Estes, J.C., “Optimized Drilling Applicable World Wide”, Petrol. Engg. (June, 1977). Schilithus, R.J. (1938). Connate Water in Oil and Gas Sands. Trans. AIME, vol. 127. pp. 199–212. Shallenberger, L.K., (1953): “What about Compressed Air?” World Oil, April 1953. pp. 23–31. Stroud, B.K. (1925). Use of Barytes as Mud Laden Fluid. Oil Weekly. pp. 29–30. Tschirley, N.K., “Hole Stability through Mud Technology-An Organized Approach,” South Petroleum Short Course, Texas Tech University, Lubbock, April 22–23, 1976. Website 1: www.erathworksaction.org/pubs/Pit Report,” Pit Pollution” Website 2: www.ofshore-environment.com/additives, “A survey of ofshore oilield drilling wastes and disposal techniques to reduce the ecological impacts of sea dumping, Jonathan Willis, May 2005”. Website 3: www.albertaoilmagazine.com Weiss, W.J., “Drilling Fluid Economic Engineering,” Petrol Eng. (Sept., 1977). Wenger, L.M., Davis, C.L., Evensen, J.M., Gormly, J.R., and Mankiewicz, P.J. (1986). Impact of Modern deepwater drilling and testing luids on geochemical evaluations. Organic Geochemistry, 35, 1527–1536. William Dye, Ken d’ Augereau, Nols Hansen, M. Otto, Larry Shoults, Richard Leaper, Dennis Clapper, and Tao Xiang, “New Water-Based Mud Balances High Performance Drilling and Environmental Compliance”, SPE-92367 Zwicker, S.L., Collins, J., Gilbert, J.T.E., Mooore, J.E., and King, R.J. (1983). Technical Guidelines for ofshore oil and gas development, in For the East-West Environment and policy Institute (ed. J.T.E. Gilbert). Penn Well Books, Oklahoma City, OK, PP. 49–104.

4 Drilling Hydraulics 4.1 Introduction Hydraulics can be deined as the study of the physical science and technology of the static and dynamic behavior of luids under the inluence of mechanical forces and/or pressure, and uses of that knowledge in designing and controlling machines. In drilling engineering, drilling hydraulics is an essential part of drilling operations where computation of pressure proiles along the wellbore and particularly in the annulus contributing to well safety and well integrity are done to improve the API recommended practice for drilling luid rheology and drilling hydraulics estimation. Drilling hydraulics plays a vital role while drilling activities continue to operate which is also referred to as rig hydraulics. In the petroleum industry, drilling hydraulics provides a productivity tool which is helpful in the drilling of hydrocarbon wells for hydraulics calculations, and optimization of rate of penetration (ROP) to the driller, tool pushers, engineers, chemists, students and other professionals. It can help on the decision on selection of bit nozzles. In addition, accurate use of hydraulic energy at i) drill bit, ii) calculations of frictional pressure drops through the drill pipe and various surface equipment, iii) eicient cleaning ability of the drilling system, and iv) proper utilization of mud pump horsepower are some of the features necessary to optimize for eicient, safe, and cost efective drilling operations. An incorrect design resulting in an ineicient hydraulics system can – i) slow down the ROP, ii) fail to properly clean the hole of drill cuttings, iii) cause lost circulation, and inally

141

142 Fundamentals of Sustainable Drilling Engineering iv) lead to blowout of the well. As a result, proper design and maintenance of rig hydraulics is crucial. To understand and properly design the hydraulic system, it is important to discuss hydrostatic pressure, types of luid low, criteria for type of low, and types of luids commonly used in the various operations at the drilling industry. Hence this chapter deals with the type of luids; pressure losses in the surface connections, pipes, annulus, and the bit; jet bit nozzle size selection; surge pressures due to vertical pipe movement; optimization of bit hydraulics; and carrying capacity of drilling luid.

4.2 Types of Fluids here are diferent types of luids. Almost all the luids follow the following categories: i) ii)

Newtonian luid Non-Newtonian Fluid

4.2.1 Newtonian Fluid Normally Newtonian luids are those liquids where low molecular weight substances exist. Examples include water, light crude oil, organic and inorganic liquids, gases, solutions of low molecular weight inorganic salts, molten metals and salts which exhibit Newtonian low behavior. A Newtonian Fluid can be deined as – “the shear stress is directly proportional to shear rate at a constant temperature and pressure”. he constant proportionality is known as dynamic viscosity of luid. he shear stress and the rate of deformation are normally expressed by Newton’s law of viscosity which can be written mathematically as: dux (4.1) d dy Here: = shear stress, Pa = dynamic viscosity, Pa-s d dux or = the velocity gradient perpendicular to the direction of shear, or equivady lently the strain rate, s−1 In ield unit, viscosity is expressed in centipoises (1 poise = 100 centi poise) and the ield unit of share stress is in lbf /100 t2. Figure 4.1 shows the linear variation of shear stress with shear rate. he slop of the line gives the viscosity of the luid. Equation (4.1) is called the Newtonian luid model. he fundamental concept of the Newtonian luid behavior is already explained in section 3.6.2 of Chapter 3. he linear relationship between shear stress and shear rate as illustrated by Eq. (4.1) is valid only if the luid moves in conined layers or laminae. A luid that lows in this type of arrangement is said to be laminar low. his phenomenon is true only at relatively low rates of shear. he pipe low and other types of low will be discussed in the next section of this chapter. Example 4.1: Calculate the shear stress of a luid which has a viscosity of 55 cp and a shear rate of 15 s–1.

Drilling Hydraulics 143

Shear Stress ( )

1

2

3

Shear Rate ( )

Figure 4.1 Characteristics of newtonian luid.

Solution: Given data: = Mud viscosity = 55 cp = 0.55 Poise = 0.55 dyne.s / cm2 = 0.55 Pa-s d dux = = Shear rate = 15s–1 dy Required data: = Shear stress, Pa he shear stress of the luid can be calculated using Eq. (4.1) as: d

dux dy

0.55 Pa.s 15 s

1

8.25 Pa

4.2.2 Non-Newtonian Fluid A non-Newtonian luid is a luid whose low behavior or properties is not the same as Newtonian luid i.e. fundamentally the rate of shear is not proportional to the corresponding stress and cannot be described by a single constant value of viscosity. Most of the drilling luids are non-Newtonian, due to their complex characteristics in behavior. Some other examples can be illustrated as foams, suspensions, polymer solutions, and melts. Non-Newtonian luids can be classiied as i) shear-thickening, ii) shear-thinning, iii) time-dependent (i.e. thixotropic, and rheopectic), visco-plastic, and visco-elastic luids. In addition to these types of luids, non-Newtonian luids can also be categorized as i) Bingham plastic, and ii) power-law luids. A shear-thickening luid is deined as a luid in which apparent viscosity increases with the increase of shear strain rate. It is also termed ‘dilatant.’ A shear-thinning luid is the opposite of shear-thickening luid where apparent viscosity decreases with the increase of the rate of shear strain which is also called as pseudoplastic luid. Examples of this type of luid are drilling luids and cement slurries in general. here are also luids that are time-dependent; a luid is called thixotropic if the apparent viscosity decreases with time ater the shear rate is increased to a new constant value. On the other hand, if the apparent viscosity increases with time ater the shear rate is increased

144 Fundamentals of Sustainable Drilling Engineering

Viscoplastic

Shear Stress

Bingham Plastic

Pseudoplastic Newtonian Fluid Dilatant Fluid Shear Rate

Figure 4.2 Characteristics of diferent non-Newtonian luids

to a new constant value, the luid is called rheopectic. Again, drilling luids and cement slurries are generally thixotropic. A luid that exhibit a viscoelastic property i.e. a blend of viscous luid behavior and of elastic solid-like behavior is called visco-elastic luid. Viscoelasticity is the property of materials that exhibit both viscous and elastic characteristics when undergoing deformation, such as honey. Figure 4.2 shows the typical low curves (rheograms) for the above mentioned categories of luid behavior.

4.2.2.1

Diferent Rheological Models for Non-Newtonian Fluids

For non-Newtonian luids, there are some rheological models that describe the relationship between shear stress and shear rate when a luid lows through a circular section or an annulus. he rheological models are generally used to approximate the luid behavior. Among the various rheological models, this chapter considers the most widely used models and one newly developed model by the irst author of this book. he models are: i) Bingham plastic model, ii) power-law model, iii) shear-thinning luid model, and iv) Herschel-Bulkley model. he other model for Newtonian model is already discussed in the above section. i) Bingham Plastic Models: Bingham plastic luids can be deined as luids that have a linear stress-strain relationship and which require a inite yield stress before they start to low. he linear plot of stress-strain relationship does not pass through the origin, but rather intersects to a point of stress line. Examples are clay suspensions, toothpaste, mayonnaise, chocolate, and mustard. Figure 4.3 depicts the relationship between the shear rate and shear stress. Bingham plastic models are used to approximate the pseudoplastic behavior (i.e. decrease of apparent viscosity with increasing shear rate) of drilling luids and cement slurries. It is deined in terms of the shear stress and shear rate, which are given by the following mathematical models:

p

=0

Shear Stress ( )

Drilling Hydraulics 145

+

Yield Stress

Yield points

Shear Rate ( ) –

Figure 4.3 Shear rate vs. shear stress relationship for Bingham plastic luid.

p

y

;

if

y

(4.2a)

p

y

;

if

y

(4.2b)

Here: y p

= a minimum shear stress that needs to initiate luid low, Pa = Bingham plastic viscosity, Pa-s

he deinition of Bingham plastic luid says that there will not be any low until there is a certain minimum shear stress applied to the luid which is called a yield point stress ( y ). It may also predict a non-physical yield point. Once the yield point has been exceeded, changes in shear stress are proportional to changes in shear rate. he slop of the curve (Figure 4.3) or the constant proportionality is called the plastic viscosity ( p ). he plastic viscosity depends on pressure and temperature. he above two Bingham plastic models are valid only for laminar low. hese models work well for higher shear rates. However, the models give a signiicant error at low shear rates. Example 4.2: A moving plate is set 2 cm above a stationary plate which has a crosssectional area of 25 cm2. If a force of 250 dynes is required to just initiate the upper plate and a force of 550 dynes is needed to move the plate with a uniform velocity of 8 cm/s, calculate the yield point and plastic viscosity of the luid. Solution: Given data: L = Gap between the plates = 2 cm A = Cross-sectional area of the upper plate = 25 cm2

146 Fundamentals of Sustainable Drilling Engineering Fy = Force needed to initiate the plate movement (i.e. V = Fluid velocity = 8 cm/s F = Force needed to move the plate = 550 dynes

0) = 250 dynes

Required data: = Yield point, Pa y = Plastic viscosity, Pa-s p he yield point ( y) needed to initialize the luid can be calculated using Eq. (4.2a) as: p

y

p

0

y

y

Now, the deinition of shear stress can be written using Eq. (3.6) as: 250 dynes 25 cm2

F/A herefore,

y

10 dyne / cm2

10 dynes / cm 2

he plastic viscosity can be calculated using the force needed to move the plate and with the luid velocity and by Eq. (4.2a) as: y p

F/A

550 / 25 10 8/2

y

V /L

3.0dyne.s / cm2

3 Poise

300 cp

For Bingham luid, plastic viscosity, yield point, and zero-sec-gel can be calculated using a FannV-G meter (See Chapter 3) reading with the following relationships. p

2

y

600

300

(4.3a)

300

600

(4.3b)

0

(4.3c)

3

Here: 600 300 3 0

= the Fann dial reading at 600 rpm = the Fann dial reading at 300 rpm = the Fann dial reading at 3 rpm = yield point stress at dial reading at 3 rpm

Alternatively, the dial readings can be reverse calculated by using plastic viscosity, yield point, and zero-gel by rearranging the Eqs. (4.3a – c). It is noted that these readings give the corresponding plastic viscosity, and yield point in ield units. 300

600

p

2

p

y

y

(4.4a) (4.4b)

Drilling Hydraulics 147 3

(4.4c)

0

If the FannV-G meter RPMs are any other readings except 300 and 600 rpm, the following equations can be used: 300 N 2 N1

p

y

Here: N1 , N 2 N1 , N 2

N2

N1

p

(4.5)

N1

N1 300

(4.6)

= he Fann rpm reading = he Fann dial reading at N1 and N 2 rpm

Example 4.3: In the drilling luid laboratory, a student was conducting an experiment for the Bingham luid where he was using the Fann V-G meter to measure the viscosity of the luid and he found the following Fann data: 300 30; 600 55, and 200 27; 49. Calculate the plastic viscosity and yield point of the luid using the Bingham 400 plastic model. Solution: Given data: 300 = Dial reading at 300 rpm = 30 600 = Dial reading at 600 rpm = 55 200 = Dial reading at 200 rpm = 27 400 = Dial reading at 400 rpm = 49 Required data: p = Plastic viscosity, Pa.s y = Yield point, Pa For 300 and 600 rpm readings, the plastic viscosity and yield point can be calculated using the Eqs. (4.3a) and (4.3b) as: p

y

2

300

600

600

300

55 30 25cp 0.25 Poise

0.25 dyne.s / cm2

0.25 Pa. s

2 30 55 5 lb f /100 ft 2

5 lb f /100 ft 2 1.04 dyne / cm2

dyne / cm2 ; 4.79lb f /100 ft 2

(1 Pa 4.79 lb f /100 ft 2 )

1.04 Pa

For the second set of readings, we should use Eqs. (4.5) and (4.6) as: p

300 N 2 N1

N2

N1

300 49 27 400 200

33 cp

0.33 Pa. s

148 Fundamentals of Sustainable Drilling Engineering

y

N1

N1 300

p

200 300

27 33

5 lb f /100 ft 2 1.04 dyne / cm 2

1.04 Pa

ii) Power-Law Models: A power-law luid can be deined as a luid in which the shear stress at any point is proportional to the rate of shear at that point with some power on the shear rate. he rheological equation for the power law model can be given as: K

np

(4.7)

Here: K = low consistency index, Pa. sn dux = shear rate or velocity gradient perpendicular the plan of shear, s dy = power-law exponent or low behavior index, dimensionless np

1

he apparent viscosity as a function of shear rate can be written as: app

K

np 1

(4.8)

Shear Stress ( )

Shear Stress ( )

Power-law luids can be further classiied into three diferent types of luids based on n p: i) pseudoplastic luids for n p < 1, ii) Newtonian luids for n p = 1, and iii) Dilatant luids for > 1. he power-law models are also known as Ostwald-de Waele model. Equations (4.7) and (4.8) are useful because they are simple and require only two parameters for characterizing luid behavior. hese models are also used to approximate the pseudoplastic behavior of drilling luids and cement slurries. However, these models can only approximate the behavior of a real non-Newtonian luid. Figure 4.4 shows the graphical representation of the model Eqs. (4.7) and (4.8). In the power-law model, K is a measure of the thickness of the luid, analogous to apparent viscosity of the luid. he larger the K value, the thicker the luid is. he value

=K

1

=K

Shear Rate ( )

n–1

=K

(a)

Shear Rate ( )

n–1

(b)

Figure 4.4 Shear rate vs. shear stress relationship for power-law luid: (a) pseudoplastic power-law luid, and (b) dilatants power-law luid.

Drilling Hydraulics 149 of n indicates the degree of non-Newtonian behavior of the luid. For example, if n is less than one, the power-law forecasts the efective viscosity which decreases with the increase of shear rate indeinitely. It is noted that in Eq. (4.8), 0 n p 1 will yield d app / d 0 which indicates that shear-thinning behavior of luids is characterized by a value of n p 1. Lots of polymer melts and solutions have the value of n in the range of 0.3 – 0.7 based on the concentration, molecular weight of the polymer, and some other properties. In addition, smaller values of power-law index (n p 0.1 0.15) are encountered with ine particle suspensions like kaolin-in-water, bentonite-in-water, etc. Naturally, the smaller the value of n p, the more shear-thinning the material is. Although, Eq. (4.7) or (4.8) ofers the simplest approximation of shear-thinning behavior, it predicts neither the upper nor the lower Newtonian plateaus in the limits . In addition, a luid needs ininite viscosity at rest and zero viscosof 0 or ity while the shear rate approaches ininity. However, a real luid has a minimum and maximum efective viscosity which depends on the physical chemistry at the molecular level. hus, the power law models (Eqs. 4.7 and 4.8) are only a good representation of the luid behavior within the range of shear rates to which the coeicients are itted. he shortcoming of the power-law model is that it underestimates the shear stresses at medium and low shear rate ranges. In the literature, there are a number of other models that better explain the entire low behavior of shear-dependent luids such as shearthinning luid. he following section presents some models as an example. Example 4.4: A moving plate is set 2 cm above a stationary plate which has a crosssectional area of 25 cm2. Calculate the consistency index and low-behavior index if a force of 250 dyne is required to move the upper plate at a constant velocity of 8 cm/s and a force of 300 dyne is needed to move the plate with a uniform velocity of 10 cm/s. Solution: Given data: L = Gap between the plates = 2 cm A = Cross-sectional area of the upper plate = 25 cm2 F1 = Force needed to move the plate by 8 cm/s = 250 dynes V1 = First luid velocity = 8 cm/s F2 = Force needed to move the plate by 10 cm/s = 300 dynes V2 = Second luid velocity = 10 cm/s Required data: K = Flow consistency index, Pa. sn n p = Power-law exponent or low behavior index, dimensionless To calculate K and n p, Eq. (4.7) is used at the two rates of shear observed and Eq. (3.4) is used for shear stress as: F/A 250 25

K

8 2

np

K

np

300 and 25

K

10 2

np

150 Fundamentals of Sustainable Drilling Engineering Now, dividing the second equation by the irst equation as: 300 250

np

10 8

Taking the ln of both sides and solving for n p as: ln 300 / 250

np

ln 10 / 8

0.817

Substituting the value of n in the irst equation above gives as: 250 25

8 K 2

np

10 (4)0.817

K

322.2 Pa. s 0.817

322.2 eq.cp

For a power-law luid, the low behavior index can be calculated using Fann V-G meter which is written as: log10

600 300

np

3.322 log

0.301

600

(4.9)

300

In Eq. (4.9), if we use the modiied power-law, it can be written using Eqs. (4.4a) and (4.4b) as: np

3.322 log

2

p p

y

(4.10)

y

he consistency index, K can be written as: K

5.11

300 np

(4.11)

511

In Eq. (4.11), K is in eq. poise. It can be expressed in terms of lb f the conversion factor of 1 Pa 4.79lb f /100 ft 2.

sec

n

/100 ft 2 using

K can also be calculated using the modiied power-law which gives as: K

2

p

y n

1022

(4.12)

If the Fann V-G meter RPMs are any other readings except 300 and 600 rpm, the following equations can be used: log np

N2 N1

N2 log N1

(4.13)

Drilling Hydraulics 151 5.11

K

N

(4.14)

np

1.703 N

Example 4.5: In the drilling luid laboratory, a student was conducting an experiment for the Bingham luid where he was using the Fann V-G meter to measure the viscosity of the luid and he found the following Fann data: 300 30; 600 55, and 200 27 ; 400 49. Calculate the consistency index and low-behavior index for the power-law model. Solution: Given data: 300 = Dial reading at 300 rpm = 30 600 = Dial reading at 600 rpm = 55 200 = Dial reading at 200 rpm = 27 400 = Dial reading at 400 rpm = 49 Required data: np K = Flow consistency index, Pa. s n p = Power-law exponent or low behavior index, dimensionless For 300 and 600 rpm reading, K and n can be calculated using the Eqs. (4.9) and (4.11) as: np

3.322 log

600

3.322 log

300

55 30

0.874

and 5.11

K

5.11 30 5110.874

300 np

511

0.658 eq. poise

In ield units: K

0.658 4.79 3.152 lb f /100 ft 2 .

[Note: 1 Pa 4.79lb f /100 ft 2]

For the second set of readings, we should use Eqs. (4.13) and (4.14) as: log np

K

5.11 1.703

N2 N1

N2 log N1

5.11

N

N

49 27 400 log 200 log

np

1.703

27 200

0.8598

0.8598

0.9174 eq. cp

152 Fundamentals of Sustainable Drilling Engineering In ield unit: K

0.9174 4.79

4.394 lb f / 100 ft 2

iii) Shear-thinning luid models: he majority of complex luids used in oil ield applications are non-Newtonian polymeric solutions demonstrating shear-thinning (pseudoplastic) behavior in solution. he two main polymers used in the oil industry for hydrocarbon recovery are synthetic polyacrylamide (in its partially hydrolyzed form, HPAM) and Xanthan biopolymer gum. Bulk property measurement of polymeric solutions is a standard and reliable experimental procedure. herefore, researchers’ eforts have been made to extend the laws of motion for purely Newtonian luids (Darcy’s law) to rheologically complex ones using easily measurable properties such as the shear rate/viscosity behavior. A bundle of parallel capillary tubes approach has been used to measure the macroscopic and microscopic properties of porous media. his approach leads to the deinition of an average radius which is dependent on macroscopic properties of the medium such as porosity, absolute permeability, and some measure of tortuosity. he available mathematical models (such as power law, Carreau, or Cross models) to describe the luid rheology have been developed to deine viscosity and apparent shear rate from the use of the Darcy velocity. Experimental results show that the shape of the apparent viscosity curve is similar to that of the bulk shear rate. Most experimental works had been performed with Xanthan biopolymers whose experimental results are available in the literature where they tried to ind the shape factor, SF . For the porous media, Chauveteru’s form of the deinition of porous media wall shear strain rate or in-situ shear rate is

. pm

SF ux

k

(4.15)

Here: ux = Fluid velocity in porous media in the direction of x axis, m / s .SF = Shape factor which is medium-dependent =Apparent shear rate within the porous medium, s 1 pm k = Reservoir permeability, m2 = porosity of luid media, m3 / m3 In the context of polymer looding (part of enhanced oil recovery schemes), in-situ rheology depends on polymer type and concentration, residual oil saturation, core material and other related properties which are addressed in the available literature. A brief discussion has been outlined by Lopez (2004). he existence of a slip phenomenon in the Newtonian region at ultra low low rates is conirmed and the degree of shit (the SF factor) in the non-Newtonian region is quantiied. It is shown that the adoption of rigorous and reproducible core lood procedures is required to yield unambiguous data on in-situ polymer viscosity and polymer retention in real systems. Some researchers pointed out that Eq. (4.15) has a generic form which depends on polymer type, medium structure and approach. In this area, there have been developed several constitutive equations in the past that capture the full bulk rheological behavior of pseudoplastic solutions. To model the bulk rheology of the non-Newtonian luid, the Carreau-Yasuda model may be written as:

Drilling Hydraulics 153 0  ef .

1  (

Here: a nc eff 0

a

pm )

(4.16)

nc a

= Parameter in Carreau–Yasuda model, dimensionless = Power-law exponent for Carreau–Yasuda model, dimensionless = Fluid efective viscosity, Pa s = Fluid dynamic viscosity at zero shear rate, Pa s = Fluid dynamic viscosity at ininite shear rate, Pa s = time constant in Carreau–Yasuda model, s

he exact form of the shear stress-shear rate (stress-stain) relationship depends on the nature of the polymeric solution. herefore, recently, a question is coming out about the efect of memory on rock/luids in porous media when predicting oil low outcomes. Hossain and Islam (2006) have reviewed the existing complex luid low models with memory available in literature. None of them has focused on shear thinning luid models which may couple with luid memory. Hossain et al. (2007, and 2008) have developed a model which represents a more realistic rheological behavior of luid and media. hey have developed a stress-strain relation coupling the macroscopic and microscopic properties with memory (see Chapter 3). In that model, they did not consider the polymeric luid properties in porous media. However, the conventional practice is to consider the Newtonian luid low equations as ideal models for making predictions. Even non-Newtonian models focus on what is immediately present and tangible in regard to luid properties. he bulk macroscopic properties of these solutions, mainly their viscosity/shear rate dependency, are well understood and characterized using established models. Existing theoretical models as well as experimental indings are well established in the literature. Recently, Hossain et al. (2009) attempted to model shear rate and viscosity of a polymeric complex luid as a function of time and other related bulk properties of luid and media itself where memory has been incorporated to represent macroscopic and microscopic behavior of luid and media in a more realistic way. hey argue  that the intangible dimension of time and other luid and media properties can be coupled to demonstrate the more complex behavior of shear thinning luids in porous media. Hossain et al. (2009) proposed the following model for apparent shear rate:

. pm

Here: p t

t SF

k

1

2

t 0

p d x

(4.17)

= pressure of the system, N / m2 = time, s = fractional order of diferentiation, dimensionless = ratio of the pseudopermeability of the medium with memory to luid viscosity, m3 s1 / kg = a dummy variable for time i.e. real part in the plane of the integral, s

154 Fundamentals of Sustainable Drilling Engineering Equation (4.17) provides the efects of the polymer luid and formation properties in one dimensional luid low with memory. his model may be extended to a more general case of 3-dimensional low for a heterogeneous and anisotropic formation. It should be mentioned here that the irst part of the Eq. (4.17) is the apparent core properties; the second part is the efect of luid memory with time and the pressure gradient. he second part is in a form of convolution integral that shows the efect of the luid memory during the low process. his integral has two variable functions of t x where the irst is a continuous changing function and second is a ixed and 2 p / is an overlapping function on the other function, function. his means that t 2 p/ x in the mathematical point of view. hese two functions depend on the space, time, pressure, and a dummy variable. To analyze the memory efect in the shear-thinning luid viscosity, Hossain et al. (2009) proposed the following model for efective viscosity. 0 eff t

1

SF

0

2

t

p d x

a

nc a

(4.18)

1

k

he solution of Eq. (4.16) and Eq. (4.18) is shown in Figure 4.5 which shows the variation of viscosity verses shear rate of the Hossain et al. (Eq. (4.18)) for diferent values to compare the Carreau-Yasuda model (Eq. (4.16)) in a log-log plotting. All the data generated by solving these two models are overlapped with each other, except for the range of data variation. For the same conditions and input data, the proposed model gives more information than the Carreau-Yasuda model. he proposed model provides a wider range of data in both the zero shear and the ininite shear region. he existence of the Carreau-Yasuda model is only in the power-law region if we compare it with the proposed model. It is also noted that all values data lie in the transition and powerlaw region which are very diicult to capture and explain. If increases, the data range extends to reach the other two regions, zero shear and ininite shear. herefore it may be concluded that the proposed model is more appealing and illustrative in deining the rheological properties of the shear-thinning luid low in porous media. iv) Herschel-Bulkley model: he Herschel-Bulkley model is a combination of the Bingham Plastic and the Power law models. It is also known as the yield power-law model. his model considers the yield point shear stress which is a shortcoming of the power-law model. Figure 4.6 shows the stress-strain relationship for the HerschelBulkley model. Mathematically, this model is deined as: K

n y

(4.19)

In Eq. (4.19), if y = 0, the Herschel-Bulkley model is reduced to the power-law model. On the other hand if n = 1, the model reduces to the Bingham plastic model. It is

Drilling Hydraulics 155 102

Carreau-Yasuda model = 0.2 = 0.4 = 0.6 = 0.8

Efective viscosity (

eff ), pa–s

101

100

10–1

10–2

10–3 10–4

10–2

100

102

Apparent shear rate (

pm), s

104

106

–1

=0

Shear Stress ( )

Figure 4.5 Comparison of Hossain et al viscosity model with Carreau-Yasuda model.

Herschel-Bulkley luid

+

Yield Stress

Yield points

Shear Rate ( )

Figure 4.6 Shear rate vs. shear stress relationship for Herschel-Bulkley luid.

noted that sometimes non-linear regression is needed for solving the resultant mathematical expressions which are not readily solved analytically. his model is preferable compared to power law or Bingham models because it gives more accurate rheological behavior when adequate experimental data are available. he yield stress is normally taken as the 3 rpm reading, with the n and K values then calculated from the 600 or 300 rpm values or graphically. Some drilling luids fall under the Herschel-Bulkley luid model. It requires a certain minimum stress to initiate low.

156 Fundamentals of Sustainable Drilling Engineering

4.3

Flow Regimes

When a luid is forced to low inside a pipe (example, drill pipe, drill collar etc.), there are diferent geometrical conigurations or low regimes which prevail. he low regime can be deined as a range of stream lows that have similar bed forms, low resistance, and means of transporting sediment. While drilling luids low in a well, the luid behavior may difer because the regime depends on the luid properties, length and size of the conduit, and low rate. he low regime also depends on the coniguration of the inlet. In general, low regimes can be classiied as i) laminar low, ii) transition low, and iii) turbulent low.

4.3.1 Laminar Flow he most common annular low regime is laminar which is also known as streamline low and creates a steady-state low (Figure 3.7a). It is sometimes referred to as sheet low, or layered low. Laminar low can be deined as the motion of a luid where every particle in the luid follows the same path of its previous particles. It occurs when a luid lows in parallel layers, with no disruption between the layers. It exists from very low pump rates to the rate at which turbulence begins. At low velocities, the luid tends to low in an organized way. here is no cross low perpendicular to the direction of low, no eddies, and no spins of luids. In laminar low, the motion of the particles of luid is very orderly with all particles moving in straight lines parallel to the pipe walls. he luid moves fastest in the center of the conduit and slowest at the walls (Figure 4.7). It is also true for pipe and annular low too (Figure 3.7b). his indicates that center layers usually move at rates greater than the layers near the wellbore or pipe. he major characteristics of this low regime are: i) low pattern is linear i.e. no radial low, ii) luid velocity at the center of the pipe is maximum and velocity at wall is zero, iii) it produces minimal hole erosion, iv) as the low velocity increases, the low type changes from laminar to turbulent. Laminar low can be characterized by Reynolds number, N Re . If Reynolds number is less than 2100 i.e. N Re 2100 , the low is treated as laminar low.

4.3.2 Turbulent Flow Turbulent low or turbulence is a low regime characterized by the chaotic nature of the luid property changes. Turbulent lows are always highly irregular and chaotic but not all chaotic lows are turbulent (Figure 4.8). Turbulence occurs when increased velocities between the layers create shear strengths exceeding the ability of the mud to remain in laminar low. he layered structure becomes chaotic and turbulent (Figure 4.8(c – d)). Turbulent lows are unsteady by deinition. A constant source of energy supply is necessary to continue turbulent low. Otherwise, turbulence disperses rapidly as the kinetic energy is converted into internal energy by viscous shear stress. It causes eddies formation of many diferent length scales. Turbulent low can be characterized by Reynolds number, N Re . Flows with high Reynolds numbers generally become turbulent. For pipe low, if the Reynolds number is greater than 4000 i.e. N Re 4000 , the low is treated as turbulent low. However, we oten assume that luid low is turbulent if N Re 2100.

Drilling Hydraulics 157

Max Velocity V=0

Laminar Flow (a) Characteristics of laminar low r r r2 r2

r1

v

v

(b) Pipe low

(c) Annular low

Figure 4.7 Characteristics and the velocity proiles for laminar low. Pipe

Laminar Flow

DYE TRACERS (a)

(b)

(c)

Pipe

Turbulent Flow Fluid Velocity proile Particle motion (d)

(e)

Figure 4.8 Characteristics of turbulent low: (a) laminar low, (b) transition between laminar and turbulent low and (c – e) turbulent low.

Turbulence usually takes place in the drillstring and seldom around the drill collars. Much published literature suggests that annular turbulent low increases hole erosion problems. In summary, the basic characteristics of turbulent low can be written as: i) low pattern is random (low in all directions), ii) tends to produce hole erosion, iii) results in higher pressure losses (takes more energy), iv) provides excellent hole

158 Fundamentals of Sustainable Drilling Engineering cleaning but forms eddies in wall of the drill string. A comparison between laminar and turbulent low is shown in Table 4.1. Reynolds number: Reynolds observed that when circulating Newtonian fluids through pipes the onset of turbulence was dependant on the variables such as i) pipe diameter (d), ii) density of fluid , iii) viscosity of fluid (μ), iv) average flow velocity (v). He also found that the onset of turbulence occurred when the above combination of these variables exceeded a value of 2100. Reynold’s observation was very significant because it means that the onset of turbulence can be predicted for pipes of any size, and fluids of any density or viscosity, flowing at any rate through the pipe. This grouping of variables is generally termed a dimensionless group which is known as the Reynolds number. Therefore, the onset of turbulence in pipe flow is characterized by the dimensionless group as: N Re

vdi

(4.20)

Here: v di d

q

= Fluid density, gm/cc = Avg. luid velocity, cm/s = Pipe inner diameter, cm. = Dynamic viscosity of luid, cp = Circulating volume, cc/s

In ield units, Reynolds number can be written as: N Re

928 vdi

(4.21)

Here: v di d

q

= Fluid density, lbm/gal q = Avg. luid velocity, t/s = 2.448 di2 = Pipe inner diameter, in. = Dynamic viscosity of luid, cp = Circulating volume, gal/min

Reynolds found that as he increased the luid velocity in the tube, the low pattern changed from laminar to turbulent at a Reynolds number of 2100. However, later investigators have shown that under certain conditions (i.e. non-Newtonian luids and very smooth conduits), laminar low can exist at very much higher Reynolds numbers. For Reynolds numbers of between 2,000 and 4,000 the low is actually in a transition region between laminar low and fully developed turbulent low (Figure 4.8b). Example 4.6: While drilling, a 10.0 lbm/gal of mud having a viscosity of 1.2 cp was being circulated through Drillstring at a rate of 650 gal/min. If the internal diameter of the drillpipe is 5.0 in, determine the type of low in the drillpipe of the circulating system.

Drilling Hydraulics 159 Table 4.1 A comparison between laminar and turbulent low. Flow Type

Laminar Flow

Turbulent Flow

01

Flow is smooth

Flow pattern is random in both time and space

02

Flow is essentially organized and layered.

Flow is essentially random and unpredictable and seconds the well-deined Laminar low conditions.

03

Velocity increase towards the middle

Uniform at its inal stage

04

Only longitudinal velocity

Longitudinal and transverse velocities

05

Same uniform velocity

Final velocity is uniform

06

Plug low is a special case of laminar low (lat at center)

No Plug low

07

Plug low occurs at low velocity and high viscosity of luid

No plug low

08

Laminar shear resistance

Laminar and turbulent shear resistance

Laminar boundary layer

Turbulent boundary layer

Solution: Given data: = Density of the mud = 10.0 lbm/gal m = Viscosity of the mud = 1.2 cp m q = Circulating volume or volume low rate = 650 gal/min di = Inner diameter of drillpipe = 5.0 in

Steeper Proile and energy exchange

Thickness

Thickness

09

160 Fundamentals of Sustainable Drilling Engineering Required data: Type of low he average luid velocity can be calculated as: v

q 2.448 di2

650 gal / min 2.448

5 in

2

10.62 ft / s

Equation (4.21) is used to determine whether the luid is laminar or turbulent N Re

928 vdi

928

10 lbm / gal

10.62 ft / s

1.2 cp

5 in

410, 640

Since the Reynolds number is considerably very high comparing with 2,100, the luid of the drillpipe is in turbulent low.

4.3.3 Transitional Flow In the case of pipe low, when the luid velocity increases the layers of luid start to become a little unstable. his type of low is called transitional low (Figure 4.9). herefore, this low can be deined as a mixture of laminar and turbulent low where turbulence occurs in the center of the pipe, and laminar low near the edges. If the low rate continues to increase further, the low turns down to turbulent low. In such situations, it is oten diicult to estimate the low rate at which turbulence may take place. A range of Reynolds number can lead to inding out the transition zone. If 2100 N Re 4000 , low is in transition, and is neither laminar nor turbulent, sometimes called mixed low. However, during any design, it is chosen as turbulent for being in the safe side. It is sometimes easy to characterize the transition zone by critical luid velocity. It is used to deine the velocity at which the low regime changes from laminar to turbulent. his variable is the most important since all other parameters in the Reynolds number equation (Eq. 4.20 or 4.21) are considered constant. Since no single Reynolds number deines the transitional zone, it follows that a range of critical velocities may be necessary to determine the low regime. Based on critical velocity criteria, low regimes can be characterized by critical velocity Vc , and actual velocity Vac as: i) if Vc Vac, low is laminar, ii) if Vc Vac, low is turbulent, and iii) if Vc Vac , low is transition. he critical velocity can be determined for the Bingham plastic model as: VcB Here: VcB m

di

1.08

p

1.08

2 p

12.34

2 m di y

mdi

= Critical velocity for the Bingham plastic model, t/s = Mud density, ppg = Pipe inner diameter, in

(4.22)

Drilling Hydraulics 161 Velocity Proile Turbulent Flow

Smooth Pipe NR=107 , f=0.012 V

Laminar Flow NR 256

8

Clay

1/16 – 2 1/256 – 1/16 < 1/256

Term

254 Fundamentals of Sustainable Drilling Engineering 0

Depth (ft)

1000 2000 3000 D 4000 0

2000

4000

6000

8000

10000

Stresses and pore pressure (psi)

Figure 6.1 Normal subsurface pressure with depth.

Figure 6.1 shows the normal subsurface stresses and pore pressure distribution with depth. Note that the D-axis has the direction vertically downward (i.e. opposite to the gravitational acceleration) with a reference point at the earth surface (i.e. D = 0). he vertical stress increases downwards approximately at 0.8 – 1.0 psi/t.

6.2.3 Formation Pressure Formation pressure (or pore pressure) is the luid pressure found within the pore spaces of the formation. It can be expressed as an average vertical pressure or equivalent mud weight. he unit of pore pressure is psi, ppg, g/cc etc. It is an essential parameter in drilling activities of porous, luid-illed rock systems. he pore luid carries part of the total stresses of the formation and thus relieves the rock matrix from part of the load. Knowledge of formation pressure is important in drilling engineering since it afects the casing design, mud weight, rate of penetration, problems with stuck pipe, and well control. In addition, knowledge of the pore pressure in the various formations is extremely important while studying borehole stability during drilling, rock stability during production, and compaction/subsidence. It is very important because of the necessities of the prediction and detection of high pressure zones where there is a risk of blowout. Such zones are usually associated with the thick shale sequences which have trapped the connate water and normally released during deposition. If the sedimentation process continues, grains of sediment are continuously building up on top of each other usually in a water illed environment. As sediments deposit to form sedimentary layers, the luid (water) is trapped in small pores which form during the sedimentation process and an increasing portion of the overburden stress is carried through grain-to-grain contact. he grains of the sediment are packed closer together, and some of the water is expelled from the pore spaces (Figure 6.2). Under normal compaction, the pore luid remains in communication with the surface. In this case, the luid pressure within the pores is normal, meaning that it is approximately equal to the hydrostatic pressure. his indicates that the pore luid pressure is dependent on the density of the luid in the pore space and the depth of the pressure. It will be

Formation Pore and Fracture Pressure Estimation

255

Matrix Pores

Expelled Fluid

Figure 6.2 Water expelled out from the pore space.

Ground surface Hydrostatic communication between staked rock layer

D

Interstitial water Rock grain

Figure 6.3 Normal pore pressure of a water bearing formation system.

independent of the pore size or pore throat geometry. herefore, the pressure of the liquid in the pore space can be measured and plotted against depth as shown in Figure 6.1. his type of diagram is known as a P-Z diagram. Due to the communication with the formation and surface, the pore pressure gradient is a straight line as shown in Figure 6.1. he gradient of the line is a representation of the density of the luid. Hence the density of the luid in the pore space is oten expressed in units of psi/t. Based on the depositional characteristics of the formation pore space and rock matrix, pore pressure can be categorized as i) normal pressure, and ii) abnormal pressure

6.2.3.1 Normal Pressure When formation pore pressure is approximately equal to theoretical hydrostatic pressure for a given vertical depth, the formation pressure is called normal pore pressure. In terms of pressure gradient, it is deined as the pressure gradient corresponding to the hydrostatic gradient of a fresh or saline water column. Figure 6.3 shows the normal pore pressure system in a conventional hydrocarbon formation. As mentioned above, under normal compaction the pore luid within the pore is treated as normal pore pressure which can be written at a depth, D as: D

Pfn

fn

gdD

0

Here Pfn = normal formation pore pressure

(6.2)

256 Fundamentals of Sustainable Drilling Engineering fn = formation luid density at normal condition D = total vertical depth dD = vertical depth from a reference point (ground surface) g = gravitational acceleration

Equation (6.2) is valid based on the assumption that it is given by the weight of a luid column above, i.e. in analogy to Eq. (6.1). Most of the oilield brines have a dissolved mineral content which may vary from 0 to over 200,000 ppm. he pore luid density in case of brine with sea water salinity is in the range 1.03–1.07 g/cm3. So the pore pressure increase with depth is roughly 0.45 psi/t. However, the hydrostatic gradient ranges from 0.433 psi/t (pure water) to about 0.50 psi/t. In most geographical areas the hydrostatic gradient is taken as 0.465 psi/t (assumes 80,000 ppm). In many important cases, however, the pore pressure deviates from the normal value Pfn . Table 6.2 shows some typical values of the normal pore pressure gradient for several geographical areas of world where active drilling operations continue. Note that water densities vary from region to region. he normal pore pressure must be determined using the proper water density or pressure gradient. In ield unit hydrostatic pressure Eq. (6.2) can be written by recalling Eq. (4.34a) as:

Pfn Here Pfn m

D

0.052

m

D

(6.3)

= normal formation pore pressure, psi = mud weight, ppg = total vertical depth, t

Table 6.2 Normal formation pressure gradients for several areas of active drilling (Bourgoyne et al., 1986) Pressure gradient (psi/t)

Density (g/cm3)

Anadarko Basin

0.433

1.000

California

0.439

1.014

Gulf of Mexico

0.465

1.074

Mackenzie Delta

0.442

1.021

Malaysia

0.442

1.021

North Sea

0.452

1.044

Rocky Mountain

0.436

1.007

West Africa

0.442

1.021

West Texas

0.433

1.000

Formation Pore and Fracture Pressure Estimation

257

Example 6.1: Find out the normal pore pressure at a depth of 5000 t. below sea level. Assume that the drilling activities will be continued in California area. Also ind out the mud weight for that area. Solution: Given data: D = total vertical depth = 5,000 t Gnp = normal pressure gradient for California = 0.439 psi/t (Table 6.2) Required data: Pfn = normal pore pressure, psi m = mud weight, ppg he normal pore pressure for California area can be estimated as:

Pfn

Gnp D

5000 ft

0.439 psi / ft = 2,195.0 psi

he mud weight can be calculated using Eq. (6.3) as:

Pfn m

0.052 D

2195 psi 0.052

5000 ft

8.44 ppg

6.2.3.2 Abnormal Pressure Formation pressure which is smaller or greater than the magnitude of the hydrostatic pressure of a column of pore luid that reaches from the surface to the vertical depth of the formation is called abnormal pressure. In short, it is deined as any formation pressure above or below the hydrostatic gradient, and is called abnormal pressure. Figure 6.4 shows the development of abnormal pressure in the formation. Due to the abnormal pressure, the pore luid expels out from the pore space (Figure 6.4). Figure 6.5 shows the pressure variation with depth of the formation. If the pressure gradient is higher than the normal pressure gradient, it is called overpressured which is shown in Figure 6.5a. On the other hand, if the pressure gradient is less than the normal pressure gradient, it is called underpressured which is shown in Figure 6.5b. he underpressured formation pressure is also called subnormal pressure. In general,

Matrix Pores

Figure 6.4 Abnormal pressure development in the formation.

258 Fundamentals of Sustainable Drilling Engineering Geological Section Pore Pressure Gradient, psi/ft

Depth (ft)

Overpressure (Abnormally Pressured) Formation

Depth (ft)

Normal Pressure Gradient = 0.465 psi/ft

Abnormal Pressure Gradient > 0.465 psi/ft

Normal Pressure Gradient = 0.465 psi/ft

Pressure Gauge

Underpressure (Abnormally Pressured) Formation Abnormal Pressure Gradient < 0.465 psi/ft

Underpressure

Overpressure

Pressure (psi)

Pressure (psi)

(a) Overpressure Formation

(b) Underpressure (Subnormal Pressured) Formation

Figure 6.5 Variation of pressure with showing overpressured and underpressured formation.

Man-made Undercompacted shale Massive Shale Section

Isolated Sand Lenses

(a)

Shale

Salt Diaper

Massive Shale

Sealing Fault

(b)

Shale

(c)

DenseCaprock

(d)

Figure 6.6 Diferent formations showing pressure seals.

subnormal pressures are less common and cause fewer problems than overpressures. Table 6.3 shows the potential reasons for abnormal pressure gradient of the formation. All abnormal pressures require some means of sealing or trapping the pressure within the rock body (Figure 6.6). Otherwise, hydrostatic equilibrium back to a normal gradient would eventually be restored. Massive shales provide good pressure seals, however shales do have some permeability. So, normal pressures will eventually be established if it is given suicient time. It may take tens of millions of years for a normal pressure gradient to re-occur. Both types of abnormal pressure as mentioned above are associated with sealing mechanisms. he pressure seal is a zone of low permeability and acts to trap the pore luids within a formation. It restricts the vertical and lateral movement of pressure (i.e. evaporation, faults etc.). he seal prevents equalization of the pressures

Formation Pore and Fracture Pressure Estimation

259

Table 6.3 Potential reasons for abnormal pressure gradient of the formation. Artesian systems Structural reasons Tectonics Faults Salt or shale diapirs Others Surface erosion Rock diagenesis Sulfates Precipitation Clays hermal efects Osmosis through shale Biochemical efects External pressure sources Natural Man-made Undercompacted shale

which occur within the geological sequence. he seal is formed by a permeability barrier resulting from either physical or chemical action. he physical seal may be the result of a gravity fault during deposition or the deposition of a iner grained material. he chemical seal may be due to calcium carbonate being deposited, thus restricting average permeability. Another example might be chemical diagenesis during the compaction of organic material. Both physical and chemical action may occur simultaneously to form a seal (i.e. gypsum-evaporite action). In normal compaction, water is expelled from the formation pores during the compaction process. If the pore water is trapped, it will be pressurized by the overburden stress (Figure 6.7). he overburden is now supported by both the grain-to-grain contact and the luid pressure. his is called under compaction. he pore volume in undercompacted formation also tends to be larger than that in normally compacted formation at the same depth. As mentioned earlier, when the pore pressure is higher than the normal hydrostatic pressure, it is referred to as abnormal, and the situation is oten called overpressured. Pore luid may be trapped naturally by the deposition of ine-grained sediment, such as shale on top of the formation. Like an abnormal pressure gradient, there are many possible causes of abnormal pressure, which will be discussed later. While drilling in an abnormal pressure zone, the followings are the signs that indicate this pressure existence in the formation: • • • •

Normalized drilling rate (Drilling models) Change in rotary torque Change in drag Shale density

260 Fundamentals of Sustainable Drilling Engineering Overburden stress, ob = ef + Pp Efective stress, ef Pp Pore pressure

Figure 6.7 Relation between overburden stress, pore pressure, and efective stress.

• • • •

Gas analysis Flow line temperature Size and shape of cuttings Open hole logs

From the deinition of abnormal pressure, it can be classiied as underpressured (i.e. subnormal) or overpressured formation pressures. 1. Underpressured Formation Pressure: Underpressured formation pressure is also called subnormal formation pressure. As shown in Figure 6.5b, the subnormal pressure is always smaller than the normal formation pore pressure which shows some very speciic geographical locations on earth. Lost circulation problems and diferential sticking are common problems in these areas. here are many mechanisms by which subnormal pressures occur. he major mechanisms such as thermal expansion, formation foreshortening, precipitation, epeirogenic movement, depletion, potentiometric surface are discussed here. i) hermal Expansion: As sediment and pore luids are suppressed with the increasing burial depth, the temperature rises. In this case, if the pore luid is allowed to expand, the density will decrease, which results in a diminution in pressure. ii) Formation Foreshortening: During a compression process of the formation beds, there is some bending of strata as shown in Figure 6.8. Due to this action, the upper bed A will bend upward, while the lower bed C will bend downwards. he intermediate bed B must expand to ill the void and so create a subnormally pressured zone. his is assumed to apply to some subnormal formation zones in Indonesia and the USA. It is noted that this action may also cause overpressures in the top and bottom beds (i.e. Bed A and Bed C). iii) Precipitation: In dry areas such as Texas, Middle East, South India, etc., the water table may be located hundreds of feet below surface. his reduces the hydrostatic pressure and creates subnormal pressured zones in the formation. iv) Epeirogenic Movements: A change in elevation can cause abnormal pressures in formations open to the surface laterally, but otherwise sealed. If the outcrop is raised

Formation Pore and Fracture Pressure Estimation

261

Overpressured A

Bed A P

Bed B

Subnormal Pressure P

P

B

Bed C C Overpressure

Figure 6.8 Foreshortening of formation beds (Redrawn from Ford, 1999).

Production Well

Development Well

Producing zone

Deeper Prospect

Figure 6.9 Production of oil or gas.

this will cause overpressures (Figure 6.5a), if lowered it will cause subnormal pressures (Figure 6.5b). However, pressure changes are rarely caused by changes in elevation alone because associated erosion and deposition are also signiicant. Loss or gain of water saturated sediments is also important. v) Depletion: A subnormally pressured zone may occur when hydrocarbons or water are produced from a capable formation in which no subsidence happens (Figure 6.9). his is important when drilling development wells through a reservoir where there is a production for some time. Some pressure gradients in Texas aquifers have been as low as 0.36 psi/t. vi) Potentiometric Surface: his mechanism refers to the structural relief of a formation and can result in both subnormal and overpressured zones. he potentiometric surface is deined by the height to which conined water will rise in wells drilled into the same aquifer. he potentiometric surface can therefore be thousands of feet above or below ground level (Figure 6.10). vii) Faulting: A discontinuity in a rock formation caused by the fracturing of the earth’s crust can create the fault. here are various causes of fault fractures such as the movement of “tectonic plates” relative to each other. In oilield terms a fault block is a compartment of a rock formation surrounded or partly surrounded by faults, which may have sealed in hydrocarbons separately from the rest of the formation. When there is a sealing fault that deviates the formation zones downward, subnormal pressured zones are created (Figure 6.11a and b). Normal faults and thrust faults are the result of various stress imbalances in the crust and supericial sediments. hey are oten caused

262 Fundamentals of Sustainable Drilling Engineering Intake Area Surface

Excess Pressure

Subnormal Pressure

Potentiometric Surface Oil pool A Reservoir Rock

ace Surf Oil pool B

Discharge Area

Figure 6.10 Potentiometric surface in connection with the ground surface (Redrawn from Ford, 1999).

Marker Bed Marker Bed PA PA

Subnormal Pore Pressure PB

A

A PB

B

Normal Pore Pressure

Pressure may increase

Top of Transition Zone

Normal Pore Pressure Flow Abnormal Gradient Pore Pressure

B Sealing Fault

(a) Normal Faulting

(b) Down faulting

Figure 6.11 Subnormal pressures due to faulting.

by, helped by, or linked to overpressure. When moving and dilating, pressures can easily be transferred. his can result in moving luids to a previously lower potential or bleeding pressure of, returning it back to hydrostatic. Faults are also good lateral seals. viii) Outcrop Aquifer: Outcrop can be deined as the appearance of a rock formation at the surface whereas an aquifer is an underground water reservoir contained between layers of rock, sand or gravel. Figure 6.12 shows a portion of bedrock or other stratum protruding through the soil level, indicating a fault or some other oil-bearing formation. In a water-drive ield, the aquifer is the water zone of the reservoir underlying the oil zone. In reality, the efect of under pressuring is usually very insigniicant. herefore, it does not have any practical concern. In reality, the largest number of abnormal pressures reported in literature is the overpressures, and not subnormal pressures. 2. Overpressured Formation Pressure: As mentioned earlier, the formations whose pore pressure is greater than the corresponding normal gradient 0.465 psi/t is called overpressured. hese pressures can be plotted between the hydrostatic gradient and the overburden gradient (1 psi/t.) which is also shown in Figure 6.5a. his overpressure can cause severe drilling problems. Overpressures at diferent geographical locations worldwide are shown in Table 6.4. In nature, there are numerous mechanisms that cause such overpressures to develop in the formation. Some such as formation foreshortening and potentiometric surface have already been discussed under subnormal pressures in the above section. It is due

Formation Pore and Fracture Pressure Estimation

263

Outcropping aquifer Outcropping aquifer

Patm

Patm

(a) Aquifer outcrops below rig

(b) Aquifer

Figure 6.12 Aquifer outcrops below rig.

Table 6.4 Overpressures at diferent geographical locations. Geographical Location

Pressure Gradient

Gulf Coast

0.8 – 0.9 psi/t.

Iran

0.71 – 0.98 psi/t.

North Sea

0.5 – 0.9 psi/t.

Carpathian Basin

0.8 – 1.1 psi/t.

to the fact that both under and over pressures can occur as a result of these mechanisms. he other mechanisms that cause the overpressured are summarized below. i) Faulting: It is also called luid charging. In this mechanism, fault may redistribute sediments, and place permeable zones opposite to impermeable zones. he fault movement is in the upward direction. hus it creates barriers to luid movement (Figure 6.13). In this case, hydrocarbon from deep or high-pressure reservoir may low into shallower formation through fractures or other paths. his may also prevent water being expelled from shale, which will cause high porosity and pressure within that shale under compaction. his is a common cause of abnormal pressure in shallow formations. ii) Incomplete Sediment Compaction: In the rapid burial of low permeability clays or shales, there is little time for luids to escape. Under normal conditions the initial high porosity is decreased as the water is expelled through permeable sand structures or by slow percolation through the clay/shale itself. If the burial is rapid, however, there is no time for this process to take place, and the trapped luid will help to support the overburden. iii) Massive Rock Salt Deposition: he deposition of salt can occur over wide areas. Since salt is impermeable to luids, the underlying formations become overpressured. Abnormal pressures are frequently found in zones directly below a salt layer (Figure 6.6). iv) Repressuring from Deeper Levels: It is also called luid migration efects. his is caused by the migration of luid from a high to low pressure zone at shallower depth.

264 Fundamentals of Sustainable Drilling Engineering

Fault or fracture

Figure 6.13 Fluid charging due to fault or fracture in the formation.

Underground Blowout

Casing Leaks

Faulty Cement Job

(a)

(b)

(c)

Figure 6.14 hree examples of shallow formations being charged with deeper gas.

his may be due to faulting (Figure 6.13), improperly abandoned (Figure 6.14a) or from a poor casing/cement job (Figure 6.14b and c). When this happens, the shallow formation is said to be charged. As shown in the igures, the low path for this type of luid migration can be natural or man-made. he danger of repressuring the formation zone is that the unexpectedly high pressure could cause a kick, since no lithology change would be apparent. High pressures can occur in shallow sands if they are charged by gas from lower formations. Sometimes, even if the upward movement of luid is stopped, considerable time may be required for the pressures in the charged zone to bleed of and return to normal. his situation is common in old ields. v) Diferential Density Efects: When the density of the hydrocarbon or other pore luid in an inclined formation is much lower than the normal luid density, abnormal pore pressure may develop in the updip region. he common occurrence in inclined gas reservoirs of this type of abnormal pressure is shown in Figure 6.15. his situation is encountered frequently when a gas reservoir with a signiicant dip is drilled. Because of a failure to recognize this potential hazard, blowouts can be occurred in familiar gas sands previously presented by other wells. However, the magnitude of the abnormal pressure can be calculated easily by use of the hydrostatic pressure concepts as described in Chapter 4. A higher mud density is required to drill the gas zone safely near the top of the structure than is required to drill the zone near the gas/water contact. vi) Salt Diaperism: his is the upward movement of a low-density salt dome due to buoyancy, which distributes the normal layering of sediments and produces pressure

Formation Pore and Fracture Pressure Estimation

265

anomalies (Figure 6.16). he salt may also act as an impermeable seal to lateral dewatering of clays. Salt diapirs plastically “low” or extrude into the previously deposited sediment layers. he resulting compression can result in overpressure. vii) Phase Changes During Compaction: Sometimes, it is called the diagenesis efect. Minerals may change under increasing pressure i.e. under compaction. (Example: gypsum + anhydrate + free water). It has been estimated that a 50 t. bed of gypsum will produce a 24 t. column of water. Conversely anhydrite could be hydrated at depth to yield gypsum resulting in a 40% increase in rock volume. his diagenesis is due to the chemical transformation of one rock mineral to another. For example, at 200 –300°F, montmorillonite can be converted to illite by releasing the interlayer water (Figure 6.17). he transformation of montmorillonite to illite also releases large amounts of water (Figure 6.17a). he last water layer in the interlayer space has a much higher density than that of bulk water. hus, abnormal pore pressure may develop as this water is released into the pores (Figure 6.17b). viii) Tectonic Compression: he lateral compression of sediments may result either in upliting weathered sediments or fracturing/faulting of stronger sediments. hus formations normally compacted at a depth can be raised to a higher level. If the original pressure is maintained, the uplited formation would be overpressured. ix) Salt Formation: If there is a salt formation at the underground layer, there would be normal pressure above the salt formation zone (Figure 6.18). On the other hand, the pressure at the bottom of the salt layer is oten extremely overpressured. Gulf of Mexico

Sea Level

Top of sand structure GWC Gas Sand

Figure 6.15 Diferential Density Efects (Redrawn from Bourgoyne et al., 1986).

Isolated san lens Shaded Sand Represent Abnormal Pore Pressure

Far Field Equilibrium Restored

Salt Diaper

Figure 6.16 Salt diapirs.

266 Fundamentals of Sustainable Drilling Engineering

Pp

(a) Montmorillonitc – release of interlayer water at high temperatures.

(b) lllite – low interlayer water content; abnormal pressure developed due to digenesis.

Figure 6.17 Clay diagnosis.

Normally Pressure

Salt Salt

Pressure at the bottom of the salt is often extremely overpressures

Figure 6.18 Salt formations.

x) Compaction Efects: Compaction is principally a process of mechanical rearrangement. If it applies to shales, which are deposited with a large content of organic material, they will produce gas as the organic material degrades under compaction (Figure 6.19). If this gas is not allowed to escape, it will also form salts which will be precipitated in the pore space, thus helping to reduce porosity and create a seal. Again pore space is reduced under compaction and pore water expands with the increasing burial depth and increased temperature. hus, normal formation pressure can be maintained only if there exists a permeable path to allow the formation water to escape freely (Figure 16.19). If pore water can escape as quickly as required by the natural compaction rate, the pore pressure will remain at hydrostatic pressure. However, if the water low path is blocked or severely restricted, the increasing overburden stress will cause the pressurization of the pore water above hydrostatic pressure. he pore volume also will remain greater than normal for the given burial depth. herefore, the natural loss of permeability due to the compaction of ine-grained sediments may create a seal, which would allow developing abnormal pressures. he compaction rate of the sediments plays a major role while compaction efects continue. he factors afecting compaction rate are rate of deposition, tectonic forces, formation permeability, lithology, diagenesis, and osmosis. Example 6.2: A gas sand reservoir is shown in Figure 6.15 where the average gas density was measured as 0.65 lbm/gal. Assume that the water-illed portion of the sand is

Formation Pore and Fracture Pressure Estimation

(a) Normal arrangement

267

Expelled luid

(b) Under compaction

Figure 6.19 Rock matrixes and pore spaces arrangement under normal and under compaction.

pressured normally and the gas/water contact is at a depth of 6,000 t. What is the mud weight that would be required to drill through the top of the sand structure safely at a depth of 4,500 t.? Solution: Given data: = gas density = 0.65 lbm/gal g D gw = total vertical depth of gas/water contact = 6,000 t. Ds = total vertical depth of the sand structure = 4,500 t. Gnp = normal pressure gradient for gulf of Mexico = 0.465 psi/t. (Table 6.2) Required data: = mud weight, ppg m he normal pressure at a depth of 6,000 t. of gas/water contact can be estimated using pressure gradient concept as:

Pfn _ GWC

Gnp D

6000 ft

0.465 psi / ft = 2,790.0 psi

Again, the normal pressure at a depth of 4,500 t. where gas sand exists can be estimated using pressure gradient concept as:

Pfn _ GS

Gnp D

4500 ft

0.465 psi / ft = 2,092.5 psi

However, the pressure in the gas sand at 4,500 t. can also be determined hydrostatic pressure concept as:

Pfn _ GS 2,790.0 0.052

Pfn _ GWC

0.65 lbm / ft

0.052

g

DGWC DGS

6,000 ft 4,500 ft = 2,739.3 psi

268 Fundamentals of Sustainable Drilling Engineering his pressure is higher than that calculated based on a normal pressure gradient at 4,500 t. herefore, the minimum mud weight can be calculated using Eq. (6.3) as:

Pfn _ GS m

0.052 D

2739.3 psi 0.052 4500 ft

11.7 ppg

6.2.4 Overburden Pressures he pressures discussed in Section 6.2.3 relate entirely to the pressure in the pore space of the formations. However, it is also important to quantify the vertical stress at any depth because this pressure will have a signiicant impact on the pressure at which the borehole will fracture when exposed to high pressures. Vertical stress develops due to the overburden load (Figure 6.20). It is deined as the combined weight of the formation matrix and the luids overlying a formation. his vertical stress ultimately introduces the matrix stress which is deined as the resistance of the formation matrix to compaction expressed in psi or psi/t. he vertical pressure any point in the earth is known as the overburden pressure or geostatic pressure which is the pressure exerted by the overburden load upon underlying formations (Figure 6.20). he overburden gradient is derived from a cross plot of the overburden pressure versus depth which is shown in Figure 6.21. Figure 6.22 shows the equilibrium condition of overburden pressure. At equilibrium condition, the overburden pressure is the sum of vertical matrix stress and the formation pore pressure. Mathematically,

Pob Here Pob v

Pfn

v

Pfn

(6.4)

= overburden pressure = vertical matrix stress = normal formation pore pressure

Example 6.3: Calculate the overburden pressure of an underground reservoir if the matrix stress is 8,500 psi and the formation pore pressure is 5000 psi.

Overburden Overburden Pressure

Matrix Stress Pore Fluid Pressure

Figure 6.20 Overburden load on formation zone.

Formation Pore and Fracture Pressure Estimation

269

Depth (ft)

Normal pore pressure Gradient = 0.456 psi/ft Fracture pressure gradient Overburden gradient

Pressure (psi)

Figure 6.21 Typical pressure versus depth showing pore pressure gradient, overburden, and fracture pressure gradient.

Equilibrium Overburden Pressure

Matrix Stress

+ Pore Fluid Pressure

Figure 6.22 Equilibrium condition for rock matrix and formation pore space.

Solution: Given data: = vertical matrix stress = 8,500 psi v Pfn = normal formation pore pressure = 5,000 psi Required data: Pob = overburden pressure = ? he overburden pressure can be estimated using the Eq. (6.4) as:

Pob

v

Pfn

8,500 psi 5,000 psi 13,000 psi

Due to the compaction efect as mentioned earlier, the overburden pressure depends on several factors such as rock and luid densities, lithology etc. Table 6.5 shows the typical matrix and luid densities in general. he pressure at any point is a function of the mass of the rock and luid above the point of interest. In order to calculate the overburden pressure at any point, the average density of the material (rock and luids) above the point of interest must be determined. he average density of the rock and luid in the pore space is known as the bulk density of the rock. he bulk density at a given depth can be calculated as: b

f

r

1

(6.5)

270 Fundamentals of Sustainable Drilling Engineering Here b f r

= bulk density of porous sediment = luid density in the pore space = grain density of rock matrix = porosity

In an area of signiicant drilling activity, the change in bulk density with depth usually is determined by conventional well logging methods. Since the lithology and luid content vary with depth, the bulk density will also vary with depth. he overburden pressure or gradient is derived from the pressure exerted by the rock above the depth of interest. his overburden pressure at any point is therefore the integral of the bulk density from surface down to the point of interest. Table 6.5 shows the typical matrix and luid densities. In many areas, it is convenient to use the exponential relationship relating change in average sediment porosity to depth of burial when calculating the overburden stress, ob , resulting from geostatic load at a given depth. To use this approach, the average bulk density data are expressed irst in terms of average porosity. hen Eq. (6.5) for average porosity yields: r

b

r

f

(6.6)

avg

Equation (6.6) allows average bulk density data read from well logs to be expressed easily in terms of average porosity for any assumed grain density and luid density. If these average porosity values are plotted against depth on semi-log paper, a good straightline trend usually is obtained (Figure 6.23). he equation of this line is given by: oe

K Ds

(6.7)

Table 6.5 A list of typical matrix and luid densities. Type

Substance

Density (gm/cc)

Rock Matrix

Sandstone

2.65

Limestone

2.71

Dolomite

2.87

Anhydrite

2.98

Halite

2.03

Gypsum

2.35

Freshwater

1.0

Fluid

Seawater

1.03 – 1.06

Oil

0.6 – 0.7

Gas

0.15

Formation Pore and Fracture Pressure Estimation

271

0

Sediment depth (D), ft

1000 2000 3000 4000 5000 6000 0.01

1.0 Porosity ( ). %

Figure 6.23 Average porosity variation with sediment depth.

Here o

K Ds

= porosity at surface (D = 0) = porosity decline constant at = the depth below the surface of the sediments

he constants o and K can be determined graphically or by the least-square method. he porosity decline constant can be estimated from the Eq. (6.7) by taking ln in both sides of the equation and solving the same for K as:

ln o ln Ds

K

(6.8)

he vertical overburden stress ( ob ) resulting from geostatic load at a depth can be written in terms of bulk density of the system in the same form of Eq. (6.1) as: D ob

b

gdD

(6.9)

0

So, the vertical overburden stress resulting from the geostatic load can be expressed in terms of average sediment porosity at a particular depth. Now substituting Eq. (6.5) into Eq. (6.9) yields: D ob

g

f

r

1

dD

(6.10)

0

Equation (6.10) is valid only for onshore area. However, we can utilize Eq. (6.10) for ofshore area too. In this case the total depth would be in two segments: i) from the surface to the ocean bottom (i.e. total depth of sea water: 0 to Dsw), and ii) from the mudline to the depth of interest (i.e. Dsw to D). In this case, Eq. (6.9) can be used for these two situations. hus b would become seawater density, sw which is equal to 8.5 lbm/gal up

272 Fundamentals of Sustainable Drilling Engineering to the depth of Dsw and then from sea bed to the depth D would be same as mentioned in Eq. (6.10). So, Eq. (6.9) can be written as: D sw Dsw g

ob

g

r

r

dD

f

(6.11)

Dsw D ob

sw

Dsw g g D Dsw

g

r

r

dD

f

(6.12)

Dsw

he variation of with depth D due to overburden stress can be estimated using Eq. (6.7). herefore, substituting Eq. (6.7) into Eq. (6.12) yields: D ob

sw

Dsw g g D Dsw

g

r

r

f

o

e

K D

(6.13)

dD

Dsw

Solving the Eq. (6.13) and applying the limits of the integration, the equation becomes as:

ob

sw

Dsw g g D Dsw

g

r

r

f

1 e K

o

K D

e

K Dsw

(6.14) Let Ds

ob

D Dsw. Substituting this in Eq. (6.14) yields:

gDs sw Dsw g

gDs sw Dsw g

ob

ob

g

r

r

o

r

r

f

o

e

K

g

r

r

f

K Dsw

e

K g

gDs sw Dsw g

f

o

K

K Dsw

e

K Dsw

e

e

K

K Ds

1 e

e

Ds Dsw

(6.15)

K Dsw

(6.16)

K Ds

(6.17)

In the right hand side of Eq. (6.17), within the range of Dsw, there is no existence of rock, so r 0 and the porosity becomes 1. herefore, the porosity decline constant will become zero. As a result, e K Dsw 1. hus, Eq. (6.17) can be written as: ob

sw

Dsw g

gDs

g

r

r

f

o

K

1 e

K Ds

(6.18)

For onshore area, Eq. (6.18) can be written as:

ob

gDs

g r

r

f

K

o

1 e

K Ds

(6.19)

Formation Pore and Fracture Pressure Estimation

273

In ield unit, Eqs. (6.18) and (6.19) can be written as:

ob

0.052

sw

Dsw

0.052

ob

r

r

Ds

r

Ds

f

o

K r

f

o

K

1 e

1 e

K Ds

K Ds

(6.20)

(6.21)

Here ob sw

Dsw r

Ds f o

K

= vertical overburden stress, psi = density of sea water, lbm/gal = depth from surface to the ocean bottom, t. = grain density of rock matrix, lbm/gal = the depth from the sea bed to up to a depth of interest, t. = density of luid in the pore space, lbm/gal = porosity at surface (D = 0), fraction = porosity decline constant at , t.–1

Example 6.4: Determine the porosity decline constant for the North Sea area. It is noted that an average grain density of 2.55 g/cm3, an average pore luid density of 1.044 g/cm3, and the value for surface porosity of 45% were recorded. Assume the average bulk density of the sediment is 2.35 g/cm3 at a speciied depth of 9,000 t. Also compute the vertical overburden stress along the coast line of North Sea at the same depth. Solution: Given data: = average grain density of rock matrix = 2.55 g/cm3 r = average density of luid in the pore space = 1.044 g/cm3 f = porosity at surface (D = 0) = 0.45 o Ds = the depth below the surface of the sediments = 9,000 t. = bulk density of porous sediment = 2.35 g/cm3 b Required data: K = porosity decline constant at =? = vertical overburden stress =? ob Before calculating the porosity decline constant, we have to calculate the average porosity at the speciied depth by using the Eq. (6.6) as: r

b

r

f

avg

2.55 2.35 2.55 1.044

0.133

Using Eq. (6.7), K can be calculated as: o

e

K Ds

0.133 0.45e

K

9000

K

0.000135 ft -1

As long as the vertical overburden stress is along the coast line of North Sea, Eq. (6.19) can be used if we assume that Dsw = 0. herefore,

274 Fundamentals of Sustainable Drilling Engineering ob

2.55 gm / cm3

9000 ft

25.4 cm / ft

2.55 gm / cm3 1.044 gm / cm3 0.000135 ft 25.4 cm / ft 1 e

0.000135 ft 25.4 cm/ ft

1

981

981cm / s 2

cm 0.45 s2

1

9000 ft 25.4 cm/ ft

2

= 571854330 gm / cm s – 87971272.6 gm / cm s 2 2 2 = 483,883,057.4 gm / cm s = 483,883,057.4 dynes / cm = 7,016.3 psi (since 1 dynes/cm2 = 0.0000145 psi) 6.2.5 Pore Pressure Estimation he estimation of formation pore pressure is an important task in drilling activities. he formation pore pressure must be estimated during well planning because it afects directly the mud and casing programs. he accuracy of pore-pressure estimation is critical to the success of a drilling operation. his pressure is one of the most critical parameters needed by the drilling engineer in planning and drilling a well. In well planning, the engineer must irst determine whether there is a presence of abnormal pressures or not (Figure 6.24). If there is an existence of abnormal pressure, it is important to know the depth at which the luid pressure deviates from its normal pressure or gradient. Finally the magnitude of the pressures must be estimated. However, porepressure prediction and estimation are still an active research area; many diferent techniques have been proposed to improve the accuracy. here are three general categories applied to detect and/or estimate the abnormal formation pore pressure. he followings are the categories: i) predictive techniques, ii) detection techniques, and iii) conirmation techniques.

Normal Pressure Gradients

0'

Depth, ft

West Texas: 0.433 psi/ft Gulf Coast: 0.465 psi/ft

Abnormal Pressure Gradients

??

Depth of interest where abnormal pressure starts Pore Pressure, psig

Figure 6.24 Presence of abnormal pressure at a certain sediment depth.

Formation Pore and Fracture Pressure Estimation

275

6.2.5.1 Predictive Techniques he predictive techniques for formation luid pressure estimation are applied before drilling. he predictive techniques are based on measurements that can be made by i) geophysical measurements: identify geological conditions which might indicate the potential for overpressures such as salt domes, ii) analyzing data from wells that have been drilled in nearby locations (i.e. ofset well data which should be emphasized in the planning of development wells), iii) seismic data that has been used successfully to identify transition zones, iv) ofset well histories which may contain information on mud weights used, problems with stuck pipe, lost circulation or kicks, and v) wire line logs or mud logging information which is also valuable when attempting to predict overpressures. Geophysical measurements include the shallow and/or deep seismic surveys (i.e. formation velocity), comparison with nearby wells, gravity, magnetic and electrical prospecting methods. hese geophysical methods are used in the initial exploration stage. here may also be data from wells drilled in the same area. When planning development wells, emphasis is placed on data from previous drilling experiences in the area. For wildcat wells, only seismic data may be available. Most pore pressure prediction techniques rely on measured or inferred porosity. he shale compaction theory as mentioned earlier is the basis for these predictions. he procedures for prediction suggest to irst measure the porosity indicator (e.g. density) in normally pressured, clean shale, to establish a normal trend line. hen if the indicator suggests porosity values that are higher than the trend, then abnormal pressures are suspected to be present. Finally, the magnitude of the deviation from the normal trend line is used to quantify the abnormal pressure. he current approach to predicting pore pressure is based on the fact that formations with abnormal pressures tend to have higher porosities than normally compacted formations. However, the available literature shows that the prediction techniques are primarily in two folds: i) correlation of available data from nearby wells, and ii) seismic data. 1. Estimation using Correlations: In 1971, Matthews was the irst person who showed how to calculate pore pressure from well log data. his strategy utilizes a geologic age speciic overlay which indicates the normally pressured compaction trendline for the appropriate geologic age. Ater plotting the observed resistivity/conductivity data on the geologic age speciic overlay, formation pore pressures can be predicted. A simple calibration of the data is required to implement this method. he second pore pressure prediction was developed by Ben Eaton. Eaton developed a simple relationship that predicts the formation pore pressure knowing the normally pressured compaction trendline, the observed resistivity/conductivity data and a relationship for formation overburden stress. he two pore pressure prediction techniques require petrophysical data, speciically formation resistivity or conductivity, to predict pore pressures. 2. Estimation using Seismic Data: Seismic data are more important in the planning of exploration wells. To estimate formation pore pressure from seismic data, the average acoustic velocity as a function of depth is an important parameter which must be determined to estimate formation pore pressure using from seismic data. he machine displays only time which is the reciprocal of velocity. his time is called interval transit time. he observed interval transit time is a porosity dependent parameter that varies with porosity according to the following relation:

276 Fundamentals of Sustainable Drilling Engineering tt Here tt tf tr

tr 1

tf

(6.22)

= the observed interval transit time, s/t. = the interval transit time in the pore luid, s/t. = the interval transit time in rock matrix, s/t. = porosity

Table 6.6 depicts the interval transit times for common matrix materials and pore luids. It is noted that pore luid transit times are greater than rock matrices. herefore the observed transit time in rock increases with increasing porosity. Sometimes it is useful to use empirical or mathematical models to estimate extrapolated formation pore pressure. hese models are desirable when plotting a porositydependent parameter vs. depth for this purpose specially to extrapolate a normal pressure trend (observed in shallow sediments) to deeper depths, where the formations are abnormally pressured. Oten a linear, exponential, or power-law relationship is assumed so that normal pressure trend can be plotted as a straight line on Cartesian, semilog, or log-log graph paper. However, in some cases, an acceptable straight line trend is not observed for any of these approaches. As a result a more complex model must be used. Such complex model can be derived using Eq. (6.7) where normal compaction process exists. Substituting Eq. (6.7) for the into Eq. (6.22) yields:

tt

t f oe tt

o

K Ds

tr 1

tf

tr e

tt o

tf

o

e

K Ds

tr tr

o

tf

K Ds

(6.23)

tr

(6.24)

e

tr

K Ds

(6.25)

Taking ln in both sides of Eq. (6.25) yields:

tr

ln o

tf

tr

tt

ln o

tf

tr

K Ds

(6.26)

Equation (6.26) represents the normal pressure relationship of the average observed sediment travel time and depth. his equation is complicated by the fact that rock matrix transit time also varies with porosity. his variance is due to the compaction efects on shale matrix travel time. As shown in Table 6.6, rock matrix transit time for shales can vary from 167 μs/t. for uncompacted shales to 62 μs/t. for highly compacted shales. In addition, formation changes with depth also can cause changes in both matrix travel time and the normal compaction constants o and K . hese problems can be resolved only if suicient normal pressure data are available.

Formation Pore and Fracture Pressure Estimation

277

Table 6.6 Representative interval transit time times for common matrix materials and pore luids (Bourgoyne et al., 1986). Transit Time (10–6, s/t.)

Description Matrix Material

Dolomite

44

Calcite

46

Limestone

48

Anhydrite

50

Granite

50

Gypsum

53

Quartz

56

Shale Salt Sandstone Pore Fluid

62 – 167 67 53 – 59

Distilled Water

218

100,000 ppm NaCl

208

200,000 ppm NaCl

189

Oil

240

Methane

626*

Air

910*

Note: Valid only near 14.7 psia and 60°F

To describe the prediction method analysis, the following worklow is outlined below. i.

ii. iii. iv. v.

Identify, acquire and review ofset well data including: a. Petrophysical data b. Drilling records c. Measured pressure data Construct pore pressure prediction model using petrophysical data Include ofset well data in the pore pressure prediction model Calibrate pore pressure prediction model, if necessary Analyze the pore pressure prediction model against data obtained from reviewing drilling records and select or develop an accurate pore pressure prediction model

278 Fundamentals of Sustainable Drilling Engineering

6.2.5.2

Detection Techniques

While drilling a well, the detection techniques are applied to estimate formation luid pressure. hey are basically used to detect an increase in pressure in the transition zone. hese are certain drilling response parameters which can be monitored while the well is being drilled. Any change in these parameters is a signal that a transition zone may have been penetrated. here are three sources of data which allows the detection of abnormal pressures: i) drilling parameters, ii) drilling mud parameters, iii) drilling cuttings. Table 6.7 shows the methods for detecting abnormal pressures using these techniques. 1. Drilling Parameters: First drilling parameters as listed in Table 6.7 are observed. Empirical equations are then applied to produce a term which is dependent on pore pressure. he theory behind using drilling parameters to detect overpressured zones is based on facts such as i) compactions of formations increases with depth due to overburden which expedite ROP to decrease with depth provided all other things being constant, ii) in the transition zone the rock will be more porous (less compacted) than that in a normally compacted formation. As a result an increase in ROP will occur. In addition, as drilling proceeds the diferential pressure between the mud hydrostatic and formation pore pressure in the transition zone will reduce which results a much higher ROP. he use of the ROP to detect overpressured zones is a simple concept, but more dificult to apply in practice. his is due to the fact that many other factors afect the ROP apart from formation pressure. Some additional factors are: i) bit type, ii) bit diameter, iii) bit nozzle size, iv) bit wear, v) weight on bit, vi) rotary speed, vii) mud type, viii) mud density, ix) efective mud viscosity, x) solids content and size distribution in mud, xi) pump pressure, and xii) pump rate. Since these other parameters efects cannot be held constant, they must be considered so that a direct relationship between ROP and formation pressure can be established. his is achieved by applying empirical equations to produce a “normalized” ROP, which can then be used as a detection tool. he followings correlations are normally used to ind out the formation pressure using detection technique (i.e. drilling parameters). i) Bingham Model: Bingham (1964) developed a model to detect overpressures which is based on a normalised drilling rate equation. He proposed the following generalized equation as a drilling equation.

R Here A db dexp E N R W

AN

E

W db

dexp

= rock matrix strength constant or drillability constant = bit diameter, in = bit weight exponent or d-exponent or formation drillability = rotary speed exponent = rotary speed, rpm = rate of penetration or drilling rate, t./hr = weight on bit, lbf

(6.27)

Formation Pore and Fracture Pressure Estimation

279

Table 6.7 Methods for detecting abnormal pressures by detection techniques (Ford, 1999). Source of Data

Parameters

Time of Recording

Drilling Parameters

Drilling rate of penetration

While drilling Delayed by the time required for mud return

d, dc exponent Drilling rate equations Torque Drag Drilling Drilling Mud Parameter

Gas content

While drilling

Flowline mud weight Inlux of oil and gas (i.e. kick) Flowline temperature Chlorine variation Drillpipe pressure Pit volume Flow rate Hole ill up Drill Cuttings

Shale cuttings Bulk density Shale factor

While drilling Delayed by the time required for sample return

Electrical resistivity (i.e. Shale slurry resistivity) Volume Shape and size Novel geochemical Physical techniques

he model proposed by Bingham [i.e. Eq. (6.27)] is called the “drilling rate” equation. ii) Jordan and Shirley Model: Jordan and Shirley (1966) reorganised Eq. (6.27) for dexp . He simpliied this equation by assuming that the rock matrix strength constant did not change (A = 1) and the rotary speed exponent was equal to one (i.e. E = 1). he rotary speed exponent has been found experimentally to be very close to one. hese simpliications helped to remove the variables which were dependent on lithology and

280 Fundamentals of Sustainable Drilling Engineering rotary speed. his means however that the resulting equation can only be applied to one type of lithology and theoretically at a single rotary speed. he latter is not too restrictive since the value of E generally close to one. On the basis of these assumptions and accepting the above mentioned limitations, the following equation is produced using Eq. (6.27) as:

R N

W db

dexp

(6.28)

Taking log into both sides of Eq. (6.28), the equation becomes as:

R N W log db log

dexp

(6.29)

A modiied version of Eq. (6.29) can be written as:

log dexp

R 60 N

12W log 106 db

(6.30)

he model proposed by Jordan and Shirley [i.e. Eq. (6.30)] is called the “d-exponent” equation. Since the values of R, N, W, and db are either known or can be measured at surface the value of the d-exponent can be determined and plotted against depth for the entire well. However, this equation is not a rigorous solution for the dexp of Eq. (6.27) because of the above mentioned assumptions suggested by Jordan and Shirley (1966). Equation (6.30) can be used to detect the transition from normal to abnormal pressure if the drilling luid density is held constant. A detail analysis can be found in their article. It should be realized that this equation takes into account the variations in the major drilling parameters. However, to get the accurate results, there are some conditions that should be maintained. hese conditions are: i) no abrupt changes in WOB or RPM should occur, i.e. keep WOB and RPM as constant as possible, ii) to reduce the dependence on lithology, the equation should be applied over small depth increments only, iii) a good thick shale is required to establish a reliable “trend” line. Example 6.5: Determine the value of the dexp if the drilling rate is 35 t./hr, the rotary RPM is 100, and the weight on the bit is 60,000 lbf. Assume necessary data. Further calculate what will happen to dexp if the drilling rate is increased to double of its original case. Make comments on the result. Solution: Given data: R1 = drilling rate = 35 t./hr N = rotary speed = 100 rpm

Formation Pore and Fracture Pressure Estimation W R2

281

= weight on bit = 60,000 lbf = drilling rate = 70 t./hr

Assuming: db = bit diameter = 12.25 in Required data: dexp1 = formation drillability = ? dexp2 = formation drillability = ? he d-exponent can be calculated by using the Eq. (6.30) as:

R 60 N 12W log 106 db

log

log

dexp1

35 60 100

12 60,000 log 106 12.25

2.2341 1.2308

1.82

Now, if the rate of penetration is doubled, then d-exponent can also be calculated in the same fashion as:

R 60 N 12W log 106 db

log

log

dexp 2

70 60 100

12 60,000 log 106 12.25

1.9330 1.2308

1.57

It is showing that an increase in R resulted in a decrease in dexp . In this case, doubling of the rate of penetration decreased the modiied d-exponent from 1.82 to 1.57 iii) Rehm and McClendon Model: It can be observed that the mud weight consideration is not taken care by the “d-exponent” Eq. (6.30). Since mud weight determines the pressure on the bottom of the hole, an increase of the mud weight will increase the chip hold-down efect which results a decrease in ROP. As a result, Rehm and McClendon (1971) proposed modifying the d-exponent to correct for the efect of mud density changes as well as changes in weight on bit, bit diameter, and rotary speed. Ater an empirical study, they computed a modiied d-exponent correlation as:

dm

dexp

n

(6.31)

e

Here dm n

e

= modiied d-exponent = mud density equivalent to normal pore pressure gradient or normal mud weight, ppg = equivalent mud density at the bit while circulating or actual mud weight in use, ppg

282 Fundamentals of Sustainable Drilling Engineering Equation (6.31) is oten used for a quantitative estimate of formation pore pressure gradient as well as for the qualitative detection of abnormal formation pressure. Numerous empirical correlations have been developed in addition to the equivalent matrix stress concept. Oten these correlations are presented in the form of graphical overlays constructed on a transparent plastic sheet that can be placed directly on dm plot to read the formation pressure. As recommended by Rehm and McClendon (1971), Figure 6.25 shows the depth vs. dm plot in a Cartesian coordinates for the normal pore pressure, and abnormal pressure trend line. he procedure for determining pore pressure from dm can be explained as follows: • • • •

Calculate dm over 10–30 t. intervals Plot dm vs depth (use only date from Clean shale sections) Determine the normal line for the dm vs. depth plot. Establish where dm deviates from the normal line to determine abnormal pressure zone

Rehm and McClendon recommend using linear scales for both depth and dm values when constructing a graph to establish formation pore pressure quantitatively (Figure 6.25). A straight-line normal pressure trend line having intercept with depth and slope is assumed such that:

dmn

dmo

(6.32)

mD

Here dmn = value of dm read from the normal pressure trend line at a depth of interest (Figure 6.26) dmo = intercept of the normal trend line m = slop of the normal trend line D = depth

Abnormal Pressure

Depth

Normal Pressure

Normal Compaction Trend Line

Transition Zone Overpressure Zone

dm Figure 6.25 Depth verses dm plotting in Cartesian coordinates.

Formation Pore and Fracture Pressure Estimation

283

No

Depth (ft)

d ren lT

a rm Normal

dm

dmn Abnormal

D dm

Figure 6.26 Depth verses dm plotting showing dmn on the trendline.

According to the authors, the value of slope m is fairly constant with changes in geologic age. he modiied “d-exponent” correlation oten is used for estimating the formation pressure gradient as well as the abnormal formation pressure. Rehm and McClendon suggested the following empirical equation to calculate the equivalent mud density as: e

7.56log dmn dm

16.5

(6.33)

Here, e is in lbm/gal he formation pressure gradient can be written as:

Gf

0.052

e

(6.34)

Here, G f is in psi/t. he formation pressure can be written as:

Pf

Gf D

(6.35)

Here, Pf is in psi Example 6.6: For the Malaysian area, determine the value of the dm if the drilling rate is 30 t./hr, the rotary RPM is 90, and the weight on the bit is 65,000 lbf. In addition, an equivalent circulating density at the bit was 9.5 lbm/gal. Assume necessary data. Solution: Given data: R = drilling rate = 30 t./hr N = rotary speed = 90 rpm W = weight on bit = 65,000 lb f = actual mud weight in use = 9.5 ppg e Additional assumption: db = bit diameter = 12.0 in Required data: dm = modiied d-exponent = ?

284 Fundamentals of Sustainable Drilling Engineering Before inding out the dm, it is necessary to ind out the d-exponent which can be calculated by using the Eq. (6.30) as:

log

R 60 N

log

12W 106 db

dexp

30 60 90 12 65,000 log 106 12.00 log

2.2553 1.9 1.1871

We know that for the Malaysian area, the normal formation pressure gradient is 0.442 psi/t. (Table 6.2). So, the mud density equivalent to normal pore pressure gradient ( n) can be calculated as: 0.442 0.052

n

8.5 ppg

herefore, the modiied d-exponent can be calculated using Eq. (6.31) as:

dm

n

dexp

1.9

e

8.5 9.5

1.7

iv) Zamora Model: It is noted that Rehm and McClendon mentioned to use linear scales for plotting depth vs. dm as shown in Figure 6.25. However, Zamora recommends using a linear scale for the depth but a logarithmic scale for dm values when constructing a graph to estimate formation pore pressure quantitatively (Figure 6.27). A straightline normal pressure trend line having intercept dmo and exponent m is assumed such that:

dmn

dmoe mD

(6.36)

Zamro reported that the slope of the normal pressure trend line varied only slightly and without apparent regard to location or geological age. He also introduced another empirical equation to calculate the formation pressure gradient.

Gf

Gn

dmn dm

(6.37)

0

lT d ren

Depth (ft)

a rm

No Normal

10,000

Abnormal 20,000 0.1

1.0

dm

Figure 6.27 Depth verses dm plotting in semi-logarithmic coordinates.

10

Formation Pore and Fracture Pressure Estimation Here Gn

285

= normal pressure gradient, lbm/gal

Example 6.7: Figure 6.28 shows the depth vs. d-exponent and modiied d-exponent plot. Estimate the formation pressure at 13,500 t. using Rehm and McClendon and the Zamora correlation. Assume that Figure 6.28 is constructed based on gulf of Mexico data. Solution: Given data: D = depth = 13,500 t. From Figure 6.28, we can ind out the dmn and dm at a depth of 13,500 t. as: dm = modiied d-exponent = 1.11 dmn = dm from the normal pressure trend line at a depth of interest = 1.66 Gn = normal pressure gradient = 0.465 lb /gal (Table 6.2) m

Required data: Pf = formation pressure = ? Rehm and McClendon Model: Before inding out the formation pressure, it is necessary to ind out the equivalent mud density based on Rehm and McClendon which can be calculated by using the Eq. (6.33) as:

16.5 7.56log 1.66 1.11

0

0

2000

2000 4000

4000 Normal Pressure Trend Line

6000 Depth (ft)

Depth (ft)

6000 8000 10.000

dmod= 1.15+0.0000380

8000 10.000 12,000

12,000 13.500 ft 1.11 14,000

2.0

0.1

Modiied d-Exponent (d-UNITS)

2.0

1.5

1.0

0.5

0

Modiied d-Exponent (d-UNITS)

16.5 14.53 ppg

0.4 0.6 0.8 1.0

7.56log dmn dm

0.2

e

1.66

13.500 ft 14,000 16,000

16,000 18,000 18,000

Figure 6.28 Depth verses dexp and dm plotting for Example 6.7.

1.11

1.66

286 Fundamentals of Sustainable Drilling Engineering he formation pressure gradient can be obtained using Eq. (6.34) as:

0.052

Gf

0.052 14.53 0.756 psi / ft

e

Finally, the formation pressure can be calculated using Eq. (6.35) as:

Pf

0.756 13,500 10,206 psi

Gf D

Zamora Model: he formation pressure gradient can be obtained directly using Eq. (6.37) as:

Gf

Gn

dmn dm

1.66 1.11

0.465

0.695 psi / ft

Finally, the formation pressure can be calculated again using Eq. (6.35) as:

Pf

Gf D

0.695 13,500

9,382.5 psi

v) Eaton Model: he d-exponent is generally used to simply identify the top of the overpressured zone. he value of the formation pressure can however be derived from the modiied d-exponent, using the method proposed by Eaton (1976) as:

Pf

ob

ob

Pf

D

D

D

D

dmc dmn

n

1.2

(6.38)

Here = overburden stress (i.e.

ob

Pf ob

Ppn), psi

= overburden stress gradient, psi/t.

D Pf dmc dmn

v

= formation pressure gradient, psi/t.

D

D

ob

= normal pressure gradient, psi/t. n

= calculated modiied d-exponent at a given depth = modiied d-exponent from normal trend (i.e. extrapolated) at a given depth (Figure 6.26)

Eaton claims the relationship is applicable worldwide and is accurate to 0.5 ppg. Example 6.8: What is the pore pressure at the point indicated on the Figure 6.29. Assume a Gulf Coast area where the depth is 10,000 t. Also assume that the overburden stress gradient is 0.95 psi/t. and normal formation pressure gradient is 0.465 psi/t. Use the Eaton Equation. Find out the EMW of the formation too. Solution: Given data: D = depth of the formation = 10,000t.

Depth (ft)

Formation Pore and Fracture Pressure Estimation

0.25

Robs

end al Tr

10,000'

Norm

Transition

dmc

Rn

0.5

287

1

dmn

2

3

Figure 6.29 Depth verses Robs and Rn plotting for Example 6.8.

= overburden stress gradient = 0.95 psi/t.

ob

D Pf D

= normal pressure gradient = 0.456 psi/t. n

Required data: = formation pore pressure at a depth of 10,000 t., psi Pf From Figure 6.29, we can ind out the Robs and Rn at a depth of 10,000 t. as: Robs = observed shale resistivity of the formation = 0.8 ohms-m Rn = resistivity of the formation at a normal trend = 1.55 ohms-m he Eaton model can be expressed in terms of resistivity of the formation which is analogous with d-exponent as:

Pf D

0.95

Pf

ob

ob

Pf

D

D

D

D

0.95 0.456

0.80 1.55

n 1.2

Robs Rn

1.2

0.726624 psi / ft

herefore,

Pf

0.726624 D 0.726624 10000

7266.24 psi

he equivalent mud weight (EMW) can be calculated as (Eq. 4.36a):

EMW

Pf 0.052 D

7266.24 0.052 10000

13.97 lbm / gal

288 Fundamentals of Sustainable Drilling Engineering 0

Depth (ft)

2000

Surface Casing

4000

2,500'

Mud weight gradient, 0.52 psi/ft

6000

Fracture gradient, 0.73 psi/ft

8000

14000

12000

10000

8000

6000

4000

2000

0

10000

Pressure, psi

Figure 6.30 Casing set and pressure gradient for Example 6.9.

Example 6.9: he mud engineer of an Arabian oil company designed the mud weight of 10 lbm/gal for a formation that needed to be drilled where the pressure gradient was found 0.52 psi/t. he surface casing was set at a depth of 2,500 t. It was noticed that the fracture gradient below the surface casing was 0.73 psi/t. he driller realized that he was passing a pressure transition zone while drilling at a depth of 10,000 t. his new situation gave the impression that the designed mud weight might be less than pore pressure which results a kick. To avoid a kick, determine the maximum safe underbalance between mud weight and pore pressure if the well kicks from formation at a depth of 10,000 t. Solution: Given data: D = total vertical depth = 10,000 t. = mud weight = 10 ppg m = normal pressure gradient = 0.52 psi/t. Gnp D = depth at which surface casing is set = 2,500 t. = fracture pressure gradient = 0.73 psi/t. Gfp Required data: EMWmax = maximum safe underbalance mud weight, ppg Figure 6.30 shows the casing seat and pressure gradient where an elaboration is explained for this example. In general, when a well kicks, the well is shut in and the wellbore pressure increases until the new BHP equals the new formation pressure. At that point, the influx of formation fluids into the wellbore ceases. Since the mud gradient in the wellbore has not changed, the pressure increases uniformly everywhere (Figure 6.31).

Formation Pore and Fracture Pressure Estimation

289

0

2000

Casing seat at 2,500'

525 psi

2,500'

1,825 psi

6000 8000

After kick and stabilization

1,300 psi

Depth (ft)

4000

Before kick 5,200 psi

5,725 psi

10000

Kick at 10,000'

14000

12000

10000

8000

6000

4000

2000

0

P, 525

Pressure, psi

Figure 6.31 wellbore pressures at diferent depth for Example 6.9.

At 2,500t. he initial mud pressure can be estimated as:

Pim

Gnp D

0.52 psi / ft

2,500 ft = 1,300 psi

he fracture pressure can also be estimated as:

Pfp

G fp D

0.73 psi / ft

2,500 ft = 1,825 psi

herefore, the maximum allowable increase in pressure = (1,825 – 1,300) = 525 psi At 10,000 t. Since the pressure increases uniformly everywhere as shown in Figure 6.31, the maximum allowable increase in pressure at a depth of 10,000 t. will be 525 psi. his increase in pressure corresponds to an increase in mud weight which can be calculated using Eq. (4.36a) as:

EMWmax

525 0.052 10000

1.01 lbm / gal

his increase in EMW is the maximum which is the kick tolerance for a small kick. vi) Combs Model: In 1968, Combs presented a general equation for penetration rate. He attempted to improve on the use of the drilling rate for pore pressure by correcting for hydraulics, diferential pressure, bit wear and in addition to W, db, and N. He assumed that the penetration rate is proportional to weight on bit, rotary speed, and bit hydraulics, each released to a ixed power as shown below:

290 Fundamentals of Sustainable Drilling Engineering

R Here f q R W aW aN aq dh dn Pd Rd tN f Pd f tN

Rd

W 3,500 dh

aW

N 200

aN

q 96 dh dn

aq

f Pd f t N

(6.39)

= function of = luid circulation rate, gpm = shale drillability or rate of penetration, t./hr = weight on bit, lbf = bit weight exponent (= 1.0 for ofshore Louisiana) = rotating speed exponent (= 0.6 for ofshore Louisiana) = low rate exponent (= 0.3 for ofshore Louisiana) = borehole diameter, in = diameter of one bit nozzle, in = diferential pressure, lbf/gal/1000t. = shale drillability at zero diferential pressure, t./hr = bit wear index (equivalent to rotating hours), = function related to diferential pressure = function related to bit wear

vii) Other Drilling Parameters: Torque is one of the other parameters that might be suitable to identify overpressured zones. An increase in torque may reduce overbalance which results in the physical breakdown of the borehole wall. his breakdown of the wall will generate more material, and then the drilled cuttings. hese excess materials will accumulate in the annulus and thus there is a change in torque. here are also the propositions that borehole walls may squeeze into the open hole as a result of the reduction in diferential pressure. Drag may also increase as a result of these efects, although increases in drag are more diicult to identify. 2. Drilling Mud Parameters: An overpressured zone on the mud can be identiied by monitoring the efect of diferent drilling mud parameters (Table 6.7). he main efects due to abnormal pressures will be i) increasing gas cutting of mud, ii) decrease in mud weight, and iii) increase in low-line temperature. Since all these efects can only be measured when the mud is returned to the surface they involve a time lag of several hours in the detection of the overpressured zone. As a result, during the time it takes to circulate bottoms up, the bit could have penetrated quite far into an overpressured zone. i) Gas Cutting of Mud: Gas cutting of mud may happen in two ways: i) from shale cutting – if gas is present in the shale which is being drilled the gas may be released in the annulus from the cuttings, ii) direct inlux – this can happen if the overbalance is reduced too much, or due to swabbing when pulling back the drillstring at connections. Continuous gas monitoring of the mud is done by the mudlogger using gas chromatography. A degasser is usually installed as part of the mud processing equipment so that entrained gas is not re-cycled downhole or allowed to build up in the mud pits. ii) Mud Weight: he mud weight measured at the lowline will be inluenced by an inlux of formation luids. he presence of gas is readily identiied due to the large

Formation Pore and Fracture Pressure Estimation

291

decrease in density, but a water inlux is more diicult to identify and isolate. Continuous measurement of mud weight may be done by using a radioactive densometer. iii) Flow-Line Temperature: he clays that are under compaction with relatively high luid content have higher temperature than other formations. By monitoring the lowline temperature, a slow increase in temperature will be observed when drilling through normally pressured zones. In this case, if there is an overpressured zone encountered, temperature will rise rapidly as drilling through the overpressured zone itself (Figure 6.32). herefore, lowline temperatures should be monitored carefully on a continuous basis. he normal geothermal gradient is about 1°F/100 t. and has been detected when drilling overpressured zones. It is also reported that changes in lowline temperature up to 10°F/100t. have been detected when drilling overpressured zones. When using this method we should keep in mind that other efects such as circulation rate, mud mixing, etc. may inluence the mud temperature too. iv) Pit Level and Total Pit Volume: Figure 5.12 shows the arrangement of a pit volume indicator where it indicates the increase in pit volume due to abnormal pressure. he functions are discussed in Section 5.3.1. he pit level indicators monitor variations in the total mud volume. It may show mud-volume reduction due to lost circulation. he pit level may also increase because of the luid entry into the wellbore as a result of unexpected high formation pressures. Ultrasonic equipment is used to measure accurately the levels of drilling luid in mud tanks. his method is useful on loating, deepwater ofshore drilling rigs. v) Mud Flow Rate: Pit level volume indicator takes some time to detect the abnormal pressure zone. herefore, low rate measurements are used to detect abnormality which is superior to pit level checks. his is due to the fact that even small low scan be detected before they become suiciently large to show on any pit level measuring device. herefore more time is available to take proper control measures. vi) Hole Fill-up: If the drillstring is pulled from the borehole, the mud volume needed to ill the same should be equal to the displaced pipe volume. It is very critical to keep the hole full at the time when drill collars are pulled because on pulling the same length of collars as that of the drillpipe, the level of drilling mud in the borehole will fall four to ive times faster than the drillpipe. In addition, if there is an unexpected luid entry (i.e. salt water, oil, or gas) from the formation into the wellbore, the mud volume required to ill the borehole will be less than the displaced volume of the pipe pulled out. hus, the irst indication of a pressure kick will be notiied.

Depth (ft)

0’

Normal Trend Top Overpressure

Flowline Temperature (°F)

Figure 6.32 Flowline temperature distributions with depth to detect overpressure.

292 Fundamentals of Sustainable Drilling Engineering 3. Drilling Cuttings: his detection method examines the cuttings, trying to identify cuttings from the sealing zone (Table 6.7). Since overpressured zones are associated with under-compacted shales with high luid content, these detection methods are aimed at determining the degree of compaction as measured from the cuttings. he methods commonly used are: a) density of shale cuttings, b) shale factor, and c) shale slurry resistivity (Table 6.7). he shape and size of the cuttings may give an indication (large cuttings due to low pressure diferential). As with the drilling mud parameters, these tests can only be done ater a lag time of some hours. i) Density of Shale Cuttings: In normally pressured formations the compaction and therefore the bulk density of shales should increase uniformly with depth (given constant lithology). If the bulk density decreases, this may indicate an undercompacted zone which may be an overpressured zone. he bulk density of shale cuttings can be determined by using a mud balance (Figure 3.6). A sample of shale cuttings must irst be washed and sieved to move caving. he cuttings are then placed in the cup of the mud balance so that the density indicated by the balance is equal to the density of water (i.e. 8.3 ppg) which is equivalent to a full cup of water. hus the mass of the shale cuttings in the balance is equal to the mass of a volume of water equal to the total cup volume of the balance. At this point, the following relation can be used:

Vs

bs

Here Vs Vt bs w

w

Vt

(6.40)

= volume of shale cutting, t.3 = total volume of cup, t.3 = bulk density of shale, lbm/t.3 = density of water, lbm/t.3

When enough shale cuttings is added to obtain a balance with the mud cup on and when the rider indicated the density of water, fresh water is added to ill the cup. he mixture is agitated to remove any air existence. he mud cup then is replaced and the average density ( m) of the cuttings/water mixture is determined. At this point Eq. (6.40) should be written as:

V

Vs

m t

bs

w

Substituting Vs from Eq. (6.40) into Eq. (6.41) and then solving for 2 w bs

2

w

(6.41)

Vt Vs bs

will give as:

(6.42) m

A number of such samples should be taken at each depth to check the density calculated as above and so improve the accuracy. he density at each depth can then be plotted as shown in Figure 6.33 to detect the overpressured zone. As we mentioned earlier, the bulk density of porous sediments depends on porosity, shale density is also a porosity dependent parameter, which is oten plotted against

Formation Pore and Fracture Pressure Estimation

293

Depth (ft)

0’

Normal Trend Top Overpressure

Bulk density

Figure 6.33 Bulk density variations with depth to detect overpressured zone.

depth to estimate formation pressure. A mathematical model of the normal compaction trend for the bulk density of shale cuttings can be developed by using Eq. (6.5) as: bsn

r

r

(6.43)

f

Now, substituting Eq. (6.7) into Eq. (6.43) for porosity variation will give: bsn

r

r

f

o

e

K Ds

(6.44)

Here bsn

= shale density for normally pressured shales

he grain density of pure shale is 2.65 g/cm3. he average pore luid density can be obtained from Table 6.2. Constants o , and K can be based on shale-cutting bulk density measurements made in the normally pressured formations. ii) Shale Formation Factor: his technique measures the reactive clay content in the cuttings. It uses the “methylene blue” dye test to determine the reactive montmorillonite clay present, and thus indicate the degree of compaction. he higher the montmorillonite, the lighter the density, which indicates under compacted shale. Montmorillonite will absorb methylene blue and change its color. Shale factor method may be compared with the cation exchange capacity of solids carried by the drilling luid out of the wellbore. It can be related to the water-holding capacity of drill cuttings or montmorillonite content. he shale factor also appears to be a supplementary and useful indicator to detect the cap rocks on top of the overpressured zones. iii) Shale Slurry Resistivity: As compaction increases with depth, water is expelled and so conductivity is reduced. A plot of resistivity against depth should show a uniform increase in resistivity, unless an undercompacted zone occurs where the resistivity will reduce (Figure 6.34). To measure the resistivity of shale cuttings a known quantity of dried shale is mixed with a known volume of distilled water. he resistivity can then be measured and plotted. iv) Shape and Size of Shale Cuttings: he shape of drill cuttings is round in the normal hydrostatic pressure environments. On the other hand, the shape is angular and

294 Fundamentals of Sustainable Drilling Engineering

Depth (ft)

0’

Normal Trend Top Overpressure

Resistivity

Figure 6.34 Resistivity variations with depth to detect overpressured zone.

sharp while encountering the pressure transition zones. Moreover, cuttings from highpressure formations are unusually large and splintery in appearance. v) Volume of Shale Cuttings: While drilling, entry into an overpressured zone is characterized by an increase in the penetration rate. his gives rise to an increase in volume of cuttings over the shale shaker.

6.2.5.3

Conirmation Techniques

he conformation techniques for formation luid pressure estimation are applied ater drilling. Table 6.8 shows diferent parameters that are applied ater drilling to conirm the abnormal pressure existence in the formation. Once the hole has been successfully drilled certain electric wireline logs and pressure survey may be run to conirm the presence of overpressures. he logs that are partially sensitive to under compaction are: a) sonic log, b) density log, and c) neutron logs. However, there are some other logs such as resistivity log, and conductivity log are used in this regard.

6.2.6 Fracture Pressure In the planning of the mud program, it is useful to know the maximum mud weight which can be used at any particular depth. his maximum weight is deined by the fracture gradient which can be deined as the minimum total in situ stress divided by the depth. he mud weight used in the well must lie between the formation pressure gradient and the fracture gradient. Knowledge of the fracture gradient is vital when drilling through an overpressured zone. he fracture pressure can be deined as the pressure required inducing fractures in rock at a given depth. It is the pressure above which injection of luids will cause the rock formation to fracture hydraulically. he factor used to determine formation fracturing pressure as a function of well depth is in units of psi/t. he orientation of the produced fracture depends on the orientation of the principal stress of the fracture point. At any point in the formation there exists a stress regime consisting of three perpendicular stresses as shown in Figure 6.35. If we consider that 1 as maximum, 2 as intermediate, and 3 as minimum, the fracture will be developed perpendicular to the minimum stress (Figure 6.36). To initiate a fracture in the wall of the borehole, the pressure in the borehole must be greater than the least principal stress in the formation. To propagate the fracture, the pressure must be

Formation Pore and Fracture Pressure Estimation

295

Table 6.8 Methods for detecting abnormal pressures by conirmation techniques (Ford, 1999). Source of Data

Parameters

Time of Recording

Electrical survey

Ater drilling

Resistivity Conductivity Shale formation factor Salinity variations Well Logging

Interval transit time, bulk density, hydrogen index hermal neutron cam capture cross section Nuclear Magnetic Resonance Downhole gravity data Pressure bombs

Direct Pressure Measuring Devices

When well is tested or completed

Drillstem test Wire line formation test

2

1

3

Figure 6.35 Stress regime distributions in three plan of a block. 1

3

2

Figure 6.36 Fracture development perpendiculars to the minimum stress.

296 Fundamentals of Sustainable Drilling Engineering maintained at a level greater than the least principal stress. Formation fracture gradient study is important because it – i) helps in selecting the casing seats, ii) helps to prevent the lost circulation, iii) helps in planning the hydraulic fracturing, and iv) helps in selecting the production/injection areas. he Factors that afect fracture gradient are: i) type of rock, ii) degree of anisotropy, iii) formation pore pressure, iv) magnitude of overburden, and v) degree of tectonics action in the area.

6.2.7 Methods for Estimating Fracture Pressure here are two methods that are available for determining fracture pressure gradient. hese include i) direct method, and ii) indirect method. he direct method depends on the determination of the pressure required for fracturing the rock and the pressure required to propagate the resulting fracture. he indirect method is based on theoretical background and uses stress analysis to predict fracture gradient.

6.2.7.1

Direct Method

Direct method is a technique where mud is used to pressurize the well until the formation fractures. he value of the surface pressure at fracture is noted and is added to the hydrostatic pressure of mud inside the hole to determine the total pressure required to fracture the formation. his pressure is commonly called formation breakdown pressure. Formation breakdown pressure is determined by a pressure test that is called the leak-of test (Figure 6.37). It represents an experimental approach to determine the fracture gradient. Ater each casing string is cemented in place, the leak-of test (LOT) or pressure integrity testing (PIT) is used to verify the casing, cement, and formations below the casing seat. It also tests how these parameters can withstand the wellbore pressure required to drill safely to the next depth at which casing will be set. he major functions of LOT are i) estimate the formation fracture gradient just below the casing seat, and ii) check cement bond. hese tests are normally performed at the start of each new hole section, just ater drilling out of a casing shoe of the previous hole section. his means that the test can be made in the open hole section below the surface or intermediate casing. he general procedure is as follows: i) drill out cement and casing shoe to approximately 10 t. into formation (i.e. 5 – 10 t. below the casing shoe), ii) close the BOP at the surface, iii) circulate to clean hole and stabilize drilling-luid density, iv) close well and pump in drilling luid (approximately 0.25 to 1 bbl/min), and v) monitor surface pressure. Figure 6.38 shows leak-of test results taken ater drilling the irst sand below the casing seat. During the test, there is a constant pressure increase for each incremental drilling luid volume pumped. So the early test results fall on a relatively straight line. he straight line trend continues until point A, where the formation grains start to move apart and the formation begins to take a whole mud. he pressure at point A is called the leak-of pressure and is used to compute the formation fracture gradient. Pumping is continued during the leak-of test long enough to ensure that fracture pressure has been reached. At point B, the pump is stopped, and the well let shut in order to observe the rate of pressure decline. he rate of pressure decline is indicative of the rate at which mud or mud iltrate is being lost.

Surface Pressure

Formation Pore and Fracture Pressure Estimation

Leak-of pressure A

297

Formation breakdown pressure

B

Propagation pressure C

D E

Shut-in pressure 0

0

Time Increment of mud pumped in

Figure 6.37 Leak-of test.

Pump stopped

3000 Pressure (psi)

B A

SPfrac 2000

1000

0

2 4 6 Volume pumped (bbl)

2

4 6 Time (min)

Figure 6.38 Leak-of test results taken ater drilling the irst sand below the casing seat.

he predicted surface leak-of pressure is based on the formation fracture pressure predicted by one of the empirical correlations presented in the next section. he predicted surface leak-of pressure is given by:

Plo

Pfp 0.052

m

D

Pf

(6.45)

Here Plo Pfp

= surface leak-of pressure, psi = observed fracture pressure, psi = mud density, lbm/t.3 m D = total depth, t. Pf = friction pressure loss, psi

Frictional pressure loss can be calculated using the gel strength as:

Pf

g

D

300 d

Here g

D d

= gel strength, lbm/100t.2 = total depth, t. = inner diameter of the drill pipe, in

(6.46)

298 Fundamentals of Sustainable Drilling Engineering

6.2.7.2

Indirect Methods

Estimations of formation fracture pressures and gradients are based on theoretical and empirical correlations. In literature, a number of theoretical and ield-developed correlations are reported to approximate fracture gradients. hese correlations are established using stress analysis for predicting the fracture gradient. Many of these correlations are suitable for immediate application in a particular geologic area. However, it is an observation approach based on density (or other) logging measurements taken ater the well been drilled. In general, the fracture gradient is a function of pore pressure, pore pressure gradient, overburden gradient, and stress rate. Calculation procedures for these areas rely on either a history of the ield or geological structure, or on ield determinations utilizing leak-of tests or logging methods. he following equations and correlations are commonly used to determine the fracture pressure theoretically. i) Hubbert and Willis Model: In 1957, they proposed a method for calculating fracture gradients based on the fact that fracturing occurs when the applied luid pressure exceeds the sum of minimum efective stress and formation pressure. he efective stress is deined as the diference between the total stress and pore pressure. he fracture plane is assumed to be perpendicular to the minimum principle stress. he below equation is used to determine the fracture pressure.

Pfp

Pf

min

(6.47)

Here Pfp = observed fracture pressure at the point of interest, psi min = minimum efective stress at the point of interest, psi Pf = formation pore pressure at the point of interest, psi he failure of the material of porous media is controlled by the magnitude of the efective stress only and not the total stress. In this method, the fracture pressure is controlled by overburden stress gradient, formation pore pressure gradient and Poisson’s ratio of rocks. Hubbert and Willis method was found not applicable in sot rocks. In calculating the fracture gradient, Hubbert and Willis explored the variables involved in initiating a fracture in formation. According to them, the fracture gradient is a function of overburden stress, formation pressure, and a relationship between the horizontal and vertical stresses. hey believed this stress relationship to be in the range of 1/3 to 1/2 of the total overburden. herefore the fracture gradient determination would be as follows:

G fr _ min

1 3

G fr _ max

1 2

min

D

2 Pf D

min

Pf

D

D

Here G fr

Pfp D

= fracture pressure gradient at the point of interest, psi/t.

(6.48a)

(6.48b)

Formation Pore and Fracture Pressure Estimation min

D Gp D

299

= minimum efective stress gradient at the point of interest, psi/t. Pf = = formation pore pressure gradient at the point of interest, psi/t. D = depth, t.

If an overburden stress gradient or minimum efective stress gradient is assumed to be 1 psi/t., Eq. (6.48) becomes as:

G fr _ min

2 Pf 1 1 D 3 Pf

1 1 2

G fr _ max

(6.49a)

(6.49b)

D

he above procedures can be done in a graphical form for a quick solution. Let’s assume a mud weight (example – 12.0 lb/gal) value required to balance the formation and enter it to the ordinate (Figure 6.39). Applying this value draws a horizontal line along the pressure gradient up to the limit of the intersection of formation pressure gradient line and constructs a vertical line from this point to the minimum and maximum fracture gradients. Read the fracture mud weight from the ordinate. It is shown that the fracture mud weight for a 12.0-lb/gal equivalent formation pressure could range from 14.4 to 15. In Eqs. (6.48 – 6.49), Hubbert and Willis assumed that the stress relationships and the overburden gradients were constant for all depths. Since this has been proven untrue in most 19 Minimum and maximum fracture and mud weight, lb/gal

um

g fp

t

0.7

M in im Por um ep fp res g0 sur eg .73 rad ps ien i/ t

Pore and Fracture Pressure, lb/gal

17

i/f

s 3p

ft

18

im

M

16 15 14 13

ax

12 11

Pore pressure

10 9 0.4

0.5

0.6 0.7 0.8 0.9 Pressure Gradient, psi/ft

1.0

Figure 6.39 Graphical determination of fracture gradients as proposed by Hubbert and Willis.

300 Fundamentals of Sustainable Drilling Engineering cases, subsequent methods have attempted to account for one or both of these variables more accurately. ii) Matthews and Kelly Model: Matthews and Kelly (1967) published a fracture gradient relationship which difers from the Hubbert and Willis model. hey noticed based on drilling experience that the formation fracture gradients increase with depth, even in normally pressured formations. herefore, the following correlation was introduced. min

Here F z ob

F

z

(6.50)

= variable matrix stress coeicient for the depth at which the value of be normal matrix stress, dimensionless = matrix stress = ob Pf , psi = overburden pressure, psi

z

would

Substituting the Eq. (6.50) into Eq. (6.47), fracture pressure can be obtained as:

Pfp

F

z

Pf

(6.51)

In Eq. (6.51), the variable matrix stress coeicient is a monotonic function of depth to represent formation properties. his coeicient relates the actual matrix stress conditions of the formation to the conditions of matrix stress if the formation were compacted normally. For simplicity, the authors assumed an overburden pressure gradient equal to 1.0 psi/t. and a pore pressure gradient equal to 0.465 psi/t. In their work, the authors concluded that the fracture pressure was higher than pore pressure due to rock matrix cohesive force, which can be interpreted as rock stress that changes with the compaction degree. he cohesiveness of the rock matrix is usually related to the matrix stress. It varies only with the degree of compaction. Example 6.10: Calculate the minimum and maximum equivalent mud weights in ppg that can be used immediately below the casing seat at a depth of 12,000 for the pore pressure gradient of 0.58 psi/t. and an overburden gradient of 0.95 psi/t. It is assumed that matrix stress coeicient is 0.712. Use the Mathews and Kelly method. Solution: Given data: D = total vertical depth = 12,000 t. = mud weight = 10 ppg m = pore pressure gradient = 0.58psi/t. Gp = overburden gradient = 0.95 psi/t. Go F = variable matrix stress coeicient = 0.712 Required data: EMWmin = maximum equivalent mud weight, ppg EMWmax = maximum equivalent mud weight, ppg he overburden pressure at a depth of 12,000 t. = 0.95 12,000 = 11,400 psi

Formation Pore and Fracture Pressure Estimation

301

he pore pressure at a depth of 12,000 t. = 0.58 12,000 = 6,960 psi Using Mathews and Kelly method, the minimum stress can be calculated by Eq. (6.50) as: min

F

z

0.712

11400 6960

4, 440 psi

he fracture pressure can be obtained using Eq. (6.51) as:

Pfp

4440 6960 11, 400 psi

herefore, maximum equivalent mud weight which can be calculated using Eq. (4.36a) as:

EMWmax

11400 0.052 12000

18.27 lbm / gal

And the minimum equivalent mud weight can be calculated as:

EMWmin

6960 0.052 12000

11.15 lbm / gal

Equation (6.51) can be expressed in terms of fracture gradient. Matthews and Kelly developed the following equation for calculating fracture gradients in the sedimentary formations as:

G fr

F z D

Pf D

(6.52)

hey believed that the conditions necessary for fracturing the formation would be similar to those for the normally compacted formation. hey also believed that the coeicient would vary with diferent geological conditions. F can be obtained by substituting actual ield data of breakdown pressures into the above equation and solving the same for F . Matthews and Kelly have developed the variation of stress coeicient with depth for south Texas gulf coast and Louisiana gulf coast (Figure 6.40). he igure shows a nonlinear trend for the stress coeicient vs. depth correlation. he procedure for calculating fracture gradients using the Matthews and Kelly technique can be summarized as follows: 1. Obtain formation luid pressure (Pf ). his can be measured by drill stem tests, kick data, logs, or another satisfactory method. Pf for the depth, D 2. Obtain the matrix stress ( z) by using z ob and assuming a gradient of 1.0 psi/t. for the overburden. 3. Determine the depth, Di , for which the matrix stress, z, would be the normal value. Assume that the overburden pressure gradient is 1.0 psi/t. and 0.465 psi/t. as pore pressure gradient, i.e. 0.535 Di z . From the relationship, the value of Di can be found. 4. Use the value of Di , apply it to Figure 6.40 to obtain the corresponding value of F . 5. Finally calculate the formation fracture gradient (G f ) by using Eq. (6.52).

302 Fundamentals of Sustainable Drilling Engineering 0

Matrix stress coeicient Versus D1 for South Texas Gulf Coast and Louisiana Gulf Coast

2 4

South Texas Gulf Coast

Depth × 1,000 ft

6 8 Louisiana Gulf Coast

10 12 14 16 18 20 0.3

0.4

0.5

0.6

0.7

0.8

0.9

1.0

F

Figure 6.40 variations of matrix stress coeicients with depth for Matthews and Kelly model.

Example 6.11: A well of 12,500 t. was drilled at Louisiana Gulf Coast area where the pore pressure gradient was found 0.695 psi/t. Calculate the fracture gradient in units of psi/t. and lbm/gal using Matthews and Kelly model. Solution: Given data: D = total vertical depth = 12,500 t. Pf Gp = = pore pressure gradient = 0.695 psi/t. D Required data: Pfp = fracture pressure gradient in psi/t. Gfr = D Pfp = fracture pressure gradient in ppg Gfr = D In this case Pf and D are known i.e. pore pressure gradient is known. he matrix stress, Pf where overburden gradient is considered as z may be calculated using z ob 1 psi/t. Finally F is determined graphically using Figure 6.40. We will use the above procedure to calculate the fracture gradient. 1. First, determine the pore pressure gradient. Pf

Gp =

D

= 0.695 psi/t.

Formation Pore and Fracture Pressure Estimation 2. Next, calculate the matrix stress. z

ob

D Pf

1 0.695

D

12500 0.305 12500 3,812.5 psi

3. Now determine the depth, Di under normally pressured conditions. In this case, the rock matrix stress z would be 3,812.5 psi and normal pore pressure gradient is 0.46 psi/t. obn

Di

Pfn Di

1.0 0.46

Di

3,812.5

zn

Di

7,060.19 ft

4. Using Di 7060 ft, Matthews and Kelly plot (Figure 6.40) is applied to construct Figure 6.41 and obtained the corresponding value of Fz 0.65. 5. Finally to calculate the formation fracture gradient (G f ), Eq. (6.52) is applied. F

G fr

z

D

Pf D

0.65

3,812.5 0.695 0.893 psi / ft 12,500

In terms of ppg, the formation fracture gradient is

0 Matrix stress coeicient Versus D1 for South Texas Gulf Coast and Louisiana Gulf Coast

2 4

South Texas Gulf Coast

Depth × 1,000 ft

6 8 Louisiana Gulf Coast

10 12 14 16 18 20 0.3

0.4

0.5

0.6

0.7

0.8

0.9

1.0

F

Figure 6.41 matrix stress coeicients for Example 6.11 using Matthews and Kelly model.

303

304 Fundamentals of Sustainable Drilling Engineering 0.893 psi / ft 0.052

G fr

17.18 ppg

iii) Pennebaker Model: he Pennebaker (1968) correlation is similar to the Mathews and Kelly method as shown by Eq. (6.50). He correlated the stress rate coeicient with depth regardless of the pore pressure gradient. Pennebaker did not assume a constant overburden pressure gradient. Instead he used a variable overburden pressure gradient taking into account the depth and formation type. iv) Eaton Model: In 1969, Ben Eaton modified the Hubbert and Willis method. He assumed that both overburden stress and Poisson’s ratio are assumed to be variables with depth. Eaton also assumed an elastic rock behavior and a lateral strain that could be related to the vertical stress ratio as a function of Poisson’s ratio. The horizontal and vertical stress ratio and the matrix stress coefficient are dependent on the Poisson’s ratio of the formation. Mathematically the model can be written as:

x

y

h

1

(6.53)

z

Here x y

= matrix stress in x-direction, psi = matrix stress in y-direction, psi = Poisson’s ratio

Equation (6.53) is analogous with Eq. (6.51). Substituting the analogy, the fracture pressure can be obtained as:

Pfp

1

Pf

ob

z

=

Pf

ob

Pf and applying

(6.54)

he fracture gradient for any depth of interest can be written as:

G fr

Pf

ob

1

D

Pf D

(6.55)

Eaton prepared several graphs and monographs both for overburden stress and Poisson’s ratio variables by utilizing actual ield fracture data and log-derived values (Figure 6.42 – 6.45). Using a suitable choice for each variable, the monograph can be used to calculate a fracture gradient (Figure 6.42). A graphical presentation for the Eaton approach provides a quick solution. he graphs and monographs are used in the same manner as the Matthews and Kelly graph shown in Figure 6.41. v) Christmen Model: Christmen (1973) proposed a method to predict fracture gradient for ofshore ield application. he determination of fracture gradient procedures assumes that overburden stress consists of rock matrix stress and formation luid stress. he Christmen model is a modiied version of Eaton method. In shallow water, the reduction in fracture gradient is almost insigniicant because as water depth increases, fracture gradient declines. he efective stress ratio has been correlated to the bulk density of the sediments. Christmen concluded that the bulk density of the sediments tends

Formation Pore and Fracture Pressure Estimation

305

DEPTH, ft

Variable Overburden Stress by Eaton 0 2000 4000 6000 8000 10,000 12,000 14,000 16,000 18,000 20,000 0.70

0.75

0.80

0.85

0.90

0.95

1.00

1.05

Overburden Stress Gradient, psi/ft

Figure 6.42 Variation of overburden stress with depth as proposed by Eaton.

0 2 Extreme upper limit

Depth × 1,000 ft

Overburden 4 equals 1.0 psi/ft 6 shale 8 10 12 14 16

Gulf Coast variable overburden

West Texas overburden equals 1.0 psi/ft producing formations

18 20

0

0.1 0.2 0.3 0.4 0.5 0.6 Poisson’s ratio

Figure 6.43 Variation of Poisson’s ratio with depth as proposed by Eaton.

to increase with increases in depth, overburden stress, and geological age. he water has no rock matrix for ofshore area. Since rock is denser than water, the fracture gradient at a given depth is lower for an ofshore well than for onshore well at the same depth. he efect of the water depth in calculating the overburden gradient can be shown by the model proposed by Christmen which is shown below:

Gob

1 D

w

Dw

Here Gob = overburden gradient, psi/t. = density of seawater, lbm / ft 3 w = average bulk density, lbm / ft 3 b

b

Dml

(6.56)

306 Fundamentals of Sustainable Drilling Engineering PD

1.00

0.90

0.8

0.85 0.80

0.7

0.5 0.4

Example: Determine fracture gradient at 12,000’ with formation pressure of 0.67 psi/ft at 12,000’. Overburden load is 0.96 and Poisson’s Ratio is 0.46 from monograph fracture gradient is 0.91 psi/ft or 17.5 ppg.

19.0 18.0 17.0 16.0 15.0 14.0 13.0 12.0 11.0 10.0

0.75

1.0 0.9 0.8 0.7 0.6

Fracture Gradient (psi/ft)

0 0.5 5 0.4 0 4 . 0 5 0.3 0 . 03

0.6

PWD Fracture Gradient (lb/gal)

0.8

Formation Pressure (psi/ft)

0.9

0.9

o Rati son Pois

Overburden (psi/ft)

1.0

PD

0.5

0.70 0.65 0.60

Formation Pressure (psi/ft)

0.95 SC

0.55 0.50 0.45 0.40

Figure 6.44 Monograph determinations of fracture gradients as proposed by Eaton.

Dw = seawater depth, t. Dml = depth below mud line, t. If we assume the seawater density of 1.02 g/cc, Eq. (6.56) becomes:

Pfp D

1 0.44 Dw D

b

Dml

(6.57)

vi) Anderson et al., Model: Anderson et al. (1973) developed a model based on Biot’s stress/strain relationships for elastic porous media. All the previous eforts were based on the assumed that the formation properties coeicient is a function of depth. However, the proposed model was not based on this assumption. he authors derived an expression for the fracture pressure gradient that is a function of well depth, overburden pressure, pore pressure, Poisson’s ratio, and the ratio of the compressibility of the porous rock matrix to the intrinsic compressibility of rock (α). he model can be written in form as:

Pfp Here Pob

cr cb

Pf

2 1

Pob

Pf

(6.58)

= overburden pressure, psi = ratio of the compressibility of the porous rock matrix to the intrinsic comc pressibility of rock = 1 r cb = compressibility of the porous rock matrix, 1/psi = bulk compressibility of the rock matrix, 1/psi

Formation Pore and Fracture Pressure Estimation

307

0 1,000 9 10 11 12 13 14 15

1,000 3,000 4,000 5,000 6,000

16 17 18 19

7,000

Depth (ft)

8,000 9,000 10,000 11,000 12,000 13,000 14,000 15,000 16,000 17,000 18,000 19,000 20,000 9

10 11 12 13 14 15 16 17 18 19 20 Fracture Gradient (Ib/gal)

Figure 6.45 Graphical determinations of fracture gradients with depth using the Eaton approach.

Anderson et al. (1973) used ield data to evaluate empirically some of the parameters involved in terms of quantities available from the well log. hey concluded that, the ratio of the compressibility of the porous rock matrix to the intrinsic compressibility of the rock is found to be empirically related to formation porosity. Poisson’s ratio, according to the derived relationship is found to be empirically related to the shaliness of the sand as estimated by the use of sonic and density logs. hen, the fracture pressure, which is dependent upon Poisson’s ratio (i.e., by shaliness) as well as by porosity, is assumed to have a uniform behavior with depth. vii) Belloti and Giacca Model: Another formula that was used to calculate fracture pressure gradient was based on the Terzaghi equation and presented by Belloti and Giacca (1978). his technique classiied the formations according to their elasticity and other properties such as permeability, shaliness, etc. he following equations can be used to calculate the fracture pressure gradient.

G fr

Gp

2 1

Gob G p

(6.59)

308 Fundamentals of Sustainable Drilling Engineering Here G fr = fracture gradient, psi/t. Gob = overburden gradient, psi/t. G p = pore pressure gradient, psi/t. Equation (6.59) is used when the pressure is totally employed at the well bore, as in case of iltration controlled by wall-building luids. For the case of free formation invasion by drilling luids where the pressure distribution creates a gradient inside the rock, the following equation is can be used:

G fr

Gp 2

Gob G p

(6.60)

he authors used a constant value of ( ) according to rock lithology. Example 6.12: A well of 14,750 t. was drilled at South Texas Gulf Coast area where the pore pressure gradient was found at 0.74 psi/t. Calculate the fracture gradient in units of psi/t and lbm/gal using the Hubbert and Willis model, Matthews and Kelly model, Eaton model, and the Belloti and Giacca model. Summarize the results in tabular form, showing answers, in units of lb/gal and also in psi/t. Solution: Given data: D = total vertical depth = 14,750 t. Pf Gp = = pore pressure gradient = 0.74 psi/t. D Required data: Pfp = fracture pressure gradient in psi/t. Gfr = D Pfp Gfr = = fracture pressure gradient in ppg D Hubbert and Willis model:

G fr _ min

2 Pf 1 1 D 3

G fr _ max

1 1 2

1 1 2 0.74 3 Pf D

1 1 0.74 2

0.827 psi / ft 0.87 psi / ft

In terms of ppg, the formation fracture gradient is

G fr _ min

0.827 psi / ft psi / ft 0.052 lbm / gal

15.90 ppg and

Formation Pore and Fracture Pressure Estimation

0.87 psi / ft psi / ft 0.052 lbm / gal

G fr _ max

309

16.73 ppg

Matthews and Kelly model: 1. First, determine the pore pressure gradient. Pf

Gp =

= 0.74 psi/t.

D

2. Next, calculate the matrix stress. z

ob

D Pf

1 0.74

D

14,750 0.26 14,750 3,835.0 psi

3. Now determine the depth, Di under normally pressured conditions. In this case, the rock matrix stress z would be 3,812.5 psi and normal pore pressure gradient is 0.46 psi/t. obn

Di

Pfn Di

1.0 0.46

Di

3,835.0

zn

Di

7,101.85 ft

4. Using Di 7101.85 ft , Matthews and Kelly plot (Figure 6.40) is applied to construct Figure 6.46 and obtained the corresponding value of Fz 0.74. 5. Finally to calculate the formation fracture gradient (G f ), Eq. (6.52) is applied. G fr

F

Pf

z

D

D

0.74

3,835.0 0.74 14,750

0.9324 psi / ft

In terms of ppg, the formation fracture gradient is

G fr

0.9324 psi / ft 0.052

17.93 ppg

Eaton model: Equation (6.55) shows that the overburden stress gradient and Poisson’s ratio should be found out irst from the graphs in Figure 6.42 and Figure 6.43 as proposed by Eaton. Figure 6.47 and Figure 6.48 show the overburden stress gradient and Poisson’s ratio respectively as: ob

D

0.98 psi / ft and

0.48

Now applying Eq. (6.55), the fracture gradient can be calculated as:

G fr

0.48 0.98 0.74 1 – 0.48

0.74

0.962

psi ft

310 Fundamentals of Sustainable Drilling Engineering In terms of ppg, the formation fracture gradient is:

G fr

0.962 psi / ft 0.052

18.49 ppg

Belloti and Giacca model: Applying Eq. (6.60), the fracture gradient can be calculated as:

G fr

Gp 2

0.74 2 0.48 0.98 0.74

Gob G p

0.9704 psi / ft

In terms of ppg, the formation fracture gradient is:

G fr

0.9704 psi / ft 0.052

18.662 ppg

he summaries of the fracture gradients by diferent models are shown in Table 6.9. In the above example, it is noted that all the methods applied here take into consideration the pore pressure gradient. As the pore pressure increases, the fracture gradient

0 Matrix stress coeicient Versus D1 for South Texas Gulf Coast and Louisiana Gulf Coast

2 4

South Texas Gulf Coast

Depth × 1,000 ft

6 8 Louisiana Gulf Coast

10 12 14 16 18 20 0.3

0.4

0.5

0.6

0.7

0.8

0.9

1.0

F

Figure 6.46 matrix stress coeicients for Example 6.12 using Matthews and Kelly model.

Formation Pore and Fracture Pressure Estimation

311

DEPTH, ft

Variable Overburden Stress by Eaton 0 2000 4000 6000 8000 10,000 12,000 14,000 16,000 18,000 20,000 0.70

0.75

0.80

0.85

0.90

0.95

1.00

1.05

Overburden Stress Gradient, psi/ft

Figure 6.47 Variation of overburden stresses with depth for Example 6.12.

0 2 4

Extreme upper limit

Depth × 1,000 ft

Overburden equals 1.0 psi/ft shale

6 8 10 12 14

Gulf Coast variable overburden

West Texas overburden equals 1.0 psi/ft producing formations

16 18 20 0

0.1 0.2 0.3 0.4 0.5 0.6 Poisson’s ratio

Figure 6.48 Variation of Poisson’s ratio with depth for Example 6.12.

also increases. While calculating the fracture gradient by Hubbert and Willis, it is apparently considered only the variation in pore pressure gradient. On the other hand, Matthews and Kelly consider the changes in rock matrix stress coeicient, and in the matrix stress along with pore pressure. Ben Eaton considers variation in pore pressure gradient, overburden stress and Poisson’s ratio to calculate the fracture gradient. Belloti and Giacca also consider similar parameters. he last two methods are probably the most accurate of the four methods. If we know Poisson’s ratio, the last two methods are actually quite similar, and usually yield similar results.

312 Fundamentals of Sustainable Drilling Engineering

6.3 Current Development on Formation Pore and Fracture Pressure Daines (1980) proposed a technique for predicting fracture pressure for wildcat wells; he described a theoretical model in order to demonstrate the principle stress system within a basin of simple topography and structure. In this model, if a well is drilled nearly vertically, then it should be approximately parallel to one of the principle stresses, which is equal to the efective weight of the overlying strata. he horizontal stresses are a combination of the stresses caused by gravity and a superposed horizontal stress. he latter may be nonexistent or may reach a maximum of two or three times the vertical stress. he minimum horizontal stress is measured by the irst fracture test in compact formation. As the vertical stress increases approximately linearly with depth, then the tectonic horizontal stress will increase linearly with depth and is also deined by a constant stress ratio G fr G p / Gob G p . Since this ratio is obtained from the irst fracture test, then at any subsequent depths the fracture pressures may be calculated providing pore pressures, overburden pressures and formation lithology as an indicate for Poisson’s ratio. Breckels and Eekelen (1982) proposed correlations for fracture gradient and depth. hey plotted hydraulic fracturing and leak-of test data versus depth and drew lower bound curves, which were assumed as representing the minimum horizontal stress for particular areas. hen a relationship between minimum horizontal stress and depth was derived to estimate fracture pressures. Another attempt to study the relationship between formation properties coeicients and depth was made by Brennan and Annis (1984). heir work is based on shallow soil boring density and density log to estimate overburden pressure gradient. A correlation between horizontal to vertical efective stress ratio and depth had been developed. But soon it was concluded that this procedure generated very poor correlations, which can be attributed to variation in the depth of the top of the abnormal pore pressure zone and the rate of change of the pore pressure. To minimize these factors, efective horizontal stress gradient versus efective vertical stress gradient (Gob G p ) was plotted. By this plot, the depth problem was eliminated and pore pressure efects minimized. he relationship described by the empirical correlation deined efective horizontal stress gradient as a function of efective vertical stress gradient. An equation is obtained from the above relationship, which is then solved for pressure gradient. So, given the overburden pressure gradient and pore pressure gradient, a direct solution can be made for the fracture pressure gradient. Constant and Bourgoyne (1988) used the data published by Eaton to introduce the stress ratio, which was obtained by itting an exponential function using the data. Aadnoy and Soteland (1989) stated that at a shallow depth, the rocks are not fully compacted or consolidated. herefore, lithology may not play the same role as for deeper depths. he authors gave a good analysis of the factors that afect leak-of tests. hese factors include the absence of exact measurement, lithology, faults, intact versus non-intact boreholes, and mud properties. Lesage et al., (1991) elucidated that the horizontal stresses are signiicantly larger than the pore pressure, so a suitable safe range of mud weight usually can be found;

Formation Pore and Fracture Pressure Estimation

313

even throught potential shear failure of the wellbore provides other constraints on mud weight, especially in highly deviated wells. Clearly, abnormally high pore pressure or weak formations present potential problems for drillers. Abnormally high or low earth stresses also can lead to unexpected diiculties. Rocha et al., (1994) proposed a method to estimate fracture pressure gradient using only the leak-of test data and being independent of the pore pressure. he method is based on a new concept called “pseudo overburden pressure”, which is deined as the overburden pressure a formation would exhibit if it was plastic. In this method it was assumed that fracture pressure is a strong function of depth. hese can be seen by the relationship, which was introduced by plotting leak-of test data collected from diferent areas with depth. hen high correlation coeicients were obtained, which indicate that depth is one of the most important factors afecting fracture pressure. As a conclusion of their work, the authors stated that for the case of plastic formations such as shales the value of the stress ratio should be very close to 1.0 implying that fracture pressure would be a function only of the overburden pressure. In other word, in the presented method overburden pressure function is chosen and correlated directly to fracture pressure data represented by leak-of test data. Yasser (1995) used the concept that, in normal fault regime basins, fracture propagation pressure which was calculated accurately from porosity, vertical stress, and pore pressure, is not based on rock mechanics laws but on the relationship given below H

1

v

(6.61)

Here H

= horizontal efective stress, psi = porosity, dimensionless

Equation (6.61) means that the higher the porosity, the smaller the ratio between the horizontal and vertical efective stresses, which in fact, is the opposite of what is observed in nature. he author stated that the relationship between pore pressure and fracture pressure will vary with diferent overpressure mechanisms and local boundary conditions, so that prediction of one from the other, even using established techniques, can lead to signiicant errors. Rodney et al., (2002) stated that pre-drill pore pressure and fracture gradient determination from seismic data is available as a means of drilling risk reduction in deep water classic basins. Based on the work of several investigators, pore and fracture gradient can be computed using seismic data.

6.4 Future Trend on Formation Pore and Fracture Pressure he future trend toward solving the challenges related to formation pore and fracture pressures are in the direction of the application of artiicial intelligent techniques. A

314 Fundamentals of Sustainable Drilling Engineering new development in pore pressure prediction is the artiicial neural network (ANN). An ANN has the capability of intelligent analyzing with simple mathematical method and dealing with non-linear, fuzzy, and complex relationship. Feed-forward with back-propagation neural network (FFBPANN) is the most wildly used ANN due to its powerful adaptability for diferent problem and excellent performance when dealing with complex relationship. he output of the ANN is pore pressure. his ANN has three layers such as two hidden and one as the output layer. he irst set of inputs includes gamma ray; formation density is the input of the irst layer. he second set of inputs, which includes interval transit time, formation density, depth and the results of the irst layer, are the inputs of the second layer. Compared with the ANNs used in the literature, the novel design of this ANN is the fact that it has two sets of inputs and a diferent structure. he ANN can generate a more accurate pore pressure prediction with logging data because it can simulate the process and predict the pore pressure more precisely. he ANN modeling proved that it is more accurate than the conventional pore pressure prediction methods since it is not based on the theory of shale compaction and since it precisely simulates the prediction process. he better the ANN constructed, the more accurate the prediction results of formation pore and fracture pressures.

6.5 Summary he chapter discusses the issues related to the formation of pore pressure and fracture gradients. he diferent rock mechanical properties are discussed in detail. he development of underground stresses and the related formation pressure, fracture pressure is also outlined in this chapter. he importance of diferent types of pore pressures and their detail impacts on the formation of pore and fracture gradients are discussed thoroughly. he diferent causes of abnormal pressures with detailed detection and prediction techniques are the main focus of the chapter. Pore pressure estimation and prediction techniques and correlations are well explained to understand the techniques. he same procedure is applied for fracture pressure and gradient calculation. Finally the current state-of-the-art on the formation pore pressure and fracture pressure along with the fracture gradient are elaborated in this chapter.

6.6 Nomenclature A D d E f g m N q

= rock matrix strength constant or drillability constant = total vertical depth, t. = inner diameter of the drill pipe, in = rotary speed exponent = function of = gravitational acceleration, t./sec2 = slop of the normal trend line = rotary speed, rpm = luid circulation rate, gpm

Formation Pore and Fracture Pressure Estimation R W aN aq aW cr cb db dh dm dn Ds Dw dmc dmn dmo Dml Dsw dexp dD F f Pd f tN Gf Gn Gp G fr Gob Pd Pfp Pf Pfn Plo Pob Rd tN tt tf tr Vs Vt K

315

= shale drillability or rate of penetration, t./hr = weight on bit, lbf = rotating speed exponent (= 0.6 for ofshore Louisiana) = low rate exponent (= 0.3 for ofshore Louisiana) = bit weight exponent (= 1.0 for ofshore Louisiana) = compressibility of the porous rock matrix, 1/psi = bulk compressibility of the rock matrix, 1/psi = bit diameter, in = borehole diameter, in = modiied d-exponent = diameter of one bit nozzle, in = the depth from the sea bed to up to a depth of interest, t. = seawater depth, t. = calculated modiied d-exponent at a given depth = modiied d-exponent from normal pressure trend line (i.e. extrapolated) at a given depth (Figure 6.26) = intercept of the normal trend line = depth below mud line, t. = depth from surface to the ocean bottom, t. = bit weight exponent or d-exponent or formation drillability = vertical depth from a reference point (ground surface) = variable matrix stress coeicient for the depth at which the value of z would be normal matrix stress, dimensionless = function related to diferential pressure = function related to bit wear = formation pressure gradient = normal pressure gradient, lbm/gal Pf = = formation pore pressure gradient at the point of interest, psi/t. D Pfp = = fracture pressure gradient at the point of interest, psi/t. D = overburden gradient, psi/t. = diferential pressure, lbf/gal/1000t. = observed fracture pressure at the point of interest, psi = formation pore pressure at the point of interest, psi = normal formation pore pressure = surface leak-of pressure, psi = overburden pressure, psi = shale drillability at zero diferential pressure, t./hr = bit wear index (equivalent to rotating hours), = the observed interval transit time, s/t. = the interval transit time in the pore luid, s/t. = the interval transit time in rock matrix, s/t. = volume of shale cutting, t.3 = total volume of cup, t.3 = porosity decline constant at , t.–1

316 Fundamentals of Sustainable Drilling Engineering Pf

= formation pressure gradient, psi/t.

D Pf D

b w b e

f m n

r f fn sw bs w

avg o H v z ob x y v ob ob min min

D ob

D Pf g

= normal pressure gradient, psi/t. n

= ratio of the compressibility of the porous rock matrix to the intrinsic comcr pressibility of rock = 1 cb = density of the rock = bulk density of porous sediment = density of seawater, lbm / ft 3 = average bulk density, lbm / ft 3 = equivalent mud density at the bit while circulating or actual mud weight in use, ppg = luid density in the pore space = mud density, lbm/t.3 = mud density equivalent to normal pore pressure gradient or normal mud weight, ppg = grain density of rock matrix, lbm/gal = density of luid in the pore space, lbm/gal = formation luid density at normal condition = density of sea water, lbm/gal = bulk density of shale, lbm/t.3 = density of water, lbm/t.3 = porosity, dimensionless = average porosity = porosity at surface (D = 0), fraction = horizontal efective stress, psi = vertical matrix stress = matrix stress = ob Pf , psi = overburden pressure, psi = matrix stress in x-direction, psi = matrix stress in y-direction, psi = vertical stress = vertical overburden stress, psi Ppn), psi = overburden stress (i.e. ob v = minimum efective stress at the point of interest, psi = minimum efective stress gradient at the point of interest, psi/t. = overburden stress gradient, psi/t. = friction pressure loss, psi = gel strength, lbm/100t.2 = Poisson’s ratio

Formation Pore and Fracture Pressure Estimation

317

6.7 Exercise E6.1: Find out the normal pore pressure at a depth of 7000 t. below the sea level. Assume that the drilling activities will be continued in Malaysia. Also ind out the mud weight for that area. E6.2: Consider a gas sand reservoir as shown in Figure 6.15. If the water-illed portion of the sand is pressured normally and the gas/water contact occurred at a depth of 5,300 t., what mud weight would be required to drill through the top of the sand structure safely at a depth of 4,100 t.? Assume the gas has an average density of 0.78 lbm/gal. E6.3: Determine the pore pressure of a normally pressured formation in the Gulf of Mexico at 9,000t. depth. E6.4: Calculate the matrix stress of an underground reservoir if the overburden pressure is 6,300 psi and the formation pore pressure is 4000 psi. E6.5: Determine values for surface porosity of an area where an average grain density of 2.55 g/cm3, an average pore luid density of 1.02 g/cm3, and the value for porosity decline constant is 0.00009 t.–1. Assume the average bulk density of the sediment is 2.52 g/cm3 at an speciied depth of 8,500 t. E6.6: Determine porosity decline constant for West Texas area. It is noted that an average grain density of 2.50 g/cm3, an average pore luid density of 1.00 g/cm3, and the value for surface porosity of 38% were recorded. Assume the average bulk density of the sediment is 2.25 g/cm3 at an speciied depth of 10,000 t. Also compute the vertical overburden stress at the same depth. E6.7: A penetration rate of 25t./hr was observed while drilling in shale at a depth of 10,500t. using a 9.875-in bit in the gulf of Mexico. he WOB was 26,000 lbf and the rotary speed was 110rpm. he equivalent circulating density at the bit was 10.0 lbm/gal. Compute the dexp and the dm. Assume the normal pressure gradient for the area as 0.465 psi/t. E6.8: Figure 6.28 shows the depth vs. d-exponent and modiied d-exponent plot. Estimate the formation pressure at 14,000 t. using the Rehm and McClendon and the Zamora correlation. Assume that Figure 6.28 is constructed based on North sea data. E6.9: What is the pore pressure at a depth of 12,500 t. if the formation is in Gulf Coast area? Assume that overburden stress gradient is 0.85 psi/t., and normal formation pressure gradient is 0.465 psi/t. Use Eaton Equation. Use Figure 6.29. Also ind out the EMW of the formation. E6.10: he mud engineer of Schlumberger calculated the mud weight of 12 lbm/gal for the North Sea area where the pressure gradient was found 0.452 psi/t. he surface casing was set at a depth of 2,000 t. he fracture gradient was calculated as 0.73 psi/ t. and the transition zone was detected at a depth of 8,000 t., which results a kick. To avoid kick, determine the maximum safe underbalance between mud weight and pore pressure if well kicks from formation at a depth of 8,000 t. E6.11: Calculate the minimum and maximum equivalent mud weight in ppg that can be used immediately below the casing seat at a depth of 10,000 for the pore pressure gradient of 0.57 psi/t. and an overburden gradient of 0.90 psi/t. It is assumed that matrix stress coeicient is 0.70. Use Mathews and Kelly method. E6.12: A well of 13,000 t. was drilled at a Texas Gulf Coast area where the pore pressure gradient was found 0.735 psi/t. Calculate the fracture gradient in units of psi/t. and lbm/gal using Matthews and Kelly model.

318 Fundamentals of Sustainable Drilling Engineering E6.13: A well of 15,000 t. was drilled at a South Louisiana Gulf Coast area where the pore pressure gradient was found 0.689 psi/t. Calculate the fracture gradient in units of psi/t. and lbm/gal using the Hubbert and Willis model, Matthews and Kelly model, Eaton model, and Belloti and Giacca model. Summarize the results in tabular form, showing answers, in units of lb/gal and also in psi/t.

References Aadnoy, B.S, Soteland, T. Rogaland, U., and Ellingsen, B. Casing Point Selection at Shallow Depth. SPE/IADC 18718 presented in New Orleans, Louisiana, Feb–March 1989. Alixant, J.L. and Desbrandes, R.: “Explicit Pore-Pressure Evaluation: Concept and Application,” SPEDE (September 1991) p. 182. Anderson, R.A., Ingram, D.S., and Zanier, A.M. SPE-AIME. Determining Fracture Pressure Gradients Drom Well Logs. SPE 4135 paper presented in 1973. Bassiouni, Z.: “heory, Measurement, and Interpretation of Well Logs,” SPE, Richardson, TX, 1994, pp. 1–19. Bennan, R.M and Annis, M.R. A New Fracture Gradient Prediction Technique hat Shows Results in Gulf of Mexico Abnormal Pressure. SPE 13210 paper presented in Houston, Texas, Sept 1984. Bourgoyne A.T. Jr, et al.: “Applied Drilling Engineering,” SPE, Richardson, TX, 1991, pp. 246–252. Bourgoyne, A.T. Jr, and Rocha, A.L. Jr.: “A New, Simple Way to Estimate Fracture Pressure Gradient,” SPEDC, September 1996, pp. 153–159. Breckels, I.M., and van Eekelen, H.A.M, Relationship Between Horizontal Stress and Depth in Sedimentary Basins. SPE 10336 paper presented in 1982. Carothers, J.W.: “A Statistical Study of the Formation Factor Relationship,” he Log Analyst, September–October 1948, pp. 14–20. Chilingar, G.V. and Knight, L., “Relationship Between Pressure and Moisture Content of Kaolinite, Illite and Montmorillonite Clays,” AAPG Bulletin, 1960, V. 44, No. 1, pp. 100–106. Christman, S. “Ofshore Fracture Gradients, J. Pet. Tech., (Aug. 1973), 910–914. Combs, G.E, 1968. “Prediction of Pore Pressure from Penetration Rate”. 43rd Annu. Fall Meet., Soc. Pet. Eng., AIME, Houston, TX, SPE 2162, 16 pp. Constant, W.D. and Bourgoyne, A.T., Fracture Gradient Prediction for Of-shore Wells. SPE 15105 paper presented in Jun 1988. Daine, S.R. Exploration Logging Inc. he Prediction of Fracture Pressures. SPE paper 9081 presented in 1980. Eaton, B.A. (1969). Fracture Gradient Prediction and Its Application in Oilield Operations. J. Per. Tech., Oct. 1969, 1353–1360; Tram, AIME, 246. Eaton, B.A., and Eaton, L.E.: “Fracture Gradient Prediction for the New Generation,” World Oil, October 1997, p. 93. Eaton, B.A.: “Fracture Gradient Prediction and Its Application in Oilield Operations,” JPT, October 1969, p. 246. Eaton, B.A.: “he Equation for Geopressure Prediction from Well Logs,” paper SPE 5544, presented at the 1975 SPE Annual Technical Conference and Exhibition, Dallas, TX, September 28–October 1. Economides, M.J., and Martin, T.: “Modern Fracturing – Enhancing Natural Gas Production,” ET Publishing, Houston, TX, 1997, pp. 116–124.

Formation Pore and Fracture Pressure Estimation

319

Fricke, H.: “A Mathematical Treatment of the Electrical Conductivity and Capacity of Disperse Systems,” Physical Review, 1924, 24, pp. 525–587. Gardner, G.H.F., et al.: “Formation Velocity and Density – he Diagnostic Basis for Stratigraphic Traps,” Geophysics, Vol. 39, No. 6, December 1974, pp. 2085–2095. Hottman, C.E., and Johnson, R.K.: “Estimation of Formation Pressures from Log-derived Shale Properties,” JPT, June 1965, p. 717. Hubbert, M.K. and Willis, D.G. (1957). Mechanics of Hydraulic Fracturing. Trans., AIME 210, 153–166. Hubbert, M.K. and Willis, D.G., “mechanics of Hydraulic Fracturing”, Trans., AIME (1957), 210, 153–160. Lesage, M., Hall, P., Pearson, J.R.A and hiercelin, M.J., Cambrige Research. Pore-Pressure and Fracture Gradient Predictions. SPE 21607 paper presented in Jun 1991. Littleton, R., Cody, R., Landreth J., Irving, T. and Greve, J., Pre-drill Seismic Predictions Platform (Pore Pressure, Fracture Gradient, Lithology, and Pore Fluids) Efectively Used as a Well Planning Tool by a Multi-Discipline Deepwater Operations Team. IADC/SPE 74487 paper presented in Dallas, Texas, Feb 2002. Matthews, W.R. and Kelly, J., “How to predict formation pressure and fracture gradient from electric and sonic logs”, OGJ, February 20, 1967. Matthews, W.R.: “Here is How to Calculate Pore Pressure from Logs,” OGJ, November 15, 1971– January 24, 1972. Matthews,W. R. and Kelly, J. (1967). How to Predict Formation Pressure and Fracture Gradient from Electric and Sonic logs. Oil and Gas Journal, February 20. MI Drilling Fluids, Inc.: “Plotting Pressures From Electric Logs,” 1999. 110. Pennebaker, E.S., “An Engineering Interpretation of Seismic Data”, SPE 2165, presented at the SPE 43rd Annual Fall Meeting, Houston, September 29–October 02, 1968. Perez-Rosales, C.: “Generalization of Maxwell Equation for Formation Factor,” paper SPE 5502, presented at the 1975 SPE Annual Technical Conference and Exhibition, Dallas, TX, September 18–October 1. Porter, C.R., and Carothers, J.W.: “Formation Factor-Porosity Relation Derived from Well Log Data,” SPWLA, 1970, Paper A. Rocha, L.A., Petrobras, S.A, and Bourgoyne, A.T., A New Simple Method to Estimate Fracture Pressure Gradient. SPE 28710, paper presented in 1994. Roegiers, J-C.: “Rock Mechanics,” Chapter 3 or Reservoir Stimulation, ed. Economides, M.J. and Nolte, K.G., Schlumberger Educational Services, 1987. Schlumberger: “Log Interpretation Charts,” Houston, Tx, 1979. Schlumberger: “Oilield Glossary – Where the Oilield Meets the Dictionary,” http://www.glossary.oilield.slb.com. Terzaghi, K.: “heoretical Soil Mechanics,” John Wiley and Sons, New York City, NY, 1943. Timur. A., et al.: “Porosity and Pressure Dependence on Formation Resistivity Factor for Sandstones,” Cdn. Well Logging Soc., 1972, 4, paper D. Winsauer, H.M., et al.: “Resistivity of Brine-Saturated Sands in Relation to Pore Geometry,” AAPB Bulletin 36, No. 2, February 1952, pp. 253–277. Yoshida, C., et al.: “An Investigative Study of Recent Technologies Used For Prediction, Detection, and Evaluation of Abnormal Formation Pressure and Fracture Pressure in North and South America,” IADC/SPE 36381 presented at the 1996 IADC/SPE Asia Paciic Drilling Technology Conference, Kuala Lumpur, Malaysia, September 9–11.

7 Basics of Drill String Design 7.1 Introduction he drill string is an important part and a major component of the rotary drilling system. he drill string is a pervasive term that is sometimes also called a drillstem. It is the connection between the rig and the drill bit. A typical drill string consists of kelly, drill pipe, drill collars, tools and drill bit. he drill string has two primary objectives: i) it provides a conduit for the drilling luid to be pumped down through it, and circulates back up the annulus, ii) it provides torque to the drill bit for cutting the rock. he major functions of drill string are: i) to suspend the bit, ii) to transmit rotary torque from kelly to the drill bit (i.e. impart rotary motion to the bit), iii) to provide a conduit for circulating drilling luid to the bit (i.e. provide luid conduit from rig to bit), iv) to provide weight on bit (WOB), and v) to lower and raise bit in the well. In addition, the drill string may serve some of the following specialized services such as i) it allows the formation evaluation and testing when logging tools cannot be run in the openhole, ii) it provides some stability to the bottomhole assembly to minimize vibration and bit jumping, and iii) it allows formation luid and pressure testing through the drill string. It must be remembered that in deep holes the drill string may be 8–10 km long. Trying to control the bit on the end of such long string is a diicult task. herefore the drill string must be carefully chosen to meet the requirements. Although the drill string is oten a source of problems such as washouts, twist-ofs, and collapse failures, it is rarely designed to prevent these problems from occurring. In many cases, a few minutes of drill string design work could prevent most of the problems.

321

322 Fundamentals of Sustainable Drilling Engineering

7.2 Drill String Components he drill string assembly consists primarily of the kelly, drill pipe, bottomhole assembly (BHA), and drill bit. he drilling luid and rotational power are transmitted from the surface to the bit through the drill string. Figure 7.1 shows the usual arrangement of drill string components and bit. he drill pipe section contains conventional drill pipe, and heavy weight pipe. he drill pipe is attached with a square or hexagonal pipe called kelly at the upper end of the drill string. he BHA may contain the following items such as: i) drill collars, ii) stabilizers, iii) jars, iv) reamers, v) shock subs, and vi) bit sub. In addition, the drill string may include shock absorbers, junk baskets, drilling jars, reamers, and other equipment. here are some special tools in the BHA or drill pipe, which may include monitor-while-drilling (MWD) tools, and drill stem-testing tools. Finally there exists drill bit at the lower end of the drill string. Heavy walled large-diameter drill collars furnish bit load. he drill bit is attached to the drill collars by means of a bit sub. For an efective rock cutting, the lower part of the drill collar is stacked onto the drill bit to provide the WOB. he drill cuttings generated by the rock bit are removed from the bottom of the hole by the drilling luid, which is circulated inside the drill string and through the drill bit into the annular space between the drill string and the bottomhole wall. Stabilizers are placed above the bit to control the direction in which the drill bit penetrates the formation. Downhole motors with bent subs and rotary-steerable tools are also used for controlling the direction in which the bit drills.

7.2.1

Kelly

A description of a kelly is already covered in Chapter 2. It is a special section of pipe that is attached to the bottom of the swivel by threading. Figure 7.2a shows the arrangement, which is not round. It has a hexagonal (6 sides) or square shape (4 sides) of pipe (Figure 7.2b). hey come in 40t.. and 54t. lengths. Table 7.1 shows the diferent available size of the kelly. It is attached to the swivel and its in a matching slot in the rotary table. he kelly it into a device called kelly bushing. he kelly bushing then its into the master bushing which is mounted on the rotary table (Figure 7.3). As the rotary table turns, kelly is also turned which rotates the drill string and the drill bit. he functions of the kelly are i) to transmit rotation and weight to the drill bit, and ii) to carry the total weight of the drill string.

7.2.2

Drill Pipe

Drill pipe is the major component of the drill string, which forms the upper part of the drill string. It has a seamless pipe with threaded joints at either end known as tool joints (Figure 7.4). Each section of pipe is called a joint with a box (female) and pin (male) located on the ends. At the one end of the pipe there is the box, which has the female thread. Drill pipe is threaded together or assembled in sections and put into the hole as the bit turns. he other end is the male thread known as the pin. hese tool joints provide a shoulder that suspends the drill pipe in the slips or elevators. It consists of a tube body and tool joint. he drill pipe is hollow and allows luid or

Basics of Drill String Design 323 mud

Kelly

Drill String

Kelly Joint

mud

DP

Mud

To pits

Tool joint

Bottom Hole Assembly

mud

HWDP

Drill Collar Shock Tool

Near Bit Pressure or Stabilizer

Drill collars

Bit

BIT

(a)

Rotary box Connection L.H.

mud

Stabilizer

Drill pipe

mud

Jar

(b)

Swivel

Rotary box connection

Swivel stem spec. BA

Tool joint box member Drill pipe

Rotary pin Connection L.H. Rotary box Connection L.H.

Spec 7 swivel sub Kelly cock (optional)

Rotary pin connection

Upper upset

Rotary box connection Rotary pin connection

Rotary pin Connection L.H. Rotary box Connection L.H.

Rotary box Kelly (square or hexagon) connection (square illustrated) Note: All connections between “lower upset” of Kelly and bit are R.H. Rotary pin Connection Rotary box Connection

Lower upset

Tool joint pin member Crossover sub

Drill collar

Rotary pin connection

Kelly cock or Kelly saver sub Protector rubber (optional)

Rotary pin Connection

Rotary box connection Rotary pin connection

Bit sub

Bit

(c)

Figure 7.1 Components of the drill string.

transmitting wires to pass through it. he drill pipe is used in lengths known as singles, which are available in three ranges (Table 7.2). he most common range is 27 t. – 30 t. in length. he exact length of each single must be measured on the rig since lengths are not uniform.

324 Fundamentals of Sustainable Drilling Engineering Table 7.1 Diferent size of kelly. Square

Hexagonal

1 2

3

3

3

1 2

3

1 2

4

1 4

4

1 4

5

1 4

5

1 4

2

6”

6

SQUARE KELLY Top Upset with Left Hand Connection

HEXAGONAL KELLY Top Upset with Left Hand Connection

E

E

F G

B

A

G

F Bottom Upset with Right Hand Connection

Bottom Upset with Right Hand Connection

(a)

(b)

Figure 7.2 Components of a kelly.

Table 7.2 Drill pipe lengths (Ford, 2005). Range

Length (t.)

1

18 – 22

2

27 – 30

1

38 – 45

B

A

Basics of Drill String Design 325

Kelly

Kelly bushing

Rotary table

Bowl Lock Assy. API Insert Bowl Hinge Pin Stationary Drive Hole Bush Hole for Lifting Sing

APS-Insert Bowl Hinge Pin Stationary Drive Hole Bushing for Pin Type Kelly Bushing Lock for Bowl Label to lock in Rotary Table

Body Segment

Holes for Lifting Sling Hock Hinge Pin Removable Body Segment

Figure 7.3 Components of kelly bushing.

Figure 7.4 Drill pipe arrangement.

Various diameters of drill pipe are available, together with diferent wall thickness (Table 7.3). However, the most commonly used diameters of drill pipe are 4, 4½, and 5 inches OD. he wall thickness dimension relates to the weight per foot of the drill pipe and allows a selection of the pipe to meet speciic drilling requirements. A drill pipe is normally purchased in large batches and a record should be kept to monitor the wear and use each batch sustains. he physical properties of a drill pipe can be found

326 Fundamentals of Sustainable Drilling Engineering Table 7.3 Dimensions of drill pipe (Ford, 2005). Size (OD, inches)

Weight (lb/t)

ID (inches)

5.65

1.815

10.40

2.151

9.50

2.992

13.3

2.764

15.50

2.602

5

16.25

4.408

5

19.50

4.276

5

25.60

4.000

21.90

4.776

24.70

4.670

3 8 7 2 8 1 3 2 1 3 2 1 3 2 2

1 2 1 5 2 5

in any available handbook or manual. However, for identiication purposes, a drill pipe can be classiied according to the size (nominal OD), wall thickness (or nominal wall thickness), steel grade, and length ranges. he steel grades used and the corresponding minimum tensile yield strength for each are given in Table 7.4.

7.2.3 Tool Joint Tool joints are positioned at each end of a length of drill pipe, which are shown in Figure 7.5. It provides the screw thread for connecting together the joints of drill pipe and the only seal is the shoulder-to-shoulder connection between box and pin. Initially tool joints are screwed at the end of drill pipe, and then reinforced by welding. A new development is to have shrunk-on tool joints. his process involves heating the tool joint, then screwing it on to the pipe. As the joint cools, it contracts and forms a very high close seal. One advantage of this method is that a worn joint could be heated, removed and replaced by a new joint. he modern method is to lash-weld the tool joints onto the pipe. Hard facing material is used for the tool joints, and so replacements are not required. When a connection is made, the rig tongs must be engaged around the tool joints, whose greater wall thickness can sustain the torque required. he strength of the

Basics of Drill String Design 327 Table 7.4 Minimum tensile yield strength for new drill pipe (Mitchell and Miska, 2011). Steel Grade

Minimum Yield Strength, psi

D

55,000

E

75,000

X-95

95,000

G-105

105,000

S-135

135,000

V-150

150,000

Internal Upset

External Upset

Internal-External Upset

Figure 7.5 Tool joint.

tool joint depends on the cross sectional area of the box and pin. With continual use the threads become worn, and there is a decrease in the tensile strength. Various sizes of tool joints are available and can be found in the data handbook. Tool joint boxes usually have 18 degree tapered shoulders, and pins have 35 degree tapered shoulders. Tool joints are subjected to the same stresses as the drill pipe, and also have to face additional problems such as: i) when pipe is being tripped out the hole, the elevator supports the string weight underneath the shoulder of the tool joint, ii) frequent engagement of pins and boxes, if done harshly, can damage threads, and iii) the threaded pin end of the pipe is oten let exposed. Tool joint life can be substantially extended if connections are greased properly (dope) and a steady torque applied. Rubber thread protectors are also used.

7.2.4

Heavy Wall Drill Pipe

he use of a heavy weight drill pipe (HWDP) in the drilling industry has become a widely accepted practice. It has a greater wall thickness than ordinary drill pipe. he pipe is available in conventional drill pipe outer diameters. However, its increased wall thickness gives a body weight of 2–3 times greater than regular drill pipe (Figure 7.6). HWDP provides three major beneits to the user – i) it reduces drilling cost by virtually eliminating drill pipe failures in the transition zone, ii) it signiicantly increases performance and depth capabilities of small rigs in shallow drilling areas through the case of handling and the replacement of some of the drill collars, and iii) it provides substantial savings in directional drilling costs by replacing the largest part of the drill-collar string, reducing down hole drilling torque, and decreasing tendencies to change direction. he

328 Fundamentals of Sustainable Drilling Engineering HWDP

DC

Figure 7.6 Heavy weight drill pipe.

major functions of HWDP are to reduce failures at transition zone, to reduce downhole torque and drag in directional drilling, and to reduce diferential sticking. Most HWDP have an integral center upset acting as a centralizer and wear pad. It helps prevent excessive tube wear when run in compression. his pipe has less wall contact than drill collars and therefore reduces the chances of diferential pipe sticking. HWDP is oten used at the base of the drill pipe where stress concentration is greatest. he stress concentration is due to i) the diference in cross section and therefore stifness between the drill pipe and drill collars, and ii) the rotation and cutting action of the bit can frequently result in a vertical bouncing efect.

7.2.5 Bottomhole Assembly he bottomhole assembly (BHA) is the component of the drill string located directly above the drill bit and below the drill pipe. he primary component of the BHA is the drill collar. herefore, it has a signiicant efect on drill bit performance. he other components of BHA are stabilizers, jars, reamers, crossovers, shocks, hole-openers, and various subs such as bit subs, shock subs (Figure 7.7). In addition to these main components, the BHA typically consists of a down hole motor, rotary steerable system (RSS), and measurement and logging while drilling tools (MWD and LWD respectively. However, some classify the drill bit as a part of the BHA. It hangs below the drill pipe and provides weight to the drill bit to induce the teeth to penetrate the formation. he functions of BHA are i) to protect the drill pipe in the drill string from excessive bending and torsional loads, ii) to control direction and inclination in directional holes, iii) to drill more vertical and straighter holes, iv) to reduce severities of doglegs, key seats, and ledges, v) to assure that casing can be run into a hole, vi) to reduce rough drilling (rig and drill string vibrations), and xi) as a tool in ishing, testing, and work over operations. 1. Drill Collars: Drill collars (DC) are heavy, stif steel tubulars, which have a much larger outer diameter and generally smaller inner diameter than a drill pipe. hey are used at the bottom of a BHA to provide weight on bit and rigidity. he primary function of the drill collar is to provide suicient weight on bit. he weight of the collar also ensures that the drill pipe is kept in tension to prevent buckling. Figure 7.8 shows a typical short drill collar and non-magnetic drill collar. It is a pipe with thick walls that are attached to the bottom of the drill string. herefore it has a signiicantly thicker wall

Basics of Drill String Design 329 BHA for holdup and horizontal sections

BHA Straight hole

Head sub

Coiled tubing

Connector Check valve assembly

Inner tube landing ring Long top sub

Pressure disconnect Drill collars Inner tube stabilizer

Orienting tool

Drill collar sub Mud motor

SUM 1 MWD in nonmagnetic drill collar Stabilizer sub Mud motor Adjustable best housing Inner tube stabilizer ixed diamond bit

Figure 7.7 Schematics of bottomhole assembly [hese bottomhole assemblies are designed for drilling a straight hole (let) and a directional hole (right)].

Short Drill Collar

Non-Magnetic Drill Collar

Figure 7.8 Drill Collar.

than a drill pipe. Since the drill collars have such a large wall thickness, tool joints are not necessary and the connection threads can be machined directly onto the body of the collar. Drill collars add weight to the bit and make the bit cutters bite into the rock. Normally multiple drill collars are used to add weight. he purposes of drill collars are i) to put extra weight on bit, so they are usually larger in diameter than drill pipe and have thicker walls, ii) to keep the drill string in tension, thereby reducing bending stresses and failures due to fatigue, iii) to provide stifness in the BHA for directional control, iv) to stabilize the bit. he weakest point in the drill collar is the joint, therefore the correct make up torque must be applied to prevent failure. he external surface of a regular collar is round (slick), although other proiles are available. he drill collars

330 Fundamentals of Sustainable Drilling Engineering

Spiral Drill Collar

Square Drill Collar

Figure 7.9 Spiral drill collar.

are normally supplied in ranges two lengths (30–32 t.). Drill pipe and drill collar come in sections, or joints, about 30 feet long. here are several types of drill collars that are explained below. Square Drill Collars: Square drill collars provide the ability to maximize the available weight on the bit when drilling in challenging formations (Figure 7.9). he square design has a larger cross sectional area than round drill collars, which increases its stifness and rigidity to prevent deviation while drilling. he square shape also provides four point stabilization to prevent buckling. Square geometry makes for a stable and stif BHA ideal for drilling in hard formations requiring all available weight on the bit. he square drill collar achieves four objectives – i) it provides continuous centralization over their length, ii) it maximizes bending resistance (stifness), iii) it maximizes torsional damping, and iv) it minimizes axial vibrations. hese collars are usually 1/16 less than bit size, and are run to provide maximum stabilization of the BHA. Spiral Drill Collars: Spiral drill collars decrease the risk of diferential pressure sticking of the BHA (Figure 7.9). he spiral drill collars usually have slip and elevator recesses. Stress-relief groove pins and bore back boxes are optional. In directional drilling, spiral drill collars are preferable. he spiral grooves machined in the collar reduce the wall contact area by 40% for a reduction in weight of only 4%, thus reducing the chances of diferential sticking. his is likely to happen when the formation is highly porous, a large overbalance of mud pressure is being used and the well is highly deviated. he problem can be overcome by reducing the contact area of the collar against the wellbore. Non-Magnetic Drill Collar: his type of collar is also called a monel drill collars. Non-magnetic drill collars are usually non-spiral. hey are made of a special nonmagnetic steel alloy (Figure 7.8). hey are manufactured from high-quality, corrosionresistant, austenitic stainless steel.  Magnetic survey instruments (MWD/Magnetic Single Shots/Multi Shots) run in the hole and need to be located in a non-magnetic drill collar of suicient length to allow the measurement of the earth’s magnetic ield without magnetic interference. Survey instruments are isolated from magnetic disturbance caused by steel components in the BHA and drill pipe. he primary purpose of non-magnetic drill collars is to reduce the interference of the magnetic ields associated with those sections of the BHA, which are both above and below the magnetic compass contained in the survey tool with the earth’s magnetic ield. Four critical factors play an important role in selecting non-magnetic collars. hese factors are their total length,

Basics of Drill String Design 331 the location of the survey compass with the non-magnetic collars, the type of material of which the collars are composed, and distinguishing hot spots. Medium and Large Round Collars: he purposes of large round collars are to provide stifness next to the drill bit and to add weight to the BHA. he medium collars add weight to the BHA and reduce ever-present lexure stresses between large collars and drill pipe or other tools of less rigidity than the large collars. Both may be used for jarring weight. Short Drill Collars: Short drill collars (SDC’s) are also called pony collars. hey are simply shortened versions of a steel drill collar. Short drill collars may be manufactured or a steel drill collar may be cut to make two or more short collars. For a directional driller, the SDC and the short non-magnetic drill collar have their widest application in the make-up of locked BHAs. SDCs of various lengths (e.g. 5’, 10’, 15’) are normally provided by the manufacturers. Short Non-Magnetic Drill Collars: It is a short version of the non-magnetic collars. Cutting a full-length non-magnetic collar oten makes them. he short non-magnetic collars may be used between a mud motor and an MWD collar to counteract magnetic interference from below. It is used in locked BHAs, particularly where the borehole’s inclination and direction give rise to high magnetic interference.  It is also used for BHAs of horizontal wells.  2. Stabilizers: A stabilizer consists of a length of pipe with blades on the external surface and located above the bit. hese blades may be either straight or spiral and there are numerous designs of stabilizers (Figure 7.10). he blades can either be ixed on to the body of the pipe, or mounted on a rubber sleeve (sleeve stabilizer), which allows the drill string to rotate within it. According to the blades, stabilizers can be categorized. he function of the stabilizer depends on the type of hole being drilled. However, the functions of stabilizers are i) to control hole deviation, ii) to reduce buckling and bending stresses on the drill collars, iii) to prevent wall thickening, iv) to improve performance of the bit, v) to allow higher WOB since the string remains concentric even in compression, vi) to centralize drill collars in hole and increase stifness, vi) increase ability of drill collars to drill smooth straight hole, and vii) to wipe wall of hole to ensure full gage. 3. Jars: his type of tool is used to generate upward or downward loads to free stuck pipes or release ish (Figure 7.11). here are two types of drilling jars based in its operation: i) hydraulic, and ii) mechanical. Hydraulic jars are stimulated by a straight pull and give an upword blow. Mechanical jars are present at surface to operate when a given compression load is applied and given a downward blow. Jars are usually positioned at the top of the drill collars. Jars are needed when there are sloughing formations, there are sensitive shales, the mud system does not have good suspension properties, and there is expensive equipment in BHA. 4. Roller Reamers: Roller reamers are also called drilling reamers. hey consist of stabilizer blades with rollers embedded into surface of the blade. he rollers may be made from high grade carburized steel or have tungsten carbide inserts (Figure 7.12). he reamer acts as a stabilizer and is especially useful in maintaining gauge hole. It is used to drill a bigger hole. It is also used for any potential hole problems such as doglegs, ledges, and key seats. A roller reamer is a very useful tool for drilling operation, especially used for the function of stabilization in drilling of the abrasive formation.

332 Fundamentals of Sustainable Drilling Engineering

Figure 7.10 Stabilizers.

Figure 7.11 Jars.

Sleeve dressed with type ”W”

gth

31” Nominal Length

n Total Le

24”

D Pin Tool Joint

11”

21’4”

C Spiral Upset

A Nominal size

Sleeve Length

42”

D Box Tool Joint B Elevator Upset Diameter

24”

Sleeve body dia

Basics of Drill String Design 333

DIferent roller

Figure 7.12 Roller reamers.

Crossover

Shock sub

Figure 7.13 Images of various subs.

5. Various Subs: here are various subs used at BHA for diferent purposes. he word “sub” refers to any short length of pipe, collar, casing, etc., with a deinite function for drilling operations. he following are some of the subs used during drilling string design. Crossovers: A crossover sub is used between the drill string and drill collars. Short joints of pipe to connect two pipes of diferent sizes or thread types are called crossovers (Figure 7.13). Shock Subs: Shock subs are also called vibration dampeners (Figure 7.13). hey are normally located above the bit to reduce the stress due to bouncing when the bit passes through hard rock. he shock sub absorbs the vertical vibration either by using a strong steel spring, or a resilient rubber element. he purpose of shock subs is to dampen the vibration produced by the drill bit and the drill string. It is reasonable to surmise that shock subs prolong the life of drill bits and drill strings and in some cases the rig. hey are not as stif (resistance to axial bending) as drill collars and, because of this, oten have limited application in straight hole drilling. In addition, large drill collars may be more efective in reducing bottomhole vibrations. Sometimes we use shock absorbers based on application. he functions of shock absorbers are almost same as shock subs, which are to: i) reduce or eliminate vertical oscillations, ii) maintain uniform bit load, iii) increase bit life, iv) increase ROP, and iv) reduce drill collar failures.

334 Fundamentals of Sustainable Drilling Engineering

7.3

Drilling Bit

Technically, the drill bit is not a component of the BHA. However, it does generate and send axial and torsional loads to the BHA. It is located at the bottom end of the drill string and makes contact with the subsurface layers, and drills through them. A drilling bit is deined as the cutting or boring tool, which is made up on the end of the drill string (Figure 7.14). Its basic function is to cut rock at the bottom of the hole. he bit consists of a cutting element (cutters) and a luid circulation element (nozzles). he drill bit is rotated mechanically to crush and penetrate new formations. he broken and loosened rocks are known as cuttings, which are removed from the wellbore by circulating drilling luid down the drill pipe and through nozzles in the drill bit. he bit drills through the rock by scraping, chipping, gouging or grinding the rock at the bottom of the hole. Drilling luid applies hydraulic power to improve penetration rates. he penetration rate of a bit is a function of several parameters including WOB, RPM, mud properties and hydraulic eiciency. here are several bit sizes ranges from 3¾ inches to 26 inches in diameters. he most commonly used sizes are 17½, 12¼, 77⁄8, and 6 ¼ inches.

7.3.1

Types of Drilling Bits

here are several types of drill bits manufactured for diferent situations and conditions encountered during drilling operations. Basically there are two types of drill bits; these are the ixed-cutter bits, and roller-cone bits. Figure 7.15 shows the detail classiications

Blade Drag Bit

Rolling Cutter Bit

Figure 7.14 Images of typical drilling bits.

Diamond Bit

Basics of Drill String Design 335 Rotary Drilling Bits

Fixed-Cutter Bits

Roller-Cone Bits

Hybrid Bits

Insert Bits Steel-Cutter Bits

Diamond Bits

Impregnated Bits MIlled-tooth or Steel-tooth Bits

Natural Diamond Bit

PDC Bit

TSP Bit Tungsten-Carbide-Insert (Tci) Bit

Figure 7.15 Classiication of rotary drilling bits.

Figure 7.16 Examples of drag bit.

of rotary drilling bits. he most common types are the roller-cone bits and diamond bits. he diamond bit is commonly used in hard formations. Roller-cone bits usually have three cone-shaped steel cutting devices that are free to turn as the bit rotates. herefore it is sometimes called as rolling-cutter bit. 1. Fixed-Cutter Bits A ixed-cutter bit is also called a drag bit. It is deined as a drill bit that has ixed blades, which are integral with the body of the bit and rotate as a single unit. It is usually designed for using in sot formations such as sand, clay, or some sot rock. Fixed-cutter bits have steel wings extending from the central shat of the bit instead of roller cones (Figure 7.16). In a two-blade bit, the body and blades are stamped as a single unit (Figure 7.16). hese were the irst bits used in rotary drilling but are no longer in common use. A drag bit is used in drilling water wells that consist of a drill pipe connector attached to blades on the end. hese wings consist of rigid steel blades shaped like a ishtail which rotate as a single unit with the drill string since the beginning of rotary drilling in early 19th century. Due to the dragging/scraping action of this type of bit high RPM and low WOB are applied. he main advantages of drag bits are – i) no rolling parts which require strong clean bearing surfaces, ii) because it is made from one solid piece of steel there is less chance

336 Fundamentals of Sustainable Drilling Engineering of bit breakage, which would leave junk in the bottom of the hole. he main disadvantages in using drag bits are: i) the introduction of roller cone bits which could drill sot formations more eiciently, ii) if too much WOB is applied, excessive torque led to bit failure or drill pipe failure, iii) drag bits tend to drill crooked hole, therefore some means of controlling deviation is required, iv) drag bits are limited to drilling through uniformly, sot, unconsolidated formations where there were no hard abrasive layers. Fixed-cutter bits can be classiied as – i) steel-cutter bits, ii) diamond bits, and iii) impregnated bits. i) Steel-Cutter Bits: Drag bits with steel cutter elements are called steel-cutter bits which look like ishtails (Figure 7.17). It works better relative to other bit types in uniformly sot, unconsolidated formations. As the formation becomes harder and more abrasive, the bit wear increases rapidly and drilling rate decreases rapidly. his type of bit is best for sot, uniform, and unconsolidated formations. Now, it is replaced by other types in all areas. ii) Diamond Bits: Due to the hardness of diamond, it has been used as a material for cutting rock for many years. In general, the term “diamond bit” refers to a bit where diamonds are used as a cutter set at the surface of the contact area. he cutting action is developed by scraping away the rock and drills by a high-speed ploughing action that breaks the cementation between rock grains. his type of bit is used in abrasive formations and is best for hard non-brittle formations. Diamond bits can be classiied as natural diamond bits, polycrystalline diamond compact (PDC) bits, and thermally stable polycrystalline (TSP) bits. Natural Diamond Bits: he hardness and wear resistance of diamond prepared it as a necessary material for a drilling bit. he natural diamond bit is truly a type of drag bit since it has no moving cones and operates as a single unit (Figure 7.18). he cutting action is achieved by scraping away the rock using high RPM. h e face or crown of the

Figure 7.17 Examples of steel cutter bit.

Basics of Drill String Design 337

Figure 7.18 Examples of natural diamond bit.

bit consists of many diamonds set in matrix body. he diamonds are set in a specially designed pattern and bonded into a matrix on a steel body. Regardless of its high wear resistance, diamond is sensitive to shock and vibration. herefore great care must be taken when running a diamond bit. Efective luid circulation across the face of the bit is also very important to prevent overheating of the diamonds and matrix material. It is also necessary to prevent the face of the bit becoming grimy with rock cuttings, which is called bit balling. he higher cost of diamond bits is the major disadvantage, which is sometimes 10 times more expensive than a similar sized rock bit. In addition, if a roller cutter bit is selected correctly, a diamond bit will not guarantee higher ROP for the same formation. hey are however cost efective when drilling formations are for long rotating hours (200 – 300 hours per bit). Since diamond bits have no moving parts they tend to last longer than roller cone bits. Once the cutting elements have worn down, no further cutting structure is available. hey can be used for extremely long bit runs. Longer life of bit reduces the number of round trips, which decreases the capital costs of the bit. his is essential in ofshore drilling. In addition, the diamonds of the bit can be extracted which have some salvage value. Natural diamond bit diamonds are set in a pre-designed pattern that ensures suicient overlap to prevent excessive wear to the matrix. hese can include both natural diamonds and shaped TSPs. Natural diamond bits are most suitable when drilling in sot to medium hard formations. As a general rule, the soter the formation, the bigger the size of diamonds should be set in the bit.  PDC Bits: PDC bits are the new generation of diamond bits known as polycrystalline diamond compact (PDC) bits (Figure 7.19). PDC bits are also called polycrystalline diamond (PCD) bits. A new family of drag bits has been made possible by introducing a sintered polycrystalline diamond drill blank as a bit cutter element since the mid1970s. he drill blanks consist of a layer of a synthetic polycrystalline diamond about (1/64)-inch thick that is bonded to a cemented tungsten carbide substrate in a highpressure high-temperature (HPHT) process. It contains many small diamond crystals bonded together. he PDC is bonded either to a tungsten carbide bit-body matrix or to a tungsten carbide stud that is mounted in a steel bit body. hey perform best in sot,

338 Fundamentals of Sustainable Drilling Engineering

Figure 7.19 Examples of polycrystalline diamond compact bits.

Figure 7.20 Examples of TSP bits.

irm, and medium-hard, non-abrasive formations that are not gummy to avoid bitballing. Good results are obtained in carbonates or evaporates that are not broken up with hard shale stringers. It is also good in a sandstone, siltstone, and shale. h e design of the crown proile is important. Double-cone and lat proiles are also used which are called dual-diameter bits. TSP Bits: A further development of the PDC bit concept was the introduction in the late 1980s of TSP diamond bits (Figure 7.20). hese bits are manufactured in a similar fashion to PDC bits but are tolerant of much higher temperatures than PDC bits. TSP bits are manufactured similarly to PDC bits except TSP bits can resist much higher operating temperatures than PDC bits. iii). Impregnated Bits: Impregnated-bit bodies are PDC matrix materials that are similar to those used in cutters. he working portions of impregnated bits are unique, such that they contain matrix impregnated with diamond (Figure 7.21). Both natural and synthetic diamonds are prone to breakage from impact. When embedded in a bit body, they are supported to the greatest extent possible and are less susceptible to breakage. However, because the largest diamonds are relatively small, cutting depth must be smaller and ROP must be achieved through increased rotational speed. hey are most frequently run in conjunction with turbo drills and high-speed positive displacement motors that operate at several times the normal rotational velocity for rotary drilling (500 – 1,500 rpm). Diamond impregnated bits are also used in full-size conventional drilling (Figure 7.21) when a turbine is used to provide high rotary speed. Turbines

Basics of Drill String Design 339

Figure 7.21 Examples of Impregnated bits.

are available that have no rotating elastomeric seals, so they can withstand high temperatures, but their high rotary speed is not compatible with rotary bits, so diamond impregnated bits are used. During drilling, individual diamonds in a bit are exposed at diferent rates. Better bit performance and reduction in the number of required bits have been reported in abrasive and heterogeneous formations when impregnated bits with turbines are used instead of roller cone bits and PDCs (Botelho et al., 2006). hese bits are generally only used when nothing else will work—the rate of penetration is low, they are extremely expensive, and they cannot be repaired when worn. 2. Roller-Cone Bits he most common type of bit used worldwide is the roller cone bit. It is also called a rolling cutter bit or simply a rock bit (Figure 7.22). he cutting action is provided by cones having either steel teeth or tungsten carbide inserts that drill holes predominantly with a grinding and chipping action. he irst successful rock bit was designed by Hughes in 1909 which was a major innovation since it allowed rotary drilling to be extended to hard formations. he irst design was two or more cones containing the cutting elements, which rotate about the axis of the cone as the bit is rotated at the bottom of the hole. However, the three-cone rolling cutter bit is by far the most common bit. hese bits are mounted on bearing pins, or arm journals, which extend from the bit body. Figure 7.23 shows the roller cone bearing used in rolling cutter bits. Rolling cutter bits have improved a lot over time. In the early stages, the bit did not have self-cleaning option. Proper bottomhole cleaning is very important where luid low through jets in the bit (i.e. nozzles) is responsible for the cleaning (Figure 7.24a). herefore, the three-cone bit is developed where a straight hole exists and intermeshing teeth for better cleaning are introduced (Figure 7.24). Other improvements include hard-facing on the teeth and body, steel and milled tooth, carbide tooth (tungsten carbide insert), change from water courses to jets (Figure 7.24b), sealed bearings, and

340 Fundamentals of Sustainable Drilling Engineering

(a) For soft formation

(b) For hard formation

Figure 7.22 Roller cone bits.

Figure 7.23 Roller cone bearing.

journal bearings. Roller cone bits are available with a large variety of tooth design and bearing types. he major disadvantages include the limited space, cone ofset to stop rotating periodically to scrape the hole like PCD bits, and faster tooth wear. he major advantages of the roller cone bits are jet bits through which drilling luid exits from the

Basics of Drill String Design 341

Figure 7.24 Roller cone bits with straight hole nozzle.

Figure 7.25 Insert roller cone bit (photo courtesy of Reed-Hycalog NOV.)

bit through nozzles between the cones. hus it creates high velocity jets of mud. his will help lit cuttings away from the bit. Other advantages include: 1. 2. 3. 4. 5. 6. 7.

For any type of formation, there is a suitable design of rock bit It is available with a large variety of tooth design and bearing types It can handle changes in formation It has an acceptable life and drilling rate It has a reasonable cost he use of tungsten carbide for hard-facing and gauge protection he introduction of sealed bearings to prevent mud causing premature failure due to abrasion and corrosion of the bearings

Rock bits are classiied as “milled tooth” or “insert” depending on the cutting surface of the cones. As mentioned in Figure 7.15, the roller-cone bit can further be classiied as insert bit, milled-tooth or steel-tooth bit, and tungsten-carbide-insert (TCI) bit. i) Insert Bit: In insert bits, the cutting structure is a series of inserts pressed into the cones (Figure 7.25). Insert bits are used in medium to hard formations, with the size, shape, bearings, and number of inserts. hese parameters are varied to it the speciic drilling conditions. he bits are available with either roller or journal bearings depending on the operating conditions. he bearings, seals, and lubricants should all

342 Fundamentals of Sustainable Drilling Engineering be speciied to withstand high temperatures if the bits are to be used in geothermal drilling. ii). Milled-tooth Bit: In milled-tooth bit, the cutting structure is milled from the steel making up the cone (Figure 7.26). he cutters have inner rows of teeth that are intermeshing. So, uses of inner rows are advantageous. On the other hand, the outerrow of teeth (i.e. heel teeth) has no intermeshing which creates very diicult job. It wears and leads to out of gauge bit (i.e. hole). Normally long teeth arrangements are used for sot formations and shorter teeth for harder formations. Cone ofset of bit results in scraping, gouging action in sot-formation. It also provides high drilling rates especially in soter rocks. iii). TCI Bit: he TCI bits are manufactured by pressing a tungsten carbide cylinder into accurately machined holes in the cone (Figure 7.27). he tungsten carbide teeth designed for drilling sot formations are long and have a chisel-shaped end. he various types of insert bit tooth designs are shown in Figure 7.28. TCI bit has long life cutting structure in hard rocks and has hemispherical inserts for very hard rocks. It has larger and more pointed inserts for soter rock and can handle high bit weights and high RPM. he inserts of TIC fail through breakage rather than wear because the tungsten carbides are very hard and brittle material. 3. Hybrid Bits he research on developing hybrid bits was done in the early 1930s. However, it was deemed impractical and even unreasonable. Due to the technological advancement in 21st century, it has become a reality. Over the last 100 years, many technologies have had signiicant impact on the drilling industry. Advancement on the rotary rig, rolling bits, top drive, and PDC bits are some of the revolutionary technologies that have changed the way operators drill wells. he everyday demands and challenges faced by the industry have become even more diicult. For example, complex well proiles, hard and inter-bedded formations, and rig or equipment limitations increase the potential for shorter runs. However, these shorter run cause expensive tool damage, and ultimately reduce operator proitability. While PDC performance has improved signiicantly, it still is subject to dynamic ineiciencies in terms of higher torque luctuations and overall level of torque generated. Similarly, enhancements in roller cone technology could provide improvements in ROP or overall footage, but continue to be burdened with the

Figure 7.26 Milled-tooth bit.

Basics of Drill String Design 343

Figure 7.27 Tungsten carbide insert bit.

Soft Formation Inserts Gage compact

Ovoid

Ogive

Conical

90° Chisel

Wedge Crested Chisel

Soft to Medium Formation Inserts

Medium to Hard Formation Inserts

Hard Formation Inserts Scoop Chisel

Blunt Chisel

Sharp Chisel

Figure 7.28 Example tungsten carbide insert cutter used in rolling cutter bits (Bourgoyne et al., 1986).

inherent limitations of the technology. As a result, in the same spirit, Hybrid bit development came into picture through Baker Hughes Inc (Figure 7.29). Hybrid drilling technology is a paradigm shit in innovation, a coalescence of roller cone and PDC bits into a single design. he result is a technology designed to exploit the best attributes of each bit type, bridging the gap between them. With the cutting superiority and continuous scraping of diamond bits and the rock-crushing strength of roller cones, this repairable bit has proven to survive highly inter-bedded formations with smooth drilling and excellent tool face control. In the most complex applications, hybrid drill bit technology combines roller cones and PDC ixed cutters into a single bit to reduce drilling time, to create smoother drilling, remarkable torque management, and precise steerability. Leveraging the cutting superiority of PDCs in

344 Fundamentals of Sustainable Drilling Engineering

Figure 7.29 Example of Hybrid Bit.

sot formations and the rock-crushing strength and stability of roller cones in hard or inter bedded formations, the hybrid bit has the potential to maintain higher overall ROP for more footage than a roller cone or PDC could individually. A superior directional bit for motor and rotary applications, the hybrid bit provides increased buildup rate capabilities, dampened torque response, and precise steerability on a variety of bottomhole assemblies. he hybrid bit is improving drilling rates in tough applications worldwide. Laboratory tests and ield performances conirm beneits of the combined technology. Compared to PDC bits, the hybrids have – i) lower and more consistent drilling torque, ii) better dynamics and directional control, iii) improved durability and reliability in inter bedded formations, and iv) less torsional vibration (stick/slip). Compared to traditional roller cone bits, they have – i) increased rate of penetration (ROP) potential, ii) less axial vibration (bit bounce), and iii) lower weight on bit requirement. 

7.4 Drill String Design he objective of designing the drill string is to obtain the optimum size and length of diferent drill string components in terms of durability and cost efectiveness. An iterative approach is usually applied due to the inherent complexity of the problem. In general a design model is initially assumed. Based on the initial consideration, the components of the drill string are selected, and then incorporating factors that were overlooked during the irst step reines the design. During the design, a good knowledge of drill string performance properties (available sizes, grades, etc.), previous history of drilling in similar conditions, and also costs associated with drill string

Basics of Drill String Design 345 components. he following design criteria should be considered while designing the drill string. 1. Design involves the determination of: a. Length b. Weight c. Grades 2. Factors afecting the design: a. Hole or depth size b. Mud weight c. Safety factor d. Length/weight of DC e. DC sizes 3. Design should be tested for the following criteria: a. Tension b. Collapse c. Critical speed d. Shock loading e. Torsion f. Stretch 4. Design should follow the following procedure a. Tension b. Collapse c. Others (if necessarily) However, there are some other major standards that need to be satisied at the inal stage of the design. hese criteria are: i) the load capacity divided by a SF of any drill string component should be greater than or equal to the maximum permissible load, ii) the neighbouring elements must be well-suited which is accomplished by selecting elements with an appropriate bending-stress ratio, iii) the drill string geometric properties should be selected in conjunction with an optimal hydraulic and casing program, iv) in deviated wells, drill string rotation should not produce excessive wall and casing damage, and v) a minimum level of the cost of the string should be maintained. In summary design of drill string means determination of length, weight, grades of drill pipe to be used during drilling, coring or any other operation which depends on hole depth, hole size, mud weight, safety factor and/or margin of pull (MOP), length and weight of DCs, and drill pipe size. he design factors such as tension, collapse, and other factors – shock loading, torsion, stretch of pipe, and critical rotating speed need to be considered. he main factors considered in the selection of drill strings are i) the collapse load, and ii) the tensile load on the drill pipe. Burst pressures are not generally considered since these only occur when pressuring up the string on a plugged bit nozzle or during a DST. However, it is very unlikely that the burst resistance of the pipe will be exceeded. Torsion is not needed to be considered except in a highly deviated well. Once the collapse and tension loads have been quantiied, the appropriated weight and grade of the drill pipe can be selected.

346 Fundamentals of Sustainable Drilling Engineering In general, a graphical approach to drill string design is recommended. If one section of the string does not meet requirements, it must be upgraded. he procedure can be listed as – i) choose a weight and grade of pipe to satisfy the collapse conditions, ii) using the pipe chosen in (i), calculate the tension loading, including buoyancy efects, iii) draw the tension loading line and also the maximum allowable load line, iv) modify the tension load as given in (ii) by applying a design factor, MOP etc., v) generate three design lines, vi) if any of these design lines exceed the maximum allowable load, a higher rated drill pipe must be used for that section of pipe, vii) calculate the new tension loading line for the new drill string and repeat steps (v) and (vi).

7.4.1

Collapse Load

Collapse pressure can be deined as a required external pressure that causes yielding of the drill pipe or casing. It can also be deined as the diference between external and internal pressure (Figure 7.30). he collapse pressure will occur if the drill pipe is empty (i.e. no mud). It develops due to the diference in pressure inside and outside of drill pipe (Figure 7.31a). In normal operation the mud column inside and outside the drill pipe are both equal in height and in density (Figure 7.31b). herefore zero diferential pressure across pipe body exists and thus no collapse happens. Normally, collapse pressure will happen during DST test.

Pc = 0

D X

(a)

(b)

(c)

Figure 7.31 Collapse pressure at diferent situations for a typical drill pipe.

outside

inside

outside

inside

D-X

Figure 7.30 Collapse pressure.

Basics of Drill String Design 347 he highest external pressure tending to collapse the drill string will occur at the bottom when the drill string is run empty into the hole. If a non-return valve is run, it is normally standard practice to i ll up the pipe at regular intervals when running in. he highest anticipated external pressure on the pipe can be written as: 0.052

PC

(7.1a)

LTVD

f

where, PC = collapse pressure, psi = density of luid outside the drill pipe, ppg f LTVD = total true vertical depth of the well at which PC acts, t. Equation (7.1a) can also be expressed as: PC

LTVD

f

(7.1b)

144

where, PC = collapse pressure, psi = density of luid outside the drill pipe, lb f / ft 3 f LTVD = true vertical depth at which PC acts, t. Equation (7.1) is based on the assumption that there is no luid inside the pipe to resist the external pressure. he collapse resistance of the drill pipe is given in Tables 7.4. he collapse resistance of the drill pipe is generally derated by a design factor (i.e. divide the collapse rating by 1.125). A suitable grade and weight of drill pipe must be selected whose derated collapse resistance is greater than Pc. his string must then be checked for tension. If there are diferent luids inside and outside the drill pipe, the diferential collapse pressures across the drill pipe prior to opening of the DST tool (Figure 7.31a) can be obtained as: pc where, D X inside outside

0.052 D

outside

0.052 D X

inside

(7.2)

= total depth of luid column or drill pipe, t. = depth of the empty drill pipe, t. = density of luid inside the drill pipe, ppg = density of luid outside the drill pipe, ppg

When luid density inside and outside the drill pipe is the same (Figure 7.31b), i.e. outside

inside

pc

0.052 D

(7.3)

When the drill pipe is completely empty, X = 0, and inside 0, the diferential collapse pressures across the drill pipe would be the maximum collapse pressure (Figure 7.31c) and hence Eq. (7.2) can be reformed as: pc

max

0.052 D

outside

(7.4)

348 Fundamentals of Sustainable Drilling Engineering A safety factor in collapse can be determined by SF

Collapse resistance Collapse pressure pc

(7.5)

Normally a safety factor of 1.125 is considered for the collapse rating. In general the drill pipe is subjected to biaxial loading due to the combined loading of tension and collapse. Due to the biaxial loading, the drill pipe is stretched resulting in a decrease in its collapse resistance. Burst pressure develops when the internal pressure is higher than that of the external pressure. It can be rated as: pb

Internal pressure External pressure

(7.6)

where, pb = burst load or pressure, psi A safety factor in burst can be determined by SF

Burst rating Allowable burst

(7.7)

7.4.2 Tension Load he tensile strength of the drill pipe is shown in Table 7.4. he tension loading can be calculated from the known weights of the drill collars and drill pipe below the point of interest. he efect of buoyancy on the drill string weight, and therefore the tension, must also be considered. Buoyancy forces are exerted on exposed horizontal surfaces and may act upwards or downwards. hese exposed surfaces occur where there is a change in cross-sectional area between diferent sections (Figure 7.32). he load calculation can be started at the bottom of the drill string and worked up to the top. he tension loading can be determined for each depth. his is represented graphically by the tension loading line (Figure 7.32). If the drill pipe is to remain in tension throughout the drilling process, drill collars need to be added to the bottom of the drill string. he buoyant weight of the drill collars must exceed the buoyant force on the drill pipe. In addition, the neutral point shown in Figure 7.32 must be within the length of the drill collars. Drill collars are required to maintain the drill string in tension because the function of the drill collars is to provide WOB. When selecting the drill pipe, the maximum tensile loads that the string could be subjected to need to be considered. In addition to the design load calculated on the basis of the string hanging freely in the wellbore, some other safety factors and margins are generally added: i) design factor - it is generally added to the loading line calculated above (in general, multiply by 1.3) which allows for extra loads due to rapid acceleration of the pipe, ii) margin of overpull (MOP) - it is generally added to the loading line because this allows for the extra forces applied to the drill string when pulling on stuck pipe. Tabulated API properties should be considered for designing tension. he magnitude depends on mud density and steel density where submerged weight should be considered. In general steel density is considered 489.5 lbm/t.3 or 65.5 lbm/ gal or 7850 kg/m3.

Basics of Drill String Design 349 To provide an added safety factor, only 80–90% of the yield strength tabulated is generally used for the drill pipe. herefore, the weight and length of the drill pipe can be calculated using the load balance of the drill string as: 0.9 × drill pipe yield strength = weight of DP + weight of DC + weight of HWDP + MOP

(7.8)

where, MOP = margin of overpull or maximum overpull on the drill string by the drawworks, lbf MOP is the minimum tension force above expected working load to account for any drag or stuck pipe. he typical MOP value ranges from 50,000 – 100,000 lbs. Maximum overpull should not exceed 80% of tensile strength of weakest drill pipe section in the drill string. Mathematically, Eq. (7.8) can be written as: 0.9 Pd

LdpWdp LdcWdc LHdpWHdp B f

(7.9)

MOP

Here, Pd = drill pipe yield strength or design weight, lbf Ldp = length of drill pipe, t. Ldc = length of drill collar, t. LHdp = length of heavy weight drill pipe, t. Wdp = nominal weight of the drill pipe, lbf/t. Wdc = nominal weight of the drill collar, lbf/t. WHdp = nominal weight of the heavy weight drill pipe, lbf/t. B f = buoyancy factor, fraction = 1 m / s = mud density, lbm/gal m = density of steel, lbm/ t.3 s Compression(-)

Tension (+)

D Drill Pipe

D

w2 f2 C

A f1

B

Drill Collars

B

w1

C

A

f1

Figure 7.32 Axial Load distributions on the Drill String.

** Not API standard: shown for information only.

Collapse Pressure Internal Yield Pressure Tensile Strength Internal Internal weight Size of per foot Diameter Diameter outer D E G** S.135** at Full (in.) with Diameter D E G** S.135** D E G** S.135 1,000 1,000 1,000 1,000 Upset Coupling (in.) (psi) (psi) (psi) (psi) (psi) (psi) (psi) (psi) (lbf) (lbf) (lbf) (lbf) (in.) (lbf) 2 3⁄8 4.85 1.995 1.437 6,850** 11,040 13,250 16,560 7,110** 10,500 14,700 18,900 70 98 137 176 6.65 1.815 1.125 11,440 15,600 18,720 23,400 11,350 15,470 21,660 27,850 101 138 194 249 2 3⁄8 6.85 2.441 1.875 – 10,470 12,560 15,700 – 9,910 13,870 17,830 – 136 190 245 2 7⁄8 2 7⁄8 10.40 2.151 1.187 12,770 16,510 19,810 24,760 12,120 16,530 23,140 29,750 157 214 300 386 1 9.50 2.992 2.250 – 10,040 12,110 15,140 – 9,520 13,340 17,140 – 194 272 350 3 ⁄2 3 1⁄2 13.30 2.764 1.875 10,350 14,110 16,840 21,170 10,120 13,800 19,320 24,840 199 272 380 489 15.50 2.602 1.750 12,300 16,770 20,130 25,160 12,350 16,840 23,570 30,310 237 323 452 581 3 1⁄2 4 11.85 3.476 2.937 – 8,410 10,310 12,820 – 8,600 12,040 15,470 – 231 323 415 4 14.00 3.340 2.375 8,330 11,350 14,630 17,030 7,940 10,830 15,160 19,500 209 285 400 514 13.75 3.958 3.156 – 7,200 8,920 10,910 – 7,900 11,070 14,230 – 270 378 486 4 1⁄2 4 1⁄2 16.60 3.826 2.812 7,620 10,390 12,470 15,590 7,210 9,830 13,760 17,690 242 331 463 595 1 20.00 3.640 2.812 9,510 12,960 15,560 19,450 9,200 12,540 17,560 22,580 302 412 577 742 4 ⁄2 5 16.25 4.408 3.750 – 6,970 8,640 10,550 – 7,770 10,880 13,960 – 328 459 591 5 19.50 4.276 3.667 7,390 10,000 12,090 15,110 6,970 9,500 13,300 17,100 9 396 554 712 5 1⁄2 21.90 4.778 3.912 6,610 8,440 10,350 12,870 6,320 8,610 12,060 15,500 321 437 612 787 24.70 4.670 3.500 7,670 10,460 12,560 15,700 7,260 9.900 13,860 17,820 365 497 696 895 5 1⁄2 19.00** 4.975 4.125 4,580 5,640 – – 5,090 6,950 – – 267 365 – – 5 9⁄16 5 9⁄16 22.20** 4.859 3.812 5,480 6,740 – – 6,090 8,300 – – 317 432 – – 9 25.25** 4.733 3.500 6,730 8,290 – – 7,180 9,790 – – 369 503 – – 5 ⁄16 6 5⁄8 22.20** 6.065 5.187 3,260 4,020 – – 4,160 5,530 – – 307 418 – – 25.20 5.965 5.000 4,010 4,810 6,160 6,430 4,790 6,540 9,150 11,770 359 489 685 881 6 5⁄8 6 5⁄8 31.90** 5.761 4.625 5,020 6,170 – – 6,275 8,540 – – 463 631 – – * Collapse, internal yield and tensile strengths are minimum values with no safety factor. D.F.G.S–135 are standard steel grades used in drillpipe.5

Table 7.4 Dimensions and Strength of API Seamless Internal Upset Drill Pipe.

350 Fundamentals of Sustainable Drilling Engineering

Basics of Drill String Design 351 From Eq. (7.9), the total weight carried by the top joint of drill pipe is given by Pa

(7.10a)

LdpWdp LdcWdc LHdpWHdp B f

If we use safety factor, Eq. (7.10a) can be written as: Pa

LdpWdp LdcWdc LHdpWHdp B f

(7.10b)

SF

Here, Pa = actual weight or total weight carried by the top joint, lbf To provide an added safety factor of 90%, the theoretical yield strength can be calculated as: Pt

0.9 Pd

(7.11)

Here, Pt = theoretical yield strength, psi If Pa < Pd, then pipe is ok for tension. In general, the diference between Pt and Pa gives the MOP. he ratio of Eq. (7.11) and Eq. (7.10) gives the safety factor (SF) as: SF

Pt Pa

0.9 Pd

(7.12)

LdpWdp LdcWdc B f

Safety factor is normally in the range of 1.1–1.3. It is noted that SF is not applied for heavy weight drill pipe. In such case, Eq. (7.9) can be written in terms of SF as: 0.9 Pd

LdpWdp LdcWdc B f

SF LHdpWHdp B f

MOP

(7.13)

hus length of the drill pipe can be found by rearranging Eq. (7.13) as: Ldp

0.9 Pd MOP SF Wdp B f

Wdc L Wdp dc

WHdp LHdp Wdp SF

(7.14a)

If we do not consider SF, length of the drill pipe can be found by rearranging Eq. (7.9) as: Ldp

0.9 Pd MOP Wdp B f

Wdc L Wdp dc

WHdp Wdp

LHdp

(7.14b)

If dual-grade drill pipe is used at diferent section of drill string, the length of drill pipe is calculated as: Ldp2

0.9 Pd MOP SF Wdp2 B f

Wdp1 Wdp2

Here, Ldp1 = length of drill pipe grade 1, t. Ldp2 = length of drill pipe grade 2, t.

Ldp1

Wdc L Wdp2 dc

WHdp LHdp Wdp2 SF

(7.15)

352 Fundamentals of Sustainable Drilling Engineering Wdp1 = nominal weight of the drill pipe grade 1, lbf/t. Wdp2 = nominal weight of the drill pipe grade 2, lbf/t. A tapered string is designed by irst considering the lightest available grade and selecting its maximum useable length as a bottom section. Successive heavy grades and their usable lengths are selected in turn. Example 7.1: A drill string needs to be designed based on the information given here. It is noted that the outer diameter of the drill pipe is 5 , total vertical depth is 12,000 and mud weight is 75 lbf/t.3 (i.e. 10 ppg). Total MOP is 100,000 lbs and the design factor, SF = 1.3 (tension); SF = 1.125 (collapse). he bottomhole assembly consists of 20 drill collars with an outer diameter of 6.25 and an inner diameter of 2.8125 where the weight of drill collar is 83 lbf/t. and each collar is 30 t. long. In addition, you need to consider the length of slips is 12”. Solution: Given data: dodp = outer diameter of drill pipe = 5 in LTVD = total vertical depth = 12,000 t. = mud weight = 75 lbf/t.3 (10 ppg) m MOP = margin of pull = 100,000 lbs = design factor of safety for tension = 1.3 SFT = design factor of safety for collapse = 1.125 SFc = number of drill collar = 20 Ndc dodc = outer diameter of drill collar = 6.25 in didc = inner diameter of drill collar = 2.8125 in Wdc = weight of the drill collar = 83 lbf/t. = length of drill collar = 30 t. Ldc = length of slips = 12 in Lslips Required data: Design the drill string For Collapse loading: If the total vertical depth is 12,000 t., and the mud density is 10 ppg, then collapse pressure can be calculated using Eq. (7.1a) as: PC

0.052 LTVD

m

0.052 12,000 ft 10 ppg

6,240 psi

If we use 75 lb f / ft 3 mud, collapse pressure can be calculated using Eq. (7.1b) as: PC

LTVD m 144

12,000 ft 75 lb f / ft 3 144 in2 / ft 2

6,250 psi

Applying SF for collapse, PC 6,250 psi 1.125 7,031 psi Now from Table 7.4, choose 19.50 lbf/t. for 5” and we select Grade D for which ID = 4.276”.

Basics of Drill String Design 353 For Tension loading: f

BF 1

75 lb f / ft 3

1

490 lb f / ft 3

s

0.847

Now if we apply Eq. (7.10b) to calculate actual weight or total weight carried by the top joint, it becomes as: Pa

MOP

LdpWdp LdcWdc

BF SFT

100,000 12,000 20 30 400,000 lb f

19.5

20 30

83

0.847 1.3

From Table 7.4, for 5” and 19.5 lbf/t. drill pipe, Pt = 396,000 lbf for Grade E and = 290,000 lbf for Grade D Decision: We need to select Grade E instead of Grade D because of the huge diference in tensile strength. However, as long as the actual weight is greater than the theoretical yield strength (i.e. P >Pt), the selected design of Grade E is not OK and needs to be veriied again. As the chosen grade is not ok, let us choose the next grade which is 5 ½ outer diameters. For this grade, let us choose the weight of the drill pipe as 21.90 lbf/t. and grade E for which the tensile yield strength is 437,000 lbf. Now, apply the chosen grade for the entire pipe. For Tension and Compression loading (Figure 7.33): At 12,000 t. i.e. the bottom of DC: 0.052 LTVD

PdC _ bottom

m

0.052 12,000 ft 10 ppg

6,240 psi

Cross sectional area of DC: Referring to Figure 7.33, AdC _ bottom F1_ bottom

4

2 dOd did2

4

6.252 2.8122

24.47 in2

PdC _ bottom AdC _ bottom 6,240 24.47 152,692.8 lbs W1_ dc LdC 20 30 83 49,800 lbs dc

So, tension at the bottom of the collar at point 1 = F1_ bottom = 152,692.8 lbs (Tension) At 11,400 t. i.e. the top of DC: AdC _ top

2 dOd did2

6.252 5.02

4 PdC _ top

4

0.052 LTVD

F2 _ top

PdC _ top

m

outer

2 dOd did2

4.2762 2.81252

inner

19.19 in2

0.052 11, 400 ft 10 ppg

AdC _ top

5,928 psi

5,928 19.19 113,758 lbs

354 Fundamentals of Sustainable Drilling Engineering W2 _ dc

Ldp

dp

11, 400 ft 19.5

222,300 lbs

So, tension at the top of the collar at point 2 = F1_ bottom W1_ dc = (–152,692.8 + 49,800) lbs = 102,892.8 lbs (Compression) At 11,400 t. i.e. the bottom of the DP (Point 3): 2 d2 d2 dOd did2 19.19 in2 inner 4 Od id outer 0.052 LTVD m 0.052 11, 400 ft 10 ppg 5,928 psi

Adp _ bottom Pdp _ bottom F3 _ bottom

Pdp _ bottom

W3 _ dp

Ldp

Adp _ bottom dp

5,928 19.119 113,758.0 lbs

11, 400 ft 19.5

222,300 lbs

So, tension at the bottom of the drill pipe at point 3 = T2dp dc

F3_ bottom

= ( 102,892.8 + 113,758) lbs = 10,865.2 lbs (Tension) At the top of the DP (Point 4): W4 _ dp F4 _ top

Ldp

dp

11, 400 ft 19.5

222,300 lbs

tension at the bottom of the drill pipe at point 3 T3

10,865.2 lbs

So, tension at the top of the drill pipe at point 4 = W4 _ dp F4 _ top = 222,300 lbs 10,865.2 lbs = 233,165.2 lbs (Tension) Total weight carried by top joint 4

400,000

Compression(-) 200,000 0

Tension(+) 200,000

Drill pipe = 11,400 ft

0

6,000

1

Drill Collar = 20 x 30 ft =600 ft

2 3

12,000

Figure 7.33 Axial Load distributions on the Drill String for Example 7.1.

400,000

Basics of Drill String Design 355 Maximum allowable load: If we assume that 85% of theoretical load can be allowed to carry by the drill string, then the maximum allowable load is: W4 _ dp

0.85 Pt

0.85 396,000 lbs

335,750 lbs

he total weight carried by the top joint, 400,000 lbs and as the maximum allowable load is 335,750 lbs, therefore a diferent size of the drill pipe need to be selected for at least 1,200 t. (Figure 7.34). From Table 7.4, for 5.5” and 21.90 lbf/t. drill pipe, Pt = 437,000 lbf for Grade E. this grade can be selected up to 1,200 t. Decision: We may choose the next grade for only the irst 1,200’ 0 – 1,200 t. : Grade E, 21.90 lbf/t. 200 – 12,000 t. : Grade E, 19.5 lbf/t. Check the new Grade: Now if we apply again Eq. (7.10b) to calculate actual weight or total weight carried by the top joint, it becomes: Pa Pa

100,000

MOP

1,200 21.5

LdpWdp LdcWdc

10,800 20 30

BF SFT

19.5

20 30

83

0.847 1.3

402,251.95 lb f Table 7.4 shows, Pt = 437,000 lbf/t, and inally it shows that Pa < Pt. herefore, the design is ok and this is the inal design decision. Total weight carried by top joint 400,000

4

Compression(–) 200,000 0

Tension(+) 200,000 400,000

0

6,000

3

1

Drill Collar = 20 x 30 ft = 600 ft

2

335,750 lbs Maximum allowable load

Drill pipe = 11,400 ft

1,200

12,000

Figure 7.34 Axial Load and maximum load distributions on the Drill String for Example 7.1.

356 Fundamentals of Sustainable Drilling Engineering

7.4.3 Other Design Factors Shock Load: It arises between slip area set and the moving drill pipe. When a moving drill pipe is suddenly stopped by setting slips, shock load develops. he additional tensile force generated due to this shock load can be obtained as (7.16)

3,200 Wdp

Fs

Here, Wdp = weight of drill pipe per unit length, lbf/t. Torsion: Torsion in a drill string is produced by a twisting moment. his moment is called torque which results in a shear or torsional stress and an angle. he shear stress and the diferential angle of twist can be calculated as:

d t dz

Here T r di do Ip Es E

t

Tr Ip

(7.17)

T Es I p

(7.18)

= shear or torsional stress, psi = torque, in-lbf = distance from the center of the drill pipe to a point under consideration di 2r do , in = inside diameter of drill pipe, in = outside diameter of drill pipe, in do4 di4 , in4 = polar moment of inertia = 32 E = shear modulus of elasticity = 21 = Young’s modulus of elasticity, psi = Poisson’s ratio, (the ratio of transverse contraction strain to longitudinal extension strain in the direction of stretching force. = angle of twist, radian

trans

)

longitudinal

d t = diferential angle of twist, in–1 dz he maximum shear stress occurs at the outer ibre of the pipe, and for this case Eq. (7.17) can be written as: 16 doT max

where Z p = polar sectional modulus, psi

do4

di4

T Zp

(7.19)

Example 7.2: A drill string has 3000 t. long, and 5.5 in outer diameter drill pipe. While the pipe was moving, it was suddenly stopped. A torque of 200 lbf-in is applied which

Basics of Drill String Design 357 develops torsional stress and angle at a distance of 5.124 from the center of the pipe. Assume that the Young’s modulus of elasticity for steel is 29 106 psi and Poisson’s ratio is 0.44. Find out the shock load, torsional stress, maximum shear stress and diferential angle of twist. Solution: Given data: dodp = outer diameter of drill pipe = 5.5 in Ldp = total drill pipe length = 3,000 t. T = torque = 200 in-lbf r = distance from the center of the drill pipe to the point = 5.124 in E = Young’s modulus of elasticity = 29,000000 psi = Poisson’s ratio = 0.44 wdp = weight per feet = 21.9 lbf/t. From Table 7.4, didp = inner diameter of drill pipe = 4.778 in wdp = weight per feet = 21.9 lbf/t. Required data: = shear or torsional stress in psi Fs = shock load in lbf d t = diferential angle of twist, in–1 dz Applying Eq. (7.16), shock load can be calculated as: Fs

3,200 Wdp

3,200

210.24 ×106 psi

3,000 21.9

he shear stress can be calculated using Eq. (7.17) as: Tr Ip

200 lb f 32

in do4

5.124 in di4

200 lb f 32

5.5

4

in

5.124 in

4.778

4

in

26.5

4

lb f in2

26.5 psi

he diferential angle of twist can be calculated applying Eq. (7.18) as: d t dz

T Es I p

200 lb f

T E 21 7

32

5.14 ×10 in

do4 di4

in

29,000000 psi 5.54 4.7784 2 1 0.44 32

1

he maximum shear stress is calculated by Eq. (7.19) as: 16 doT max

do4 di4

16 5.5 in

200 lb f

5.54 4.7784

in in4

17, 600 psi

in4

358 Fundamentals of Sustainable Drilling Engineering he torque developed in the drill string can be calculated if the horsepower required to rotate the string is obtained by recalling Eq. (2.1) for a given rpm as: T

5252 HPds N

(7.20)

where HPds = horsepower required to turn the rock bit and drill string, hp N = drill string rotary speed, rev/min T = torque, t.-lbf he horsepower required to rotate the drill pipe is given as: HPdp

Cd do2 NLdp

(7.21)

m

Here HPp = horsepower required to rotate the drill pipe, hp Cd = an empirical factor that depends on hole inclination angle (0.000048 – 0.00000665 for hole angles ranging from 3 to 5°) = specii c gravity of mud m Example 7.3: While drilling, 250 hp was applied to rotate the drill string and bit where 500 rpm was recorded from the rotary speed machine. In addition, 175 hp was applied to rotate 3,500 t. of drill pipe of 5 in OD with the same speed as drill string. Assume that Cd = 0.000005. Calculate the required torque for drilling string and the speciic gravity of mud. Solution: Given data: HPds = horsepower required to turn the rock bit and drill string = 250 hp N = drill string rotary speed = 500 rev/min HPp = horsepower required to rotate the drill pipe = 175 hp Cd = an empirical factor that depends on hole inclination angle = 0.000005 Ldp = length of drill pipe = 3,500 t. Cd = outer diameter of drill pipe = 5 in Required data: T = torque in t.-lbf = speciic gravity of mud m Applying Eq. (7.20), the torque developed in the drill string can be calculated as: T

5252 HPds N

5252

250 hp

500 rpm

2626 lb f

in

he speciic gravity of mud is calculated using Eq. (7.21) as: HPdp m

Cd do2 NLdp

175 hp 2

0.000005 5 in2 500 3,500 ft

0.8

Basics of Drill String Design 359 he following two equations can be used to calculate the maximum allowable makeup torque before the minimum torsional yield strength of the drill pipe body is exceeded. In such case, Eq. (7.19) can be rearranged and written for torsional yield strength due to pure tension as: Qmin

0.096167 I pYmin

(7.22)

do

Here, Qmin = minimum torsional yield strength, t.-lbf Ymin = minimum unit yield strength, psi It is well established that during normal drilling operations, the drill pipe is subjected to both torsion and tension. hus Eq. (7.22) becomes: Qmin _ t

0.096167 I p do

2 Ymin

Wtj2 A2

(7.23)

Here, Qmin _t = minimum torsional yield strength under tension, lbf-t. Wtj = total load in tension or total weight carried by the top joint, lbf A = cross-sectional area, in2 Example 7.4: Find out the minimum torsional yield strength and torsional yield strength under tension for the following data: OD = 4.5 in, top joint load is 400,000 lbf. Assume that the ID of the pipe is 3.958 in. Use an E-grade pipe. Solution: Given data: Ip = horsepower required to rotate the drill pipe = 175 hp do = outer diameter of drill pipe = 4.5 in Wtj = total load in tension carried by the top joint = 400,000 lbf di = inner diameter of drill pipe = 3.958 in It is assumed that, Ymin = yield strength of drill pipe = 150,000 psi Required data: Qmin = minimum torsional yield strength in t.-lbf Qmin _t = minimum torsional yield strength under tension in lbf-t. he polar moment of inertia is calculated as: Ip

32

do4 di4

32

4.54 3.958 4

16.16 in4

he cross sectional area, A can be calculated as: A

4

do2 di2

4

4.52 3.9582

3.6 in2

360 Fundamentals of Sustainable Drilling Engineering Now, the minimum torsional yield strength is given applying Eq. (7.22) as: Qmin

0.096167 I pYmin

0.096167

16.16 in4

7,900 psi

4.5 in

do

2728.24 psi

he minimum torsional yield strength under tension is also given by Eq. (7.23): 0.096167 I p

Qmin _ t

do

2 Ymin

Wtj2

0.096167

16.16 in4

4.5 in A2 = 3506.76 lb f ft

1500002

400,0002 3.62

Note that the drill pipe weights given in tabular form are nominal weights used mainly for drill pipe classiication. hese tables are available in any petroleum engineering handbook or the book of Mitchell and Miska (2011). he calculation of the approximate weight of a drill pipe includes the approximate weight of the tool joint assembly. he following equations can be used to calculate the adjusted weight as: Wdp Here, Wdp Wdp Wdp

adj

Wdp

Wdp plain

upset

(7.24)

29.4

= approx. adjusted weight of drill pipe, lbf/t. plain = plain end weight, lbf/t. upset = upset weight, lbf/t.

adj

Now the approximate adjusted weight of the tool joint can be calculated as: Wtool joint Here, Wtool joint L do di dTE

0.222 L do2 di2

3 0.167 do3 dTE

0.501di2 do dTE

(7.25)

= approximate adjusted weight of the tool joint, lbf/t. = combined length of pin and box, in = outside diameter of pin, in = inside diameter of pin, in = diameter of box at elevator upset, in

Equation (7.24) can also be represented in terms of approximate adjusted weight of the tool joint and tool joint adjusted length as: Wdp

adj

Ltool joint

29.4

Wtool joint 29.4 Ltool joint

L 2.253 do dTE 12

(7.26) (7.27)

Here, Ltool joint = tool joint adjusted length, t. Stretch of Pipe: he stretch of drill pipe develops due to the action of drill collars and its own weight carried out by the hook. So, the drill pipe stretches under the action of

Basics of Drill String Design 361 drill collars and its own weight can be calculated separately as the elongation due to i) its own weight, and ii) drill collar’s weight Due to its own weight: In FPS system: L2dp 65.44 1.44 o

m

(7.28)

9.625 107

Here: o

Ldp m

= stretch due to own weight, in = total length of drill pipe, t. = mud density, ppg

In MKS system, Eq. (7.28) can be written as: 2.346 10 8 L2dp 65.44 1.44

o

m

(7.29)

Here: o

Ldp m

= stretch due to own weight, m = total length of drill pipe, m = mud density, kg/lt

Due to weight of drill collars: In FPS system: Ldc Ldp dc

735444 Wdp

Here: dc

Ldp Ldc Wdp Wdc

Wdc

(7.30)

= stretch due to drill collar, in = total length of drill pipe, t. = total length of drill collar, t. = weight of the drill pipe, lbf/t. = weight of the drill collar, lbf/t.

In MKS system, Eq. (7.30) can be written as:: dc

373.8 10

Here: dc

Ldp Ldc Wdp Wdc

10

Wdc L Ldp Wdp dc

(7.31)

= elongation due to drill collar, m = total length of drill pipe, m = total length of drill collar, m = weight of the drill pipe, kg/m = weight of the drill collar, kg/m

If tension is applied, Ldp Pdi t

p

735294 Wdp

(7.32)

362 Fundamentals of Sustainable Drilling Engineering Here: = stretch due to tension, t. t Pdi p = diferential pull, lbf Wdp = weight of the drill pipe, lbf/t. Example 7.5: A 10 ppg mud is circulated through a 5 in. drill pipe assembly of 8,000 t. If 50 drill collars of 30 t. long each are also used, calculate stretch for drill pipe and collar due to their own weight. Assume the OD and ID of drill collar as 6.25 in and 2.8125 in respectively and weight of drill collar is 93 lbf/t. In addition assume that a diferential pull of 1,000 lbf is applied on the drill pipe. Also, ind out the stretch due to tension. Solution: Given data: Ldp = total length of drill pipe = 8,000 t. dodp = outer diameter of drill pipe = 5 in didp = outer diameter of drill pipe = 4.408 in (Table 7.4) Wdp = weight of the drill pipe = 16.25 lbf/t. (Table 7.4) = mud density = 10 ppg m Ldc = total length of drill collar = 30 t. x 50 = 1,500 t. dodc = outer diameter of drill collar = 6.25 in didc = outer diameter of drill collar = 2.8125 in Wdc = weight of the drill collar = 93.0 lbf/t. Pdi p = diferential pull = 1,000 lbf Required data: = stretch due to own weight in inch o = stretch due to drill collar in inch dc = stretch due to tension in t. t he stretch due to drill pipe own weight can be given using Eq. (7.28) as: L2dp 65.44 1.44 o

m

9.625 107

80002 65.44 1.44 10 9.625 107

33.93 in

he stretch due to drill collar weight can be given using Eq. (7.30) as: Ldc Ldp dc

Wdc

735444 Wdp

1500 8000

93

735444 16.25

0.074 in

he stretch due to tension can be given using Eq. (7.32) as: Ldp Pdi t

p

735294 Wdp

8000 1000 735294 16.25

0.67 ft

Critical Rotating Speed: he components of a drill string can vibrate in three modes – axial or longitudinal, transverse or lateral, and torsional. Figure 7.35 shows these three types of vibration experienced during drilling. Axial action can be recognized at surface (Figure 7.35a) and transverse method is possible only with drill pipe (Figure 7.35b).

Basics of Drill String Design 363

Axial Vibration (a)

lateral Vibration (b)

Torsional Vibration (c)

Figure 7.35 Triaxial shock and vibration.

Torsional mode cannot be seen due to rotary table which controls of angular motion (Figure 7.35c). he vibration causes resonance and hence wears and fatigue. he pipe vibration should coincide with bit rotation. It is calculated based on drill string length and drill pipe dimensions or drill collar length. It is important therefore to review each element of vibration, their efects, methods of detection and actions to control the speciic vibration when encountered. Axial vibration occurs when it causes the bit and therefore the drill string to vibrate or bounce on the formation. It can be due to several things including variation on the WOB, changes in mud pressure and the interaction of the bit cutting structure on the formation i.e. interaction with stringers, ledges, hard rock formations etc. Bit bounce is typically encountered with roller cone bits, which exhibit an unstable bottomhole pattern. Lateral vibrations are experienced at right angles to the drill string and are commonly referenced as ‘bit whirl’ or ‘BHA whirl’ where the lateral vibration causes a bending vibration in the BHA. Whirl can manifest itself in both forward and backward directions. Torsional vibrations (stick slip) describe the situation where the drill string stops or slows down rotation to a point where the drill string torques up and rapid releases energy once the BHA and bit free up and begin rotation again. Due to the built up torque the string rotates signiicantly faster than the nominal rpm during the slip phase. Stick slip is caused largely by interaction with the formation and frictional forces between the drill string, BHA and the wellbore, environments that become increasingly common in highly deviated and deep wells. he longitudinal vibration based on total length and drill pipe dimensions can be calculated as: rpmLc Here: rpmLc

258,000 Ldp

= critical rpm for longitudinal vibration, rev/min

(7.33)

364 Fundamentals of Sustainable Drilling Engineering he transverse vibration can be calculated as: rpmTc Here: rpmTc

4760,000 2 do di2 Ldp

(7.34)

= critical rpm for transverse vibration, rev/min

Example 7.6: Find out the critical rpm for both longitudinal and transverse vibration if 5 in of 16.25 lbf/t., and 7,500 t. drill pipe. Solution: Given data: Ldp = total length of drill pipe = 7,500 t. dodp = outer diameter of drill pipe = 5 in didp = outer diameter of drill pipe = 4.408 in (Table 7.4) Wdp = weight of the drill pipe = 16.25 lbf/t. Required data: rpmLc = critical rpm for longitudinal vibration in rev/min rpmTc = critical rpm for transverse vibration in rev/min he critical rpm for longitudinal vibration can be given by Eq. (7.33) as: rpmLc

258,000 Ldp

258,000 7,500

34.4 rpm

he critical rpm for transverse vibration can be given by Eq. (7.34) as: rpmTc

4760,000 2 do di2 Ldp

4760,000 2 5 4.4082 7,500

1498 rpm

7.5 Bit Design he design features of the most widely used bits are the roller cone bits, and PDC bits. herefore, these two bits will be discussed here only.

7.5.1 Roller Cone Bits he design of roller cone bits can be described in terms of the four principle elements of the design. he following aspects of the design will be dealt with in detail. i. ii. iii. iv.

Cutting structure Fluid circulation Types of cones Bearing assemblies

Cutting Structure: he selection of a bit is mainly dependent on the hardness of the formation to be drilled. herefore, the design of the cutting structure will be based on the

Basics of Drill String Design 365 hardness of the formation. he main considerations in the design of the cutting structure are the height and spacing of the teeth or inserts. For sot formations, bits require deep penetration into the rock so the teeth are long, thin and widely spaced to prevent bit balling. Bit balling occurs when sot formations are drilled and the sot material accumulates on the surface of the bit preventing the teeth from penetrating the rock. For moderately hard formations, it needs a heavier load so teeth height is decreased and teeth width increased. he spacing of the teeth must be suicient to allow good cleaning. While drilling hard formations, bits rely on the chipping action and not on tooth penetration to drill. herefore, teeth are shorter and stubbier than comparing with sot formations. he teeth must be strong enough to withstand the crushing/chipping action and suicient numbers of teeth should be used to reduce the unit load. Here spacing is not critical sine ROP is reduced and the cuttings tend to be smaller. Fluid Circulation: Drilling luid passes from the drill string and out through nozzles in the bit. As it passes across the face of the bit, it carries the drilled cutting from the cones and into the annulus. he original design for rock bits only allow the drilling mud to be ejected from the middle of the bit (Figure 7.36). here are three jet nozzles used for eicient cleaning. Jet nozzles are small rings of standard outer diameter and various inner diameters. hey are made of tungsten carbide and diameters less than 7/32 are not recommended. Types of Cones: One of the basic factors that needs to be considered in the design of the cone is the journal or pin angle. Since all three cones it together, the journal angle speciies the outside contour of the bit. Bearing Assemblies: While designing the bearing assembly, the most important factor is space availability. Preferably the bearings should be large enough to support the applied loading. he inal design ensures that the bearings will not wear out before the cutting structure.

7.5.2 PDC Bits here are ive major components of a PDC bit that need to be considered during the design: i. ii.

Cutting materials Bit body materials Fluid

Fluid

Jet Nozzle Open Bearing

Jet Nozzle Sealed Bearing

Figure 7.36 Fluid circulation through bit nozzle (courtesy, uralbmt).

Fluid

Open Bearing

366 Fundamentals of Sustainable Drilling Engineering iii. iv. v. vi. vii.

Bit proile Fluid circulation Cutting rake Cutting density Cutting exposure

i) Cutting materials: Normally polycrystalline diamond material has 90 – 95% pure diamond that is set into the body of the bit. he PCD is formed by high temperatures (i.e. more than 1400°C) and pressures (i.e. more than 600,000 psi). ii) Bit body materials: he cutters of a PDC bit are mounted on a bit body. Normally two types of bit body are used for the PDC bit – steel body, and tungsten carbide matrix body. Steel body bit is cheaper but faces erosion problems. iii) Bit proile: Normally three basic types of crown proiles exist – lat or shallow cone, tapered or double cone, and parabolic. he lat cone proile evenly distributes with WOB between each of the cutters on the bit (Figure 7.37a). he taper cone proile allows increased distribution of the cutters toward the outer diameter of the bit (Figure 7.37b). As a result it achieves greater rotational and directional stability, which ultimately gives even wear. he parabolic proile gives a smooth loading over the bit proile and the largest surface contact area (Figure 7.37c). As a result, this type of bit gives even more rotational and directional stability and even wears compared to the taper cone proile. iv) Fluid Circulation: One of the most important design criteria is to have the ability to remove the cuttings and to cool the bit eiciently. his option is the same as the roller cone bit. In general, more than three jets are used on a PDC bit. v). Cutting Rake: he PDC cutter can be set at various rack angles. hese rack angles include back rake and side rake. he back rake angle determines the size of cutting that is produced and the side rake is used to direct the formation cuttings towards the lank of the bit and into the annulus. vi). Cutting Density: Is the number of cutters per unit area on the face of the bit. he cutter density is used to control the amount of load per cutter. vii). Cutting Exposure: Is the amount by which cutters protrude from bit body. It is necessary to ensure good cleaning of the bit face and mechanical strength.

7.6 Drilling Bit Selection he selection of a bit means a thorough examination of bit records from ofset well data. he best selection is by the trial-and-error method. he data and the bit design

(a)

(b)

Figure 7.37 PDC bit proiles (redrawn from Ford, 2005).

(c)

Basics of Drill String Design 367 should be examined, analysed and this information needs to be used to determine the characteristics of the best performing drill bits. Special care must be given to the details such as the premature failure of bits, reasons to pull bits, and dull characteristics of inserts (i.e. whether the inserts were worn or broken) etc. For example, a drill bit that had broken inserts clearly indicates that the formation should have been drilled with a much harder drill bit. here are some data required to select the correct bit such as projected lithology column with detailed description of each formation, drilling luid details, and well proile. When drilling directional wells, special attention should be given. he directional contractor should provide an assessment on required BHA changes, motor requirements and any limitations on bit operating parameters, which may efect the bit selection. In addition bit characteristics in terms of walk, build and drop tendencies need to be evaluated for their inluence on the well trajectory. Formation characteristics (drillability, and abrasiveness) and cost per foot analyses can help greatly in bit selection. he drillability of a formation is a measure of how easily the formation is to drill. It is inversely proportional to the compressive strength of the rock formation. Drillability generally decreases with depth in a given area. Abrasiveness of a formation is a measure of how rapidly the teeth of the milled-tooth-bit will wear when drilling the formation. Abrasiveness generally increases as drillability decreases. In summary, bit selection criteria depend on the following two situations: i) Situation-1: bit records for a formation are not available, and ii) Situation-2: bit records for a formation are available.

7.6.1 Situation-1: When Bit Records are Not Available Several Rules of humb are oten used for initial bit selection: Rules of humb #1: If the formation hardness is known, then use the IADC Charts (available in any handbook of IADC), or Bourgoyne et al., (1986). Table 7.5 shows the bit types oten used in various formation types. Rules of humb #2: Bit cost consideration plays a vital role for selecting initial bit type and features. Rules of humb #3: Selection of tri-cone roller bits. his is a good choice for an initial bit type, which is used for the shallow portion of the well. TCR bits are most versatile. In addition, use the longest tooth size possible. Rules of humb #4: Selection of diamond bits which perform best in non-brittle formations (having a plastic mode of failure) and bottom portion of well (due to longer bit life, minimizes high-cost tripping operations). Rules of humb #5: Selection of PCD drag bits, which perform best in uniform sections of carbonate formations (without thin stringers of brittle rocks or hard shales). Rules of humb #6: PCD drag bits should not be used in gummy formations (gluey shales, tending to cause bit balling. Rules of humb #7: Carefully evaluate a dull bit when it is removed from the well. Maintain carefully well-written records of the performance of used bits for future references.

368 Fundamentals of Sustainable Drilling Engineering Table 7.5 Bit types oten used in various formation types (Bourgoyne et al., 1986). IADC bit classiication

Formation

1–1 1–2 5–1 6–2

Sot formations having low compressive strength and high drillability (sot shales, clays, red beds, salt, sot limestone, unconsolidated formations, etc.)

1–3 6–1

Sot to medium formations or sot interspersed with harder streaks (irm, unconsolidated or sandy shales, red beds, salt, anhydrite, sot limestone, etc.)

2–1 6–2

Medium to medium hard formations (harder shales, sandy shales, shales altering with streaks of sand and limestone, etc.)

2–3 6–2

Medium hard abrasive to hard formations (high compressive strength rock, dolomite, hard limestone, hard slaty shale, etc.)

3–1 7–2

Hard semiabrasive formations (hard sandy or chert bearing limestone, dolomite, granite, chert, etc.)

3–2 3–4 8–1

Hard abrasive formations (chert, quartzite, pyrite, granite, hard sand rock, etc.)

7.6.2 Situation-2: When Bit Records are Available Bit selection and evaluation is easier when bit performance records in a formation are available. he most valid criterion for comparing the performance of various drill bits is the drilling cost per foot drilled. he drilling cost per foot formula presented in Chapter-11 can be used for this purpose. Since no amount of arithmetic allows us to drill the same section of hole more than once, we must compare between succeeding bits in a given well, or, between bits used to drill the same formation in a diferent well.

7.7 Drilling Bit Performance he performance of the bit can be evaluated based on the criteria such as how far it drilled, how fast it drilled (ROP), how much it costs to run per foot of the hole drilled. he drilling cost analysis will be presented in Chapter 11. Since ROP is one of the most signiicant factors in the assessment of bit performance, it is discussed in detail only for two bit types, roller cone bit and PDC bit.

7.7.1 Roller Cone Bits To evaluate the bit performance of a roller cone bit, ROP plays a vital role, which depends on 1) weight on bit (WOB), 2) rotary speed (RPM), 3) mud properties, and 4) hydraulic eiciency.

Rate of penetration (ROP), ft/hr

Basics of Drill String Design 369

Threshold WOB

Weight on bit (WOB), lbs

Rate of penetration (ROP), ft/hr

Figure 7.38 Linear variation of rate of penetration over weight on bit in a log-log plot.

High HPH at bit Medium HPH at bit Threshold WOB

Low HPH at bit

Weight on bit (WOB), lbs

Figure 7.39 Nonlinear variation of rate of penetration due to hole cleaning over weight on bit in a loglog plot.

1. Weight on Bit A certain minimum WOB is required to overcome the compressibility of the formation (Figure 7.38). Experimental study shows that once this threshold is exceeded, ROP increases linearly with WOB. However there are certain limitations to the WOB which can be applied to hydraulic horsepower (HPH) at the bit, type of formation, hole deviation, bearing life, tooth life etc. i) Hydraulic Horsepower: If the hydraulic horsepower is not suicient to ensure good bit cleaning, the ROP is reduced either by bit balling, or by bottomhole balling. If this condition arises, there would not be any increase in ROP due to an increase in WOB. herefore, it is necessary to improve the HPH by other means. Figure 7.39 shows an increased ROP with WOB where the HPH generated by the luid lowing through the bit is improved. he HPH at the bit is given by: HPH

PbnQbn 1714

(7.35)

Here, Pbn = pressure drop across the nozzles of the bit, psi Qbn = low rate through the bit, gpm Practically, HPH can be improved by increasing Pbn , which is done by designing smaller nozzles. Hydraulic horsepower can also be increased by increasing bn, which means

370 Fundamentals of Sustainable Drilling Engineering faster pump speed or larger liner. his may cause a radical change to other drilling factors such as annular velocity, which may not be beneicial. Hole cleaning may be improved by using extended nozzles to bring the luid stream nearer to the bottom of the hole. ii) Type of Formation: Sometimes WOB cannot be increased in sot formations. he excessive weight will only bury the teeth into the rock and result increased torque. Ultimately it will not improve ROP increment. iii) Hole Deviation: In some areas, WOB will produce bending in the drill string, leading to a curved hole. he drill string should be properly stabilized to prevent this happening. iv) Bearing Life: An increase in WOB reduces the operational life of the bearing. herefore, optimizing ROP will depend on a compromise between WOB and bearing wear. v) Tooth Life: WOB is oten limited in sot formations, where excessive weight will only bury the teeth into the rock and cause increased torque, with no increase in ROP. 2. Rotary Speed An optimum speed must be determined because ROP is afected by the rotary speed of the bit. he RPM inluences the ROP since the teeth must have time to penetrate and sweep the cuttings into the hole. Figure 3.40 shows how ROP varies with RPM for diferent formations. he non-linearity in hard formations is due to the time required to break down rocks of higher compressive strength. Experience is very important in selecting the correct rotary speed in any given situation. RPM is the function of type of bit and type of formation. i) Type of Bit: In general, lower RPMs are used for insert bits comparing with milled tooth bits. his is due to the allowance of more time to penetrate the formation by the inserts. he insert crushes a piece of rock and then forms a crack, which loosens the fragment of rock. ii) Type of Formation: Harder formations are diicult to penetrate which leads to maintain low RPM. A high RPM may cause damage to the bit or the drill string. 3. Mud Properties Mud properties play a vital role while drilling. hey create a hydrostatic balance around the cutting area to restrict an inlux of formation luids into the wellbore. In addition, due to the slide overburden pressure from the mud, they form the ilter cake on the wall of the borehole. his ilter cake prevents any further entry of mud into the formation. he overbalance and ilter cake also exists at the bottom of the hole where it afects the

Rate of penetration (ROP), ft/hr

Soft formation

Hard formation

Rotary speed (RPM)

Figure 7.40 Variation in the rate of penetration over rotary speed in a log-log plot.

Basics of Drill String Design 371 removal of cuttings. In addition, the ilter cake covers up the cracks and prevents mud pressure being exerted below the chip. he diferential pressure on the chip tends to keep the chip against the formation. his is known as the static chip hold down efect, which leads to lower down the penetration rates. Sometimes a dynamic chip hold down may occur because cracks form around the chip where mud enters the cracks to equalise the pressure. As a result, a pressure drop is created which tends to ix the chip against the bottom of the hole. Both static and dynamic hold down efects cause bit balling and bottomhole balling which can be prevented by ensuring correct mud properties. 4. Hydraulic Efficiency he efects of increased hydraulic horsepower at the bit are already explained earlier in section 7.7.1. Hydraulic eiciency is directly related to HPH. So it is recommended to allow a minimum low rate to ensure that the bit face is kept clean and the cutting temperature is kept to a minimum. his requirement for low rate may poorly afect the optimization of HPH.

7.7.2 PDC Bit To estimate the bit performance of a PDC bit, WOB, RPM, mud properties, and hydraulic eiciency are important. 1. Weight on Bit and Rotary Speed PDC bits tend to drill faster with low WOB and high RPM. hese bits require higher torque than roller cone bits. he general recommendation is to use the highest RPM that might be achieved. Although the torque is fairly constant in shale sections the bit will tend to dig in and torque up in sandy sections. When drilling in these sandy sections, or when the bit drills into hard sections and ROP drops, the WOB should be reduced. However, a constant bit weight should be maintained to produce a rotary torque at least equal to that of a roller cone bit. If there is a too low WOB, it will cause premature cutter wear, possible diamond chipping, and a slow ROP. 2. Mud Properties PDC bit works better in terms of best ROP when we use oil-based muds. However, a good deal of success has been achieved with water-based muds. he improved performance in oil-based muds is due to increased lubricity, decreased cutter wear temperature and preferential oil wetting of the bit body. he performance of PDC bits with respect to other mud properties is consistent comparing with roller cone bits. 3. Hydraulic Efficiency his is same as roller cone bits as stated earlier.

7.8 Drilling Optimization Techniques he fundamental concept of drilling needs to be understood before undergoing any optimization of parameters related drilling operations. In order to drill a well, three

372 Fundamentals of Sustainable Drilling Engineering factors have to be established simultaneously – i) a certain load has to be applied on the bit, ii) the bit has to be rotated, and iii) a drilling luid has to be circulated within the wellbore. So, making a hole for the recovery of underground oil and gas is a process that requires two major constituents – i) Man-power, and ii) Hardware systems. he manpower includes a drilling engineering group and a rig operator group. hey irst provides engineering support for optimum drilling operations, including rig selection, design of mud program, casing and cement programs, hydraulic program, drill bit program, drill string program and well control program. A rig operator group is responsible for the daily operations ater drilling begins. his group consists of a tool pusher and several drilling crews. On the other hand, the hardware systems which make up a rotary drilling rig are i) power generation system, ii) hoisting system, iii) drilling luid circulation system, iv) rotary system, v) well blowout control system, and vi) drilling data acquisition system and monitoring system. Managing all these ingredients in a cost efective way is very challenging. herefore, drilling optimization is widely used to maximize the drilling eiciency of oil and gas wells in a cost efect manner. Diferent computer sot wares, tools and equipment are used in the optimization process, such as, measurements while drilling (MWD), surface sensors, and computer sotware. In addition, experienced expert personnel play a vital role in the optimization process. In the recent years, drilling optimization techniques have been used to reduce drilling operation costs. Reducing the operation time, since time is always money in drilling operations would do this. he researchers in the drilling engineering ields are always looking for the prediction of unexpected events and optimizing the related parameters. he philosophy of optimization in drilling operation is using the record of the irst drilled wells as a basis and applying optimization techniques to reduce drilling costs for the next wells being drilled. Drilling optimization can be deined as a process that employs downhole and surface sensors, computer sotware, MWD, and experienced expert personnel – all dedicated to reduce trouble time and increase drilling eiciency (Paes et. al, 2005). It can also be deined as the provision of real-time data to expedite decision-making based on information transmitted from downhole (Bharadwaj and Vinayaka, 2013). he disadvantage of using conventional drilling optimization processes is the independence of real time data, which makes the optimization process ineicient. Real time and rig-site data should be used to make the optimization more accurate and eicient. he main parameter that should be looked into in the optimization process is the drilling time that can be optimized by increasing the penetration rate. he objective of optimizing drilling parameters in real time is to arrive to a methodology that considers past drilling data and predicts drilling trend advising optimum drilling parameters in order to save drilling cost and reduce the probability of encountering problems. Figure 7.50 provides the timeline of some important achievements in drilling optimization history. In the 1950s the scientiic period took place with expansion in drilling research. he optimization technique was irst applied in 1967, which has considerably reduced drilling costs. Ater the 1970s, rigs with full automation systems started to operate in oil and gas ields. Operator companies developed techniques of drilling optimization in the mid of 1980s. In the 1990s diferent drilling planning approaches were brought to identify the best possible well construction performance. Ater the 2000s real time operations support centers were built. In recent years drilling

Basics of Drill String Design 373 parameters are easily acquired, stored and transferred in real time and thus currently have become an important aspect of drilling technology.

7.8.1 History of Drilling Optimization A historical time line for drilling optimization is shown in Figure 7.41. One of the irst attempts for the drilling optimization purpose was presented in the study of Graham and Muench in 1959. hey analytically evaluated the weight on bit and rotary speed combinations to derive empirical mathematical expressions for bit life expectancy and for drilling rate as a function of depth, rotary speed, and bit weight. Galle and Woods (1963) produced graphs and procedures for ield applications to determine the best combination of drilling parameters. One of the most important drilling optimization studies was performed by Bourgoyne and Young (1974). hey proposed the use of a linear drilling penetration rate model and performed multiple regression analysis to select the optimized drilling parameters. hey used minimum cost formula, showing that maximum rate of penetration may coincide with minimum cost approach if the technical limitations were ignored. In the mid 1980s operator companies developed techniques of drilling optimization in which their ield personnel could perform optimization at the site referring to the graph templates and equations. In the 1990s diferent drilling planning approaches were brought to surface (Bond et al., 1996, Carden et al., 2006). New techniques identiied the best possible well construction performances. Later on “Drilling the Limit” optimization techniques were also introduced (Schreuder and Sharpe, 1999). Towards the end of the millennium real-time monitoring techniques started to take place, e.g. drilling parameters started to be monitored from of locations. A few years later realtime operations/support centres started to be constructed. Some operators proposed advanced techniques in monitoring of drilling parameters at the rig site. Following the early developments in rotary drilling system, groundbreaking developments in the latter years of the century took place. Highly inclined wells were drilled using rotary steerable; pressure controlled drilling techniques with acquisition of drilling parameters.

1952 Introduction of Jet type roller Cone bits

1963 Best Constant Weight and RPM, Galle & Woods

1959 First Drilling Optimization, by Graham and Muench 1950 Scientiic Period Expansion of Drilling Research Optimization of drilling start

1970 Rig Automation Period

1986 Real-Time Drilling Optimization (Manual), at the Rig Site Chevron

1974 Multiple Regression Spproach, by Bourgoyne

1991 Field Veriication of Drilling Models, by maidla and Ohara

2009

1950

Drilling Optimization Timeline

1999 Real-Time Data Monitoring in Ofshore Norway 2003 Real-Time Operating Centers, Shell & Halliburton

2008 Real-Time Data Transfer to Support Centers, by Stateoil Mitter et al.

2005 Real-Time Monitoring of Parameters, at the Site ExxonMobil Dupriest et al.

Figure 7.41 Time line for drilling optimization (Eren and Ozbayoglu, 2010).

2009 Real-Time Drilling Optimization by means of Mult. Regs.

374 Fundamentals of Sustainable Drilling Engineering

7.8.2 Parameters for Drilling Optimization Actual data is the only source of information to make a recommendation to optimize drilling operations. he parameters those of which could be collected from a drilling activity are as listed in Table 7.6. Each parameter to be collected from the rig site is going to have an impact on the overall optimization process. Data reliability and accuracy is very important, all of the data collecting sensors should be accurately calibrated and be signalling the correct magnitude of measurement. he success of drilling optimization is closely related with the quality of the recorded drilling parameters. he parameters recorded for drilling optimization are critically important to be representative of data they are meant to relect. he brief description of the drilling parameters is deemed necessary to be explained. Whenever the cost of drilling activity is reduced, the whole process is considered optimized. Optimization could be performed by means of adjusting the magnitude of two or more independent parameters. his could be achieved mainly by means of i) minimized cost per foot, and ii) minimizing problems. he cost of a drilling process could be minimized by means of working with optimized combination of controllable drilling parameters. Hole problems those of which are being generated due to ineficient parameter usage generally occurring at the rig sites could be avoided. Drilling optimization is considered that the rig equipment, BHA, and the bit to be used are already in the optimum selections. In order to achieve the objective of minimum cost drilling the bit should be prevented from damages when run into the hole.

7.8.3

Factors Afecting the Drilling Operations

here are parameters that signiicantly afect drilling operations. hese parameters are normally used for drilling optimization. herefore, it is important to know about those parameters. In general, drilling parameters may be broadly classiied under two types – i) rig and bit related parameters, and ii) formation parameters. he rig and bit related parameters can be controlled but the formation parameters have to be dealt with. he formation parameters recorded for drilling optimization are critically important to be representative of data they are meant to relect. Many drilling parameters afect the performance of the drilling operation. If they are not adjusted properly,

Table 7.6 Parameters from a drilling activity. WOB

Drill string Properties

RPM

Casing details

Pump parameters

Drilling luid properties

Depth

Torque

Inclination

Hook-load

Azimuth

LWD

ROP

MWD

Basics of Drill String Design 375 they will make the operation less economical. Rig and bit type parameters are broadly categorized as weight on bit or hook load, rotational speed (RPM), torque, and hydraulic parameters (i.e. Bit hydraulics) – low rates, density of drilling luid etc. However, WOB, RPM, low rate, bit hydraulics, and more importantly the type of bit are the most important drilling parameters afecting drilling operations because they are afecting rate of penetration (drilling speed) and the economics of drilling. he parameters that come under the formation type are local stresses, mineralogy, formation luids, rock compaction and abrasivity of formation. Beyond the above stated parameters, determining the rate of penetration is among the most sought ater parameters in drilling industry. his is due to the fact that it allows for optimization of drilling parameters to decrease drilling costs and enhance drilling process safety. Among the above factors, some of the parameters are discussed below. Weight on Bit: Represents the amount of weight applied onto the bit. It is the abbreviation for “Weight on Bit”. his load is then transferred to the formation which in turn is the energy created together with string speed that advances drill string. It is measured through the drilling line, usually by means of having attached a strain gauge, which measures the magnitude of the tension in the line itself, and gives the weight reading based on the calibration. his sensor measures a unique value, which is the overall weight (Hook-load) of the string including the weight of the block and Top Drive System (TDS). For all of these circumstances correct calibration is required in order to have proper reading for this drilling parameter. Field study shows through testing that doubling the bit RPM in 6,000-psi rock while keeping WOB constant resulted in 70% increase in ROP. However, doubling WOB, with RPM constant, resulted in 300% increase in ROP. Bit condition is very important as there is blunting while drilling progresses, which depends on the formation being drilled. RPM: his parameter stands for “revolutions per minute”. It represents the rotational speed of the drill string. With the invention of TDS, the reading is directly linked to the electronics of the unit itself. It is considered that the measurements for this parameter are accurate as long as the acquisition system set-up has been thoroughly made up. Torque: his parameter is the torque of the drill string while it is rotating. It is measured by means of TDS systems. Previously the readings for this parameter were relative. his parameter is going to be signiicantly important for inclined and highly deviated wellbores, which is also related with the wellbore cleaning issues. Pump Parameters: he pump parameters are composed of the liner size in use, pump strokes, and the pump pressure. In case there are two pumps working simultaneously all of the data for two of the pumps should be acquired. With the electric pumps the stroke is transmitted in the same way as RPM. he pressure at the pump in case of having been acquired could be compared with the reliability of the standpipe pressure. Pump pressure should always be greater than the standpipe pressure. he use of low meters could also be adapted for accurate low rate measurements. Depth: he value of depth, in other means the bit position is input in the mudlogging unit (MLU). he operator is the responsible for that. Usually it is linked to the position of the block, by means of the sensors located at the crown block. Inclination – Azimuth: hese two parameters are the responsibility of the directional driller. An eicient communication between the MLU and the measurements

376 Fundamentals of Sustainable Drilling Engineering while drilling (MWD) unit is to the beneit of these two parameters, which may be very important for wellbore stability considerations. ROP: his parameter is the most important parameter, since all of the calculations in this study are based on estimations of ROP. It is measured through the relative change of the position of the block in time. Accurate calibrations are very important in order to have a representative ROP parameter. String–Casing Properties: he string and casing properties are very important when the frictional pressure losses are to be calculated. Fluid Properties: Rheological properties and the density of the drilling luids are also among the very important parameters to be recorded for optimization purposes. Usually the drilling luid density is measured through calibrated mud weight (MW) sensors. Rheological properties on the other hand are still measured manually. Recent developments in regards to real-time pipe viscometers dictate alternative solutions. here are experimental studies performed in the laboratory using pipe-viscometers. Continuous real-time viscometer probes placed on the low line could facilitate data acquisition over the rheological properties of drilling luids in real-time. Logging While Drilling (LWD): Formation related parameters could be captured during drilling and be used in the optimization process. LWD consideration needs to be applied to enhance the optimization process.

7.8.4

How to Optimize the Drilling Operations

he optimization of the drilling performance, even more in a ield development context requires i) data acquisition, and ii) data processing. Data acquisition has the relevant measurement of drilling data such as WOB, RPM, torque, ROP and low rate. Some of these data are time dependent. Data processing is based upon relevant drilling data, the processing leads to drill bit response follow up with mechanical speciic energy (MSE), HMSE logs, and E/S Diagram, events identiication (steady drilling, vibrations, cleaning issue, wear development, and drilling response optimization (drilling parameters adaptation). he surface data allows tracking of the drilling behaviour. his is especially possible when the full bit design is known. In other cases, detailed information on the design needs to be provided (cutter distribution, orientation and position). Using the bit signature together with the GeoScan lithology, we can then assess on a real time basis the drilling performance. he wear phenomena can be tracked and a wear logs is created. he vibrations are also monitored using surface data, bit signature and predicted ROP. Two main services are provided in this regard i) real time service (RTS), and ii) next well service (NWS). he RTS provides the decision maker with the information needed to modify and optimize the drilling parameters in order to increase ROP, bit life and decrease vibrations. Pull out decisions can also be supported by this RTS. NWS uses the parameters logs recorded during drilling operation and electric logs. he lithology can also be reviewed and the ield mapped, well ater well. Lessons learned are gathered. his leads to the construction of a reference knowledge database (RKD). BHA components and bit design can then be adapted to improve performance for the next well. Guidelines are given to the drillers. Figure 7.42 summarizes the algorithmic steps, which should be followed consecutively to optimize drilling parameters of a hydrocarbon ield using mathematical

Basics of Drill String Design 377 Data preparation and validation

Comparative optimization method

Modeling penetration rate

Optimum drilling mud properties

Hydraulic optimization

Optimum bit selection

Modelling wear rate of selected bits

Determining maximum allowable mechanical horsepower

Specifying optimum bit weight/rotary speed to minimize cost per foot

Figure 7.42 Algorithm of the mathematical optimization procedure.

solutions. As shown in this igure, some of the comparative optimization results such as selection of optimal bit and mud properties will be employed in the numerical technique. Each step of this algorithm can be achieved by using the proper mathematical model for each parameter optimization.

7.8.5 Traditional Optimization Process he traditional optimization process consists of (i) pre-run modeling, (ii) real-time data measurement and monitoring, and (iii) post-run analyses and knowledge management. At the center of this process, the team members are the personnel who are expert in these technologies and who can make recommendations to avoid trouble and improve drilling performance. Generally, a comprehensive drilling optimization should include solutions for: i) drill string integrity, ii) hydraulics management, and iii) wellbore integrity. However, new drilling optimization technologies emphasize information management and real-time decision making. On the other hand, the traditional three-step optimization process will not it the real time process and has had to be changed. First pre-run modeling needs to be changed to “real-time modeling”. his change is required because the input parameters for pre-run models have typically been out-dated and incorrect. herefore, modeling results were oten of little use for real-time decision making. Second, integrated real-time modeling and data are required to allow

378 Fundamentals of Sustainable Drilling Engineering detailed diagnoses on the downhole environment. hird, a rig-to-oice integration is best so the optimization process can be monitored 24/7 by an asset team. hese three new technologies have been summarized by (Chen, 2004) as i) real-time modeling, ii) integrated real-time modeling and data, and iii) a real time operation center (RTOC). i) Real Time Modeling: he objective of optimizing drilling parameters in real time is to arrive to a methodology that considers – i) past drilling data, and ii) predicts drilling trend advising optimum drilling parameters. Real time optimization is needed in order to save drilling cost and reduce the probability of encountering problems. Conventional modeling is usually run during well planning to avoid a set of predicted data. As drilling processes, the input parameters may change intentionally or unintentionally. As a result, conventional, stand-alone computer sotware requires constant manual updating to produce pertinent results. Such a procedure, however, has proven to be impractical. In contrast, real-time modeling is automatically updated using “correct” input data, which is no doubt more accurate. In addition, real-time modeling is always “on” allowing continuous monitoring to prevent drilling accidents. Real time modeling also allows integration with real time data to enable real time decision making. To date, several real-time drilling optimization-related modeling programs are being developed as BHA dynamics, torque and drag, pore pressure/fracture gradient prediction, hydraulics, hole cleaning, and wellbore stability. ii) Integrated Real Time Modeling and Data: Although real-time modeling produces better results than the conventional, stand-alone modeling, the delivery of useful information in a useful form and diagnosis of a problem requires an integration of modeling with downhole data. For example, the integration of the following models and data is always beneicial: • Bottomhole Assembly (BHA) dynamics model with downhole vibration data • Pore pressure model with Pressure While Drilling (PWD) and Formation Testing While Drilling (FTWD) data • Hydraulic model with PWD data • Hole cleaning model with PWD and solids in mud • Wellbore stability model with Logging While Drilling (LWD) imaging data iii) RTOC: he irst Real-Time Operation Center (RTOC) was set-up by Shell E&P in New Orleans in early 2002. Since then, several other RTOCs for diferent operators have been developed particularly for ofshore rigs. here are many reasons to setup RTOCs. First, wells drilled ofshore are very expensive. hey clearly require full attention by the best staf available. Second, critical decisions are always multidisciplinary; and multidisciplinary decision making with expert staf is impractical to arrange at a rig. hird, a permanent, common ground needs to be identiied for oice and ofshore staf throughout planning and execution; and RTOCs readily satisfy this element. Lastly, full time (24/7) real-time drilling optimization monitoring and information management is required to avoid hazards; and 24/7 monitoring available to key personnel is best done an RTOC.

Basics of Drill String Design 379

7.9

Factors Afecting Rate of Penetration

he factors which afect the rate of penetration (ROP) are very numerous and perhaps important variables exist which are unrecognized up to this time. A rigorous analysis of drilling rate is complicated by the diiculty of completely isolating the variable under study. For example, the interpretation of ield data may involve uncertainties due to the possibility of undetected changes in rock properties. Studies of drilling luid efects are always plagued by diiculty of preparing two muds having all properties identical except one that is under observation. While it is generally desirable to increase penetration rate, such gains must not be made at the expense of overcompensating, detrimental efects. he fastest on-bottom drilling rate does not necessarily result in the lowest cost per foot of drilled hole. Other factors such as accelerated bit wear, equipment failure etc. may raise the cost. hese restrictions should be kept in mind during the following discussion. he factors that have an efect on ROP are listed under two general classiications such as environmental and controllable. Table 7.7 shows the list of parameters based these two categories. Environmental factors are not controllable such as formation properties and drilling luids requirements. Controllable factors on the other hand are the factors that can be instantly changed such as weight on bit, bit rotary speed, hydraulics. he reason that drilling luid is considered to be an environmental factor is due to the fact that a certain amount of density is required in order to obtain certain objectives such as having enough overpressure to avoid low of formation luids. Another important factor is the efect of the overall hydraulics to the whole drilling operation which is under the efect of many factors such as lithology, type of the bit, downhole pressure and temperature conditions, drilling parameters and mainly the rheological properties of the drilling luid. Rate of penetration performance depends and is a function of the controllable and environmental factors. It has been observed that the drilling rate of penetration generally increases with decreased Equivalent Circulating Density (ECD). Another important term controlling the rate of penetration is the cuttings transport. Ozbayoglu et al. (2004) conducted extensive sensitivity analysis on cuttings transport Table 7.7 Variables that afect ROP. Environmental Factors

Controllable Factors (Alterable)

Depth

Bit Wear State

Formation properties

Bit design

Mud type

Weight on bit

Mud density

Rotary speed

Other mud properties

Flow rate

Overbalance mud pressure

Bit hydraulic

Bottomhole mud pressure

Bit nozzle size

Bit size

Motor/turbine geometry

380 Fundamentals of Sustainable Drilling Engineering for the efects of major drilling parameters, while drilling for horizontal and highly inclined wells. It was concluded that the average annular luid velocity is the dominating parameter on cuttings transport, the higher the low rate the less the cuttings bed development. Drilling penetration rate and wellbore inclinations beyond 70° did not have any efect on the thickness of the cuttings bed development. Drilling luid density did have moderate efects on cuttings bed development with a reduction in bed removal with increased viscosities. Increased eccentricity positively afected cuttings bed removal. he smaller the cuttings the more diicult it is to remove the cuttings bed. It is clear that turbulent low is better for bed development prevention. One of the most important considerations in order to have an eiciently cuttings transported hole is to take into account the factors given in Table 7.6. However, in any engineering study of rotary drilling it is convenient to divide the factors that afect the ROP into the following list: 1. Personal eiciency 2. Rig eiciency 3. Formation characteristics (e.g. strength, hardness and/or abrasiveness, state of underground formations stress, elasticity, stickiness or balling tendency, luid content and interstitial pressure, porosity and permeability etc.) 4. Mechanical factors i.e. bit operating conditions – a) bit type, and b) rotary speed, and c) weight on bit 5. Hydraulic factor (e.g. jet velocity, bottom- hole cleaning ) 6. Drilling luid properties (e.g. mud weight, viscosity, iltrate loss and solid content) 7. Bit tooth wear he most important variables that afect the ROP are: 1. Bit type 2. Formation characteristics 3. Bit operating conditions (i.e. bit type, bit weight, and rotary speed) Table 7.8 Factors for eicient hole cleaning. Hole angle Fluid velocity Fluid properties (rheological properties and density) Cutting size, shape, and concentration Annular size Rate of pipe rotation and pipe eccentricity Fluid low regime (laminar and turbulent) Bit size

Basics of Drill String Design 381 4. Bit hydraulics 5. Drilling luid properties 6. Bit toot wear 1) Personal Efficiency he manpower skill and experience is referred to as personal eiciency. Given equal conditions during drilling/completion operations, personnel are the key to have success or failure of those operations and ROP is one of them. Overall well costs as a result of any drilling/completion problem can be extremely high; therefore, continuing education and training for personnel directly or indirectly involved is essential to successful desired ROP and drilling/completion practices. 2) Rig Efficiency he integrity of drilling rig and its equipment, and maintenance are major factors in ROP and to minimizing drilling problems. Proper rig hydraulics (pump power) for eicient bottom and annular hole cleaning, proper hoisting power for eicient tripping out, proper derrick design loads, drilling line tension load to allow safe overpull in case of a sticking problem, and well-control systems (ram preventers, annular preventers, internal preventers) that allow kick control under any kick situation are all necessary for reducing drilling problems and optimization of ROP. Proper monitoring and recording systems that monitor trend changes in all drilling parameters are very important to rig eiciency. hese systems can retrieve drilling data at a later date. Proper tubular hardware speciically suited to accommodate all anticipated drilling conditions, and efective mud-handling and maintenance equipment will ensure that the mud properties are designed for their intended functions. 3). Formation Characteristics he formation characteristics are some of the most important parameters that inluence the rate of penetration. he following formation characteristics afect the ROP – i) elasticity i.e. elastic limit, ii) ultimate strength, iii) hardness and/or abrasiveness, iv) state of underground formations stress, v) stickiness or balling tendency, vi) luid content and interstitial pressure, and vii) porosity and permeability. Among these parameters, the most important formation characteristics that afect the ROP are the elastic limit and ultimate strength of the formation. he shear strength predicted by the Mohr failure criteria sometimes is used to characterize the strength of the formation. To determine the shear strength from a single compression test, an average angle of internal friction varies from about 30 to 40° from the most rock. he following model has been used for a standard compression test: 1 0

Here, 0 1

2

cos

(7.36)

= shear stress at failure, psi = compressive stress, psi = angle of internal friction

W required to initiate drilling was obtained by d t plotting drilling rate as a function of bit weight per bit diameter and then extrapolating

he threshold force or bit weight

382 Fundamentals of Sustainable Drilling Engineering 20

Atmospheric pressure

18 Shear Strength , 1,000 psi

16

Pink quartzite

Knippa basalt

14 Virginia limestone

12 10

Rush Springs sandstone

8 Anhydrite 6 Berea sandstone

4

Carthage marble

2 0 0

40 80 120 160 200 240 280 320 W db

t

W db

,lbf / ft t

Figure 7.43 Relationship between rock shear strength and threshold bit weight at atmospheric pressure (Mitchell and Miska, 2011).

back to a zero drilling rate. he laboratory correlation obtained in this manner is shown in Figure 7.43. he other factors such as permeability of the formation have a signiicant efect on the ROP. In permeable rocks, the drilling luid iltrate can move into the rock ahead of the bit and equalize the pressure diferential acting on the chips formed beneath each tooth. Formation as nearly an independent or uncontrollable variable is inluenced to a certain extent by hydrostatic pressure. Laboratory experiments indicate that in some formations increased hydrostatic pressure increases the formation hardness or reduces its drill-ability. he mineral composition of the rock also has some efect on ROP. Rocks containing hard, abrasive minerals can cause rapid dulling of the bit teeth. Rocks containing gummy clay minerals can cause the bit to ball up and drill in a very ineicient manner. 4) Mechanical Factors he mechanical factors are also sometimes called as bit operating conditions. he following mechanical factors afect the ROP – i) bit type, ii) rotary speed, and iii) weight on bit. i) Bit Type: he bit type selection has a signiicant efect on rate of penetration. For rolling cutter bits, the initial penetration rates for shallow depths are oten highest when using bits with long teeth and a large cone ofset angle. However, these bits are practical only in sot formations because of rapid tooth wear and sudden decline in penetration rate in harder formations. he lowest cost per foot drilled usually is obtained when using the longest tooth bit that will give a tooth life consistent with the bearing life at optimum bit operating conditions. he diamond and PDC bits are designed for a given penetration per revolution by the selection of the size and number of diamonds or PDC blanks. he width and number of cutters can be used to compute the efective

Basics of Drill String Design 383 number of blades. he length of the cutters projecting from the face of the bit (less the bottom clearance) can limit the depth of the cut. he PDC bits perform best in sot, irm, and medium-hard, nonabrasive formations that are not gummy. herefore, the bit type selection i.e., whether a drag bit, diamond bit, or roller cutter bit must be used and the various tooth structures afect to some extent the drilling rate obtainable in a given formation must be considered. Figure 7.44 shows the characteristic shape of a typical plot of ROP vs. WOB obtained experimentally where all other drilling variables remain constant. No signiicant penetration rate is obtained until the threshold bit weight is exceeded (point a). ROP increases gradually and linearly with increasing values of bit weight for low-to-moderate values of bit weight (segment ab). A linear sharp increase curve is again observed at the high bit weight (segment bc). Although the ROP vs. WOB correlations for the discussed segments (ab and bc) are both positive, segment bc has a much steeper slope, representing increased drilling eiciency. Point b is the transition point where the rock failure mode changes from scraping or grinding to shearing. Beyond point c, subsequent increases in bit weight cause only slight improvements in ROP (segment cd). In some cases, a decrease in ROP is observed at extremely high values of bit weight (segment de). his type of behaviour sometimes is called bit loundering (point d – bit loundering point). he poor response of ROP at high WOB values is usually attributed to less-eicient hole cleaning because of a higher rate of cuttings generation, or because of a complete penetration of a bit’s cutting elements into the formation being drilling, without room or clearance for luid bypass. ii) Rotary Speed: Figure 7.45 shows a characteristic shape typical response of ROP vs. rotary speed obtained experimentally where all other drilling variables remain constant. Penetration rate usually increases linearly with increasing values of rotary speed (N) at low values of rotary speed (segment ab). At higher values of rotary speed (ater point b, segment b to c), the rate of increase in ROP diminishes. he poor response of penetration rate at high values of rotary speed usually is also attributed to less eicient bottomhole cleaning. Here, the bit loundering is due to less eicient bottomhole cleaning of the drill cuttings. Combined Efect of Bit Weight and Rotary Speed on ROP Maurer (1962) developed a theoretical equation for rolling cutter bits relating ROP to bit weight, rotary speed, bit size, and rock strength. he equation was derived from the

Bit Floundering Point ROP

d c e b a Weight on bit

Figure 7.44 Typical response of ROP to increasing bit weight (Mitchell and Miska, 2011).

384 Fundamentals of Sustainable Drilling Engineering

ROP

Bit Floundering Point

c b

Rotary Speed

a

Figure 7.45 Typical response of ROP to increasing rotary speed (Mitchell and Miska, 2011).

following observations made in single-insert impact experiments – i) the crater volume is proportional to the square of the depth of cutter penetration, ii) the depth of cutter penetration is inversely proportional to the rock strength. For these conditions, the equation can be written as: 2

ROP Here, ROP K Sc Wb Wtb db N Wo db

K Wb Sc2 db

Wtb db

N

(7.37)

t

= rate of penetration, t./min = constant of proportionality = compressive strength of the rock = bit weight = threshold bit weight = bit diameter = rotary speed = threshold bit weight per inch of bit diameter t

his theoretical relation assumes perfect borehole cleaning and incomplete bit tooth penetration. Bingham (1965) suggested the following drilling equation on the basis of considerable laboratory and ield data. he equation can be written as: ROP Here, K a5

K

W db

a5

N

(7.38)

= constant of proportionality that includes the efect of rock strength = bit weight exponent

In this equation, the threshold bit weight was assumed to be negligible and bit weight exponent must be determined experimentally for the prevailing conditions. iii) Weight on Bit: he signiicance of WOB can be shown as explained by Figure 7.46. he igure shows that no signiicant penetration rate is obtained until the threshold bit weight (Wt ) is applied (Segment oa, i.e. up to point a). he penetration rate

Rate of Penetration

Basics of Drill String Design 385

d c

Threshold Bit Weight

e

b

a

Weight on bit

Figure 7.46 Typical bit weight response with ROP.

then increases rapidly with increasing values of bit weight (Segment ab). hen a constant rate in increase (linear) in ROP is observed at moderate bit weight (Segment bc). Beyond this point (c), only a slight improvement in the ROP (segment cd) is observed. In some cases, a decrease in penetration rate is observed at extremely high values of bit weight (Segment de). his behavior is called bit loundering. It is due to less eicient bottomhole cleaning (because the rate of cutting generation has increased). 5) Hydraulic Factor Hydraulic factor is also called bit hydraulics. he two hydraulic factors afect the ROP greatly – i) jet velocity, and ii) bottomhole cleaning. he mechanical factors of weight on the bit and rotary speed are then linearly related to the drilling rate, provided the hydraulic factors are in proper balance to insure proper cleaning of the hole. he hydraulic factors afect drilling rate only when they inluence the rate of penetration or the eiciency of the drilling. i) Jet Velocity: Signiicant improvements in penetration rate could be achieved by a proper jetting action at the bit. he improved jetting action promoted better cleaning of the bit face as well as the hole bottom. here exists an uncertainty on selection of the best proper hydraulic objective function to be used in characterizing the efect of hydraulics on penetration rate. Bit hydraulic horsepower, jet impact force, Reynolds number, etc, are commonly used objective functions for describing the inluence of bit hydraulics on ROP. Eckel (1968) studied with micro bits in a laboratory drilling machine. He made the most extensive laboratory study to date of the relation between penetration rate and the level of hydraulics. His study was at constant bit weight and rotary speed. Eckel proposed the following model based on Reynolds number: N Re Here, Ks f

v dnz a

Ks

f

v dnz a

= a scaling constant = drilling luid density = low rate = nozzle diameter = apparent viscosity of drilling luid at 10,000 s–1

(7.39)

386 Fundamentals of Sustainable Drilling Engineering

Penetration Rate, ft/hr

100 Indiana lime Pbh – Pt =500 psi N = 75 rev/min db = 1.25 in.

W

10

1

1

10

Reynolds - Number Function,

1,500 lbf 1,000 lbf 500 lbf

100 1 1,976

f

dnz

Figure 7.47 Efect of Reynolds number and WOB on ROP (Eckel, 1968).

In Eq. (7.39), the shear rate of 10000 s–1 was chosen as representative of shear rates present in the bit nozzle. he scaling constant, K s , is somewhat arbitrary, but a constant value of 1/1,976 was used by Eckel to yield a convenient range of Reynolds-number group. Figure 7.47 shows the experimental results of Eckel’s inding. It is noted that increasing the Reynolds number function for the full range of the Reynolds number studied increased ROP. He found that when the bit weight was increased, the correlation curve simply was shited upward as shown in the igure. ii) Bottomhole Cleaning: It is one of the most important mechanisms for cutting transport in rotary drilling. However, proper bottomhole cleaning is very diicult to achieve in practice. he jetting action of the mud crossing through the bit nozzles has to provide suicient velocity and cross low across the rock face to efectively remove cuttings from around the bit as rock is newly penetrated. his would prevent cuttings from building up around the bit and teeth (bit balling), prevent excessive grinding of the cuttings and clear them on their way up the annulus, and maximize the drilling eiciency. here are many variables that play a part in the eiciency of bottomhole cleaning. hese variables include bit weight and rotation speed, bit type, low rate, jet velocity, diferential pressure, nozzle size, location and distance from rock face, solids volume, and cutting characteristics etc. Proper bottomhole cleaning will eliminate excessive regrinding of drilled solids, and will result in improved penetration rates. he eiciency of bottomhole cleaning can be achieved through proper selection of bit nozzle sizes. he maximum hydraulic horsepower and the maximum impact force are the two requirements to get the best hydraulic cleaning at the bit. Both these items increase when the circulation rate increases. However, when the circulation rate increases, so does the frictional pressure drop. Inadequate hole cleaning can lead to costly drilling problems, such as: mechanical pipe sticking, premature bit wear, slow drilling, formation fracturing, excessive torque and drag on drill string, diiculties in logging and cementing, and diiculties in casings landing. he most prevalent problem is excessive torque and drag, which oten leads to the inability of reaching the target in high-angle/extended-reach drilling. 6) Drilling Fluid Properties here are functions of drilling luids that can have unique challenging inluences. For example, the two mud properties that have direct impact on hole cleaning are viscosity

Basics of Drill String Design 387 and density. he main functions of density are mechanical borehole stabilization and the prevention of formation-luid intrusion into the annulus. Any unnecessary increase in mud density beyond fulilling these functions will have an adverse efect on the ROP. his density increase may cause fracturing of the formation under the given in-situ stresses. So, mud density should not be used as a criterion to enhance hole cleaning. In contrast, viscosity has the primary function of the suspension of added desired weighting materials, such as barite. he following drilling luid properties afect the ROP – i) density (i.e. mud weight), ii) rheological low properties (i.e. viscosity), iii) iltration characteristics (i.e. iltrate loss), iv) solid content and size distribution, and v) chemical composition. i) Density: An increase in drilling luid density causes a decrease in penetration rate for rolling cutter bit. he density of the mud controls the pressure diferential across the zone of crushed rock beneath the bit. If the density increases, it causes an increase in the bottomhole pressure beneath the bit. hus, there is an increase in the pressure differential between the borehole pressure and the formation luid pressure. Cunningham and Eenink (1959) conducted experiments on Berea sandstone and clay/water mud. Figure 7.48 shows the efect of mud density (i.e. mud weight) on ROP based on the experimental data. It shows a wider range of borehole and formation luid pressure. Note that a good correlation is obtained when the data are replotted with drilling rate as a function of overbalance (right side of Figure 7.48). Paiaman et al. (2009) reported that ROP decreases with the increase of mud weight as shown in Figure 7.49.

14

12

12 P f= 4

psig

psig

psig

,000

,000

P =3

psig

4

,000

,000

6

f

8

P f= 2

10

Drilling Rate, ft/hr

14

P f= 1

Drilling Rate, ft/hr

Efect of Mud Density (Overbalance) on Penetration Rate: Bourgoyne and Young (1974) observed that the relation between overpressure and penetration rate could be represented approximately by a straight line on semilog paper for the range of overbalance commonly used in ield practice. In addition, they suggested normalizing the penetration rate data by dividing by penetration rate corresponding to zero overbalance (borehole pressure equal to formation pressure). Figure 7.50 shows the normalized ROP and overbalance for the data as suggested by Bourgoyne and Young. Note that a reasonably accurate straight-line representation of the data is possible for moderate values of overbalance.

10 8 6 4 2

2

0

0 0

1000 2000 3000 4000 5000 6000 7000 Pm – Mud Column Pressure, PSI

0 2000 4000 6000 8000 (Pm – Pf ) Diferential Pressure, PSI

Figure 7.48 Efect of Mud Weight on Rate of Penetration (Bourgoyne, 1986).

388 Fundamentals of Sustainable Drilling Engineering

ROP (ft/hr)

40

y = −14.784

+ 158.96

R2 = 0.7315

30 20 10 0 8.0

8.5

9.0 9.5 10.0 Mud Weight (ppg)

10.5

11.0

Figure 7.49 Efect of Mud Weight on Penetration Rate (Paiaman et al., 2009).

Drag bit Diamond bit Rolling cutter bit Rolling cutter bit Rolling cutter bit Rolling cutter bit Rolling cutter bit

0 log

R Ro -1

-2 0

500

1,000

1,500

2,000

2,500

Overbalance, psi

Figure 7.50 Exponential relation between penetration rate and overbalance for roller-cone bits (Mitchell and Miska, 2011).

From Figure 7.50, we see that the equation for the straight line is given by: log10 Here, Pbh Pf R Ro m

R Ro

m Pbh

Pf

(7.40)

= circulating bottomhole pressure, psi = formation luid pressure, psi = rate of penetration (ROP), t./hr = ROP at zero overbalance, Pbh Pf 0, t./hr = slope of the straight line in the plot, psi–1

he circulating bottomhole pressure (Pbh ) can be expressed in terms of ECD (equivalent circulation density, c ) as follows: Pbh

0.052 c D

(7.41)

Basics of Drill String Design 389 Here, D

= total depth, t.

Also the Formation luid pressure Pf can be represented bypore pressure gradient, G p as follows: (7.42)

0.052 G p D

Pf

herefore, applying Eqs. (7.41) and (7.42), Eq. (7.40) can be re-written as follows: log10

R Ro

0.052 mD

c

Gp

(7.43)

Equation (7.43) can be written as: log10 Here, a4

R Ro

a4 D

Gp

c

(7.44)

= overbalance exponent

his equation is useful for studying the efect of mud density changes on ROP. So, Eq. (7.44) can be re-arranged as follows: R2 R1 Here R1 R2 1 2

e

2.304 a4 D

1

2

(7.45)

= rate of penetration (ROP) corresponding to 1, t./hr = rate of penetration (ROP) corresponding to 2, t./hr = old mud weight, lbf/gal = new mud weight, lbf/gal

Example 7.7: Estimate the change in penetration rate ater the mud-weight is increased from 25 t./hr to a certain rate using the following data: a4 = 3.56 x10–05, D = 12,500 t., 12.5 lb f / gal, 2 13.5 lb f / gal. 1 Solution: Given data: R1 = old rate of penetration = 25 t./hr a4 = overbalance exponent = 3.56 x 10–05 t. D = total depth = 12,500 t. = old mud weight = 12.5 lbf/gal 1 = new mud weight =13.5 lbf/gal 2 Required data: R2 = new rate of penetration in t./hr

390 Fundamentals of Sustainable Drilling Engineering he new ROP can be given by Eq. (7.45) as:

So,

R2 R1

e

2.304 a4 D

R2

1

2

R1 e

e

05

2.304 3.56 10

1.02528

25

12,500 12.5 –13.5

ft hr

0.424 10.6

e

1.02528

ft hr

ft . If the mud weight is increased by hr 8.33%, ROP m is increased by 8%, ROP decreases by 57.6%. ii) Viscosity: Penetration rates tend to decrease with increasing viscosity (Figure 7.51). he luid viscosity controls the parasitic frictional losses in the drill string and thus the hydraulic energy available at the bit jets for cleaning. here is also experimental evidence that increasing plastic viscosity reduces penetration rates even when the bit is perfectly clean (Figure 7.52). Plastic viscosity is that part of the resistance to low caused by mechanical friction. he friction is caused by viscosity of the luid phase of the drilling mud. In addition, viscosity acts on the mobility of cuttings. With a high viscosity, cuttings tend to remain stuck on the bottom involving their re-drilling and thus a reduction in the performances of the bit. he best rates of penetration will be obtained with a luid having a viscosity as low as possible at the exit of the nozzles of the bit (Figure 7.52). iii) Filtration Characteristics: Penetration rate increases with increasing iltration rate. he iltration characteristics of the mud control the pressure diferential across the bit nozzle and formation rock. 10.6

Rate of Penetration

herefore, new rate of penetration, R2

Viscosity

ROP (ft/hr)

Figure 7.51 ROP vs. viscosity plot (Alum and Egbon, 2011).

40 35 30 25 20 15 10 5 0

y =-4.3912 × +36.562 2

R = 0.6087

0

1

2

6 3 4 5 Plastic Viscosity (cP)

Figure 7.52 ROP vs. plastic viscosity plot (Paiaman et al., 2009).

7

8

Basics of Drill String Design 391 iv) Solid Content and Size Distribution: Drilling muds are usually composed of a continuous luid phase in which solids are dispersed. Plastic viscosity is that part of the resistance to low caused by mechanical friction. he friction is caused by solid concentration, size and shape of solids, and viscosity of the luid phase. Penetration rate decreases with increasing solids content (Figure 7.53a and 7.53b). Figure 7.53a shows the variation of solid content rate of penetration and on the other hand, Figure 7.53b shows the efect of solid content on ROP at constant plastic viscosity. he solids content also controls the pressure diferential across the bit nozzle and formation rock. For practical ield applications, plastic viscosity is regarded as a guide to solids control. Plastic viscosity increases if the volume percent remains constant, and the size of the particle decreases. Decreasing particle size increases surface area, which increases frictional drag. v) Chemical Composition: he chemical composition of the luid has an efect on penetration rate, such that the hydration rate and bit-balling tendency of some clays are afected by the chemical composition of the luid. 7) Bit Toot Wear Most bits tend to drill slower as the drilling time elapses because of tooth wear. he tooth length of milled tooth rolling cutter bits is reduced continually by abrasion and chipping. he teeth are altered by a hard facing or case-hardening process to promote a self-sharpening type of tooth wear. However, while this tends to keep the tooth pointed, it does not compensate for the reduced tooth length. he teeth of tungsten carbide insert-type rolling cutter bits and PDC bits fail by breaking rather than by abrasion. Oten, the entire tooth is lost when breakage occurs. Reductions in penetration rare due to bit wear usually are not as severe for insert bits as for milled tooth bits unless a large number of teeth are broken during the bit run. Several authors have published mathematical models for computing the efect of cutting-element wear on penetration rate for roller-cone bits. Galle and Woods (1963) published the following model: (7.46)

= the fractional tooth height that has been worn away, in = tooth wear exponent y = –2.0454 × +33.767

40 35 30 25 20 15 10 5 0

y = –2.8264 × +36.071

40

R2 = 0.6186

2

R = 0.6181

ROP (ft/hr)

ROP (ft/hr)

Here, h a7

a7

1 0.928125 h2 6h 1

ROP

30

20

10 2

4

6

8

10

12

14

16

2

4

6

8

Solid Content (%)

Solid Content (%)

(a)

(b)

Figure 7.53 ROP vs. solid content plot (Paiaman et al., 2009).

10

12

392 Fundamentals of Sustainable Drilling Engineering A value of 0.5 was recommended for the exponent a7 for self-sharpening wear of milledtooth bits, the primary bit type discussed in Galle and Woods (1963). Bourgoyne and Young (1974) suggested a similar but less complex relationship: ROP

exp

(7.47)

a7 h

Bourgoyne and Young suggested that the exponent a7 be determined on the basis of the observed decline of penetration rate with tooth wear for previous bit runs under similar conditions. Example 7.8: he initial penetration rate of 30 t./hr was recorded in shale at the beginning of a bit run. he previous bit was identical to the present bit and was operated under the same operating conditions (such as bit weight, rotary speed, mud density, and other factors). However, a drilling rate of 10 t./hr was observed in the same shale formation just before pulling the bit. In addition, the previous bit was graded as T-6. Calculate the approximate value of a7. Solution: Given data: ROP1 = initial rate of penetration = 30 t./hr ROP2 = inal rate of penetration = 10 t./hr h1 = 0 in 6 h2 = T-6 = 0.75 in 8 Required data: a7 = exponent constant he new ROP can be given by Eq. (7.47) as: ROP1

Ke

a7 h1

Ke

a7 0

K

and ROP2

a7 h2

Ke

Ke

a7 0.75

Ke

0.75a7

Now, dividing the irst equation by the second equation as: ROP1 ROP2

K Ke

0.75a7

e 0.75a7

Taking the natural logarithm of both sides and solving for a7 gives: ROP1 ROP2 0.75

ln a7

30 10 0.75

ln

1.46

7.10 Rate of Penetration Modelling he main characteristic of rotary drilling penetration performance is not only the fracture of the rock on the bottom, but also the removal of the fractured cuttings

Basics of Drill String Design 393 from the rock face in an instant and eicient manner to provide further fracturing and drilling progress. Due to the complexity of understanding the rate of penetration mechanism of drilling operations, industry pioneers have adopted empirical approaches by quantifying the efects of the controllable parameters on ROP performance, more than the analytical model implementation for the understanding of rate of penetration in the industry of drilling. It is reportedly known that time spent for the drilling of wells is composed by up to 30% “rotating time” of the total well construction time. Penetration rate optimization is consequently an important cost reduction consideration. It is assumed that all of the properties of the formations afecting rate of penetration, that is subject to optimization are macroscopically homogeneous and are with unique physical properties throughout the entire interval. he development of an ROP model is a challenging job due to the known and unknown variables. As a result, numerous investigations have been done in this area. In considering which variables to choose for developing an ROP model, experience and research suggest the eight variables as mentioned earlier. hese variables are mainly – i) mud properties, ii) hydraulics, iii) bit type, iv) weight on bit, v) drill string rotation speed, vi) depth, vii) bit tooth wear, and viii) formation properties. However, for horizontal and inclined wellbores, hole cleaning is also a major factor that inluences the ROP. he basic interactive efects between these variables were determined by design experiments. Variable interaction exists when the simultaneous increase of two or more variables does not produce an additive efect as compared with the individual efects. he meaning of variable interaction is illustrated in Figure 7.54. In addition, the mathematical model for the penetration rate could be written as a function of drilling parameters such as WOB/db, RPM, as given in below section. Also the bit tooth wear has been considered in the same equation for the optimization purposes.

Increasing Variables

Relative Drilling Rate

WOB N WOB+N

Negative Interaction

Actual WOB + N WOB Hydraulic WOB + Hydraulic Actual WOB + Hydraulic

Figure 7.54 Positive and negative interaction.

Positive Interaction

394 Fundamentals of Sustainable Drilling Engineering

7.10.1 Established Models for Rate of Penetration 1) ROP Models: Graham and Muench (1959) are some of the irst researchers who conducted evaluations on drilling data to determine optimum weight on bit and rotary speed combination. hey used a mathematical analysis method for drilling related costs to drill under optimum circumstances. Empirical mathematical expressions were derived for bit life expectancy and the drilling rate as a function of depth, rotary speed and bit weight. he proposed mathematical relations contained constants representative of the respective formations existing in the area. heir study resulted in being able to propose optimum weight on bit and rotary speed by means of calculations under any drilling conditions in order to minimize total drilling costs. here are three most widely used models for estimating rate of penetration; i) Maurer, ii) Galle and Woods, and iii) Bourgoyne and Young. Maurer’s Method: Maurer (1962) derived ROP equation for roller-cone type of bits considering the rock cratering mechanisms. His method was developed based on a theoretical penetration equation as a function of WOB, RPM, bit size and rock strength. he developed equation was based on observations such as the amount the crater cutter can create, rock strength related considerations. In addition, it was based on ‘perfect cleaning’ condition where all of the rock debris is considered to be removed between tooth impacts. A working relation between drilling rate, weight on bit and string speed was achieved. It was also mentioned that the obtained relationships were a function of the drilling depth. Maurer rate of drilling equation is expressed as: dFD dt Here FD t V db

4 dV db2 dt

(7.48)

= distance drilled by bit, t. = time, hr = volume of rock removed, = bit diameter

Galle and Woods’ Method: Galle and Woods (1963) were some of the irst researchers to investigate the efect of best constant bit weight and rotary speed for lowest cost and developed semi-empirical equations. hey investigated the efects of weight on bit, rotary speed, and cutting structure dullness on drilling rate, rate of tooth wear and bearing life. hey presented graphs and procedures for ield applications to determine the best combinations of constant weight and rotary speed. hey assumed a relation for the wear rate as a function of time in relation to inverse ratio of bit weight to bit diameter. he given equation was limited with a load application of 10,000 lbf/in of bit diameter. hey also published an equation showing a relationship between the tooth wear rate and the rotary speed for only milled tooth bits designed for sot formations. In their graphs, the drilling cost, footage, drilling hours and condition of teeth and bearing of the dull bit may be calculated. he drilling costs were demonstrated to be reduced using

Basics of Drill String Design 395 the recommended combinations of the drilling parameters. hey presented the drilling rate equation as given in (7.49) as a function of WOB and RPM. dFD dt

C fd

Wk r ap

(7.49)

Here C fd = formation drillability parameter a = 0.028125h2 + 6.0h + 1 h = bit tooth dullness, fractional tooth height worn away, in p = 0.5 (for self-sharpening or chipping type bit tooth wear) k = 1.0 (for most formations except very sot formations), 0.6 (for very sot formations) r = function of N which can be expressed as Eq. (7.50) and Eq. (7.51) 7.88WOB W = function of WOB and db, such that W db Now, r can be expressed for two types of formations. For hard formation: 100

r

e

N2

r

e

N2

100

N 0.428 0.2 N 1 e

N2

N 0.750 0.5 N 1 e

N2

(7.50)

For sot formation: 100

Here N

100

(7.51)

= rotational speed

Galle and Woods (1963) also deined rate of dulling and bearing life equation respectively as shown in Eq. (7.52) and Eq. (7.53). Rate of dulling equation: dh dt

1 i Af a m

(7.52)

L N

(7.53)

where: i = N 4.348 10 5 N 3 m = 1359.1 714.19 log10 W Bearing life equation: B

S

where: S = drilling luid parameter L = tabulated function of W used in bearing life equation

396 Fundamentals of Sustainable Drilling Engineering Bingham Model: Bingham (1965) proposed a rate of penetration equation based on laboratory data as stated in Eq. (7.54). In his equation, the threshold bit weight was assumed to be negligible and rate of penetration was a function of applied weight on the bit and rotary speed of the string. he bit weight exponent, a5 was set to be determined experimentally through the prevailing conditions.

ROP

a5

WOB K db

N

(7.54)

Here ROP = rate of penetration K = proportionality constant for rock strength efect a5 = bit weight exponent Bourgoyne and Young’s Method: Bourgoyne and Young’s (1973 and 1974) method is the most important drilling optimization method since it is based on statistical synthesis of the past drilling parameters. A linear penetration model is being introduced and multiple regression analysis over the introduced rate of penetration equation is being conducted. For that reason this method is considered to be the most suitable method for the real-time drilling optimization. hey developed a mathematical model and a summary of the equations is given below. he rate of penetration is expressed as: 8

d ROP dt Here a1 i ai xi

a1

e

ai xi i

2

(7.55)

= formation strength parameter = index number for ith drilling rate of penetration equation coeicient or summation index for ith data point = set of constants that relates with each of the drilling parameters considered = set of dimensionless drilling parameters calculated from the actual collected drilling data

he normalization constants given in the general ROP Eq. (7.55) are modiied accordingly as a function of the data property when used as an input to the regression cycle. When modiied normalization constants are used, the coeicients should give accurate predictions for ROP. So, the dimensionless drilling parameters in Eq. (7.55) are described as following: Formation Resistance: 1.0

(7.56)

10,000 TVD

(7.57)

x1 Consolidation Efects: x2

Basics of Drill String Design 397 Overpressure Efects: TVD 0.69 g p 9.0

x3

(7.58)

Diferential Pressure: x4

TVD g p

(7.59)

ec

Bit diameter and WOB:

x5

ln

WOB db

WOB db WOB db

4.0

t

(7.60)

t

Rotary Speed: ln

x6

N 100

(7.61)

h

(7.62)

Tooth Wear: x7 Bit Hydraulic: x8 Here TVD gp

h m

Q dn

mQ

350 dn

(7.63)

= total vertical depth, t. = pore pressure gradient of the formation, lbf/gal = equivalent circulating mud density at the bottomhole, lbf/gal

ec

WOB db WOB db

ln

= weight on bit per inch of bit diameter, 1000 lbf/in = threshold weight on bit per inch of bit diameter, 1000 lbf/in t

= bit tooth dullness, fraction of original tooth height worn away = mud density, lbf /gal = low rate, gal/min = Viscosity = bit nozzle diameter, in

he constants given in Eq. (7.55), a1 through a8 should be determined through the multiple regression analysis using the drilling data. hey represent the efects of formation strength [Eq. (7.56)], compaction efect [Eq. (7.57)], over pressure [Eq. (7.58)], pressure diferential [Eq. (7.59)], bit weight [Eq. (7.60)], rotary speed [Eq. (7.61)], tooth wear [Eq. (7.62)] and hydraulic exponent [Eq. (7.63)]. he threshold weight on bit and bit

398 Fundamentals of Sustainable Drilling Engineering diameter value is not a constant, signiicantly, it may have varying magnitudes based on formation characteristics, and for this reason whole data trend is observed when this threshold value is determined as an input. he same value could easily be obtained from a drill-of test. he fractional tooth height calculation methodology is a function of reference abrasiveness constants in the same ield, and is related to the time bit in use have operated. herefore, combining the Eqs. (7.56 – 7.63), the open form of the general ROP Eq. (7.55) for roller cone bit types is given as: a1 a2 10000 TVD

d ROP dt

a3TVD 0.69 g p 9.0

a4 TVD g p

ec

a5 ln

WOB db 4.0

e

WOB db WOB db

t

a6 ln

N 100

a7

h

a8 ln

mQ 350 dn

t

(7.64) Here al a2 a3 a4 a5 a6 a7 a8

= formation strength parameter = exponent of the normal compaction trend = under compaction exponent = pressure diferential exponent = bit weight exponent = rotary speed exponent = tooth wear exponent = hydraulic exponent

he considered efects of the controllable and uncontrollable drilling variables on ROP are individually described below for each item. Figure 7.55 gives the schematically represented general rate of penetration equation for roller-cone bit types.

a3

Under Compaction

X3 = D0.69 (gp – 9)

a2

Normal Compaction

a4

Pressure Diferential X4 = D(gp – )

X2 = (10000 – D) a5

ROP a1

WOB

dF — = f(1)f(2)......f(8) dt

Formation Strength

X5 =

W W – da da 4–

a8

Hydraulic pq X6 = 350 da

a6

RPM a7

Tooth wear

X7 = –h

Figure 7.55 General rate of penetration equation.

X6 = Lx

N 135

W da

Basics of Drill String Design 399 Bourgoyne and Young (1973) also expressed bit wear by using certain assumptions. Tooth wear model is deined as:

dh dt

Here H1 , H 2 , H 3 H

WOB db

max

H3 H

N 100

WOB db

H1

WOB db

H2 2 1 H2 h

4

1

max

WOB db

max

(7.65)

= Constants that depend on bit type = formation abrasiveness constant, hrs = Bit weight per inch of bit diameter at which the bit teeth would fail instantaneously, 1000 lbf/in

Bearing wear model: dBbw dt

1 B

N 100

WOB 4 db

b

(7.66)

Here Bbw = bearing wear fraction of the total life = life of teeth at standard conditions, hrs B b = constant Reza and Alcocer Method: Reza and Alcocer (1986a) developed a dynamic non-linear, multidimensional, dimensionless drilling model for deep drilling applications using theorem. Buckingham theorem is a dimensional analysis theorem Buckingham used to generate equations in dimensionless forms. he model is based on three equations – rate of penetration, rate of bit dulling and rate of bearing wear. heir study relected the efects of the following variables on three given equations: weight on bit, rotary speed, bit diameter, bit nozzle diameter, bit bearing diameter, drilling luid characteristics (density and viscosity), drilling luid circulation rate, diferential pressure, rock hardness, temperature and heat transfer coeicient. hey deined the rate of penetration as given in Eq. (7.67) in a form of non-linear, multivariable equation. ROP N dbd

C1

2 Ndbd

a

3 Ndbd Q

b

Edbd WOB

c

pdbd WOB

Here ROP = rate of penetration, t./min C1 = proportionality constant in penetration rate equation dbd = bearing diameter, in = drilling luid kinematic viscosity, cp Q = volumetric low rate, gpm E = rock hardness, psi

d

(7.67)

400 Fundamentals of Sustainable Drilling Engineering In Eq. (7.67), C1, a, b, c, and d are unknown parameters. In order to ind the coeficients using the available data a linear regression analysis methodology was applied ater taking the natural logarithm of both sides of the equation above. When the solution of the ROP equation was written the following relation was reported to investigate the deep well drilling problems, equation (7.68). ROP N dbd

0.33

2 Ndbd

0.43

3 Ndbd Q

0.68

0.91

Edbd WOB

pdbd WOB

0.15

(7.68)

he general equation for the rate of bit dulling was obtained as in equation (7.69). dbt N db

Q 0.001 N db3

0.56

WOB E db2

0.26

db Q

0.03

(7.69)

Here dbt = bit tooth dullness, fraction of original tooth db = bit diameter he general equation for the bit bearing life was obtained as in equation (7.70). Bbw N

T ht dbd 0.05 N WOB

0.4

0.51 2 N dbd

Q 3 N dbd

0.5

(7.70)

Here Bbw = bearing wear fraction of the total life T = temperature at the bottom of the hole, °F ht = heat transfer coeicient, BTU / ft 2 hr dbd = bearing diameter, in In the second part of their study Reza and Alcocer (1986b) mentioned that the exponents of the derived models are sensitive to unknowns, and there would be luctuations from region to region and well to well. For that particular reason their inding was a generalization of the model speciically for a region and in deep ield/wells. Warren’s Model: Warren derived a model of the drilling process for tri-con bits called perfect-cleaning model in 1987 and later modiied by Hareland (Hareland and Hoberock, 1993). he basic idea is that under steady-state drilling conditions, the rate of cutting removal from the bit is equal to the rate at which new chips are formed. h is implies that the cutting-generation process, the cutting removal, or a combination of the two processes controls the ROP. he perfect-cleaning model, which is shown in the following equation, is reviewed as a starting point for development of an imperfectcleaning model. ROP

a S 2 db2 N bWOB 2

Here a, b, c = bit constant for Warren’s constant S = conined rock strength, psi

c N db

1

(7.71)

Basics of Drill String Design 401 Unfortunately, ROP in most ield cases is signiicantly inhibited by the rate of cuttings removal from under the bit. hus Eq. (7.71) is not efective for predicting ield ROP without modiication to account for imperfect cleaning. herefore, it is necessary to modify the ROP model for imperfect cleaning conditions, which happen because of real situations. hus the resultant expression for ROP is: a S 2 db2

ROP

N WOB 2

b N db

1

c db

f

(7.72)

Fjm

Here f

Fjm

= luid speciic gravity = mud plastic viscosity, cp = modiied jet impact force, klbf

he modiied impact force is calculated from the following equation: Fjm Here Av Fj

1 Av 0.122 Fj

(7.73)

= ratio of jet velocity to return velocity = jet impact force, klbf

If Av is the ratio of the jet velocity to the luid return velocity, the Av (for three jets) is given by: Av

vn vf

0.15 db2

(7.74)

3 dn2

Modiied Warren’s Model: Neither Winters (Winters et al., 1987) nor Warren (Warren, 1987) addresses Chip’s hold down efects on penetration rate modeling, but it is known that this efect is important. It is an estimation of the resultant forces on a chip when the bit generates it. To establish the best relationship for chip hold down, data from laboratory full scale drilling tests was used in which bottomhole pressure varied and other conditions remained constant. A reasonable it to these diferent lithologies is given by: f c Pe

cc ac Pe 120

bc

(7.74)

Here Pe = diferential pressure f c Pe = chip hold down function ac , bc , cc = lithology-dependent constant Units of ac , bc , cc are chosen such that f c Pe is dimensionless. Equation (7.71) can now be modiied to include chip hold down efect and becomes: ROP

f c Pe

a S 2 db2 N b WOB 2

b N db

c db

1 f

Fjm

(7.75)

402 Fundamentals of Sustainable Drilling Engineering Hareland (Hareland et al., 1993) modiied this ROP model for the efect of bit wear on ROP by introducing a wear function, W f into the model: ROP W f fc Pe

a S 2 db2 N b WOB2

Here BG

1 f

Fjm

BG 8

1

Wf

c db

b N db

(7.76) (7.77)

= change in bit tooth wear

It can be calculated based on the WOB, ROP, relative rock abrasiveness and conined rock strength. n

BG Wc

WOBi N i Arabr Si i

i 1

(7.78)

Here Wc = bit wear coeicient Arabr = relative abrasiveness Rock compressive strength is a function of pressure and lithology: S So 1 as Pebs

(7.79)

Here S = conined rock strength So = unconined rock strength as , bs = coeicient depends on formation permeability Pessier and Fear Method: Pessier and Fear (1992) elaborated the mechanical speciic energy methodology which was developed by Teale (1962). hey performed simulator tests in the computer and conducted laboratory tests to quantify and develop an energybalanced model for drilling of boreholes under hydrostatically pressurized conditions. hey derived an equation for mechanical speciic energy, Eq. (7.80). hey found better identiication methodologies (than WOB and ROP concentrated evaluation) for bearing problems of the drill bits, which are more quick and reliable by continuously monitoring Es and μ, Eq. (7.81). Es

WOB

1 AB 36

Here Es AB

= bit speciic energy, psi = borehole area, in2

13.33 s N db ROP

T db WOB

(7.80) (7.81)

Basics of Drill String Design 403 s

= bit speciic coeicient of sliding friction, = apparent viscosity at 10,000 sec–1, cp

Osgouei Model: Osgouei (2007) developed a drilling model for predicting the ROP by considering the efect of the various drilling parameters. In his study, Bourgoyne & Young’s model is improved and enhanced for both PDC and insert-tooth – roller bits as well as for horizontal and directional wells. he major improvements are the consideration of additional drilling parameters occurring due to inclination as well as re-deinition of same drilling parameters due to PDC’s. He initiated the model as: ROP

f1

f2

f3

f4

f5

f6

f7

f8

fn

(7.82)

fn represent the functional relations between penwhere f1 , f 2 , f 3 , f 4 , f 5 , f 6 , f 7 , f 8 , etration rate and various drilling variables. Each of these functions contains constants which are shown as a1 through an . Determination of these constants is accomplished by using a multiple regression analysis of collected drilling data. he general form of the proposed model for roller-cone bits is ROP

f1

f2

f3

f4

f5

f6

f7

f8

f9

f10

f11

(7.83a)

ROP

f1'

f 2'

f 3'

f 4'

f 5'

f 6'

f 7'

f 8'

f 9'

f10'

f11'

(7.83b)

For PDC bits

In the upcoming sections, the functions (f1, f2, f3 . . . . . , fn) are deined and presented for both type of bits. Efect of formation strength (f1) is deined by f1'

f1 e a1

(7.84)

he functions of f1 & f1' primarily represent the efects of formation strength and bit type on the penetration rate. hey also contain the efects of other parameters, which are not included into consideration. he term f1 & f1' are expressed in the same units as penetration rate and commonly is called the drillability of the formation. he drillability is numerically equal to the penetration rate that would be observed in the given formation type (under normal compaction) when operating with a new bit at zero overbalance, a bit weight, a rotary speed, and a depth of the “normalization” values. he drillability of the various formations can be computed using drilling data obtained from previous wells in the area. Efect of compaction (f2) and (f3) are deined by: f 2' f 3'

f2 f3 e

e

a2 8800 TVD

a3TVD

0.69

g p 9.0

(7.85) (7.86)

As seen from Eq. (7.85), normalization depth was used in his study is 8800 t. he functions f2 and f2' account for the rock strength increase due to the normal compaction with depth, and f3 and f 3' model the efect of pore pressure gradient on penetration rate.

404 Fundamentals of Sustainable Drilling Engineering Efect of diferential pressure (f4) and ( f 4' ) is deined by f 4'

f4

e

a4 TVD g p

ec

(7.87)

Where measured depth is considered with determining ECD. he functions f4 & f 4' model the efect of overbalance on penetration rate, and, thus assume an exponential decrease in penetration rate with excessive bottomhole pressure. he Efect of the Bit Diameter and Bit Weight (f5) & ( f 5') is deined by: a5

WOB db

f5

WOB db WOB db

f 5'

WOB db

(7.88) c a5

mech

(7.89)

c

Here WOB db WOB db

= critical weight on bit per inch of bit diameter, 1000 lbf/in c

= mechanical weight on bit per inch of bit diameter, 1000 lbf/in mech

It is noted that the penetration rate is directly proportional to (WOB/db) as mentioned by several authors. he critical bit weight (WOB/db)c must be estimated by considering drill string properties, bit type and ield data. he mechanical weight on bit (WOB/db)mech is a concept usually observed when using PDC’s and is deined as the diference between the applied weight on bit and pump-of force acting on the face of bit divided by the bit diameter. According to Duklet and Bates (1980), the mechanical weight on bit is given by: WOB db

WOBapplied 0.942 Pb db 1 db

mech

Pb Here An

Q2 12031 An2

(7.90) (7.91)

= the total nozzle area

he pump-of force is approximated by an empirical expression developed using previous Christensen tests. he pump-of force can be a substantial hydraulic force created by the diferential pressures on the bit, due to the bit face pressure drop. his force tends

Basics of Drill String Design 405 to unload the cutting and is subtracted from the measured load to obtain the actual weight on bit. Efect of Rotary Speed (f6) and ( f 6') is deined by f 6' Here Nc

a6

N Nc

f6

(7.92)

= the critical rotary speed

Several authors assumed that penetration rate is directly proportional to N. Note that the critical rotary speed (Nc) must be estimated by considering drill string properties, bit type and ield data. Efect of Tooth Wear (f7) and ( f 7' ) is deined by: f 7'

f7

e

a7

h

(7.93)

Efect of Bit Hydraulic (f8) and ( f 8') is deined by: f 8'

f8

Fj

a8

(7.94)

Fjc

he value depends on bit type, drilling mud property and pump pressure. he Efect of Hole Cleaning (f9), (f10), (f11) and ( f 9'), ( f10' ), ( f11' ) is deined by:

f 9'

f10' f11'

f9

f10 f11

Abed Awell 0.2 Vactual Vcritical Cc 100

a9

(7.95)

a10

(7.96) a11

(7.97)

Today, one of the most common applications in the petroleum industry is to drill on inclined and horizontal wells. One of the major problems in drilling a horizontal and inclined well is hole cleaning. he technology applied successfully in cleaning vertical wells oten does not apply directly in horizontal and inclined wells. So, hole cleaning plays an important role on developing the realistic functions to predict penetration rate. he functions ( f9), ( f10), ( f11) and ( f 9'), ( f10' ), ( f11' ) deine the efect of hole cleaning in horizontal, inclined and vertical sections of wells where roller cone bits as well as PDC bits are used. Note that the equation (7.94) is a dimensionless function considering for horizontal section, equation (7.95) is simulating the inclined section and equation (7.96) is represented vertical section for proper hole cleaning for both PDC and roller cone bits.

406 Fundamentals of Sustainable Drilling Engineering If we apply Eqs. (7.84) – (7.97) to Eq. (7.83), the resultant equation will represent the ROP equations for Osgouei Model. ROP e a1 e

a2 8800 TVD

e

a3TVD 0.69 g p 9.0

e

a4 TVD g p

a5

WOB db

a6

N Nc

WOB db

e

a7

a8

Fj

h

Fjc

Abed Awell 0.2

ec

a9

Vactual Vcritical

a10

Cc 100

a11

(7.98)

c

For PDC bits ROP

e a1 e

WOB db WOB db

a2 8800 TVD

e

a3TVD0.69 g p 9.0

e

a4 TVD g p

a5

mech

N Nc

a6

e

a7

h

a8

Fj Fjc

ec

Abed Awell 0.2

a9

Vactual Vcritical

a10

Cc 100

a11

(7.99)

c

2). Tooth Wear Model As indicated in Bourgoyne & Young’s drilling model, ( f 7 ) & ( f 7' ) have a value of 1.0 when totally new tungsten carbide insert bits (IADC code: 517 & 523) and PDC bits are used. Osgouei (2007) assumed that bit cone ofset selection is proper. So bearing wear is negligible. he developed model for estimating frictional tooth dullness, h, is given by: dh dt

g1 g 2 g 3 g 4

(7.100)

he function g1 describes the efect of formation abrasiveness on tooth wear and deined by: g1

H3

(7.101)

H

In equation (7.100), the value of H3 for tungsten carbide insert bits (IADC code: 517 & 523) and PDC bits is 0.02 according to Bourgoyne and Young and the value of τH depend on formation properties and it must be estimated using drill-of tests or previously drilled well data. he function g2 considers the efect of weight on bit on tooth wear. his function is diferent for tungsten carbide insert bits (IADC code: 517 & 523) and PDC’s. For tungsten carbide insert bits (IADC code: 517 & 523) it is deined by:

g2

WOB db WOB db

2.9 max

max

WOB db

(7.102a)

Basics of Drill String Design 407 Here WOB db

max

= bit weight per inch of bit diameter at which the bit teeth would fail instantaneously, 1000 lbf/in

Estes (1971) has pointed out that the rate of bit wear will be excessive if a very high bit weight is used. For PDC bits, the efect of weight on bit on tooth wear is deined by: WOB db

g2

WOB db

cir

(7.102b)

mech

Note that the normalized bit weight (WOB/db )cir must be estimated by considering drill string properties, bit type and ield data. he function g3 describes the efect of pipe rotation on tooth wear and deined by: N Nc

g3

H1

(7.103)

he value of H1 for tungsten carbide insert bits (IADC code: 517 & 523) and PDC bits is 1.50 according to Bourgoyne & Young and the value of Nc depend on drill string properties and bit type. he function g4 is used to emphasize the efect of tooth geometry on tooth wear. For all types of bits, tooth wear is proportional to the inverse of the contact area (A) if failing by fracturing of brittle tungsten carbide is ignored. Generally the shape of bits should be classiied into three main shapes: cylindrical, triangular and spherical. For cylindrical shape, since there is no change in contact area, the efect of tooth geometry on tooth wear is given by: 1

g4

(7.104)

For triangular shape, the efect of tooth geometry on tooth wear is given by: H2 2 1 H2 h 1

g4

(7.105a)

he value of H2 is 1.0 according to Bourgoyne & Young. Finally, for spherical shape, the efect of tooth geometry on tooth wear is given by: g4

1 dc h 2 h

(7.105b)

By substituting Eqs. (7.101 through 7.105) into Eq. (7.100) and integrating for h, the value of frictional tooth dullness, h, can be calculated as:

408 Fundamentals of Sustainable Drilling Engineering For tungsten carbide bit: i) Tooth geometry on tooth wear for cylindrical shape: WOB db

H3

dh dt

WOB db

H

2.9 WOB db

max

H1

N Nc

max

(7.106a)

ii) Tooth geometry on tooth wear for triangular shape: WOB db

H3

dh dt

WOB db

H

2.9

N Nc

max

WOB db

max

H2 2 1 H2 h 1

H1

(7.106b)

iii) Tooth geometry on tooth wear for spherical shape:

dh dt

WOB db

H3 H

WOB db

2.9

N Nc

max

WOB db

max

H1

1 dc h 2 h

(7.106c)

For PDC bit: i) Tooth geometry on tooth wear for cylindrical shape:

dh dt

WOB db

H3 H

WOB db

H1

N Nc

cir

(7.107a)

mech

ii) Tooth geometry on tooth wear for triangular shape:

dh dt

H3 H

WOB db WOB db

cir

N Nc

H1

H2 2 1 H2 h 1

(7.107b)

mech

iii) Tooth geometry on tooth wear for spherical shape:

dh dt

H3 H

WOB db WOB db

cir

mech

N Nc

H1

1 dc h 2 h

(7.107c)

Basics of Drill String Design 409 3) Mechanical Speciic Energy: he concept of mechanical speciic energy (MSE) has been used efectively in lab environments to evaluate the drilling eiciency of bits. MSE analysis has also been used in a limited manner to investigate speciic ineiciencies in ields operations (Dupriest et. al., 2005). he MSE surveillance process provides the ability to detect changes in the eiciency of the drilling systems, more or less continuously. In early 2004, an operator initiated a pilot to determine whether rig-site personnel might use the concept more broadly as a real-time tool to maximize the rate of penetration (ROP). h e results have exceeded expectations. he average ROP on the six rigs selected for the three-month pilot was increased by 133% and new ield records were established on 10 of 11 wells. Real time MSE surveillance is used to ind the lounder or founder point for the current system and in some cases the cause of founder. MSE is a ratio and quantiies the relationship between input energy and ROP. his ratio should be constant for a given rock, which is to say that a given volume of rock requires a given amount of energy to destroy. he relationship between energy and ROP derived by Teale (1965) is presented here as InputEnergy OutputROP

MSE MSE Here Tor

480Tor RPM db2

ROP

4WOB db2

(7.108) (7.109)

= torque, lbf-t.

Figure 7.56 shows the relationship between ROP and WOB to relate the MSE and the drill of curve. In region II, the linear slope means that the ratio of input energy WOB to ROP is constant. Since MSE equals to this ratio, it must also be a constant value, but only if the bit is operating within the linear portion of the curve. When the bit is in region I or III, a disproportionate amount of energy is being used for the given ROP. his provides a useful diagnostic. If MSE is constant the bit is eicient and operating in region II. If MSE rises, the system is foundering. By plotting MSE continuously at the rig site, the driller can see whether it moves in or out of founder as various parameters are tested. he energy required to destroy a given volume of rock is determined by its compressive strength. Teale (1965) derived the speciic energy equation by calculating the Region lll: Founder Bit Balling Bottom Hole Balling Vibrations

Potential Performance Performance is enhanced by redesigning to extend the founder point

ROP Region ll: Eicient

Region l: Inadequate Depth of Cut (DOC)

WOB

Figure 7.56 Relationships between ROP and WOB (Dupriest et al., 2005).

410 Fundamentals of Sustainable Drilling Engineering torsional and axial work performed by the bit and dividing this by the volume of rock drilled. his concept is also reported by Dupriest (Dupriest, 2005). Although there is a clear connection between rock strength and energy required for destroying it, Teale was surprised when lab-drilling data showed the MSE value to be numerically equal to rock compressive strength in psi. his is useful from an operations standpoint because it provides a reference point for eiciency. If the observed MSE is closed to the known conined rock strength, the bit is eicient. If not, energy is being lost. he value should change as the lithology changes. However, ield experience shows the occurrence of energy losses when the bit founder is very large. In such situations, they cannot be confused with the small changes that occur with rock compressive strength. Drilling Speciic Energy: Armenta (Armenta, 2008) modiied the concept of MSE and its original mathematical equation developed by Teale (Teale, 1965). In the modiication, he included a bit hydraulic-related term on the original MSE correlation and presented the equation in the below form: DSE

WOB 120 RPM Tor AB AB ROP

1,980,000 HPB AB ROP

(7.110)

Here DSE =drilling speciic energy, psi AB = borehole area, in2 = bit hydraulic factor, dimensionless HPB = bit hydraulic horse power, psi he irst two terms on the right hand side of Eq. (7.110) are similar to those on Teale’s original equation. However, the third term represents the bit hydraulic related term. he number 1,898,000 is a unit conversion factor. he parameter Lambda (λ) is a dimensionless bit hydraulic factor depending on the bit diameter (Figure 7.57). he ratio of bit hydraulic power HPB and bit area (HPB/AB) is the bit hydraulic power per square inch, HSI (hp/in2). he DSE concept was evaluated by applying Eq. (7.110) and the relationship of DSE and ROP was investigated for diferent drilling parameters (i.e. WOB, and HSI). DSE vs. ROP for diferent WOB values for all the experiments show grouping of curves according to the WOB (Figure 7.58). Field data was used to calculate DSE using Eq. (7.110) to identify ineicient drilling condition. he ROP and DSE both were plotted irst against depth to identify any particular pattern (Figure 7.55). A good agreement between the experimental data and the DSE model was observed. All the curves have similar pattern showing three main regions: i) High DSE and low ROP indicating ineicient drilling; ii) low DSE and high ROP which indicate eicient drilling; iii) A transition zone from region 1 to region 2 in between these two regions (Armenta, 2008). In order to show the efect of the hydraulic term (i.e. HSI) again DSE, Figure 7.59 was plotted to show the efect of DSE on ROP where the data was grouped according to the HSI. During the experimental work, WOB was kept constant and diferent WOB curves are shown on the plot to make a connection between DSE and ROP as shown in Figure 7.59. It was shown in Figure 7.60 that all the data with HSI between 0.5 hp/in2 and 1.7 hp/ in2 are located on the ineicient drilling region (Region 1: high DSE and low ROP) for

Basics of Drill String Design 411 Hydraulic Factor (Lambda), dimensionless

0.060 0.050 0.040 0.030 0.020 0.010 0.000

4

5 6

7 8

9 10 11 12 13 14 15 16 17 18 19 20 Bit dia-meter, in

Figure 7.57 Hydraulic Factor (λ) (Armenta, 2008).

ROP, ft/hr

2,000

0

50

DSE , psi

100

150 0

100,000 200,000 300,000

2,500 3,000

Depth, ft

3,500 4,000 4,500 5,000 5,500 6,000

Figure 7.58 ROP and DSE vs. depth for ield data (Armenta, 2008).

120,000

DSE, psi

100,000 80,000 60,000 WOB=50,000lb

40,000

WOB=40,000lb

20,000 0 0.0

WOB=30,000lb WOB=20,000lb

5.0

10.0

15.0 20.0 ROP, ft/hr

25.0

30.0

Figure 7.59 DSE vs. ROP with experimental data grouped according to the WOB (Armenta, 2008).

412 Fundamentals of Sustainable Drilling Engineering 120,000 100,000

DSE, psi

80,000

0.5 hp/in2 < HIS < 1.7 hp/in2

60,000 1.8 hp/in2 < HIS < 5.7 hp/in2

40,000

5.8 hp/in2 < HIS < 7.9 hp/in2

20,000 0 0.0

5.0

10.0

15.0 ROP, ft/hr

20.0

25.0

30.0

Figure 7.60 DSE vs. ROP with experimental data grouped according to the HSI (Armenta, 2008).

their particular WOB. On the other hand all the data with HSI between 5.8 hp/in2 and 7.9 hp/in2 are on the eicient drilling region (Region 2: low DSE and high ROP). It is revealed from Figure 7.60 that the bit hydraulic is the driver to move from ineicient drilling when the WOB is constant. When increasing HSI not only is the cutting removed faster underneath the bit, the bit cutting structure is kept clean to break new rock more efectively. Khamis (2013) modiied the DSE equation [Eq. (7.109)] by using the area of the 1.2651 Db 2 ) and modifying hydraulic factor as: drilling bit (AB 4 Db2 DSE

4 WOB Db2

480 RPM Tor 2

Db ROP

3,189,335 HPB Db 4 ROP

(7.111)

he input parameters of the DSE Eq. (7.110) can be used to estimate the DSE and therefore the drilling parameters can be optimized in order to maximize the ROP by minimizing the DSE.

7.10.2 Optimization of the Penetration Rate he drilling rate of the penetration model should be deined in order to conduct the real-time data analysis for ROP optimization. he model described below aims to optimize WOB and RPM where multiple linear regression technique is used as an optimization methodology. Multiple regressions are used to ind the parameters of an equation, which make that equation to be best representation of the data. Codes are designed to ind the coeicients of the model; mathematically correlating rate of penetration with the controllable and uncontrollable drilling parameters. he mission is to obtain drilling data at a rig site network, pipe the collected data to the operation center, and run the analysis and send feed back to the rig-site as shown in Figure 7.61. he data process technique is performed to the drilling data set to achieve general equation to predict ROP as a function of input drilling parameters. he multiple regression

Basics of Drill String Design 413

Rig-n Rig-n+1

Sensors D/A Converter Rig Site Network

Sensors D/A Converter

Operation Center Network

Rig Site Network

Optimization

Figure 7.61 Drilling optimization data transmission process (Eren and Ozbayoglu, 2010).

technique is based on regression model that contains more than one regressor variable (Montgomery and Runger, 2003). Multivariable data analysis is characterization of an observation unit by several variables (Davis, 2002). Multivariable analysis method gets afected for the changes in magnitude if several properties simultaneously act on it. Multiple regressions consider all possible interactions within combination of variable as well as the variables themselves. A standard plan for ROP is 700 – 1000 t./day. It is well known that too fast drilling (i.e. ROP: +100 t./hr) can result in poor borehole cleaning, cuttings can fall in when pumps are tuned of during connection and tripping operations which cause diferential sticking. On the other hand, slow drilling (i.e. ROP: 10 t./ hr) can usually be improved by adding more weight on a bit. Typically only 30–40% of the total drilling time is spent rotating the bit on bottom of the hole. Recently, ROP is optimized using drilling speciic energy (DSE) based on real time and rig-site data. he work involves adequately deining the problems to be solved, formulating the objectives of drilling optimization tasks into mathematical equations and solving the formulated optimization problems. Introducing bit hydraulics improves the ROP signiicantly. Drilling parameters need to be considered during the development of a correlation between ROP and the related factors such as Weight on Bit (WOB), Revolution per Minute (RPM), Torque (T), drilling luid circulation rate (Qm), and bit hydraulics (HPb).

414 Fundamentals of Sustainable Drilling Engineering here are mainly two optimization methodologies; using analytical models such as the method of Galle and Woods, drill-of tests, and the use of the numerical (statistical) models such as multiple regression analysis. he drilling optimization procedure considered by Osgouei (2007) is based on two objective functions i) maximizing the rate of penetration, and ii) minimizing cost per foot. In order to derive the optimum drilling parameters analytically, two separate diferential equations are deined: i) rate of penetration [Eq. (7.112)] and ii) teeth wear as a function of time [Eq. (7.113)]. In a general form, they can be written as: he general form of the optimized model for roller-cone bits is: ROP

WOB , N, h db

f1

dh dt

f2

(7.112)

WOB , N, h db

(7.113)

As seen in equations (7.112) & (7.113), only the operable parameters can be considered. So, it can be concluded that drilling optimization can be conducted to select the proper weight on bit and rotary speed. During analytical derivation of optimum value for weight on bit and rotary speed, some constraints due to practical application are introduced. WOBmin

WOB

N min 0

WOBmax

(7.114)

N N max

(7.115)

1.0

(7.116)

h

Where for totally worn out teeth, the value of h is zero and for new teeth, it equal to one. In general, the optimized WOB and RPM should lie within the operation window of their respective applicable range and mathematically, it can be represented by the following equation: dF dt Here dF dt Wv db N h

f

Wv , N,h db

(7.117)

= rate of penetration (ROP), t./hr = vertical weight on bit component = bit diameter = rpm = bit tooth dullness, fractional tooth height worn away

For roller cone and tungsten carbide insert bits:

WOB db

a5 H1 opt

WOB db

a5 H1 a6

max

(7.118a)

Basics of Drill String Design 415 For PDC bit:

WOB db

H1 a5

WOB db

WOB db

c

cir

(7.118b)

H1 a6

opt

Ater determining the optimum weight on bit and bit life (tb), the corresponding rotary speed can be calculated for roller cone bits and PDC bits, assuming complete tooth wear, which is given as: For tungsten carbide insert bits:

N opt 100

H

WOB db

tb H 3

max

WOB db

WOB db

1 H1 opt

(7.119a)

2.9 max

For PDC bits: 100

N opt tb H 3 H

(7.119b)

1 H1

WOB db

cir

WOB db

opt

Ater the necessary calculus the optimized equation for the vertical weight component for each diameter of bit size, the optimum bit weight can be expressed as (Bourgoyne et al. 1986):

Wv db Here Wv db a5 a6 H1

a5 H1 opt

w db

a6 max

W db

t

a5 H1 a6

(7.120)

= optimum weight on bit and drill bit diameter opt

= bit weight exponent = rotary speed exponent = tooth geometry constant used to predict bit tooth wear

In a parallel routine the optimum bit speed (N Opt ) can be expressed as (Bourgoyne et al. 1986):

416 Fundamentals of Sustainable Drilling Engineering

N Opt

60

H

W db

tb

Wv db

max

W db

Opt

(7.121)

4 max

Here N Opt = optimum rotary speed = formation abrasiveness constant H tb = bit drilling time W = weight on bit In ROP optimization, drilling cost per foot can be deined to account for daily rig rate, bit cost, and timings required in the course of bit runs, which is discussed in Chapter 11.

7.11 Current Development on Drill String and Bottomhole Assembly Design New developments involve using the drill string as a vehicle for sending downhole information to the top of the hole. High-speed-telemetry drill pipe can provide highquality downhole dynamic data along with logging information (gamma scans, density images, etc) that can be efectively used for real-time drilling optimization. Many researchers have been performed for drilling real-time data. Most of these researches focused on the application of real-time data in the optimization of the drilling parameters. A large amount of sotware was built in order to be able to handle the tremendous amount of data that can be easily visualized and analyzed. Onoe et al. (1991) described the concept, design and capabilities of an advanced real-time information system for drilling. he objectives of this system are to provide signiicant increases in drilling eiciency and engineering accuracy while at the same time to enhance operational safety and optimize the data management associated with drilling operations. hree important attributes distinguish this system from other “realtime” systems either existing or under development. First, the system provides “realtime” engineering models for decision support augmented by a “real time” expert system. Second, the system can be interfaced with any data acquisition hardware. hird, it addresses a wider range of data analysis and engineering functionality. Additionally, scenarios for its utilization in the ield to optimize drilling operations are provided. It was also recognized that this system would need to grow and adapt to accommodate new technology and changing requirements during the 1990’s and beyond. honhauser (2004) investigated the use of process related data measured in real time for performance analysis while and ater drilling. his process showed that it is possible to automatically derive activities and events from real-time data, just as it is possible to accomplish an understanding of various events, which results in non-optimal performance or trouble time through visual inspection of data plots. Quality problems with existing real-time data, revealed during post analysis were discussed as well as their origin in the historically developed pattern of geology-driven, depth-based view of all the drilling process.

Basics of Drill String Design 417 High-resolution operation analysis can be performed with existing data, which showed a very high potential for automated process optimization and early problem recognition. Mathis and honhauser (2007) addressed the problem related to the real-time data and developed essential steps criteria to measure and evaluate data quality. Quality control and improvement, data quality benchmarking, and accessibility of controlled data are management strategy proposed in their paper and therefore signiicant time saving was achieved compared to a manual quality control. A visual concept has been introduced, which allows the suring of time and depth based data with unique navigation concept. Vogel and Asker (2010) presented certain scenarios to inform operators and other drilling organizations about the cost-efectiveness and importance of real time data management techniques and information transfer for complimenting technology in drilling operation. his technique can save the oil and gas industry operator money in the current drilling operations and even in future operations. It also ills some of the knowledge gap in the industry and saves money for the environmental and safety sector of this industry, which can be very expensive when incidents occur. Following the real time data management and information transfer technique will allow for safe and eicient drilling with maximum ROI and reduced risks. Staveley and how (2010) illustrated techniques for improving collaboration and analysis of real-time and historical drilling data, increasing the cost of efectiveness of drilling eforts. hey presented a case study highlighting the achievable beneits. A drilling knowledge base makes it possible to unlock the value of all the drilling data a company has paid to collect but rarely uses due to its disparate nature. Earth model sotware makes it possible to perform multi-well analysis and implement the collaborative worklows to facilitate the type of drilling analysis and planning that the industry has known for years can reduce NPT, increase drilling eiciency, and ultimately reduce costs. hese worklows can be used for completely green exploration wells, where you have no data and can create a drilling knowledge base during drilling; for ields where some ofset data is available; and for established ields where many wells have already been drilled. Each well added to the knowledge base efectively decreases drilling uncertainty. Eren and Ozbayoglu (2010) developed a model to optimize drilling parameters during drilling operations such as weight on the bit, bit rotation speed in order to obtain maximum drilling rate and hence minimize the cost per foot and the overall drilling cost. he model that was developed used actual ield data collected through modern well monitoring and data recording systems, which will be used in predicting the rate of drilling penetration as a function of available parameters. he study demonstrated that drilling rate of penetration could be predicted at relatively accurate levels, based on past drilling trend. he optimum weight on bit and bit rotation speed could be determined in order to achieve minimum cost drilling. It is believed that by means of efective communication infrastructures and thorough team eforts having eicient real-time drilling optimizations based on statistical syntheses are not too distant. Sharma et al. (2010) included six case histories where the use of downhole drilling data increases drilling eiciency. hese cases described four diferent applications where a downhole optimization sub’s (DHOS) real-time data was used to improve drilling operations. he case studies are proof that having optimization sensors that provide information like bending moments, DWOB, etc. are essential to answer such questions and are key tools in the benchmarking process. Armed with these tools, even the most diicult of wells will have an engineered solution.

418 Fundamentals of Sustainable Drilling Engineering Maidla and William (2005) showed how MSE was implemented in a drilling information system in real time on the rig and at remote monitoring locations. he study showed that the use of MSE in real time is a useful tool for both drillers and drilling engineers. Conducting MSE tests in real time is an efective way to develop an understanding of MSE behaviour and contributes to acceptance by rig personnel. he general practice of adjusting drilling parameters to minimize the value of MSE is a good rule of thumb. Rashidi et al. (2008) presented a new method to combine Mechanical Speciic Energy (MSE) and Rate of penetration (ROP) models to calculate real time bit wear which takes into consideration the fundamental diferences between MSE and ROP models and that the latter only takes into account the efect of bit wear. Encouraging results have been obtained which shows a linear relationship between MSE (Rock Energy) and rock drillability (Drilling Strength) equations with the use of K1 as a constant of proportionality. Change in mud weight and bit wear are the two most dominant factors, which cause an irregularity in normal decreasing trend of the inverse of coeicient K1 versus depth. he developed model is correlative using diferent sliding coeicient of friction to account for variations in bit parameters like bit diameter, number of cutters, cutter diameter, back rake and side rake, etc. which are not accounted for in the ROP equation presented and the MSE calculation. his approach has been veriied with a small dataset, and by analyzing more bit runs the authors believe this can become a valuable tool in real time analysis of bit wear. Rashidi et al. (2010a) described the real-time application of a developed model for bit wear analysis. he model was developed based on the diference between rock energy model, MSE, and rock drillability from rate of penetration model. It has been modiied and implemented as an engineering module in the newly developed sotware, Intelligent Drilling Advisory system (IDA’s), and used to estimate real-time bit wear for both roller cone and PDC bits. Sotware from a remote server for the analysis retrieves the drilling data. he data is subsequently quality controlled before calculating instantaneous bit wear while the bit is in the hole. In this research, bit runs for two ofset wells in Alberta, Canada, will be analyzed in detail using the sotware module. Similarities between the recorded bit wear outs reported in the ield and the simulation results indicate that the procedure can be used for bit wear estimation with good accuracy. Depth for normalization of constant K1 and multiplication factor are set manually for each bit run section to get a smother bit wear trend. he automatic calibration and setting of these factors will be integrated into the future development of the sotware. Calculated inal bit wear out values show good matches compared to the ield data. his engineering sotware module could be used to identify unnecessary tripping which will result in time and cost reduction as well as an additional tool to aid in the estimation of bit wear status while drilling. Mohan et al. (2009) presented a new correlation to identify ineicient drilling conditions using MSE. Hydro Mechanical Speciic Energy (HMSE) was introduced encompasses hydraulic as well as mechanical energy. he HMSE equation will be of value during both planning and operational phases of selecting drilling parameters and also optimize them. However, Armenta (2008) presented a novel correlation to identify ineicient drilling conditions using experimental and ield data. Results showed that drilling speciic energy (DSE) can be used to identify ineicient drilling conditions. Experimental results illuminated the importance of including bit hydraulics into Speciic Energy analysis for drilling optimization. he new hydraulic

Basics of Drill String Design 419 term included on the speciic energy correlation is the key to correctly matching the amount of energy used to drill and the rock compressive strength. Also, this term illuminates how much hydraulic energy is needed to drill faster and eiciently when the mechanical energy (axial and torsional) is increased. Rashidi et al. (2010b) conducted a study to demonstrate the efects of changing the drilling parameters bit wear and bit designs on ROP for both approaches. Optimum bit types and designs with corresponding drilling parameters can be globally recommended for entire bit runs using ROP model. he MSE model can be used to adjust the operating parameters to reach a maximum ROP value “locally”, or in real-time with no efect of bit design or bit wear integrated. he lexibility of using an ROP model as opposed to the MSE equation transformed into an ROP equation is also investigated. he MSE model is easier to use in terms of inding the ineiciencies and reaching the instantaneous optimization level. he MSE model has its limitation in planning and post analysis of the drilling phases. MSE is useful as a tool to detect possible drilling problems while drilling without addressing the exact causes. he ROP model is more comprehensive compared to the MSE model. It includes bit wear, bit hydraulics and bit design, which gives the user the capability to optimize bit runs and hole sections for lowest $/t. he ROP models can be used in all phases of the drilling cycle including pre-planning, real-time drilling and post analysis. he big advantage of ROP models over the MSE model is that it can recommend drilling parameters that maximize the ROP over the entire bit run and not just instantaneously, meaning that ROP models can be used as a global optimization tool while MSE models are only local. Voss et al. (2010) described the drilling of a sidetrack from a well that was originally drilled in 2005 and makes comparisons between two projects proposed with respect to equipment used and planning techniques implemented. he original 2005 wellbore was drilled directionally through approximately 5000 t. of salt. his caused several drilling related issues, including severe vibration and downhole tool failures. With the objective of improving drilling performance on the sidetrack well while avoiding disastrous failure, the operator and Service Company jointly used a structure engineering optimization process. As a result of the total system optimization program, ROP was doubled from 15.5 to 30.6 t./hr while comparing the target well with the ofset well. his action saved the operators cost $2.1 million in this hole section which resulted in 76% reduction in drilling removable time (DRT). In addition, it exhibited minimum vibration throughout the entire run. A total systems approach and proper pre-well planning were shown to be the key to success including: service company’s teams and conditions, risks and contingencies taken by operator, eicient planning and ield execution, improved bit selection proper bit and reamer synchronization, well-trained service company rig and oice engineering services. Zoellner et al. (2011) studied several cases to monitor drilling hydraulics by analyzing luid low in relation to pump pressure and other relevant sensor channels. He tried to recognize early the onset of hydraulics related problems in order to take preventive action. he concept is based on recognition variations in expected behaviour of rig sensor responses using hybrid algorithms, which link analytic, static and knowledge bases concepts. he outlined concept to display previous start-up sequences and corresponding parameters to provide a reference for the driller should result in a minimization of start-up time and pressure surge of the

420 Fundamentals of Sustainable Drilling Engineering current sequence in the sense of an on-going optimization process within one BHA run and therefore lost and hidden lost time can be avoided. Tagir et al. (2010) proposed an expert system which ofers an eicient way of combining some basic measurements provided by the surface sensors for early diagnosis and prevention of possible damage of downhole drilling equipment, primarily the drill bit itself. he fundamental theory behind the proposed approach is based on certain elements of fractal analysis as well as artiicial neural networks. Some real iled data examples are used for training the model and assessing the current drill bit conditions by using the proposed methodology. For extending this experience to a real ield application, one should apply the results of the studies obtained in the experimental borehole (i.e. a determined optimal combination of the diagnostic criteria and the sampling frequency) to subsequent boreholes drilled in the same general area, so that the input-output data will be somewhat clustered to reduce uncertainties in problematic scenarios. Authors believe that this methodology opens new opportunities for realtime drilling optimization that can be eiciently implemented within the scope of the existing drilling practice. It should be noted that neural networks-based expert systems usually perform satisfactory interpolation, while it may generate erroneous results in case of extrapolation. Because of this, the more representative and diverse database from the previous experience that is available, the higher the probability of accurate diagnosis that can be potentially achieved. Sawaryn et al. (2010) discussed how data quality inluences worklows and decisionmaking in drilling and completions and examines the use of semi-automated processes for quality assurance. With poor data, additional steps are required and worklows must be repeated. In even relatively simple situations, controlled tests suggest that small changes or omissions may have a signiicant inluence on the work eiciency or outcome. In earlier work, the quality of any data stream has been described in terms of identity, presence, measurement frequency, accuracy, continuity, units and associated metadata. For some of these, a degree of self-checking is possible, applying simple algorithms to the data stream to detect presence and bounds, with alarms to alert the operator if these are transgressed. In other cases, such as the change in drag and torque with depth, the stream must be checked against a trend, called a pseudo-log determined from the physics. hese calculations are performed by “smart agents” directly in real time on the WITSML data feed from the rig. he paper describes the early work developing smart agents to address data quality and structure of the associated toolkit that can be used to construct more complex agents from a wider selection of data sources, including system generated ones. he computational resources required are also discussed. he increase in digital data and the skills shortage makes the manual assurance of all the data streams neither practical nor cost efective. Since current applications are not tolerant of errors and omissions, a step change in data quality will be needed if more automated worklows are to be achieved. Greater assurance of the data at source and an improved understanding of the worklows will help. Mostoi et al. (2010) developed rock strength log of Asmary formation from backward simulation of drilling operation. his log is critical for analysis such as drilling optimization, sand production evaluation and wellbore stability. According to the bit constants estimated from the ield and other bit constants that have been previously calculated from laboratory tests, the drilling operation is simulated and the drilling optimization to minimize the cost per foot

Basics of Drill String Design 421 value is carried out. Based on cost equation, the best bit runs are introduced which can reduce the drilling operation up to 38%. Drilling simulation can improve the drilling schedule estimation. On the other hand, drilling project can be analyzed more accurately from economical view before drilling operation starts. Maidla and William (2010) addressed the measuring techniques that involved data quality control (QC) and automatic drilling operations detections of routine drilling operations. hese are available today in modern drilling programs, and goes through examples of how implementation was carried out in the onshore area in drilling a series of similar wells. Measurement accuracy, training, and the development of new work processes were successfully implemented, which led to key performance indicator (KPI) time savings between 31% and 43%. You cannot improve what you don’t measure. And in this case you cannot measure without a proper data quality control procedure in place. he automatic operations detection technology, preceded by a rigorous data QC process was a means to help prepare meaningful reports to lag opportunities to improve safety and performance. Spoerker et al. (2011) presented a technology, which explains how automatic operations detection was carried out to address the proposed challenges, and the necessary reporting and user interaction needed. he theory and one case history on this was presented and covered the start-up phase of such initiative, and all of its push backs, and lead the readers through the implementation and inal results that were successfully archived. Performance target selection should aim at consistent operation around a best practice rather than operational time only. Based on the deinition of a target value it is possible to calculate the diference in performance for crews, rigs, or complete rig leets as a savings potential. his process can be highly automated and translated to instant performance reports e.g. to be used on the rig as well as trend monitoring on a management level, for example by means of a management score board. Continues monitoring of performance trends will lead to continuous improvement with higher operational consistency and safety. Barbato and Cenberlitas (2011) presented a description and features of the Micro-Flux Control (MFC) system, beneits of standard application, and case studies with real ield data. MFC technology is virtually applicable to any conventional well without compromising existing rig components in order to authorize and optimize data analysis during drilling operations. he overview of the diferent regions has shown that appropriate real time micro-lux analysis of naturally occurring or intentionally induced events combined with Dynamic Mud Weight Management (DMWM) has provided a signiicant advantage in Non-Productive Time (NPT) reduction and an obvious advantage in overall safety. Alum and Egbon (2011) developed a semi-analytical model for ROP based on the original Bourgoyne and Young Model using real time bit records obtained from wells drilled in the Niger Delta reservoirs. Simple regression analysis was applied on the equation on the parameter that contains diferential pressure to obtain regression constants, which were then used to generate mathematical relationship between ROP and drilling luid properties. Gidh et al. (2011) developed an Artiicial Neural Network (ANN) based sotware system to replace the human factor of applying operating parameters such as WOB and RPM. By following the real-time ANN recommendations, changes can be implemented to increase overall ROP while maximizing bit life by managing the dull condition. As a result of applying the model developed here the operator completed the 8–1/2 hole

422 Fundamentals of Sustainable Drilling Engineering section almost three days ahead of plan even with the unplanned trip to retrieve the lost cone. he reduction in drilling days saved the operator approximately $150,000. Van Oort et al. (2011) discussed the job of the optimization center at Shell Upstream Americas. he team of that center is highly efective improvement team capable to help drive performance optimization and the delivery of top quartile performance on its wells in North America and beyond. Using the optimization approaches, it has been possible to help accelerate well delivery times and associated learning curves by as much as factor of three, oten in a minimum amount of time. his approach is a highly efective way to bring performance optimization focus to ield operations. he worklow and organizational structure was applied to well delivery optimization with projects ranging from shale gas drilling in the Continental US and Canada as well as hard rock drilling in the Middle East. Koederitz and Johnson (2011) described the development and ield-testing of an autonomous drilling system. his system sotware uses a test process to evaluate and quantify the drilling performance for a given set of target set points. he research method is used to identify these set points. Its development was based on early work in the application of real-time MSE display. Overall, the ield testing results were favorable, displaying that the potential for autonomous drilling optimization without drilling knowledge is practical, lexible, and economical, exhibiting promise in a range of cost-efective applications. Bataee and Mohseni (2011) predicted the proper penetration rate, optimizing the drilling parameters, estimating the drilling time of a well and therefore reducing the drilling cost for future wells using ANNs. hey got some valuable observations, which were based on their model. Increasing WOB or rotary speed does not always increases ROP. his study shows in some parts which the driller exerts high WOB and rotary speed (N), the ROP value decreases due to cleaning problem and bit loundering. his is the ability of ANN analysis whether no equation can ind the actual amounts of parameters that maximize penetration rate. As results show always less mud weight used leads in higher ROP value, which is a correct concept. Greater range for N and WOB is used and observed that best one was neither the maximum nor the minimum value. An appropriate ROP was selected based on the previous ROP to be achieved by using the modeled function and applying the corresponding drilling bit parameters. Dykstra et al. (2011) focused on the technical challenges faced when drilling the Haynesville shale play in North Louisiana. One of the most daunting is penetrating the hard, abrasive Hosst on sandstone-shale sequence and hard Knowles limestone in the intermediate section of the overburden. he operator applied a systematic drilling eiciency optimization (DEO) approach encompassing well planning, well execution and post-well analysis to drive performance improvement through these formations. Optimization eforts focused on polycrystalline diamond compact (PDC) bit design, bit hydraulic, positive displacement motor (ODM) selection, sot torque rotary system (STRS) utilization, bottomhole assembly (BHA) design and active management of drilling parameters. Combined, these eforts reduced cost per foot and days per thousand feet by over 50% while drilling approximately 70 well over a two-year period. Signiicant technical lessons were as follows: i) PDC cutter selection, cutter placement, blade layout and nozzle placement and orientation can be reined to yield longer, faster bit runs in the Hosst on and Knowles formations, ii) higher hydraulic horsepower contributed to improved bit performance in both hard and sot formations, iii) low speed,

Basics of Drill String Design 423 high torque downhole motors helped protect PDC bits from damage caused by torsional stick-slip, iv) STRS allowed wider ranges of WOB and RPM to be used without stick-slip and improved bit performance on both rotary and motor assemblies, v) he number and placement of stabilizers in BHAs could be adjusted to make them less prone to buckling and lateral vibration over desired range of WOB and RPM and vi) Active monitoring of drilling parameters, Stick-Slip Alarm (SSA) and MSE by rig site and remote personnel improved recognition and mitigation of drilling dysfunctions and improved average ROP and run length.

7.12 Future Trend on Drill String and Bottomhole Assembly Design here are still challenges related to drill string and bottomhole assembly design. he following are some of them. Hole Deviation: In the process of drilling a borehole, geosteering is the process of directing the borehole position (inclination and azimuth angles) on the run to achieve the optimum well placement. hese changes are based on geological information gathered while drilling. here are many companies provide real time geosteering services. However, there are still challenges that need to be addressed. Corrosive Environments: As a result of failure in drill pipe due to corrosion, more focus is being paid to geochemistry. he understanding of geochemistry of the drilling luids and the formation luids is vital in minimizing the failure due to corrosion. It can be mitigated by corrosive scavengers and by controlling the mud pH in the presence of H2S. he corrosion of tubulars may occur because of oxygen, acid gases (CO2 or H2S) that may also be toxic, and/or other chemicals that create a spontaneous electromotive potential. Oxygen is always present in drilling luids. It enters the system during mixing and routine maintenance operations. A few parts per million is suicient to cause signiicant corrosion. Pitting, caused by the formation of oxygen-corrosion cells under patches of rust or scale or at holidays in inhibitor ilms on treated surfaces, is characteristic of oxygen corrosion. he best method for preventing oxygen corrosion is to minimize the entrainment of air at the surface by using only submerged guns in the pits and arranging for returns from desanders, desilters, etc. to be discharged below the pit luid level. he mixing hopper is a prime source of air entrainment, and it should be open only when mud-conditioning materials are being added. When oxygen must be scavenged because of unacceptable corrosion rates, the usual method is to use easily oxidized materials that have minimal efect on drilling luid properties. he most common oxygen scavengers are the soluble sulphite salts. Chromate salts and a few organic materials are used occasionally. When it is not practical to remove oxygen, chemicals may be added that coat or passivate the steel tubulars to minimize the attack by oxygen. he coating materials frequently are oily organic surfactants. Passive elements include certain inorganic and metal organic salts. Removal of H2S is accomplished with iron or zinc materials. hese combine with H2S to form insoluble sulides, which are not easily decomposed to reform into toxic H2S. As a result, removal of H2S is still a challenge.

424 Fundamentals of Sustainable Drilling Engineering Gas Hydrate Inhibitors: Gas hydration inhibitors utilize low molecular weight organic compounds for gas hydrate inhibition. hey have important applications in deepwater drilling. Gas hydrates are clathrates that are formed under the appropriate conditions of temperature and pressure. Clathrates are complexes formed between two chemicals in which one type of molecule completely encloses the other molecule in a crystal lattice. In the case of gas hydrates, hydrogen-bonded water molecules form a cage-like structure that surrounds gas molecules forming a solid substance with a high gas density. An agglomeration of these cage structures can result in blockage of lines and valves in drilling equipment. he hydrates of interest to the petroleum industry are formed with natural gas components, the major component of which is methane, but other components (ethane, propane, isobutane, carbon dioxide, nitrogen, and hydrogen sulide) also form water clathrates and create a real challenge for drill string and BHA design. Shale Inhibitors: Reactive shale tends to adsorb water, which can result in the swelling or disintegration of the shale and lead to problems such as bit balling, high torque and drag, and stuck pipe. Using oil-base mud may solve this problem. If using oil-base mud is not possible due to environmental issues or government regulations, water-based mud should be used with various chemical inhibitors such as organic cationic materials (OCMS), KCl and glycol to control reactive shale. KCl additives work by changing places with sodium atoms in the clay structure since potassium ions are smaller than sodium ions. his causes the clay structure to shrink rather than expand. Soluble silicates have also been used as shale inhibitors. hese materials are soluble at high pH, but precipitate out of solution if the pH drops. Tiny amounts of these silicates enter the pore space between shale structures, and form a barrier to prevent further water penetration and creates problem for BHA. Researchers need to address these issues while designing the drill string and BHA. Some oil companies such as Saudi Aramco have its own laboratories to run studies on how to prevent failures of drill string. With high-tech labs, they were able to develop geochemical studies on all different luids to be encountered during drilling operations. his helps to minimize drill string failures, which results in saving costs.

7.13 Summary he chapter discusses almost all aspects of basic drill string and BHA design including drill bit. he diferent types of drill bit and their applications are outlined in detail. h e ROP optimization and the factors that inluence the ROP are also discussed. he existing ROP models are explained here. he current development in the area and the future trend of drill string and BHA are also presented in the chapter.

7.14 Nomenclature A AB a4

= cross-sectional area, in2 = borehole area, in2 = overbalance exponent

Basics of Drill String Design 425

E h HPB HPds HPp H1

= bit weight exponent = rotary speed exponent = tooth wear exponent = buoyancy factor, fraction = 1 m / s = an empirical factor that depends on hole inclination angle (0.000048 – 0.00000665 for hole angles ranging from 3 to 50) = total depth of luid column or drill pipe, t. = bit diameter = inside diameter of drill pipe, in = outside diameter of drill pipe, in = nozzle diameter = diameter of box at elevator upset, in = drilling speciic energy, psi E = shear modulus of elasticity = 21 = Young’s modulus of elasticity, psi = the fractional tooth height that has been worn away, in = bit hydraulic horse power, psi = horsepower required to turn the rock bit and drill string, hp = horsepower required to rotate the drill pipe, hp = tooth geometry constant used to predict bit tooth wear

Ip

= polar moment of inertia =

a5 a6 a7 Bf Cd D db di do dnz dTE DSE Es

K Ks L Ldc Ldp Ldp1 Ldp2 LHdp Ltdp Ltool joint m N N Opt P Pbh Pd Pf Pt Qbn Qmin Qmin _t R

do4 di4 , in4

32 = constant of proportionality that includes the efect of rock strength = a scaling constant = combined length of pin and box, in = total length of drill collar, t., m = total length of drill pipe, t., m = length of drill pipe grade 1, t. = length of drill pipe grade 2, t. = length of heavy weight drill pipe, t. = total length of drill pipe, t. L 2.253 do dTE = tool joint adjusted length = , t. 12 = slope of the straight line in the plot, psi-1 = drill string rotary speed, rev/min = optimum rotary speed = actual weight or total weight carried by the top joint, lbf = circulating bottomhole pressure, psi = drill pipe yield strength or design weight, lbf = formation luid pressure, psi = theoretical yield strength, psi = low rate through the bit, gpm = minimum torsional yield strength, t.-lbf = minimum torsional yield strength under tension, lbf-t = rate of penetration (ROP), t./hr, t./min

426 Fundamentals of Sustainable Drilling Engineering = distance from the center of the drill pipe to a point under consideration di 2r do , in = ROP at zero overbalance, Pbh Pf 0, t./hr = rate of penetration (ROP) corresponding to 1, t./hr = rate of penetration (ROP) corresponding to 2, t./hr = critical rpm, rev/min = compressive strength of the rock = torque, in-lbf = bit drilling time = torque, lbf-t. = total vertical depth of well, t. = low rate = weight on bit or bit weight, lbf = weight of the drill collar, lbf/t., kg/m = nominal weight of the drill pipe, lbf/t., kg/m = approx. adjusted weight of drill pipe, lbf/t. = plain end weight, lbf/t. = upset weight, lbf/t. = nominal weight of the heavy weight drill pipe, lbf/t. = threshold bit weight = approximate adjusted weight of the tool joint, lbf/t. = vertical weight on bit component = nominal weight of the drill pipe grade 1, lbf/t. = nominal weight of the drill pipe grade 2, lbf/t. = depth of the empty drill pipe, t. = minimum unit yield strength, psi = polar sectional modulus, psi

r

Ro R1 R2 rpmc S T tb Tor TVD v W Wdc Wdp Wdp adj Wdp plain Wdp upset WHdp Wo Wtool joint Wv Wdp1 Wdp2 X Ymin Zp dF = rate of penetration (ROP), t./hr dt Wv = optimum weight on bit and drill bit diameter db opt Wo db f inside m outside s 1 2

= threshold bit weight per inch of bit diameter t

= density of luid outside the drill pipe, ppg = density of luid inside the drill pipe, ppg = mud density, lbm/gal, kg/lt = density of luid outside the drill pipe, ppg = density of steel, lbm/ t.3 = old mud weight, lbf/gal = new mud weight, lbf/gal = shear or torsional stress, psi = Poisson’s ratio, (the ratio of transverse contraction strain to longitudinal extension strain in the direction of stretching force.

o

= stretch due to own weight, in, m

trans longitudinal

)

Basics of Drill String Design 427 dc t 0 1

t a H

m

pb Pbn d t dz

= stretch due to drill collar, in, m = stretch due to tension, t. = shear stress at failure, psi = compressive stress, psi = angle of internal friction = angle of twist, radian = apparent viscosity of drilling luid at 10,000 s–1 = formation abrasiveness constant = bit hydraulic factor, dimensionless = speciic gravity of mud = burst load or pressure, psi = pressure drop across the nozzles of the bit, psi = diferential angle of twist, in–1

7.15 Exercise E7.1: A drill string needs to be design based on the information given here. It is noted that the outer diameter of the drill pipe is 5.5 , total vertical depth is 10,000’, mud weight is 12 ppg. Total MOP is 150,000 lbs and the design factor, SF = 1.2 (tension); SF = 1.1 (collapse). he bottomhole assembly consists of 30 drill collars with an outer diameter of 6.625” where the weight of drill collar is 93 lbf/t. and each collar is 30 t. long. In addition, you need to consider the length of slips is 10 . E7.2: Design a 5.5 and 24.7 lbf/t. drill string using a new pipe to reach a TVD of 12,500 t. in a vertical hole. he bottomhole assembly consists of 25 drill collars with an outer diameter of 6.625 and inner diameter of 2.929 . he weight of drill collar is 93 lbf/t. and each collar is 22 t. long. For design purpose, the additional information are: MW is 10.5 ppg, MOP is 140,000 lbs and the design factors are 80% for tension and 1.125 for collapse. You need to consider the length of slips is 12 . E7.3: A drill string has 5000 t. long, and 5.0 in outer diameter drill pipe. While the pipe was moving, it was suddenly stopped. A torque of 270 lbf-in is applied which develops torsional stress and angle at a distance of 4.15 from the center of the pipe. Assume that the Young’s modulus of elasticity for steel is 29 106 psi and Poisson’s ratio is 0.64. Find out the shock load, torsional stress, maximum shear stress and diferential angle of twist. E7.4: During the drilling operation, 150 hp was applied to rotate the drill string and bit where 800 rpm was recorded from the rotary speed machine. In addition, 105 hp was applied to rotate 2,900 t. of drill pipe, 5.5 in OD with the same speed as drill string. Assume that Cd = 0.0000043. Calculate the required torque for drilling string and the speciic gravity of mud. E7.5: Find out the minimum torsional yield strength and torsional yield strength under tension for the following data: OD = 5.5 in, top joint load is 500,000 lbf. Assume that the ID of the pipe is 4.67 in. E7.6: A 12 ppg mud is circulated through a 5.5 in drill pipe assembly of 4,000 t. If 30 drill collars of 32 t. long each are also used, calculate stretch for drill pipe and

428 Fundamentals of Sustainable Drilling Engineering collar due to their own weight. Assume the OD and ID of drill collar as 6.25 in and 2.8125 in respectively and weight of drill collar is 93 lbf/t. In addition assume that a diferential pull of 800 lbf is applied on the drill pipe. Also ind out the stretch due to tension . E7.7: Estimate the change in penetration rate ater the mud-weight is increased from 20 t./hr to a certain rate using the following data: a4 = 3.46 x10–05, D = 13,500 t., 10.5 lb f / gal, 2 11.0 lb f / gal. 1 E7.8: An initial penetration rate of 20 t./hr is observed in shale at the beginning of a bit run. he previous bit was identical to the current bit and was operated under the same conditions of the bit weight, rotary speed, mud density, and other factors. However, a drilling rate of 12 t./hr was observed in the same shale formation just before pulling the bit. If the previous bit was graded T-6, compute the approximate value of a7.

References Alum, M.A.O and Egbon, F. (2011). Semi-Analytical Models on the Efect of Drilling Fluid Properties on Rate of Penetration (ROP). SPE 150806, presented at the Nigeria Annual International Conference and Exhibition, Abuja, Nigeria, July 30–August 3, 2011. Armenta, M. (2008). Identifying Ineicient Drilling Conditions using Drilling-Speciic Energy. Paper presented at the 2008 Annual Technical Conference and Exhibition held in Denver, Colorado, USA, 21–24 September 2008. Bahari, A. and Seyed, A.B. (2009). Drilling cost optimization in a hydrocarbon ield by combination of comparative and mathematical methods. Pet. Sci. (2009) 6:451-463 Barbato, T.L. and Cenberlitas, A.S. (2011). Enabling Technology Optimizes Dynamic Mud Weight Management and Reduces Well Cost Associated with Drilling Operations. Paper SPE/IADC 140375 presented at the SPE/IADC Drilling Conference and Exhibition held in Amsterdam, 1–3 March 2011. Bataee, M. and Mohseni, S. (2011). Application of Artiicial Intelligent Systems in ROP Optimization: a Case Study in Shadegan Oil Field. Paper SPE 140029 presented at the SPE Middle East Unconventional Gas Conference and Exhibition held in Muscat, 31 January–2 February 2011. Bharadwaj, A.M. and Vinayaka, S. (2013). Drilling Optimization: A Review. International Journal on heoretical and Applied Research in Mechanical Engineering (IJTARME), Volume-2, Issue-1, 2013. Bingham M.G. (1965). A New Approach to Interpreting Rock Drillability. re-printed from Oil and Gas Journal, April 1965. Bond D.F., Scott P.W., Page P.E., and Windham T.M. (1996). Applying Technical Limit Methodology for Step Change in Understanding and Performance. SPE 51181, IADC/SPE Drilling Conference, New Orleans, April 1998. Bourgoyne, A.T. and Young, F.S. Jr. (1974). A Multiple Regression Approach to Optimal Drilling and Abnormal Pressure Detection. Soc. Pet. Eng. J. August, 371–384, Trans., AIME, 257. Bourgoyne, A.T. Jr., Young, F.S. (1974). A Multiple Regression Approach to Optimal Drilling and Abnormal Pressure Detection. SPE 4238, August. Bourgoyne, A.T., Chenevert, M.E., and Millhein, K.K. (1986). Applied Drilling Engineering. Textbook Series, SPE, Richardson, Texas, 2:232–240. Bourgoyne, A.T., Jr. and Young, F.S., Jr. (1973). A Multiple Regression Approach to Optimal Drilling and Abnormal Pressure Detection. SPE 4238, SPE-AIME Sixth Conference on Drilling and Rock Mechanics, Austin, TX, January 1973.

Basics of Drill String Design 429 Carden, R.S., Grace, R.D., and, Shursen, J.L. (2006). Drilling Practices,” Petroskills-OGCI, Course Notes, Tulsa, OK, pp 1–8 Chen, D. C-K. (2004). New Drilling Optimization Technologies Make Drilling More Eicient. Paper ID – 2004-020, presented at the Petroleum Society’s 5th Canadian International Petroleum Conference, Calgary, Alberta, Canada, june 8–10, 2004. Cunningham, R.A. and Eenink, J.G. (1959). Laboratory Study of Efect of Overburden, Formation, and Mud Column Pressures on Drilling Rates of Permeable Formations. Trans., AIME, 216, 9–17. Davis J.C. (2002). Statistics and Data Analysis in Geology, third edition. USA: John Wiley & Sons, Inc: 461. Duklet,P.C. and Bates, T.R. (1980). An Empirical Correlation to predict Diamond Bit Drilling Raets. SPE 9324, 55th Annular Technical Conference and Exhibition of SPE, Dallas-Texas, September 21–24, 1980. Dupriest, F.E. and Koederitz, W.L. (2005). Maximizing Drill Rates with Real-Time Surveillance of Mechanical Speciic Energy. Paper presented at the SPE/IADC Drilling Conference held in Amsterdam, he Netherlands, 23–25 February 2005. Dykstra, M., Schneider, B. and Mota, J. (2011). A Systematic Approach to Performance Drilling in Hard Rock Environments. Paper SPE/IADC 139841 presented at the SPE/IADC Drilling Conference and Exhibition held in Amsterdam, 1–3 March 2011. Eren, T. and Ozbayoglu, M.E. (2010). Real time optimization of drilling parameters during drilling operations. SPE-129126, SPE Oil and Gas India Conference and Exhibition, 2010. Eren, T. and Ozbayoglu, M.E. (2010).Real Time Optimization of Drilling Parameters during Drilling Operations. Paper SPE 129126 presented at the SPE Oil and Gas Conference and Exhibition held in Mumbai, 20–22 January 2010. Estes, J. C. (1971). Selecting the Proper Rotary Rock Bit, ” J. Pet. Tech (Nov. 1971) 1359–1367. Galle, E.M. and Woods, A.B. (1963). Best Constant Weight and Rotary Speed for Rotary Rock Bits,” Drill. and Prod. Prac., API, pp. 48–73. Galle, E.M. and Woods, H.B. (1960). Variable Weight and Rotary Speed for Lowest Drilling Cost. paper presented at 20th Annual Meeting of AAODC, New Orleans, LA, September 25–27, 1960. Gidh,Y., Ibrahim, H. and Purwanto, A. (2011). Real-Time Drilling Parameter Optimization System Increases ROP by Predicting/Managing Bit Wear. Paper SPE 142880 presented at the SPE Digital Energy Conference and Exhibition held in Texas, 19–21 April 2011. Graham J.W. and Muench N.L. (1959). Analytical Determination of Optimum Bit Weight and Rotary Speed Combinations. SPE 1349-G, Fall Meeting of the Society of Petroleum Engineers, Dallas, TX, October 1959. Irawan, S. Rahman, A.M.A. and Tunio, S.Q. (2012). Optimization of Weight on Bit During Drilling Operation Based on Rate of Penetration Model, Research Journal of Applied Sciences, Engineering and Technology 4(12): 1690–1695, 2012. Jacintoa, C.M.C., Filho, P.J.F., Nassar, S.M., Roisenberg, M., Rodrigues, D.G. and Limab, M.D.C. (2013). Optimization Models and Prediction of Drilling Rate (ROP) for the Brazilian Pre-Salt Layer. Chemical Engineering Transactions, 33, 2013, pp. 823–828. Khamis, M.A.N. (2013). Optimization of Drilling Parameters using Speciic Energy in Real Time.PhD dissertation, King Fahd University of Petroleum & Minerals (KFUPM), Dhahran 31261, Saudi Arabia. Koederitz, W.L. and Johnson, W.E. (2011). Real-Time Optimization of Drilling Parameters by Autonomous Empirical Methods. Paper SPE/IADC 139849 presented at the SPE/IADC Drilling Conference and Exhibition held in Amsterdam, 1–3 March 2011. Lummus, J.L. (1970). Drilling Optimization. Journal of Petroleum Technology, pp. 1379, November, 1970.

430 Fundamentals of Sustainable Drilling Engineering Maidla, E. and William, J. (2010). Rigorous Drilling Nonproductive-Time Determination and Elimination of Invisible Lost Time: heory and Case Histories. Paper SPE 138804 presented at the 2010 SPE Latin American & Caribbean Petroleum Engineering Conference held in Lima, 1–3 December 2010. Mathis, W. and honhauser, G. (2007). Mastering Real-Time Data Quality Control – How to Measure and Manage the Quality of (Rig) Sensor Data. Paper presented at the 11th International Conference on Petroleum Data Integration, Information and Data Management in Amsterdam, 19–20 April 2007. Maurer, W.C. (1962). he ‘Perfect-Cleaning’ heory of Rotary Drilling. Journal of Pet. Tech, November 1962. Mitchell, R.F. and Miska, S.Z. (2011). Fundamentals of Drilling Engineering. SPE, ISBN 978-155563-207-6, Richardson, TX 75080 – 2040, USA. Montgomry, D.C. and Runger G.C. (2003). Applied statistics and probability for Engineers, third edition. USA: John Wiley & Sons, Inc: 482. Mostoi, M., Shabazi, K., Rahimzadeh, H. and Rastegar, M. (2010). Drilling Optimization Based on the ROP Model in One of the Iranian Oil Fields. Paper SPE 131349 presented at the CPS/ SPE International Oil & Gas Conference and Exhibition held in Beijing, 8–10 June 2010. Onoe, Y., Yoder, D. and Lawrence, M. (1991).Improved drilling performance eiciency and operations using an advanced real-time information system for drilling. Paper SPE 22571 presented at the 66th Annual Technical Conference and Exhibition of the Society of Petroleum Engineers held in Dallas, 6–9 October 1991. Osgouei, R.E. (2007). Rate of Penetration Estimation Model for Directional and Horizontal Wells. MSc thesis, Petroleum and Natural Gas Engineering, Middle East Technical University, Turkey. Ozbayoglu M.E., Miska, S.Z., Reed T., and Takach N. (2004). Analysis of the Efects of Major Drilling Parameters on Cuttings Transport Eiciency for High-Angle Wells in Coiled Tubing Drilling Operations. SPE 89334, SPE/IcoTA CT Conf. And Exhb., Houston, TX, March 2004. Paes, P., Aragao, A., and Chen, D.C-K.(2005) Cost–Efective Drilling Optimization Technologies in Campos Basin. SPE 94785, presented at the SPE Latin American and Caribbean Petroleum Engineering Conference, Rio de Janerio, Brazil, 20–23 June, 2005. Paiaman, A. M., Al-Askari, M. K. G., Salmani, B., Al-Anazi, B. D. and Masihi, M. (2009). Efect of Drilling Fluid Properties on Rate of Penetration. Nat a, 60 (3) 129–134. Pessier, R.C. and Fear, M.J. (1992). Quantifying Common Drilling Problems With Mechanical Speciic Energy and a Bit-Speciic Coeicient of Sliding Friction. SPE 24584, Washington DC, October 1992. Rashidi, B., Hareland, G. and Nygaard, R. (2008). Real-Time Drill Bit Wear Prediction by Combining Rock Energy and Drilling Strength Concepts. Paper SPE 117109 presented at Abu Dhabi International Petroleum Exhibition and Conference held in Abu Dhabi, 3–6 November 2008. Rashidi, B., Hareland, G., Fazaelizadeh, M., and Svigir, M. (2010a). Comparative Study Using Rock Energy and Drilling Strength Models. Paper ARMA 10-254 presented at the 44th US Rock Mechanical Symposium and 5th U.S.-Canada Rock Mechanical Symposium, held in Salt Lake City, UT June 27–30, 2010. Rashidi, B., Hareland, G., Tahmeen, M., Anisimov, M. and Abdorazakov, S. (2010b). Real-Time Bit Wear Optimization Using the Intelligent Drilling Advisory System. Paper SPE 136006 presented at the 2010 SPE Russian Oil & Gas Technical Conference and Exhibition held in Moscow, 26–28 October 2010. Reza M.R. and Alcocer C.F. (1986b). A Unique Computer Simulation Model Well Drilling: Part II – he Reza Drilling Model. SPE 15109, SPE 56th California, Regional Meeting of SPE, Oakland, CA, April 1986.

Basics of Drill String Design 431 Reza, M.R. and Alcocer, C.F. (1986a). A Unique Computer Simulation Model Well Drilling: Part I – he Reza Drilling Model. SPE 15108, SPE 56th California Regional Meeting of SPE, Oakland, CA, April 1986. Sawaryn, S.J. Whiteley, N. Deady, A. Borresen, A. and Gibson, N. (2010).he Inluence of Data Quality on WorkFlows and Decision-Making in Well Delivery. Paper SPE 1248418 presented at the SPE Intelligent Energy Conference and Exhibition held in Netherlands, 23–25 March 2010. Schreuder J.C. and Sharpe P.J. (1999). Drilling he Limit – A Key to Reduce Well Costs. SPE 57258, Asia Paciic Improved Oil Recovery Conference, Malaysia, October 1999. Sharma, N., Srinivasan, A. and Hood, J. (2010). Case Histories: Real-Time Downhole Data Increase Drilling Eiciency. Paper SPE 126863 presented at the SPE North Africa Technical Conference and Exhibition held in Cairo, 14–17 February 2010. Spoerker, H., honhauser, G. and Maidla, E. (2011). Rigorous Identiication of Unplanned and Invisible Lost Time for Value Added Propositions Aimed at Performance Enhancement. Paper SPE/IADC 138922 presented at the SPE/IADC Drilling Conference and Exhibition held in Amsterdam, 1–3 March 2011. Staveley, C. and how, P. (2010). Increasing Drilling Eiciencies through Improved Collaboration and Analysis of Real-Time and Historical Drilling Data. Paper SPE 128722 presented at the SPE Intelligent Energy Conference and Exhibition held in Netherlands, 23–25 March 2010. Teale R. (1962). he Concept of Speciic Energy in Rock Drilling. International J. Rock Mech. Mining Sci (1965) 2, pp. 57–73. Teale, R. (1965). he Concept of Speciic Energy in Rock Drilling.International J. Rock Mech. Mining Sci, vol. 2, pp. 57–73. honhauser, G. (2004). Using Real-Time Data for Automated Drilling Performance Analysis. Oil Gas European Magazine 4/2004, OG 170–173 van Oort, E., Griith, J. and Schneider, B. (2011). How to Accelerate Drilling Learning Curves. Paper SPE/IADC 140333 presented at the SPE/IADC Drilling Conference and Exhibition held in Amsterdam, 1–3 March 2011. Vogel, S. and Asker, J. (2010). Real Time Data Management and Information Transfer as an Efective Drilling Technique. Paper IADC/SPE 136296 presented at the IADC/ SPE Asia Paciic Drilling Technology Conference and Exhibition held in Vietnam, 1–3 November 2010. Voss, W., homson, S, homson, C, and Buxton, B. (2010). Total System Optimization Delivered Signiicant Performance Improvement and Cost Savings in GoM Challenging Salt Section. Paper IADC/ SPE 128901 presented at the IADC/ SPE Drilling Conference and Exhibition held in New Orleans, 2–4 February 2010. Website 1: http://www.nov.com/Downhole/Drill_Bits.aspx Zoellner, P., honhauser, G., Luetenegger, M. and Spoerker, H.F. (2011). Automated Realtime Drilling Hydraulics Monitoring. Paper IADC/SPE 140298 presented at the SPE/IADC Drilling Conference and Exhibition held in Amsterdam, 1–3 March 2011.

8 Casing Design 8.1 Introduction Drilling a hole for extracting hydrocarbon is not an easy job. It is always a challenge due to the highly diversiied geological structure and petro physical properties of earth deposition and age. In addition while drilling, the well is drilled in sections from surface (for onshore) or the seabed (for ofshore) through all of the formations to the target depth because of the technological limitations. During drilling operations, the well encounters diferent formation zones with enormous challenges such as faults, highpressure formations, toxic materials, and thief zones etc. Lining the inside of the borehole with steel pipe to ensure a hydraulic and mechanical seal seals of the well. Once a certain length of hole is drilled it has to be cased with steel pipe, which is called casing and is joined together by threaded sleeves. herefore, casing is deined as a heavy large diameter steel pipe, which can be lowered into the well for some speciic functions. Casing is using a strong steel pipe used in an oil or gas well to ensure a pressure-tight connection from the surface to the oil or gas reservoir. It is a steel pipe of approximately 40 t. in length that starts from the surface and goes down to the bottom of the borehole. It is rigidly connected to the rocky formation using cement slurry, which also guarantees hydraulic insulation. he space between the casing string and the borehole is then illed with cement slurry before drilling the subsequent hole section. he inal depth of the well is completed by drilling holes of decreasing diameter and uses the same diameter protective casings in order to guarantee the borehole stability. According to API standards, the dimensions of the tubes, types of thread and joints are standardized.

433

434 Fundamentals of Sustainable Drilling Engineering However, special direct-coupling casings without a sleeve joint also exist. he selection of casing sizes, weights, grades, and types of threaded connections for a given situation presents engineering and economic challenge of considerable importance. he costs of the casing can constitute 20–30% of the total cost of the well. Sometimes, it is the greatest single item of expense for the well. Since the cost of the casing can represent up to 30% of the total cost of the well, the number of casing strings run into the well should be minimized. his chapter discusses the types of casings, diferent components of casing and landing procedures. It also discusses the manufacturing of casings, rig side operations, handling procedures, casing design, and selection criteria. Finally, the current practice and future trends in casing for the oil industry are discussed.

8.2 Importance of Casing String Casing the borehole is one of the most important parts of drilling operations. However, casing is normally set to serve a speciic purpose and is neither arbitrary nor compulsory for any hole condition. he casing transforms the well into a stable, permanent structure able to contain the tools for producing luids from underground reservoirs. It supports the walls of the borehole and prevents the migration of luids from layers at high pressure to ones at low pressure. Moreover, the casing enables circulation losses to be eliminated, protects the hole against damage caused by impacts and friction of the drill string, and acts as an anchorage for the safety equipment such as BOPs. Failure of casing or tubing results in expensive reworking and may lead to loss of the well, or loss of life. Casing serves the following important functions in the well. 1) It helps to keep the hole open and provides support for weak, vulnerable or fractured formations. hus it prevents the collapse of the borehole during drilling, and the hole from caving in or washing out. 2) It is used to isolate the porous media with diferent luids, and pressure regimes from contaminating the pay zone. his is basically achieved through the combined presence of cement and casing. hus production from a speciic zone can be achieved. 3) It prevents cross channeling between two or more subsurface luidbearing layers. 4) It prevents the contamination of near-surface freshwater zones and protects freshwater sands from contamination by luids from lower zones. It keeps water out of the producing formation. 5) It protects drilling luids from subsurface formations (prevents lost circulation) and from invasion by formation luids (i.e. saltwater, gas, etc.). 6) It provides a passage for hydrocarbon luids and most production operations are carried out through special tubing, which is run inside the casing. 7) It provides a suitable connection for the wellhead equipment and serves as a structure to install the BOP for well control during drilling. 8) It minimizes the formation of damage by drilling mud (i.e. water-sensitive shale, hydrocarbon-bearing zones).

Casing Design 435 9) It provides a hole of known diameter and depth to facilitate the running of testing and completion equipment. 10) It is used to complete and produce the well eiciently.

8.3 Types of Casing String he functions, and types or names of the various casings vary according to the depth where they are placed. A typical stack of casing showing its threads is shown in Figure 8.1. In reality it is not possible to drill a hole to total depth (TD) with a small diameter drill bit, and then case the hole from surface to TD. his is due to the presence of high-pressured zones at diferent depths along the wellbore, and the presence of weak, unconsolidated formations or sloughing, shaly zones. hese troublesome zones need to be sealed of by running casing and subsequently allow drilling up to TD. As a result, diferent sizes (i.e. continuously decreasing diameter) of casing are used which gives a tapered shape to the inished well. Apart from the diiculties of drilling the rocks encountered, the number and size of casings also depend on the depth of the well and on the reason for drilling. Starting from the uppermost and largest casing, the irst one comes as the conductor pipe, then the surface casing and the intermediate casing, and inally the production casing. In addition, there is a special type of pipe used in ofshore drilling called marine riser. he diferent types of casings are discussed as follows:

8.3.1 Stove Pipe and Riser A stovepipe is used as a marine conductor, drive pipe or structural pile or foundation pile for ofshore drilling only (Figure 8.2a). It is run to prevent washouts of nearsurface unconsolidated formations. It also provides a circulation system for the drilling mud and ensures the stability of the ground surface upon which the rig is placed. For example, Figure 8.2b shows that the circulation is maintained through the conductor pipe attached to the sea loor. In general, stovepipe does not carry any weight from the wellhead equipment and can be driven into the ground or seabed with a pile driver. A typical size for a stovepipe ranges from 26–42 in. However, it may vary from 16 to 60 in diameter and the range of the length is 150 to 300 based the depth of the water depth from the sea level.

Figure 8.1 Casing with threaded joints.

436 Fundamentals of Sustainable Drilling Engineering

with riser mud

Stove pipe

(a) Stove pipe in an ofshore platform

(b) A conductor pipe with riser in the sea bed

Figure 8.2 A typical example of a riser.

A  drilling riser  is a conduit that provides a temporary extension of a  subsea  oil well to a surface drilling facility. In general, there are two diferent types of risers such as marine riser, and tieback riser. A marine riser is the pipe which connects the subsea BOP stack with the loating drilling rig and generally deployed from  ixed platforms  or very stable loating platforms like a  spar  or  tension leg platform  (TLP). A marine drilling riser consists of a large diameter, low pressure main tube with external auxiliary lines that include high pressure choke and kill lines for circulating luids to the subsea blowout preventer (BOP), and usually power and control lines for the BOP. he riser allows mud to be circulated back to surface, and provides guidance for tools being lowered into the wellbore. he international standard ISO 13624-1:2009 covers the design, selection, operation and maintenance of marine riser systems for loating drilling operations. Its purpose is to serve as a reference for designers, for those who select system components, and for those who use and maintain this equipment. It relies on basic engineering principles and the accumulated experience of ofshore operators, contractors, and manufacturers. A tieback riser can be either a single large-diameter high-pressure pipe, or a set of concentric pipes extending the casing strings in the well up to a surface BOP. here are some risers that have joints with buoyancy modules (Figure 8.3). Riser tensioner is a pneumatic or hydraulic device used to provide a constant strain in the cables, which support the marine riser. A telescopic joint is a component installed at the top of the marine riser to accommodate vertical movement of the loating drilling rig.

Casing Design 437

Figure 8.3 Drilling riser joints with buoyancy modules.

8.3.2 Conductor Pipe he conductor is the irst casing string that needs to be run and thus has the largest diameter. he conductor pipe is run from the surface to a shallow depth to protect near surface unconsolidated formations, seal of shallow-water zones (Figure 8.4). It permits the circulation of the mud during the irst drilling phase. It protects the surface of unconsolidated formations against erosion due to the mud circulation, which could compromise the stability of the rig foundations. Conductor pipe protects subsequent

Conduction Pipe

Surface Casing

Production Casing Production Tubing Protect "V" Casing

N. P.

(a) Normally pressured

(b) Abnormally pressured

Figure 8.4 A typical diferent types of casing seats at diferent well depth.

438 Fundamentals of Sustainable Drilling Engineering casing strings from corrosion. It provides protection against shallow gas lows and protects the foundation of the platform in ofshore operations. his casing allows one or more BOPs to be mounted on it or a diverter system if the setting depth of the conductor pipe is shallow. he size of the conductor pipe varies according to the geographical locations. For example, atypical size for a conductor pipe is either 18⅝ or 20 in the Middle East. In North Sea exploration wells, the size of the conductor pipe is usually 26” or 30”. However it might vary from 16” to 48” in diameter and the length of the conductor pipe is normally 40’–300’ (Figure 8.3). In general it is set at approximately 100 t. below the ground level or seabed. Conductor pipe is always cemented to surface. It is used to support subsequent casing strings and wellhead equipment or alternatively the pipe is cut of at the surface ater setting the surface casing. In ofshore operations, conductor pipes are either driven by a hammer or run in a drilled hole or run by a combination of drilling and driving especially where hard boulders are encountered near seabed.

8.3.3

Surface Casing

Surface casing is run ater the conductor casing and is set at approximately 1,000–1,500 t. below the ground level or seabed. It is used to prevent caving of weak formations that are encountered at shallow depths and washing out of poorly consolidated surface beds. his casing should be set in competent rocks such as hard limestone. his will ensure that formations at the casing shoe will not fracture at the high hydrostatic pressures, which may be encountered later. he surface casing is cemented up to the surface to increase its stifness and makes it capable of bearing the compressive loads resulting from the positioning of the subsequent casings. It protects freshwater sands from possible contamination caused by drilling luid mud, oil or gas and or saltwater from lower zone. It is used to provide anchorage for the subsequent casing, and to support the wellhead. he surface casing also serves to provide protection against shallow blowouts and hence BOPs are connected to the top of this string. he setting depth of this casing string is chosen in such as way so that it may protect the troublesome formations, thief zones, water sands, shallow hydrocarbon zones and build-up sections of deviated wells. A typical size of this casing is l3⅜ (Figure 8.5) in the Middle East and 18⅝ or 20 in North Sea operations. However it might vary from 8⅝ to 20 in diameter and the length of the surface casing is normally 300 –5,000 (Figure 8.5). Its length depends on the depth of the aquifers and on the calculated wellhead pressure following the entry of luids from the bottomhole into the casing. In fact, as the surface casing is the irst casing on which the BOPs are mounted, it has to be positioned at a depth where the formation fracturing pressure is suiciently high to allow the BOPs to be closed without any risk.

8.3.4

Intermediate Casing

Intermediate casing is also called protection casing. It depends on well depth and geology in a speciic area. It is usually set in the transition zone below or above an overpressured zone (Figure 8.5). It is used to protect against problem formations such as mobile salt zones, caving shales, thief zones etc. he primary functions of intermediate zones is to seal of troublesome zones which contaminate drilling luid; jeopardize

Casing Design 439 36” Hole 30” Conductor Casing 13? Surface Casing 9? Intermediate Casing

5½ Production Casing

Cement 36” Casing shoe (Conductor Pipe)

Surface Casing

20” Casing shoe (Surface Casing)

Intermediate Casing

6000’

Outmost casing String or Conductor Pipe

2000’

100’

7” Production Casing

Production Casing

Liner 13? ” Casing shoe (Intermediate Casing) Production Tubing 12.25” Casing shoe (Liner) Reservoir Formation

Packer

Figure 8.5 A detail casing placement at diferent well depth with diferent casings.

drilling progress with possible pipe sticking, excessive hole enlargement; contain abnormal pressure luids; protect formation below the surface casing from higher pressure credited by mud. he casing depth of the intermediate columns depends on the pore pressure proile of the underground luids. As the hole goes deeper, the well has to be cased because the hydrostatic pressure of the mud equals the fracturing pressure of the weakest formation present in the openhole. he weakest formation is usually the one nearest the surface, immediately under the last pipe of cemented casing. In this way it is possible to drill every phase of the well with drilling luids of diferent densities. he intermediate casings are cemented along the entire length of openhole, up to about a hundred metres in the preceding casing. Good cementation of this casing must be ensured to prevent communication behind the casing between the lower

440 Fundamentals of Sustainable Drilling Engineering hydrocarbon zones and upper water formations. Multistage cementing may be used to cement this string of casing in order to prevent weak formations from being subjected to high hydrostatic pressure from a continuous, long column of cement. he most common size of this casing is 9⅝ or 10¾ . However it ranges from 7⅝ to 13⅜ in diameter and no speciic range in length.

8.3.5 Production Casing Production casing is the last casing string placed in the hole and it reaches the top of the pay formation. It is set through a productive interval to segregate pay zones, and can be used to produce luid instead of tubing. If the completion is open-hole, or it goes right through all of it, the completion has a cased borehole. he completion equipment is set inside this casing, which enables the underground luids to reach the surface. he primary functions are to isolate producing zones, to provide reservoir luid control and to permit selective production in multi zone production. his is the string through which the well is completed and perforations are made to allow hydrocarbon production (Figure 8.5). he usual sizes of this string are 4½ , 5 and 7 . However it ranges from 4½ to 9⅝ in diameter and no speciic range in length. his is the most important casing and must not collapse since it has to remain eicient for the entire productive life of the well. he design of this casing must ensure its resistance to the maximum pressure exerted by the luids to be produced, and guarantee its resistance to any corrosion that might be induced by the chemical composition of the luids.

8.3.6 Liners A liner is a string of casing that is run in a particular depth of interest within the TD and does not reach up to the surface (Figure 8.5). Liners are hung on the intermediate casing by using a liner-hanger and ensure the hydraulic and mechanical seal (Figure 8.6). In liner completions, both the liner and the intermediate casing perform as the production string because a liner is set at the bottom and hung from the intermediate casing. he major advantages of using the production linear are: i) total costs of the production string are reduced, ii) running and cementing times are reduced, iii) the length of reduced diameter is reduced which allows completing the well with optimum sizes of production tubings. In general, liner is used to reduce the cost of casing which works as an intermediate casing. he choice of a liner rather than a casing depends on economic and technical considerations. It decreases the weight on the hook during the running of the liner into the well. his factor is important especially in deep wells, or when the rig has a limited hook load capacity. Moreover, the liner also leads to improved borehole hydraulics, as the decrease in length of the small-diameter annulus reduces circulation head losses. If necessary, the liners may be backed up to the surface with a casing run downhole in a special seating in the head of the hanger. he liner and its hanger are lowered into the well with a drill string, and its length is such that when the operation is completed the hanger is about 330 t. inside the preceding casing. Typically the major design criterion for a liner is the ability to withstand the maximum expected collapse pressure. he basic types of liner systems are shown in Figure 8.6. For example, drilling liners are used to isolate lost circulation or abnormally pressured zones to permit deeper

Casing Design 441 Intermediate Casing Packer Liner Hanger Casing Shoe

Scab liner Liner

Tie back liner

Scab tie back liner

Figure 8.6 Diferent types of liners attached with casings.

drilling. Production liners are run instead of a full casing to provide isolation across the production or injection zones. he tieback liner is a section of casing extending upwards from the top of an existing liner to the surface. It may or may not be cemented in place. he scab liner is a section of casing that does not reach the surface and is used to repair existing damaged casing. It is normally sealed with packers at top and bottom. In some cases, it is also cemented. he scab tieback liner is a section of casing extending from the top of an existing liner but does reach the surface. he scab tieback liner is normally cemented in place. However, there are some other advantages of using liners that include i) complete wells with less weight landed on wellheads and surface pipes, ii) a scab liner tieback provides heavy wall cemented section through salt sections, iii) permits drilling with a tapered drill string, iv) where rig capacity cannot handle full string; when running heavy 9 5/8” casing, v) to provide a polished bore receptacle (PBR) completion. his type of completion is recognised to be the best casing to tubing seal system, vi) improved completion lexibility, vii) to provide an upper section of casing (tieback liner) which had seen no drilling, viii) for testing in critical areas where openhole testing is not practised. he disadvantages of a liner are i) possible leak across a liner hanger, and ii) diiculty in obtaining a good primary cementation due to the narrow annulus between the liner and the hole.

8.4 Components of Casing String A casing string is made of individual joints of steel pipes of diferent sizes (Figure 8.7). he chart in Figure 8.7 depicts the most common casing size and hole size conigurations. Solid lines indicate commonly used bits for that size pipe and can be considered adequate clearance to run and cement the casing or liner. he dotted lines represent less commonly used conigurations. he selection of one of these broken paths requires that special attention be given to the connection, mud weight, cementing, and doglegs (Economides et al., 1998). Casings are connected together by threaded connections (Figure 8.1). In general, the joints of casing in a string have the same outer diameter and are approximately 40 t. long. A bull-nose shaped device, known as a guide shoe or casing shoe, is attached to the bottom of the casing string (Figure 8.6).

442 Fundamentals of Sustainable Drilling Engineering Casing and liner size (inches)

4

Bit and hole size (inches)

4¾

Casing and liner size (inches)

57 3

5½

5

61 2

61 3

77 3 75 3

Casing and liner size (inches) Bit and hole size (inches)

4½

65 3

77 3

753 3 7 4

7

8½

8¾

9573 9 3

85 3

95 3

85 3

9½

105 3

121 4

103 4

1137 4 11 3

13x x 14

Bit and hole size (inches)

105 3

121 4

Casing and liner size (inches)

113 4 117 3

13x x 14

16

20

Bit and hole size (inches)

143 4

12½

20

26

16

20

24

30

Casing and liner size (inches)

14¾ 17½

Figure 8.7 Diferent sizes of casing string (Mitchell and Miska, 2011).

A casing hanger is a mechanism that locks into the casing head, responsible for hanging the casing pipe (Figure 8.8). It is attached to the top of the casing, which allows the casing to be suspended from the wellhead. Slip hangers seal automatically or manually, depending on the types of seals integral to their installation. here are some other items of equipment such as loat collar, centralizers and scratchers associated with the cementing operation (Chapter 9). hese items may be included in the casing string or attached to the outside of the casing.

8.5 Classiication and Properties of Casing Casing is manufactured in a wide variety of sizes, lengths, grades and weights. Casing can be specially made for diicult environments such as highly corrosive, toxic, and high-pressure zones. A number of diferent coupling types are also available. he detailed speciication of the sizes, weight and grades of casing that are most commonly used has been standardized by the API. he various types of casing and their properties such as sizes, weights and grades that are available can be found in manufacturer catalogues and cementing company handbooks. Casing is generally classiied in manufacturer catalogues and handbooks in terms of i) size (i.e. outside diameter, OD),

Casing Design 443

Figure 8.8 Casing hanger (FMC Technologies, http://www.fmctechnologies.com).

ii) range of length, iii) casing grade, iv) casing weight in wt/t, and v) type of coupling i.e. connections. American Petroleum Institute (API) declared the standardization of casing based on these standards.

8.5.1 Casing Size he outside diameter of a casing is recognized as the casing size. It is the main body of the tubular. he sizes vary from 4.5 to 36 in diameter. hese can be found in manufacturer’s catalogues or the ield book tables. Tubulars with an OD of less than 4.5 are called tubing. Figure 8.7 shows the sizes of casing used for a speciic well, which are generally limited to those standard sizes. he igure also shows the hole sizes required to accommodate these casing sizes. he choice of OD may be limited by the availability of certain sizes.

8.5.2

Range of Length

Casing is normally available in three length ranges as shown in Table 8.1. he joint length of the casing has been standardized and classiied by the API recommendation. In reality it is not possible to manufacture the casing to a speciic length. herefore, when the casing is delivered to the rig side, the length of each joint should be measured Table 8.1 API casing length ranges Ranges

Ranges of Length (t.)

Average length (t.)

R-1

16–25

22

R-2

25–34

31

R-3

>34

42

444 Fundamentals of Sustainable Drilling Engineering and recorded on the tally sheet. he length is measured from the top of the collar to the uppermost thread. Lengths are recorded to the nearest 100th of a foot. he most common range of lengths is 25–34 t. However, the shorter lengths are useful as pup joints when spacing out the hanger.

8.5.3 Casing Grade Casing grades are very much dependent on the chemical composition and the mechanical properties of steel. hese properties of casing difer extensively. A variety of compositions and treatment processes are used during the manufacturing process to develop desired properties. he steel materials manufactured through the process have been classiied by the API into a series of grades (Table 8.2). he table shows the maximum and minimum yield strength in addition to minimum ultimate tensile strength. he minimum elongation is also shown to the corresponding grades. A letter, and a number designate each grade. he letter refers to the chemical composition of the material and the number refers to the minimum yield strength of the material (i.e. N-80 casing means a minimum yield strength of 80,000 psi and K55 has a minimum yield strength of 55,000 psi). herefore, the grade of the casing provides an indication of the strength of casing and the higher the grade is, the higher the strength of the casing shows up. In

Table 8.2 API Recommended Casing Grades and Properties Yield Strength

Minimum Ultimate Tensile Strength

Minimum Elongation

API Grade

Minimum

Maximum

psi

%

H-40

40,000

80,000

60,000

29.5

J-55

55,000

80,000

75,000

24.0

K-55

55,000

80,000

95,000

19.5

C-75

75,000

90,000

95,000

19.5

L-80

80,000

95,000

95,000

19.5

N-80

80,000

110,000

100,000

18.5

C-90

90,000

105,000

100,000

18.5

C-95

95,000

110,000

105,000

18.0

S-95

95,000

110,000

110,000

18.0

T-95

95,000

110,000

105,000

18.0

P-110

110,000

140,000

125,000

15.0

Q-125

125,000

150,000

135,000

18.0

V-150

150,000

180,000

160,000

18.0

Casing Design 445 addition to the API grades, certain manufacturers produce their own grades of material. Both seamless and welded tubulars are used as casing although seamless casing is the most common type of casing and only H and J grades are welded.

8.5.4 Casing Weight Within each grade of casing various wall thicknesses are available for a given OD. he wall thickness is indicated by the weight per foot, which can be obtained from ield book tables. However, as an example, Table 8.3 shows the four diferent weights of 9⅝ casing. API sets the dimensions of casings, where very strict provisions exist for tolerances. As a result, the actual ID of the casing varies slightly in the manufacturing process and thus the drit diameter of casing is mentioned in the speciications for all casing. he drit diameter is the minimum ID of the casing. his diameter would be important when a decision needs to be made for certain drilling or completion tools which will be able to pass through the casing. For example, the drit diameter of 9⅝ and 53.4 lbf/t. casing is less than 8½ bit and therefore an 8½ bit cannot be used below this casing setting depth. If the 47 lbf/t. casing is too weak for the particular application then a higher grade of casing would be used (Section 8.5.3). he volumetric capacity of the casing is calculated using the nominal ID of the casing.

8.5.5 Casing Connections As already mentioned in the length ranges of casing in Table 8.1, sections of piece wise casing are delivered to the rig side. herefore, it must be joined with threaded connectors as each length is run in the well. A threaded connection is used to connect individual joints of casing. It consists of a pin and box. Connections can be of three types–i) threaded and coupled, ii) integral-joint, and iii) lush joints (Figure 8.9). hreaded and coupled connections have pins on both ends of the pipe that screw into a common coupling. For most threaded and coupled casings, the threads are cut into the unaltered diameter of the tubes. Integral-joint casing connections oten have the ends of the casing tube thickened (swaged) on either the tube OD or ID (or both). his provides more metal into which threads can be cut. hese connections are classiied into four types such as API, premium, gastight, and metal-to-metal seals. Table 8.3 API Recommended 9 5/8” Casing Weight Weight

Outer diameter

Inner diameter

Wall thickness

Drit diameter

lbf/t

in

in

in

in

53.5

9.625

8.535

0.545

8.379

47

9.625

8.681

0.472

8.525

43.5

9.625

8.755

0.435

8.599

40

9.625

8.835

0.395

8.679

446 Fundamentals of Sustainable Drilling Engineering

Pin

Pin

Field end

Coupling Box OD same as pipe OD

Box Mill end

Box OD expanded

Pin Threaded and coupled

Integral joint

Flush joint

Figure 8.9 Diferent types of joints.

he coupling must be leak resistant and should have the same or greater physical properties as the casing itself. Various types of connections may be used. he standard types of API threaded and coupled connections are i) short thread connection (STC), ii) long thread connections (LTC), iii) buttress thread connection (BTC), and iv) extreme line connection (ELC). he STC thread proile is rounded with 8 threads per inch and LTC is similar. However, it has a longer coupling, which provides better strength and sealing properties than the STC. he BTC proile has lat crests with the front and back cut at diferent angles. ELC also have lat crests and have 5 or 6 threads per inch. he ELC connection is the only API connection that has a metal-to-metal seal at the end of the pin and at the external shoulder of the connection, whereas all of the other API connections rely upon the thread compound, used to make the connection, to seal of the leak path between the threads of the connection.

8.6 Manufacturing of Casing he three basic processes used in the manufacturing of casing: i) Seamless process ii) Electric-resistance welding, and iii) Electric-lash welding

8.6.1 Seamless Process In the seamless process, a billet is irst pierced by a mandrel in a rotary piercing mill (Figure 8.10). he heated billet is introduced into the mill, where it is gripped by two obliquely oriented rolls that rotate and advance the billet into a central piercing plug.

8.6.2 Electric-resistance Welding In the electric welding processes, lat sheet stock is cut and formed and the two edges are welded together without the addition of extraneous metal to form the desired tube.

Casing Design 447

(a) Rotary Piercing Mills

(c) Reelers

(b) Plug Mills

(d) Sizing Mills

Figure 8.10 Manufacturing of seamless casing (Mitchell and Miska, 2011). PINCH BUTT-END ROLL WELDER

LOOPER

LEVELING & FORMING

UNCOILING

SIZING

WELD BEAD TRIMMER

CUTTING

HIGH FREQUENCY WELDING

COOLING

BLOWER

END-FACING

HYDROSTATIC TEST

GALVANIZING

STRAIGHTENING

THREADING & SOCKETING

MARKING

PACKING

Figure 8.11 Manufacturing process for steel pipes and tubes at TST pipes.

8.6.3 Electric-lash Welding In electric-lash welding technique processes a sheet by cutting it to the desired dimensions, simultaneously forming the entire length to a tube, and lashing and pressing the two edges together to make the weld. Figure 8.11 shows the steps of manufacturing process for steel pipes and tubes in detail.

8.7 Rig-site Operation Rig-site operations are one of the heavy works in the whole drilling operation. here are three types of rig-site operations: i) handling procedure, ii) running procedures, and iii) landing procedures. When handling and running the casing on the rig, there might have damage of the threads, which cause the casing leaks. It is also known for a joint of

448 Fundamentals of Sustainable Drilling Engineering

CASING COUPLING Casing Coupling

Figure 8.12 Installing conductor casing.

the wrong weight or grade of casing to be run in the wrong place. As a result, a weak spot would be creating in the drill string. Such mistakes are usually very expensive to repair, both in terms of rig time and materials. herefore, it is important to use the correct procedures when running the casing.

8.7.1

Handling Procedures

As was deined earlier, casing is a pipe usually larger in diameter and longer than drill pipe and is used to line the hole. Casing operations occur periodically throughout the drilling process starting with the conductor casing, surface casing, intermediate casing, and ending with production string which takes place during well completion (Figure 8.12). here is special equipment that is normally used during the handling process (Figure 8.13, and Figure 8.14). his equipment is heavy. he activities involved in casing operations can vary according to the type of casing being installed, but generally fall into these steps: i) installing casing tools, ii) running casing into the hole, iii) installing casing accessories, iv) circulating and cementing. hese steps are discussed below. i) Stacking: When the casing arrives at the rig site, the casing should be carefully stacked in the correct running order. his is especially important when the string contains sections of diferent casing grades and weights. On ofshore rigs, where deck space is limited, do not stack the casing too high or else. It will create excessive lateral loads on the lowermost row. Casing is of-loaded from the supply boat in reverse order, so that it is stacked in the correct running order.

Casing Design 449

Figure 8.13 Special casing elevators.

Elevators

Monkeyboard

Pipe

Fig. 8.14 Derrickman latching elevators.

ii) Proper Checking: he length, grade, weight and connection of each joint should be checked thoroughly. Each joint should be clearly numbered with paint. he length of each joint of casing is recorded on a tally sheet. If any joint is found to have damaged threads it can be crossed of the tally sheet. he tally sheet is used by the drilling engineer to select those joints that must be run so that the casing shoe ends up at the correct depth when the casing hanger is landed in the wellhead. iii) Coupling Check: While the casing is on the racks the threads and couplings should be thoroughly checked and cleaned. Any loose couplings should be tightened. iv) Proper Protection: Casing should always be handled with thread protectors in place. hese need not be removed until the joint is ready to be stabbed into the string.

450 Fundamentals of Sustainable Drilling Engineering

8.7.2

Running Procedures

Liners are run on a drill pipe with special tools which allow the liner to be run, set and cemented all in one trip (Figure 8.15). he liner hanger is installed at the top of the liner. he hanger has wedge slips. hese slips can be set against the inside of the previous string and can be set mechanically (rotating the drill pipe) or hydraulically (diferential pressure). A liner packer may be used at the top of the liner to seal of the annulus ater the liner has been cemented. he basic liner running procedure is as follows: 1. Visually check each joint of casing/liner to ensure all joints are clear of foreign matter, measured and drited. 2. Reduce the annular preventer closing pressure to less than the collapse rating of the casing/liner, if necessary. 3. Make up a full opening safety valve (in the open position) on the casing circulating swage and position it in a readily accessible drill loor location. 4. Make up the shoe loats and shoe track as per the running list. 5. Check loat equipment ater the shoe track is run in ensure the loat is holding and that circulation is possible. 6. Install centralizers as per the centralizer programme. 7. Partially ill each joint and completely ill every ive joints. 8. Make up the connections in accordance with API Speciication 5CT. 9. Run the casing/liner smoothly, avoiding high acceleration and deceleration, which could cause unnecessary surge/swab pressures. 10. Limit the casing/liner lowering speed to 45 sec/joint or to the optimum speed from surge/swab calculations. 11. Monitor returns constantly by using the trip tank and inform the driller of any potential loss circulation zones. 12. Monitor drags. 13. Count the joints of casing/liner remaining on deck before landing the casing/liner at the settling depth and compare this number against the amount in the hole and amount received at the well site. his should conirm that the casing/liner is set at the proper depth. 14. Minimize the time between landing the casing/liner and breaking circulation to avoid plugging the loat equipment. 15. Land the casing such that it is at a safe height for installing the cementing head, i.e., 4 feet–5 feet above the rig loor if possible. 16. Circulate a minimum volume of 150% of the annulus/casing/liner contents, once circulation has been established. In short, the running procedure can be summarized as run the liner on drill pipe to the required depth, set the liner hanger, circulate drilling luid to clean out the liner, back of (disconnect) the liner hanger setting tool, pump down and displace the cement, set the liner packer, pick up the setting tool, and reverse circulate to clean out cement and pull out of hole.

Casing Design 451 Plug Dropping Head

Setting Tool

Hanger Slick Joint

Cementing Manifold

Liner Tie-Back Sleeve Pack-of Bushing (Retrieval-Optional) Wiper Plug (Shear type) Stand-Of Devices

Landing Collar Float Collar

Float Shoe

Figure 8.15 Casing liner equipment.

8.7.3

Landing Procedures

Casing landing practices vary signiicantly throughout the industry. In some cases, considerable additional axial stress will be placed in the casing when it is landed in the wellhead. Ater the casing is run to the required depth, it is cemented in place while suspended in the wellhead. he method used for landing the casing will vary from area to area, depending on the forces exerted on the casing string ater the well is completed. hese forces may be due to changes in formation pressure, temperature, luid density and earth movements (compaction). Landing procedures follow the following four common methods and the axial stress must be considered in the casing design. An API committee identiied these four common methods for landing casing: 1) Landing the casing with the same tension that was present when cement displacement was completed. 2) Landing the casing in tension at the freeze point, which is generally considered to be at the top of the cement. 3) Landing the casing with the neutral point of axial stress (σz = 0) at the freeze point. 4) Landing the casing in compression at the freeze point.

8.8 Casing Design and Selection Criteria Based on the commercial hydrocarbon quantities discovery, the design of a casing program starts with specifying the surface and bottomhole well locations and the size of

452 Fundamentals of Sustainable Drilling Engineering the production casing. he number and sizes of tubing strings and the type of subsurface artiicial lit equipment may ultimately be placed in the well and determine the minimum ID of the production casing. In general, these speciications are determined for the drilling engineer by other members of the engineering staf. In some cases, consideration must also be given to the possibility of exploratory drilling below an anticipated productive interval. he drilling engineer then must design a program of bit sizes, casing sizes, grades, and setting depths that will allow the well to be drilled and completed safely in the desired producing coniguration. To obtain the most economical design, casing strings oten consist of multiple sections of diferent steel grade, wall thickness, and coupling types. Such a casing string is called a combination string. Additional cost savings sometimes can be achieved by the use of liner-tieback combination strings instead of full strings running from the surface to the bottom of the hole. he casing design process involves three distinct operations: i) the selection of the casing sizes and setting depths; ii) the deinition of the operational scenarios which will result in burst, collapse and axial loads being applied to the casing; and inally iii) the calculation of the magnitude of these loads and selection of an appropriate weight and grade of casing. Before embarking on a casing design exercise, the essential data must be obtained from various sources including: geologists, petrophysicists, reservoir engineers etc. he format given in Table 8.4 shows from where the data may be obtained. Once the above data is obtained, it may be organised in the format given in Table 8.5, which would greatly help in casing design calculations. It should be noted that the accuracy of the casing programme is dependent on the accuracy of data used.

8.8.1

Factors Inluencing Casing Design

Casing design involves the determination of factors that inluence the failure of casing and the selection of the most suitable casing grades and weights for a speciic operation, both safely and economically. he casing programme should also relect the completion

Table 8.4 Sources of data for casing design Data

Source

1. Formation pressure, psi

Ofset wells, well logs, log analyst

2. Casing setting depths, t.

Ofset wells, kick tolerance calculations

3. Fracture gradient in psi/t. or fracture pressure at the casing seat, ppg or psi

Ofset wells, well logs, calculation of fracture gradient

4. Mud density, ppg

As above

5. Mean sea water level, t.

Geographical data

6. Available casing grades and weights

Stock status report

7. Strength properties (i.e. burst, collapse, yield)

API manufacturer’s catalogues

8. Geothermal temperatures, °F, °C

Ofset wells

Casing Design 453 Table 8.5 Essential Data Essential Data Casing OD, in

18⅝

13⅜

9⅝

7

Casing setting depth (TVD), t. Casing grade and weight (lb/t.) I.D., in Drit diameter, in Coupling type Collapse strength, psi Burst strength, psi Body yield strength (lbf x 1000) Connection parting load (lbf x 1000) Mud density to drill hole for this casing, ppg Expected formation pressure at next TD, psi Fracture gradient at casing seat, psi/t. Mudline depth, t. Geothermal gradient,

and production requirements. he following are some of the factors inluencing casing design. 1. A good knowledge of stress analysis and the ability to apply it are necessary for the design of casing strings. he end product of such a design is a ‘pressure vessel’ capable of withstanding the expected internal and external pressures and axial loading. Hole irregularities further subject the casing to bending forces, which must be considered during the selection of casing grades. 2. A safety margin is always included in casing design, to allow for future deterioration of the casing and for other unknown forces, which may be encountered, including corrosion, wear and thermal efects. 3. Loading conditions during drilling and production. 4. he strength properties of the casing seat (i.e. formation strength at casing shoe). 5. he degree of deterioration the pipe will be subjected to during the entire life of the well. 6. he availability of casing.

454 Fundamentals of Sustainable Drilling Engineering

8.8.2 Design Criteria here are three basic forces where the casing is subjected to collapse, burst and tension. hese are the actual forces that exist in the wellbore. hey must irst be calculated and must be maintained below the casing strength properties. In other words, the collapse pressure must be less than the collapse strength of the casing and so on. Casing should initially be designed for collapse, burst and tension. Reinements to the selected grades and weights should only be attempted ater the initial selection is made. he suitability of selected casing depends on the accuracy of data collected in Table 8.5. For directional wells a correct well proile is required to determine the true vertical depth (TVD). All wellbore pressures and tensile forces should be calculated using true vertical depth only. he casing lengths are irst calculated as if the well is a vertical well and then these lengths are corrected for the appropriate hole angle.

8.8.3 Approaches of Casing Design he designer must consider all the anticipated loadings on the casing string at the time when the casing is run and throughout the life of the well. he design must meet the conlicting requirements of collapse and burst, while ensuring the tensile properties of the casing are never exceeded. he most economical design should be selected, consistent with good engineering practice. his usually results in a “combination” string (or tapered string), where the OD remains the same throughout but certain sections of difering grade and weight of casing are included to reduce costs. he below steps are followed in casing design considerations. he following loads should be considered in the approach during casing design: 1. Design Process a) Selection of casing sizes b) Selection of setting depths c) Deinition of design properties d) Calculation of magnitude of properties 2. Design Properties a) Collapse strength or loading (i.e. pressure) b) Burst strength or loading (i.e. pressure) c) Yield strength–tensile and compressive d) Biaxial loading considerations e) Efect of bending 3. Design Procedure a) Collapse pressure calculation b) Burst pressure calculation c) Tensile/compressive strength calculation 4. Safety Factor

8.8.3.1 Design Process he design process includes i) selection of casing sizes, ii) selection of setting depths, iii) deinition of design properties, and iv) calculation of magnitude of properties.

Casing Design 455 1. Selection of Casing Sizes: As mentioned earlier, Figure 8.7 shows the common hole and bit sizes, and casing and liner sizes. he size of the casing strings is controlled by the inner diameter of the production string and the number of intermediate casing strings required reaching the desired depth. To enable the production casing to be placed in the well, the bit size used to drill the last interval of the well must be slightly larger than the OD of the casing connectors. he selected bit size should provide suicient clearance and beyond the OD of the coupling to allow for mud cake on the borehole wall and for casing appliances, such as centralizers and scratchers. he bit used to drill the lower portion of the well also must it inside the casing string above. his, in turn, determines the minimum size of the second-deepest casing string. With similar considerations, the bit size and casing size of successively more shallow well segments are selected. Selection of casing sizes that permit the use of commonly used bits is advantageous because the bit manufacturers make readily available a much larger variety of bit types and features in these common sizes. However, additional bit sizes are available that can be used in special circumstances. 2. Selection of Setting Depths: he selection of the number of casing strings and their respective setting depths generally is based on a consideration of the pore-pressure gradients and fracture gradients of the formations to be penetrated. he pore pressure gradient and fracture gradient data are obtained by the methods presented in Chapter 6. hey are expressed as an equivalent density, and are plotted against depth (Figure  8.16). A line representing the planned-mud-density program is also plotted. he mud densities are chosen to provide an acceptable trip margin above the anticipated formation pore pressures to allow for reductions in efective mud weight caused by upward pipe movement during tripping operations. In summary, when planning a well the formation pore pressures and fracture pressures can be predicted from the following procedure:

Fracture gradient

Pore pressure gradient

Low mud-weight proile

Medium-line mud-weight proile

Alternative mud-weight schedule

Figure 8.16 Alternative mud-weight schedules.

High mud-weight proile

456 Fundamentals of Sustainable Drilling Engineering

Fracture gradient d

Pore pressure gradient

Conductor Surface

Depth

Normal pressure

Equivalent Mud Density

Fracture gradient less kick margin

c

Intermediate

b

Mud density (pore pressure plus trip margin)

a

Production

Depth Objective

Figure 8.17 Casing setting depths (Bourgoyne et al., 1991).

1) Analyze and plot log data or d-exponent data from an ofset (nearby) well. 2) Draw in the normal trend line, and extrapolate below the transition zone. 3) Calculate a typical overburden gradient using density logs from ofset wells. 4) Calculate formation pore pressure gradients from equations (e.g. Eaton). 5) Use known formation and fracture gradients and overburden data to calculate a typical Poisson’s ratio plot. 6) Calculate the fracture gradient at any depth. As mentioned above, equivalent mud density in lbm/gal is an important parameter for setting casing depth. Figure 8.16 shows three mud weight selection principles: low mud weight, median-line mud weight, and high mud weight. he median-line principle is a simple tool to establish an optimal mud weight schedule. he oil industry has commonly used a mud weight barely exceeding the pore pressure, as shown in the let stepped curve in the igure. When borehole stability analysis became invoked, a high mud weight like the right stepped curve was oten recommended to reduce the tangential stress and, hence, the collapse potential of the well. he middle stepped curve gave better results because it is based on the idea of minimum disturbance of the stresses acting on the borehole. Once the formation pore pressure and fracture pressure are set, the casing setting depth is inalized. Figure 8.17 shows the relationship between casing-setting depth and these gradients. A commonly used trip margin is 0.5 lbm/gal or one that will provide 200 to 500 psi of excess bottomhole pressure (BHP) over the formation pore pressure. To reach the depth objective, the efective drilling luid density shown at Point a is chosen to prevent the low of formation luid into the well (i.e., to prevent a kick). However, to carry this drilling luid density without exceeding the fracture gradient of the weakest formation exposed within the borehole, the protective intermediate casing must extend at least to the depth at Point b, where the fracture gradient is equal to the mud density needed to drill to Point a. Similarly, to drill to Point b and to set intermediate casing, the drilling

Casing Design 457 luid density shown at Point c will be needed and will require surface casing to be set at least to the depth at Point d. When possible, a kick margin is subtracted from the true fracture-gradient line to obtain a design fracture-gradient line. If no kick margin is provided, it is impossible to take a kick at the casing-setting depth without causing hydrofracture and a possible underground blowout. Other factors-such as the protection of freshwater aquifers, the presence of vugular lost-circulation zones, depleted low-pressure zones that tend to cause stuck pipe, salt beds that tend to low plastically and to close the borehole, and government regulations-also can afect casing depth requirements. In addition, experience in an area may show that it is easier to get a good casing-seat cement job in some formation types or that fracture gradients are generally higher in some formation types. When such conditions are present, a design must be found that simultaneously will meet these special requirements and the pore-pressure and fracture-gradient requirements outlined above. he conductor casing-setting depth is based on the amount required to prevent washout of the shallow borehole when drilling to the depth of the surface casing and to support the weight of the surface casing. he conductor casing must be able to sustain pressures expected during diverter operations without washing around the outside of the conductor. he conductor casing oten is driven into the ground, and the resistance of the soil governs the length. he casing-driving operation is stopped when the number of blows per foot exceeds some speciied upper limit. Example 8.1: A well is being planned to drill where well completion requires the use of 7-in. production casing set at 15,000 t. Determine the number of casing strings needed to reach this depth safely, and select the casing setting depth of each string. Pore pressure, fracture gradient, and lithology data from logs of nearby wells are given in Figure 8.18. Allow a 0.5 lbm/gal trip margin, and a 0.5 lbm/gal kick margin when making the casing-seat selections. he minimum length of surface casing required to protect the freshwater aquifers is 2,000 t. Approximately 180 t. of conductor casing generally is required to prevent washout on the outside of the conductor. It is general practice in this area to cement the casing in shale rather than in sandstone. Solution: he planned-mud-density program irst is plotted to maintain a 0.5 lbm/gal trip margin at every depth. he design fracture line is then plotted to permit a 0.5 lbm/gal kick margin at every depth. hese two lines are shown in Figure 8.18 by dashed lines. To drill to a depth of 15,000 t, a 17.6 lbm/gal mud will be required (Point a). his, in turn, requires intermediate casing to be set at 11,400 t. (Point b) to prevent fracture of the formations above l1,400 t. Similarly, to drill safely to a depth of 11,400 t. to set intermediate casing, a mud density of 13.6 lbm/gal is required (Point c). his, in turn, requires surface casing to be set at 4,000 t. (Point d). Because the formation at 4,000 t. is normally pressured, the usual conductor-casing depth of 180 t. is appropriate. Only 2,000 t. of surface casing is needed to protect the freshwater aquifers. However, if this minimum casing length is used, intermediate casing would have to be set higher in the transition zone. An additional liner also would have to be set before the total depth is reached to maintain a 0.5 lbm/gal kick margin. Because shale is the predominant formation type, only minor variations in casingsetting depth are required to maintain the casing seat in shale.

458 Fundamentals of Sustainable Drilling Engineering Equivalent Mud Density, lbm/gal 8

10

12

14

16

2,000

20

Fracture gradient

4,000

d

Fracture gradient less 0.5 lbm/gal kick margin

6,000 Depth, ft

18

8,000 10,000 c 12,000 14,000

Pore pressure gradient

b Mud density 0.5 lbm/gal trip margin

a

16,000

Figure 8.18 Setting depth example (Mitchell and Miska, 2011).

Example 8.2: A well is being planned to drill where well completion requires the use of 7-in. production casing set at 15,000 t. Determine the casing size (i.e. OD) for each casing string needed to reach this depth safely. Pore pressure, fracture gradient, and lithology data from logs of nearby wells are given in Figure 8.18. Allow a 0.5 lbm/gal trip margin, and a 0.5 lbm/gal kick margin when making the casing-seat selections. he minimum length of surface casing required to protect the freshwater aquifers is 2,000 t. Approximately 180 t. of conductor casing generally is required to prevent washout on the outside of the conductor. It is general practice in this area to cement the casing in shale rather than in sandstone. Solution: A 7 in. production casing string is desired. An 8.625-in. bit is needed to drill the bottom section of the borehole (Table 8.6). An 8.625 in. bit will pass through most of the available 9.625 in. casings (Table 8.7). However, a inal check will have to be made ater the required maximum weight per foot is determined. According to the data presented in Table 8.6, a 12.25 in. bit is needed to drill to the depth of the intermediate casing. As shown in Table 8.7, a 12.25 in. bit will pass through 13.375 in. casing. A 17.5 in. bit is needed to drill to the depth of the surface casing (Table 8.6). Finally, as shown in Table 8.7, a 17.5 in. bit will pass through 18.625 in. conductor casing, which will be driven into the ground. 3. Deinition of Design Properties: the deinitions of design properties are important for proper calculation. Collapse pressure, burst pressure, yield strength, tensile strength, and compressive strength are the design properties. Collapse pressure: it can be deined as the diference between external and internal pressure. Mathematically, it can be expressed as given by Eq. (8.1):

pb

External pressure Internal pressure

(8.1)

Casing Design 459 Table 8.6 Commonly used bit sizes for running API casing (Burgoyne et al., 1986) Casing Size (OD) (in)

Coupling Size (OD) (in)

Common Bit Sizes Used (in)

5.0

6, 6.125, 6.25

5

5.563

6.5, 6.75

5.5

6.050

7.875, 8.375

6

6.625

7.875, 8.375, 8.5

6.625

7.390

7.875, 8.375, 8.5

7.0

7.656

8.625, 8.75, 9.5

7.625

8.500

9.875, 10.625, 11.0

8.625

9.625

11.0, 12.25

9.625

10.625

12.25, 14.75

10.75

11.750

15.0

13.375

14.375

17.5

16.0

17.0

20.0

20.0

21.0

24.0, 26.0

4.5

p p

EXTERNAL PRESSURE

Figure 8.19 Collapse failure from external pressure.

A detailed description about the collapse pressure is given in Section 7.4.1 of Chapter  7. Here we will discuss some detail of collapse pressure related to casing design. Collapse requirements are mandatory for designing collapse. Collapse pressure is afected by axial stress and if external pressure exerts, collapse failure will happen as shown in Figure 8.19. here are two important factors that afect the collapse pressure: i) the collapse pressure resistance of a pipe depends on the axial stress, and ii) the API design factor. Table 8.8 shows a typical API design factor.

460 Fundamentals of Sustainable Drilling Engineering Table 8.7 Commonly used bit sizes that will pass through API casing (Burgoyne et al., 1986) Casing Size (O.D., in.)

4½

5

5½

6⅝

7

7⅝

8⅝

Weight per Foot (IBM/t) 9.5 10.5 11.6 13.5 11.5 13.0 15.0 18.0 13.0 14.0 15.5 17.0 20.0 23.0 17.0 20.0 24.0 28.0 32.0 17.00 20.00 23.00 26.00 29.00 32.00 35.00 38.00 20.00 24.00 26.40 29.70 33.70 39.00 24.00 28.00 32.00 36.00 40.00 44.00 49.00

Internal Diameter (in.) 4.09 4.052 4.000 3.920 4.560 4.494 4.408 4.276 5.044 5.012 4.950 4.892 4.778 4.670 6.135 6.049 5.921 5.791 5.675 6.538 6.456 6.366 6.276 6.184 6.094 6.006 5.920 7.125 7.025 6.969 6.875 6.765 6.625 8.097 8.017 7.921 7.825 7.725 7.625 7.511

Drit Diameter (in.) 3.965 3.927 3.875 3.795 4.435 4.369 4.283 4.151 4.919 4.887 4.825 4.764 4.653 4.545 6.010 5.924 5.796 5.666 5.550 6.413 6.331 6.241 6.151 6.059 5.969 5.879 5.795 7.000 6.900 6.844 6.750 6.640 6.500 7.972 7.892 7.796 7.700 7.600 7.500 7.386

Commonly Used Bit Sizes (in.) 3⅞

3¾ 4¼

3⅞ 4¾

4⅝ 4¼ 6 5⅝

4¾ 6¼

6⅛ 6

5⅝ 6⅜

6½ 7⅞ 6¾

Casing Design 461 Table 8.7 Commonly used bit sizes that will pass through API casing (Burgoyne et al., 1986) Casing Size (O.D., in.)

9⅝

10¾

11¾

13⅜

16

18⅝ 20

Weight per Foot (IBM/t) 29.30 32.30 36.00 40.00 43.50 47.00 53.50 32.75 40.50 45.50 51.00 55.00 60.70 65.37 38.00 42.00 47.00 54.00 60.00 48.00 54.50 61.00 68.00 72.00 55.00 65.00 75.00 84.00 109.00 87.50 94.00

Internal Diameter (in.) 9.063 9.001 8.921 8.835 8.755 8.681 8.535 10.192 10.050 9.950 9.850 9.760 9.660 9.560 11.154 11.084 11.000 10.880 10.772 12.715 12.615 12.515 12.415 12.347 15.375 15.250 15.125 15.010 14.688 17.755 19.124

Drit Diameter (in.) 8.907 8.845 8.765 8.679 8.599 8.525 8.379 10.036 9.894 9.794 9.694 9.604 9.504 9.404 10.994 10.928 10.844 10.724 10.616 12.599 12.459 12.359 12.259 12.191 15.188 15.062 14.939 14.822 14.500 17.567 18.936

Commonly Used Bit Sizes (in.) 8¾, 8½

8⅝, 8½ 8½ 7⅞ 9⅞ 9⅝

8¾, 8½ 8¾, 8½ 11 10⅝

12¼

11 15 14¾

17½ 17½

Burst pressure: it develops when internal pressure is higher than that of external pressure. It can be rated as

pb

Internal pressure External pressure

(8.2)

Yield strength: the yield strength or yield point of a material is deined in engineering and materials science as the stress at which a material begins to deform plastically.

462 Fundamentals of Sustainable Drilling Engineering Table 8.8 Typical API design factors Required

Forces

Design factor

Design

10,000 psi

Collapse

1.125

11,250 psi

100,000 lbf

Tension

1.8

180,000 lbf

10,000 psi

Burst

1.1

11,000 psi

Prior to the yield point the material will deform elastically and will return to its original shape when the applied stress is removed. Once the yield point is passed, some fraction of the deformation will be permanent and non-reversible. Tensile strength: Tensile strength is a measure of the ability of material to resist a force that tends to pull it apart. It is expressed as the minimum tensile stress (force per unit area) needed to split the material apart. It is also called ultimate tensile strength (UTS), or ultimate strength. Compressive strength: Compressive strength is the resistance of a material to breaking under compression. It can be measured by plotting applied force against deformation in a testing machine. Compressive strength is oten measured on a universal testing machine. 4. Calculation of Magnitude of Properties: he casing string must be designed to stand up to the expected conditions in burst, collapse and tension. For collapse it is considered that hydrostatic pressure increases with depth. For burst, assume full reservoir pressure all along the wellbore. In tension, the tensile stress due to weight of string is highest at top. In addition, casing design is done based on the worst possible conditions. he worst possible cases are i) For collapse design, assume that the casing is empty on the inside (Pinside = 0 psig), ii) For burst design, assume no “backup” luid on the outside of the casing (Poutside = 0 psig), iii) For tension design, assume no buoyancy efect, and iv) For collapse design, assume no buoyancy efect. he above conditions are quite conservative. hey are also simpliied for easier understanding of the basic concepts. During the calculation of the magnitude of properties, the above considerations should be taken care. hese calculations are discussed in the next section.

8.8.3.2 Design Properties and Procedure he design of the casing is based on the i) collapse strength (radial load), ii) burst strength (radial load), iii) yield strength–tensile and compressive, iv) biaxial and triaxial loading, and v) efect of bending. i) Collapse Strength Collapse strength is one of the most important considerations while designing casing string. he following assumptions are made during the design of collapse. 1) he most severe lost circulation problem ater cementing and continuing to drill the next section 2) he most severe collapse loading anticipated when the casing is run 3) For both cases, the maximum possible external pressure results from the drilling luid in the hole when the casing is placed and cemented 4) he beneicial efect of cement is ignored

Casing Design 463 5) he detrimental efect of axial tension on collapse pressure rating is considered 6) he beneicial efect of pressure inside the casing can also be taken into account 7) A safety factor is applied (1.1) he collapse of a steel pipe tube from external pressure is very complex phenomenon and much more diicult to calculate than bursting of pipe from internal pressure. he reason for this is that collapse is an instability type of failure in many cases and is sensitive to many factors such as ovality, the ratio of tube diameter to wall thickness, yield strength, type of steel heat treatment, and localized wall reduction. here is no simple method of calculating the collapse of a tube because collapse strength continues to be proposed and studied (Tamano et al., 1983; Issa and Crawford, 1993; Ju et al., 1998). Formulas for calculating collapse-performance properties were irst introduced in the late 1960s by API. here are four collapse pressure formulas proposed by API as shown in Figure 18.1. hese four collapse pressure formulas are i) yield strength collapse, ii) plastic collapse, iii) transition collapse, and iv) elastic collapse. Figure 8.20 shows the variation of collapse resistance with dn/t for the above four collapse. Five factors (F1, F2, F3, F4, and F5) are used with the tube’s dn/t ratio to determine which of the four collapse-pressure formulas is applied. he factors are dependent on the yield strength of the tube. hey are deined by the following equations:

F1

c0 c1 F2

F3

F4

c6 c7

c2

2 yield

c 4 c5

yield

c8

2 yield

yield

yield

3 RF 2 RF

c10 yield

3 RF 2 RF

F5 Here c0 = 2.8762 c2 = 2.1302 10 11 c4 = 0.026233 c6 = –465.93 c8 = –1.0483 10 8 c10 = 46.95

106

c1 = 1.0679 c3 = –5.3132 c5 = 5.0609 c7 = 3.0867 c9 = 3.6989 F2 RF F1

RF

F4 RF 10 6 10 17 10 7 10 2 10 14

c3

3 yield

(8.3) (8.4)

c9

3 yield

(8.5)

3

1

3 RF 2 RF

2

(8.6)

(8.7)

464 Fundamentals of Sustainable Drilling Engineering 25,000 Plastic

Elastic

7 in. P-110 casing

Yield 15,000 Plastic

API Collapse Resistance, psi

20,000

10,000

5,000

Transition Yield

Transition Elastic

0 5

10

15

20

25

30

35

dn/t

Figure 8.20 Collapse modes.

he dn/t ranges where the four collapse-pressure equations applicable are separated by three changeover points, which are dependent on casing grade and the values of the factors. he equations used to determine these three changeover points are discussed below. Yield-Strength Collapse Pressure Formula: he yield-strength collapse-pressure formula calculates the external pressure that generates the minimum yield stress on the inside wall of a tube and can be derived theoretically using the Lamé equation. He formulated this equation for the thickest-walled tubulars used in oil wells. he equation can be written as:

2

Pcr

dn 1 t yield

(8.8)

2

dn t

dn d values up to the value of the n ratio where the t t dn ratio for this changeover point can plastic collapse formula becomes applicable. he t his equation is applicable for

be calculated as:

F1 2 dn t

2

8 F2

F3

F1 2

yield

2 F2

F3 yield

(8.9)

Casing Design 465 Here dn = nominal OD of pipe, in t = thickness, in Pcr = collapse pressure rating, psi = the minimum yield stress, psi yield Plastic-Collapse Pressure Formula: the equation is based on 2,488 physicalcollapse tests of K-55, N-80, and P-110 casings (API TR 5C3 2800). Statistical methods were used to analyze the results of the physical tests, and a plastic-collapse formula was developed to calculate a collapse value with a 95% probability that the actual collapse pressure will exceed the minimum stated with no more than a 0.5% failure rate:

Pcr

he

yield

F1 F dn 2 t

F3

(8.10)

dn ratio where the changeover from the plastic collapse formula to the transit

tion formula can be calculated as:

dn t

2

F2 F1 3 F2 F1

(8.11)

Transition-Collapse Pressure Formula: the transition-collapse formula was developed to provide a transition from the plastic-collapse formula to the elastic-collapse formula:

Pcr

he

F4 dn t

yield

F5

(8.12)

dn ratio where the changeover from the transition collapse formula to the t

elastic-collapse equation can be calculated as:

dn t

yield

F3

F1 F4

yield

F2 F5

(8.13)

466 Fundamentals of Sustainable Drilling Engineering Elastic-Collapse Pressure Formula: this equation was theoretically derived and was found to be an adequate upper bound for collapse pressures as determined by testing. API adopted this equation in 1968.

Pcr

46.95 106 dn t

dn 1 t

(8.14)

2

Collapse Resistance of Casing with Combined Loading Formula: API ofers an equation to calculate the external pressure equivalent when both external and internal pressures are applied to a tubular:

Peq

Pe

2 dn t

1

(8.15)

Pi

Here Peq = external pressure equivalent in collapse due to external and internal pressure Pe = external pressure, and Pi = Internal pressure Collapse Pressure with Axial Stress: the current API formula accounts for the combined inluence of tension and collapse loading on a casing by modifying the minimum yield strength to the yield strength of an axial-stress-equivalent grade. he equivalent yield-strength formula is: 2 pa

1 0.75

a yield

0.5

a yield

(8.16)

yield

Here pa a

yield

= equivalent yield strength, psi = total axial stress, not included bending due to hole deviation, doglegs, or buckling = minimum yield strength of pipe, psi

Example 8.3: Compute the API collapse-pressure rating for 20-in, K-55 casing with a nominal wall thickness of 0.64 in. and a nominal weight per foot of 135 lbf/t. Solution: Given data: dn = nominal diameter of the casing pipe = 20 in t = thickness of the casing pipe = 0.64 in Wn = nominal weight per foot of the pipe = 135 lbf/t

Casing Design 467 Required data: Pcr = Collapse pressure rating, psi he

dn ratio can be calculated as: t dn = 20/0.64 = 31.25. t

Now ind

dn using Eq. (8.13) t dn t

yield

F3

F1 F4

yield

F2 F5

Compare the two results. It is found that it falls in the range of transition collapse. Compute F1–F5 using the following Equations.

F1

c0 c1

yield

F2

c 4 c5

yield

F3

c6 c7

yield

F4

Here c0 = 2.8762 c2 = 2.1302 10 11 c4 = 0.026233 c6 = –465.93 c8 = –1.0483 10 8 c10 = 46.95

106

2 yield

c3

3 yield

c8

2 yield

c9

3 yield

3 RF (2 RF )

c10 yield

F5

c2

3 RF RF (2 RF )

3

3RF 1 (2 RF )

2

F4 RF c1 = 1.0679 c3 = –5.3132 c5 = 5.0609 c7 = 3.0867 c9 = 3.6989 F2 RF F1

10 6 10 17 10 7 10 2 10 14

Eq. 18.5 is used to calculate collapse pressure rating.

Pcr

Pcr

yield

F4 dn t

55,000

F5 1.989 0.036 31.25

1,520.64 psi

468 Fundamentals of Sustainable Drilling Engineering

ii) Burst Loading Burst pressure is also called internal yield pressure for pipe. In general, the casing experiences a net burst loading if the internal radial load exceeds the external radial load (Figure 8.21). he burst load, ΔPb at any point along the casing can be calculated using Eq. (8.2). In designing the casing to resist burst loading the pressure rating of the wellhead and BOP stack should be considered since the casing is part of the well control system. he following assumptions need to be considered while designing burst pressure. Assumptions 1) Based on well-control condition assumed to occur while circulating out a large kick 2) he burst design should ensure that formation fracture pressure should be exceeded before the burst pressure of the casing is reached 3) he formation fracture pressure is used as a safety pressure release mechanism. 4) he design pressure at the casing seat is equal to the fracture pressure plus a safety margin. 5) he pressure inside the casing is calculated assuming that all of the drilling luid in the casing is lost to the fractured formation leaving only formation gas in the casing 6) he external pressure (backup pressure) outside the casing is assumed to be equal to the normal formation pore pressure 7) A safety factor is assumed (1.1-1.2) Barlow Model: API uses the Barlow model to determine the minimum internal yield pressure for tubular (API TR 5C3). he Barlow equation, which is sometimes called an “API” Burst is:

Pbr

f

2

yield

dn

t

(8.17)

Here f = wall-thickness correction factor = 0.875 for standard API tubulars when a 12.5% wall- thickness tolerance is speciied. Pbr = burst pressure rating, psi

Casing Design 469 API recommends the use of Eq. (8.17) with wall thickness rounded to the nearest 0.001 in and the results rounded to the nearest 10 psi. According to Lame equations, the burst loading can be estimated as:

Pbr

dn2 dm2 yield

(8.18)

dn2 dm2

Here dn = nominal OD of pipe, in dm = maximum pipe body ID based on minimum speciic wall thickness, in Example 8.4: Compute the burst requirement if the pore pressure is 6000 psi if the factor of safety is assumed as 1.1. Solution: Given data: Pp = pore pressure = 6,000 psi Required data: Pbr = burst pressure in psi he burst requirement based on the expected pore pressure can be calculated as:

Pbr

Pp SF

6,000 psi

1.1 6,600 psi

he whole casing string must be capable of withstanding this internal pressure without failing in burst. Example 8.5: Compute the API burst resistance for 20-in, 133-lbf/t, K-55 casing with a nominal wall thickness of 0.64 in. Use Barlow model. Solution: Given data: dn = nominal OD of pipe = 20 in = minimum yield strength of pipe (k-55) = 55,000 psi yield t = nominal wall thickness of pipe = 0.64 in Required data: Pbr = burst pressure in psi

Pbr

f

2

yield

dn

t

0.875

2 55,000 psi 0.65 in 20 in

3,128.13 psi

iii) Yield Strength Yield strength can be expressed as the ability of a metal to tolerate gradual progressive force without permanent deformation. It can be classiied as tensile loading (i.e.

470 Fundamentals of Sustainable Drilling Engineering pressure) and compressive loading. Axial tension loading results primarily from the weight of the casing string suspended below the joint of interest. Pipe body yield strength is the tension force that causes the pipe body to exceed its elastic limit. API deines the pipe body yield strength as the axial load in the tube, which results in the stress being equal to the material’s minimum speciic yield strength (Figure 8.22). To calculate the stress in the tube, the speciic or nominal OD and the ID are used for API casing. For Tension design, assume no buoyancy efect and thus pipe-body tensile strength can be expressed as:

Ften

yield

4

2 dno dni2

(8.19)

Here Ften = pipe-body tensile strength, psi dno = nominal OD of pipe, in dni = nominal ID of pipe, in Equation (8.19) can be written in terms of cross-sectional area as

Ften

yield

As

(8.20)

2 dno dni2 . 4 he efect of compressive forces need only be considered for surface casing, due to the weight transferred from later casing strings. It is not usually a critical factor. So, yield strength in compression is typically assumed to be the same as in tension. However, when a casing is loaded in compression, axial buckling may occur, and the casing may fail before reaching the pipe-body yield strength. Use Paslay and Cernocky (1991) and Mitchell (2003) models.

where, As

Ften

dno

dnini As

Figure 8.22 Pipe-body tensile stress.

Casing Design 471 Example 8.6: Compute the body-yield strength for 20-in., K-55 casing with a nominal wall thickness of 0.64 in. and a nominal weight per foot of 133 lbf/t. Solution: Given data: dn = nominal OD of pipe = 20 in σyield = minimum yield strength of pipe (k-55) = 55,000 psi t = nominal wall thickness of pipe = 0.64 in Wn = nominal weight of pipe = 133 lbf/t. Required data: Ften = body-yield strength in psi his pipe has a minimum yield strength of 55,000 psi and an ID of (K55)

d

20.00 2 0.64

18.72 in

hus, the cross-sectional area of steel can be calculated using the sub-equation of Eq. (8.20) as

As

4

202 18.722

38.93 in2

Now, Eq. 8.20 predicts a minimum pipe-body yield at an axial force of:

Ften

yield

As

55,000 38.93

2,140,907.43 lb f

iv) Biaxial and Triaxial Loading It can be established both theoretically and experimentally that the axial load on a casing can afect the burst and collapse ratings of that casing which is shown in Figure 8.23. It noted that as the tensile load imposed on a tubular increases, the collapse rating decreases and the burst rating increases. his igure also shows that as the compressive loading increases the burst rating decreases and the collapse rating increases. he burst and collapse ratings for casing quoted by the API assume that the casing is experiencing zero axial load. However, since casing strings are very oten subjected to a combination of tension and collapse loading simultaneously, the API has established a relationship between these loadings. he casing will in reality experience a combination of three loads (Triaxial loading). hese are Radial, Axial and Tangential loads (Figure 8.23). he latter being a resultant of the other two. Triaxial loading and failure of the casing due to the combination of these loads is very uncommon and therefore the computations of the triaxial loads on the casing are not frequently conducted. In the case of casing strings being run in extreme environment (>12,000 psi wells, high H2S) triaxial analysis should be conducted. he current API model accounts for the combined inluence of tension and collapse loading on a casing by modifying the minimum yield strength to the yield strength of

472 Fundamentals of Sustainable Drilling Engineering Axial Load

Tangential (Hoop) Load

Radial Load

r

a

t

Figure 8.23 Tri-axial loading on casing.

an axial-stress-equivalent grade. he reduced equivalent yield strength is based on von Mises theory. he equivalent yield-strength formula is give as:

Bouyant weight carried by weakest grade a

d

4

2 0

(8.21)

2 i

d

2 pa

a

1 0.75

0.5

yield

a yield

(8.22)

yield

Here: σa = the axial stress due to tension, psi σpa = the equivalent yield strength, psi d0 = the outer casing diameter, in di = the inner casing diameter, in Biaxial efect is calculated using the following set of equations:

46.95 10

6

F Ypa

3B / A 2 B/A

3B / A B 2 B/A A G

F B A

3

3B / A 1 2 B/A

2

(8.23)

Casing Design 473 where A, B, C, F and G are empirical constants 5

A 2.8762 0.10679 10

B 0.026233 0.50609 10 C

465.93 0.030867

pa

10

2 pa

2 pa

0.36989 10

0.21301 10

pa

0.53132 10

16

3 pa

6 pa

0.10483 10

7

13

3 pa

Example 8.7: Determine the collapse strength for a 5 1/2” O.D., 14.00 lbf/t, J-55 casing under axial load of 100,000 lbf. Solution: Given data: Fab = equivalent axial force, lbf = 100,000 lbf do = the outer casing diameter = 5.5 in di = the inner casing diameter = 5.012 in = the minimum yield strength of the grade = 55,000 psi (Grade J-55) yield Required data: = the equivalent yield strength, psi pa he axial tension will reduce the collapse pressure using Eq. (8.21) and Eq. (8.22) as:

Bouyant weight carried by weakest grade a

4

do2 di2

100,000 lb f 2

4

5.5

24,820 psi

2

5.012 in

2

2 pa

1 0.75

a

0.5

yield

24,820 1 0.75 55,000

2

0.5

a yield yield

24,820 55,000

55,000 38,216 psi

Here the axial load decreased the J-55 rating to an equivalent “J-38.2” rating v) Efect of Bending In directional drilling, the efect of wellbore curvature and vertical deviation angle on axial stress in the casing and coupling must be considered during the casing string design. When a casing is forced to bend, the axial tension on the convex side of the bend can increase signiicantly. In sections of the hole where there are severe dog-legs

474 Fundamentals of Sustainable Drilling Engineering (sharp bends) the bending stresses should be checked. he most critical sections are where dog-leg severity exceeds 10° per 100’. So, stress can be expressed as:

1 E dn K ds 2

b

(8.24)

Here = bending stress b E = Young modulus of elasticity dn = normal OD of pipe Kds = dogleg severity In oilield units where the dog-leg severity, Kds, is expressed as the change in angle in degrees per 100 t. of borehole length, and the pipe is assumed to be steel, the simpliied form of Eq. (8.24) can be written as:

218 dn K ds

b

(8.25)

In terms of an equivalent axial force, Fcr, Eq. (8.25) can be expressed as:

Fab

b

As

218 dn K ds As

(8.26)

he area of steel, As can be expressed as the weight per feet of pipe divided by the density of steel. If we apply ield unit, Eq. (8.26) becomes as:

Fab

64 dn K dsWdp

(8.27)

Here Fab = equivalent axial force, lbf dn = normal OD of pipe, in Kds = dogleg severity, degrees/100t Wdp = weight per foot of drill pipe in air, lbf/t When the axial tension strength (Fcr) divided by the cross-sectional area of the pipe wall under last perfect thread is greater than the minimum yield strength, the joint strength is given by: 5

Fcr

0.95 A jp

140 K ds dn ult

(8.28)

0.8 ult

yield

Here σult = ultimate strength, psi

Fcr A jp

yield

, K ds is in degrees/100ft, and A jp

4

dn 0.1425

2

dn 2 t

2

Casing Design 475 When the axial tension strength divided by the cross-sectional area of the pipe wall under last perfect thread is less than the minimum yield strength, the joint strength is given by: ult

0.95 A jp

Fcr

yield

218.15 K ds dn

yield

0.644

(8.29)

It was developed from the experimental tests conducted with 5.5˝, 17- lbf/t, K-55 casing with short round-thread coupling (STC) Example 8.8: Determine the maximum axial stress for a 5 1/2˝ O.D., 14.00 lbf/t, J-55 casing under axial load of 100,000 lbf axial-tension load in a portion of a directional wellbore having a dogleg severity of 4°/100ʹ. Compute the maximum axial stress assuming uniform contact between the casing and the borehole wall. Solution: Given data: Fab = equivalent axial force, lbf = 100,000 lbf dno = the nominal outer casing diameter = 5.5 in dni = the nominal inner casing diameter = 5.012 in = the minimum yield strength of the grade = 55,000 psi (Grade J-55) yield Required data: = the maximum axial stress, psi pa–max he axial stress without bending can be calculated using Eq. (8.21):

100,000 lb f

Bouyant weight carried by weakest grade a

2 no

d

4

2 ni

2

d

4

5.5

2

5.012 in

24,820 psi 2

he additional stress level on the convex side of the pipe caused by bending can be computed using Eq. (8.25) as:

218 dn K ds

b

218 5.5 4

4,796 psi

So, the total maximum axial stress will be: pa max

a

b

24,820 psi 4,796 psi

29,616 psi

vi) Torsion For most casing strings, torque is seldom applied, and when it must be applied, it is limited to the connection makeup torque Mt. he torsional shear stress acting in the circumferential direction at a radius at some point in the pipe-body wall thickness is

Mt r Jp

(8.30)

476 Fundamentals of Sustainable Drilling Engineering

t 4 dn 2 t

Jp

dn t

1

2

1

1

(8.31)

Here τ = shear stress, psi Mt = makeup torque, = polar moment of inertia Jp If we include internal and external pressures, axial force, bending, and torsion, the von Mises equivalent stress equation for torsion can be written as: 2

2 r

t

vm

t

a

b

2 a

2

b

r

6

2

(8.32)

Here σvm = von Mises triaxial equivalent stress, psi σa = total axial stress, not including bending due to hole deviation, doglegs, or buckling, psi σb = bending stress, psi σr = radial stress, psi σt = tangential stress, psi

8.8.3.3 Design Procedure he inal casing design procedure can be shown at a glance in Figure 8.24 where the steps of casing design process are explained. he casing design process involves three distinct operations: i) the selection of the casing sizes and setting depths, ii) the deinition of the operational scenarios which will result in burst, collapse and axial loads being applied to the casing; and inally iii) the calculation of the magnitude of these loads and selection of an appropriate weight and grade of the casing.

8.8.3.4

Safety Factor

The uncertainty associated with the conditions used in the calculation of the external, internal, compressive and tensile loads described above is accommodated by increasing the burst collapse and axial loads by a design factor (Table 8.8). These factors are applied to increase the actual loading figures to obtain the design loadings. Design factors are determined largely through experience, and are influenced by the consequences of a casing failure. The degree of uncertainty must also be considered (i.e. an exploration well may require higher design factors than a development well). Table 8.9 shows the ranges of factors that are commonly used in addition to Table 8.8.

Casing Design 477 Design Casing Coniguration

Select casing setting depth

Formation, strength, pore pressure, mud weights, geological considerations, directional wellplan, drilling luid selection etc.

Deine load cases for each string

Select casing sizes

Calculation of Internal/External, and axial loads on each string

Well objectives, logging tools, testing equipment, production equipment contingency

Calculation of net collapse, and burst loads

Select casing weight and grade

Calculation of net axial loads

API ratings of casing and design factors

Derate collapse rating of casing based on axial loads

Conirm casing selection

Figure 8.24 Casing design process (Ford, 2005).

Table 8.9 Ranges of typical API design factors Forces

Ranges of design factor

Collapse

1.0–1.125

Tension

1.0–2.0

Burst

1.0–1.33

Triaxial

1.25

8.9 Current Development in Casing Technology With the evolution of casing drilling technology, the need to re-look into the casing design has become one of the essential issues; especially when we consider the deep wells with abnormal conditions. Also exploring in a high sour gas environments leads to improve bodies of the casing from H2S and CO2 attacks. In this part, the recent developments in the casing manufacturing are discussed.

478 Fundamentals of Sustainable Drilling Engineering

8.9.1 Casing Material Development to Protect the Corrosion

104 103

DSS 22Cr-5Ni-3Mo CW 2205

15Cr-60Ni-16Mo 21Cr-61Ni-9Mo 25Cr-50Ni-6Mo

Quench Annealed

27Cr-31Ni-3.5Mo 22Cr-42Ni-3Mo

13Cr

2

10

10

20Cr-25Ni-4Mo

%Cr

API L-80 C-75-2

SS85 SS90

d

API J-55 N-80

an

10–1

M

o

1

Ni

Partial Pressure of CO2, psia

Sour gases such as H2S and CO2 have greater impact on the life of the well. hey mainly attack the steel of the tubulars, and eventually corrosion will occur to their bodies. Tubular manufacturers continued to igure out this issue and ind the permanent solution for it. Unfortunately, the situation cannot be generalized for all environments. Based on this challenging scenario, researchers started to look for each case separately. In the industry, there has been a trend towards the development of increasing severe oil and gas production environments in terms of pressure, temperature, and aggressive luids. his trend is expected to continue into the future. Such severe conditions necessitate the use of Corrosion Resistant Alloys (CRA’s). At present, materials speciications for CRA’s are based on a combination of standard tests (e.g., NACE TM-01-77), it for purpose testing, and experience. Figure 8.25 shows an example of empirically estimated boundaries of CRA performance based on the partial pressures of the H2S & CO2. Production casing and liners are exposed to the produced luids, and in the event of any connection or packer leak, the upper strings of the casings or tie back strings could also be exposed for a long period of time to the sour faces. hese strings must therefore be resistant to Sulide Stress Cracking (SSC) and Stress Corrosion Cracking (SCC). he liners below the packers are exposed to the produced luids, which raise the possibility of the corrosion of steel grades such as Q-125 and SS-110 liners. To counter this, manufacturers start to think if CRAs can be considered in the selection because SCC is a potential problem for certain grades. Severe SSC is addressed well by using the grades T-95 or SS-110, which have reasonable resistance to SSC. In deep wells, it is standard that you must have competent production liners in order to maintain the well integrity for the life of the well. For example, the Kuwait Oil Company (KOC) led the initiative to start using CRAs in their deep wells. he

%

10–2 10–3 10–2

10–1

1

10

102

103

104

Partial Pressure of H2S, psia

Figure 8.25 Empirically Estimated Boundaries of CRA Performance (Al-Saeedi et. al., 2013).

Casing Design 479 following factors were considered when selecting the material for production casings and liners (Al-Saeedi et. al., 2013): • he sour severity with respect to SSC was evaluated reference to new NACE MR-0175/ISO 15156 severity diagram (Figure 8.26), with all operating conditions being in the most severe area for sour service. he Major Manufacturer Material Selection Guide is also shown in Figure 8.27. • he use of C-110 grade is recommended in sour conditions for only intermediate casing because it cannot be considered fully sour grade over the whole range of pH and H2S partial pressure. • T-95 propriety grade is fully resistant to any sour conditions. • Presence of oxygen may have a dramatic corrosion impact on carbon steel equipment in presence of wet luid. • he use of oil-based mud instead of water-based mud strongly minimizes the SSC likelihood for intermediate casing, because of no or low water wetting combined with a limited duration of exposure to a wet sour luid. he CRA grade selected was a 28% Chrome high-alloy austenitic stainless, equivalent strength 125 Ksi, suitable for highly corrosive oil and gas environments. his proprietary grade is characterized by: • Very good corrosion resistance in H2S, CO2, and chloride-containing environments • Very good resistance to pitting owing to its high Pitting Resistance Equivalent (PRE) value of 38 minimum • General corrosion comparable to or better than Alloy 825 • Tensile strength equivalent to ASTM 316 • Very good performance in elevated temperature (geothermal wells) • Entirely non-magnetic properties 0.05psi, 0.3kPa Historical sweet/sour demarcation 6.5

1 5.5

pH

0

2

4.5

3 3.5

2.5

0.1

1

10

100

1000

H2S Partial Pressure, kPa

Figure 8.26 NACE MR 0175/ISO 15156 Sour Service Deinition Diagram (Al-Saeedi et. al., 2013).

480 Fundamentals of Sustainable Drilling Engineering

> 0.1 bar

H2S

> 0.2 bar

232 C

SMC276 (15%Mo)

204 C

SM2050 (11%Mo)

177 C

SM2550 (6%Mo)

149 C

SM2535 (3%Mo) SM2242 (3%Mo)

250 C

SM25CRW SM25CR

200 C

SM22CR

200 C

SM17CRS

180 C

SM13CRS

180 C

SM13CRM

150 C

SM13CR

0.1 bar

0.03 bar

CO2

Nickel Alloy

Duplex Stainless Steel MartenslticFerritic Stainless Steel MartenslticStainless Steel

0.003 bar 0.2 bar

Sour Service > 0.003 bar Sour Service & High Collapse

H2S

High Collapse High Strength 0.003 bar

Sour Service Carbon Steel

Non Sour Carbon Steel

Arctic

Figure 8.27 Major Manufacturer Material Selection Guide (Al-Saeid et. al., 2013).

KOC has run the irst 5˝, 21.4 ppf, 28% Chrome Alloy, 125 Ksi, CRA with premium connection as production in well SA-437. he well was a deviated well with inal angle of 40 degrees. he liner was run at the well TD of 16,504 t, and had a length of 1,740 t, with TOL at 14,764 t. Based on the KOC experience, recommendations are listed below: • Use T-95 and C-110 high quality sour service grades, which provide more than suicient SSC resistance for both the deep oil and gas wells. • For the cemented production liners, the selection of CRA was recommended in order to ensure the long-term mechanical integrity. • he selection between carbon steel and CRA for the irst string of production tubing was dependent on the expected timing of irst production of reservoir water. • Success of well SA-437 encouraged the KOC to extensively use the CRA in all North Kuwait Jurassic wells with high percentages of H2S and CO2.

8.9.2 Development in Casing Connections he growing and development of new drilling techniques is changing the technical requirements for travelers and their connections. Among the diferent new drilling techniques with particular growing and success during the last years, the Drillingwith-Casing is a particular case that introduces particular speciic requirements and

Casing Design 481 needs that are usually devoted to drill pipe strings. he resistance to alternative loading (fatigue) and extra torsion loads are key performance features that were not required for typical tubing and casing connections even a few years ago. Selecting the appropriate connector for each casing string in a well represents a diicult challenge for drilling engineers. A classiication system for premium connectors simpliies the connector selection process. Premium connectors can be classiied into four generic conigurations (Jellison and Davila, 1996): • Metal Seal hreaded and Coupled (MTC): Figure 8.28 provides metalto-metal internal pressure radial seal for MTC. Generally these connection features are a buttress, modiied buttress or hooked thread forms. • Slim-Line High Performance (SLH): Figure 8.29 provides a higher joint strength for SLH. • Integral Flush Joint (IFJ): Figure 8.30 provides maximum running clearance since the box OD is the same as the pipe body OD for IFJ. • Metal Seal, Integrated joint (MIJ): Figure 8.31 provides axial load and pressure capabilities that are equal to those for the pipe.

A2

Ap

A1

Figure 8.28 MTC Connector with Internal, Reverse Angle Torque Shoulder (Jellison and Davila, 1996). A4

Ap

A2

A1

A3

Figure 8.29 SLH connector with Center, Reverse Angle Torque Shoulder (Jellison and Davila, 1996). Ap A2

A1

Figure 8.30 IFJ Connector with External, Square Torque Shoulder (Jellison and Davila 1996). A4

Ap

A1

A2

A3

Figure 8.31 MIJ Connector with External, reverse Angle Torque Shoulder (Jellison and Davila 1996).

482 Fundamentals of Sustainable Drilling Engineering Casing connector selection is inluenced by many factors such as casing string type, well type, well location, anticipated loads, presence and amount of H2S, hole clearance, cost and availability. Connection evaluation performance should pass through some tests in order to be recommended (Qing et al., 2007). hese tests are (santi et al., 2005): • • • •

Finding the best connection and threaded compound combination Investigate stresses and fatigue performance Static capacity veriication test Post-fatigue ISO Series B test to a pre-determined cycle at a certain stress level

Semi-Premium hreaded & Coupled (T & A) Connection: A new development of a cost-efective semi-premium connection and an ultra-high fatigue resistance connection is described in Figure 8.32 (Qing et al., 2007a). he results showed that the connections satisfactorily achieved the requirements established at the beginning of the development program, that is, for the semi-premium connection the purpose was to obtain a better behaviour than the API connections currently used for drilling casing applications. Concerning the premium connection, it was demonstrated that this design satisies the objectives as in all the cases, with the exception of the failure due to tong marks. Fatigue levels exceeded the Class B mean curve without showing any failure on the connections. Based on the experience, the following conclusion was made (Qing et al., 2007b): • he bending angles at which the connections were tested make them suitable for a deviated well. In particular, the upset connections which also allow for very high angles with a very important life.

Figure 8.32 Semi-Premium T and A Connection.

Casing Design 483 • he semi-premium connection presents a very good balance between performance and cost, which makes it appropriate for less demanding wells with no sealability requirements. High torque Casing Connection: As well paths become more complex, and because the available API standard connections (BTC, LTC, and STC) do not meet the requirements of high torque transmission capability, this led to the development of the new casing connection (Sam et al., 2011). he development of new connections should show the following important features: • • • •

High torque transmissibility Compatibility with API buttresses Reasonable cost performance ratio High robustness and qualiication for ield operations

he VA roughneck 4½ in casing connection is being developed to fulill all of the above goals (Figure 8.33). his connection has successfully conducted a ield test at Rohöl-Aufsuchungs Aktiengesellschat (RAG) Austria’s well WIN-002. he make-up of each connection was documented with a torque-turn monitoring system to disclose any possible risk. he records from the ield trial showed good and reproducible results. In advance of the ield trial, several specimens of the connection were made to optimum torque several times. he thread behaviour was monitored and documented by an independent third party inspection company named Tuboscope. No galling or damage occurred at any specimen. he features of the new connection reduce the risk of getting stuck in hole signiicantly. Furthermore, the sealing of the cement slurry is enhanced because of the now possible and non-dangerous rotational movement of the casing string during the cement job. It also showed excellent results at its ield trial, that give encouragement to expand it to the other casing sizes like 5 ½˝ and 6⅝˝. Using of Solid Expandable Casing: Solid expandable tubulars have proven to be a viable technology that enables operators to reach reservoirs that cannot be reached economically using conventional drilling technology. As these systems continue to evolve,

R

VA roughneck

R

J

Spacer

API BTC

Figure 8.33 Shows a comparison between normal BTC and VA roughneck connections. he top is the BTC connection, the middle one is the VA roughneck, and the bottom one is the crossover connecting the two connections.

484 Fundamentals of Sustainable Drilling Engineering new applications are being pursued and implemented. Early wells that applied solid expandable tubulars consisted mainly of simple vertical wells or wells that required some form of simple remediation such as repairing a deteriorated casing. he strategy of using expandables in more challenging wells developed as a result of process reinements and system enhancements (Ming, 2013). here are several avenues to consider when optimizing well design with expandable casings. Opportunities exist to save resources merely by reducing the casing size itself. In addition, the optimization of drilling is available in the most favorable size ranges: not too small, and not too large. In general, there are speciic hole sizes that are more cost efective to drill than other hole sizes. For example, it is generally accepted that hole sizes below 7 7/8 inches are generally more diicult to drill than larger sizes. Smaller bits and other bottomhole assembly (BHA) parts can be less durable due to their smaller weight per feet. he assemblies are also quite lexible, which can lead to drag and buckling problems. Similarly, hole sizes above 12 inches tend to be challenging to drill because scaling up all the components of the BHA is diicult and expensive. Only the bit and few drill collars and stabilizers are near the hole size, and the rest will be undersized. Undersizing leads to pump and hydraulics problems such as annular velocity needed for hole cleaning, cuttings loading and equivalent circulating density. Clearly, using technology that allows more of the hole sections in a well to be drilled in the optimum size range, or sweet spot, will result in dramatic economic beneits. Solid expandable casing technology has added a degree of freedom to the design of the well to allow more of the hole sections to be drilled in the optimum hole size range. Drilling and Reaming of the Hole Sections: In order to install the expandable solid tubulars, the operator needs a method to directionally drill the hole sections as well as ream out the hole to the desired size. his can be achieved by adding a near bit stabilizer, motor, loat sub, and a measurement-while-drilling (MWD) in the BHA. he steerable reaming tool is a tool that has ixed cutters that are ofset like a bi-center bit. However, it has a special stabilization pad that improves the efectiveness of the cutters and reduces vibrations. It is designed to make the BHA perform in a more stable manner in rotary mode compared to a bi-center bit. Expandable Casing: he installation of solid expandable casing involves the drilling of the hole section in which the casing is to be deployed. he bottom section of the expandable liner, called the launcher is then made up and run through the rotary table. his is followed by joints of expandable casing screwed together until the required amount of the liner is hanging on the rotary table. he drill string is then run inside the liner and latched into the expansion cone, which is part of the launcher through the use of a safety thread connection. he liner is then carried to the bottom on the drill string. Once on bottom, the cement is pumped as in an inner string cement job. he liner can be rotated and or reciprocated to facilitate an optimum cement job. Immediately ater the cement is pumped, a latch-down plug is dropped. When the plug reaches the launcher, it sits and creates a pressure chamber below the expansion cone. Expansion is initiated with hydraulic pressure being applied down the drill string. he liner is expanded at approximately 20 to 30 feet per minute per stand. As each stand is removed from the hole, the pressure is bled of, the stand broken out and racked back. hen, the circulation (top drive or Kelly hose) is reattached. his process is repeated until the entire expandable liner has been expanded and sealed back into the base casing. he

Casing Design 485

Drill Hole

Run Expandable Liner

Condition Mud Cement Liner

Pump Plug

Latch Plug Start Expansion

Expand Hanger Joint

Drill Out Shoe

Figure 8.34 Expandable Open Hole Liner System installation sequence (Karl and Mark, 2003).

expansion cone is then recovered to surface and the loat shoe is drilled for the next hole section (Figure 8.34). A case study from a Middle Eastern ofshore operator was planned to address three main areas of concerns: i) poor hole cleaning, ii) losses, and iii) stuck pipes (Karl and Mark, 2003). he economic analysis showed that slimming the top hole section through the use of one string of expandable casing would result in savings in the following areas: i) wellheads, ii) drilling luids, iii) cement, iv) bits, v) lost in hole charges, and vi) platform costs. he process of breaking down the well into its individual component hole sections, looking at the application of expandable casing to each hole section, and then reassembling an optimized well plan has several advantages for developing an optimized well program (Figure 8.35). It provides a clear way to approach developing a new well plan with alternative hole sizes. Using this process, there can be a change from using solid expandable tubular technology in a remedial way to using solid expandable in a forward-looking way. Casing while Drilling Technology: Casing while drilling (CWD) technology is one of the greatest developments in drilling operations. he casing while drilling involves drilling and casing a well simultaneously and hence, the overall cost of drilling may be reduced signiicantly by reducing drilling time and drill string problems encountered during conventional drilling process (Hossain and Amro, 2004). here are a number of reasons for the interest in casing while drilling. he simplest reason is that it eliminates at least one trip (at casing point). his reason alone may be suicient incentive to consider CWD for expensive rig operations. A more important reason for considering the CWD system is that it signiicantly reduces downhole trouble time, while at the same time eliminating certain practices used for trouble avoidance when drilling conventionally. Lost circulation and well control incidents have been almost eliminated in the wells drilled with the CWD system. his is particularly important for wells that encounter a weak zone before drilling into a higher-pressure zone. Oten in this situation it is dificult to balance the lost circulation potential in the upper zone with well inluxes in the lower zone, particularly when tripping out to run casing (Tommy et al., 2004).

486 Fundamentals of Sustainable Drilling Engineering

30” Conductor @ 564’

20” Conductor @ 564’ 24” Hole vs. 36” Hole

185 8 Casing @ 3189’

16” Casing @ 3189’ 18½” Hole vs. 26” Hole

133 8 Liner @ 5932’

133 8” x 16” OHL @ 5932’ 17” Hole vs. 17” Hole

95 8 Liner @ 8668’

7” Liner @ 11,043’ Standard well design stick diagram

95 8 Casing @ 8668’ 12¼” Hole

7” Liner @ 11,043’

Optimized Design stick diagram

Figure 8.35 Well stick chart showing the standard and the optimized one with the incorporation of solid expandable casing (Karl and Mark, 2003).

CWD Systems and Equipment: he CWD system is composed of downhole and surface components that provide the ability to use normal oil ield casings as the drill string so that the well is simultaneously drilled and cased. A retrievable drilling assembly is suspended in a proile nipple located near the bottom of the casing. he casing is rotated from the surface with a top drive for all operations except when there is a normal operational need to drill without drill string rotation. he drilling luid is circulated down the casing ID and up the annulus between the casing and wellbore. he casing used with the casing drilling system is generally the same size, weight, and grade that would normally be used in the well. he casing connections may require a change from the conventional well design because they must provide adequate torsional strength, fatigue resistance, and low clearance. his typically might require that an 8-round connection be replaced with a buttress connection and include a torque ring for additional torque capacity. Both integral and coupled connections have been used successfully. here are two mainstream CWD technologies, namely retrievable (latch) and nonretrievable (cement in place) systems. he retrievable system involves latching the BHA into the irst joint of the casing. Upon reaching the total depth (TD), the latched BHA is pulled out of the hole prior to cementing. he non-retrievable system cementing can be performed immediately ater reaching the TD. In this case, the BHA including the bit must be drilled out in order to drill the next hole section. he non-retrievable system is less complicated to deploy, and is oten more economically attractive than the retrievable system. he BHA of CWD normally consists of a pilot bit with an underreamer located above it to open the hole to the inal wellbore diameter. he pilot bit is sized to

Casing Design 487 pass through the casing and the underreamer opens the hole to the size that is normally drilled to run casing. For example, an 8-1/2” pilot bit and 12-1/4” underreamer may be used while drilling with 9-5/8” 36 ppf casing. he surface CWD equipment consists of the casing drive system (CDS), shown in Figure 8.36, includes a slip assembly to grip the interior of large casing or the exterior of small casing and an internal spear assembly to provide a luid seal to the pipe. his allows the casing to be placed into the drill string without screwing into the top casing coupling. he use of the CDS speeds up the casing handling operation and prevents damage to the threads by eliminating one make/break cycle (Figure 8.36). CWD Accessories: he infrastructure to support drilling with a drill pipe has been developed quite extensively over the past 100 years. he opposite condition existed for CWD when it was irst introduced. he lack of certain support items limited the operations that could be undertaken with casings and an entire suite of auxiliary equipment needed for CWD had to be developed. In many instances, a perceived small market inhibited the development of CWD support accessories by conventional service providers. Underreamers: Both bi-center tools and expandable reaming tools have recently been developed for this application. Unfortunately most of these tools can open the hole only about 20-25% whereas the CWD system requires a tool that can open the hole about 50%. For this reason, underreamers were developed speciically for use with the CWD systems. hese underreamers (Figure 8.37) include features to assure smooth

Figure 8.36 Top drive casing system (CDS) (Tommy et al., 2004).

488 Fundamentals of Sustainable Drilling Engineering

Figure 8.37 CWD underreamer (Tommy et al., 2004).

rotation, minimize the possibility of leaving parts in the hole, and assure that they close when being retrieved. Connections: Casings are not as rugged as drill pipes, nor are they as straight as drill pipes. he tubes and connections are mass-produced to be economical, yet for CWD applications they need a similar load carrying capacity as a drill pipe. Many connections have an adequate axial load rating, but few non-premium connections have adequate torque carrying capacity. his was initially addressed by developing a “multilobe torque ring” that could be inserted in a buttress box to provide a torque shoulder for increased (typically doubling) torque capacity. As the casing drilling process attracted larger projects, connection companies began to develop lower cost premium connections speciically for use with the process and one operator began ordering casing directly from the mill dressed for casing drilling application. Wear Bands: he casing must be in good condition when the drilling is completed because at that point it becomes the casing for completing the well. he condition of the casing ater drilling was evaluated in early ield trials when the casing was tripped out

Casing Design 489 many times and inspected. No wear or damage was seen in the pipe body, nor was any detected by wall thickness inspections. However, it is not unusual for some of the couplings in the lower portion of the casing to be worn, oten on only one side. he casing coupling wear appears to be caused by the angular misalignment of casing joints at the couplings. he misalignment results from the combined tolerances in the four machining operations involved (two pin threads and two box threads), and the fact that the casing itself is not completely straight. Wear protection that is economical and relatively easy to install was developed to resolve this concern. A “wear band” is installed on the casing immediately downhole of the couplings (Figure 8.38). hese bands are installed in the ield with a portable hydraulic crimping tool. he lower end of the wear bands includes about 1 in. of tungsten carbide hard facing material similar to that used for wear protection on drill pipe. Centralizing Tools: Rigid centralizers may be needed for directional performance, wear management, key seat control, and centralization for cementing. No conventional cementing centralizers were found that could take the abuse of drilling and still remain on the casing ater more than a few hours of drilling. he main criteria for a CWD centralizer is that it is economical, rugged enough to withstand drilling forces, and that it can be attached to the casing without altering the casing performance. A centralizer with blades hydro-formed directly on a tubular body was developed as an efective means of centralizing the casing while drilling with it. his patented process shapes the blades by cold metal low similar to the process used for downhole casing expansion. hese stabilizers provide a smooth transition between a stif blade and lexible tube material (Figure 8.39). Cementing Equipment: Once the retrievable drilling assembly is removed from the casing at the casing point, there is no loat equipment in place to prevent the back low of the cement when the cement job is completed. In some cases this has been handled by holding pressure on the casing ater the cement is pumped until it begins to set up. In other cases, a relatively expensive composite cement retainer is run and set with wire line. Neither of these solutions is ideal and better-suited cementing accessories are being developed. Non-drillable pump down loat equipment that lands in the proile

Crimped area Hard Facing Casing Coupling

Wear Band

Figure 8.38 Wear bands installed below couplings (Tommy et al., 2004).

490 Fundamentals of Sustainable Drilling Engineering

Crimping area

Cavity from Hydro-forming TC hard facing

Figure 8.39 Hydro Formed Crimp-on Stabilizer (Tommy et al., 2004).

nipple is available for some sizes of casing for use in cementing the production casing. Pump down composite loat equipment for other intermediate casing is in the late stages of testing. his is just another example of gaps in technology that hinders the introduction of a disruptive technology, but will be illed soon ater the technology begins to gain acceptance in the market place.

8.10 Discussions on Some Case Studies Some cases of using new technologies in casing design are discussed. Here, casing while drilling technology is focused on due to the greater efect on the drilling operations. Underbalance Drilling with CWD Technology (UBDWC): Shell has developed and operated gas ields in south Texas for the past 50 years. hese ields are 10,000 to 16,000-t, high-pressure/high temperature wells and normally have initial shut-in tubing pressures approaching 10,000 psi when virgin pressure sands are completed. he bottomhole temperatures range from 280 to 400°F. Most wells have multiple lowpermeability pay sands that require massive hydraulic fracture treatments to produce economically. Each pay interval is fractured and treated in a separate stage, and the production from all the sands is commingled. Well E was the irst new well designed to include UBDWC. A smaller casing program was possible than that used in ofset wells (Figure 8.40a). he smaller design eliminated a drilling liner by drilling in a tapered string of production casing (3½ × 2⅞-in.) through depleted sands intermingled with high-pressure sands (Figure 8.40b). While drilling Well E, the 7⅝-in. shoe at 9,000 t. broke down at 16.8 lbm/gal, rather than the expected 17.7 lbm/gal, and could not be repaired. Drilling continued with a 16.3 lbm/gal oil-based mud to 10,862 t, with high background gas and lost returns. Ofset wells had required a 17.0 lbm/gal mud to drill to the next casing point (11,300 t). However, the mud could not be raised above 16.3 lbm/gal without losses. he

Casing Design 491

1,700ft

1,700ft 8,150ft 8,869ft

8,860ft high pressure 10,800ft 11,330ft

fault zone depleted

11,330ft

5-in. liner drilled in

depleted 12,430ft

12,430ft

drilled in (a)

(b)

Figure 8.40 Well E: (a) Conventional design in ofset well, and (b) UBDWC design (Gordon et al., 2005).

decision was made to drill in a liner to the next casing point and then sidetrack out of the liner to TD. he original design for Well E had a 5 1⁄2-in., lush-joint liner not suitable for drilling operations. A 5-in., 18 lbm/t. P110, with a non-upset integral lushthreaded connection liner was selected for drilling. A conventional PDC bit was run on bottom and crossed back to the casing with a bit sub containing a backpressure valve. A full-opening auto ill (i.e., ball-activated) loat collar was run two joints of-bottom. A setting sleeve without a hanger or packer was used to rotate the liner on a 3½-in. drill pipe. Ater tripping to the 7⅝ in. shoe, the mud weight was reduced from 16.3 to 15.8 lbm/gal. he liner was drilled 468 t.in. 26 hours (4,000- to 5,000- lbf WOB and 90 to 100 RPM) through a fault zone that had required several LCM cement squeezes on ofset wells. Drilling the liner in allowed the mud weight to be reduced 1.7 lbm/gal lower than on ofset wells, resulting in fewer lost-circulation problems. Penetration rates were similar to conventional drilling results in ofset wells. At TD, a ball was dropped to release the hanger, but the steel ball seat had been eroded and the ball failed to seat. A standing valve was run, but the tool would still not release. he 5-in. liner shoe was tack-cemented in place, the liner-running tool backed of in the casing, and the top of the liner squeezed with cement. A whipstock was run just above the liner loat collar, and a window was milled in the 5-in. liner. At this point, a BHA similar to that of the re-entry program was picked up and run on a tapered 3½-in., 12.95-lbm/t., L80 premium integral wedge thread × 2⅞- in., 7.9-lbm/t., L80 two-step, upset-integral casing string. he oil-based mud was reduced to 12.6 lbm/gal to minimize overbalance in the depleted sands. Figure 8.41 shows the new BHA design for the UBDWC. A rotating head, with remotely operated low line valves was used to divert gas to a large separator or through the choke manifold. Before picking up the BHA, a suicient number of 90-t. stands to drill to TD were made up and stood back in the derrick. Casing-tongs and torque-turn equipment were used to make up each stand. A crossover back to the top-drive connection was made up on each stand, and the BHA was tripped to just above the window. To drill ahead, a stand of 3½-in. casing with a crossover was picked up and made up

492 Fundamentals of Sustainable Drilling Engineering into the string with tongs. he crossover was then made up to the top drive, and drilling commenced. he well was drilled from 11,313 to 12,431 t. through seven sands of varying pressure at an average of 11.3 t./hr. High background gas and a 5- to 30-t. lare were observed. he deepest sand was 400 psi higher than the mud hydrostatic pressure at TD. Without UBDWC, an additional drilling liner would have been required to reach this objective. At TD, 100 bbls of 12.0 lbm/gal mud was pumped ahead of 14.5 lbm/gal cement. he cement was displaced with 11.0 lbm/gal CaCl2, and the rate was varied from 1 to 3 bbls/min throughout the cement job to maintain constant bottomhole pressure. he string was rotated at 20 RPM, and the mandrel hanger was landed ater the plug was bumped. Subsequent cased hole logging indicated excellent cement bond. Eliminating the liner and downsizing the program saved U.S. $750,000 (25% cost reduction). Well E was completed successfully using cased-hole logs. his well demonstrated that severely depleted sands and high-pressure sands could be drilled together, as long as there was no need to trip once TD was reached. UBDWC makes it possible to drill depleted sands intermingled with high-pressure sands in one-hole sections. Smaller casing programs are possible and liners can be eliminated. Well costs in mature south Texas ields have been reduced by 30% through the use of drilling with casing and underbalanced drilling techniques. Lower drilling costs makes smaller reserves targets viable a key advantage in a mature play like the South Texas Vicksburg. Drilling with a liner while underbalanced was done successfully on one well, but several problems were experienced. Drilling with liners has many of the potential beneits of drilling with casing. However, the current liner-running systems need to be modiied for drilling. A limitation of UBDWC is the inability to obtain openhole logs. In most cases in the Shell’s South Texas ields, there is enough ofset data to make an efective completion on the basis of cased hole logging. In step-out or exploration drilling, this is a signiicant limitation.

Tubing Stripper Remotely Operated Flowline Valve 27 8 ” , 7.9#, RTS -6 Casing Rotate pipe during cementing, no centralization Flag joint

Ten Drill Collars

Drilling Landing Nipple Cement Plug Landing Collar Drill Collar Watermelon Mill Drill Collar Watermelon Mill Pony Drill Collar Bit sub w/ back pressure alive 37 8 ” or 4 1 8” PDC Bit

340’ Stabilizer Drill Collar Stabilizer Pony Drill Collar PDC Bit (a)

100’

(b)

Figure 8.41 (a) re-entry BHA prior to drilling with casing, (b) Re-entry BHA used for drilling with casing while underbalanced.

Casing Design 493 CWD in a Salt Dome Environment: Structural traps around salt domes provided some of the earliest production along the Gulf of Mexico coast. Reserves in smaller reservoirs are still being identiied around these domes using 3-D seismic and advanced logging and visualization techniques. he steeply dipping and faulted formations around the domes provide good hydrocarbon traps, however the altered tectonic stresses and complex geology makes drilling the wells challenging (David et al., 2007). One such salt structure is the Chacahoula Dome located in Lafourche Parish, LA. his dome underlies a surface area of about eight square miles with the top of the salts slightly less than 1,000 t. below the surface at its crest. he discovery well for this structure was drilled in 1930. he area has been a continuous source of production of both oil and gas since that time, with sporadic drilling activity continuing until today. Wells as deep as 16,000 t. have been drilled adjacent to the dome, however, most wells are less than 9,000 t. deep. here are currently about 40 producing wells around the dome. he dome is located in a marsh area where drilling locations are limited due to environmental considerations. Most of the current drilling is conducted from pads adjacent existing roads to minimize the environmental impact. Recent wells drilled on the south side of the dome have been problematic to drill because of borehole instability and lost circulation issues leading to stuck pipe and sidetracking the well. Several of the wells were abandoned before reaching the intended target depth. hese wells are targeted at traps formed by the highly dipping formations truncated against the 80o dipping salt face. he reservoirs are typically small fault blocks associated with localized anomalies in the salt body that have been identiied with the better geophysical techniques available today. Figure 8.42 shows the dome structure and the location of the two CWD wells and their recent ofsets. Two wells were drilled with CWD technology to depths of about 7,200 t. he surface holes on both wells were drilled conventionally to 2,500 t. where a 9-⅝˝ casing was set. A seven inch casing was then used to drill the production interval to TD in each well. A it-for-purpose rig was manufactured especially for the CWD operations in this ield. he small rig’s design caused some problems requiring modiications that were worked through in the irst well and before the second well spudded. he largest issue with the rig was an inadequate capacity to handle the drilled solids in the closed loop mud system. his was addressed by adding freestanding solid control equipment. he other signiicant rig related time loss was 45 hours lost on the second well while repairing the draw works. During this time the casing was rotated and circulated to keep it free. Both wells successfully penetrated the target formations. he CWD technology adequately addressed the lost circulation and stuck pipe concerns. No signiicant luid was lost in the production hole section drilled with the casing. he elimination of lost circulation is one of the primary beneits that has been seen for CWD and is attributed to the casing rubbing on the borehole wall as it is rotated and mechanically compacting the ilter cake and enhancing it by grinding drilled cuttings into the wellbore wall surface. A rotary steerable tool was used for sidetracking and deviation control on the irst well. Its directional performance was lawless, but it is relatively expensive and encountered mechanical failures that caused additional BHA trips. A steerable motor was tried for deviation control on the second well, but the service provider did not have a motor compatible with eicient CWD operations.

494 Fundamentals of Sustainable Drilling Engineering

CD 1 Well Location

Salt 45 dip Salt

Recent Pad Wells CD 2 Well Location

Figure 8.42 General location of CWD wells and recent ofset wells (David et al., 2007).

he rotary steerable drilling assembly used for the operation is shown in Figure 8.43. All the directional control part of the BHA and MWD equipment was positioned in the 6-¼˝ pilot hole below the 8-⅞˝ underreamer. A PDC bit was used for sidetracking. his system had no diiculty in sidetracking of the cement plug and drilling the well vertically with an inclination of less than 1o. In general, the production sections of two salt dome wells were drilled with CWD technology in an area where considerable diiculties are encountered in drilling conventional wells. Downhole formation related problems associated with conventional drilling were largely eliminated on these wells. Other mechanical problems related to lack of experience drilling in the area and to the use of new tools largely ofset the gain in drilling eiciency due to eliminating the normal problems. he second well drilled much faster than the irst and demonstrated a cost savings relative to the average cost of recently drilled conventional wells. Eliminating the rig downtime and issues related to the steerable motor should make a third well more cost efective than the best of the ofsets. Shallow Formation-Problems Solutions with CWD Techniques: Orubadi formation is located in Permit PRL 21, in the Western Province of onshore Papua New Guinea (PNG). he PRL 21 is located in the Foreland of the Papuan Basin with more than 3 kilometers of classic, coal, limestone and shale overlying the uppermost sandstone, below the Ieru Shale which is gas bearing in PRL 21. he formation frequently presented some drilling-related issues and tripping in casing operation, such as packof problems and the inability to get the surface casing string to the bottom eiciently due to the sticky nature and reactive clay of the predominantly claystone formation. As a result, dedicated wiper trips are required to ensure a clean borehole prior to the casing-running operation, and consequently, prolonged the drilling lat time over the well. hat is why they think of how to solve these issues in order to optimize the drilling operations. So they proposed to test the CWD technique.

Casing Design 495

DLA

Internal Tandem Stabilizer Spacer Collar

7”Casing Shoe

8 8?” Underreamer

External Tandem Stabilizer

MWD System

Rotary Steerable System

Bit

Figure 8.43 RST BHA (David et al., 2007).

he 13⅜-in × 17-in OD casing bit and 13⅜-in double-valve loat collar were initially made up to the single full casing joint respectively and thread locked the connection in the operator’s supply base prior to loading out to the well location. he 13⅜-in drilling-with-casing spear with lexible joint was picked up to the rig loor and made to the top-drive connection (Figure 8.44). he casings were tripped in hole to 60.39 m and torque rings were installed on every connection. Break circulation was taken at the 18⅝-in. casing shoe with 200 gal/min prior to drilling the new formation. he

496 Fundamentals of Sustainable Drilling Engineering

DP Pup Joint Crossover

Stop Ring

Slips

Drag Block

Pack-of Rubber Cup

Bullnose

Figure 8.44 CWD spear (Budi and Keith, 2013).

drilling-with-casing operation commenced with low drilling parameters to keep the vertical integrity of the wellbore, with a 200 to 500 gal/min low rate, 130 to 470 psi standpipe pressure (SPP), 1 to 5 klb WOB, 0.9 to 2.9 kt-lb torque, and 20 to 50 RPM. he casing strings were seen erratically vibrating, and in order to avoid damage on the rig diverter connection, the drilling operation was stopped. However, slow rotation and a low circulation rate were allowed to prevent sticking issues while the rig was chained up to the diverter system to center the position. he vibration was allegedly due to less weight on the casing string while drilling through a shallower formation. he vibration issue was gradually alleviated while drilling through a deeper formation. he drilling parameters were later altered to suit the formation from 177 m, and 20 bbl of Hi Vis pill were pumped when required on the ly. he bit had to be picked up and cleaned several times to gain a worthwhile ROP while drilling through the clay formation as the ROP oten dropped while drilling through the sot and sticky rock. Twenty bbls of Hi Vis sweeps were pumped down to aid in cleaning the bit. Erratic torque and SPP were observed at 757 m. A mitigation technique was attempted by working the strings up and down and 40 bbl of Hi Vis sweep plus detergent was pumped down to ensure the hole and bit was cleaned. Upon one joint drilled down, the string was wiped up and

Casing Design 497 down a full joint length about three times to ensure there was no signiicant drag or ill prior to making up the connection. his step was repeated to ensure the borehole was clean and no signiicant drag or ill was observed. Optimum drilling parameters of 15 to 22 klb WOB, 40 to 70 RPM, 1.5 to 5.6 kt-lb torque, 700 to 800 gal/min low rate and 340 to 410 psi SPP were applied to improve the drilling penetration rate, which was noted to be very low from 1 to 4 m/hr, starting from a depth of 959 m and continuously lasting until 1,000 m. Some attempts had been taken to improve the drilling rate (i.e. adding additional KCl on to the mud system to assist in cleaning the bit face from sticky clay, picking up the pipe, and fanning and cooling the bit). However, very little progress was made. herefore, the operator representative on board called out to stop the drilling operation at the 1,000.7 m section of total depth (TD). he formation at 1,000 m was recorded as 20% sandstone and 80% claystone. As a result of this successful operation, below were the achievements: • 85 joints of 13⅜-in., 68 ppf, N80, BTC (with torque rings) casing were safely drilled down, set, and cemented in place at section TD of 1,000.7 m MD/TVD. • he new world record of the total distance drilled of 935.70 m in the PNG area with 13⅜-in casing to date. • he well was successfully maintained vertically where an inclination at 1,012.03 m MD was recorded at 0.56o. • he spear performed exceptionally in carrying high drilling induced loads, torque and tension of the casing string during the drilling-withcasing operation without any signiicant issues. • No near misses or accidents were recorded to either personnel or the environment. he main objective to case of the problematic zone was achieved, and the operator was enabled to set the casing through the troublesome Orubadi formation in a single trip.

8.11 Future Trend on Casing Design Development he oil and gas industry is always on top of solving issues and problems that could face the operations. he development of casing will continue to improve. Although the current developments have solved several issues related to drilling, still there are many areas that need to be addressed. his part of the chapter addresses some of these areas. BHA of the CWD in Deviated Wells: he current technology applied to drilling deviated and horizontal wells is to use the retrievable CWD technique. Ater completing the drilling of the well, BHA must be retrieved before cementing the casing. his operation will be time consuming and there is a risk of the sticking of the casing. herefore, if a BHA can be developed in such a way that it can be cemented along with the casing and later can be drilled out this will be good for having safe operations. In fact it is diicult if not impossible to decide to leave the BHA in the hole because some of its tools have a radioactive source, which must be recovered out. So in that case they can develop a procedure to retrieve these radioactive sources before cementing the BHA in the hole or they can develop radioactive sources that lose their energy ater

498 Fundamentals of Sustainable Drilling Engineering some time. he operations of cementing the BHA in the hole will be cost efective in deep water where the cost can be as high as one to two million dollars a day. Using of CWD in the Managed Pressure Drilling (MPD) Operations: CWD can be very useful in MPD situations where controlling the annulus pressure is critical. Instead of drilling the wall with a pipe and later running the casing, casing can be utilized to drill the well and case it right ater drilling. By doing this, we can eliminate many risks and at the same time add a new means for controlling the well. CWD can ofer a safe and cost efective solution especially in ultra-deep ofshore locations and provide good controlling capabilities. CWD can eliminate the problems associated with tubular tripping in and out. So it can considerably reduce the risks in the unconventional drilling situations like the narrow drilling window environments. Mud Cap Drilling (MCD) Using CWD Technology: CWD technology is very useful when dealing with situations where MCD is needed to apply. MCD is used where there is a real well control situation of having severe losing and potential well kick from the top zones. herefore, in order to isolate lost zones, MCD is the primary priority to avoid critical situations. So CWD technology can play a very good line of defense in case of any uncontrolled situations. So the operator can decide to case the well in case there is a well kick ater a severe loss. By doing that they can set the casing earlier, but at the same time they will not lose the well or end up with a catastrophic situation.

8.12 Summary Casing technology is one of the most important pillars in oil industry operations. It is very important to give it a higher attention during well construction. he failure to select the optimum casing will lead to losing the well. he fundamental aspects of casing, its design criteria and selection procedure are outlined here. he current developments such as casing connection, CRA alloy for deep HPHT areas, expandable casing, and casing-while-drilling technology are highlighted. Some examples of these developments have been discussed as case study to evaluate the achievements as compared to the old technologies of the casing. he areas that need to be looked at in the future are also proposed. hese areas include mainly introducing the developed technologies of casing into the areas of unconventional drilling such as MPD, MCD, and CWD BHA for the deviated and horizontal wells.

8.13 Nomenclature do di dm dn dni dno E Jp Kds

= the outer casing diameter, in = the inner casing diameter, in = maximum pipe body ID based on minimum speciic wall thickness, in = nominal OD of pipe, in = nominal ID of pipe, in = nominal OD of pipe, in = Young modulus of elasticity = polar moment of inertia = dogleg severity, degrees/100t

Casing Design 499 = wall-thickness correction factor = 0.875 for standard API tubulars when a 12.5% wall-thickness tolerance is speciied. F1, F2, F3, F4, and F5 = Five factors used in Eqs. (8.3–8.7) Fab = equivalent axial force, lbf Ften = pipe-body tensile strength, psi Mt = makeup torque, = burst pressure rating, psi Pbr = external pressure, psi Pe = Internal pressure, psi Pi = collapse pressure rating, psi Pcr = external pressure equivalent in collapse due to external and internal pressure Peq t = thickness, in Wdp = weight per foot of drill pipe in air, lbf/t = total axial stress, not including bending due to hole deviation, doglegs, or σa buckling, psi = bending stress, psi σb = radial stress, psi σr = tangential stress, psi σt = equivalent yield strength, psi σpa σult = ultimate strength, psi σyield = the minimum yield stress or strength of pipe, psi σvm = von Mises triaxial equivalent stress, psi τ = shear stress, psi f

8.14 Exercises Ex 8.1: A well is being planned to drill where well completion requires the use of 7-in. production casing set at 12,000 t. Determine the number of casing strings needed to reach this depth safely, and select the casing setting depth of each string. Pore pressure, fracture gradient, and lithology data from logs of nearby wells are given in Figure 8.18. Allow a 0.5 lbm/gal trip margin, and a 0.5 lbm/gal kick margin when making the casingseat selections. he minimum length of surface casing required to protect the freshwater aquifers is 3,000 t. Approximately 150 t. of conductor casing generally is required to prevent washout on the outside of the conductor. It is general practice in this area to cement the casing in shale rather than in sandstone. Ex 8.2: Compute the API collapse-pressure rating for 20-in, K-55 casing with a nominal wall thickness of 0.635 in. and a nominal weight per foot of 133 lbf/t. Ex 8.3: Compute the burst requirement if the pore pressure is 8,000 psi if the factor of safety is assumed as 1.3. Ex 8.4: Compute the API burst resistance for 22-in, 133-lbf/t, K-55 casing with a nominal wall thickness of 0.65 in. Use Barlow and Lame models. Ex 8.5: Compute the body-yield strength for 21-in., K-55 casing with a nominal wall thickness of 0.61 in. and a nominal weight per foot of 120 lbf/t.

500 Fundamentals of Sustainable Drilling Engineering Ex 8.6: Determine the collapse strength for a 6½ O.D., 21.00 lbf/t, J-55 casing under axial load of 200,000 lbf. Ex 8.7: Determine the maximum axial stress for a 5½ O.D., 14.00 lbf/t, J-55 casing under axial load of 300,000 lbf axial-tension load in a portion of a directional wellbore having a dogleg severity of 5°/100’. Compute the maximum axial stress assuming uniform contact between the casing and the borehole wall.

References Al-Saeedi, M.J., Al-enezi, D., Sounderraja, M., Saxena, A.K., Gumballi, and McKinnell, D.C. (2013). First Implementation of CRA Casing in Sour HPHT Reservoirs in Deep Wells in Kuwait, SPE 1648603, presented in Cairo, Egypt, April 2013. Andrew, K.W., and Eric, E.M. (1985). Minimum Cost Casing Design for Vertical and Directional Wells. SPE 14499, paper presented in Morgantown, WV, Nov 1985. API TR 5C3 (2008). Bulletin on Formulas and Calculations for Casing, Tubing, Drill Pipe, and Line Pipe Properties, 7th edition, 2008, Washington DC, API. Budi, U. and Keith, W. (2013). Drillable PDC Casing Bit Deines Challenging Onshore Drilling Environment and Sets Longest Single-Trip Drilling-With-Casing Record. Paper IPTC 16445, presented at the International Petroleum Technology Conference held in Beiging, China, 26–28 March 2013. Gordon, D., Billa, R., Weissman, M. and Hou, F. Underbalanced Drilling With Casing Evolution in the South Texas Vicksburg. SPE 84173, paper presented at the SPE Annual Technical Conference and Exhibition held in Colorado, USA, 5–8 October 2003. Hossain, M.M., and Amro, M.M. (2004). Prospects of casing While Drilling and the Factors to be Considered During Drilling Operations in Arabian Region. IADC/SPE 87987, paper presented at the IADC/SPE Asia Paciic Drilling technology conference and Exhibition held in Kuala Lumpur, Malaysia, 13–15 September 2004. Issa, J.A. and Crawford, D.S. (1993). An improved Design Equation for Tubular Collapse. SPE 26317, presented at the SPE Annual Technical Conference and Exhibition, Houston, 3–6 October, 1993. Jellison, M.J., and Davila, M.A., Intevep, S.A.A. (1996). How to Evaluate and Select Premium Casing Connectors. IADC/SPE 35037, paper presented at the 1996 IADC/SPE Drilling Conference held in New Orleans, Louisiana, 12-15-1996. Ju, G.T., Power, T.L., and Tallin, A.G. (1998). A Reliability Approach to the Design of OCTG Tubulars Against Collapse. SPE 48332, presented at the SPE applied technology workshop on Risk based decision of well casing and tubing, the Woodland, Texas, USA, 7–8 May, 1998. Karl, D., and Mark, R. (2003). Planning the Well Construction Process for the use of Solid Expandable casing. SPE/IADC 85303, Paper presented at the SPE/IADC Middle East Drilling Technology conference and Exhibition held in Abu Dhabi, UAE, 20–22 October 2003. Lu, Q., Prideco, G. Wu, J. and Hannahs, D. (2007). Connection Qualiication for Casing-Dilling Applications. SPE/IADC 105432 paper presented in the 2007 SPE/IADC Drilling Conference held in Amesterdam, he Netherlands, 20–22 February 2007. Ming, T. (2003). Design and Application of Expandable casing Technology of Deep Sidetrack Horizontal Well in Tahe Oilield. IPTC 16760, paper presented at the international petroleum technology Conference held in Beijing, china, 26–28 March 2013.

Casing Design 501 Qing L. and Dan H., Grant Prideco; Jiang W., Chevron; and Steve L., Grant Prideco. Connection Performance evaluation for casing-Drilling Applications. OTC 18495 paper presented at the 2007 Ofshore technology Conference held in Houston, Texas, USA, 30 April 2007. Rahman, S.S and Chilingarain, G.V. (1995). Casing Design heory and Practice, Elsevier 1995. Sam, G., Szlachta, M., Schafer, M. (2011). voestalpine tubulars GmbH, P. Winkler, voestalpine tubulars GmbH. New Robust “High torque” casing Connection Reduces Risk and Cost. SPE/ IADC 148058, paper presented in the 2011 SPE/IADC middle East Drilling Technology Conference and Exhibition held in Muscat, Oman, 24–26 October 2011. Santi, N. and Carcagno, G.E. and Toscano, R. (2005). Premium and Semi-Premium Connections Design for varied Drilling-with-Casing Applications. OCT 17221, paper presented at the 2005 Ofshore technology Conference held in Houston, TX, USA, 2–5 May 2005. Tamano, T., Mimaki, T., and Yanagimoto, S. (1983). A New Empirical Formula for Collapse Resistance of Commercial Casing. Journal of Energy Resources Technology, ASME, 1983. Tommy, W., Robert, T. and Bruce, H. (2004). Casing Drilling with Retrievable Drilling Assemplies. OTC 16564, paper presented at the Ofshore Technology Conference held in Houston, Texas, USA, 3–6 May 2004. Yuma, D.V., Tommy, W. and Robert, T., (2007). Two Salt-Dome Wells Successfully Drilled with Casing-While-Drilling Technology. SPE/IADC 10773, paper presented at the SPE/IADC Drilling Conference held in Amesterdam, he Netherlands, 20–22 February 2007.

9 Cementing 9.1 Introduction Since the introduction of Portland cements for the construction of oil and gas wells in 1920s, cementing has become one of the essential phases in the drilling operations and in the maintenance of production wells. he cementing process involves mixing powder cement with water and some additives to prepare cement slurry and placing the slurry into the annular space between the casing and the wellbore. he objective is to ill the void space between the wellbore and the casing string, by doing so, it acts as a sealant between the wellbore and the casing. It also supports and protects the casing string which has been run in the wellbore prior to cementing. It will help if properly implemented. Finally cementing allows completing the drilling process safely and economically. he cementing job is performed by deploying the cement slurry into the well using pumps, displacing the drilling luids still existing within the well, and replacing them with cement. he cement slurry lows to the bottom of the wellbore inside the casing, and then lows up in the space between the casing and the wellbore to the surface or the target depth, as shown in Figure 9.1. he wells are drilled in stages since it is extremely diicult and almost impossible to drill a well from surface to the oil or gas pay zone in one run without encountering problems that could lead to complete failure of the drilling operation, or to catastrophic consequences and consequently abandoning the well. here are four main cementing stages in the drilling operations which include cementing the conductor, the surface, the

503

504 Fundamentals of Sustainable Drilling Engineering

Formation Casing

Cement Slurry

Figure 9.1 Cement being pumped into the casing.

intermediate and the production casings, as can be seen in Figure 9.2. he cementing process is performed ater the casing strings have been run in the wellbore ater a certain depth has been reached where each drilling stage serves an important purpose toward the safe conclusion of this risk prone process. Cementing is the irst part of the completion process for a production well. During the production phase, cementing is used most commonly to permanently shut of water inlux into the well. At the end of the well life when production is not economical, cementing prepares the well for abandonment. Oil well cement (OWC) is a powdery substance made of limestone and clay. Most cement used in the oil industry is a type of Portland cement. In the construction industry, cements are mixed with sand, gravel, and water to form concrete. In the oil industry, cements are mixed with water and special additives to form slurry, which is then pumped into the well. he slurry solidiies when it reaches the targeted place. he drilling engineer designs the cementing job. He determines the number of casing strings and their setting depths and calculates the volume of the void space that needs to be illed with the slurry, the quantities of cement powder, water and additives, and the placement technique for the application desired. he appropriate cement slurry design for well cementing is a function of many parameters, including the well bore geometry, casing equipment, formation integrity, and drilling mud properties. he depth of the well, the nature of geology, the geothermal proile, the pressure gradient, abnormal pressure formations and corrosive luid also afect well design.

9.2 Applications of Oil Well Cements Cementing is a critical part of well construction. It has to be designed, planned and executed properly. Otherwise it could lead to disastrous consequences which may include

Cementing

3660 ft

505

20 in.

7375 ft

16 in.

12090 ft

133/8 in.

13976 ft

95/8 in.

Figure 9.2 Typical well proile showing cemented casing strings.

loss of personnel life, destruction of the drilling rig, oil spills, environmental pollution or economic loss. Oil well cementing is the process of placing cement slurry in the annulus space between the well casing and the rock formations surrounding the well bore. When a certain section of a well has been drilled, a casing string is placed in the well bore to prevent the well walls from collapsing. Placing a casing string is not suficient to ensure wellbore stability. Hence cement is placed between the casing and the wellbore walls as shown in Figure 9.2. Oil well cementing was introduced in the 1920s to serve the following major objectives: (i) To support the walls of the wellbore to prevent formation collapse. (ii) To provide zonal isolation between formations in order to prevent movement of gas or luids between diferent geological formations (Figure 9.3) (iii) To protect oil producing zones from salt water low (Figure 9.4) (iv) To support and seal the casing in place and protect it from collapse under pressure (v) To protecting well casings from corrosion, (vi) To reduce the risk of ground water contamination by oil, gas or salt water he application of cement in oil and gas wells as shown in Figure 9.5 serves other purposes such as i) cementing liner strings, ii) sidetracking, iii) well abandonment by setting cementing plugs, iv) squeeze cementing to shut of water inlux. Cementing liner strings is similar to the primary cementing of casing strings. he only diference is that the liner string does not extend to the surface. he functions of cement are similar for both cases. When sidetracking a hole around an obstruction, such as a stuck bottom

506 Fundamentals of Sustainable Drilling Engineering

Casing Cement Shale Water sand Shale Oil sand

Figure 9.3 Zonal isolation.

Casing Cement Salt water Lost circulation zone Heaving Shale Heaving Shale

Figure 9.4 Salt water zone.

hole assembly (BHA) or changing the direction of drilling for geological reasons, it is oten necessary to place a cement plug at the required depth to change the wellbore direction or to help support a mechanical whip stock so that bit can be guided in the desired direction. In some cases an exploration well is abandoned when no hydrocarbon was found, or when a section of the pay zone in the well or the whole well was completely depleted. A cement plug can be placed at the required depth to help prevent zonal communication and migration of any luids that might iniltrate underground freshwater sources or reach the surface and pollute the environment surrounding the well. he cement is squeezed to shut of the oil zone intervals that were invaded by water during the production phase of the well.

9.2.1 Cement Applications Primary Cementing: Primary cementing is applied in wells ater casing is lowered to the setting depths to provide the various functions stated earlier. It constitutes the

Cementing

507

majority of cementing application sand is the irst cementing job in the life of a well. It involves the process of pumping cement slurry into the annulus between casing and the wellbore, as can be seen in Figure 9.5. For a successful primary cementing operation, the drilling engineer will consider many factors in the cementing plan such as well depth and well completion type, mud system, well location, and geological environment. Following well established procedures in the use of cementing equipment will ensure that the casing is properly positioned in the wellbore. When the casing is properly sealed in place, the cement should be able to prevent casing corrosion by avoiding casing contact with formation luids. It should also prevent the movement of luids through the annular space outside the casing i.e. from one formation to another or to the surface, and stops the movement of luid into fractured or cavernous formations. he cement will not allow formation luids to move from one formation strata to the annulus within a wellbore. Squeeze Cementing: Squeeze cementing is the process of injecting cement into a conined zone behind the casing such as casing leaks and low channels in formations (Figure 9.5d). It’s a remedial job required to repair faulty primary cementing at a later age of well life. he applications of squeeze cementing include: (i) Casing leaks: cement slurry are directed and forced through casing leaks. Casing leak can develop due to corrosion caused by water or hydrogen sulide gas or other kinds of luids.

Casing

Steel Casing Borehole

Liner

Cement Cement

(a) Cementing Casing Strings

(b) Cementing Liner Strings

Old Cement Cement Plug

Hole New Cement

(c) Cement plug

(d) Squeeze cement

Figure 9.5 Applications of cementing (Burgoyne et al., 1986).

508 Fundamentals of Sustainable Drilling Engineering (ii) Weak cementing zone behind casing: sometimes void spaces or channels exist in the annulus between casing and wellbore due to improper primary cement placement. Squeeze cementing job is normally carried out as a remedial action to reinforce such weak zones. (iii) Water shut of: cement slurry are also forced into lower casing perforations to seal of or at least control water production into a producing well. (iv) Gas shut of: in a high gas oil ratio well, sealing the upper casing perforation can reduce the volume of gas production into a producing well. (v) Lost circulation zones: cement can be used to seal of fractures or very permeable geological formations few centimeters from the well surface. (vi) Selective zonal isolation: depleted reservoirs, water aquifer, or abnormal pressure zones can be isolated by squeeze cementing.

9.2.2 Variables Afecting Zonal Isolation here are many factors that need to be considered to ensure good quality zonal isolation. he factors include: (i) Borehole size, shape and uniformity (ii) Borehole stability includes lost circulation, lows etc. (iii) Cementing process such as displacement design, job execution, and cement volumes. (iv) Cement material properties and relationships between pipe-cement-formation. (v) Pressure and temperature changes/cycling over the life of the well. (vi) Geomechanics such as changes in in-situ stresses in cement and pipe. (vii) Chemistry such as corrosion and chemical resistance of pipe and cement. (viii) Geology and Geochemistry includes formation type, structure and formation luid chemistry.

9.3 Cement Production 9.3.1

Production Process

Limestone and clay, or materials containing the same mineral constituents are mixed in deinite proportions to produce chemical reactions during a burning process. he inished product is an extremely ine dry powder, which when mixed with water will become hard. his product is Portland cement, patented in England in 1824. Cement production involves the transformation of the raw materials through a series of steps into a consistent powdered product. he blended raw material is called the ‘raw feed’ or ‘kiln feed’ and is heated in a rotary kiln up to a temperature of about 1400°C to 1500°C. he rotary kiln is basically a hollow metal cylinder up to 200 meters long and 6 meters in diameter, and exposed to high heat at one end. he raw feed enters the kiln at the cool end and gradually passes down to the hot end, then falls out of the kiln and cools down. he material formed in the kiln is described as ‘clinker’ and is typically between

Cementing

509

1 mm and 25 mm across. Ater cooling, the clinker is passed directly to the cement mill. he cement mill grinds the clinker to a ine powder. A small amount of gypsum which is a form of calcium sulfate is normally ground up with the clinker. he gypsum controls the setting properties of the cement when water is added. he active properties of the clinker minerals give cement its exceptional binding characteristics which are exploited in concrete construction. Figure 9.6 shows a schematic diagram of the cement production process. he production steps of cement can be summarized as follows: (i) Raw materials are crushed, screened and stockpiled. (ii) Raw materials are mixed with deinite proportions to obtain “raw mix”. hey are mixed either dry (dry mixing) or by water (wet mixing). (iii) Prepared raw mix is fed into the rotary kiln. (iv) As the materials pass through the kiln their temperature is raised up to 1300–1600°C. he process of heating is called “burning”. he output is known as “clinker” which is 0.15–5 cm in diameter. (v) Clinker is cooled & stored. (vi) Clinker is ground with gypsum (3–6%) to adjust setting time. (vii) Packing.

9.3.2 Cement Components he principal components of the inished Portland cement are lime, silica, alumina and iron. Table 9.1 shows cement components and characteristics where the components

Raw Mill

Electrostatic Precipitator

Raw Meal Silo

Suspension Preheater

Gypsum Clinker Silo Cement Mill

Cement Silo Rotary Kiln

Packing House

Cement Tanker

Figure 9.6 Schematic diagram of the cement production process.

510 Fundamentals of Sustainable Drilling Engineering form complex compounds expressed by the formula. Each compound afects the slurry in a diferent manner. When water is added to cement, setting and hardening reactions begin immediately. he chemical compounds in cement undergo hydration and recrystallization resulting in a set product.

9.4 Classiications of Oil Well Cements The API has established a classification system for cements used in oil and gas operations. The cements are manufactured with the process described in Figure 9.6. However the proportions of various chemicals are different. In addition the cements are ground to a different fineness which varies the required water-cement ratio. In the beginning, only one or two types of oil well cement were available. As oil/gas wells became deeper and subjected to more hostile environments, the more harsh performance criteria could not be satisfied by those cements. With the advent of the API Standardization Committee in 1937, improved OWCs were developed. The API specifications for Materials and Testing for Well Cements (API Specification 10A, 2002) include requirements for eight classes of OWCs (classes A through H) as explained in Table 9.2. OWCs are classified into grades based upon their C3A (Tricalcium Aluminate) content: Ordinary (O), Moderate Sulphate Resistant (MSR), and High Sulphate Resistant (HSR). Each class is applicable for a certain range of well depth, temperature, pressure and sulphate environments. Class A, Class G and Class H are the three most commonly used oil well cements. Class A is used in milder, less demanding well conditions, while Class G and H cements are usually speciied for deeper, hotter and higher pressure well conditions. Conventional types of Portland cement incorporating suitable additives have also been used. he chemical composition of cement is what distinguishes one type of oil well Table 9.1 Cement components & characteristics. Compound

Characteristics

Tricalcium aluminate/C3A (3CaO .Al2O3)

(i) Promotes rapid hydration (ii) Afects the initial setting and thickening time of the cement. (iii) Makes the cement susceptible to sulfate attack.

Tetracalciumaluminoferrite/C4AF (4CaO.Al2O3.Fe2O3)

(i) Promotes low – heat hydration.

Tricalcium silicate/C3S (3CaO.SiO2)

(i) Major Component and produces most of the strength (ii) Responsible for early strength development.

Dicalcium silicate/C2S (2CaO.SiO2)

(i) Hydrates slowly. (ii) Promotes small gradual grain in strength over an extended period of time.

—

— More costly than ordinary portland cement More costly than ordinary portland cement

More costly than ordinary portland cement

Lower Cost

Cost

Lower Cost

MSR** and HSR*** grades MSR** and HSR*** grades MSR** and HSR*** grades

MSR** and HSR*** grades

MSR** and HSR*** grades

O*, MSR** and HSR*** grades, Comparable with ASTM C 150, Type III

MSR** and HSR*** grades, Comparable with ASTM C 150, Type II

38

O* grade compatible with ASTM C 150, Type I Portland Cement

Availability

44

H

0 to 2440

38

G

0 to 2440

38

F

3051 to 4880

38

E

3050 to 4270

56

D

1830 to 3050

0 to 1830

Range of depth, m

46

C

0 to 1830

46

w/c, % mass fraction of cement

B

0 to 1830

A

Cement Class

Table 9.2 Key features of API Oil Well Cement (API Speciication 10A, 2002).

Cementing 511

A

Intended for use when special properties are not required

Cement Class

Other features

Table 9.2 Continued H (1) Basic well cement (2) Suface area is coarser than Class G (3)hickening times controllable with additives to prevent loss of circulations up to 450 F.

G (1) Basic well cement (2) hickening times controllable with additives to prevent loss of circulations up to 250 F.

F (1) Required under conditions of extremely high temperature and pressure (2) retarded cement and retardation is achieved by reducing C3S and C3A, and increasing the particle size of the cement grains

E (1) Required under conditions of high temperature and pressure (2) retarded cement and retardation is achieved by reducing C3S and C3A, and increasing the particle size of the cement grains

D (1) Required under conditions of moderately high temperature and pressure (2) retarded cement and retardation is achieved by reducing C3S and C3A, and increasing the particle size of the cement grains

C Intended for use when conditions require high early strength (2) he C3S content and surface area are relatively high

B

Intended for use when special properties are not required moderate or high sulphate resistance (2) lower C3A content than Class A

512 Fundamentals of Sustainable Drilling Engineering

Cementing

513

Table 9.3 API Cement composition.

Compounds % API Class

C 3S

C2S

C 3A

C4AF

Fineness cm2/gm

Water/ Cement Ratio

A

53

24

8

8

1,500

-

1,900

0.46

B

47

32

3

12

1,500

-

1,900

0.46

C

70

10

3

13

2,000

-

2,400

0.56

D

26

54

2

12

1,100

-

1,500

0.38

G

52

32

8

12

1,400

-

1,600

0.44

H

52

32

8

12

1,200

-

1,400

0.38

J

53.8

38.8

1,240

-

2,480

0.44

SiO2

CaO

0.435

cement from another and determines the suitability of the cement for speciic uses. he chemical composition of OWC is slightly diferent from that of regular Portland cement. OWCs usually have lower C3A contents. hey are coarsely ground and may contain friction-reducing additives and special retarders such as starch, sugars, etc, in addition to or in place of gypsum as the Table 9.3 explain the composition of all API classes and their ineness with required water cement ratio. API Class G and H are by far the most commonly used OWCs today. he chemical composition of these two cements is similar. he basic diference is in their surface area (Table 9.3). Class H is coarser than Class G cement and thus has a lower water requirement. Cement that is ground too ine should not be used as oil well cement. Microine cements and ultra-ine (blain surface> 9000 cm2/gm) Portland cements cannot be used for primary cementing because it does not develop suicient compressive strength to hold the casing in downhole condition and it does not generally have adequate sulphate resistance. However, microine cement is a good option for oil well repairing since typical OWCs cannot be used because of their larger particle size and the subsequent dificulty to penetrate in extremely small cracks/channels.

9.5 Cement Properties he cement properties determine the success or failure of the cementing job from the blending of the cement slurry components at the surface, to the pumping through the surface lines, and inside the casing and in the annulus until the hydration and setting phase in the desired place. he most important properties during the slurry pumping are density, thickening rate, iltration rate, and rheology. Ater the cement hardens, the most important properties are permeability, compressive strength, soundness and ineness.

514 Fundamentals of Sustainable Drilling Engineering

9.5.1 Density he density of neat cement slurry, i.e., mixture of water and cement, varies from 1773 kg/m3 (110lbm/t3) to 1965 kg/m3 (123lbm/t3) depending on the API Class of the cement and the water/cement ratio (w/c). Increased or decreased variation of the density is dependent on the bottom-hole environment. If cement density is high, the pressure generated by the cement column will be high and might be higher than the fracture pressure of weak formations and if so it could result in fracturing the formations or cause lost circulation. On the other hand if the cement density is low, the pressure in the over pressured formations could be higher than the cement column pressure and lead to inlux from the formation to the latter into blowout. Prior knowledge of the wellbore environment is imperative to alleviate such challenges. Based on the information available the density of the slurry can be adjusted to ensure lawless cement job. his can be accomplished by adding either weight reducing material, or weight increasing material. he most common ones are listed Table 9.4. he slurry density is calculated by adding the masses of all components and divided by the total of absolute volumes of all.

Pslurry

lbcement lb water lbadditives gal cement gal water gal additives

lbs gal

(9.1)

Example 9.1: A slurry is composed of a sack Class G cement, 35% silica lour and 44% water. Find the density of slurry. Solution: Given data: Weight of Cement = 94 lbs/ sack Weight of Water = 44% of a cement sack Weight of Silica Flour = 35% of cement sack Required data: Wt = Total weight (lbs) Vt = Total volume (gal) Vabst = Absolute volumes (Halliburton cementing tables) Weight of Water = 94 × 0.44 = 41.36 lbs Weight of Silica Flour = 94 × 0.35= 32.9 lbs Total Weight = weight of cement + weight of water + weight of silica lour Total Weight = 94 + 41.36 + 32.9 Table 9.4 Weighing materials. Additives

Speciic Gravity

Color

Additional Water (gal/lbs)

Barite

4.33

White

0.024

Hematite

4.95

Red

0.0023

Limenite

4.45

Black

0.00

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= 168.26 lb Volume of a cement = Absolute volume × Weight of cement Volume of cement = 0.0382×94 = 3.59 gal Volume of water = 0.1202×41.36 Volume of water = 4.97 gal Volume of silica lour = 0.454×32.9 = 1.49 gal Total Volume = Vcement + Vwater+ Vsilica lour Total Volume = 3.59 + 4.97 + 1.49 Total Volume = 10.05 gal By applying the Eq. 9.1, we get Density of slurry Pslurry

lbs gal

total weight total volume

168.26 10.05

Pslurry = 16.74 lbs/gal 9.5.2 Fluid Loss Fluid loss is a complex process related to drilling luids as well as cement slurries during drilling operations. It occurs when the water in the cement slurry leaves it and invades the permeable formation due to the pressure diferential between them. Analogous to drilling luids, luid loss creates similar problems for cement slurries during the cementing operations. When large volumes of liquid are lost it will degrade the cement properties leading to a poor cement sheath. As a result of cement iltrate inlux into the formation, the formation face pores are sealed and impedes the low of liquid. Properly designed cement should have the ability to seal the formation face and to minimize the luid loss. Many kinds of luid loss control additives are available for example bentonite, latex, Attapulgite, and many other cellulose derivatives such as CMHEC.

9.5.3

hickening Time

hickening time is the time duration in which cement slurry remains pumpable. he upper limit of pumpability is reached when the cement consistency reaches 100 Bc. he thickening time of cement slurry is a function of several parameters which includes downhole pressure and temperature. When the cement reaches its desired location it hardens and develops strong sheath to seal of any luid movement behind the casing and to support it. Prior to presuming drilling, time must be spent waiting for cement to harden. he waiting time can be controlled by adding materials to the cement slurry to reduce it based on the temperature, pressure and depth. Figure 9.7 shows thickening time plot.

516 Fundamentals of Sustainable Drilling Engineering 120

Consistency, Bc

100 80 60 Base Mix 40 20 0 0

1

2 Time, hours

3

4

Figure 9.7 hickening time plot of cement slurry at HPHT conditions( Mobeen et al., 2014).

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 applied: Volume of dry cement Mixing rate

(9.2)

Amount of fluid required to displace plug Displacement rate

(9.3)

Tm

Td

A premature setting can have disastrous consequences such as loss of circulation in the well, whereas too long setting times can cause inancial losses due to lost productivity, in addition to possible segregation of the slurry or contamination by luids. OWC slurries must also harden rapidly ater setting. A slow setting behavior can be achieved by adjusting the composition of the cement and or by adding retarders. Constituents of the cement slurry and their percentage can afect the hardening time. For oil well construction, it is generally desirable to maintain the setting time of the cement slurry fairly constant over the temperature range of 60oC (140°F) to 104oC (220°F). Accurate control of the thickening time, i.e. the time ater initial mixing at which the cement can no longer be pumped is crucial in the oil well cementing process. It is important to simulate the well conditions (temperature, pressure, etc.) as precisely as possible in determining the thickening time. here are some other factors that afect the pumpability of the slurry, but are very diicult to simulate during determining the thickening time of the slurry, such as luid contamination, luid loss to formation, unforeseen temperature variations, unplanned shutdowns in pumping, etc. he thickening time is usually controlled by using retarders. Lignosulfonates and hydroxycarboxylic acids are retarders that are believed to perform well for OWCs with

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517

low C3A contents. he mechanism by which these chemicals and others act as retarders is not well understood and is still a matter of controversy. However, it is known that retarders bind to calcium ions and are able to inhibit the growth of ettringite crystals. Other retarders used in well cementing include cellulose derivatives, organo-phosphonates and inorganic compounds such as acids and salts of boric, phosphoric, hydroluoric, and chromic, zinc oxide (ZnO) and Borax (Na2B4O7.10H2O), sodium chloride (concentrations greater than 20% by weight of water. he thickening time of OWC slurries was also found to increase with the addition of polyvinyl alcohol (PVA) latex hickening time was found to be almost independent of temperature when the ECSC (Engineered Cement Set Control Additive) additive was used in the slurry, and the slurry allowed eicient and reliable cementing of long cement columns with a large temperature diferential between the top and the bottom. Unlike retarders, CaCl2, NaCl, and sodium silicates are used to shorten the setting time and ofset the set delay caused by other additives such as dispersants and luid loss control additives. he accelerating efect of such chemicals depends on their chemical nature, concentration, curing temperature and other constituents of the cement slurry. Salts of carbonates, aluminates, nitrates, sulphates, thiosulphates, as well as alkaline bases such as NaOH, KOH, and NH4OH accelerate the setting time (Nelson et al., 1990; Nelson et al., 2006).

9.5.4 Viscosity and Yield Point Viscosity stands for the liquid resistance to shear forces which occurs during cement slurry low, and the yield point is the liquid initial resistance to low. Both properties are important during pumping and placement of the cement. Pumping high viscosity cement through the casing and the annulus at high rate generates high frictional loss that can result in formation fractures. Rheological low properties of cement slurry include plastic viscosity (μp), yield point (τy), frictional properties, gel strength, etc. he plastic viscosity and yield point are calculated by equations given below. he details of rheological properties are provided in Chapter 3rd of the book. p

600

300

(9.4)

y

300

p

(9.5)

Example 9.2: A rotational viscometer containing cement slurry gives a dial reading of 196 at a rotor speed of 300 RPM and a dial reading of 250 at a rotor speed of 600 RPM. Calculate plastic viscosity and yield point. Solution: Given data: θ600 = 250 θ300 = 196 Required data: μp = Plastic viscosity, cp τy = Yield point, lbf/100t2

518 Fundamentals of Sustainable Drilling Engineering Applying Eq. 9.4, we get

μp = θ600 – θ 300 = 250 – 196 = 54 cp Now applying Eq. 9.5 for yield point calculations, we get

τp = θ 300 – μp = 196 – 54 = 142 lbf/100t2 The rheological properties of OWC slurries are important in assuring that the slurries can be mixed at the surface and pumped into the well with minimum pressure drop. The rheological properties of the cement slurry also play a critical role in mud removal. A proper flow regime must be sustained for thorough removal of the mud from the wellbore. The flow regime of a cement paste or slurry can change with time, temperature, pre-treatment, application of shear, type of application, type of dispersion, physical and chemical characteristics of solid and liquid ingredients, the addition of special surface-active agents, and the extent of grinding and mixing. The rheological behavior of the cement slurry also depends on a number of factors including the water-cement ratio, size and shape of cement grains, chemical composition of the cement and the relative distribution of its components at the surface of cement grains, presence of additives, mixing and testing procedures, etc.

9.5.5 Permeability he objective of placing cement in the annulus is to create a seal ater it has been set to impede luid low through the cement. A good sheath of cement should have no permeability. he volume and size distribution of pores afect not only the mechanical strength of cement based materials, but also its durability. he porosity and pore size distribution of hardened OWC slurry depends on a number of factors such as the water cement ratio, degree of hydration, type of cement, mixing conditions, chemical admixtures and mineral additives, etc. High temperature has a drastic efect on the pore structure and compressive strength of cement based materials. he total porosity is more than doubled when the curing or casting temperature increases from 20°C to 1000°C. Change in porosity and pore size distribution occurs during the setting period for cement but gas low could not be completely impeded. Polymeric latexes improve the ability of the set cement to prevent migration of reservoir luids from one zone to another by decreasing permeability and preventing gas migration through the set slurry in the semi-solid state. he permeability of cement slurry can be calculated by using the equation given below; k (2000 OP Q

where: Q = Flow rate, lit/s k = Permeability, md A = Cross Sectional Area, cm2

L) / (A

IP2 OP2 )

(9.6)

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519

OP = Outlet Pressure, atm IP = Inlet Pressure, atm μ = Viscosity, cp L = Length, cm

9.5.6 Compressive Strength he compressive strength of cement is the force that must be exerted to crush a mass of cement divided by the cross sectional area of the mass. he compressive strength properties determine the integrity of cement and its ability to bear long term imposed stresses (Bourgoyne et al., 1986). he tensile strength is a lot weaker than the compressive strength, about 12 times lower. Cement sheath is subjected to deterioration under extreme conditions. he extreme temperature cycling of the well bore results in severe mechanical damage and ultimate failure of the cement sheath, potentially leading to micro-annulus. he rate of deterioration is generally intensiied at high temperature and pressure such as in the case of oil and gas deep wells. Control of cement reactivity and mechanical properties during the life cycle of the well is crucial. he oil well cement should meet a wide range of short-term criteria such as free water, thickening time, iltrate loss, development of strength, shrinkage, etc., in addition to various long-term requirements including resistance to chemical attack, thermal stability and mechanical integrity of the cement sheath. he mechanical properties of hardened OWC slurry are afected by a number of factors and depend on the chemical composition of its constituents, temperature, curing regime etc. When cement slurry is subjected to compressive strength development test, it can be analysed that hydration reaction is very fast at the start of test but later it slows down and the compressive strength development becomes almost constant with very small change as Figure 9.8 explains the development of Class A cement slurry. Similar case is observed in Class G cement at HPHT conditions where rise in compressive strength is very fast for the irst few hours (Figure 9.9). To hold the casing in place, the compressive strength of the set cement has to be high enough. As a general practice, 500 psi of compressive strength has to be developed by

Compressive Strength, psi

6,000

170°F 3,000 psi

5,000

Class A

4,000 3,000 2,000 1,000 0 0

10

20

Curing Time, Days

Figure 9.8 shows compressive strength development of class A cement slurry.

30

520 Fundamentals of Sustainable Drilling Engineering 17

300

16

3,000

6

2,500

12

Temperature (F)

13

200

5 Temperature (F) Acoustic Impedance (Mrayl)

150

11 10

Compressive Strength (psi)

4

1,500

1,000

500

100 3.5

9 8

4.5

Transit Time (microsecond/in)

2,000

Compressive Strength (psi)

5.5 14

Acoustic Impedance (Mrayl)

250

15 Transit Time (microsecond/in)

6.5

50

0

5

10 15 Time (hours)

20

3 25

0

-500

Figure 9.9 Compressive strength development of simple class G cement at HPHT conditions.

the set cement before any other downhole operation starts. he time it takes the cement to reach this minimum compressive strength is oten referenced as “wait on cement” (WOC). During this time, the subsurface operations are stopped and only routine surface operations are carried out. he support capability of the cement is given by: F lbf

0.969 Sc d h

(9.7)

where: F = support capability Sc = comprehensive strength of cement, psi d = casing outer diameter, inch h = height of cement column behind casing.

9.5.7

Soundness

In Portland cement, “soundness” is deined as the ability of hardened cement slurry to retain its volume ater setting without delayed destructive expansion. his destructive expansion is caused by excessive amounts of free lime (CaO) or magnesia (MgO). If this change is too great it will cause deformation of the set cement and produce serious problems such as, cement sheath fractures, casing deformation, rock formation fractures. It could permit luid low through the cement from the formation to the wellbore and wellbore luids to the rock formations. Soundness can be detected by the Autoclave-Expansion Test (ASTM C 151).

9.5.8 Fineness Fineness of cement describes the size of the cement particles. It is expressed in terms of speciic surface area of particles. It afects the hydration rate and the rate in which the

Cementing

521

cement develops strength. he ineness of the cement can be measured with a turbidimeter. he cement ineness inluences some properties such as luid loss can be reduced if the ineness is high or it can reduce the water requirement of the set cement. Increasing the ineness of cement beyond an optimum limit increases the water requirement of concrete and reduces the durability of set cement.

9.5.9 Hydration of Cement Slurries Portland cement consists of ive major compounds and a few minor compounds. he composition of a typical Portland cement is listed by weight percentage in Table 9.5. When water is added to cement, each of the compounds undergoes hydration and contributes to the inal product as Figure 9.10 explains the heat of hydration process. Only the calcium silicates contribute to strength. Tri-calcium silicate is responsible for most of the early strength during irst 7 days. Di-calcium silicate which reacts more slowly contributes only to the strength at later times. he equations of the hydrations of major compounds are given by: 2C 3S 6H

C 3S2 H3 3CH

(9.8)

2C 2S 4H

C 3S2 H3 CH

(9.9)

C 6 A2 s3H32

(9.10)

C 6 A,F s3 H32 (A,F)H3

(9.11)

2C 3 A 3C s H2 26H 2C 4 AF 3C s H2 21H

Upon the addition of water, tri-calcium silicate rapidly reacts to release calcium ions, hydroxide ions, and a large amount of heat (stage 1). he pH quickly rises over 12 because of the release of alkaline hydroxide (OH-) ions. his initial hydrolysis slows down quickly with a corresponding decrease in heat (stage 2) explains the hydration of Portland cement. he reaction slowly continues to produce calcium and hydroxide ions until the system becomes saturated. Once this occurs, the calcium hydroxide starts to crystallize. Simultaneously, calcium silicate hydrate begins to form. Ions precipitate out Table 9.5 Composition of Portland cement with chemical composition and weight percent (Roij et al., 2012). Cement Compound

Weight Percentage

Chemical Formula

Tricalcium silicate

50

3CaO.SiO2

Dicalcium silicate

25

2CaO.SiO2

Tricalcium aluminate

10

3CaO.Al2O3

Tetracalciumaluminoferrite

10

4CaO.Al2O3.Fe2O3

Gypsum

5

CaSO4.2H2O

522 Fundamentals of Sustainable Drilling Engineering Stage 1

Heat evolution

Stage 2

Stage 5

Stages 3 and 4 C3S hydration C3A hydration

Time

Figure 9.10 Schematic representation of hydration of Portland cement (Michaux and Nelson, 1990).

of solution accelerating the reaction of tri-calcium silicate to calcium and hydroxide ions. he evolution of heat is then dramatically increased again (stage 3). he formation of the calcium hydroxide and calcium silicate hydrate crystals provide “seeds” upon which more calcium silicate hydrate can form. he calcium silicate hydrate crystals grow thicker which makes it more diicult for water molecules to reach the anhydrate tricalcium silicate. he speed of the reaction is controlled by the rate at which water molecules difuse through the calcium silicate hydrate coating. his coating thickens over time causing the production of calcium silicate hydrate to become slower and slower (stage 4). he setting and hardening of OWC slurry are the result of a series of simultaneous and consecutive reactions between water and the constituents of the cement. Diferent products result when cement is mixed with water based on the percentage of the compounds in the cement. he table below reveals the efect of the compounds in the cement on the reactions behaviour and end product properties. Table 9.6 explains the reaction properties of major compounds of cement.

9.6 Types of Cementing here are diferent types of cementing depending on well conditions, geological structures geophysical properties and the geographical locations of the wells. Table 9.6 Reaction properties of major cement compounds. Properties

C3S

C2S

C3A

C4AF

Rate of Reaction

Moderate

Slow

Fast

Moderate

Heat of Libration

High

Low

Very High

Moderate

Early Cementitious Value

Good

Poor

Good

Poor

Ultimate Cementitious Value

Good

Good

Poor

Poor

Cementing

523

9.6.1 Primary Cementing he purpose of a primary cement job is to inject the cement slurry in the annulus behind the casing. In most cases this is done in a single operation by pumping cement down the casing and up into the annulus (Figure 9.11). In which, irst mud circulation is performed to condition the well. he bottom plug is released which helps in cleaning the inside of casing as well as helps in avoiding the cement contamination by separating both luids. Spacer and cement is pumped down ater bottom plug. hen cement is displaced by the top plug with the help of displacing luid ater top plug. When top plug bumps on the bottom plug, this is the indication of cement displacement around the casing in annulus. he single stage procedure is described as follows: 1. 2. 3. 4. 5. 6.

Circulation of Mud for well conditioning Releasing bottom wiper plug Pumping of spacer Pumping of cement slurry Releasing top wiper plug Displacing with displacement luid (generally mud) until the top plug lands on the loat collar 7. Pressure testing of the casing Sometimes a longer casing string is to be cemented in particular where the formations are weak and may not be able to support the hydrostatic pressure generated by a very long column of cement slurry. In this case cement job is performed in two stages (Figure 9.12). he irst stage is completed as the primary single stage cementing. he second stage is performed by dropping a special tool in the casing string which is used to open ports of multi stage, allowing cement to be pumped from the casing and into the annulus. When the second stage slurry is ready to be pumped the multi stage tool is opened and the second stage slurry is pumped down the casing, through the stage

Mud circulation

Specer and Cement Pumping

Top Cementing Plug Bottom Cementing Plug

Centralizers

Float collar

Slurry

Spacer Original mud

Figure 9.11 Primary cementing process.

Displacement

Displacing Fluid

Displacement

Plugs bump

524 Fundamentals of Sustainable Drilling Engineering First stage cement

Dart placement Second stage cement

Plug placement

Figure 9.12 Multistage cementing process.

cementing tool and into the annulus, as in the irst stage. When the required amount of slurry has been pumped, the multi stage tool is closed. his is called multistage cementing.

9.6.2 Squeeze Cementing Squeeze cementing is the process in which cement slurry is pumped with force through holes in the casing and into the annulus and/or the formation. Squeeze cementing is oten used to carry out remedial operations during a work-over on the well (Figure 9.13). he main objectives of squeeze cementing are: 1. To repair casing failures 2. To shut of lost circulation zones 3. To carry out remedial work on a poor primary cement job (e.g. to ill up the annulus) 4. To seal of gas or water producing zones to maximize oil production from the completion interval 5. To prevent luids escaping from abandoned zones. In squeeze cementing the pores in the rock rarely allow all the cement slurry to get into the formation since a very high permeability would be required for this to occur. here are two processes by which cement can be squeezed: • High pressure squeeze - his technique requires the formation to be fractured and then allows the cement slurry to be pumped into the fractured zone. • Low pressure squeeze – During this technique the fracture gradient of the formation is not exceeded. Cement slurry is placed against the

Cementing

525

Figure 9.13 Squeeze cementing process.

formation, and when pressure is applied the luid content (iltrate) of the cement is squeezed into the rock, while the solid cement material (ilter cake) builds up on the face of the formation.

9.6.2.1

Equipment used in Squeeze Cementing

he high pressure and low pressure squeeze operations can be conducted with or without packers. Bradenhead Squeeze: his technique involves pumping cement through drill pipe without the use of a packer (Figure 9.14). he cement is spotted at the required depth. he BOPs and the annulus are closed in and displacing luid is pumped down, forcing the cement into the perforations, since it cannot move up the annulus. his is the simplest method of placing and squeezing cement, but it has problems of placing cement at target zone and can pressurized the casing. hat’s why, it is recommended only for low pressure squeeze cementing operation. Squeeze using a Packer: he use of a packer makes it possible to place the cement more accurately, and apply higher squeeze pressures. he packer seals of the annulus, but allows communication between drill pipe and the wellbore beneath the packer (Figure 9.15).

526 Fundamentals of Sustainable Drilling Engineering Placing cement

Applying pressure

Reverse circulation

Figure 9.14 Bradenhead cementing procedure.

Tubing

Packer

Figure 9.15 Squeeze cementing with packers.

9.6.3 Plug Cementing During the life of a well, at some stage cement plugs are set. Cement plugs are applied to avoid vertical luid movement. Cement plugs serve in diferent ways as fellows: • • • • •

Abandonment of depleted zones Shut of lost circulation zones Providing a kick of point for directional drilling Isolating a zone for formation testing Abandoning an entire well.

Cementing Conditioning

Displacing cement & drilling luid pipe

Placing cement plug

527

Pull pipe slowly

spacer cement spacer and prelush

cement plug prelush

Figure 9.16 Balanced plug cementing.

he major problem while setting cement plugs is avoiding mud contamination. Certain precautions should be taken to reduce contamination as given below; • Select a section of clean hole which is in gauge • he plug should be long enough (500 plugs are common). he top of the plug should be 250 above the productive zone • Condition the mud prior to placing the cement plug • Use a prelush luid ahead of the cement • Use densiied cement slurry here are two commonly used techniques for placing a cement plug: Balanced plug: his method is designed to achieve an equal level of cement in the drillpipe and annulus. Prelush, cement slurry and spacer luid are pumped down the drillpipe and displaced with mud. he displacement continues until the level of cement inside and outside the drillpipe is the same (hence balanced). If the levels are not the same then a U-tube efect will take pace. he drillpipe can then be retrieved leaving the plug in place (Figure 9.16). Dump bailer: A dump bailer is an electrically operated device which is run on wireline. A permanent bridge plug is set below the required plug back depth. A cement bailer containing the slurry is then lowered down the well on wireline. When the bailer reaches the bridge plug the slurry is released and sits on top of the bridge plug as Figure 9.17 explains the process of dump bailer.

9.6.4 Liner Cementing Liners are installed in place of casing to avoid casing extension to surface. hey are usually installed in production zones to avoid production casing installations. Liners cementing is very diicult task as they are run drillpipe and therefore the conventional cementing techniques cannot be applied its cementing. Special equipment is used for liner cementing. As like casing, the liner has a loat collar and shoe installed. here are some extra equipment must be installed in string such as a landing collar, positioned about two joints above the loat collar. A wiper plug is held in place on the end of the tailpipe by shear pins.

528 Fundamentals of Sustainable Drilling Engineering Wire line

Dump bailer

Mud Cement Dump release

Casing

Bridge plug or obstruction

Figure 9.17 Dump bailer method.

he liner cementing process is, explained in Figure 9.18, as follows: 1. 2. 3. 4. 5. 6. 7. 8. 9. 10.

Conditioning of a well prior to cementing to clean up the debris. Pumping of spacer ahead of cement slurry Pumping of cement slurry Releasing the pump down plug Displacement of cement down the running string and out of the liner into the annulus and keep pumping until the pump down plug lands on the wiper plug. Applying pressure to the pump down plug and shear out the pins on the wiper plug to release the wiper plug Both plugs move down the liner until they latch onto landing collar Bump the plugs with 1000 psi pressure Stops the pumps Starts reverse circulation for cleaning

9.7 Oil Well Cement Additives Typical admixtures for OWC slurries can be categorized into eight groups: accelerators, retarders, extenders, weighting agents, dispersants, luid-loss control agents, lost circulation control agents, and other special additives such as antifoam agents, ibers, etc. (Figure 9.19). he OWC slurry may incorporate retarders or accelerators to control the setting behavior. Weighting agents are light-weight systems to increase the density of the OWC slurry system, and extenders to lower the density of the cement system and increase its yield. Similarly, diferent admixtures are used as dispersants or viscosiiers

Cementing Mixing

Displacing

529

End of Job Reverse Circulation

Pump down plug

Liner hanger Liner wiper plug

Landing collar

Float shoe

Figure 9.18 Liner cementing procedure.

Heavy weight materials; Barite, Hematite

Friction reducers (dispersants): Polymers, Calcium lignosulphonate

Accelerators; CaCl2, NaCl Reterders; Calcium lignosulphonate CMHEC Saturated salt solution Cement Slurry

Extenders; Bentonite, Pozzolan Mud contaminants; Diesel, NaOH

Fluid loss additives; Organic polymers, CMHEO

Figure 9.19 Major cementing additives.

to control the viscosity of the slurry. For instance, luid loss additives are used to control the loss of the aqueous phase of the OWC slurry to the geological formation and to maintain constant water to solid ratio in cement slurries, while lost circulation control agents are used to control the loss of the cement slurry to weak or regular formations. A detailed review of cement additives has been provided by Nelson et al. (1990 and 2006).

530 Fundamentals of Sustainable Drilling Engineering In addition to chemical admixtures, a number of mineral additives such as ly ash, silica (α-quartz and condensed silica fume), diatomaceous earth, gilsonite, powdered coal (Nelson et al. 1990; Nelson et al., 2006), etc. have been used to alter certain properties of OWC slurries.

9.7.1

Accelerators

Accelerators shorten slurry’s set time and allow the slurry to develop necessary early compressive strength in a practical time frame (Santra et al., 2012). Accelerators are used for shallow low temperature and pressure cement jobs where long thickening time is not necessary. he most common accelerators used are calcium chloride, sodium chloride and gypsum.

9.7.2 Retarders Retarders delay slurry’s set time. his delay allows the cement to be placed before hardening occurs. hese additives counter the efects of increased temperature on cement slurry. he most commonly used retarders are calcium lignosulfate and borax.

9.7.3 Fluid Loss Agent Excessive losses of water to the formation can prevent cement from hardening correctly. Fluid-loss control additives are used to reduce excessive losses of water to the formation. In addition, these additives increase viscosity, retard the set time, and control free water in the slurry. he most common luid loss agents used are the organic polymers and cellulose derivatives.

9.7.4 Extenders Extenders lighten the density of the slurry for cementing across weak formations. Lighter slurry lowers the hydrostatic pressure and helps prevent formation damage. Mostly used extenders are ly ash and sodium silicate.

9.7.5 Anti-foaming Agent Cement foaming is one of the problems associated with cement slurry while mixing. he entrapped air in the cement slurry could cause damage to the pumps in the ield and also could cause incorrect density readings and consequently mixing incorrect cement slurry density. Defoamers are used to minimize foaming problems and are normally used with every cement system. Defoamers are special additives developed by diferent companies and are available in powder or liquid for convenient use.

9.7.6 Free Water Control Additives Free-water control additives tie up water in light weight or extended slurries. If this water were not controlled, the slurry properties would change as water was absorbed

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531

into the surrounding formations. his absorption afects slurry low and placement. Aluminum chlorohydrate is mostly used to prevent free water.

9.7.7 Lost Circulation Control Agents Controlling lost circulation is an important issue to be considered when cementing across highly permeable and vuggy formations as well as formations having natural or induced fractures. Lost circulation might be controlled by reducing cement slurry density and by adding additives to act as a plugging bridge on the opening area of the high permeability zone or the fracture. here are diferent types of lost circulation control agents, granular type (e.g. Gilsonite), lake type (e.g. cellophane), and ibrous agents (e.g. nylon).

9.7.8 Weighing Agent Weighting materials can be used to increase the density of the cement or slag and help control formation pressures. Barite and hematite are most used weighing materials.

9.7.9 Dispersants Dispersants reduce slurry viscosity, which is very important for placement and cohesion. Proper dispersion of a slurry results in enhanced early compressive strength, improved luid-loss control and improved free-water control. Naphthalene sulfonate and broxin are commonly used as dispersants.

9.7.10 Strength Retrogression Agents Cement slurries that remain at temperatures above 200°F (94°C) exhibit a reduction of compressive strength over time. his phenomenon, called strength retrogression, can be minimized or prevented by adding another source of silica, such as silica lour or silica sand, to the slurry (Iverson et al., 2010).

9.8 Cementing Design Process he cost of drilling and completion a well can be huge depending on the location and depth. Proper planning should include detailed design of the cement used for completion to alleviate remedial work over. Cement design is usually streamlined to a particular well according to prevailing downhole conditions which is followed by testing in the lab to ensure that the design. Ravi and Xenakis (2007) discussed a three step approach to cement design (Table 9.7). Step one would comprise a detailed engineering analysis. It would require classifying the nature of the formation; is it a hard or a loose formation? It would require ascertaining all forces that would come into play as the well is being produced; are there high temperatures, high pressures or both? Is it normally or abnormally pressured? Step one also covers stress analysis to determine if the cement sheath would sustain the series of cyclic loads it would encounter during its

532 Fundamentals of Sustainable Drilling Engineering Table 9.7 hree step process for cement design (Ravi and Xenakis, 2007). Steps

Explanation

Step 1 Engineering analysis failure

1) Efect of well operation on cement sheath integrity 2) Evaluate Properties of cement sheath to reduce the risk of failure

Step 2 Cement slurry design and testing placement

1) Lab tests – hickening time, mechanical properties 2) Other tests – Wettability, hole cleaning and slurry

Step 3 Cement slurry design and testing improvement

1) People, equipment, quality process 2) Cement sheath evaluation, monitoring, and learning

lifetime. he answers to step one questions would lead to step two which would involve designing the cement slurry based on factors identiied in step one. he properties of the cement like tensile strength, Young’s modulus, Poisson’s ratio, plasticity parameters, shrinkage/expansion during hydration, and post-cement slurry hydration are chosen so as to efectively match the efects of downhole conditions. hereater, laboratory investigations are conducted on the designed slurry. he data from the laboratory tests and the analysis of step one are then analyzed together to evaluate performance. Step three would involve best drilling and cementing practices such as centering of casing and efectively cleaning out hole of all mud so as not to undermine the performance of the designed slurry. It also comprises monitoring during the life of the well.

9.8.1 Planning Cement Job he planning of the cement job includes determining the type and volume of cement and cement additives. It also plans the procedures for mixing the cement, water and additives. he prelushing as well as cement placement and displacement should be properly planned. he cement system design takes into consideration chemical environment, mix water, wellbore luids bottom hole static temperature, bottom hole circulating temperature, pore pressure, formation permeability, formation integrity, and hole geometry.

9.8.2

Factors Afecting Cement Job Design

he behavior of OWC slurries must be adjusted to achieve efective well cementing jobs. he mechanical properties and durability of solid cement during the life of the well are important criteria, especially under harsh pressure and temperature environments. he design of cement slurry is very critical in deeper wells. High temperature and pressure expose the cement to extreme stresses and afect its quality. In such situations, the properties of cement should ensure its long term integrity. Improper oil and gas well design and well cementing can jeopardize oil production. Oil wells could leak and lead to environmental disasters particularly in marine habitats, and result in

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533

huge economic losses. he oil industry realizes the value of spending more money on research and development of materials and equipment to improve oil ields exploration and production and to prevent potential oil and gas leakage. Cementing is a complex operation, depending on the region where drilling will take place and lithology encountered. Special attention has to be paid to cementing in HPHT wells. Cement shrinking and stress changes induced by downhole variation of pressure and temperature afects bonding properties of the cement with the casing and the formation. With poor bonding properties, the cement will degrade and one key function of the cement, zonal isolation, will fail. In HPHT formations, the wells are subjected to high temperature variations and these changes afect both the formation and the casings, causing expansion and contraction. his expansion and contracting of casing and plastic formation causes cracks in the already set cement. Figure  9.20 shows potential gas migration problems encountered in HPHT formations. hese problems are related to shrinkage, strength retrogression, luid loss, and gas migration and thickening time. he most common problem is gas migration which happens due to poor zonal isolation (Figure 9.20). his problem occurs as a result of poor bond of cement sheath with casing and formation and cracks in cement as a result of stress and shrinkage (9.20a–9.20c). Sometimes, gas migration problems exist in acidic environment where acidic gases corrode the casing (Figure 9.20d). When cement and water are mixed a hydration reaction process takes place, and the pore pressure in the setting cement reduces with its pore spaces. Ater cementing deep wells compression takes place and subjects the cement sheath to high load and destroys the matrix porosity

Cement Well Plug Well Casing Cement Fill Formation Rock

Figure 9.20 Potential problems in deep wells with poor cement sheath or major cementing problems in HPHT wells.

534 Fundamentals of Sustainable Drilling Engineering by compaction. his destruction of cement matrix is caused by mechanical failure or damage and they create cracks in the cement matrix. hese cracks are a pathway for the migration of gas from the formation to the surface, thereby shortening the life of the well because the integrity of the cement has been compromised (Yetunde and Ogbonna, 2011). Migration of gas through the cement has been an industry problem for many years. Some studies pointed out that approximately 80% of wells in Gulf of Mexico transmit gas to surface through cemented casing. For twelve months or more, ater cement has set, it continues to hydrate and consequently develop in strength. Ater this time, it maintains the strength that it has attained except if it is afected by erosion. Cement will attain maximum strength in two weeks when exposed to temperatures exceeding 230oF. Ater the irst two weeks, the strength slowly starts to decrease. his process of cement losing its strength is known as strength retrogression. Structural changes and loss of water are the causes of cement degradation. When cement is set, it contains a complex calcium silicate hydrate. At temperatures around 250oF, Calcium Silicate Hydrate is converted to a weak porous structure which causes strength retrogression. he rates at which these changes occur depend upon temperature (Joel and Iseghohi, 2009). Over the years, several types of new chemical admixtures such as retarders, viscosity modifying admixtures, accelerators, strength developers etc. have been introduced to optimize the properties of cement. Early age and hardened properties of cement systems are highly dependent on the type and quantity of chemical admixtures used. he performance of chemical admixtures is strongly inluenced by the chemical and physical properties of the cement. Most of the commercial chemical admixtures have been used with Ordinary Portland cement and for general purpose use. In order to cope with bottom hole conditions additives are usually mixed with the slurry. he interactions of OWC with diferent types of admixtures and the associated cement-admixture compatibility at high temperature are still largely unexplored. OWC has advanced with time to be a special class of cements to meet the demanding requirements of oil ields and has helped in classifying the OWC cement to guide the drilling engineers to the best practices in oil well cementing.

9.9 Laboratory Tests on Cements Slurry Laboratory tests are the main technique to evaluate and develop diferent properties of cement and to simulate the actual behavior of the cement in downhole environment including high pressure and temperature. he lab testing is conducted according to the American Petroleum Institute (API Speciications-10A, 2012) procedures and consists of several cement tests and each assesses a speciic cement property. he properties of cement test include: 1) 2) 3) 4) 5)

hickening time Density Rheology Fluid loss Free water separation

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535

6) Particles settling 7) Permeability and porosity 8) Compressive strength test a) Compressive strength by “Crushing” method b) Compressive strength by “Sonic” method he testing program low chart is shown in Figure 9.21. In this section a testing program will be followed to demonstrate the various tests and equipment used to evaluate the properties of cement. Table 9.8 shows the experimental program, which explains the equipment used in measuring the diferent properties of cement.

9.9.1

Well Speciications

A cement design of a well in the Middle East has been used to test cement properties. he speciications of well are given in Table 9.9.

9.9.2 Cement Slurry Design he particular well has a special cement system design since the well is deep with high pressure and temperature conditions. he selected cement system consists of diferent

Thickening Time

Free Water Content

Fluid loss

Density Tests

Rheology

Compressive Strength

Crushing Method

UCA Method Particles Setting

Porosity & Permeability

Figure 9.21 Laboratory Tests.

536 Fundamentals of Sustainable Drilling Engineering Table 9.8 Experimental program. Experimental Program Tests

Equipment

Parameters

hickening Time Test

HPHT Consistometer

Consistency, Bc

Free Water Test

Graduated Cylinder

Free water, ml

Fluid Loss

Fluid Loss Tester

Fluid loss, ml per 30 min

Density Test

Pressurized Mud Balance

Density, lb/gal

Rheology Test

Viscometer

Plastic viscosity, yield point, gel strength

Compressive Strength

HPHT Curing Machine

Crushing compressive strength, psi

Ultrasonic Cement Analyzer

Non-Destructive compressive strength, psi

Particles Settling Test

Long cylinder and HPHT Curing Chamber

Density segregation

Porosity and Permeability Test

Automated Porosimeter and Permeameter

Porosity and permeability

Table 9.9 Well speciications. Well Parameters

Values

Depth of well (TVD)

14000t

Bottom hole circulating temperature (BHCT)

228oF

Bottom hole static temperature (BHST)

290oF

Time to reach bottom (TRB)

49min

Surface pump pressure

1050psi

Mud weight (MW)

85PCF

Bottom hole pressure (BHP)

8265psi

materials in which each material contributes to enhance the various properties to ensure that the cementing job is successful. his design has been reached ater much iteration in which the percentages of the diferent components have been varied until the optimum percentage has been reached. Table 9.10 shows the cement slurry design of the particular well. A series of tests are conducted on the slurry design according to the experimental program shown in Figure 9.21.

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Table 9.10 Cement slurry design. Properties

Values

Slurry Density (Approx.), PCF

125

Water Cement Ratio

0.44

Slurry Yield

1.367

hickening Time

4–5 hours

Class G cement powder + 35% silica lour + 1% expanding agent + 0.8% Dispersant + 0.2% Fluid loss control agent + 0.5% Fluid loss control agent + 1% Retarder + 0.25gm Defoamer Table 9.11 Chemical composition of Class G cement.

9.9.3

Chemical Component

(%)

Silica (SiO2)

21.6

Alumina (Al2O3)

3.3

Iron Oxide (Fe2O3)

4.9

Total Calcium Oxide, (TCaO)

64.2

Magnesium Oxide (MgO)

1.1

Sulphur Trioxide (SO3)

2.2

Loss on Ignition

0.6

Insoluble Residue

0.3

Equivalent Alkali (as Na2O)

0.41

C3A