Drilling Design and Implementation for
Extended Reach and Complex Wells
Published by
K&M TECHNOLOGY GROUP, LLC
Houston, Texas
2003
Contributing Authors
Mike Mims
Tony Krepp
©1997- 2003 by K&M Technology Group, LLC
All rights reserved
Third Edition
Printed in the United States of America
This book or parts thereof may not be reproduced
in any form without permission of K&M
Technology Group, LLC, Houston, Texas.
Brand names, company names, trademarks, or other
identifying symbols appearing in illustrations and
text are used for educational purposes only and do
not constitute an endorsement by the authors,
editor, or publisher.
Drilling Design and Implementation for ER and Complex Wells
TABLE OF CONTENTS
1
INTRODUCTION ............................................................................................................................... 9
2
PURPOSE & SCOPE........................................................................................................................ 12
3
WHAT IS EXTENDED REACH DRILLING ................................................................................ 14
3.1
4
WHAT’S DIFFERENT ABOUT ERD ............................................................................................ 18
4.1
4.2
4.3
4.4
5
ERD DEFINITIONS ...................................................................................................................... 15
GENERAL ERD DIFFERENCES ..................................................................................................... 18
SPECIFIC SHALLOW ERD WELL DIFFERENCES ............................................................................ 26
SPECIFIC LONG ERD WELL DIFFERENCES .................................................................................. 27
SPECIFIC DEEP WATER ERD WELL DIFFERENCES ....................................................................... 28
PLANNING ERD WELLS ............................................................................................................... 30
5.1
ORGANIZATIONAL STRUCTURE ................................................................................................... 30
5.2
ERD PROJECT PLANNING OUTLINE ............................................................................................. 31
5.3
RISK MANAGEMENT ................................................................................................................... 34
5.3.1
“Aggressive” Strategies to Reduce Risk .......................................................................... 36
5.4
RIG CAPABILITY ......................................................................................................................... 37
5.4.1
Hydraulics Capability ...................................................................................................... 39
5.4.2
Rotary and Hoisting Capability ....................................................................................... 40
5.4.3
Power Capability ............................................................................................................. 40
5.4.4
General Rig Capabilities .................................................................................................. 41
5.5
ERD PLANNING – GENERAL REQUIREMENTS .............................................................................. 44
5.5.1
Hole Size Selection ........................................................................................................... 44
5.5.2
Wellpath Design ............................................................................................................... 45
5.5.2.1
Build and Hold Profile................................................................................................. 45
5.5.2.2
Catenary Profile ........................................................................................................... 46
5.5.2.3
S-Turn Profile .............................................................................................................. 48
5.5.2.4
Complex 3-D Well Designs......................................................................................... 48
5.5.3
Casing Design .................................................................................................................. 49
5.5.3.1
Casing Depths.............................................................................................................. 49
5.5.3.2
Casing Running ........................................................................................................... 49
5.5.3.3
Casing Wear ................................................................................................................ 50
5.5.3.4
Hydraulics Issues ......................................................................................................... 52
5.5.4
Drilling Fluids Selection .................................................................................................. 52
5.5.5
Wellbore Stability ............................................................................................................. 56
5.5.6
Hole Cleaning .................................................................................................................. 57
5.5.7
Torque and Drag Modeling.............................................................................................. 61
5.5.8
Directional Drilling Strategy ........................................................................................... 62
5.5.9
Negative Weight Wells ..................................................................................................... 64
5.5.10
Drillstring Design ............................................................................................................ 64
5.5.10.1
General Drillstring and BHA design....................................................................... 64
5.5.10.2
Drillpipe size........................................................................................................... 65
5.5.10.3
Other Drillstring Specifications .............................................................................. 67
5.5.10.4
Integral Bladed Drillpipe ........................................................................................ 68
5.5.10.5
High Friction Pipe Dope ......................................................................................... 68
5.5.11
Surveying and Targets...................................................................................................... 68
5.5.11.1
Targets and Geological Uncertainty ....................................................................... 69
5.5.12
Formation evaluation ....................................................................................................... 70
5.5.13
Cementing ........................................................................................................................ 72
6
HOLE CLEANING ........................................................................................................................... 73
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Drilling Design and Implementation for ER and Complex Wells
6.1
FUNDAMENTALS OF HOLE CLEANING ......................................................................................... 73
6.1.1
Cuttings Transportation.................................................................................................... 73
6.1.2
What is Happening Downhole? ........................................................................................ 74
6.1.3
Systems Approach ............................................................................................................. 76
6.1.4
What is a “Clean” Hole? ................................................................................................. 78
6.1.5
How is the Hole Cleaned? ................................................................................................ 80
6.1.5.1
Rotation........................................................................................................................ 80
6.1.5.2
Flowrate ....................................................................................................................... 81
6.1.5.3
Fluid Rheology ............................................................................................................ 82
6.1.5.4
Bottoms-up .................................................................................................................. 83
6.2
GUIDELINES FOR HOLE CLEANING WHILE DRILLING .................................................................. 84
6.2.1
Drilling Fluids .................................................................................................................. 84
6.2.1.1
Rheology Guidelines.................................................................................................... 84
6.2.1.2
OWR Guidelines .......................................................................................................... 85
6.2.1.3
Low Gravity Solids ...................................................................................................... 85
6.2.2
Flowrates and hydraulics ................................................................................................. 85
6.2.3
Drillpipe Rotation ............................................................................................................. 87
6.2.4
Connection Practices ........................................................................................................ 88
6.2.5
Monitoring Hole Cleaning Performance .......................................................................... 89
6.2.5.1
Drilling in The Box ...................................................................................................... 89
6.2.5.2
Off-bottom Torque and Drag (T&D) Data................................................................... 92
6.2.5.3
Cuttings Returns .......................................................................................................... 95
6.2.5.4
Drilling Parameters ...................................................................................................... 95
6.2.5.5
Mud Properties ............................................................................................................. 95
6.2.5.6
Downhole Tools ........................................................................................................... 96
6.3
GUIDELINES FOR CLEANUP PRIOR TO TRIPPING .......................................................................... 98
6.4
GUIDELINES FOR TRIPPING.......................................................................................................... 99
6.4.1
Standard Tripping Procedure ........................................................................................... 99
6.4.2
Backreaming ................................................................................................................... 100
6.4.2.1
Guidelines for Back-Reaming through a ‘Tight Spot’ ............................................... 103
6.4.2.2
Guidelines for Precautionary Backreaming ............................................................... 103
6.5
GUIDELINES FOR REMEDIAL HOLE CLEANING .......................................................................... 104
6.5.1
Stop and Circulate .......................................................................................................... 105
6.5.2
Wiper Trips ..................................................................................................................... 105
6.5.3
Sweeps ............................................................................................................................ 105
6.5.4
Backreaming ................................................................................................................... 107
7
TORQUE, DRAG, BUCKLING AND VIBRATIONS ................................................................. 108
7.1
TORQUE AND DRAG THEORY .................................................................................................... 108
7.1.1
Torque............................................................................................................................. 110
7.1.2
Drag................................................................................................................................ 111
7.1.3
Friction Factors .............................................................................................................. 111
7.1.3.1
Planning Friction Factors ........................................................................................... 113
7.1.3.2
Sensitivity Analysis ................................................................................................... 114
7.1.4
General Torque and Drag Definitions............................................................................ 116
7.2
WELLPATH DESIGN ................................................................................................................... 116
7.2.1
Catenary Well Profile ..................................................................................................... 117
7.2.2
S-Turn Profile ................................................................................................................. 117
7.2.3
Complex 3-D Well Designs ............................................................................................. 118
7.3
KEY WELL INTERVALS FROM A TORQUE, DRAG AND BUCKLING VIEWPOINT........................... 119
7.3.1
Shallow Build Section ..................................................................................................... 119
7.3.2
Tangent Section .............................................................................................................. 121
7.3.3
Lower Build and Turn Section ........................................................................................ 122
7.3.4
Lower Drop Section ........................................................................................................ 122
7.3.5
Reservoir / 8½" Section .................................................................................................. 122
7.4
BUCKLING................................................................................................................................. 123
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Drilling Design and Implementation for ER and Complex Wells
7.4.1
Buckling Theory ............................................................................................................. 123
7.4.1.1
Sinusoidal (or “snaky”) Buckling .............................................................................. 126
7.4.1.2
Helical (or “Coiled Spring”) Buckling ...................................................................... 126
7.4.1.3
Common Misconceptions .......................................................................................... 127
7.4.2
Common Buckling Intervals ........................................................................................... 127
7.4.3
Options to Prevent or Reduce Buckling ......................................................................... 129
7.4.3.1
Wellpath Design ........................................................................................................ 129
7.4.3.2
Drillpipe Size and Stiffness ....................................................................................... 129
7.4.3.3
Special Downhole Tools to Improve Drillpipe Stiffness ........................................... 130
7.4.3.4
Rotation and Flotation ............................................................................................... 131
7.5
VIBRATIONS ............................................................................................................................. 132
7.5.1
Types of Vibrations ........................................................................................................ 132
8
NEGATIVE WEIGHT WELLS .................................................................................................... 134
8.1
DRILLING OPERATIONS ............................................................................................................ 134
8.1.1
Drillstring Design .......................................................................................................... 134
8.1.2
Tripping In ..................................................................................................................... 135
8.1.3
Drilling ........................................................................................................................... 135
8.1.4
Deep Sliding Technique ................................................................................................. 136
8.1.5
Drilling with Block Weight ............................................................................................. 137
8.2
CASING RUNNING OPERATIONS ................................................................................................ 137
8.2.1
First Line Contingencies ................................................................................................ 138
8.2.1.1
Lighter Weight Casing .............................................................................................. 138
8.2.1.2
Inverted Casing Designs ............................................................................................ 138
8.2.1.3
Hangoff Drill collars.................................................................................................. 139
8.2.1.4
Run Casing as a Liner................................................................................................ 139
8.2.1.5
Apply Top Drive Weight ........................................................................................... 139
8.2.1.6
Top Drive Pull-Down Systems .................................................................................. 141
8.2.2
Casing Floatation Techniques ....................................................................................... 142
8.2.2.1
Air Filled (Empty) ..................................................................................................... 143
8.2.2.2
Mud Over Air ............................................................................................................ 145
8.2.2.3
Air Cavity Technique ................................................................................................ 145
8.2.2.4
Heavy Mud Over Light Mud ..................................................................................... 146
9
HYDRAULICS PLANNING .......................................................................................................... 147
9.1
HYDRAULICS MODELING.......................................................................................................... 147
9.2
OPTIMIZATION OF HYDRAULICS PERFORMANCE ...................................................................... 147
9.2.1
Identify Rig Hydraulic Limitations ................................................................................. 147
9.2.2
Well Design .................................................................................................................... 148
9.2.3
Drilling Fluid ................................................................................................................. 149
9.2.4
Drillstring Design .......................................................................................................... 150
9.2.4.1
Drillpipe Size............................................................................................................. 150
9.2.4.2
Tooljoint Design and Dimensions ............................................................................. 154
9.2.4.3
HWDP Length ........................................................................................................... 154
9.2.5
BHA Design.................................................................................................................... 154
9.2.5.1
MWD / FEWD Selection........................................................................................... 155
9.2.5.2
Adjustable Stabilizers ................................................................................................ 155
9.2.5.3
Rotary Steerable Tools .............................................................................................. 155
9.2.5.4
Steerable Motors with PDC bits ................................................................................ 156
9.2.5.5
Steerable Motors with Tricone Bits ........................................................................... 156
9.2.6
Bit Hydraulics ................................................................................................................ 157
9.2.6.1
PDC Bits .................................................................................................................... 157
9.2.6.2
Tri-cone Bits .............................................................................................................. 157
10
ECD MANAGEMENT .............................................................................................................. 158
10.1
WHAT IS ECD .......................................................................................................................... 158
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Drilling Design and Implementation for ER and Complex Wells
10.1.1
ECD and pipe rotation.................................................................................................... 159
10.2
WHAT ARE THE EFFECTS OF ECD ............................................................................................. 160
10.3
WHY IS ECD A PARTICULAR CONCERN FOR ERD ..................................................................... 161
10.4
EXAMPLES OF ECD MAGNITUDES ............................................................................................ 162
10.5
ECD MANAGEMENT – PLANNING PHASE .................................................................................. 163
10.5.1
Wellpath Design ............................................................................................................. 164
10.5.2
Hole Size Optimization ................................................................................................... 164
10.5.3
Casing Plan .................................................................................................................... 165
10.5.3.1
Run Intermediate Casing as a Liner ...................................................................... 165
10.5.3.2
Use Alternative Casing Connections and Centralizers .......................................... 165
10.5.3.3
Use different sizes of casing.................................................................................. 166
10.5.3.4
Casing Flotation and ECD .................................................................................... 166
10.5.4
Drilling Fluids ................................................................................................................ 166
10.5.4.1
Rheologies............................................................................................................. 166
10.5.4.2
Gel Strengths ......................................................................................................... 167
10.5.4.3
Sweeps .................................................................................................................. 167
10.5.5
Drillstring Design ........................................................................................................... 168
10.5.6
Bit and stabilizer design ................................................................................................. 169
10.5.7
Pressure While Drilling (PWD) Technology .................................................................. 169
10.6
ECD MANAGEMENT – OPERATIONAL PHASE............................................................................ 169
10.6.1
Flowrate and RPM ......................................................................................................... 169
10.6.2
ROP ................................................................................................................................ 170
10.6.3
Slide Drilling Practices .................................................................................................. 170
10.6.4
Backreaming ................................................................................................................... 171
10.6.5
Down-Reaming ............................................................................................................... 171
10.6.6
Tripping Practices .......................................................................................................... 171
10.6.7
Summary of ECD Management in Operational Phase ................................................... 172
11
DIRECTIONAL DRILLING STRATEGIES .......................................................................... 174
11.1
PRIORITIES FOR DIRECTIONAL DRILLERS .................................................................................. 174
11.2
PLANNING BHA STRATEGY ...................................................................................................... 175
11.2.1
Key Issue – Hole Cleaning ............................................................................................. 176
11.2.2
Key Issue – Hydraulics ................................................................................................... 176
11.2.3
Key Issue – Directional Control Required...................................................................... 177
11.2.4
Key Issue – Tortuosity .................................................................................................... 177
11.2.5
Key Issue – Torque, Drag and Buckling ......................................................................... 178
11.2.6
Key Issue – Bit Selection................................................................................................. 178
11.2.7
Key Issue – Overall Drilling Cost and Efficiency ........................................................... 179
11.3
SPECIFIC MOTOR ISSUES ........................................................................................................... 182
11.4
BHA ALTERNATIVES........................................................................................................... 183
11.4.1
Shallow Build Sections ................................................................................................... 184
11.4.2
Tangent Sections ............................................................................................................. 185
11.4.3
Deep Build / Drop / Turn Sections.................................................................................. 188
11.4.4
Horizontal Sections......................................................................................................... 189
11.5
GENERAL BHA CONSIDERATIONS ............................................................................................ 192
11.5.1
Jars ................................................................................................................................. 192
11.5.2
BHA Weight .................................................................................................................... 192
11.5.3
Stabilizer Designs ........................................................................................................... 193
11.5.4
Adjustable Stabilizers ..................................................................................................... 193
11.5.5
BHA Prediction Modeling for Rotary Assemblies .......................................................... 194
11.5.6
Advanced Rotary Slide Drill Technique ......................................................................... 194
11.5.7
Chasing the Curve .......................................................................................................... 197
11.5.8
Reporting Practices ........................................................................................................ 198
11.5.9
Rotary Steerable Tools (RST’s) ...................................................................................... 199
12
BIT SELECTION STRATEGY ................................................................................................ 203
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Drilling Design and Implementation for ER and Complex Wells
12.1
PDC BITS .................................................................................................................................. 204
12.1.1
Matrix Verses Steel Bodied ............................................................................................ 204
12.1.2
Vibration Management ................................................................................................... 205
12.1.3
PDC cutter Design and Placement ................................................................................ 205
12.1.4
Gauge Length ................................................................................................................. 205
12.2
TRI-CONE BITS ......................................................................................................................... 207
12.3
BI-CENTER BITS ....................................................................................................................... 207
12.4
RST BITS .................................................................................................................................. 209
12.5
BIT HYDRAULICS...................................................................................................................... 209
12.6
BIT SELECTION FOR STEERABLE APPLICATIONS ....................................................................... 211
13
SURVEYING AND GEOLOGICAL UNCERTAINTY MANAGEMENT .......................... 213
13.1
THEORY AND DEFINITIONS ....................................................................................................... 213
13.1.1
Confidence Interval ........................................................................................................ 214
13.1.2
MWD Operation and Uncertainties ............................................................................... 215
13.1.3
Gyro Operation and Uncertainties................................................................................. 216
13.1.4
Random and Systematic Errors ...................................................................................... 217
13.1.5
Survey Interval ............................................................................................................... 217
13.2
OPTIONS TO REDUCE SURVEY UNCERTAINTY ........................................................................... 218
13.2.1
MWD Surveys ................................................................................................................. 218
13.2.2
Gyro Surveys .................................................................................................................. 219
13.2.3
In-Hole Referencing (IHR) ............................................................................................. 219
13.2.4
In-Field Referencing (IFR)............................................................................................. 220
13.2.5
Geosteering .................................................................................................................... 220
13.3
TARGET DESIGN ....................................................................................................................... 220
13.3.1
Target Size and Shape .................................................................................................... 220
13.3.2
Allow for the Survey Uncertainty ................................................................................... 223
13.4
REDUCING GEOLOGICAL UNCERTAINTY ................................................................................... 224
14
CEMENTING ............................................................................................................................. 225
14.1
14.2
14.3
14.4
14.5
14.6
14.7
14.8
14.9
15
DISPLACEMENT INSIDE CASING ................................................................................................ 225
DISPLACEMENT OUTSIDE CASING ............................................................................................ 226
CEMENTING CASING ................................................................................................................. 227
CEMENTING LINERS ................................................................................................................. 228
OPEN HOLE CEMENT PLUGS ..................................................................................................... 229
SLURRY DESIGN ....................................................................................................................... 230
SPACER TRAINS ........................................................................................................................ 232
ECD ISSUES.............................................................................................................................. 233
CASING CENTRALIZATION ........................................................................................................ 234
WELL CONTROL ..................................................................................................................... 235
15.1
WELL CONTROL BASICS ........................................................................................................... 235
15.2
WELL CONTROL - WHAT’S DIFFERENT ABOUT ERD WELLS ................................................... 238
15.2.1
Taking a Kick ................................................................................................................. 238
15.2.2
Detecting a Kick ............................................................................................................. 239
15.2.3
Killing a Well ................................................................................................................. 240
15.2.4
Other Differences ........................................................................................................... 240
15.3
KILLING ERD WELLS ............................................................................................................... 241
15.3.1
Wait and Weight Method ................................................................................................ 241
15.3.2
The Drillers Method ....................................................................................................... 242
15.3.3
Engineers Method .......................................................................................................... 242
15.4
VERTICAL AND DEVIATED KILL SHEETS .................................................................................. 243
16
DEEPWATER ERD WELLS .................................................................................................... 244
16.1
16.2
RISER ISSUES ............................................................................................................................ 245
ECD ISSUES.............................................................................................................................. 246
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Drilling Design and Implementation for ER and Complex Wells
16.3
BUILD SECTION ISSUES ............................................................................................................. 246
17
COMPLETIONS AND WORKOVERS IN ERD .................................................................... 248
18
SPECIALTY TOOLS AND NEW TECHNOLOGIES ........................................................... 250
18.1
DIRECTIONAL DRILLING ........................................................................................................... 250
18.1.1
Rotary Steerable Tools ................................................................................................... 250
18.1.2
Adjustable Stabilizers ..................................................................................................... 250
18.1.3
Steerable Motors............................................................................................................. 251
18.1.4
Rotating Near Bit Stabilizers .......................................................................................... 251
18.1.5
Pin Down Motors............................................................................................................ 252
18.1.6
At-Bit Inclination Tools .................................................................................................. 252
18.1.7
Steerable Turbines .......................................................................................................... 253
18.1.8
Walking Bits.................................................................................................................... 253
18.1.9
Downhole Thrusters ....................................................................................................... 254
18.1.10
AG-itator .................................................................................................................... 254
18.1.11
Anaconda ................................................................................................................... 254
18.1.12
Drop Gyro’s ............................................................................................................... 254
18.2
MWD TECHNOLOGY ................................................................................................................ 254
18.2.1
Directional MWD ........................................................................................................... 255
18.2.2
MWD Directional Survey Accuracy ............................................................................... 255
18.2.3
Real Time Multi-Axis Vibrations .................................................................................... 255
18.2.4
Real Time Downhole Annular Pressure (“Pressure While Drilling”) ........................... 256
18.2.5
Downhole WOB / Downhole Torque .............................................................................. 257
18.2.6
MWD Caliper ................................................................................................................. 257
18.2.7
MWD Gyro’s .................................................................................................................. 258
18.3
CASING AND CEMENTING ......................................................................................................... 258
18.3.1
Expandable Slotted Casing ............................................................................................. 258
18.3.2
High Torque Casing Connections................................................................................... 259
18.3.3
Casing Shoes .................................................................................................................. 259
18.4
DRILLPIPE ................................................................................................................................. 260
18.4.1
5⅞” Drillpipe Premium High Torque drillpipe .............................................................. 260
18.4.2
Integral Bladed Drillpipe ............................................................................................... 260
18.4.3
165 ksi High Strength Material Drillpipe ....................................................................... 260
18.4.4
Composite and Titanium Drillpipe ................................................................................. 261
18.4.5
Pin-Up Drillpipe ............................................................................................................. 261
18.5
HOLE CLEANING ....................................................................................................................... 261
18.5.1
Integral Bladed Drillpipe ............................................................................................... 261
18.5.2
Hydraulic By-Pass Sub ................................................................................................... 262
18.6
TORQUE REDUCTION ................................................................................................................ 262
18.6.1
Non Rotating Drillpipe Protectors ................................................................................. 262
18.6.2
Roller Bearing Subs ........................................................................................................ 263
19
EXAMPLES OF OPTIMIZED ERD WELL DESIGNS ......................................................... 264
19.1
19.2
19.3
19.4
19.5
20
EXAMPLE #1: ERD PROJECT, UKRAINE .................................................................................... 264
EXAMPLE #2: SHALLOW ERD PROJECT, OFFSHORE WEST AFRICA .......................................... 267
EXAMPLE #3: INFILL ERD WELL, OFFSHORE AUSTRALIA ........................................................ 271
EXAMPLE #4: ERD SATELLITE DEVELOPMENT, OFFSHORE AUSTRALIA ................................... 275
EXAMPLE #5: SIGNIFICANT PROBLEMS ON ERD WELLS, OFFSHORE AUSTRALIA ..................... 278
RELEVANT TECHNICAL PUBLICATIONS ........................................................................ 280
20.1
20.2
20.3
20.4
20.5
ER DRILLING - GENERAL .......................................................................................................... 280
HOLE CLEANING IN ERD .......................................................................................................... 285
TORQUE, DRAG AND BUCKLING ............................................................................................... 286
HYDRAULICS AND ECD’S / PRESSURE WHILE DRILLING .......................................................... 289
DIRECTIONAL DRILLING ........................................................................................................... 290
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Drilling Design and Implementation for ER and Complex Wells
20.6
20.7
20.8
20.9
20.10
20.11
20.12
DRILLPIPE ................................................................................................................................. 292
DOWNHOLE VIBRATION ........................................................................................................... 293
CASING WEAR .......................................................................................................................... 294
SURVEYING .............................................................................................................................. 294
CEMENTING IN ERD ............................................................................................................ 295
WELL CONTROL IN HIGH ANGLE WELLBORES .................................................................... 296
COMPLETIONS IN ERD ......................................................................................................... 296
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Drilling Design and Implementation for ER and Complex Wells
1
INTRODUCTION
The following manual has been compiled by K&M Technology Group as a training aid for ERD
and Complex Well Drilling Engineering and Practices. This text has been written for presentation
to attendees of the K&M Horizontal and ERD Drilling Induction Training (H.E.R.D.I.T.) course
and will be used as the course text.
This is the 3rd edition of the text and it outlines the latest technologies and practices utilized in
ERD planning, drilling and completions.
About the authors:
This text has been compiled by Michael Mims, President and CEO, Tony Krepp, Vice President
of Engineering, Harry Williams, Vice President of Training, and Russell Conwell, Senior Drilling
Engineer for K&M Technology Group. Mike, Tony and Russell are based in Houston, Texas,
while Harry is based in Perth, Australia.
Mike first became involved in ERD drilling during the Unocal Pt. Pedernales Project and has
since participated in many of the world’s high profile ERD projects. Mike holds more than 10
patents on ERD technologies and continues to use and develop leading edge technologies in his
client’s well designs.
Tony has been involved in numerous ERD and horizontal projects for K&M in Australia, Canada,
Eastern Europe, USA and Africa. Tony’s specialties are in well designing for optimized
performance and application of downhole technologies (especially bits, directional drilling,
MWD and logging technologies). He has played a key role in many innovative ERD and
horizontal design solutions while participating in K&M projects.
Harry joined K&M after retiring from Exxon, where he was involved in drilling their record
breaking ERD wells. He has a broad background in drilling operations and has developed a
number of training aides that are currently being used worldwide.
Russell has been involved in ERD projects in Australia, USA, Russia and China, while working
with Exxon, Woodside and K&M. He has a strong operations background, recently being
involved as the lead Operations Engineer for the longest well in the world drilled from a platform.
All of these gentlemen have planned and participated in numerous record breaking ERD wells.
They are all currently involved in regional and world record projects that will set new
benchmarks for drilling performance and depth.
2007 – Third Edition
Page 9
Drilling Design and Implementation for ER and Complex Wells
About K&M:
K&M Technology Group is a Houston, Texas based company with operations currently active in
the USA, Australia, New Zealand, West Africa, China, Norway, Russia and the UK. K&M was
founded in 1988 when its founder, Michael Mims, became involved in the development of
leading edge technologies for extended reach wells for UNOCAL in California. K&M’s
technical services have since expanded to include software development, training programs and
well site surveillance services; all aimed at improving drilling performance in complex well
environments. Though the company was originally formed in California, it moved its central
operations to Perth, Western Australia in 1992.
K&M's mission is to lead the oil & gas industry in the development and application of leading
edge extended reach technology. K&M's technological advances became so greatly recognized
by 1997 that some of its largest clients requested K&M to bring its technology back into the U.S.
market. K&M services are now offered worldwide to clients such as Exxon, Chevron, BP, Esso,
Shell, Texaco and Apache, to name a few.
K&M has been involved in extended reach and horizontal drilling from its inception. In early
1989, K&M were contracted to design and build a special liner system for one of the first
extended reach drilling programs for Unocal. With this development of additional technology,
the company was thrust further into the new and technically complex world of extended reach
drilling. K&M's accomplishments in the extended reach field have been chronicled on numerous
fronts, such as winning the prestigious Australian Institute of Engineers, Engineering Excellence
Award for accomplishments in the field of extended reach drilling and with numerous worldwide
patents.
K&M has played a variety of roles in the design, drilling and completion in a wide range of
complex projects. With the recognition K&M has received from its contribution on record setting
wells, clients often involve K&M very early in the stages of field development. This work
includes studies ranging from simple feasibility studies to comprehensive development plans,
including detailed well designs and economic analysis.
K&M continues to work for many of the world's major oil companies on difficult, complex
drilling projects. K&M's state-of-the-art expertise and its team of highly skilled engineers have
enabled the company to offer a wide range of technical and training services. K&M is involved
in projects internationally where its teams are acting in roles from Field Surveillance Engineers to
Lead Design Engineers to Total Project Management Teams. K&M has also performed the role
of "troubleshooter" on many extended reach and horizontal wells. Innovative technical designs
have proven to be K&M's specialty in this field. Special casing running procedures, drill string
torque reducing techniques and torque & drag computer software are just a few of K&M's
technical innovations. K&M engineers hold more than a dozen patents, worldwide, for these
technologies.
2007 – Third Edition
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Drilling Design and Implementation for ER and Complex Wells
K&M also offers a range of training services as well as drilling engineering and design software
systems. The training services have been heralded as the most advanced drilling performance
schools in the industry. Through the experience gained in the development and application of
leading edge technology in their client wells, K&M's training schools help to reduce the learning
curve in advanced drilling programs. The engineers who are developing and applying these
advanced techniques teach K&M’s courses. These courses are designed fit-for-purpose to the
clients operations with content that is taken from the classroom and applied immediately in the
field.
K&M’s core team of experts has helped it to become a full service provider of technical services
to the drilling industry. K&M's development of leading edge technology in the complex world of
extended reach and horizontal drilling has helped it to become a recognized leader in the industry.
For more information visit our website at:
2007 – Third Edition
www.kmtechnology.com
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Drilling Design and Implementation for ER and Complex Wells
2
PURPOSE & SCOPE
The purpose of this training manual is to capture the current best practices and available
technologies for ERD and complex well drilling planning and implementation. This manual is
intended for use primarily by engineers and senior operations personnel and as a text for the
participants in the H.E.R.D.I.T courses.
This text assumes that the reader has a degree of competency in drilling engineering and drilling
operations practices. With input from this text, the reader will be able to apply current practices
to ERD and complex well programs and issue detailed program operational instructions.
Note that many of the design ideas that are proposed in this document are not necessarily
conventional, however almost all of the principles and practices are based on real experience.
The authors have had particular success over the past decade with challenging the ‘norm’and
therefore make no apologies for proposing solutions that may not appear in other ERD manuals.
Nor will we back off from our posture of critiquing conventional thinking as this has helped to
shed many of the “hog laws” that tend to haunt our operational practices.
The overall theme of this text is to educate engineering and operations personnel with respect to
what is really happening ‘down the hole’ in ERD and complex wells. Additionally, we hope to
encourage the reader to think of the ERD drilling and completion operations as a complex system
and to use a “systems” approach towards reaching design solutions. This method encourages
innovative and fit-for-purpose designs, rather than adopting the usual ‘off of the shelf’ solution.
Many readers may find that some of the suggestions and comments contradict those practices
already successfully used in some ERD projects and so would quite rightly ask:
• “Why should I consider such ‘non-conventional’ strategies when the conventional approach is
already in successful use”? In many cases, K&M would answer that (a) the well times could
have been much faster and less expensive, (b) that the practices necessitated much larger rig
capability than could have been used.
• Similarly, another fair question is “if such savings can be made, or if much smaller rigs can be
used by utilizing alternate drilling strategies, then why aren’t these techniques in much more
common use”? There are numerous reasons for this, some of which are as simple as lack of
experienced people that ask “why do we do it this way”, or simply that it is not in the interests
of key service companies to suggest alternate methods. However, probably the most important
reason is that it requires significant planning work, both on a project and a well-by-well basis,
to implement real optimization to the drilling performance. It is K&M’s experience that few
Operators or service companies have, or take the time to plan their work sufficiently, whereas
it is much easier (at least in the pre-spud period) to simply adopt the past solution.
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Drilling Design and Implementation for ER and Complex Wells
The manual is set out in the following structure which attempts to present this complex and
detailed subject as simply as possible:
SECTION
SUBJECT
PURPOSE
3
What is ERD?
Define what an ERD well is and provide
an overview of what has been done in the
industry
4
What is different about ERD?
Highlight the main differences from
conventional wells
5
Planning ERD wells
Overview of the planning process for an
ERD well
6-18
Detailed Discussion of various
issues and their relation to ERD
The theoretical and practical planning
considerations for the main ERD issues
19
Examples
Examples of how ERD wells have been
optimized
20
Reference
Listing of relevant SPE papers for further
investigation
The authors recognize that many of the discussions within this manual overlap each other and
there may appear to be some redundancy. This is intentional because most of the topics are
closely inter-linked, so it is difficult and inappropriate to discuss subjects in isolation.
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Drilling Design and Implementation for ER and Complex Wells
3
WHAT IS EXTENDED REACH DRILLING
Drilling technology has advanced rapidly in the last 5-10 years. As can be seen in Figure 1
below, the 10 km reach barrier has been now been surpassed three times and several Operators
are actively planning wells from 11-15 km reach. As well as the very long wells, there is also a
move to drill further with complex well designs such as big-bore, designer wells, deepwater and
other emerging technologies (i.e. expandables, multilaterals, etc.).
Traditionally, an ERD well has been defined as a well with a Horizontal/Total Vertical Depth
(HD/TVD) ratio > 2.0. The HD/TVD ratio has also been used to provide a relative measure of
the complexity of an ERD well (i.e. the higher the ratio, the more complex and difficult the well).
However, this definition does not fully capture the different types of ERD wells, or the relative
complexity of each.
The following section aims to provide a categorization of ERD wells, based firstly on their well
profile and secondly on some of their unique complexities.
INDUSTRY ERD EXPERIENCE
0
1000
6.0
2000
TVD (m)
5.0
3000
4.0
4000
3.0
5000
2.0
6000
Straight lines represent
horizontal throw to vertical
depth ratio
7000
1.0
8000
0
2,000
4,000
6,000
8,000
10,000
12,000
Horizontal Throw (m)
Figure: 1
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Industry ERD Wells Drilled to Date
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Drilling Design and Implementation for ER and Complex Wells
3.1
ERD DEFINITIONS
There are two basic types of ERD wells, which are primarily defined by the well profile:
1. Very shallow wells
2. Very long wells
TWO BASIC TYPES OF ER WELLS
Very Shallow ER wells:
Must overcome buckling and drag,
whilst dealing with low ECD limits and
unconsolidated formations
TVD
6.0
5.0
4.0
Very Long ER wells:
Must overcome large forces and
pressures, often challenging rig limits
1.0
2.0
3.0
Horizontal Throw
Figure: 2
Two Basic Types of ERD Wells
Very long ERD wells are the type of well design that is usually envisaged when “Extended
Reach” is mentioned. Very shallow ERD wells have quite unique problems and are often equally
as challenging. Whereas very long ERD wells must overcome forces and pressures of high
magnitude (i.e. brute force is needed), shallow wells must often overcome buckling and drag
while managing annular pressures within very small ECD limitations. In either case, it is
necessary to drill smart if performance is to be optimized.
In addition to the two basic ERD well types, the following specific ERD designs can also be
defined:
• Complex well Design
• Deepwater ERD Wells
• Limited Rig Capability
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Complex Well Design:
These 3-D well designs have mainly been drilled in the North Sea in the last few years and
involve significant changes in azimuth to line the well up with the required target(s). As shown
in Figure 3, the traditional HD/TVD ratio cannot be used to define the complexity of these wells,
and MD/TVD ratio provides a more meaningful definition. The use of Rotary Steerable Tools
(RST’s) has significantly improved the performance on these wells and allowed more complex
designs to be attempted.
Figure: 3
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Examples of Complex Designer Wells
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Drilling Design and Implementation for ER and Complex Wells
Deepwater ERD Wells:
With a significant increase in deepwater drilling in the last 2-3 years, there has been a move
towards the drilling of ERD wells in deepwater applications. This has resulted in very
challenging wells, which combine the unique difficulties of deepwater drilling, with the existing
difficulties of ERD wells.
The nature of deepwater drilling only serves to increase the impact of some of the existing ERD
well challenges. For example, hole cleaning becomes that much more difficult with a long riser
section, cold mud at the bottom of the riser impacts hydraulics and ECD’s, and buckling in the
long riser section limits BHA strategies.
Limited Rig Capability
K&M also believes that the definition of ERD should account for the capabilities of the drilling
rig that will be used. In essence, a 6000m MD (20,000’) high angle well may be quite
straightforward with a large rig (i.e. 5½” drillpipe and 3 x 1600 HP pumps), but will be a
significant challenge with a small rig (i.e. 5” drillpipe and 2 x 1600 HP pumps). Today, advanced
drilling technologies are being used to reduce the time and risk of drilling these long wells with
small rigs.
Many of the techniques that are described in this manual are those which have been developed
through drilling ERD wells from rigs that are not ideally suited to ERD drilling. These
“technologies” not only apply today in this application, but also will help to push the envelope for
ERD wells out further as the larger rig’s capabilities begin to be taxed.
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Drilling Design and Implementation for ER and Complex Wells
4
WHAT’S DIFFERENT ABOUT ERD
There are numerous issues that are different, or more critical, for ERD wells than for conventional
directional wells. In some case, the challenges on ERD wells are the same as those on
conventional directional wells, only magnified. In other cases, the issues are specific to the type
of ERD well that is being drilled. These key differences are discussed briefly in the topics below
and will be covered in detail later in the manual.
4.1
GENERAL ERD DIFFERENCES
ISSUE
MAJOR ERD DIFFERENCES
TORQUE,
DRAG AND
BUCKLING
Torque, Drag and Buckling limitations are regularly encountered on ERD wells during
both the drilling and completions phases. Completions and workovers must be included
in the base well designs, since there are numerous cases where ERD wells have been
successfully drilled, but cannot be completed or worked over adequately because of
design flaws or workover rig limitations. Torque, drag and buckling results are directly
related to the wellpath, drillstring, hole size, casing, completion and drilling fluids
designs. Hole cleaning and hole conditioning are also major factors that must be
considered.
Excessive torque and drag often drives the well designer towards more sophisticated
drilling fluids for improved lubricity.
TORQUE
Torque is generally only a significant limiting factor on long ERD wells or on slim-hole
ERD wells (where small diameter drillpipe will be used). It is common to rotate casing
and liners strings on ERD wells to ensure that a good cement job is obtained and this is
often the critical torque limitation.
Torque limits can be reached in a number of ways including limits to:
• Top drive or rotary table output
• Drill pipe tooljoints
• Casing connections
• Combined power usage
Efforts have been made in the industry to counter these limitations with:
• Stronger, more compact top drives
• Higher torque drill string tool joint connections
• High torque casing connections
• Subs and tools designed to reduce torque
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Drilling Design and Implementation for ER and Complex Wells
ISSUE
MAJOR ERD DIFFERENCES (CONT..)
AXIAL DRAG
Axial drag occurs due to the interaction of the drillpipe or casing as it is run in (slackoff) or picked up (pick-up) out of the hole.
Axial drag (pick-up and slack-off) becomes a problem as:
• the wells get deeper (more pipe on low side of the hole)
• with higher inclinations (higher vertical component of weight)
• as the rig gets smaller (equipment pickup and slack-off limits)
Generally, slack-off weight becomes a limiting factor:
• for directional drilling when slide drilling is no longer possible
• for casing running when the casing will not slide into the hole due to the length and
angle of the hole
Other Issues:
• when slack-off weight reaches zero for drilling and casing operations, we call these
wells “negative weight” wells
• pick-up drag is generally only an issue for casing and/or completion operations or for
ER wells with long vertical sections at TD
• Many of the casing strings that are run in extended reach wells are too long, and
therefore too heavy to pull from the hole. These runs become “one way trips” and
require a very clean hole to be successful
• Drag generally becomes a limiting factor for running casing and completions before
it begins to hinder the drilling and tripping processes.
BUCKLING
Buckling of drillpipe and casing results from excessive compression loads that build up
in the string due to axial friction.
Drill string and completion string buckling is a common problem in ERD wells. As the
length of high angle hole sections become longer, unconstrained pipe will begin to bend
in the wellbore. As this becomes more severe, a helix will develop and eventually
prevent the pipe from running into the hole. Operations that are most prone to buckling
are:
• slide drilling
• running liners
• running completions that require some ‘stab-in’ weight
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Drilling Design and Implementation for ER and Complex Wells
ISSUE
MAJOR ERD DIFFERENCES (CONT..)
HOLE
A thorough understanding of the dynamics behind good hole cleaning is critical to the
success of ERD wells. For high angle wells, in general, cuttings will fall to the low side
of the hole and away from the primary fluid flow at the top of the hole. This makes
removing the cuttings from the hole difficult and requires special techniques for various
well inclinations. The drilling parameters, BHA and bit designs, mud rheology and hole
condition will all have a significant effect on the rig system’s ability to effectively clean
the hole. To ensure good hole cleaning, it is critical that flowrates and pipe RPM are
maintained at high levels throughout the drilling process.
CLEANING
It is important to note that hole cleaning practices used to clean vertical or low angle
wells, will not be successful in high angle ERD wells.
ECD’S
ER wells inherently have higher ECD (Equivalent Circulating Density) fluctuations than
conventional wells. With the advent of MWD based Pressure While Drilling (PWD)
technology, the industry’s understanding of ECD’s has been seriously challenged. It has
been observed that the magnitude of ECD fluctuations is far greater than previously
thought.
ECD’s are more serious in ERD wells because:
• the magnitudes of the fluctuations are worse due to longer MD relative to TVD and
the drilling parameters must usually be more aggressive to maintain hole cleaning,
while the mud system can allow less scope for compromise
• wellbore stability, lost circulation and other key effects are generally more severe
and less tolerable in these wells
• temperature and pressure variations (and their effect on mud properties) are also
more extreme in these wells.
The combined power usage when deep on a long ERD well may become an issue. It is
REQUIREMENT often at this point, that maximum output levels are required from the mud pump,
drawworks and the rotary system. Many of the industry’s rigs that are being utilized for
ERD drilling do not have the capability to meet the combined output requirements.
Backreaming is the most taxing operation when considering the combined output issue.
If good hole condition and hole cleaning practices are utilized, then backreaming can be
discounted from the design plan. Although this may seem a bit haphazard at first
glance, it is now a common consideration in many K&M client wells.
POWER
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Drilling Design and Implementation for ER and Complex Wells
ISSUE
MAJOR ERD DIFFERENCES (CONT..)
SURVEY
ACCURACY
AND TARGET
DEFINITION
Survey accuracy is often a critical aspect of ERD wells that is either discounted
altogether, or widely misunderstood. ERD wells make survey accuracy more critical
because:
• increased MD results in increased cumulative survey error
• the target size is effectively reduced at high angle (see Figure 46)
• survey tool accuracy can deteriorate markedly at high angle (especially if in an eastwest direction at high latitudes)
• the ability to change direction to “get back into the target” is usually more limited
“Target definition” is the size, shape and logic behind the target area. The manner in
which the target is defined has a direct effect on the well time and cost, as well as the
required directional drilling strategies. The “angle of attack” (how the target looks from
the bit) coming into the target plays a big role in the difficulty of hitting the target. It
must be remembered that at 60° - 80° angle, the shape and size of the target area is
markedly different than it appears on a plan-view map.
The surveying uncertainty combined with the effective target area and the directional
drilling strategy drives the surveying strategy for ERD wells.
Wellbore instability is usually more critical on ERD wells due to:
INSTABILITY / • the increased wellbore angle
DIFFERENTIAL • increased hole exposure time
STICKING / • increased ECD fluctuations and effects
STUCK PIPE • increased importance of good hole for acceptable hole cleaning at high angle.
WELLBORE
Differential sticking is also often more common in these wells as:
• mud weight is often higher on ERD wells (for wellbore stability at high angles)
• the exposed reservoir intervals are longer in length
• the exposed reservoir intervals are open for a longer time
• the drillstring and BHA will be on the low side of the hole and at least partially
buried in cuttings throughout the reservoir section.
Differential sticking is even more important for wells where torque, drag or buckling
problems exist, since even minor differential sticking increases friction considerably.
Furthermore, the ability to jar or work the pipe free is reduced on ERD wells. Because
of the reduced ability to get weight or tension down to the BHA, operational tolerances
leading to stuck pipe are greatly reduced. For example, in a conventional well, up to
100-150 kips of overpull may result in permanently stuck pipe, whereas in an ERD well
the BHA may be permanently stuck with as little as 20-50 kips of overpull. In wells
with significant drag, it may not be possible to cock the jars.
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Drilling Design and Implementation for ER and Complex Wells
ISSUE
MAJOR ERD DIFFERENCES (CONT..)
CASING WEAR In general, casing wear is not a major concern in ERD wells due to much lower pipe
tension across the build section of the well. However, in some cases with poor practices
and inappropriate equipment, casing wear can be more of a risk on ERD wells. The
following are the key factors for minimizing the chances of casing wear:
• a smooth build section
• the use of good quality drillpipe hardbanding
• elimination of backreaming
If casing wear is managed effectively, high rotary speeds and thin walled casing can be
used safely despite long drilling periods through this casing. As an example, BP at
Wytch Farm successfully used light weight 9⅝” 40 ppf casing (instead of the usual 47
ppf casing). Despite drilling 8½” hole for up to 60-80 days at depths up to 10000m
(33000’), BP has not experienced significant casing wear problems.
RIG
CAPABILITY
ER wells challenge a rig’s capabilities more readily than a conventional directional well
of the same measured depth (except for pick-up loads). The need to use higher
flowrates continuously at higher pressures, use of higher pipe RPM and higher torque
and drag forces will begin to tax a rig’s output capability and preventative maintenance
program.
Also, power may be limited, especially in a backreaming scenario (where pick-up,
torque and pumps are all working hard).
It is important to understand that embarking on an ERD program which places
continuous high loads on the rig systems will result in increased rig downtime.
Changing the preventative maintenance strategies to account for this fact has proven to
be cost effective for the Operator. For instance, paying to change out all of the
expendable pump parts at the beginning of a critical hole section, even though the parts
may not have significant hours on them, will pay dividends in reduced downtime during
critical sections of the well. Not only do these increased loads increase well time and
risk, but the need to drill “smarter”, as described herein, becomes paramount.
ER wells commonly drill with much of the drill string in compression. Oil field tubulars
are not designed to drill in compression, but the gravity holding the pipe to the low side
of the hole prevents catastrophic problems from occurring. Nonetheless, over time, this
environment does stress and degrade drilling tubulars leading to failures that are more
frequent. Fishing operations in ERD wells also present unique challenges, which must
be addressed in the design stages of the well to ensure that proper tools are available
when they are required.
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Drilling Design and Implementation for ER and Complex Wells
ISSUE
WELL
MAJOR ERD DIFFERENCES (CONT..)
Well control is generally more challenging in an ERD environment.
CONTROL
Kicks are often more difficult to detect and measure in high angle wells due to:
• Simple geometry - where the shut-in pressure impact of a swabbed influx is much
less due to the high angle where the influx occurred. For example, a gas kick in
vertical wellbore may contribute 300’ TVD length of bubble, whereas it will have
only 30’ TVD height in an 85° wellbore, and zero effect in a horizontal wellbore.
• OBM or SBM drilling fluids are often necessary for lubricity and other reasons. Gas
solubility and mud compressibility factors (combined with large annular mud
volumes) can mask influx detection.
Not only is detecting a kick often more difficult, but the ability to manage and kill the
well control problem is more difficult due to:
• The flow mechanics in a shut-in wellbore at high angle prevents the kill mud from
fully displacing the hole. The kill mud will be pumped up the high side of the hole
and cannot completely displace out the stagnant lightweight mud in the low side, due
to lack of pipe rotation.
• The mud volumes and barite quantities are huge for large ERD wells, and so even
the smallest of kicks will require some waiting period while additional mud and
barite is delivered. It is not unusual for several kill attempts to be necessary in these
wells, even if the correct kill weight mud was used in the first attempt.
Furthermore, the risk of swabbing a kick in an ERD well is increased due to:
• The presence of a static cuttings bed reduces the flow-by area around the bit
• The bit selection and stabilizer designs typically used in ERD (say for improved
steerability performance) mean reduced junk-slot area.
• Because of ECD and pump pressure reasons, mud weights are typically run as low as
practicable on ERD wells, reducing the static overbalance pressure.
• The trip distances are much greater (and often more trips are made), and so the
opportunities for swabbing are increased.
Rig crews and supervisory personnel must be familiar with the need to use deviated killsheets since vertical-kill sheets are no longer applicable in high angle wellbores.
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Drilling Design and Implementation for ER and Complex Wells
ISSUE
MAJOR ERD DIFFERENCES (CONT..)
LOGISTICS
Logistics are far more complex and more difficult to manage in ERD. Unless the
offshore Drilling Supervisor is given additional logistics management support, he/she
will be overwhelmed by the logistics management issues (or at least be completely
devoted to it).
Examples of scenarios that require heightened logistics management:
• OBM/SBM transfers:
- Building / delivering initial mud volumes,
- Running casing (especially if casing is run empty), where large mud volumes may
be recovered and must then be (a) stored or sent away, or (b) stored and pumped
down hole for the cement job or casing fill-up.
• Well control (large mud volumes and barite quantities)
• Drillpipe racking space in the derrick is often insufficient for long ERD wells,
especially if tapered or multiple drillstrings are necessary. If inverted drillstrings are
necessary to manage drag and buckling, then this is made even more difficult again.
It is not uncommon for the last portion of an ERD well to require that drillpipe is
picked-up/laid-down due to insufficient derrick capacity, or to make room on the
floor to run casing.
• Substructure weight limitations may prevent the combination of a full derrick of
drillpipe and casing on the pipe rack. This may be further complicated if mud
storage capacity on board must be increased to manage OBM/SBM usage.
• For ultra-long ERD wells, there is often inadequate space available to store casing on
the pipe rack and some casing may need to be run off of the boats. Casing stacked
very high can create safety and storage problems.
• Accommodation for personnel is often a key issue for ERD wells. Additional
personnel are almost always required for these wells (such as for SBM mud systems,
extra solids control equipment, different directional drilling tools, extra rig crews for
running casing, etc.).
TIME AND
COST
The very nature of ERD wells with their more critical build sections; higher tangent
angles and deeper depths make them more difficult than conventional wells. As such,
many of the cost related “short cuts” that can be used in conventional wells should be
carefully reconsidered before they are used on ERD wells. Although the use of any
“proven premium technology” should still be justified on a well-by-well basis, it is
accurate to state that better quality equipment and materials are usually cost effective on
ERD wells.
When things go wrong on ERD wells, recovery time is also greatly increased and time
and cost estimates need to consider this increased exposure.
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Drilling Design and Implementation for ER and Complex Wells
ISSUE
MAJOR ERD DIFFERENCES (CONT..)
HSE ISSUES
ER wells are exposed to higher HSE risks in several areas:
• The stress levels on equipment will be significantly higher than for conventional
ERD wells.
• There is a risk of boredom and tiredness during the long tripping operations
• Congestion on the platform due to the large volumes of fluids and equipment and
simultaneous handling (multiple cranes / forklifts) may lead to dangerous situations
• High fluid temperatures may occur
• Well control difficulties as discussed previously
• The stress on personnel is expected to be higher than during a normal drilling
operation (i.e. a failed log or bit may require several days round tripping)
• Drilling a relief well in the event of a blowout may not be successful initially due to
the large survey inaccuracy seen on an ERD well. Repeated intersection attempts
may be necessary.
WELL
Many of today’s Operators are faced with higher workloads for an even less experienced
staff. This is driving the use of “yesterday’s” drilling programs on a, more or less, cut
and paste basis. This is always accepted as a poor practice (driven by necessity), but it
must be avoided at all cost on ERD programs. It is K&M’s experience that ERD wells
should be designed from scratch as “fit-for-purpose” within the design constraints,
rather than simply using a combination of “standard” tools and methods that are readily
available.
PLANNING
The term “fit for purpose” is often used in the drilling industry, however, due to the
factors mentioned above, there is often tremendous scope for optimization. If applied
properly, this optimization requires detailed planning and analysis, on a project as well
as well-by-well basis. Planning needs to be supported by quality analysis of results and
rig-time for engineers. It is unfortunate that in many cases, the ‘off-the-shelf’ solution is
utilized because the manpower is not available to do otherwise.
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Drilling Design and Implementation for ER and Complex Wells
4.2
SPECIFIC SHALLOW ERD WELL DIFFERENCES
Although their total measured depth may be relatively small when compared to the “very long”
ERD wells, shallow type ERD wells do have significant issues that must be addressed. Some are
common to all types of ERD wells, but others are specific to these long, shallow wellbores.
SHALLOW ERD WELL CHALLENGES
For very shallow ERD wells, relatively fast build rates are often required. Obtaining the required build
rates in very shallow formations becomes critical to minimizing the final hole angle, and for minimizing
effects of torque, drag and buckling later in the well. The final angle of the well is far more sensitive to
the achievable build rate than for long ERD well types.
Not only is very good directional control required, but build rates are often limited by the unconsolidated
nature of shallow formations and stiffness of the large OD BHA’s.
Shallow ERD wells typically must deal with negative weight issues and/or pipe buckling. This
necessitates exotic casing running techniques, inverted drillstrings and often-large OD drillpipe to
manage drillpipe buckling.
Casing running can also be affected by the faster build rates and soft, shallow formations inherent in this
well type. It is not uncommon for this type of well to be sidetracked while running surface casing or
while running into the hole with a stiff drilling assembly.
The shallow vertical depths and relatively long measured depths of these wells make equivalent
circulating densities (ECD’s) a significant issue. Drilling and casing/cementing ECD’s often limit
flowrates because of unconsolidated shallow sediments. This can be exacerbated on high stepout
shallow wells by the need to use large OD drillpipe to overcome buckling problems. This is particularly
important if cement integrity above the shoe for zonal isolation is required. The impending loss
circulation problems will make this particularly challenging.
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Drilling Design and Implementation for ER and Complex Wells
SHALLOW ERD WELL ADVANTAGES
The magnitude of forces and pressures are much less than for long ERD wells. Hence, smaller drilling
rigs can be successfully utilized. With the smaller forces, less “brute force” will be required to overcome
operational problems.
Although drag forces may be a problem for completion and workover operations, most workover rigs
would be able to overcome these problems with their conventional equipment, again, due to the lower
magnitude of these forces.
The shorter nature of the wells means that hole sections will be smaller and, therefore, hole exposure
times will be less than for very long ERD wells. This will help to reduce effects such as formation
hydration, etc.
4.3
SPECIFIC LONG ERD WELL DIFFERENCES
When ERD wells start to become very long with very high tangent angles, the magnitudes of the
forces encountered require significant pull, torque, power, flowrate and pressure capability.
Often, even purpose built ERD rigs must be upgraded for successful and efficient drilling of
today’s “mega” wells.
LONG ERD WELL CHALLENGES
Torque and pick-up loads may exceed rig or drillpipe capability. This often requires that measures be
taken to (a) minimize or (b) manage these high loads. This includes bigger/stronger rig equipment, using
more lubricious drilling fluids, wellpath and casing set depth optimization, or use of specialized
equipment.
Completions and workover options are limited, and may only be performed with the drilling rig. The
completion may have to be designed specifically to allow workovers with available rigs in the area once
the drilling equipment has left. In some cases, the completion may be unserviceable (either due to
economics or feasibility).
Drilling rig equipment reliability is tested due to continuous high operating loads.
Survey uncertainty is increased due to the length and high angle of the wellpath.
Hole exposure time is increased compared to conventional wells. This effects wellbore instability and
therefore, mud weight and type, differential sticking and well cost.
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LONG ERD WELL CHALLENGES (CONT..)
ECD’s can be difficult to manage in smaller hole sections near TD due to the long wellpath. This can be
particularly important when cementing 7” liners or even when running long buoyancy assisted 9⅝”
casing strings.
Cementing can be very challenging for long ERD wells due to the long pump times and high angle
nature of the wellbores involved (especially for long strings of 13⅜” and 9⅝” casing). Obtaining a good
primary cement job is made even more significant for ERD wells given the extremely high cost and
limited capability to perform remedial cement jobs. The ability to obtain a good primary cement job is
governed by:
• the ability to maintain the integrity of the cement into the annulus in the same form as it left the
surface
• the ability to move the pipe during the cement job and, therefore, to obtain good annular
displacement of the pre-flushes and cement
• the ability to obtain a properly designed cementing program that will remove the filter-cake buildup
on the low side of the hole and then obtain the required zonal isolation.
Logistics management is often difficult and complex for such large wells.
4.4
SPECIFIC DEEP WATER ERD WELL DIFFERENCES
Deepwater ERD wells have become more common in the last few years. These wells combine
the already significant challenges of deepwater drilling, with specific ERD challenges. In most
cases, specialized engineering solutions may be required to overcome the resulting challenges.
DEEPWATER ERD WELL CHALLENGES
ECD’s are the primary limitation, even in big hole sections (i.e. 17½” and 12¼”). This is mainly due to
reduced overburden strength with the deepwater section. Big hole sections are often limited by cuttings
loading in the riser, which acts to limit effective ROP (which therefore restricts ability of directional
driller to apply WOB).
Hole cleaning in long sections of large OD riser can be difficult. Often, extra pumping capacity (if
available) is required to boost the riser. Hole cleaning within the riser is likely already limited by the
need to use ‘thinner’ fluids for ECD management.
Low temperatures in the riser result in significant changes in mud rheology. The main impact is on the
ECD’s as the mud thickens.
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DEEPWATER ERD WELL CHALLENGES (CONT..)
As for the shallow ERD wells, relatively fast build rates are often required, but very difficult to obtain.
Not only is very good directional control required, but build rates are often limited by the unconsolidated
nature of shallow formations and stiffness of the large OD BHA’s.
Buckling of the drillstring in the large OD riser is a concern when drilling and especially when running
casing and liners. Unlike platform drilling, the casing strings are typically run on drillpipe, which will
experience severe buckling if it has to push the casing into the high angle portion. This may require
casing landing strings or flotation techniques to manage buckling.
Negative weight conditions (as opposed to buckling problems) are less likely, due to long vertical
column that provides surface weight.
The cost environment is very expensive. This influences Operators toward solutions that place rig-time
as the #1 priority.
Drilling rigs for deep-water tend to be fit-for-purpose and usually have significantly improved hydraulics
and solids control packages. In general, ECD’s will be a limit rather than surface-pressures, unless
drilling at deep TVD’s with heavy mud weights.
Pressure While Drilling (PWD) tools are more critical.
Further detail can be found in Section 16.
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5
PLANNING ERD WELLS
The following section presents a broad overview of the planning process for an ERD well. The
key to planning is not to treat an ERD well as just “another well in the program”. Designs must
be fit-for-purpose and specific to the well in question. Time spent planning upfront will
definitely pay off in the operational phase in both performance improvements, and the avoidance
of “train-wrecks”.
K&M knows of many ERD wells that have been lost or made uneconomic by a lack of effective
planning. Detailed planning is the key to ERD success!
5.1
ORGANIZATIONAL STRUCTURE
You may challenge the applicability of a topic such as this in a technical manual. The fact is that
with this industry’s dynamic corporate environment, and the inherently long planning and
implementation time associated with today’s ERD programming, the maintenance of a consistent
team to see the project through can be critical to its success.
ER programs generally push rig systems and available technologies to their limits. For this
reason, a core design team that includes all of the relevant disciplines is absolutely critical. This
team must consist of the lead drilling engineer, reservoir engineer, geologist, completions
engineer and drilling operations representative. By designing your team in this manner, each
aspect of the program is given its fare stake in the design. Having Drilling Operations involved
from the beginning helps to pave the way for acceptance of new ideas into the field by giving
them ownership in the program.
This “Core Team” concept has been used successfully by a number of different Operators. The
concept of the core team means that its membership is constantly expanding and/or contracting
dependent upon what phase of the planning or operation is at hand. The Core Team will call in
expertise from other groups and service companies in order to ensure that their particular
expertise is properly incorporated into the program. Ultimately, the Core Team is responsible for
the planning and implementation of the well program, as a single unit, from concept to first oil.
The lead drilling engineer must be involved in the overall decision making for all aspects of the
drilling engineering design and implementation, rather than leaving these decisions to the
individual technology specialists. There is a trend within the industry whereby many specialty
roles exist within a drilling engineering team. In particular specialist bit, directional drilling,
drilling fluid and logging coordinators each “select” their preferred equipment and techniques to
best meet the required objectives. It may even be that the service companies have the
responsibility for selecting the required downhole equipment. There are distinct problems with
this approach:
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• With all due respect to the individual specialists or service companies, these individuals rarely
have the appreciation or responsibility to consider the ‘big picture’. For example, the bit
specialist really only considers the ROP, footage, bit hydraulics and possibly the ‘steerability’
issues surrounding likely bit candidates. Likewise, the directional drilling representative only
considers the directional control aspects of each well section. Neither will usually consider
the effects of rig capability, torque and drag and buckling, benefits of the following hole
section, specific lithology issues, hole cleaning, or tripping.
• Service companies have a real conflict of interest if directly responsible for the planning of the
drilling strategies. It is uncommon for any service company to recommend the equivalent or
alternate technologies from a competitor, regardless of that product’s applicability to the
design. It is K&M’s experience that no one company is technically best in every aspect of
their field (although it may be that a given service company may be easily the best organized
and supported in a particular region).
• Service company personnel that assume these responsibilities are rarely well informed about
their competitor’s products or capabilities. This is regardless of the service company
involved, as the protection of trade secrets in this field is a real problem. This raises the
question as to whether the well or the Operator’s best interests are being served from a
performance basis.
It is critical in ERD type wells that a “systems” approach is taken throughout, with no one aspect
treated in isolation (just like a complex ecosystem, each component's performance is inter-related
to the others). As such, it is important that the lead engineer is ultimately responsible for decision
making, and that the lead engineer has the experience to effectively fill this role, to ensure that the
“systems” approach or big-picture is maintained.
5.2
ERD PROJECT PLANNING OUTLINE
The table below presents an outline of the general planning process for an ERD project, as
recommended by K&M. Although each Operator will not necessarily follow this same outline, it
is seen as a minimum scope of work for ‘effectively’ planning an ERD project. Depending on the
Operator’s resources, time available and the nature of the well, some early planning steps may be
combined.
The time required for planning will depend on many factors including the location, logistics,
contracting, required rig upgrades, well design etc. However, as a general rule of thumb, 6-12
months is seen as the minimum for planning an ERD well.
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PHASE
WORKSCOPE
OWR
It is K&M’s experience that a detailed, quality Offset Well Review (OWR) is an
essential tool for optimizing well designs for best performance and minimum risk.
Although time consuming, a good quality OWR will identify the key well design issues
for an ERD project. On each occasion when K&M personnel have performed such a
review, the well designs have been revised in numerous ways to account for the
learnings. Even when an Operator thought that they knew a region, a detailed OWR has
shown that key misnomers, misunderstandings and/or poor recollection of historical
events have caused well designs and practices to be less than optimal.
A detailed format for the OWR is shown in Appendix A
PWD
After completing the OWR, a Preliminary Well Design (PWD) should be generated to
achieve the following:
• Establish the drilling feasibility and evaluate the risks of a given ERD program
• Establish the required drilling rig capability, drillsting options, drilling fluids, BHA
strategies, and power requirements
• Develop plans for contracting of rig and third party services
• Define the workscope for the following stage of the project
• Allow a relatively accurate time and cost estimate to be generated and therefore used
for further economic evaluation of the project as a whole.
The PWD should be detailed enough to achieve the above objectives, but should avoid
too much detail as rework will most likely be required in the next stage.
A detailed format for the PWD is shown in Appendix A
DWD
The Detailed Well Design (DWD) should be based on the PWD, and worked in
sufficient detail to allow the following to be achieved:
• Final drillpipe and casing specifications to allow materials to be ordering
• Final confirmation of rig specifications
• Tendering and selection of directional drilling, drilling fluids, cementing and other
services.
• Improved time and cost estimate to be generated.
A detailed format for the DWD is shown in Appendix A
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PHASE
WORKSCOPE
DRILLING
PROGRAM
The Drilling Program is the final documentation, and is written to be a link between the
DWD and operations in the field. Different Operators will have their own individual
formats for a Drilling Program. However, it is important that a Drilling Program for an
ERD well contains sufficient detail to allow the well to be drilled effectively. This will
require the use of Hole Section Guidelines (HSG), which is basically a separate program
for each major section of the well. The format for the HSG’s will be an expansion of the
Detailed Procedure Outline in the DWD.
&
HSG’S
HSG’s are completed as the well is drilled and in most cases, the HSG for each section
will not be finalized until the previous section has been drilled.
TRAINING
Training engineering and operations personnel to look for and deal with the varying
aspects of ERD is essential to the efficient implementation of an ERD program. The
detail in this manual demonstrates the degree of difference between conventional
deviated wells and ERD wells. The most valuable outcome of a quality training course is
that the drilling team will now have a single, firm direction in which to move. All
operations will be handled in a similar manner from hitch to hitch and from tour to tour.
A common misconception that K&M regularly encounters when selling or presenting
training courses is that the office personnel think that the training is really only
necessary for the field personnel, but not required for the engineers and
supervisory/management staff. As will be seen in this manual repeatedly, many of the
problems and solutions that are necessary for good performance must be implemented at
the planning stage.
OPERATIONS
REVIEW
WORKSHOP
As a final step to the planning process, the complete field team (Drilling Superintendent,
Drilling Supervisors, Operations Engineers, Toolpushers and third party service field
personnel) should conduct a multiple day workshop where the well is drilled and the
plan reviewed in detail. This workshop should focus on the actual mechanics of
implementing the plan and conducting realistic "what if" exercises. It should also focus
on the critical equipment being utilized to ensure that it is fit for purpose.
PRESPUD
It is also recommended that a comprehensive pre-spud be held with the rig crews to
orient them as to what is being undertaken. Crew safety in ERD wells is often
overlooked as being the same as conventional wells. Upon careful consideration,
however, one can determine that much higher torque and pressures, much higher
volumes of materials, different equipment and slippery mud systems are now going to
be utilized. Rig and crew readiness should be an integral part of the planning process to
ensure that incidents are avoided, which could taint the entire program.
MEETING
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5.3
RISK MANAGEMENT
Risk assessment and risk management play major roles in ERD well projects, and particularly in
the planning stages, from the concept phase, through to implementation. Accurate risk
assessment is more straightforward today than it was 5-10 years ago as the industry has begun to
push the limits and drill longer and longer wells. Numerous industry wells can now be used to
benchmark a proposed program.
However, when benchmarking against industry wells, the specific circumstances of the
benchmarking project must be taken into account. For example, BP’s Wytch Farm project is still
probably the most commonly used example for performance and capability benchmarking.
However, few people take into account the unique circumstances of this project. For instance,
Wytch Farm was drilled with a purpose built rig. Perhaps even more importantly, it was a landbased project with the best-possible learning curve opportunities that an offshore environment
rarely could match. The Wytch Farm wells were almost always drilled along a very similar
azimuth, and so directional drilling, wellbore stability and other geology and stress related issues
could be reliably and easily followed.
Available technology will also play a role in accurate risk assessment in today's industry. Very
often new technology will exist to help to mitigate risk in ERD wells, but it is either not
developed to a commercial stage, or the tools/equipment are not yet in plentiful enough supply to
count on them when beginning a program. Early identification of a program's shortcomings in
this area, will allow an Operator to "participate" in the development of these technologies, when
applicable.
Modern Quantitative Risk Assessment (QRA) is somewhat of a black art, and this document will
not attempt to explore the methods and means of quantifying risk. Suffice to say, that
"perceived" risk is your most dangerous enemy when drilling ERD wells. The fear of the
unknown has kept numerous Operators from exploiting reserves that were reachable with
existing ERD technology. Assembling a team that works the project from concept to first oil
and utilizing a systems approach to dealing with unforeseen circumstances (i.e. change
management procedures) will ensure that the well is drilled with controlled and minimized risk.
One of today’s most challenging objectives is keeping that design team together throughout the
project (i.e. avoiding transfers, resignations and re-assignments).
Operators can significantly reduce risks by making an attempt to move up the learning curve prior
to detailed planning for an ERD well. This may include drilling warm-up wells and gradually
increasing reach and difficulty, or learning from what others in the area are doing (no point
reinventing the wheel or making the same mistakes as others).
It is not advisable, for instance, to trial numerous new technologies on the first well in the region.
Furthermore, new technologies should always be trialed, when possible, in less critical wells to
develop experience both with how the tool operates and how the crews will operate the tools.
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Learnings must be calibrated carefully. It should not automatically be assumed that two wells
drilled in different directions in the same field will yield similar performance results. Depending
on the tectonics and geological structure in the region, a well in an East-West orientation can be
very different to that of a North-South oriented well and may require quite different design and
operational approaches. The ideal situation is to design learnings into the buildup wells to be
used later in the more difficult ERD wells.
Again using BP’s Wytch Farm project as an example, utilizing the learning curve was a key
factor in their success. BP engineered the project (and project economics) from the big picture
viewpoint, where each well was drilled with more difficult, longer reach wells in mind. This not
only affected the trial of new technologies and practices, but also the well sequence. K&M has
repeatedly seen cases where the ‘big picture’ issues have been interfered with by the individual
well economics. In particular, gathering information is often desirable in the early wells in a
program. This information may be (a) important to the success of the most difficult wells in the
future, or (b) that will benefit the entire program. However, it is not uncommon for such
information gathering to be abandoned because the individual wells cannot support the cost (i.e.
quality 4-arm caliper information for wellbore stability planning, casing wear log, etc.). In these
situations, it may be important that the cost of such operations be amortized across the entire
program or to an engineering AFE for the ERD well.
Risk management during the planning phase of the well is best accomplished by getting the
implementation team involved in the planning as soon as possible. Given that the operations
people have input into the plan, they then have ownership in it when it reaches the field. As a
final step of risk assessment prior to spud, an Operations Review Workshop and Prespud meeting
should be conducted as detailed in the previous section.
Risk management, once the program makes it to the field, plays the most significant role in the
process. The focus of the drilling team needs to be on drilling the well efficiently, not drilling the
well fast. Furthermore, implementation of the plan as it came out of the Operations Review
Workshop needs to be conducted with change management procedures being utilized to
accommodate any late changes. The more detailed the planning that has gone into the
engineering and logistics of the well, the lower the risk will be when drilling it.
Training is perhaps one of the most important tools to reduce risk. It is essential that all personnel
be fully trained in ERD operations. It should not be assumed that ‘conventional’ drilling
experience is adequate. K&M has found that conventional drilling practices are generally not
appropriate for ERD wells. Perhaps more importantly, the misconceptions and drilling practices
that can be “gotten away with” on conventional wells cannot, necessarily, be tolerated on ERD
wells.
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5.3.1
“Aggressive” Strategies to Reduce Risk
The conventional approach to building contingency into a well design (i.e. via use of larger hole
sizes) may actually increase the overall risk in certain ERD wells compared to a well planned,
“streamlined” or “slim hole” approach.
In particular, often the highest risk and/or most challenging section of an ERD wells is the 12¼”
section. This is primarily due to the difficulties associated with hole cleaning and directional
control. If formation stability is time dependent, or if hole cleaning is too difficult to manage
within the rig’s capabilities, then a safer approach may actually be to drill a smaller hole size
program. Although a smaller hole size may not allow a contingency hole size option, the reduced
risk of encountering significant problems may offset this lack of flexibility. It should be noted,
however, that any contingency planning must allow for the ECD’s that are associated with small
hole sizes.
As discussed later, and shown in one of the example wells at the end of this manual, drilling 13½”
x 9⅞” hole to TD may prove to be a safer and more efficient option as opposed to using a
conventional 17½” x 12¼” x 8½”plan. The 9⅞” hole will afford much faster drilling than the
12¼” due to the improved hole cleaning conditions and directional control. As a result, the 9⅞”
hole can be drilled further than the 12¼” hole before casing must be set due to hydraulics, torque
or power limitations. Further, if ECD’s at TD are a problem, then 9⅞” hole to TD will have
lower ECD's than 8½” hole drilled beneath 9⅝” casing.
Another good example of using an aggressive approach to reduce risk is to use “over-sized”
drillpipe. Instead of limiting the drillpipe size for full strength over-shot fishing capability, the
risk of having a twist-off may be exponentially reduced by using larger drillpipe (i.e. that will
require the tooljoint to be burned-over). For example, 4” drillpipe has about 50% greater torque
capability compared to 3½”, while having a substantially higher tension rating, and about 50%
greater flowrates are possible. This results in better ROPs due to improved bit hydraulics, better
motor performance (steerable motors in slim hole often do not have sufficient flowrate for good
operation) and improved hole cleaning. The net effect is not only reduced cost, but the risk of
having to fish the drillpipe due to hole conditions is markedly reduced because of the improved
drilling performance.
As is always the case when a more aggressive program is attempted, there will be occasional
incidents that may be exacerbated because of the more aggressive approach. However, the result
should be that the overall performance is improved.
Another approach to reduce risk and costs may be to drill 6” hole through the pay zone, instead of
8½”. This again reduces the contingency options, on the basis that “things are less likely to go
wrong in the first place”. Especially for horizontal wells that will be left barefoot, 6” horizontal
sections offer some distinct advantages:
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• The 12¼” section probably does not need to be pushed as far, significantly reducing risks in
this section. Remember that 12¼” hole is often the most difficult part of an ERD well to drill.
• If a significant build or turn is required so that the horizontal section is aligned in a specific
direction, this will be achieved more easily in 8½” rather than 12¼” hole. After setting 7”
liner, the horizontal section can then be drilled.
• It should be noted that 6” technology has made enormous leaps in reliability and capability in
recent years. MWD technology will probably never quite match that for 8½” equipment, but
will suffice for many applications. Already, full geo-steering FEWD suites are available.
• PDC bit life due to abrasion may actually be better for 6” compared to 8½” because the gauge
cutter tip speeds are somewhat slower.
5.4
RIG CAPABILITY
The required rig capabilities for drilling ERD wells are now becoming clearer as the industry
drills more challenging wells with smaller rigs and improved technologies. The required rig
capability depends very much on the drilling strategies and practices that will be used. Generally
speaking, if ‘off-the-shelf’ conventional practices and technology are used, then significantly
more capability is required from the rig, than if strategies and technologies are used that are
specifically aimed at improved hole cleaning performance.
In the table on the following page, a comparison is made between two very different rigs that are
drilling very similar wells, to highlight what can be achieved. The biggest difference between the
two programs is that the smaller rig forces the drilling team to work within its limitations to come
up with design solutions to drill the well; whereby the larger rig has enough "grunt" to simply
overcome many of the difficulties with brute force.
In order to evaluate the required rig capability, the following areas need to be considered.
• Hydraulics capability
• Rotary and hoisting capability
• Power capability
• General capability issues
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ESSO AUSTRALIA LTD
BP WYTCH FARM
FORTESCUE A-29
M5
SUMMARY:
Although the TD and throw of this well is not
particularly significant by today’s standards, the
well exceeded the rigs rated capabilities. The
well was drilled and completed with 12¼" hole
to TD. This well set several regional depth,
reach and performance records and is believed to
have set a world record for the longest ERD well
with only 2 casing strings. K&M and Esso were
awarded an Engineering Excellence Award for
the achievement, given the limited rig capability.
At one time, this well held the world record for
ER. Although Wytch Farm is generally not a
good project to benchmark against because of
several unique factors that do not apply to most
ERD wells, it is still a good comparison for the
rig capability used.
Although the final 8½” TD is significantly larger
than the A-29 example, the 12¼” TD’s are very
similar. Given that the 12¼” section is often the
most difficult part of an ERD well to drill, the
two wells provide good benchmarking
comparisons.
WELL DETAILS:
• TD = 6210m MD (20,375 ft).
• Throw = 5249m (17,221 ft)
• 79° dropping to 45° (S-turn profile)
• 17½” was drilled to 1500mMD (4,921 ft), and
12¼” drilled to TD.
• Total days (drill and complete) were 53.4 days.
Total days to 12¼” TD = 39 days.
•
RIG CAPABILITY:
• TDS-4 top drive (38,800 ft-lb.)
• 2 x 1600 HP pumps
• Electrical power = 4500 HP
• 5½” drillpipe with HT-55 connections
• Maximum surface pressure - 3,600 psi
• (flowrate at 12¼” TD was ±700 gpm)
• Drilling fluid = Ester SBM
• Racking capacity = 5,000m of 5½" drill pipe
• Derrick load = 1,000 kips
•
•
•
•
•
•
•
•
•
•
•
•
•
•
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TD = 8700m MD (28,500 ft)
Throw = 8000m (26,250 ft)
+/- 82° tangent section, to horizontal
Includes 2000m (6,500 ft) horizontal section
17½” to 1300m (4,250 ft), 12¼” to 6700m
(22,000 ft), 8½” to TD.
Total time to drill to 12¼” TD 30-35 days.
Additional 70-80 days to drill the 8½” horizontal
section.
TDS-4 top drive
3 x 1600 HP pumps
6000 HP electrical power, with mains power to
supplement if required.
65/8” drillpipe is used for 17½” hole
5½” x 65/8” drillpipe is used for 12¼” hole, (5½”
drillpipe has 60,000 ft-lb. connections)
5½” x 5” S135 drillpipe is used for 8½” hole, (5”
drillpipe has 4½” IF connections, 3½” ID)
Low Tox OBM is used for 12¼” and 8½”
sections.
Racking space for 9,000m (29,500 ft), with 50%
each of 5” and 5½” drillpipe.
Nominal 2.3 million tons mast capacity.
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5.4.1
Hydraulics Capability
It is a general industry standard that at least 1000 gpm is the minimum necessary flowrate
required to clean a 12¼” section on an ERD well. However, it is K&M’s experience that it is
possible to adequately clean 12¼” hole on 70° - 80° wells, with as little as 650-700 gpm, given
good drilling practices and good planning. The ability to clean the hole adequately with these
low flowrates has now been tried and proven on many different ERD projects in locations around
the world.
In order to achieve this, not only do drilling and tripping practices have to be considered, but
everything from bit selection to directional drilling equipment must be designed around
maintaining good hole cleaning at all times.
Note that higher flowrates of 1000 – 1200 gpm are always preferred if possible. However, it is
the author's view that in the case of flow rate, where more is better, a lot more may not
necessarily be a lot better. There have been a number on instances on K&M's recent ERD
projects where a point of diminishing returns seems to be realized with increasing flow rates.
Although only limited evidence can be cited to support this, personal observations of wells that
had higher flowrate capability did not show any significant improvement in performance, despite
very high flow rates. Although, the authors do not subscribe to the theory of high annular
velocities washing out (eroding) the wellbore, there is the risk of ECD induced ‘fatiguing’ of the
wellbore at "ultra-high" flow rates (e.g. >1,200 gpm in 12¼" hole). Certainly, achievable
penetration rates (whereby the hole is kept in good condition with respect to cuttings loading)
seem to reach an optimum level dependent upon mud properties and good drilling practices.
Hydraulics limitations do not necessarily mean that performance is going to be greatly affected.
Techniques have been developed whereby the hole is drilled "efficiently" rather than "fast" and
performance curves for these operations rival (and often beat) those drilled with substantially
more pumping power. This topic is expanded further in a number of sections in this text.
Obviously, more pumping capacity is preferred when designing or selecting a rig for ERD drilling
(either via three rig pumps or two larger pumps). Three pumps may provide a redundancy benefit
over a two-pump system. This becomes particularly relevant in deep 17½” and 12¼” hole
sections. In most ERD wells drilled in the industry today, however, the addition of the third
pump to the rig specifications needs to be justified on an efficiency basis. The global message is
that these wells can be drilled with two pumps, but they can be drilled faster and more efficiently
with three.
However, there are many occasions that a smaller rig capability is desirable. A classic scenario
that K&M has encountered is that the ‘required’ rig capability, based on conventional practices,
proves to be too large and heavy to be economically viable. Often it is not the rig cost that drives
the project economics, but rather the production platform size, and cost that is required to support
the drilling rig.
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5.4.2
Rotary and Hoisting Capability
There is no point in generalizing torque and pick-up requirements in detail. These will be
different for each well design. However, a few generalized observations can be made:
•
Drilling torque is usually at its highest inside of 95/8" casing and in 8½” hole. This is as much
a pipe constraint (stiffness) issue, as it is a pure friction issue (long length of pipe laying on
the low side of hole).
•
Most significant ERD projects utilize a TDS-4S (or equivalent) top drive. Portable units are
now available that put out the equivalent of a TDS-4S (i.e. ±40,000 ft-lb.).
•
The top drive must be capable of maintaining high RPM (preferably 150 - 180 rpm) at the
maximum torque that is expected in the 12¼” section. Step changes in cuttings return are
usually noted at rotary speeds of 100-120 rpm and again 150-180 rpm.
•
The drillpipe should be rated to the same torque limit as the top drive. Several avenues exist
for attaining this goal:
Premium “High Torque” connections.
Use of high friction pipe dope, to increase make-up torque. Wytch Farm utilized this
approach (using Baker’s “Irish Copper” dope) to increase the torque capability of their 5”
API drillpipe, in conjunction with de-rating the drillpipe for tension during this period.
Use of torque reduction subs or Non-Rotating Drillpipe Protectors (NRDPP’s) to reduce
torque.
Use of larger drillpipe (5½” or 65/8" drill pipe). Although this may provide a higher
torque capability, it also has the potential to generate a considerable amount of additional
torque and to increase pick-up loads.
5.4.3
Power Capability
Rig power is one of the most important issues to consider in rig design specifications. The
authors know of at least two ERD wells that have been lost because they were drilled outside of
the rig's power capabilities (not considered during the planning).
It has previously been stated that compromises can be made to rig power and rig pumping
capability if the proper drilling practices are employed. From a rig power standpoint, this means
that the need for backreaming operations must be eliminated from the well plans, as this is
generally the worst case for power load. Many companies use backreaming as the primary hole
cleaning method. If this is the case, then rig power considerations must take this into account. In
general terms, this will mean a 6,000 HP rig for a 6,000m (20,000 ft) well. For most K&M client
wells, backreaming is seen as a last resort and is not allowed for in general operations calculations
for rig power requirements.
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The following formulas are used to calculate the power usage:
FORMULA
ASSUMPTIONS
•
Hookload + Overpull (kips) * ft/min
•
Drawworks (HP) = ------------------------------------------33000
•
•
Flowrate (gpm) * Pressure (psi)
Pump (HP) =
---------------------------------------
•
•
Multiply x 1.1 for 90% efficiency
Hookload - pick-up weight at TD, or string
weight if pipe being rotated
Overpull - add 100 kips if get stuck
ft/min - normal operation 50-100 ft/min
Multiply x 1.1 for 90% efficiency
Pressure and flowrate at TD
1714
2π * Torque (ft-lbs) * rpm
Top drive (HP) =
--------------------------------
•
•
Multiply x 1.1 for 90% efficiency
Torque and rpm at TD
33000
•
Based on the power for rig quarters, lighting
and any auxiliary pumps and equipment
Total Power Usage
•
= (Drawworks + Pump + Top Drive + Auxiliary power)*1.1
•
Multiply by 1.1 to give 10% safety factor
Power (MW) = Power (HP) / 1341
Auxiliary power (HP) = ± 1000 (estimate)
5.4.4
General Rig Capabilities
When specifying a rig to drill an ERD well, the following general rig capabilities also need to be
evaluated:
ISSUE
CAPABILITY
HIGH PRESSURE PIPING
Standpipe Pressure (SPP) is normally limited by pump liner ratings if only
2 mud pumps are available.
• If 3 or more pumps are available, smaller liners can be run, and the SPP
is then normally limited by the pressure rating of the high-pressure
lines.
• Generally require limit ≥ 5000psi
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ISSUE
DERRICK
CAPABILITY (CONT..)
•
•
DERRICK SET-BACK
WEIGHT AND AREA
•
•
SOLID CONTROL
EQUIPMENT
•
•
•
•
Strength of the derrick itself will need to be checked with the extra
loads imposed by drilling deep (i.e. high torque, weight of pipe)
Pipe stuck deep in long ER wells can exceed derrick head height when
drilling with triples. It is essential that the drill string be returned to a
state of tension prior to initiating rotation. This may not be possible
when drilling with triples. A solution to this problem is to drill with
doubles.
Calculate maximum amount of pipe that can be set-back based on area
(finger board restriction) and weight (sub-structure limit)
If insufficient for the length of the well, consideration will have to be
given to drilling beyond the set-back depth with singles or possibly
doubles.
Premium solids control equipment will be required
Most important is 3 or more effective shakers and centrifuge(s) if OBM
is used
Should have a Solids Control Engineer on location to optimize all the
solids control equipment
•
Particularly a concern if OBM is used
Need pit space for transfers, swapping systems and recovery of OBM
Need enough volume for storage of base oil
DRILLWATER
•
Will be an issue for deep surface holes drilled with WBM.
SUITABILITY FOR OBM
•
If OBM is required, and has not been used previously, considerable
work will be required on the rig
This includes sealing the rig floor, mud-vacs, pipe wipers, pit isolations
and cleanout, and the many HSE issues associated with using an OBM,
etc.
Will also need to consider the disposal method for cuttings (i.e. local
regulations for dumping, cuttings re-injection, ship-to-shore etc.)
MUD SYSTEM VOLUME
•
•
•
PIPE DECK AREA
•
•
•
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Need to evaluate if the pipe deck is large enough to handle the required
casing volumes
Worst case generally 9⅝” casing
Suitability of running casing off a boat
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Drilling Design and Implementation for ER and Complex Wells
ISSUE
CAPABILITY (CONT..)
DRILL PIPE
•
The size of the drillpipe used affects almost every part of the ERD well
design (i.e. hydraulics, T&D, setback limits, etc.)
BULK STORAGE TANKS
•
Large cement volumes depending on cement design
Large volumes of barite required to weight up the system.
•
ACCOMMODATION
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•
Extra personnel will be required (i.e. Solids Control Engineer,
additional pit cleaners, additional service companies specialists, etc.)
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5.5
ERD PLANNING – GENERAL REQUIREMENTS
This section is intended to cover the key design aspects of ERD wells that will be important to the
well planning team.
5.5.1
Hole Size Selection
The majority of ERD wells drilled around the world use a combination 17½”, 12¼” and 8½” hole
sizes. The reasons for this include the availability of tools and equipment, ability to drill smaller
contingency hole sizes, and simply the depth of experience in these sizes. The discussions in this
text will concentrate on these conventional hole sizes.
However, there are benefits associated with two-string well designs and 9⅞” hole in particular.
In ERD applications where two casing strings can be reliably used to TD, consideration may be
given to using 13½” and 9⅞” hole sizes (as an alternative to the traditional 17½” x 12¼” x 8½”
design). The smaller hole sizes require less flow rate to keep them clean, or can be cleaned faster
with the same flowrate, thereby allowing for faster penetration rates (9⅞” hole has 50% less
volume than 12¼”). The smaller hole sizes are also inherently more stable, if this is a
consideration. Furthermore, as no intermediate casing is run, ECD’s in the pay-zone are
significantly less.
Utilizing this smaller hole size concept can significantly change the strategies that might be used
on these "production" hole sections. For instance, with the improved hydraulics described above,
the use of a steerable system might be viable if acceptable flow rates can be maintained to TD.
Certainly, higher penetration rates are possible since the hole can be cleaned more efficiently,
which may drive a change to the bit and BHA strategy to take advantage of this.
The downside to using this strategy is that if the hole can’t be drilled to depth or casing doesn’t
make it to bottom, then 3½” or 4” drill pipe will have to be picked-up to continue on in ±6½”
hole.
Another downside to this design is the inability to affect pipe movement during the cement job
(i.e. with a three-string design the liner can be rotated), and therefore, limiting the chance for
successful zonal isolation.
In summary, when designing an ERD well, don’t automatically select the “standard” hole sizes
that have been used in the past, as there may be significant advantages to be gained by
evaluating different hole sizes and combinations.
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5.5.2
Wellpath Design
The wellpath design is critical to the success and optimal performance of any ERD project.
Despite it’s importance, the wellpath design is often given too little thought or is given a lower
than appropriate priority with respect to other key design features. Ultimately, the directional
plan affects every aspect of the well including the aspects listed below:
• Total depth (MD), tangent angle, casing depths
• Directional drilling (technology required and difficulty)
• Wellbore stability, differential sticking, losses due to mud weight requirements
• Hydraulics and hole cleaning
• Torque, Drag and Buckling
• Geological and survey uncertainty
• BHA tripping difficulties
• Casing running and the ability to move the pipe at TD
• Rig capability requirements
• Logging options
• Bit strategy
• Completion and workover design and options
There are several main wellpath design options, with many other variants using a combination of
these. These profiles are shown in Figure 4 and detailed below:
5.5.2.1
Build and Hold Profile
This could be thought of as the conventional design for high angle directional wells. A constant
build rate is used to kick the well off from vertical, building to a tangent angle that is held
constant all the way to the target. Build and hold profiles minimize the total
depth and required directional work, and are a good starting option for an ERD well design.
Several design iterations are usually required before an optimal wellpath is decided on.
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Drilling Design and Implementation for ER and Complex Wells
CATENERY
S-TURN
B&H
COMPLEX
HORIZONTAL THROW
Figure: 4 Typical Well Profile Options
5.5.2.2
Catenary Profile
There has been a trend within the industry to use “pseudo-catenary” directional plans for ERD
wells. Such designs use low initial build rates (say, 0.5°-1.0°/100ft), accelerating to higher build
rates as the angle increases (say up to 4°-5°/100ft). The benefit of these designs is that drilling
torque may be significantly reduced over a build and hold design, which uses faster initial build
rates. Likewise, casing wear is also reduced.
A common misconception in the industry is that catenary profiles will reduce torque and drag
problems. This is not true. Torque problems will be reduced, but drag problems are commonly
made worse depending upon the specific wellpath geometry.
These designs first received widespread recognition after Statoil used them on their Statfjord
ERD project. Statoil used this approach because of a shallow formation that was prone to
instability at high angles. As such, they built angle slowly until they had drilled through this
formation and then built angle at a faster rate to minimize the resulting tangent (or “sail”) angle.
They subsequently observed that drilling torque was reduced. This is mainly due to the
minimization of shallow doglegs, which can adversely affect torque and drag deeper in the
wellbore.
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In the mid-to-late 1990’s, a large proportion of ERD projects have utilized pseudo-catenary
designs. Although often used for good reason, it is the authors view that the technique was used
on some projects without sufficient regard for the downsides or without sufficient consideration
of alternate strategies. One of the downsides of a catenary design is that it considerably increases
both the tangent angle and overall total depth. For a well with 6000m (20,000ft) throw at 2500m
(8200ft) TVD, a catenary design adds about 10° angle and 1000m (3300 ft) to the total depth,
compared to a build and hold design with 2.5°/100ft build rates.
The hydraulics capability is often critical for a drilling rig on ERD wells. Catenary designs tend
to effect hydraulics as follows:
•
The additional total depth of the catenary design makes hole cleaning more difficult due to a
reduction in achievable flow rates if surface pressure and/or ECD’s are limited.
•
Directional control becomes more difficult as a result of a lower achievable flowrate for
efficient use of steerable motors.
•
There is less flowrate available for adequate bit cleaning. Not only does this affect ROP, but
it also limits the choices of bits that can be used.
•
There may be insufficient pressure drop across the bit for adequate MWD signal to surface,
especially if a negative pulse system is being used.
The increased angle of the catenary design may also make wellbore stability more difficult to
manage, which in turn can make hole cleaning unmanageable. It is likely that increased mud
weights will be required for stability at the higher angle. A commonly experienced downside of
the catenary curve is that the higher angle increases the difficulties associated with running (a)
drillpipe into hole, (b) casing/liner, (c) completion tubing or (d) coiled tubing for workovers.
Coiled tubing (CT) access limitations can be far reaching in that later remedial work will be
affected. CT technology, however, has made "leaps-and-bounds" in the past few years with
respect to running in ERD wells.
BP designed their wells at Wytch Farm such that the tangent angle was limited to no more than
82° (critical angle = tan-1 (1/μ) where μ = friction factor). Their experience suggests that coiled
tubing can still be run on remedial/service workovers as long as this critical angle is not exceeded.
Although BP use pseudo-catenary designs to reduce torque at Wytch Farm, the maximum angle
limitation has resulted in their longest reach wells having to build angle quite early. As such
these wells have become more conventional build and hold profiles.
Unless a catenary profile is required for other reasons (i.e. wellbore stability of shallow
formations, inability to build angle in unconsolidated shallow formations, etc.), then all attempts
should be made to use a directional plan that minimizes total depth and maximum angle. A
catenary profile should not be selected just for torque reduction, as there are other ways to
overcome high torque without compromising the overall well design.
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5.5.2.3
S-Turn Profile
The directional plan has to take into account specific requirements of the well (e.g. horizontal
well, or multiple targets). Where well objectives allow, consideration should be given to alternate
designs such as an S-turn profile. Although this may increase the tangent angle, an S-turn does
offer some distinct advantages:
• A reduction in the angle-of-attack into the target, thus reducing the TVD survey uncertainty
impact (although, the lateral survey uncertainty will still be just as significant).
• The effect of geological uncertainty is lessened, again because of the lower angle-of-attack.
With the inherent difficulties associated with deep sidetracks in ERD wells, this becomes a
worthwhile consideration.
• It will reduce the drilled interval in (and below) the payzone, which often proves to be the
most difficult drilling. Not only can the formation be harder and more abrasive, but also
ECD’s and torque will be at their highest. Also, formation instability issues are reduced due to
less exposure time.
• The total depth may be reduced. Although the depth to the target is greater due to the less
direct route, the total depth is often less due to the lower angle at TD.
• Payzone cementing may be made more reliable. If the angle across the pay-zone is kept to
less than ±45°, then the cuttings bed will avalanche to TD. This will reduce the residual
cuttings on the low side of the hole where flowrates are poor and actually make hole clean-up
somewhat easier.
5.5.2.4
Complex 3-D Well Designs
In ERD projects with horizontal wells, complex 3-D profiles are becoming increasingly more
common. Good examples include the Gullfaks project offshore Norway and the Unocal project
offshore Thailand, where multiple and significant azimuth corrections are made at depth, so that
the horizontal section through each objective is aligned in the desired direction.
Obviously, these wells are more difficult than “conventional” 2-D well plans. Nonetheless, such
well trajectories are possible. In fact, when an open, innovative approach has been taken toward
developing design solutions to these complex well designs; the authors have yet to have a target
offered where a well design was unachievable. On a number of occasions, K&M engineers have
been able to design viable well programs where the Operator and/or the integrated service
contractor has felt the well was impossible or highly risky. This type of well is often limited by
available weight on bit to slide drill at depth. Technologies such as rotary steering tools and
"walking bits" have played a role in making the implementation of these designs possible.
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5.5.3
Casing Design
Casing design criteria in ERD wells are the same as those in conventional directional wells, with
the additional considerations as discussed below:
5.5.3.1
Casing Depths
Casing depths will depend on a combination of many different design considerations. These
include:
• Fracture gradient and pore pressure profile, in combination with the required mud weight
profile for wellbore stability
• Completions requirements (i.e. may drive hole sizes and shoe depths).
• Exposure to troublesome formations (i.e. coals, reactive shales, salt domes, etc.).
• Wellpath considerations (i.e. may want to case off build sections, etc.).
• Drilling Fluids to be used in each hole section (i.e. implications on hole stability, torque and
drag, and hydraulics).
• Casing running may require an increased length of casing. For example, on many ERD wells
that K&M has designed, the 13⅜” casing depth is set deeper than normally required in order to
provide a long cased hole interval for running rollers on 9⅝” casing.
• Reach the limit of hydraulics or power in a larger hole size (i.e. generally 12¼”).
• Reach torque limits (i.e. may have to go down a hole size and use smaller drillpipe).
• Reach casing running limits.
• ECD limitations (refer to Section 5.5.3.4 below)
5.5.3.2
Casing Running
Casing running can be one of the most significant challenges in ERD wells. The degree of
challenge will depend on many factors such as the wellpath, length of run, and the friction factors
seen in the hole. The list below provides a summary of the possible methods that can be
evaluated for running casing in an ERD well. Note that each of these methods is covered in detail
in Section 8.2.
• Lighter Weight Casing
• Inverted Casing Designs
• Hangoff Drill collars
• Run Casing as a Liner
• Apply Top Drive Weight
• Top Drive Pull-Down Systems
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• Casing Floatation Techniques
Air Filled (Empty)
Mud Over Air
Air Cavity Technique
Heavy Mud Over Light Mud
Casing flotation has been utilized for getting casing strings into high angle holes since 1989 and
is now a tried and proven technology in the industry. The concept is to lighten the bottom portion
of the string that sits in the high angle section of the well, and to add weight to the more vertical
section at the top to help in pushing the casing to bottom. Various permutations of this
technology have been utilized from heavy mud over seawater to heavy mud over light mud over
air. The design obviously needs to be suited to the application. Collapse issues must always be
given adequate attention when planning a floated casing job. To date, two incidents have been
recorded in the industry where floated casing has collapsed due to dynamic annular pressures.
5.5.3.3
Casing Wear
Casing wear may, or may not, be an increased risk in ERD wells. This will depend on the drilling
practices, the well design and the equipment to be used. In general, a good design and the use of
good drilling and tripping practices will significantly reduce the risk of casing wear in ERD wells
(compared to conventional wells).
The use of high rotary pipe RPM, and potentially very long drilling intervals would suggest that
the risk of casing wear would be increased in ERD wells. However, the following factors act to
mitigate casing wear in ERD wells:
•
The drillpipe tension in the build section, while drilling, is much less than for conventional
directional wells. This is because the neutral point is so far above the bit.
•
Because of the increased focus on torque and drag in these wells, the build section is usually
smoother and of better quality than conventional directional wells.
The Wytch Farm project is a good example of how casing wear can be managed in an ERD well
through use of good practices. Despite drilling at least 2000m (6,600’) horizontal sections over
very prolonged time periods, BP successfully used light-weight 40 ppf 9⅝” intermediate casing,
instead of the more typical 47 ppf casing.
Casing wear can be a significantly higher risk if backreaming is to be used as a standard hole
cleaning or tripping practice. This is because of the high side-forces that occur in the build
section when backreaming.
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The following table details some of the ways of dealing with casing wear in ERD wells:
ISSUE
IMPACT ON CASING WEAR
TRIPPING AND HOLE
CLEANING
PRACTICES
The most important operational and planning requirement for reduced risk of
casing wear is to plan the well such that backreaming will not be required (at
least not until the final trip prior to running casing). Drilling fluids design,
tripping practices and hole cleaning practices need to be engineered so that
backreaming is not necessary.
DOWNHOLE
FRICTION
REDUCTION TOOLS
If used correctly, there are several downhole tools that will reduce drilling
torque and casing wear. These include Non Rotating Drillpipe Protectors
(NRDPP’s) and roller bearing type subs. These are generally placed through the
build section and in some of the tangent section.
DRILLPIPE HARD-
Selection of an appropriate drillpipe hard-banding can be critical in ERD
applications, as long periods of rotary drilling and/or reaming are likely. The
type of hard-banding is the most critical issue. Many Operators have adopted
the use of hard-banding, which is designed to reduce casing wear, as opposed to
reducing the amount of tool-joint wear. This automatically requires that the
hard-banding must be re-applied on a more frequent basis, but the risk of casing
wear is reduced. Hard-banding technology is changing rapidly to improve both
casing wear and tool-joint protection simultaneously, and the final selection will
be based on technical as well as logistical and cost issues.
BANDING
CASING WEIGHT
If casing wear is anticipated, consideration should be given to running heavier,
thicker wall casing, particularly through the build section.
SHALLOW DOGLEGS
A quality drilled surface hole with minimal critical doglegs will greatly reduce
the likelihood of casing wear. One advantage of the catenary well profile is
reduced casing wear, although we would not select the catenary profile on this
basis alone.
RIG POSITIONING
Prior to spudding an ERD well, the alignment of the topdrive and drillpipe over
the centre of the well should be checked appropriately. There are various
electronic and laser surveying methods available, but the final check will always
be the hang of the drillpipe in the hole.
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ISSUE
IMPACT ON CASING WEAR (CONT..)
WEAR BUSHING AND
DITCH MAGNET
These two items are not used for mitigation, but rather to obtain a qualitative
feel for any casing wear that is occurring as the well is drilled. In particular,
metal cuttings from the ditch magnet should be weighed at regular intervals to
note any relative changes.
DRILLING FLUID
The use of OBM will act to lower torque and casing wear. If WBM is used,
liquid lubricants and polymer beads have been seen to reduce downhole torque,
although they only provide temporary relief. Fibrous LCM has proven to be an
effective lubricant in OBM, probably a result of improved hole cleaning with
this additive rather than any actual effects.
MODELING AND
CALIBRATION
Wear models are generally comprised of many unknowns. There value is
limited unless they can be calibrated using actual wear results (from casing
calliper logs) in the same conditions as being modeled.
5.5.3.4
Hydraulics Issues
Wellbore hydraulics can also play a role in casing design where ECD (equivalent circulating
density) needs to be minimized. Running casing strings as liners will allow larger drill pipe to be
used to improve circulation rates, and keeping that larger drill pipe in the larger casing sizes will
also help to minimize ECD's. For example, many Operators have run 9⅝” casing as a liner for
these reasons.
When drilling 8½” hole, ECD’s can be very significant. For example, the slight hole size
increase that comes with using 40 ppf 9⅝” casing instead of 47 ppf casing, from 8.681” to 8.875”,
can sometimes have a significant benefit on ECD’s.
5.5.4
Drilling Fluids Selection
The criticality of the mud system design for ERD wells cannot be understated. The selection of
the proper mud system for the well is often a difficult task. Outside factors such as the number of
wells that will be drilled and rig readiness issues can play a major role in the selection of fluids
for a program.
In general, drilling fluids can be categorized as seawater, Water Base Mud (WBM), Oil Base
Mud (OBM), Lo-Tox Oil Base Mud (LTOBM), Synthetic Base Mud (SBM) and Ester Base Mud
(EBM). There are many different mud types that fall under these categories. Each system will
have its own distinct properties and advantages and disadvantages. As well as the technical
selection issues listed in the following table, the final selection will also be based on issues such
as the cost of the fluid, local environmental legislation, and disposal logistics.
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Although there is a time and place for any given mud system, it is generally the case that a high
quality mud system will be more cost effective than a cheaper mud system for an ERD well (at
least for the high angle section of an ERD well). The selection of a drilling fluid should not be
based on a cost/bbl basis, but rather on a total well cost basis and operational impact. Improved
drilling performance can be expected from a properly designed premium mud system through
better inhibition (gauge hole), better hole cleaning, better weight transfer to bit, better bit
performance (ROP) and trouble free casing runs. Premium solids control equipment will further
ensure that the drilling fluid system maintains its premium properties.
It goes without saying, that a poorly selected drilling fluid that results in hole problems (even
minor ones) will have a significant impact on an ERD well. Do not take shortcuts with the mud
selection.
Critical technical issues that must be considered when selecting drilling fluids are shown in the
table below:
ISSUE
IMPACT ON DRILLING FLUIDS SELECTION
HOLE CLEANING
CAPABILITY
The mud property design, and in particular the rheology, must take into account the
flowrate capability of the rig. The rheology will be heavily dependent upon the
actual fluid used. In general, hole cleaning capability can be attributed to a wellmaintained 6 rpm reading. Target 6 rpm readings should be 1.0 – 1.2 x the hole
size in inches.
HOLE CLEANING
REQUIREMENTS
AND LITHOLOGY
An inhibitive drilling fluid will require better hole cleaning conditions than a
dispersive system. Dispersive systems allow long, large ERD surface holes to be
successfully drilled, despite relatively poor hole cleaning parameters, because the
cuttings are predominately dissolved into the mud. Note, however, that the
lithology must be appropriate if dispersion is to be relied upon as an effective hole
cleaning tool.
WELLBORE
STABILITY
Required minimum mud weight and the inhibitive performance of the drilling fluid
are closely related. In most cases, with improved inhibition the well will require
less mud weight for stability purposes. In essence, the chemical interaction
between the rock and drilling fluid has been minimized and the mud weight is now
only required to maintain the mechanical strength of the rock.
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ISSUE
IMPACT ON DRILLING FLUIDS SELECTION (CONT..)
TIME DEPENDENCY Hole sections are generally open much longer and must be tripped through more
OF FORMATIONS often than on conventional wells. It is, therefore, important that the wellbore is
either maintained in good gauge condition or is allowed to disperse in a mud
making system. Shale hydration is a common problem in the industry that is
amplified in ERD wells. It is important to be able to run with a minimum mud
weight to slow down the hydration process and/or to minimize the chemical
interaction with the wellbore. An invert emulsion (e.g. OBM or SBM) system
keeps the water away from the rock and virtually eliminates the hydration process
if the mud’s activity level is designed properly for the formations being drilled.
WELL CONTROL
This is not only a mud weight issue. Factors such as gel strength properties (which
affect likelihood of swabbing or surging if the mud gels up when static), solubility
of gas into the mud, barite sag and ability to use high flowrates with increased mud
weights must all be considered.
LUBRICITY
In an ERD well, lubricity is not necessarily only tied to “slippery” mud. In fact, if
a drilling fluid is providing better inhibition and keeping the hole gauge, then hole
cleaning will be greatly improved. This will lead to fewer cuttings in the hole,
which will produce lower friction factors. WBM additives are now becoming
commercial and have proven effective at obtaining OBM-like friction factors.
However, these systems are not as inhibitive as the OBM systems, and require
almost continuous additions.
DIFFERENTIAL
STICKING
Differential Sticking performance of a mud system will be a key consideration
when drilling through permeable regions. Generally, the increasing angles
associated with ERD wells lead to increased mud weight, while the reservoir
section is generally much longer due to the high angle of the wellbore. Further,
ERD wells are shallow by their nature, and are commonly under-pressured. This is
critical, given that there is less capability to accommodate further increases in
torque or drag, and there is less available jarring capability to deal with stuck pipe.
Differential sticking can act on BHA’s in degrees. Namely, just because an
assembly is not differentially stuck, does not mean that there is not a degree of
differential sticking acting on the assembly. These forces act to drive the friction
factors in the well up and often play a role in the viability of the hole section.
Selecting the proper fluid and/or fluid additives to minimize the effects of
differential sticking is a key issue in ERD wells.
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ISSUE
IMPACT ON DRILLING FLUIDS SELECTION
BIT BALLING
This affects both drilling and tripping. The mud system’s anti-balling performance
has a dramatic effect on bit and BHA selection, bit hydraulics, rig flowrate
capabilities, tripping capability, well control (swabbing), and hole cleaning risks.
Both glycol and silicate WBM systems have been successfully used for the
prevention and mitigation of bit balling. These products seem to preferentially
attach themselves to steel and have eliminated bit balling in a number of K&M
client programs. OBM is the most effective way to deal with bit balling problems.
Balling is an important issue on ERD wells, because bit hydraulics is often
compromised due to limited rig capabilities. Balling should not only be thought of
as the commonly envisaged “global balling”, but also the “micro-balling” that
occurs at the cutter tips (see Figure 42).
ECD AND MUD
LOSSES
ECD’s are often greatly magnified on ERD wells, both while drilling and while
running and circulating casing. As ERD wells have grown longer and shallower,
ECD’s have begun to play a limiting role in many programs. The shallower the
vertical depth of an ERD well, the more effect the pressure drop in the annulus will
have on ECD. For example, in a 25,000’ (7,600m) vertical well, a 1,000 psi
annular pressure drop would only add a matter of ±0.8 ppg to the ECD. In
comparison, a 25,000’ MD ERD well at 6000’ TVD (2,440m TVD), will
experience a ±3.3 ppg EMW increase for the same annular pressure drop.
In hindsight, the industry has many wells where ECD’s have exceeded 10 ppg
EMW while running casing, which explains the frequent lost circulation problems
that are associated with some hole size/casing combinations. Typical ECD
fluctuations in shallow 8½” ERD wells will run up to 5.0 ppg EMW, unless the
well has been specifically designed to limit ECD’s. The selected drilling fluids
play an important role in managing ECD’s (refer to Section 10)
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5.5.5
Wellbore Stability
Wellbore instability is often more likely to occur, or is likely to be worse on an ERD well. It is
central to all assumptions of feasibility and performance on an ERD well. Hole cleaning, in
particular, is significantly affected by even small intervals of hole enlargement or swelling.
The following are the main reasons for wellbore stability being more of a concern in ERD wells:
ISSUE
IMPACT ON WELLBORE STABILITY
HOLE ANGLE
As the hole angle increases, the over-burden weight is more directly supported by
the wellbore (and mud hydrostatic). Generally, as inclination increases, so does the
required minimum mud weight. However, this is highly dependent upon the
lithology and the tectonic environment. For example, horizontal wells in sandstone
formations often do not require a weighted mud system, while high angle,
intermediate sections through shales and claystones require significantly higher
mud weights relative to low angle wells.
Also, high angles result in longer intervals of troublesome formations being open,
and therefore the likelihood of stability problems is increased. For example, a thin
5’ TVD coal seam will be 29‘ long at 80° angle.
TECTONIC
STRESSES
Horizontal stresses must be understood and managed appropriately. It is not
uncommon for wells oriented in different directions (from an offshore platform for
example) to have different stability requirements. Depending upon the relative
orientation and amplitude of the maximum and minimum horizontal stresses, the
risk of instability will be increased or decreased relative to the well’s azimuth.
Vertical stresses can also play a reverse role in hole stability. For example, when
drilling in areas around the Java Trench, the horizontal stresses often exceed the
vertical stresses. In this environment, it is actually more stable to drill in a deviated
well than it is a vertical well. Once again, however, drilling direction relative to
the horizontal stress orientation will play a role in the required minimum mud
weight for stability.
The value of multi-arm calliper logs, and a well calibrated wellbore stability
model, is invaluable for planning purposes.
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ISSUE
IMPACT ON WELLBORE STABILITY (CONT..)
TIME EXPOSURE
Time exposure is usually greatly increased for ERD wells. Formations that are
relatively benign in low angle wells may be quite problematic in ERD wells
because of the increased time exposure. This is sometimes amplified by more
frequent tripping that often occurs in ERD wells.
ECD’S
Drilling ECD’s can be significant in ERD wells. Long hole sections, or very
shallow sections with small clearance can produce large ECD effects. Wellbore
instability can be induced by constant flexing and relaxing of the wellbore as the
pumps are turned on and off. This must be considered when using high flowrates,
and possibly even high pipe RPM (refer to Section 10).
A good analogy is that of the ‘paper clip’. A paper clip can be bent back and forth
once or twice without breaking, even if it is bent quite severely. It will, however,
break due to fatigue failure if it is bent enough times. The time to failure is
dependent upon (a) how severe the bending is, and (b) how many times it is bent.
It is generally the same with the wellbore and ECD fluctuations. The wellbore will
eventually fail, depending upon the lithology, and the size and frequency of ECD
fluctuations.
TOLERANCE FOR
PROBLEMS
5.5.6
There is generally less allowable tolerance on ERD wells for instability problems.
This is due to the difficulty of hole cleaning, but also because there is less available
rig capability to overcome problems. Further, jarring is often much less effective
due to less efficient weight transfer.
Hole Cleaning
Good ERD performance must be planned well in advance. No matter how good the operations
and service people are, if you do not give them the right tools, then their hands are tied from the
start. For example, the directional drillers can only run and operate the BHA equipment that has
been provided and, as discussed herein, much of the hole cleaning performance and limitations
are directly related to the bit and BHA selection. Likewise, the mud engineers have little scope to
optimize the mud system once the initial system has been built.
The following table presents some of the key planning aspects for good hole cleaning, and each
will be discussed in detail separately in this manual. However, they are listed briefly here to
summarize at least some of the key issues and opportunities for improved hole cleaning
performance.
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ISSUE
IMPACT ON HOLE CLEANING
TRAINING
Training is critical to all aspects of an ERD well, but it tends to be of particular
value when it comes to hole cleaning. Training Engineering and Operations
personnel to look for and deal with the varying aspects of hole cleaning is essential
to the efficient implementation of an ERD well.
It is refreshing to watch a Drilling Supervisor’s eyes light up as he begins to put 2
and 2 together in the training courses. All of a sudden, the tight hole that keeps
recurring inside of casing or the lack of cuttings over the shakers at bottom’s up
begins to make sense.
BIT AND BHA
STRATEGIES
The bit and BHA strategy is one of the most important factors for hole cleaning
performance. Directional strategies must be planned well in advance of spud. The
proposed ‘system’ must be optimized with hole cleaning in mind, and not simply
be left as separate ROP and directional control issues. This is especially true for a
drilling rig that has limitations in pump and rotary output.
Bit and BHA designs play a key role in ERD drilling performance. Based on the
team structure discussed in Section 5.1, the actual design stewardship for these
“systems” should lie with the Sr. Drilling Engineer and not with the bit and
directional companies (although their input is obviously important). The aim here
is to ensure that all aspects of the well operations are considered and optimized in
these designs. Well angle, rotary speed limitations, flowrate limitations, directional
performance, bit utility and overall hole cleaning efficiency must all be considered
in the design.
DRILLSTRING
DESIGN
Consideration should be given to upgrading to larger drillpipe size if the drilling rig
is surface pressure limited. This decision must take into account other issues such
as handling ability, racking capacity, torque and drag, and ECD issues.
The use of “bladed” drillpipe should also be considered for improved hole
cleaning. The integral blades can act to stir up the cuttings bed more effectively.
A number of K&M’s clients have had very good results using this technology.
The HWDP and BHA lengths should be as short as possible for reduced surface
pressures if flowrate is limited. Shorter HWDP and BHA sections also help to
reduce torque and drag, overall. It is very common to run only the required BHA
components for directional control and MWD magnetic protection, along with 2-3
stands of HWDP (which include the jars) for transition back to the drill pipe.
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ISSUE
IMPACT ON HOLE CLEANING (CONT..)
RIG CAPABILITY
Rig capability for ERD is an area of great interest to K&M engineers in that we are
often faced with drilling wells that are beyond the “conventional” capabilities of
the available rigs. When faced with this challenge, it is first important to
understand the actual limitations of the rig and to work the well designs (and
upgrades, if necessary) around those limitations.
The most important aspects of utilizing an under-powered rig for ERD drilling are:
•
Be realistic when modeling hydraulics situations. Hydraulics modeling has a
tendency to be optimistic, working off theoretical loads and capabilities (rather
than realistic ones). For example, when looking up pump liner pressure limits,
the PSV (or ‘pop-off’) settings should be used instead, including allowances for
‘pressure buffers’.
• Upgrade the rig where necessary to overcome insurmountable limitations. In
most cases, this will be the installation or upgrading of an existing top drive or
the upgrade to high torque drilling tubulars. It is not uncommon for 5” drillpipe
to be upgraded to 5½” drillpipe, because of the significant hydraulics
improvement that 5½” drillpipe provides with minimal downside. Upgrading
to 65/8” drillpipe is a more significant issue, given the downsides associated
with such large drillpipe.
• Design the wells to stay away from the rig’s weak points. The most prominent
example of this would be backreaming off of bottom. If a rig is being strained
on power, make sure that the hole stays in good condition so that the hole does
not have to be backreamed (hole size selection, etc.). K&M would also design
the entire bit and BHA, hole sizes, and directional strategies around the
hydraulics capabilities.
If upgrades are impracticable or cannot be justified, then the rig’s limitations must
either be solved or ‘bypassed’ by alternate drilling strategies. At the very least, the
drilling strategies and the well design must reflect the rig’s limitations and be
optimized to operate within these limits.
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ISSUE
IMPACT ON HOLE CLEANING (CONT..)
WELL DESIGN /
CASING / HOLE
PLAN
There are numerous opportunities to optimize a well design that can have a
profound effect on hole cleaning and drilling performance. “Standard” hole sizes
should be considered, but not automatically assumed. Likewise, it must also be
investigated whether a contingency hole size is actually increasing risk (and
therefore forcing you to use the contingency). A more aggressive well design may
actually present less “real risk” relative to a ‘safe’ design, simply because the more
aggressive design is comfortably within the rig’s capabilities.
For example, in one of K&M’s client programs it was shown that an ERD well
could easily and efficiently be drilled in only 2 hole sections if the long tangent
hole was drilled in 9⅞” hole size. If a conventional 12¼” hole size was used to
provide contingency, then a 3rd hole section was almost definitely required to reach
TD. This was because the time-dependent formations were open for much longer,
requiring high mud weights for stability and then the risk of differential sticking in
the reservoir was too high. A ‘slimmed’ hole approach was faster, as well as being
safer than a well design with contingency built in.
The well design process is iterative. The usual completion, workover and
formation evaluation objectives must be met, but the drilling strategies and rig
limits must be included. As new are considered, all related aspects of the well
design must be re-visited to see if it is still optimum.
DRILLING FLUIDS The drilling fluid used is critical to hole cleaning. Refer to Section 5.5.4
SELECTION
WELLBORE
STABILITY
2007 – Third Edition
Wellbore stability will have a significant impact on hole cleaning. Refer to Section
5.5.5
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5.5.7
Torque and Drag Modeling
Several torque and drag models are available on the market and most directional drilling
companies have their own versions. All of the major models that are used actively in the industry
use the Dawson/Moorhead/Pasely (or similar flexible string) algorithms, but each of the models
has their own features. K&M recognized torque and drag as a major issue back in 1989 and
began compiling a database on ERD and horizontal wells beginning with the work at Pt.
Pedernales for Unocal. K&M has since built its own torque and drag model, which offers unique
features for well planning and well surveillance.
The authors favor the K&M System for obvious reasons, as it has been purpose built for use in
ERD and horizontal well planning, and hole condition monitoring while drilling. The system has
been developed over a number of years into an automated discrete data gathering system aimed at
tracking hole condition on a real time basis. Quality gathered torque and drag data is essential for
planning ERD wells.
Torque and drag modeling is now accepted in the industry as being an accurate representation of
what is seen in the field. The Drag Risk Analysis and Buckling Risk Analysis techniques
developed by K&M, are methods of applying various sensitivities to the calculations such as
varying friction factors in open hole, mud weight and WOB etc. When drag is a major limiting
factor in a well (such as in most ERD wells), the Drag Risk Plot can also act as a gauge for how
the well is going relative to critical drag levels. Details of this technique and the procedures for
running the calculations can be obtained from K&M, if desired.
Modeling torque and drag is like modeling anything else...garbage in will yield garbage out.
There is no substitute for carefully gathered field data that can be used in the planning process. It
is difficult (if not impossible) to interpret past field data unless the means by which that data was
collected is known. If good quality data is available, it is important that the data used is for hole
size/drill pipe/casing combinations that will be used on the planned well. The algorithms are
flexible string calculations; therefore the additional stiffness that would come from placing a large
size pipe in a smaller hole in a deviated well will be represented by higher friction factors.
Similarly, a heavily centralized string of casing will have a much higher running friction factor
than that of an un-centralized string of casing due to increased stiffness (and centralizer drag if
bow spring centralizers are used).
K&M strongly recommends that each of the torque and drag parameters (slack off weight, pickup weight and off-bottom torque) be calculated separately using appropriate cased and open hole
friction factors for each. Models that don’t allow for this will require a separate calculation for
each parameter with cased hole and open hole friction factors plugged in for the parameter being
calculated.
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When modeling torque and drag for an ERD well, the following is seen as the minimum work
scope for modeling.
• Slack-off and pick-up weights for the drilling assembly in each hole size
• Buckling of the drillstring when drilling in each hole size
• Off-bottom torque for the drilling assembly in each hole size
• Slack-off, pick-up, off-bottom torque and buckling as required for each casing and liner run.
• Slack-off, pick-up, off-bottom torque and buckling as required for cleanout runs, completion
running and future workover requirements.
Note that the level of detail will depend on which stage in the planning process the modeling is
being done (Refer to Section 5.2). The aim of the modeling is to ensure that each operation in the
well is actually possible, and to identify and design for the key limits.
5.5.8
Directional Drilling Strategy
Directional drilling strategies play a critical role in the success and performance of an ERD
project. Directional drilling practices are integral to minimizing torque and drag and maximizing
the ability to clean the hole.
The main aspect of the directional drilling strategy is the BHA strategy. There are three main
categories of BHA’s that can be run in an ERD well. There are many different options within
each category and there can also be a combination of assemblies from the different categories.
The three main categories are:
• Steerable assemblies (which utilize motors)
• Rotary assemblies
• Rotary Steerable Tools (RST’s)
The main considerations for the selection of these BHA’s is shown in the following table and
discussed in detail in Section 11.
As a general rule, regardless of the drilling assembly that is being used, the amount of rotary
drilling should be maximized at all times. Directional drillers with steerable systems in the hole
seem to have great difficulty with leaving the system alone in rotary mode and only making
corrections when they are “necessary”. Drilling tangent sections of an ERD well using rotary
assemblies with adjustable stabilizers has proven, on numerous occasions, to be more “efficient”
than drilling the same section with a steerable assembly in a single run.
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Drilling Design and Implementation for ER and Complex Wells
BHA
STEERABLE
MAIN CONSIDERATIONS IN SELECTION
•
Allows full directional control (inclination and azimuth)
• Sliding will be come inefficient with poor weight transfer to the bit (buckling)
• Extra tortuosity will be added to the wellpath with frequent slides back to the
“line”
• Hole cleaning will be compromised, particularly in 12¼” hole:
• String not rotated while sliding
• Rotary rpm limited by motor bend
• Hydraulics restriction with 1200 – 1500 pressure drop to be allowed for if a
motor is run
ROTARY
•
RST
•
Generally only have inclination control, though walking bits have been used
effectively in 12¼” hole to allow azimuth control.
• Minimal tortuosity added to the wellpath.
• Numerous hole cleaning benefits:
• string is rotated throughout the drilling process thereby keeping the cuttings
in the active flow regime and moving them out of the hole
• High rotary speed possible at all times (>120 rpm)
Allows full directional control (inclination and azimuth)
• Minimal tortuosity added to the wellpath.
• Hole cleaning benefits as per the rotary assembly
• RST’s are ideally suited for drilling ERD wells. However, there are still two
main disadvantages that have to be overcome – cost and reliability. Their cost
must be commercially justified on a well-by-well basis. Although reliability
has improved in the last few years, this is still an issue in most runs.
Add up all of the above factors and their contribution to drilling productivity and it often becomes
fairly easy to justify leaving the motor out of the string until it is needed for a correction run
(particularly for 12¼” hole).
In many ERD wells a significant direction or inclination change is required at depth so that the
section is drilled along a specific azimuth. The use of a steerable assembly with a rock bit on a
suitably designed drill string to allow weight transfer and ample hydraulics has proven very
effective in this application. Success has also been realized in the combined use of adjustable
stabilizers and “walking bits” to make these corrections.
It is generally easier to make such directional corrections in 8½” hole rather than 12¼” hole. Not
only is the steerable motor more effective in the smaller hole, but also the drill string buckling
tendency will be lower thereby allowing a more efficient transfer of weight to the bit. Hole
cleaning is also more manageable while slide drilling in 8½” hole rather than in 12¼”.
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5.5.9
Negative Weight Wells
Negative weight wells are those wells that are drilled with a long tangent section that exceeds the
maximum critical drag angle. Drilling assemblies will stop sliding into the hole on these wells
and must be rotated to get them into the hole. Also, casing strings will not slide to bottom using
standard running techniques and must be pushed or floated into the ground. Unocal Pt Pedernales
(Platform Irene) drilled the first of these wells in 1989 and developed a number of technologies
for dealing with this phenomenon. The first applications for buoyancy assisted casing (mud over
air), high torque liner systems, torque reducing subs and others technologies were field tested on
this project.
The biggest impact on drilling operations from the negative weight environment is the inability to
slide drill, as weight cannot be transferred to the bit without rotation. The advent of purpose built
walking bits and rotary steering tools (RST’s) will further the capabilities of this type of well in
the future. K&M has been involved in much of the groundbreaking work for this technology and
our engineers hold a number of patents for various tools and techniques for negative weight
drilling and completions.
5.5.10 Drillstring Design
Drill string design strategies play a major role in the ability to drill certain ERD projects.
Complex drill string designs are often required to allow slide drilling at depth, maximize
hydraulics, or to minimize pressure effects on the formation due to annular circulating pressures.
The main drillstring options include 3½”, 4”, 4½”, 5”, 5½”, 5⅞” and 6⅝”.
5.5.10.1 General Drillstring and BHA design
Drillstring design for a high angle wellbore is different than for a vertical or low angle well.
Unlike in vertical wells, it is acceptable for the drillpipe to be in compression when rotary
drilling. Also, the BHA does not have to be designed for the total WOB that will be applied. In
fact, it is generally impossible for the drillstring not to be in compression, regardless of the
drillstring design. The neutral point is often many thousands of feet from the bit (probably just
below the build section).
The BHA should be as short and as light as possible for a high angle wellbore. The drill-collar
portion is generally no more than the motor, MWD and 2-3 drill collars (including non-magnetic
drill-collars) for stability and transition. The stabilization should be minimized, with generally no
more than three stabilizers used.
The HWDP interval should also be minimized. Generally no more than 60-90m (180-300 ft) is
necessary. The HWDP provides transition from the drill collars to the drill pipe and provides a
place to put the jars and hydraulic release sub.
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5.5.10.2 Drillpipe size
The table below highlights the general considerations in selecting the appropriate drillstring size
for various ERD well types:
WELL TYPE
MAIN CONSIDERATIONS IN DRILLSTRING SELECTION
VERTICAL AND
5” drillpipe is generally the standard size for vertical and ‘conventional’ directional
operations. Although 5” drillpipe may be acceptable for these simple wells, K&M
regularly see many of these operations where upgrading from 5” to 5½” drillpipe
would provide significant performance benefits. The primary benefit of 5½” in
these circumstances is improved hydraulics.
CONVENTIONAL
DIRECTIONAL
WELLS
SHALLOW
ER WELLS
MEDIUM / LONG
ER WELLS
2007 – Third Edition
Shallow type ERD wells may be able to use 5” drillpipe, although larger drillpipe
will improve buckling and hydraulics performance. The optimum drillpipe size for
very shallow ERD wells is usually a compromise between buckling and ECD
management.
In general, the use of larger drillpipe in medium-long ERD wells becomes a
performance and/or risk issue unless critical buckling becomes a limiting factor.
Hydraulics is the primary benefit of larger drillpipe. For example, in a 6000m
(20,000’) ERD well, upgrading a 5” drillstring to 5½” is roughly the equivalent of
adding an additional 1600 hp pump to a two-pump system. The improved flow rate
capabilities at depth (until pressure limits are realized) means that the well can be
drilled faster through that section.
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Drilling Design and Implementation for ER and Complex Wells
WELL TYPE
MAIN CONSIDERATIONS IN DRILLSTRING SELECTION (CONT..)
VERY LONG
Very long ERD wells often utilize 5½” or 5⅞” drillstrings, with premium high
torque connections, for the increased torsional and tension requirements and benefit
from the improved hydraulics performance. 5½” drillpipe is the most common
drillpipe used for drilling 12¼” hole, although 5⅞” is becoming more common.
ER WELLS
The use of 65/8” drillpipe in North Sea ERD wells is quite common (primarily for
hydraulics reasons). For many North Sea ERD Operators, it is accepted practice
that 65/8” drillpipe is a minimum requirement. However, it is K&M’s opinion that
the need for 65/8” drillpipe is often a result of the drilling practices and strategies
used, and that 5½” or 5⅞” drillpipe can be successfully and efficiently used for
ERD wells if the drilling practices are optimized. While 65/8” drillpipe does have
obvious hydraulics benefits, the downsides associated with using 65/8” pipe must be
considered. These include:
• Slower connection and tripping times
• Greater setback requirements. Offshore rigs are not usually set up to handle
65/8” pipe other than in the collar fingers
• Higher torque and tension loads, due to the increased weight and stiffness of the
65/8” drillpipe
• Cannot be run in 9⅝” casing
NEGATIVE
WEIGHT
ER WELLS
DEEPWATER
ER WELLS
2007 – Third Edition
If the well is a negative weight type well, then an inverted drillstring (with larger
drillpipe on top of smaller drillpipe) may be required to (a) run in hole without
rotation and (b) allow slide drilling. In some extreme negative weight wells, drill
collars are run above the drillstring in the vertical section of the well. See later
detailed discussions.
Deepwater wells will generally have similar considerations to Shallow ERD wells
listed previously. The main difference will be the increased exposure to buckling
of the drillpipe in the large OD riser. In particular, running of casing and liners
will most likely require the use of HWDP or drillcollars in the landing string to
prevent buckling in the riser.
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5.5.10.3 Other Drillstring Specifications
The following table details some general considerations when specifying drillpipe for an ERD
well.
ISSUE
GENERAL CONSIDERATIONS
PIPE BODY
•
TOOL JOINTS
•
HARD-BANDING
Wall thickness - specify the pipe by wall thickness since nominal weight can be
misleading (e.g. the actual weight of 5” 19.5# drillpipe is approximately 22#).
Note that for new pipe it is also possible to specify the minimum remaining
pipe body wall at a higher tolerance than API (i.e. API is 87.5%)
• Grade - generally G105 for ERD wells, depending on many factors such as
tension required, hydraulics, sour service, etc. G105 is less prone to fatigue
than S135.
• Class - New, Premium or class II (use only premium or above for ERD wells)
• Range - API Range II is the standard length (± 10m / 30’ joints). Significant
advantages will be seen with API Range III (± 15m / 45’ joints) for long ERD
wells or multi-well program (i.e. minimize connections on trips).
Type - must consider torque rating (matched to top drive), ease of make-up and
break-out, durability, etc.
• OD - main considerations are torque rating, fish-ability, and ECD implications
(want to minimize)
• ID - Main impact is hydraulics (want to maximize)
Many different options exist with hard-banding (i.e. type, raised or flush, pin or
box, etc.). The following should be considered in the final selection:
• Maximize tooljoint protection
• Minimize casing wear
• Consider hard-banding durability and ease of reapplication
• Cost and logistics
INTERNAL PLASTIC Internal plastic coating will provide an improvement in hydraulics, but will
generally depend on the Operators experience.
COATING
As a side note, S135 drill pipe is not as ideal as G105 for use in ERD based on the fact that the
pipe is used in compression on a continuous basis. Field experience strongly supports the fact
that S135 pipe will begin experiencing fatigue failures well in advance of G105.
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5.5.10.4 Integral Bladed Drillpipe
Integral bladed drillpipe (hereafter called “bladed” drillpipe) has been used by some Operators to
improve hole cleaning. Bladed drillpipe has been used successfully in the North Sea, with some
Operators reporting a significant increase in cuttings return with a relatively small number of
joints in the string. Bladed drillpipe was originally intended to reduce drilling torque by the use
of low-friction alloys on the blade surface. A notable side benefit has been an improvement in
hole cleaning performance, which in turn helps to reduce torque.
Another benefit observed by some Operators when using the bladed drill pipe has been improved
slide drilling performance. This is a combined result of the cleaner hole and the stiffer nature of
the bladed drill pipe in the string. The bladed drillpipe is quite resistant to buckling, and therefore
may result in improved slide drilling performance.
K&M’s experience with these tools has shown no obvious benefit to the inclusion in the string if
good hole cleaning practices were already in place. A recent well utilized these tools above an
undersized BHA in a backreaming assembly prior to running casing. This is, in the authors view,
the best application for these tools.
5.5.10.5 High Friction Pipe Dope
A practice used on some ERD projects has been to use a high friction pipe dope when making up
5” drillpipe for the 8½” section. This has increased make up torque of the 5” S135 drillpipe by
about 27% to 45,000 ft-lb. using Baker’s “Irish Copper” dope or similar.
The practice has an advantage over increasing the make-up torque using standard pipe dope.
When the connection is made up to an equivalent API recommended torque using high friction
dope (based on the standard unit stress at the critical section, but adjusted for the higher
coefficient of friction), no de-rating of the tooljoint tensile load-bearing capacity is required.
However, de-rating of the tensile capability is required if standard pipe dope is used.
5.5.11 Surveying and Targets
Long intervals of high inclination, combined with ever shrinking target sizes inherent in today’s
ERD wells, mean that surveying technology is being pushed to its limits. In fact, current
surveying technology and practices have been unable to keep pace with ERD advancements.
The following table summarizes the main approaches that can be used to minimize survey
uncertainty on ERD wells:
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SURVEY METHOD
METHOD SUMMARY
MWD SURVEYS
The quality and accuracy of MWD surveys has greatly increased in the last few
years, with the use of computer correction algorithms, and other sag and magnetic
corrections.
GYRO SURVEYS
High accuracy gyros are often run to reduce survey uncertainty on ERD wells.
Quality control of tools, operations and data is critical.
IN HOLE
BP developed the IHR technique, which is now utilized extensively in ERD wells.
This process uses close station gyro readings through a “straight” portion of the
tangent section to generate a correction factor for the MWD azimuth readings.
REFERENCING
(IHR)
IN FIELD
REFERENCING
(IFR)
GEOSTEERING
This takes the IHR process one step further. Localized magnetic variations in the
earth’s atmosphere are monitored on a regular basis (i.e. daily) with these being
factored into correction algorithms for MWD surveys. This can be expensive and
complicated to set up, and is generally only relevant for an extensive ERD
campaign.
The problems resulting from large survey errors can sometimes be overcome with
the use of Geosteering. Geosteering is the use of FEWD tools to guide the
wellpath through the reservoir formations.
5.5.11.1 Targets and Geological Uncertainty
Target size for ERD wells becomes critical when geological uncertainties and survey inaccuracies
come into play. The best approach is generally to get the geologist to deliver a target that is real
and not based on a standard geometrical shape. The target center also doesn’t need to necessarily
be the center of the target boundaries. The more detail supplied with a target (i.e. hard and soft
boundaries, preferred regions, etc.) the better the product the drilling team will be able to deliver
at the end of the day. In general, this approach yields a larger target as well.
Another pertinent point is the orientation of the target. From the perspective of ER, the wider the
target as you approach it, the better. The largest unknown will be the accuracy of the lateral
surveys and the most difficult directional aspect to control will be azimuth. Therefore, the wider
target helps to absorb some of these aspects of the well.
Geological uncertainty is also an issue that must be managed in an ERD well. S-Turn wells, pilot
holes and Geosteering are all methods that can be used to ensure the issues surrounding
geological uncertainty are accounted for in the well design.
Surveying and target issues are discussed in further detail in Section 13.
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5.5.12 Formation evaluation
In many ERD wells, the amount of formation evaluation is minimized due to the difficulty in
obtaining conventional wireline or drillpipe conveyed logs. Although slow, drillpipe conveyed
logs are quite effective, except on negative weight type wells. For negative weight wells,
inverted drillstrings and/or pipe rotation are required to run in the hole to TD, which may
adversely affect the ability to log. Bearing devices are now available for some drill pipe
conveyed logs.
MWD logging (FEWD) is the dominant formation evaluation technique in ERD wells. Although
FEWD technology has advanced significantly in recent years, tool reliability is still an issue. As
such, the logic of running a “one-BHA-to-TD” approach (where a super-combo FEWD suite is
combined with a steerable BHA) is generally not a realistic goal.
Positive pulse MWD systems are generally preferred because of their reduced impact on drill
string hydraulics (i.e. no pressure drop required below the MWD for tool operation). The primary
advantage of negative pulse systems is that higher data rates can be achieved, and tool reliability
may be superior. Higher data rates are not thought to be a significant advantage for ERD wells,
as (a) ROPs at TD are not likely to be very fast, (b) generally the full super-combo suite does not
need to be pulsed in real-time, and (c) the high angle-of-attack means that Formation Evaluation
data can be simplified. If lost circulation is a concern, then the use of negative pulse systems may
be preferred, due to slightly better LCM tolerances. Currently, Sperry Sun is the only major
provider of negative pulse MWD systems.
Regardless of the MWD system to be used, the compressibility of the drilling fluid should be
considered when preparing tools. The signal amplitude on ERD wells can be too low to be
clearly interpreted, despite similar settings being adequate on shallower wells. This is because
the signal’s amplitude is attenuated and lost amidst the background noise with the longer path to
surface. The use of relatively compressible SBM drilling fluids further attenuates the MWD
signal. Often a specially configured MWD tool will be required for long ERD wells.
Specialized MWD drilling tools are often used in ERD wells to enhance drilling performance.
These tools are summarized in the table below.
As a side note, one issue often overlooked by Operators is the ability to get wireline tools down
the drillstring on a high angle wellbore if packed off (i.e. pipe stuck and no circulation). This
is particularly important for the fishing of Nuclear sources if run in FEWD tools. As a
contingency, hydraulic shear-out subs may be run in the string. Alternatively, wireline tractors
have been successfully used by several Operators to get tools down to stuck BHA’s.
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TOOLS
DOWNHOLE
WEIGHT ON BIT
AND DOWNHOLE
TORQUE
(DWOB / DTOR)
VIBRATIONS
MONITORING
SUMMARY
•
Provides a measure of the torque being generated downhole, and the weight
getting down to the bit
• Very useful if deep sliding is required
• Must be calibrated correctly to be of value
• Some Operators use as a means of monitoring hole condition and hole cleaning
•
Generally monitors 3 axis vibrations (axial, torsional, lateral)
• Can be used effectively to reduce vibration induced MWD failures
• Calibration is very important
PRESSURE WHILE • Measures the ECD at the BHA while drilling and tripping
• Important to analyse both time and depth logs to note problems
DRILLING
(PWD)
AT BIT
INCLINATION
•
Calibration again very important
• Sold often as a means of monitoring hole condition and hole cleaning, but not
an endorsed method by K&M
• More beneficial in smaller hole sizes or when ECD limits are critical
•
Depending on the directional company, can be integral part of a motor or run as
a sub
• Very valuable in landing and drilling horizontal sections and geosteering
applications
FEWD CALLIPER • Gives a rough indication of hole size while drilling
•
Can be used to monitor wellbore stability and highlight areas of concern
• Reliability in general is still not good
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5.5.13 Cementing
Cementing in ERD wells has been a big topic with K&M’s clients over the past few years and
significant headway has been made towards understanding and combating the inherent problems
with cementing ERD wells. Some of these problems include:
• Inability to move pipe while cementing
• Viscous mud systems are generally required to drill ERD wells and these are difficult to
remove from the hole without pipe movement
• Flow regimes works against good displacement
• Low side channels due to the inability to displace mud and cuttings
• High side channels due to free water and settling
• Poor centralization as a minimum of centralizers are required to get casing down
• ECD’s may restrict displacement rate
• Limited remedial options
These problems are discussed in more detail in Section 14.
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6
HOLE CLEANING
Hole cleaning is one of the biggest challenges in an ERD well. This is mainly due to the fact that
it is often poorly understood, and Operators attempt to use practices that have worked on simpler
directional or vertical wells that are not suited to what is happening downhole on ERD wells.
It is important to understand what is happening to cuttings that are generated in an ERD well, and
the interaction of these cuttings when drilling, tripping and running casing.
Good hole cleaning performance doesn’t just happen; it must be engineered into the design.
6.1
FUNDAMENTALS OF HOLE CLEANING
The following section attempts to address some of the fundamentals of hole cleaning, which will
act as the basis for the recommended practices in the following sections.
6.1.1
Cuttings Transportation
Hole cleaning can be divided into 3 categories based on the wellbore inclination. As shown
below in Figure 5, the cuttings transport, and therefore hole cleaning strategy, will be quite
different for each inclination range.
0° - 45°
45° - 65°
> 65°
Cuttings Movement With Flow
Cuttings Movement Without Flow
Figure: 5
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In a vertical to 45° degree well, cuttings are brought to the surface by combating cutting slip
velocity, where the cutting must fall thousands of feet to reach the bottom of the hole. Hole
cleaning is simply provided by the viscosity and flowrate of the drilling fluid. When the pumps
are turned off, cuttings are suspended by the viscous drilling fluid, although some settling will
occur with time.
In wells with inclinations in the range of 45° - 65°, cuttings begin to form “dunes”, as the distance
for them to fall to bottom is now measured in inches. The cuttings move up the hole mostly on
the low side, but can be easily stirred up into the flow regime. The most notable feature of this
inclination range is that when the pumps are shut off, the “dunes” will begin to slide (or
avalanche) downhole. This significantly changes the hole cleaning strategy with respect to the
vertical well scenario.
The final inclination range of 65° - 90° presents a different set of operational circumstances.
Here, the cuttings fall to the low side of the hole and form a long, continuous cuttings bed. All of
the drilling fluid will move above the drillpipe, and mechanical agitation is required to move the
cuttings (regardless of the flowrate or viscosity of the mud). Although the challenges associated
with an avalanching dune have gone away, hole cleaning in this environment is actually more
difficult (i.e. time consuming).
Finally, it should be noted that a 45° - 65° well has a portion of its wellbore that falls in the 0º 45° range, and a 65° - 90° well has sections of all three inclination ranges, and all must be
considered in the hole cleaning strategy.
6.1.2
What is Happening Downhole?
To design an effective hole cleaning system, it is critical to understand what is actually happening
in the wellbore. Downhole conditions are often misunderstood in the drilling industry, especially
in high angle wellbores.
As shown in Figure 6, fluid flowpaths and velocities are different in a high angle well compared
to a vertical well. In a vertical well (and in the vertical portion of an ERD well) the fluid moves
freely around the drillpipe. Annular velocity (AV) is a meaningful term since the fluid velocity is
essentially uniform. In a high angle wellbore, the term “AV” is less meaningful, since the fluid
is essentially only moving above the drillpipe where there are no cuttings (without pipe
movement).
This has significant consequences for mud rheology, drilling parameters, and bit and BHA
selection requirements. The only way to get the cuttings into the flow regime is to mechanically
agitate the cuttings bed (i.e. to stir the bed via drillpipe rotation) since the mud is near stationary
on the low side of the hole. Even with pipe rotation in place to stir up the cuttings, the cuttings
movement is effectively a moving beach. If the mud rheology is appropriate, the stirred-up
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cuttings will be lifted into the high velocity fluid where it is carried up the hole until it falls to the
low side again. As stirring continues, the cuttings will again be lifted and carried up hole. If the
rheology is too thin, the cuttings may be easily lifted up, but immediately fall back to the low
side.
Without rotation, the fluid simply moves above the cuttings and hole cleaning is virtually nonexistent.
VERTICAL WELLBORE
HIGH ANGLE WELLBORE
Fluid and cuttings move uniformly in annulus
High Velocity Fluid
Low Velocity Fluid
Cuttings on the low side will not be disturbed by
fluid unless stirred up by pipe rotation
Figure: 6
Fluid Movement in the Annulus
While slide drilling, the annular velocity (AV) of the fluid around the drill collars will likely keep
that region free of cuttings, regardless of the other drilling parameters. However, as the fluid
leaves the BHA, the AV drops considerably. Fluid flow will predominate on the high side of the
hole and the cuttings will quickly fall out around the HWDP. The cuttings will form a “dune”
that builds towards the surface. As it builds, the height of the dune will grow towards the top of
the hole. As the dune grows upwards, the AV above the dune increases, helping to move cuttings
to the front of the dune (see Figure 7).
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It is important to understand and to take this phenomenon into account prior to beginning rotation
following a long slide interval, or any other period where there has not been any rotation. It is
possible to pack-off the hole with the cuttings once rotation begins if the dune volume has been
allowed to grow to a critical size. Efforts should be made to prevent the build-up of large dunes
by regular periods of rotation (on or off-bottom) during long slide intervals.
Cuttings dunes form above the BHA when sliding. As a cutting dune forms, new cuttings are
unable to move past the dune causing it to grow.
Dunes can also form after backreaming or at washouts. Tight hole or pack-off can occur
when the BHA is pulled through a dune.
When rotation is initiated, the dune is disturbed suddenly and pack-off can occur.
Figure: 7
Formation of Cutting Dunes when Sliding
While drilling large hole (171/2”, 121/4” at rotary speeds greater than 120 rpm, the cuttings that are
falling to the bottom of the hole are continually thrown back into the flow regime at the top of the
hole by the stirring action of the pipe. This rotation helps to keep the cuttings moving towards the
surface. However, when the pumps and rotary are shut down for a connection, the cuttings fall to
the bottom of the hole and can begin to slide downhole (45°-65° wells). Dependent upon the
degree of slide vs. rotary drilling, the inclination, and the length of the hole, multiple “beds” can
be moving out of the hole at any one time. As these beds reach the surface, they are often
mistaken as the hole “unloading” or the result of a sweep. In fact, if drilling a hole near the 65°
inclination (where cuttings will slide downhole very slowly) with a steerable assembly, cuttings
flow across the shakers will vary considerably over time.
6.1.3
Systems Approach
Using a “systems” approach towards hole cleaning is vital to achieving optimum performance.
This is especially true for the larger hole sections, such as 17½” and 12¼”, where hole cleaning is
a particular challenge.
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As discussed earlier, using a systems approach means that all operations and design decisions
must treat the entire well as a single system. Specifically, the entire well should be viewed as a
hole cleaning system. This means that all operations and the designs selected for that operation
must be considered to be inter-related. You cannot simply change the bit or BHA, mud system,
or drilling parameters without considering how each of these components affects the others.
The directional drilling strategy must be built around establishing good hole cleaning. This in
turn affects the bit strategy and the FEWD logging strategy. Selection of bit and BHA
components also affects downhole hydraulics and therefore, mud properties. When the
combinations of all elements are considered so that the system performs as desired, then the hole
is being drilled efficiently.
This may sound like "motherhood", but the authors have rarely found a drilling group that isn't
carrying around a basket-full of hog laws that undoubtedly hinder the ideal "systems" approach.
Given a good dose of "challenging the norm" and use of world's best practice, an effective
approach can be formulated. The most difficult hurdle is often convincing management to allow
the changes to take place and then, getting the key service companies to buy into and fully
support these methods.
Following is a list of the main parameters that must be considered in a “hole cleaning system”:
PARAMETER
EFFECT ON HOLE CLEANING
FLOWRATES
The general rule is that flowrates should be as high as practical throughout,
subject to ECD related constraints. Refer to Section 6.1.5.1.
RPM
Pipe rotation is critical to hole cleaning and should be at least 120 rpm in
12¼” and larger hole sizes (ideal range is 150 – 180 rpm). Refer to Section
6.1.5.2.
MUD INHIBITION AND
LITHOLOGY TYPE
The mud inhibition and lithology type affects not only the amount of
cuttings that must be removed, but also it will affect the hole size and shape,
and cuttings size.
MUD RHEOLOGY
The ideal mud rheology can be quite complex for ERD wells. In general, the
6rpm reading should be 1.0 – 1.2 times hole size in inches.
BIT AND BHA STRATEGY This is probably the most important and least appreciated “ingredient” for
achieving good hole cleaning. It directly affects hole cleaning by
influencing flowrates, allowable pipe RPM, drilling practices and drilling
parameters.
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PARAMETER
EFFECT ON HOLE CLEANING (CONT..)
DRILLING AND TRIPPING Generally, practices that may be tolerable in conventional wells cannot be
utilized in ERD wells.
PRACTICES
WELLBORE STABILITY
Hole diameter will affect hole cleaning ability with large washouts acting to
collect cuttings despite the best practices and rig capabilities.
HOLE SIZE
Larger hole sizes will tend to be more difficult to clean due to lower AV’s.
This must also be considered in smaller hole sizes for areas of washout.
DRILLSTRING DESIGN
The drillstring design directly effects flowrates. The drillstring design can
be modified to enhance hole cleaning through improved hydraulics and more
effective stirring-up of the cuttings.
WELLBORE
TRAJECTORY
This will govern the type and location of the different flow regimes that will
be encountered as the cuttings are moved out of the hole
6.1.4
What is a “Clean” Hole?
Every high angle wellbore will have a cuttings bed of some thickness and distribution. Cuttings
beds will form in high angle wellbores, regardless of how efficient the hole cleaning practices are.
How the cuttings are distributed in the hole will dictate the measures that are required to remove
them. Management of the cuttings in the hole is a key to efficient drilling operations.
However, a wellbore does not have to be 100% clean (or free of cuttings) to be “clean”. A
“clean” hole is defined as “a wellbore with a cuttings bed height and distribution such that
operations are trouble free”.
Note that a cuttings bed that is “clean” for drilling is not necessarily the same as that for tripping a
BHA or casing. This is mainly due to the differences in annular clearance seen in these various
operations and also the ability to trip the pipe through the cutting bed. See Figure 8.
For tripping, the hole must be cleaned up further to allow free movement of the BHA through the
cuttings bed. An acceptable cuttings bed height will often depend on the bit and stabilizer design.
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“A CLEAN HOLE FOR DRILLING IS NOT THE SAME AS A CLEAN HOLE FOR TRIPPING”
Drillpipe - Cuttings bed can be
higher for drilling because the
BHA is not being pulled through it
Stabilizers - can have a significant
impact on how clean the hole must
be to trip
Casing - Running casing will require a
cleaner hole than drilling to avoid
ploughing through cuttings beds
Figure: 8
2007 – Third Edition
Bits - a bit with a large junk slot
area will trip more freely than a
heavy set bit
Clean Hole and Cuttings Beds
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6.1.5
How is the Hole Cleaned?
There are two main mechanisms for hole cleaning: Dispersion and Mechanical removal.
Dispersion effectively “dissolves” cuttings into the mud, which allows them to be easily removed
from the hole. There are two requirements for this to happen. Firstly, the formation being drilled
must be soft and easily dispersed. Secondly, the mud system being used must not have inhibitive
properties, which will prevent the cuttings dispersing into mud. In general, dispersion only
applies in large diameter top hole sections that are drilled with low cost WBM.
With Mechanical removal of cuttings from the wellbore, there are many different parameters that
work together to clean the hole (i.e. the systems approach). However, by far, rotation and
flowrate are the two most important parameters for hole cleaning in a high angle wellbore.
Rotation controls the hole cleaning efficiency, while flowrate controls the hole cleaning rate.
6.1.5.1
Rotation
Rotation is the key parameter in hole cleaning efficiency for high angle sections, where the pipe
and cuttings will lie on the low side of the hole. As shown below in Figure 9, without rotation the
active flow area is at the top of the hole over the pipe and cuttings bed. Regardless of the fluid
rheology or flowrate, it is almost impossible to move this cuttings bed without mechanical
agitation. Rotation will provide this agitation, pulling the cuttings up into the active flow area
with a mechanical and hydraulic action. The hydraulic action is due to the “viscous coupling”
effect, which is a function of the viscosity of the mud.
No Rotation
High Velocity Fluid
With Rotation
Low Velocity Fluid
Cuttings on the low side will not be disturbed by
fluid unless stirred up by pipe rotation
Figure: 9
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With rotation of the pipe, cuttings will be pulled
up into the high velocity fluid (mechanically and
also due to the viscous coupling effect)
Impact of Rotation on Cuttings Beds
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The rotary speed used is also critical for effective hole cleaning. As shown in Figure 10 below,
experience on ERD wells has shown a step change in the volume of cuttings coming over the
shakers depending on the rpm used. This graph is not based on a theoretical model, but rather it
is based on actual operational experience in high angle wellbores.
There are at least two distinct hurdle rotary speeds at which step improvements in cuttings return
will occur in high angle wellbore. These occur at 100-120 rpm, and at 150-180 rpm. These
speeds have proven to be quite consistent for different hole sizes (9⅞” through to 17½” hole size),
drillpipe sizes and mud types. Note that these step changes are not always seen in 8½” hole and
lower rpm can be used to effectively clean the hole.
Several Operators have experimented with rotary speeds of up to 220rpm, but little benefit has
been seen over 180rpm.
150 – 180 rpm
Relative Cuttings
Return Volume
100 – 120 rpm
Fine tuning of pipe rpm
from 60-80rpm is generally
not meaningful
Pipe rpm
Figure: 10
6.1.5.2
Cutting Returns Vary with Pipe Rotary Speed
Flowrate
Flowrate is the key parameter to hole cleaning rate. Simply put, the faster you pump, the faster
you move cuttings out of the hole when coupled with ample rotary speed. Field experience
suggests that a “hurdle” exists on the low side of the flow rate numbers, and that a point of
diminishing returns exists on the high side of the number (refer to Figure 11). It is important to
appreciate the fact that as long as cuttings are coming over the shakers, the hole is being cleaned.
Hole cleaning “rate” is then the issue.
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Hole Cleaning
rate at 120rpm
Point of
diminishing
benefits
Hole Cleaning
with no rotation
Relative Cuttings
Return Volume
Minimum
flowrate for
returns
Flowrate
Figure: 11
6.1.5.3
Cutting Returns Vary with Flowrate
Fluid Rheology
Although not as important as rotation and flowrate, the rheology of the mud in the hole also plays
a key role in hole cleaning, and is often difficult to optimize. The mud must be able to suspend
the cuttings in the high angle portion of the hole long enough to move it substantially up the hole.
Further, it must be able to lift the cuttings to the surface in the vertical section of the well.
Given the drilling fluids that are used for ERD wells, it must be noted that YP is largely a
meaningless term for assessing hole cleaning capability. For these wells, shear thinning fluids are
generally used for better low-end rheology. The Fann 3 and 6 rpm readings are a better measure
of hole cleaning properties in the annulus.
A useful rule of thumb for shear thinning fluids is to design the 6 rpm reading to 1.0 – 1.2 x hole
size in inches. For OBM and SBM systems, the goal is to get the downhole rheologies to these
same specifications. Surface values for these systems will vary from product to product.
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If the mud is too thick, it will have the following effects on hole cleaning:
• It will be more prone to channeling up the high side of the hole (see Figure 12), making
cutting removal more difficult (and slower).
• May increase pumping pressures to the point where flowrate has to be reduced.
• May also increase ECD’s to the point where flowrate has to be reduced.
• If the mud is too thin, it will have the following effects on hole cleaning:
• The fluid will lose it’s “viscous coupling” effect and will not be able to move the cuttings as
effectively with rotation
• Cuttings will drop out of the fluid more easily, making hole cleaning slower
LOW VISCOSITY
HIGH VISCOSITY
Low Velocity Fluid
High Velocity Fluid
With high viscosity fluid, the area of high
velocity flow shrinks, and the areas of low
velocity flow increase
Figure: 12
6.1.5.4
Change in Flow Area with Viscosity
Bottoms-up
The term “bottoms-up” is somewhat meaningless for ERD wells, since the cuttings will move up
the hole at a much lower speed than the fluid. To circulate “bottoms-up” prior to tripping will not
clean the hole - it will simply have shifted the cuttings further up the hole. This practice may
create a dune when the cuttings that have moved into the build section are allowed to avalanche
back into the upper part of the high angle section. Usually it takes at least 2, and sometimes more
than 4 times bottoms-up to clean the hole (if ample pipe rotation is applied throughout).
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6.2
GUIDELINES FOR HOLE CLEANING WHILE DRILLING
The issues to discuss regarding good hole cleaning are quite complex and wide ranging.
Essentially, there are planning and practices (implementation) related issues. This section will
discuss the practices related issues. The planning issues (such as well design, bit and BHA
strategies, rig capability, etc.) have been discussed in Section 5.5.6.
Good drilling and tripping practices are critical to ensuring acceptable hole cleaning. The
benefits of a powerful, purpose built drilling rig can be easily negated by poor or inappropriate
drilling practices. K&M is able to cite a number of client wells where good planning and good
practices have allowed “unfeasible” wells to be drilled (often more efficiently than similar wells
with purpose built rigs where less efficient or conventional drilling and hole cleaning practices
were used).
Even with excess rig capacity, drilling a well ‘smart’ can be far more important than utilizing
‘brute force’. Although it is desirable to have a powerful drilling rig with spare capability, many
Operators fall for the trap of relying on this alone to get the well down. In doing so, the many
benefits of a capable drilling rig are defeated and costs and risks are unnecessarily increased.
It is important that all engineering and operations personnel understand that practices for
vertical or conventional directional wells do not necessarily apply to ERD wells. The value in
training personnel should not be under-estimated. The best laid plans come apart very quickly
when inappropriate practices are applied, or inappropriate decisions are made, whether that
decision is made by the driller, tool-pusher, directional driller or the company man.
6.2.1
Drilling Fluids
Refer to Section 5.5.4 for a discussion of drilling fluids selection.
6.2.1.1
Rheology Guidelines
Regardless of the mud type, the overall objective is to maintain a pumpable fluid with low-end
rheologies that are high enough to keep the cuttings moving out of the hole. Although the work
on mud rheologies is ever changing, the use of 6 rpm readings as a primary indicator of hole
cleaning capability and maintaining a low plastic viscosity (PV) for pumpability, are widely
accepted. For WBM systems, maintaining a 6 rpm reading between 1 and 1.2 times the hole size
(in inches) has proven very effective in high angle hole applications. For OBM systems,
temperature and pressure effects must be taken into account. Generally, the 6 rpm reading at the
surface temperature and pressure will run slightly less than 1x the hole size in inches to account
for downhole rheologies that are in the range for WBM.
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6.2.1.2
OWR Guidelines
The Oil Water Ratio (OWR) plays an important part in hole cleaning and drilling performance in
ERD wells. Higher OWR levels are required for ERD wells, compared to vertical and low angle
wells, because of the effect on hole cleaning and flowrates. It is common for vertical applications
to run a system with a high water content (e.g. OWR = 60:40) for reduced mud cost and increased
viscosity. However, a thinner mud, with lower PV’s is necessary in ERD wells (for improved
annular cleaning, improved flowrates, and reduced ECD’s). This necessitates the use of higher
OWR levels of 80:20, or even up to 90:10 as water tends to act like low gravity solids raising the
PV.
6.2.1.3
Low Gravity Solids
Solids in the mud system, and particularly Low Gravity Solids (LGS), are critical when using a
rig with limited hydraulic capability. LGS’s directly impact the PV, and therefore the pumping
pressure. LGS can build up in the mud system to the point where flowrates will have to be
decreased due to pressure limitations. Generally, centrifuging or dilution is the only means of
removing LGS from the system. Premium solids control equipment from the shakers through to
the centrifuges will be critical to keeping the mud system as clean as possible on an ERD well.
Colloidal solids build up will also directly impact the drilling fluids ability to carry cuttings out of
the hole.
6.2.2
Flowrates and hydraulics
Ideally, maximum available flowrates should be used for every section of an ERD well, up to
the surface pressure or downhole tool limits. Other constraints such as ECD considerations may
mean that reduced flowrates are necessary.
Field experience seems to suggest that a point of diminishing returns is reached with escalating
flowrate. For example, 1300 gpm in 12¼” hole is not necessarily much better than 1000 gpm,
whereas 1000 gpm is definitely much better than 700 gpm. This statement is based on experience
where “drilling in the box” practices resulted in similar maximum sustained ROPs regardless of
the flowrate and where the hurdle flowrate of 1000 gpm (in 12¼” hole) has been obtained.
The following table presents K&M’s recommended minimum and maximum (realistic) flowrates
for different hole sizes. The minimum workable flowrate assumes a comprehensive “systems
approach” has been implemented for hole cleaning in the planning and operational stages.
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HOLE
DESIRABLE
MINIMUM WORKABLE FLOWRATE
SIZE
FLOWRATE
17½”
900 – 1200 gpm
800 gpm, with ROP at 20 m/hr (65’ / hr)
12¼”
800 – 1100 gpm
650-700 gpm, with ROP at 10-15m/hr (30-50’/ hr)
800 gpm, with ROP at 20-30 m/hr (65-100’ / hr)
9⅞”
700 – 900 gpm
500 gpm, with ROP at 10-20 m/hr (33-65’ / hr)
8½”
450 – 600 gpm
350-400 gpm, with ROP at 10-20 m/hr (33-65’ / hr)
The following should also be noted with respect to flowrates and hole cleaning:
• Off-bottom surface pressure is usually less than when on-bottom drilling (especially if a PDC
bit and steerable BHA is in use). Hence, higher flowrates may be used when off-bottom and
circulating the hole clean (if pressure limited).
• Bit nozzling should be with flowrate limitations in mind, as well as optimizing bit hydraulics.
The bit hydraulics can use up too much available pressure at the expense of hole cleaning.
Alternately, bit hydraulics can be ignored in the attempt to maximize annular velocities,
forgetting that good hole cleaning is pointless if you can’t drill ahead due to poor bit
hydraulics. Poor bit hydraulics may lead to bit balling, and a balled bit (or stabilizer) makes
tripping through a cuttings bed more difficult and increases risks.
• The bit and BHA selection has a large effect on achievable flowrates in a pressure-limited
environment (refer to Section 11 and 12).
• When discussing the desired flowrates for ERD (say 1000 – 1200 gpm in 12¼” hole, or 800900 gpm in 9⅞” hole), it is not unusual to be told, “Such high flowrates will wash out the
hole”. Many people have concerns that turbulent flow will result in erosion of the wellbore.
This is a misnomer, for several reasons:
For all intents and purposes, with the viscous mud systems that will be used in these wells,
it is impossible to get turbulent flow in the annulus, regardless of the flowrates.
Turbulence may be feasible with seawater across the drill-collars, but otherwise laminar
flow is assured.
Such high flowrates (say, 1000 - 1200 gpm in 12¼” hole) will give theoretical AV’s of
196-235 fpm across 5” drillpipe, 205-245 fpm for 5½” drillpipe, and 231-277 fpm for 65/8”
drillpipe. When you consider that walking pace is 330 – 440 fpm, it is very difficult to
visualize that such relatively slow velocities can erode the wellbore.
Regardless of the theoretical AV’s, the actual fluid velocity immediately next to the
wellbore is essentially zero (i.e. the fluid film in contact with the formation is near
stationary). This is because the fluid is viscous, and the fluid is moving slower near the
wellbore, and faster in the center of the hole (see Figure 50).
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It is clear, however, that hole erosion can and does occur (note that hole erosion should not
be confused with hole enlargement due to other reasons, such as instability or chemical
interaction). Why is this? Most hole erosion occurs at the bit, especially if the bit is
nozzled for high HSI. It has been repeatedly demonstrated that bits with poor nozzle
design and/or high HSI have been responsible for almost all of the erosion that occurs in
the wellbore. Erosion due to AV’s across the BHA and drillpipe is extremely unlikely,
except perhaps in extremely unconsolidated or shallow formations.
6.2.3
Drillpipe Rotation
High-speed drillpipe rotation is critical for good hole cleaning in the high angle portion of the
wellbore. Flowrate alone is ineffective unless the pipe is being rotated fast enough to stir the
cuttings into the flow regime. As discussed in Section 6.1.5.1, the drilling fluid is near stationary
on the low side of the hole where the cuttings reside.
Field experience suggests that there are hurdle rotary speeds that produce step changes in hole
cleaning performance on ERD wells (see Figure 10). This has been clearly verified by cuttings
return at the shakers on many ERD wells. The mechanics of why these hurdle speeds occur is
unclear, especially since relatively constant hurdle speeds have been noted for a wide variation of
hole size, drillpipe size and mud systems.
The following table presents K&M’s recommended drillstring rpm for different hole sizes.
HOLE
DESIRABLE
SIZE
RPM
MINIMUM FOR EFFECTIVE
HOLE CLEANING
17½”
120 – 180 rpm
120 rpm
12¼”
150 – 180 rpm
120 rpm
9⅞”
120 – 150 rpm
100 rpm
8½”
70 – 100 rpm
60 rpm
The following should be noted with respect to pipe RPM and hole cleaning:
•
If pipe RPM is limited by the motor bend, the possibility of increasing RPM when off-bottom
should be considered (since off-bottom stresses are less than when drilling). The off-bottom
loads on a steerable motor are significantly lower and, therefore, the fatigue considerations
may allow for the increased rotary speeds.
•
The need for high RPM should be balanced with ECD and other effects, especially when in
small hole diameters (i.e. < 8½”). Refer to Section 10.1.1.
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• Many ERD wells are successfully drilled with lower pipe speeds (typically 80-100 rpm, for
reduced fatigue on steerable motors). As such, some will argue that the K&M recommended
high rotary speeds are unnecessary. However, to compensate for the reduced rotary speeds,
much greater rig capability is normally necessary. For example, it is common on such
operations that 65/8” drillpipe, and 3 rig pumps is considered to be a minimum requirement to
enable effective hole cleaning. It is K&M’s contention that such large equipment is not
necessary if practices and parameters are set appropriately.
• Care must be exercised when rotating over ±130 rpm in 17½” or larger hole sizes. The large
annular clearance can lead to increased vibration and potential failures in the BHA and
drillstring.
• Patience is the real key to effective hole cleaning. If cuttings are still coming out of the hole,
then the hole isn’t clean yet.
6.2.4
Connection Practices
Connection practices on an ERD well should be different than those used on a vertical or low
angle well. Connections on an ERD well will generally take longer, but these practices will prove
valuable in the overall hole cleaning system.
The recommended baseline connection procedure is as follows:
• Drill down the stand with the current rpm and flowrate
• Pick-up off-bottom and increase flowrate and rpm to their maximum
• Ream one stand out and back in (repeat if the hole is tight)
• Get Off-bottom Torque (OBT) and String Weight
• Shut down the rotary
• Reciprocate the pipe and obtain Pick-up (PU) and Slack-off (SO) weights
• Shut down the pumps and make the connection
The aims of the above connection procedure are to:
• Move cuttings away from the BHA to ensure a trouble free connection
• Condition the new section of hole that has been drilled
• Collect Torque & Drag (T&D) data in a consistent manner
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6.2.5
Monitoring Hole Cleaning Performance
ERD wells that are designed with an effective hole cleaning system must also include adequate
monitoring of hole cleaning performance as the well is being drilled. This process is known as
“Hole Condition Monitoring”, and is basically the real time collection and interpretation of
relevant well data, with the aim of maximizing ROP within the hole cleaning system. The
relevant well data collected can include the following:
• Off-bottom Torque and Drag (T&D) data
• Cuttings returns
• Drilling parameters
• Mud Properties
• Downhole tools (DWOB / DTOR / PWD)
The sections below contain a brief summary of each of these areas, but first an explanation is
given of the concept of “Drilling in the Box”, which is the technique that utilizes the relevant well
data to optimize the ROP.
6.2.5.1
Drilling in The Box
“Drilling in the Box” is simply applying the systems approach used in the planning stages to the
operational phase while drilling. It is a technique whereby drilling performance (i.e. ROP) is
optimized to match the hole cleaning ability of the entire “drilling system”. Given the BHA that
is in the hole, the directional requirements associated with this BHA, and the wellpath objectives,
the ROP is effectively matched to the best drilling parameters that the rig can sustain. Real time
Torque and Drag (T&D) monitoring combined with close observation of cuttings return is used as
the primary tool for ensuring that ROP is not too fast for the system’s capability.
When referring to the “system”, the following parameters are included. Note that these
parameters are constantly changing, and therefore the system is changing, as well. No single
aspect can be treated as independent, as any changes to one aspect will no doubt affect others.
• ROP
• Drilling parameters (flowrate, pipe RPM, percentage rotary drilling)
• Mud type and rheology
• Nature of cuttings (volume, size, shape and ‘stickiness’) will affect how they move up the
wellbore)
• Hole size and angle, both of which may vary with time and as the well progresses
• T&D
• BHA and drill bit design
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For successful implementation of this concept, it is important that all aspects of the “system” are
considered. The schematic below helps to visualize this technique where each parameter and
circumstance forms the walls of the box.
Figure: 13
The “Drilling in the Box” concept.
“Drilling in the Box” is a closed loop feedback approach, for optimizing ROP for a given
situation. The idea is that the bit will be kept on-bottom longer drilling at the best possible speed
for varying circumstances.
But how fast is safe?
Historically, there have been two different schools of thought on drilling ROPs in high angle hole
sections. Some Operators choose to drill at maximum instantaneous ROPs and then perform
remedial hole cleaning operations as required (usually in the form of wiper trips or backreaming).
Alternately, some Operators nominate a “safe” speed at which ROP will be limited to. This
nominal controlled ROP may be based on personal experience, or on published “stuck pipe
school” guidelines.
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There are numerous publications and stuck-pipe training schools that quote maximum
recommended ROPs for given hole sizes and given wellbore angle. Generally, these are based
upon extensive stuck-pipe statistical analysis. Such published data should not be ignored, but it
must be appreciated that this data will be skewed significantly by Operators with inappropriate
drilling practices or poor ERD engineering.
K&M has been working to build a database and to quantify drilling performance and trouble-time
vs. trends in torque and drag and drilling parameters since 1989. The process of monitoring T&D
data (refer to Section 6.2.5.2) has proven to be a reliable way of maximizing ROP and minimizing
stuck pipe occurrences.
It has been K&M’s experience that the best overall footage/day (and therefore cost/foot) is
achieved if hole cleaning is managed pro-actively. Generally, it is much easier and more efficient
to keep the hole clean, than it is to clean up a dirty one.
It is possible to safely drill at relatively high-sustained penetration rates for long, high angle
hole sections if all drilling parameters, practices and strategies are optimized for the drilling rig
capability. Further, it is possible to do so with minimal (if any) remedial action such as
pumping sweeps, stopping to circulate, wiper tripping or backreaming. “Drilling in the box “ is
the technique, which was developed by K&M to achieve this.
The ROP’s quoted below are based on actual experience with a drilling rig of limited ERD
capability. More capable rigs should be capable of even better sustained ROPs if all parameters
are optimized for hole cleaning performance. Every operation will be dependent upon the given
lithology and associated problems, and mud system in use. Note that quoted ROPs are average
instantaneous rates (i.e. connections etc. are not included, although it should be said that
connection times were not excessive because of the high ROPs used).
If drilling parameters and strategies are not based entirely around hole cleaning optimization, then
lower sustained ROPs will likely be required to maintain good hole condition and avoid remedial
operations.
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HOLE
SUSTAINABLE ROP’S WITH LIMITED RIG CAPABILITY
SIZE
17½”
ROP’s of 50+ m/hr (150+ ft/hr) have been sustained with +/- 1000 gpm. It is noted
that in many cases this hole size is drilled with dispersive mud systems. If a highly
inhibitive mud system is in use, then sustained ROP’s of 30-50 m/hr (100 – 150 ft/hr)
may be realized.
12¼”
This is traditionally the most challenging hole size for ERD wells because of it’s
relatively large size, combined with the fact that it is usually a very long hole section
entirely at high angle drilled with an inhibitive fluid.
ROP’s of 60 m/hr (200 ft/hr) have been sustained at 900+ gpm, reducing to about 40
m/hr (130 ft/hr) at 800 gpm. Flow rates as low as 500 gpm have been used to clean
12¼” hole, however, remedial action is often necessary.
9⅞”
6.2.5.2
ROP’s of 60 – 120 m/hr (200 – 400 ft/hr) have been sustained with 850 – 900 gpm.
In most cases there was no hole cleaning limitation because the drillability limit of the
formation was the limiting factor.
Off-bottom Torque and Drag (T&D) Data
Real time T&D monitoring (surface method) involves taking torque, rotating string weight, pickup and slack-off readings at every connection. Note that all readings are off-bottom. This data is
then plotted against predicted trends that are based on previous experience.
If the actual results start to diverge away from the predicted trends, then a hole cleaning problem
may be developing. The combination of this data, and carefully monitored cuttings, mud, and
drilling parameter data can then be used to optimize drilling ROP, and/or to decide what remedial
action is necessary.
The theoretical predictions that the actual data is compared to must be good quality. Not only is
the software model important, but also the input data must be good quality and continually
calibrated with reality. Most importantly, the data must be collected in the same manner for each
data point to ensure consistent, reliable output.
An example Torque & Drag (T&D) monitoring chart is shown in Figure 14.
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Figure: 14
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T&D Monitoring Chart
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It is important to trust the T&D modeling, but it is just as important that its limitations are well
understood. T&D modeling has proven to be an excellent tool for monitoring cuttings bed
build-up, but there are many phenomena that may be occurring, that will not necessarily show
up or that may be misinterpreted. Differential sticking, key-seating and wellbore instability
effects should not be misinterpreted as cuttings build-up. The symptoms are different and their
identification underlines the importance of collecting and interpreting the T&D data in
conjunction with the other relevant well data on an ongoing basis.
A change in the pick-up weight is normally the first indicator of hole cleaning problems. The tool
joints will “plough” through cuttings while picking up the drillstring (see Figure 15). If the
cuttings bed is thin, the cuttings will be moved aside leaving a groove, and slack-off may not be
influenced to the same degree as pick-up.
Tooljoints create additional drag as they are pulled through the cuttings bed.
The drag of the tooljoint is dependent on the bed height.
Torque is not a reliable indicator of hole cleaning, but may respond if the
cuttings bed gets thick enough
Figure: 15
Ploughing of the Tooljoint in the Cuttings Bed
Slack-off weight changes indicate further development of hole cleaning problems. This is due to
the cuttings bed becoming thick enough to re-fill the groove left after pulling the tooljoint through
it while picking up. As the cuttings bed height increases, the effect on slack-off weights will
become more pronounced. Therefore slack-off weight is often used as the key indicator defining
the point at which remedial action is required.
Torque is a secondary hole cleaning indicator as it is not as sensitive to the cuttings bed height
and increased torque can be caused by other problems (i.e. changes to the mud system, hole
geometry, etc.).
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6.2.5.3
Cuttings Returns
Cuttings returns should be checked at regular intervals while drilling. Monitoring both the
volume and type of cuttings coming over the shakers will be invaluable in helping to understand
what is happening downhole.
Cuttings volume will give some indication of how well the cuttings are being removed from the
hole. ROP, flowrate, and whether the assembly is sliding or rotating, should all be taken into
consideration when comparing the volume of cuttings on the shakers.
Attempts have been made to quantitatively measure the cuttings volume coming out of the hole
with the use of cutting weighing devices attached to the discharge of the shakers. The aim of
these tools is to determine the weight of rock coming out of the hole, compared to the weight
being drilled, and thus how clean the hole actually is. There are many assumptions involved with
this method, which make it difficult to use as a definitive hole cleaning tool. However, it can be
valuable information when used in conjunction with T&D and other well data. Other Operators
have attempted a simpler method, involving the collection and weighing of cuttings in a bucket at
regular intervals. Again, this provides a valuable relative comparison.
The shape and character of the cuttings coming over the shakers are also very important. This
information can be used to determine how well the hole is being cleaned, if wellbore stability is
being seen, if the mud is doing its job, etc. The shaker hand is a critical person in the hole
cleaning system, as they will often be the first ones to pick up a change in cuttings character,
which will indicate a change downhole.
6.2.5.4
Drilling Parameters
Drilling parameters (time, depth, BHA, rpm, WOB, ROP, flowrate, pump pressure, etc.) should
be recorded at regular intervals to provide a relative indicator of changes in the system. This data
will prove invaluable in interpreting what is happening downhole. This information should
already be captured by the mud logger or other personnel, but is often not analyzed in detail by
onsite personnel.
6.2.5.5
Mud Properties
Mud properties should also be monitored on a regular basis, with an aim to identify trends (i.e.
changing conditions) rather than actual values. Properties monitored should include weight, PV,
LGS, gel strength, 6 rpm, fluid loss, Chlorides, OWR, etc.
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6.2.5.6
Downhole Tools
Various MWD-based tools have been developed to help monitor hole condition, and in some
cases have also proven to be valuable in monitoring hole cleaning performance. The tools
include:
• Downhole WOB (DWOB)
• Downhole Torque (DTOR)
• Pressure While Drilling (PWD)
Some Operators have chosen to use this technology as a primary hole cleaning tool, whereas
K&M prefers to use these tools as supplementary to the surface-based T&D monitoring method
(refer to Section 6.2.5.2).
Although Operators have had success with both techniques, it is the authors opinions that offbottom data is more meaningful due to the following:
• When using off-bottom T&D data, most BHA, and all bit interaction (both of which vary
wildly and are unpredictable) are removed from the equation.
• The MWD-based method is sensitive to MWD sensor failure, and stabilizer interaction (if the
stabilizer is below the MWD, how do you know if it is not effecting the measurements).
• The MWD-based method limits the directional drilling options (if the correct MWD
equipment is not available) and may also limit which MWD companies can be used.
DWOB / DTORQ Tools
Anadrill originally developed the DWOB/DTORQ tools, which measure downhole loads at the
MWD tool. These tools can provide very valuable information. Several Operators have used
DWOB / DTORQ extensively in high angle drilling to monitor hole cleaning. This is done by
comparing the difference between the surface loads and the downhole loads. When the surface
and downhole loads start to diverge, this is assumed to be due to cuttings loading.
K&M has several reservations for reliance upon DWOB / DTORQ as primary hole cleaning
monitoring tools (instead of surface-based T&D monitoring method). The following are key
issues:
• The DWOB / DTORQ tool relies on being on-bottom (i.e. drilling) to be effective. Hence, the
measurements must account for the variations of on-bottom bit and BHA interaction. With
PDC bits in particular, the comparison of downhole and surface loads can be quite
complicated.
• The DWOB / DTORQ information is generally very complex, and difficult to interpret on the
rig floor in real-time. Also difficult to track trends.
• Careful and frequent calibration of the tools is required, which is difficult in an ERD well.
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• Perhaps the most important limitation of relying on DWOB/DTORQ, is that this tool is useless
when tripping in or out, which is the greatest risk of stuck pipe.
Despite these disadvantages, the DWOB/DTORQ information can be very useful. The DWOB
tool is an excellent way to monitor drillpipe buckling, and is a good way to calibrate T&D and
Buckling modeling programs.
Pressure While Drilling (PWD) Tools
PWD tools are now available from each of the major MWD vendors. Some Operators have
developed this technology to be either (a) their primary hole cleaning measurement, or (b)
supplementary to DWOB measurements for monitoring hole cleaning.
Again, K&M has reservations about using this technology as a primary hole cleaning monitoring
tool, for the following reasons:
• PWD is used to monitor hole cleaning by being able to see downhole-measured ECD increase
as the cuttings bed are building up. This is possible on low angle wells where the cuttings are
supported by the mud. However, at high angles, the cuttings bed is largely supported by the
bottom of the hole rather than the mud.
• With the majority of the fluid flow on the top of the hole, and the cuttings loading taking place
on the bottom of the hole, critical cuttings loading is difficult to see until rotation is started
(which may be too late if ECD’s are a problem, or the well is close to packing off).
• PWD information is even more complex and difficult to interpret in real-time than DWOB
(PWD measurements are affected by flowrate, RPM, rheology, temperature, etc.).
• It cannot be used in real-time to avoid stuck pipe while tripping.
• K&M is a firm believer in the use of PWD for ECD management, but not as a primary hole
cleaning tool.
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6.3
GUIDELINES FOR CLEANUP PRIOR TO TRIPPING
Effective hole cleanup practices are essential to successful and risk-free tripping. It is vital
that the hole is cleaned adequately prior to POH. This does not mean that there should be no
cuttings at all, but simply that the cuttings bed height is sufficiently low and evenly distributed to
allow the bit and BHA to pass through without problems. The advent of the top-drive system has
lead to many Operators choosing not to invest time in cleaning up the hole prior to tripping, since
they have the ability to backream, if necessary. This has developed into a time consuming and
risky practice.
Prior to POH, the hole should be circulated with maximum available flowrate and maximum
allowable pipe RPM while working the last stand on bottom (refer to following Section). Pipe
RPM should be at least above 120 rpm and preferably above 150 rpm for best hole cleaning.
Circulation and rotation should continue until the hole cleans up. The shakers will clean up quite
suddenly when the hole is finally clean. Do not stop circulation after a nominal 1 or even 2 x
bottoms up, as these terms are largely meaningless for hole cleaning in high angle wellbores
(refer to Section 6.1.5.4). Remember that the mud is traveling on the high side of the hole at a
rate much faster than the cuttings moving on the low side of the hole. It is not uncommon that
good cuttings return does not actually commence until after 1 to 2 x bottoms up, and for the
shakers to clean up after 4 x bottoms up (times will vary according to parameters and conditions).
Dependent on the drilling mode, cuttings flow over the shakers may also vary considerably with
time, as the hole is cleaned-up. If a motor assembly is in the hole and periods of slide drilling
have been used, then various “dunes” may exist in the well at any one time. As these dunes are
removed from the hole, it can give the appearance that the hole is unloading. Experience with the
system on the rig will instill confidence in the amount of time the well will take to clean up. The
key is to be patient.
Regardless of the length of time that it takes to clean the hole up prior to POH, it is worth the
investment. Do not stop the hole clean-up if there are still plenty of cuttings coming over the
shakers just because you have already circulated 3-4 x bottoms up (or more). If it takes a long
time to clean the hole up, then be patient and allow it to happen.
If mud volumes are tracked carefully on the rig, then a significant mud loss can be seen as the
hole cleans-up. This phenomenon tends to make mud volume tracking especially difficult in
wells with inclinations greater than 65°. When drilling recommences, pit gains of the same sort
of volume will be observed as the cuttings bed builds-up and displaces the mud.
If there are concerns with undercutting or washing out the hole while rotating and circulating it
clean, the pipe should be reamed up slowly at 30 min/stand and the stand set back. Note, this is
not the same as backreaming as the aim is to fully cleanup the hole before tripping out.
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6.4
GUIDELINES FOR TRIPPING
Tripping practices should be tailored specifically for high angle wells, but unfortunately many
Operators simply utilize the same practices as employed in vertical holes. As the well angle
increases and cuttings beds begin to form, these beds can become quite problematic. If tripping
procedures do not account for this phenomenon, then backreaming through “tight hole” will result
in an inappropriate, time consuming, and often-dangerous operation.
6.4.1
Standard Tripping Procedure
As a general rule, the standard tripping procedures described below should be used for all trips in
high angle ERD wells.
• Cleanup the hole by circulating and rotating for minimum 1.5 x BU and then until the shakers
are clean
Maintain rpm and flowrate at their maximum level (may be able to increase once off bottom)
Rack back a stand every 30 minutes if necessary (if washout or undercuttings are seen in the
formations)
Closely monitor PWD and vibrations with MWD tools (if available)
Expect at least 3-4 x bottoms up to cleanup high angle 12¼” hole
• When the shakers are clean, pull 3-5 stands wet to check hole condition (no rotation or
circulation)
• Pump a slug and POOH on elevators
Record PU weights while tripping out and compare real-time to theoretical drag trends
• If a tight spot is encountered (20 – 40 k lbs overpull), or drag is increasing over the theoretical,
always assume that the problem is cuttings
• RIH until the BHA is clear of the obstruction (3-5 stands)
• Circulate and rotate at maximum rate for 30 minutes
The goal here is simply to confirm if it is a cuttings dune, so as not to waste time if
otherwise
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• Pull up wet through the tight spot without rotation or circulation. If the tight spot has
disappeared, then it was caused by a cuttings pile that has now been moved up the hole.
Return to step 1 and circulate the cuttings out of the hole before repeating the tripping
procedure.
If the tight spot remains in the same place, then it is likely another mechanical problem (i.e.
key seating, ledge, swelling formation). If this is the case, ream through section and try to
eliminate the tight spot. Pull up through the tight spot again without rotation to see if it has
been eliminated after reaming. If obstruction has been removed, pump a slug and continue
tripping out of the hole.
The primary rules for tripping in high angle wells are:
• Always assume that any tight hole or over-pull is due to cuttings (i.e. hole cleaning related)
• Do not assume that cased hole is a safe haven for tight hole avoidance. It is not unheard of for
stuck pipe to occur inside casing, either just inside the shoe or many thousands of feet inside
casing.
• Backreaming should be used as a last resort if a cuttings bed cannot be circulated out. If
backreaming is started, it should be continued until ± 30o inclination before circulating the
hole clean and POH.
6.4.2
Backreaming
Although backreaming may be considered an appropriate practice in vertical and conventional
low angle deviated wells, backreaming and pumping out of the hole are not appropriate practices
for high angle wellbores, when tight hole is encountered, or as a primary hole cleaning tool.
Backreaming and pumping out are not only considered to be very inefficient, but can also be very
risky on ERD wells. Whereas tight hole in vertical wells is likely to be due to wellbore
conditions, tight hole in ERD wells is likely to be due to hole cleaning or cuttings. The behavior
and response of the cuttings bed to backreaming and/or pumping out can be quite detrimental,
with packing off, stuck pipe and/or irreparable wellbore damage the possible results.
The following problems are seen with backreaming in high angle ERD wells:
•
Backreaming cleans the wellbore completely below the bit and BHA, rather than leaving a
small cuttings bed that the bit and BHA can safely trip through. As such, a dangerous
cuttings dune builds up just above the BHA. This dune is likely to be much higher and
thicker than the cuttings bed left from hole clean up. The dune significantly increases the
risk of packing off and stuck pipe. See Figure 16 below.
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Acceptable Cuttings Bed for Tripping – hole is not 100% clean, but the bed height is low enough to
allow easy passage of the assembly without pumps or rotation
Harmless cuttings left below the bit
Result of Backreaming – Hole is cleaned near 100% below the bit, moving otherwise harmless
cuttings to above the BHA. The cuttings form a dune which presents a significant stuck pipe / pack-off
risk unless backreaming is extremely slow. “Pumping out” (no rotation) is even more dangerous, since
there is no rotation to move the cuttings dune away.
Beach or dune is created
above the BHA
Figure: 16
No cuttings bed left in the
backreamed interval
Acceptable Cutting Bed and Backreaming
• If pack-off does occur, there is a high risk of permanent damage to the wellbore below the
pack-off.
A feature of high angle wells that utilize backreaming is that the wellbores often seem to
deteriorate over time, especially if any tight hole was encountered while backreaming. It is
K&M’s suspicion that this may be largely due to the “hydraulic hammer effect” (or “water
hammer effect”), which exposes the wellbore to brief, but extremely large, instantaneous
pressure surges. The ‘hydraulic hammer effect’ is well known to pipeline and systems
engineers and is the primary reason that pipeline valves are designed so that they cannot be
shut-in quickly. In essence, a quick shut-in in a high pressure hydraulic system (such is the
case if the wellbore packs off instantaneously when the pumps are on) causes a brief, but
extremely violent’ pressure wave within the upstream system. This pressure wave quickly
builds upon itself, and is known to burst pipelines and pressure vessels. It is K&M’s suspicion
that even the briefest pack-offs expose the lower wellbore to similar effects.
•
Backreaming can be detrimental for casing wear as high tensions forces in the drillstring are
seen in the build section. Casing wear is generally not a serious concern in ERD, unless
backreaming is used on a regular basis.
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•
Backreaming can also have a significant impact on the fatigue life of the drillstring.
•
High vibrations and shock are often seen on the MWD when backreaming.
•
From a feasibility aspect, power requirements for optimum rig sizing must account for
backreaming expectations. If backreaming is to be a planned part of ERD hole cleaning
practices, then the power requirements must be significantly more than if hole cleaning and
tripping practices are designed to prevent the need for backreaming.
•
Backreaming is a time consuming operation (once it is started it cannot be stopped).
Note that “Pumping out” (i.e. circulating out, without any or insufficient rotation) further
increases the risk of packing off and/or stuck pipe. In this situation, the dune is still being
created, while there is insufficient rotation to disturb and move the dune away from the BHA.
If backreaming is necessary in a high angle well (or any deviated well), the following
recommendations apply:
• There is no application for pumping out of the hole.
• Backreaming should always be performed at maximum allowable flowrate and at maximum
possible pipe RPM. As already described for hole cleaning, there are two critical rotary
speeds, at 100-120 rpm, and again at 150-180 rpm, at which hole cleaning improves
substantially.
• The pulling speed is a critical parameter. Some Operators have theoretical models for
predicting the fastest safe speed that the pipe can be pulled when backreaming. Regardless,
the process needs to be based on surface torque readings by the driller as a means of
determining pulling speed. Typical speeds may be as slow as 10 - 15 min/stand in 12¼” hole.
Be Patient!
• Clean the hole up prior to starting backreaming (min 1.5 x bottoms up then until the shakers
are clean). This will minimize the risk of stuck pipe and pack-off. Also, consider intermediate
clean-up sessions while backreaming out of the hole.
• Always clean the hole up immediately after finishing backreaming – never just POH. This
applies to both cased and openhole. POH after backreaming without cleaning the hole up first
should be done with extreme caution.
• Take special care when backreaming into a casing shoe as the larger diameter rathole below
the shoe may be an area where cuttings will accumulate. Consider extra circulation with
rotation before backreaming into the shoe.
• Consider “turbolizers”, bladed drillpipe or stabilizers in the drillstring to spread the cuttings
load.
• Consider tripping for a smaller and cheaper assembly prior to backreaming. This will allow
high cost MWD / FEWD tools to be laid out, and an undersize bit and stabilizers to be used.
This will reduce the risk of pack-off and stuck pipe.
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6.4.2.1
Guidelines for Back-Reaming through a ‘Tight Spot’
It should always be assumed that any tight spot during a trip is a cuttings-related problem. If
this simple assumption is always maintained, then the number of stuck pipe incidents will be
reduced.
If a tight spot is encountered, the pipe should be tripped back into the hole, sufficiently far enough
to ensure that the BHA is away from the cuttings bed. This usually requires 3–5 stands to tripped
back into the hole. Never commence pumping or rotation while the BHA lies within or near the
obstruction. This can be risky if the BHA is already embedded in a cuttings dune. If the BHA
cannot move down (say, because the bit is on or near bottom), gradually start rotation prior to
bringing on the pumps slowly.
At this point, circulate and rotate at maximum rates for 30 minutes. Turn the pumps and rotary
off, and pull out carefully on elevators (i.e. without pumps or rotary).
If the tight spot has moved up the hole, then the obstruction was cuttings related. The BHA
should then be tripped back into the hole, away from the tight spot, and the hole cleaned up with
high flowrate and maximum rotary speed.
If the tight spot did not move up the hole, then the obstruction may be assumed to be something
other than cuttings alone. It may still be cuttings related (say, a large hole washout that has filled
with cuttings), but probably cannot be cleaned up with normal practices. At this point, careful
backreaming may be necessary until past the obstruction.
If backreaming has been performed, consideration to cuttings build-up ahead of the BHA must
be made prior to pulling out of the hole. Always remember that a potentially dangerous cuttings
dune exists above the BHA.
Also remember that cased hole is not safe haven, and as such, the same tripping and backreaming
recommendations still apply inside high angle casing.
6.4.2.2
Guidelines for Precautionary Backreaming
On occasion, it may be necessary to backream an ERD well for precautionary reasons. This may
be considered in the following cases:
• If the casing or liner run is critical and/or close to allowable slack-off limits.
• Floated casing runs where slack-off weights will be low, and circulation will not be possible
when running the casing.
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Prior to precautionary backreaming, the hole should be cleaned with circulation and rotation until
the shakers clean up, as per previous Tripping Recommendations. There is some danger that
cleaning the hole up prior backreaming may be seen as a waste of time (given that the hole is to
be backreamed anyway). However, the intent of ‘pre-cleaning’ the hole is to get the cuttings
level down to a more manageable, lower risk level, prior to commencing a relatively high risk
operation (i.e. backreaming).
Having cleaned the hole beforehand, the hole can then be backreamed slowly with maximum
allowable flowrates and pipe RPM. On large ERD wells, or where flowrates are limited, it may
be advisable to backream in stages, with several ‘time-outs’ taken to clean the hole up to a safer
level (or at the minimum, to redistribute the cuttings dune away from the BHA).
After backreaming has been performed, never pull out of the hole without cleaning up the hole
above the BHA. It must always be remembered that a potentially dangerous cuttings dune exists
above the BHA. The BHA must be tripped into the hole away from the cuttings dune, and
cleaned up with circulation and rotation until the shakers reach a background level.
6.5
GUIDELINES FOR REMEDIAL HOLE CLEANING
K&M has repeatedly demonstrated in client wells that it is better to stay on bottom at an
optimized ROP (controlled to match hole cleaning performance) than it is to drill in short fast
bursts and then use remedial operations to clean the hole up. It is easier and more efficient to
maintain a clean hole than it is to clean up a dirty hole. High average footage/day is more
meaningful than high instantaneous ROPs.
If practices and parameters are optimized, it is generally possible to drill for very long intervals
without any wiper trips (or any other remedial measures).
However, there may be occasions where some remedial actions will be required. This may be
due to changing conditions (e.g. loss of a pump, deteriorating wellbore condition, poor mud
properties). The use of remedial operations should be used after optimization options have been
exhausted, and should be based on clear T&D and cuttings return trends. Further, the
effectiveness of remedial operations should be closely observed and quantified via T&D
recording before and after the operation.
It is critical that any remedial operations are initiated for the right reasons and that the response is
appropriate. Ensure that the symptoms correspond with cuttings bed behavior and that remedial
operations will be appropriate for hole cleaning. For example, drilling through a reservoir section
may result in some differential sticking acting as drag and erratic torque. Hole cleaning measures
would then prove inappropriate.
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6.5.1
Stop and Circulate
Once changes in the drilling parameters and ROP controls have proven ineffective, coming off
bottom and circulating should be looked upon as the first remedial hole cleaning option. As
already detailed in the hole clean-up guidelines section, this process should utilize maximum
flowrate and pipe RPM.
Remember that achievable off bottom flowrates may be higher than those used for drilling,
especially if pressure limited. Pipe RPM may also be greater than that used for drilling. If T&D
trends return to clean hole values following this procedure, then drilling may be resumed.
Otherwise, a wiper trip may be warranted.
6.5.2
Wiper Trips
Generally, it should be possible to make precautionary and remedial wiper trips for hole cleaning
unnecessary. It has been proven that long, high angle hole sections on ERD wells can be drilled
without wiper tripping, if good practices and strategies are used throughout.
In many cases, a wiper trip should be considered the last resort of ‘standard’ remedial options.
Note that wiper trips for other reasons may still be necessary (e.g. to wipe a permeable zone to
prevent excessive filter cake build up, or a swelling shale interval). However, these are not the
hole cleaning related remedial actions that are being discussed here.
6.5.3
Sweeps
Designing and maintaining an optimum mud system for hole cleaning in ERD wells is a full time
job. If the right parameters are met and drilling practices include high rotary speeds, then the
mud system will clean the hole. Once the mud system design is right, the use of sweeps only acts
to deteriorate the ideal mud properties. Furthermore, the use of sweeps in ERD wells has proven
largely ineffective, regardless of the sweep design. In ERD wells, mud rheology is already
difficult enough to keep within specification, without the detrimental effect of low-vis/hi-vis
sweeps being absorbed into the mud system.
A brief look at the downhole profile in an ERD well (refer to Figure 6) points to the reasons that
sweeps are not very useful. With the fluid flow along the top of the hole, even the most viscous
of pills will eventually allow the cuttings to fall to the bottom of the hole. Furthermore, as the
pipe is rotated and the fluid flow profile takes effect, mixing of the sweep with the drilling fluid is
inevitable. The most common result of pumping a sweep in an ERD well is that it is never
detected at the shakers.
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A further concern of sweeps in ERD wells (in 8½” or smaller hole) is that ECD’s are usually
critical already. When sweeps do work, they seem to bring cuttings back in a very concentrated
amount, which is likely to have a detrimental effect on ECD’s.
On the rare occasions that sweeps do bring cuttings to the shakers, it is unlikely that the cuttings
come from very far downhole. Almost certainly, the cuttings recovered by a sweep came from
the vertical or build section, rather than the high angle section of the wellbore. If it is determined
that a sweep is nonetheless required, the following is recommended:
• Tandem sweeps are suggested, with a relatively small low-vis volume followed by a large hivis sweep. The high-vis sweep may be weighted to improve buoyancy of the cuttings and to
move the sweep closer to the low side of the hole. This approach is intended to cause
turbulent flow (or at least better disturb the cuttings bed) followed by a “catch-all” fluid. The
two pills must be back-to-back to be effective. The low-vis sweep should be large enough to
remain intact.
The recommended sweep should have the following properties:
Low viscosity portion
Volume:
Make-up:
High viscosity portion
Volume:
Density:
FV:
Make-up:
20 – 40 bbls
sea water (WBM) or base-oil (OBM or SBM system)
120 bbls
MW + 0.50 ppg
110+ seconds
Fibrous LCM has been reported to be an excellent hi-vis
ingredient.
• The pipe should be rotated throughout the displacement process. The pipe rotary speed
while the sweep is inside of the drill pipe should be greater than 60 rpm. Pipe rotary speed
with the sweep outside of the drill pipe should be greater than 120 rpm (and preferably 150 180 rpm).
• The bit should be pulled off of bottom as the sweep clears the bit (actual preference is not to
be drilling and adding further cuttings to the system).
• Do not shut down the rotary or the pumps until the sweep is seen back at surface (likely
identified by a density change in the fluid). It is not uncommon for sweeps to be detected at
the surface earlier than expected, since the sweep will tend to ‘channel’ on the high side.
• Sweeps must be coordinated with the directional drillers to ensure that he/she does not drill in
slide mode while the sweep is in the hole.
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6.5.4
Backreaming
As discussed in the previous section, backreaming is a time consuming and risky operation on
ERD wells. It is K&M’s experience that backreaming has applications in ERD, but it is not a
‘general tripping tool’. If backreaming is to be performed as a remedial option due to ‘tight hole’,
then it should only be performed after determining that cuttings are not the problem.
A significant cuttings beach will be created after backreaming, therefore, it is important to clean
the hole up via circulation and rotation prior to POH after backreaming. Use great care when
POH after backreaming an interval if hole cleanup measures are not used, even if in cased hole.
K&M does note, however, that there is a time and place for backreaming. Backreaming may be
necessary for some reasons, such as across a depleted reservoir or through a swelling shale, or
prior to running casing in a very high angle well.
See Section 6.4.2 for detailed backreaming discussion and recommendations.
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7
TORQUE, DRAG, BUCKLING AND VIBRATIONS
In the planning and operational phases of an ERD well, torque, drag, buckling and vibrations are
all key issues that must be planned for, managed, and evaluated effectively in order to be
successful. It is important to ensure that each phase of an ERD well (i.e. drilling, casing,
completion and eventual workover operations) is feasible, with realistic contingency available,
and without incurring excessive over design.
The authors are aware of many ERD wells that have been drilled in the last 5-10 years that failed
to meet their objectives due to a poor understanding of torque and drag, and buckling. These
failures most often manifest themselves in the following ways:
•
High torque, which exceeds topdrive or drillpipe capability (may also result in twistoff)
•
Inability to run casing to bottom (often incorrectly perceived as “hanging up” or cuttings
beds)
•
Inability to slide drill
When these failures have been analyzed, the majority of cases involve ERD wells that have not
been planned and designed with due consideration of torque and drag. Also, “low angle” or
“vertical hole” practices have generally been used in the operational phase.
The following sections discuss the theory behind torque, drag and buckling, followed by the
practical considerations for planning and operations.
7.1
TORQUE AND DRAG THEORY
In a vertical well, torque and drag are not significant as the pipe generally hangs in the center of
the wellbore without contacting the sides (theoretically), and no additional forces are seen other
than the tension/compression in the string. However, in a deviated wellbore, additional forces are
seen due to the contact of the drillstring with the wellbore. These forces generally act in the
opposite direction to the pipe movement. These additional forces are also cumulative, and the
longer the wellbore, the higher the forces will be. The forces on the drillstring in a deviated hole
are summarized in Figure 17 on the following page.
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Rotation
TORQUE
AXIAL DRAG
Contact
Force
String Tension
/ Compression
Weight of
pipe
String Tension /
Compression
String Tension /
Compression
AXIAL DRAG
Contact Force
Rotation
TORQUE
Rotation
Figure: 17
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7.1.1
Torque
Torque is rotational force generated from several sources within the wellbore: frictional torque,
mechanical torque and bit torque. In some cases drillstring dynamics, or vibrations, may also
generate additional torque (refer to Section 7.5). Torque is only seen when the drillstring is being
rotated.
Frictional torque is a frictional force that is generated by contact loads between the drillsting and
the casing or openhole. This would be the only torque generated in a perfectly clean hole when
rotating off-bottom. The magnitude of this component of torque is determined by the following:
•
Tension or compression in the drillstring - The higher the tension the greater the contact
force. Note, as shown in Figure 17 above, in the build section, tension may actually be high
enough to overcome gravity forces and the contact force may actually be on the high side of
the hole. The WOB will also effect the tension in the string and therefore the frictional torque.
•
Dogleg Severity - High dogleg severity will increase the contact forces. This is particularly a
concern shallow in the well where the tension in the string is also high. The effect of high
doglegs is not as critical deeper in the well where tensions are much lower.
•
Hole and pipe size - The clearance between the drillpipe and hole size will affect the contact
forces. A small annular clearance will increase the effective stiffness of the pipe and
therefore increase contact forces.
•
String Weight - Higher string weight (i.e. HWDP) will result in a higher contact force (i.e.
more weight pushing against the side of the hole).
•
Inclination - The inclination of the wellbore will affect the contact force in that higher
inclinations result in a larger component of the string weight perpendicular to the borehole.
However, at very high inclinations the torque can actually decrease, as more of the string
weight is taken by the borehole wall, and therefore the tension in the drillstring and associated
contact force, will decrease.
•
Lubricity or friction factor - Lubricity is largely controlled by the mud and formation type.
Mechanical torque is generated by the interaction of the drillstring and BHA with cuttings beds,
unstable formations (sloughing or swelling) or differential sticking. It is also regularly seen with
BHA components having excessive interaction with the formations (i.e. undergauge bits causing
drilling on the stabilizers, spiral hole, etc.)
Bit Torque is a direct result of the interaction of the bit and the formations being drilled. The
resulting torque will depend heavily on the bit design with PDC’s generally generating more
torque that tri-cones. Downhole Torque (DTOR) subs are the best means of determining the
torque at the bit. It is critical that bit torque is included in torque estimates for determining
equipment specifications in the planning phases of an ERD well.
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7.1.2
Drag
Drag is an axial force generated in a similar manner to torque (i.e. higher contact forces, the
higher the drag), and basically takes the place of torque when drillsting rotation stops and the
pipe is moved in an axial direction only. As with torque, there is a frictional component as well
as a mechanical component. Drag will always operate in the opposite direction to that in which
the drillstring is being moved.
7.1.3
Friction Factors
In an ERD well environment, a friction factor really isn’t purely a friction factor at all. It is more
of a “fudge factor” because it is used to account for a number of things in addition to friction,
including:
•
Mud system lubricity
•
Stabilizer and Centralizer interaction
•
Pipe stiffness
•
Differential sticking
•
Cuttings beds
•
Dogleg severity (known and hidden)
•
Key seats
•
Hydraulic piston effects
It is important to note that slack-off, pick-up and torque friction factors are not the same, although
they might appear to be so in nature. Often, the industry will only publish a single friction factor
for a given hole section. In fact, most torque and drag models only allow for the entry of a single
cased hole and single open hole friction factor. To accurately model torque and drag, separate
friction factors are required for slack-off, pick-up and torque.
The majority of torque and drag prediction software models the string as a “flexible member”
where pipe stiffness is not accounted for (i.e. soft-string model). The string is modeled as a string
or cable that is capable of carrying axial loads, but not bending moments. In this case, the pipe
stiffness is accounted for by increased friction factors. Hence, casing will have higher friction
factors than will the more flexible drillpipe. Further, large OD drillpipe will have larger friction
factors than will smaller OD drillpipe. It is important to remember that friction factors are not
necessarily inter-changeable between software programs. The non-dimensional friction factor
that is calculated by one software program may be different for other programs.
Furthermore, it is important that the software is well calibrated with field results, and that the
program user is not only familiar with the software, but also the realities of drilling, casing and
completion operations.
For slack-off, in particular, there are other phenomena that must be understood when analyzing
what is really happening down the hole. Casing strings tend to ‘plough’ into the wellbore when
running through a build and turn section (see Figure 18 below). This should not be confused with
friction-related ‘drag’. Ploughing will most likely happen as the shoe moves through a build or
turn section, especially when deep in the well at high angles. The ploughing will vary, dependent
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upon the centralization of the shoe track (refer to Section 14.9), hole size and the dogleg severity.
Once the shoe-track has past the build or turn section, then the surface weight will resume along
more expected friction factors.
Stiff casing shoe tracks will ‘plough’ into the side of the
wellbore in high angle build/ turn sections.
The centralization of the casing shoe is critical to over
come this.
Predicted slack-off
weight if friction
force alone acts on
casing string
Negative
Weight
Positive
Weight
DEPTH
Actual slack-off
weight.
See the ploughing
effect at this point
Builds and
turns to
horizontal
SURFACE TENSION
Figure: 18
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‘Ploughing’ Effect of Stiff Shoe Tracks
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7.1.3.1
Planning Friction Factors
Like any offset data, it is important to ensure that the data is relevant. It is not advisable to use a
friction factor for planning assumptions unless the background of the information is understood.
As a minimum, the following must be asked of any offset friction factor data when planning an
ERD project:
1. Are the quoted friction factors relevant for the software model that you are using? Different
models use different algorithms, and therefore the resulting friction factors may not be the
same for each model.
2. Were the drilling fluids the same?
3. Is the lithology the same? Different rocks have very different friction factors. For example,
clay can have exceptionally low friction factors, while limestone or sandstone can have quite
different values.
4. If drilling in a reservoir section (for example, in a horizontal well), has the over-balance
pressure and subsequent differential sticking forces been considered? Differential sticking
will show up as increased friction factor.
5. For casing runs, is the centralization similar? Friction factors are quite sensitive to casing
centralization type, placement frequency and overall number.
6. How valuable is the offset data? Shallow and low angle wells (or sections thereof) often
produce spurious and unreliable data. This is because the accuracy that the driller can read
the weight or torque indicator is much less than that required to provide meaningful results.
Furthermore, are the open hole friction factors based on a significant open hole interval, or
simply a short open hole section below a very long cased hole interval? Again, the data can
be misleading.
7. Were lubricants in use?
8. How good was the offset hole cleaning ability? A clean hole will have lower friction factors
than will a dirty hole.
9. Is the drillstring or casing diameter similar?
10. Friction factors back-calculated through a flexible string model from gathered field date are
only indicative of those that should be used for planning purposes. Planning friction factors
must be back-calculated using actual data in a “planning model” (i.e., model with a smooth
wellpath).
Once all of this data is taken into consideration, it is still advisable to obtain the raw data from
the offset wells and to process it to come up with friction factors from the model that you will
use for planning.
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7.1.3.2
Sensitivity Analysis
Minor variations in friction factors on an ERD well can have a major impact on the resulting
torque and drag. In planning, it is critical that sensitivities are analyzed to ensure that acceptable
and realistic contingency is allowed for in the design.
K&M uses the “Drag Risk Analysis” (DRA) technique to best account for possible friction factor
variations. Similarly, Torque Risk Analysis is also performed when necessary. An example
DRA is shown in Figure 19.
Drag Risk Analysis plots should be prepared for any casing or liner run where drag is of concern,
as well as when planning drillstring and BHA strategies for tripping and sliding. It is important
that any drag analysis looks at the entire trip in the hole, rather than simply at snapshot at TD.
It should also be noted that buckling and drag are not independent, and that any buckling will
increase drag over-and-above the usual friction.
Sensitivity analysis should also consider the following parameters which can vary while drilling.
•
Mud weight - Higher mud weights will generally lower torque and drag as buoyancy of the
drillstring or casing is increased (i.e. lower contact force). Sensitivities should be run at lower
mud weights than those expected, as losses or other reasons may force this lower weight to be
used.
•
Wellpath - Minor changes in the wellpath can have a significant impact on the torque and
drag. For example, if the wellpath falls behind the plan in the build section, this will generally
require an increase in the tangent angle to hit the target. Depending on the well length and
design, this increase in inclination may add significant extra drag, and if a very high
inclination well, negative weight conditions may now become an issue (i.e. cannot slide).
•
Hole Profiles - Casing points may change as the well is drilled (i.e previous string fails to run
to bottom). Sensitivities should be analysed to see how dependent a particular operation is on
the length of cased and openhole. This is often the case for long 9⅝” casing runs, in which
the success of the run is dependent on having an adequate length of 13⅜” cased hole for roller
centralisers to be run.
•
Drillstring – Any changes to drillstrings or casing strings (even minor) should not be made
without first analysing the impact on torque, drag and buckling.
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Figure: 19
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Example Drag Risk Analysis (DRA)
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7.1.4
General Torque and Drag Definitions
•
String Tension – Often referred to as the rotating off-bottom (ROB) tension, this is the
weight of the drillstring in the hole without drag added (i.e. measured when rotating). If the
weight of the traveling blocks is added, this is known as the ROB weight, and is what is
measured on the weight indicator on the drill floor.
•
Pick-up Tension – This is a measure of the weight of the string in the hole plus the additional
drag (no rotation). Referred to as the pick-up weight (PUW) if the weight of the traveling
block is added.
•
Slack-off Tension – This is a measure of the weight of the string in the hole minus the
additional drag (no rotation). Referred to as the slack-off weight (SOW) if the weight of the
traveling block is added.
•
Off-bottom Torque (OBT) – This is a measure of the torque when rotating off the bottom of
the hole (i.e. removing bit torque component)
7.2
WELLPATH DESIGN
As discussed earlier, there are various wellpath design options for a given ERD project. Each has
distinct advantages and disadvantages that must be considered.
The wellpath has a strong effect on the torque, drag and buckling performance on a well. To
perform extensive and detailed torque and drag optimization without optimizing the wellpath is
analogous to building a house on a bad foundation. There are many constraints that a wellpath
trajectory must comply with, but if there is any design flexibility available, then it should be
optimized to reduce torque, drag and buckling problems.
Shallow ERD wells have very limited scope for wellpath optimization. Generally, the build
section must be completed as fast as is reasonably possible. The shallow formations are often
quite unconsolidated, limiting the achievable build rates.
For many ERD projects, the tangent angle is a critical angle for completions, workovers and
wireline work. Some Operators set maximum angle limits, to maintain wireline access.
Depending upon wireline experience, this may limit the maximum angle to 65° - 70°. Many
Operators set a maximum angle criteria based on Coiled Tubing access. This critical angle is
generally closer to 80° - 82°. In these situations, if the well is to proceed, the build section is then
designed within these limitations.
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7.2.1
Catenary Well Profile
The benefit of a catenary design is that drilling torque may be reduced over a build and hold
design with faster initial build rates. Likewise, casing wear may also be reduced. However, a
catenary profile will add a significant amount of extra length and increase the well angle
compared to a build and hold design.
It is a misnomer that catenary designs reduce drag. Drag problems are generally increased,
depending upon the well dimensions. The longer build section provides additional surface
weight, but is offset by the higher angle tangent section. As such, there will come a cross-over
point after which the catenary profile will increase drag problems compared to a build and hold
design. Given that most ERD wells involve high stepout, it should be assumed that a catenary
design will increase drag.
There are other significant downsides associated with a catenary profile that must be considered
(see Section 5.5.2.2).
7.2.2
S-Turn Profile
S-turn profiles have proven to be the design of choice in a number of K&M client wells.
Although their tangent angle is higher than a conventional build and hold profile, the drop into the
target provides some major benefits as detailed in Section 5.5.2.3.
An S-turn profile has some torque and drag-related issues that must be allowed for during the
planning process. The build section is usually more aggressive and the tangent angle is higher
than a build and hold design. The most critical portion of the well profile from a drag perspective
is at the drop point at the end of the tangent section. Once the well begins to drop into the target,
weight will be regained to assist with getting the string into the hole and/or applying weight to bit.
Also, torque and pick-up weight are generally adversely affected by the drop sections of these
wells. Torque can be managed through mechanical and chemical (mud additives) means. The
increase in pick-up weight is a function of the profile itself, and must be modeled carefully in the
planning process.
These phenomenons can be very deceiving when planning a well. It is critical that a full DRA is
performed for the entire set of well operations, rather than simply checking a snapshot of the
tension and torque at TD of each section. This is because the string (drillstring, casing or
completion) may be negative weight in the tangent section, and yet will have ample surface
tension at TD (see Figure 20).
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Predicted slack-off
weight
Negative
Weight
Positive
Weight
String will not run in hole
below this point
DEPTH
Tension increases as the
string enters the drop section.
Snapshot at TD would show
there is ample tension
SURFACE TENSION
Figure: 20
7.2.3
Drag Profile on S-Turn Well
Complex 3-D Well Designs
Complex 3-D wells are becoming more common in the industry. These wells often have a
horizontal section that is oriented in a specific direction (often won’t be aligned with the heel in
line with the surface location) for optimum production performance.
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Experience gained on K&M client wells has shown that significant turns deep in the hole have
increased torque and drag over what would be expected to occur for a build-and-hold section at
the same point. In particular, casing string drag has been seen to increase substantially when
running through a deep “turn” dogleg. This appears to be due to the way that the casing ‘ploughs’
through a turn. Although some ploughing also occurs through a build-only section, gravity is
acting to help bend the casing in the same direction as the wellbore’s build (assuming that the
casing has been centralized correctly for this situation). However, in a turn the casing may be
effectively ‘stiffer’ since it is bending both vertically (due to gravity and centralization) and
laterally. If a combined build and turn occurs, then the pipe will appear to be stiffer, again. This
stiffness manifests itself as increased running friction factors, or drag.
Effectively, this means that planning process must allow for more contingencies, and that pipe
centralization must be carefully planned.
3-D wells inherently require significant downhole sliding to incorporate the deep build and turn
sections (unless Rotary Steerable Tools are used). The turns are often made in 12¼” hole so that
the heel is correctly oriented for the entire 8½” section. Alternate hole sizes should be considered
for feasibility and/or performance reasons. Large turns are more easily achieved in 8½” or 9⅞”
hole size, rather than 12¼”, due to the drill string being more confined and smoother transfer of
weight to bit. Drillpipe buckling in these sections is also much harder to manifest, so drilling
performance is improved.
Bit, BHA and drag risk planning should be comprehensive for these wells to ensure that adequate
weight is available to make deep corrections. The use of tapered drill strings for improved
hydraulics and buckling performance can also affect the casing designs, etc. Once again, the
“systems” approach to planning is essential to the success of these programs.
7.3
KEY WELL INTERVALS FROM A TORQUE, DRAG AND BUCKLING VIEWPOINT
The following sections will break an ERD well into each hole interval and examine the unique
problems and circumstances that typically arise.
7.3.1
Shallow Build Section
The build section is the most critical interval on an ERD well. If torque, drag or buckling are of
concern deeper down, the fate of an ERD well is largely determined by the end of the build
section. Shortcuts should not be taken in the build section in the name of efficiency or ROP,
unless it can be shown that the ‘big picture’ issues are still being managed. The build section is
usually further complicated on offshore platforms or remote drilling pads by collision avoidance
issues.
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The build section directly and indirectly affects an ERD well in the following ways:
• The rate of build and the ability to adhere to the planned section directly affects the tangent
angle. The inability to adhere to the planned section will primarily affect drag, but may also
affect torque and buckling dependent upon the methods used to regain section.
• The build section itself has a significant effect on the total surface torque. This is due to the
fact that the highest pipe tension in the drill string occurs where the dogleg severity (DLS) is
often at it’s worst (it is for this reason that catenary profiles are effective at reducing torque).
Not only is the actual DLS important, but the overall tortuosity is critical as well (cumulative
DLS).
• K&M has demonstrated on a number of client wells that torque and drag are directly affected
by the slide drilling practices in the build section. Minimizing “hidden” doglegs by breaking
the slide intervals into the smallest practicable lengths, has proven to reduce casing running
friction factors by as much as 30%. For example, if it is necessary to slide 60ft and rotate 33 ft
per 93ft stand, then this should be broken up into 6-10 ft slide intervals, with the required short
rotation period in between each slide. This method will be less efficient due to having to align
the tool face more often, however, the overall performance on the well will likely be improved
due to lower torque and drag in the lower section of the well.
It is noted that a perfectly smooth build section would be achieved by 100% sliding (assuming
that the tool face is always high side), with a steerable motor and a small bend. This is fine in
theory, but impractical in reality. Invariably this will lead to significant hole cleaning
problems. Further, if these BHA’s are unable to achieve the designed build rates, then the
build falls behind the plan, which will increase the tangent angle and the doglegs required to
regain section.
The ideal BHA (bent housing) for achieving a desired build section will have the capability
of achieving about twice the required build rate.
• Casing wear can be an issue on ERD wells in the build section. The tortuosity of the build
section will have a direct effect on the severity of casing wear.
Several K&M client wells have monitored and attempted to quantify casing wear. This is a
qualitative process at best, but helps to raise the awareness of the issue. A single ditch magnet
in the possum belly of the shakers that is cleaned and the shavings weighed on a regular basis
can help to produce a graph of pounds of shavings per rotary hour.
•
Depending upon the well design, buckling can be at its worst in the vertical section of the
well just above the build. The vertical portion is most prone to buckling if in compression and
is especially prone to buckling in the larger diameter hole. The build section itself is actually
one of the least likely areas in the well to have buckling problems (see Section 7.4.2).
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7.3.2
Tangent Section
Doglegs in the tangent section are generally small compared to the build section. However, the
overall length of the tangent section means that significant cumulative tortuosity can be
developed in this interval.
The following observations are made:
•
The ‘period’ or frequency of any tortuosity is important in this section. A long slow period of
reasonably large amplitude creates less drag than does frequent ‘small’ curves.
This observation has a direct bearing on the directional drilling strategy. It is better to rely on
occasional inclination changes that weave across the planned wellpath, rather than frequent
slide intervals that ensure the actual and planned wellpath’s overlie each other (See Figure 21
below).
•
It should be understood that the tortuosity of a wellbore can be far greater than the MWD
survey record shows because of the slide drilling and surveying frequency practices. As
shown in the figure below, the surveys may show that the wellbore is relatively smooth, while
there can be significant hidden tortuosity present. This will be most significantly reflected by
increased drag when running casing.
•
Buckling can be a significant issue in the tangent section, depending upon hole size, drillpipe
size, the wellpath and friction factors. Friction factors will depend upon mud lubricity,
cuttings and lithology type, hole cleaning, and wellbore tortuosity.
Survey Points
If survey intervals and slide patterns are
‘consistent’ on each stand, then there are likely to
be many hidden doglegs not shown by the surveys
‘High Frequency’ tangent section that results from frequent
slide drilling. Even though this closely follows the planned
trajectory, the actual wellpath is very tortuous, and will
result in increased drag, especially when running casing
‘Slow Frequency’ curve is much smoother, and
will result in less drag when running casing. This
type of curve is indicative of being drilled in
rotary mode with adjustable stabilizers
Figure: 21
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7.3.3
Lower Build and Turn Section
Deep build and/or turn sections are commonly used in ERD wells, most often for horizontal or 3Dimensional applications. The dogleg severity of such a deep build/turn will affect slack-off
weight more than torque or pick-up weight.
Casing strings, in particular, tend to ‘plough’ into the side of the wellbore in these lower build /
turn sections. This should not be confused with friction-related ‘drag’. The ploughing will be
very dependent upon the centralization of the shoe track because the centralizers will act to stiffen
up the casing. Once the shoe-track has passed below the build or turn section, then the surface
weight will generally resume along more expected friction factors (refer to Figure 18).
7.3.4
Lower Drop Section
Deep drop sections (as in S-turn profiles) will increase torque and pick-up weights, but will
provide more slack-off weight as the BHA/drillstring/casing moves ‘over the hump’ and into the
drop section.
Buckling problems may or may not be increased, depending upon the drop rate, drill-string and
the WOB used.
7.3.5
Reservoir / 8½" Section
The reservoir section can be quite different to the earlier hole sections, from a torque, drag and
buckling viewpoint.
Any permeable formation will have some differential sticking forces acting as increased friction
on the BHA, drillstring or casing. This may be negligible or severe, and will also vary with time
as the filter cake’s properties change. When planning the well, it should be assumed that
friction factors through a reservoir section will be higher compared to previous open hole
sections. This is especially important if the overbalance pressure is large.
Torque is usually higher in 8½’ hole compared to 12¼” or 9⅞”. The reduced annular clearance
between the drillpipe and the 9⅝” casing effectively ‘stiffens’ the drillpipe, increasing friction. It
is not uncommon for drilling torque to be acceptable at TD of the 12¼” section, and yet the
torque is very high while trying to drill out the 9⅝” casing shoe. It is also not particularly unusual
for the torque to be at it’s highest when the casing has just been drilled out (i.e. when it is still
clean), and for the torque to reduce as some hole has been drilled. The addition of some cuttings
into the cased hole section provides ‘lubricity’ up to a point (polishing), until the cuttings bed
height becomes critical and torque again starts to increase. It is recommended that the cased hole
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friction factors (CHFF) are recorded for each BHA run, as well as when POH. This is important
since the CHFF can vary throughout a run as the casing gets polished, etc.
Many ERD applications involve drilling long horizontal holes in the 8½” (or smaller) section.
This results in large compression forces in the drillstring and buckling can be a problem when
slide drilling or RIH with casing/liners. See detailed discussion on buckling.
The use of torque reducing and casing wear reduction tools is most common in this section. Non
Rotating Drillpipe Protectors (NRDPP’s), Roller Bearing Subs (RBS) and lubricants are often
used in combination with high torque tooljoints to manage the high drilling torque in this section.
7.4
BUCKLING
Buckling is often poorly understood and occurs on many wells without the drilling team realizing
it. In these cases, much time and cost is invested to dealing with hole problems, making bit
changes, wiper trips and optimizing mud, when buckling may have been the real problem
throughout. Contrary to popular understanding, buckling does not necessarily need to be severe
to affect operations.
Buckling is a complex issue that manifests itself in varying degrees, and is difficult to predict
unless the model that is being used has been extensively field calibrated.
Buckling is most common in the following situations:
• Slide drilling or running liners in horizontal or very high angle hole sections.
• In deepwater ERD wells where long casing strings are being landed with drillpipe or HWDP.
• If there is a hole size enlargement where the drillpipe is in compression (such as above a liner
hanger, or in an interval of ‘washed-out’ hole).
• In completions or workovers, especially if some compression is necessary to stab into packers
or liners (small completions, such as 2⅞” or 3½”, are quite prone to buckling in high angle
wellbores).
7.4.1
Buckling Theory
Buckling is a result of compressional forces in the string. Basically, drag forces build up
compression in the drillstring or casing until a point where the Critical Buckling Load (Fb) is
exceeded and buckling will commence. Different equations have been developed to define the
Critical Buckling Load at which different modes of buckling will commence at different locations
in the well (i.e. tangent, curve). Regardless of which buckling equation is used, the mode of
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buckling (sinusoidal or helical), or which section of the well that it applies to, buckling is a
function of the following:
•
E and I - Young’s Modulus and Moment of Inertia (measure of the tubular stiffness). Stiffer
pipe has more buckling resistance. Stiffness increases with OD.
•
w - tubular weight in mud. Generally, the higher the weight of the tubular, the less prone it
is to buckling. However, higher weight will also result in increased drag and therefore
increased compressional forces, and may actually increase the chances of buckling.
•
θ - average wellbore inclination. Sin θ is used in the buckling equations, and therefore for
vertical wells (sin 0 = 0) the critical buckling load is zero. As the inclination increased,
buckling resistance also increases. However, as with the tubular weight, higher inclination
will also result in increased drag and may actually increase the chances of buckling.
•
R - radius of curvature of the hole. Buckling in less likely in curved sections of the
wellbore.
•
r - radial clearance between the wellbore and tubular. Large annular clearances will result
in less buckling tolerance as the tubular is less constrained in the wellbore.
An example of a Buckling Risk analysis is shown in Figure 22. In this case, an attempt is being
made to slide at the 12¼” TD of a build and hold well.
There are two modes of buckling – Sinusoidal and Helical buckling. These are discussed in the
following sections.
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Figure: 22
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Example Buckling Analysis
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7.4.1.1
Sinusoidal (or “snaky”) Buckling
Sinusoidal (“snaky”) buckling occurs in a relatively gradual manner as the drillpipe is placed in
compression. The drillpipe starts to ‘snake’ in the wellbore. This prevents smooth transfer of
weight to the bit, but weight can be transferred nonetheless. It can usually be ‘pushed through’ by
placing more weight on the drillstring, although the drillstring will become more ‘sinusoidal’ in
shape. The efficiency of weight transfer will deteriorate as the buckling increases. Once the
onset of sinusoidal buckling begins, the use of a PDC bit on a motor becomes very difficult in
slide drilling mode. As weight transfer begins to become uneven in this process, the bit will tend
to “bounce” on bottom. When this occurs, the motor will stall or lose tool face and the assembly
will have to be picked-up off of bottom. In this situation, a roller cone bit performs much better.
It is often possible to design the drillstring to accommodate high sliding WOB, or to minimize its
effects through optimized bit and BHA design.
Figure: 23
7.4.1.2
Sinusoidal Buckling
Helical (or “Coiled Spring”) Buckling
Helical buckling will occur quite suddenly as the drillstring literally ‘snaps’ from a sinusoidal
mode into a ‘coiled spring shape’. Helical buckling is a significant problem once it occurs, as no
further downwards movement can occur while the drillstring is ‘coiled’. No further WOB can be
applied regardless of the weight applied at surface. This is because the drillstring is now acting as
a set of weight activated slips. Literally, the coiled drillpipe will ‘grip’ the wellbore better with
more weight applied from above.
The drillstring must be designed to avoid helical buckling for tripping, slide drilling and linerrunning operations.
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Figure: 24
7.4.1.3
Helical Buckling
Common Misconceptions
Is buckling Bad for the drillpipe? For both sinusoidal and helical, the buckling itself is not
harmful to the drillstring if there is no pipe rotation. The buckling stresses are usually well below
the yield strength of the pipe. The one exception would be relatively small pipe in big hole.
However, it is important that you do not commence rotation of the drillpipe until all of the pipe
buckling has been worked out of the string. Buckled pipe will quickly be fatigued if rotated (i.e.
cyclic stresses).
This can be a significant issue for very long ERD wells, where the pipe stretch is considerable.
After making a connection, it is good drilling practice to pick-up the string off-bottom and get all
of the compression out of the pipe prior to going back to bottom and drilling ahead. If the pipe
stretch is excessive, the compression in the pipe may not be able to be released, as the string
cannot be picked up high enough. As a result, drillstring fatigue will be increased and premature
failures may result. This may necessitate drilling in doubles or even singles to ensure that there is
enough derrick height to pick-up off-bottom.
Can the pipe buckle while rotating? As discussed previously, rotation minimizes the drag forces
and compression in the string. In a vertical well it is still possible to cause buckling while
rotating, though in a high angle well, it will be very difficult to get enough WOB (i.e. enough
compression in the string) to buckle rotating pipe.
7.4.2
Common Buckling Intervals
The following observations are made about the most common occurrences of buckling in an ERD
well.
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•
The vertical section of the wellbore is prone to buckling if in compression. This is due to the
fact that the pipe in this section is poorly constrained and is not supported by the wellbore
wall, as is the pipe in the deviated section of the well.
•
At the beginning of long tangent sections, the compression in the string can be high as the
pipe is pushed into the hole.
• Buckling is likely to occur above any liner top that is set deep in the well, especially if smaller
drillpipe is used for drilling inside the liner (say 3½” drillpipe inside 7” liner). At least two
scenarios must be allowed for, with possible intermediate points in between:
When slide drilling immediately below the liner shoe. This point will have the longest
interval of ‘small’ drillpipe inside the large casing above liner top.
When slide drilling at TD. At this point, the small drillpipe is almost completely within the
liner and, therefore, well confined. However, the small drillpipe will also be quite
compressed due to the horizontal section and although a true helix may not develop inside
of the liner, the area on top of the liner that is not as well confined will be subject to severe
buckling.
•
Large diameter hole sections can be prone to buckling, such as deep high angle surface holes,
or riser sections in deepwater wells.
•
Buckling is unlikely (but not impossible) to occur in the actual build and turn sections. This
is due to the fact that drillpipe that is ‘bent’ is more resistant to buckling.
Vertical Sections
Upper Tangent where there
is high compression pushing
the rest of the string
Lower Tangent above the top of the
curve, and especially for slim pipe
above the top of a liner
Near the Heel of long horizontal sections
Figure: 25
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7.4.3
Options to Prevent or Reduce Buckling
There are numerous design options to prevent or reduce buckling problems. Some of the most
common methods are described below.
7.4.3.1
Wellpath Design
The wellpath is a compilation of many differing objectives (i.e. collision avoidance, wellbore
stability, target alignment, etc.). However, there may be scope to reduce buckling problems by
designing the wellpath with buckling in mind. Options include different build or turn rates in the
lower build section for a horizontal well, or varying the casing points or liner tops.
7.4.3.2
Drillpipe Size and Stiffness
The most common method of managing buckling is to place HWDP at strategically located
intervals in the drillstring. This method was originally developed for use in conventional
horizontal wells. While still quite effective in ERD wells, there are distinct disadvantages of
relying on these methods for ERD applications. On a conventional vertical-to-horizontal well, the
HWDP does not contribute significantly to increased torque and drag. Furthermore, hydraulics
are not usually a limitation on vertical wells. Because of this, HWDP can be used quite easily to
prevent buckling (see Figure 26). However, on an ERD well, the HWDP will be placed in a high
angle section of the well, and therefore results in significantly more torque and drag, while also
increasing surface pump pressures. As such, the use of HWDP is less appropriate on ERD wells
if there are torque, drag or surface pressure limitations. It is preferable to keep the drillstring as
stiff as possible without increasing its weight significantly.
This can often be accomplished by increasing the size of the pipe that is being used. The use of
5½”, 5⅞” and 6⅝” drill pipe for improved hydraulics and buckling performance is common in
ERD applications. The use of Non-rotating Drillpipe Protectors is also a common practice to
prevent buckling by stiffening the existing drill string at strategic locations.
Increasing the diameter of the tubular improves buckling performance because the pipe stiffness
is a function of the radius to the power of four. That is, Stiffness = fn (R4 – r4). This explains why
4” drillpipe is significantly better for buckling compared to 3½” drillpipe, and why 65/8” drillpipe
and casing are basically immune to buckling.
The use of larger pipe, to avoid buckling, needs to consider the possible increase in ECD’s. This
is especially important on very shallow ERD wells.
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The long HWDP interval on a
vertical-to-horizontal well does
not increase torque and drag
significantly, since it is largely in
the vertical section
On an ERD well, a long section of
HWDP will be required to prevent
buckling. This will increase the
torque and drag significantly because
it is in the high angle section. It may
also induced further buckling up the
hole. HWDP will also be detrimental
if the hydraulics are limited.
Figure: 26
7.4.3.3
Use of HWDP to Prevent Buckling
Special Downhole Tools to Improve Drillpipe Stiffness
There are several specialized downhole tools that can stiffen drillpipe. Most of these items
require some planning since they are relatively expensive and usually must be ordered in advance.
There are also drillstring management issues, and in some cases there are also other risks that
must be considered.
Bladed Drillpipe - Integral bladed-drillpipe (or spiraled drillpipe) will improve pipe stiffness
without significantly increasing weight. This drillpipe will also aid hole cleaning, while being
more resistant to buckling.
Non-Rotating Drillpipe Protectors / Roller Bearing Subs - Non Rotating Drillpipe Protectors
(NRDPP’s) or Roller Bearing Subs (RBS) can be used to stiffen the drillpipe without increasing
drag, (drag will increase while running through build section only) while also reducing torque.
While effective at preventing buckling, there are obvious cost and drillstring management issues
involved with these tools. Further, there is some risk of losing at least some of these downhole if
improperly applied. In general, these tools have been found to be quite sturdy and reliable, but
experience has shown that you cannot afford to take shortcuts with the quantity or type of tools
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required. The side-load forces must be modeled and sufficient quantities of these tools applied.
Do not use these tools if you are not willing to run the required amount, as you are then likely
to lose them downhole. Ensure that the side-load modeling assumes a backreaming scenario as
well.
The increased ECD’s that will result from the application of these tools must also be considered.
Roller Centralizers for Casing and Completions - “Roller” centralizers can be added to a casing
or completion string if buckling is a problem. These minimize buckling by reducing the overall
drag on the string (effectively reducing the slack-off friction factor as well as stiffening the
string). These centralizers can be used on casing, conventional jointed tubing or coiled tubing.
K&M’s experience with these tools suggests that they are very effective in cased hole, especially
if the hole is ‘clean’. Openhole experience is limited, but they will most likely do some good as
long as the hole is consolidated.
7.4.3.4
Rotation and Flotation
The best defense against pipe buckling is to preserve the ability to rotate. This applies to drilling
as well as running of liners and casing (floated). This cannot, generally, be applied to coiled
tubing or conventional completion programs.
Rotary Steerable tools (RST’s) are helping to overcome many of the drilling problems seen with
buckling when using steerable motors.
When running liners, premium high torque connections are available that allow rotation while
running in the hole and during cementing operations. Roller centralizers can also be used that
allow significant reduction of both torque and drag.
Another option to limit buckling with casing and liners is flotation. By floating the string, the
weight is significantly reduced, which results in much lower drag. However, under the right
conditions, flotation may also result in increased buckling, as the casing will have less buckling
resistance when its weight is lower. Where possible, the ability to rotate should always be
designed in as a contingency on a difficult casing run.
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7.5
VIBRATIONS
Downhole vibrations are often less severe on ER wells than seen on low angle or vertical wells.
However, they are of a particular concern in ERD wells due to their direct and indirect impact on
the overall “system”. Downhole vibrations can cause the following:
•
BHA Failures (mechanical and electronic). RST’s, MWD and FEWD tools are all
particularly sensitive to vibrations. Log quality of FEWD tools can also be affected.
•
Reduced bit life (especially PDC’s)
•
Reduced ROP
•
Reduced drillstring life and twist-off’s
•
Poor hole condition
•
Higher drilling time and cost
High-speed rotation is often required for hole cleaning on ERD wells. The question is often
asked if this high rpm is dangerous to the drillstring. In practice, it is often found that at high
rpm, the drillstring rotation is much smoother than at lower rpm. This is due to the harmonics or
natural frequencies of the drillstring and system. All efforts should be made to avoid rotating at
these natural frequencies, which will result in excessive and potentially destructive vibrations. As
long as these high rpm’s are not at the natural frequency, they will not be dangerous to the
drillstring.
Vibrations can be minimized or eliminated by downhole monitoring, and adjusting drilling
parameters and practices accordingly. Note that monitoring surface vibrations alone is of little
value, as it is highly unlikely that what is happening downhole will be seen on the surface. In
order to respond to vibrations and eliminate them, it is helpful to understand the different types of
vibrations and what causes them.
7.5.1
Types of Vibrations
The following table summarizes the different types of vibrations and steps that can be taken to
control them. Note that real-time multi-axis vibration tools are the best method for identifying
the mode of vibration, and therefore allowing the vibrations to be controlled.
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VIBRATION
TYPE
DESCRIPTION AND SYMPTOMS
DEALING WITH VIBRATION
BIT BOUNCE • Often seen as large surface vibrations • Use shock sub (more suitable in low
in short or vertical wells
angle wells)
(AXIAL)
•
•
Often a result
formations
Bit damage
of
drilling
hard •
BIT AND BHA • Refer to Figure 27 below
• Very complex and destructive
WHIRL
(LATERAL) • A major problem with early PDC bits
•
•
•
Impact damage to bit gauge pads
Localized tooljoint wear
Erratic surface torque
•
•
•
•
•
•
STICK-SLIP
(TORSIONAL)
•
•
•
Cyclic surface torque fluctuations / top •
drive stalling
MWD sensors have shown fluctuations •
of 0-300 rpm downhole
•
Over-torqued tooljoints
Adjust drilling parameters
(↑ rpm while ↓ WOB)
Use anti-whirl bits
Adjust drilling parameters
(↑ WOB while ↓ rpm)
Pick-up off-bottom and stop / restart
rotation
BHA design
Soft-torque
Run a straight motor
Adjust drilling parameters
(↑ rpm while ↓ WOB)
Soft-torque
Bit design
Bit / BHA “walks”
around the hole
Figure: 27
2007 – Third Edition
Whirling bits / BHA’s drill a
hole with a lobed pattern
Bit Whirl
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8
NEGATIVE WEIGHT WELLS
The term “negative weight well” describes a specific category of ERD well whereby the drill
string or casing strings will not run to bottom under its own weight due excessive drag forces. In
these wells, the critical drag angle has been exceeded for a long enough interval that the available
vertical forces in the well can no longer overcome the drag forces. Negative weight wells offer
up a whole new set of challenges that must be overcome. In particular, specially designed
drillstrings and casing installation methods are necessary to reach TD. The following sections
address drilling operations and casing operations in negative weight wells.
8.1
8.1.1
DRILLING OPERATIONS
Drillstring Design
ER wells place a significant stress on drill string components that they are not necessarily
designed to take. Drill pipe is not designed to be used in compression, especially while rotating.
In ERD wells the neutral point in both sliding and rotary mode is a long way above the BHA
(usually many thousands of feet above the BHA). The drill string is able to withstand this loading
because gravity is holding it to the low side of the hole, and is helping to prevent it from entering
a buckled state. Eventually a combination of this compression drilling and cyclic loading will
“prematurely” fail the pipe.
Drill string component inspection and the use of new or premium grade pipe is a must for ERD
applications. Although drill string component life is reduced when compared to conventional
drilling, this is a by-product of ERD drilling. K&M recommends setting an initial base of 200
hours for component inspection and then adjusting that number based on experience.
“Inverted” drillstrings are sometimes applied in ERD applications to increase surface weight in
order to overcome drag. This essentially involves placing large or heavy components in the
vertical part of the drillstring, and small or light components in the high angle portion of the hole.
The sizing of the components is largely driven by available hydraulics and required flow rates. In
extreme cases, drill collars may even be used to provide weight at surface.
As with any ERD drillstring, there should be an absolute minimum of HWDP and drill collars in
the BHA itself. This HWDP is used for transition between the BHA and drill string and to
provide some jarring mass above the jars. The maximum amount of HWDP that should be run in
any ERD application is 5 joints above the jars and 3 joints below (3 stands total with the jars).
Recall from earlier discussions that almost the entire drill string will be in compression; making
the age-old standard of locating the jars at the neutral point inappropriate.
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8.1.2
Tripping In
A legitimate method to overcome negative weight circumstances is to rely upon rotation to
provide sufficient surface weight to allow tripping into the well. This applies to both drillstrings
and casing strings.
Technically speaking, the initiation of rotation re-directs the friction vector from the axial
direction to a position perpendicular to the well’s axis. This creates a nearly friction-free
environment axially and allows the pipe to slide into the hole.
Some Operators prefer to plan their wells with rotation as their primary solution to negative
weight problems, whereas K&M prefers to optimize the well profile, drillstring, or casing string
as the primary solution (if possible). There are downsides associated with rotating into the hole
that include:
•
Wear and tear on surface and downhole equipment
•
Reduced bit life
•
Probable vibration related downhole component MTBF reduction (worst environment for
vibration is down-reaming)
•
Battery life considerations for MWD/FEWD tools
•
Increased risk of deteriorating hole conditions
•
ECD surging (see below)
K&M participated in extreme negative weight wells where rotation for tripping is a necessity. If
reaming into the hole is likely, ECD implications must be considered as an increased risk if
significant ECD surging is likely. This problem should be addressed in the planning stages of the
well to ensure that the field personnel have the proper equipment and training to deal with this
eventuality.
Alternative drill string design options and well plans should focus on delaying the need to rotate
into the hole for as long as possible.
8.1.3
Drilling
An obvious question in a negative weight environment is “if we have to rotate to trip into the
hole, how can we expect to slide drill under these circumstances?” In fact, slide drilling will
generally become impossible (or at least too difficult to be practicable) before conventional
tripping is no longer possible.
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Under these circumstances, a rotary drilling strategy must be adopted that will meet the
directional drilling objectives. We have already stressed the hole cleaning and drilling
performance benefits for planning on a rotary drilling strategy, but under these circumstances,
there is no longer an alternative.
The primary difference here is that the ‘rotary drilling strategy’ must work. Effective design
contingencies must, however, be available if a course correction is necessary (either due to
equipment failures or simple lack of directional control).
Consider a long, shallow negative weight ERD well, with an 85° tangent section and a significant
build / drop / turn in the lower section. Firstly, how do you ensure directional control in the long
tangent section (especially azimuth control)? Secondly, how do you initiate a course correction at
depth? K&M has been involved with many early, innovative bit and BHA design concepts (see
Sections 11 and 12), which have enabled these problems to be resolved. Furthermore,
technologies such as Rotary Steering Tools (RST’s) have expanded the design envelope and
improved performance for negative weight wells.
The presence, or likelihood, of drillstring buckling must also be considered. Depending upon the
drillstring configuration, buckling may or may not be more difficult to manage than the simple
lack of surface weight. This will affect the design solution, considerably. Casing point selection,
and contingency setting depth options will play a critical role in this issue where hole size has
such an important effect upon the ability to maintain directional control.
K&M has had several projects where previous feasibility studies had shown that a particular ERD
project was not feasible. Often “the inability to slide drill to TD” has been given as primary
limiting factor. The fact is that K&M has yet to be given a project that we were unable to make
feasible by utilizing non-traditional solutions and intensive planning.
8.1.4
Deep Sliding Technique
For negative weight wells that require slide drilling, an advanced ‘rotary slide drilling’ technique
may be used to either (a) allow slide drilling that was not previously possible, or (b) to improve
sliding ROP.
This technique is described in detail in Section 11.5.6 under Directional Drilling Strategies. It
involves the continuous movement of the drillpipe, in a manner sufficient to overcome static
friction, while attempting to maintain constant tool face in slide drilling mode.
K&M has used this technique with considerable success, as have significant projects such as
Wytch Farm. However, we hesitate to base well feasibility or well planning assumptions on the
success of this technique. Rather, it should be left as a field implementation option, for use as
necessary. This technique can be difficult to learn, and requires some patience and practice.
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The AG-itator tool described in Section 18.1.10 has also been used with considerable success to
improve sliding ROP and efficiency when weight stacking has been an issue.
8.1.5
Drilling with Block Weight
K&M has participated in client wells (e.g. drilling from slant rigs) where the block weight of the
top drive has been applied in order to achieve an acceptable weight on bit to drill with. This is a
practice that K&M engineers generally discourage, as the block weight (i.e. top drive or blocks)
should not be relied upon as the primary source of additional weight. In fact, this should be
considered as a final contingency. Furthermore, when planning, it should not be assumed that the
full block weight can actually be applied as it may damage the top drive assembly.
A pulley operated pull-down system for use in extreme negative weight wells from slant rigs has
been used in California and in Canada with significant success. While it does allow significantly
more than the actual block weight to be applied at surface, the top drive system must be designed
(or modified) to allow for this type of loading.
Generally, the thrust bearings on the top drive are not designed for operation in compression.
8.2
CASING RUNNING OPERATIONS
Casing is often the limiting factor in an ERD well, and generally requires specialized techniques
to be successful. There are numerous casing design methods that can be used to overcome
varying degrees of drag. Each of the following methods needs to account for other casing design
criteria, with collapse being a specific issue of focus.
K&M utilizes Drag Risk Analysis (DRA, refer to Section 7.1.3.2) to determine the degree of
“negative weight” that must be overcome with the design. DRA will utilize existing well data,
historical run data, and any special considerations to determine the likely running open-hole
friction factor range that applies to a given casing run. If the worst case side of this curve crosses
the “zero” tension line, then special running techniques are generally warranted. The DRA will
also assist in determining the degree of special handling that the casing might require (i.e.
different techniques apply for 250 kips of negative weight relative to 25 kips of negative weight).
To demonstrate the effectiveness of each of the running methods listed below, slack-off plots
have been included for an example well. Note that Figure 28 shows the first line contingency
methods and Figure 30 shows the floatation methods. These are not DRA plots as the slack-off
weights are only shown for a single friction factor (CHFF and OHFF of 0.3). The plots are based
on running 9⅝” 47# casing to a depth of 7000m in an 80° well, with a mud weight of 10.5ppg.
All other assumptions are included on the plots.
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8.2.1
8.2.1.1
First Line Contingencies
Lighter Weight Casing
Although this option to enhance casing running weight in ERD wells may sound simplistic, it is
often overlooked. Although this option will reduce casing material costs, its purpose is to reduce
drag when running casing in a high angle well. It will also help to alleviate ECD problems later
in the well. Note that casing materials cost savings are small compared to the overall well cost,
and typical ‘cost optimization’ of casing strings can rarely be tolerated on ERD because of the
logistics difficulties that ensue.
Obviously, lighter casing strings (via thinner walled pipe) must meet the standard pressure
integrity requirements. However, in many ERD projects, the casing is thicker-walled than is
strictly necessary, being chosen because (a) it is in stock, (b) it is simple, and (c) because it
reduces the risk of casing wear.
For example, 9⅝” casing is typically run as a long string of 9⅝” 47 ppf casing. This size of
casing ensures that casing wear will not be a risk, while simplifying the materials requirements
(because it is commonly used on other projects). However, it may be that 9⅝” 40 ppf casing was
sufficient to meet pressure integrity requirements. This lighter casing will reduce drag forces, and
may alleviate the need for complex selective flotation techniques. Furthermore, the increased
casing I.D. will result in ECD reductions when drilling 8 ½” hole.
Casing wear is not generally a problem in a quality drilled ERD well. As long as backreaming is
not a standard practice, casing wear is generally lower in ERD wells than in conventional wells.
As such, thinner walled casing can be safely tolerated. An example of this is the Wytch Farm
Project, where 9⅝” 40 ppf casing was utilized, even though they drilled very long sections of 8½”
hole below this casing point. They did not see any significant wear problems.
The use of lighter weight casing will obviously have to consider casing collapse, if flotation
techniques are to be applied.
8.2.1.2
Inverted Casing Designs
One of the easiest ways to overcome small amounts of negative weight is the use of an inverted
casing string design. This technique would place heavier casing on top in the vertical section,
with lighter-weight casing in the high angle tangent section. Although it is not usually an issue,
this technique will involve having a smaller internal diameter in the upper casing, which can
create issues for completions or later workovers. As an alternative option, it may be preferable to
run a tapered casing string (with say 10¾” heavy walled casing above 9⅝” casing) in order to
combat these issues. As a rule of thumb, the use of inverted or tapered casing can buy up to an
additional 50 kips of string weight for the running string. If ECD’s are an issue, however, tapered
string should be carefully considered as the reduced clearances around the larger OD casing can
generate substantial annular pressures.
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8.2.1.3
Hangoff Drill collars
In extreme cases, drill collars may be hung inside the top casing joints as the casing is run. This
technique, although slow, does provide significant additional surface weight during the running
process. See Figure 29 below.
K&M has utilized this technique on some client slant rig operations. A storm packer is generally
run to provide the hanging force for the collars with a reliable release. As the collars get into the
high angle portion of the well, pipe is tripped into the hole to retrieve the packer. The collars are
moved up the hole and re-hung near the surface. The casing running operations are then resumed
until available weight at the surface runs out, again.
This is a slow method of running casing, and would only be used in extreme cases. The need for
this technique is typically limited to shallow ERD wells, where surface weight is very limited and
where magnitudes of the drag forces are sufficiently small to allow this approach to be effective.
8.2.1.4
Run Casing as a Liner
It may be necessary or desirable to run casing as a liner in order to overcome drag. Even large
strings of casing, such as 9⅝”, may be run in ERD wells as a liner for this purpose. This liner
may or may not be tied back to surface.
The primary benefit of running the casing, as a liner is that rotation may be more viable, either to
overcome drag or for a better cement job. It is unusual, however, that long strings of casing that
are run as a liner are able to be rotated unless the liner is floated (either fully, or selectively). This
is due to the large forces required to rotate the pipe if it is full of mud.
8.2.1.5
Apply Top Drive Weight
Unless flotation is employed, the application of top-drive weight is really only for shallow ERD
wells. This is because the magnitude of the drag force that is preventing the casing from sliding
into the well is otherwise too large.
K&M prefers to design casing runs so that the use of block weight is available as a contingency,
rather than as the primary means of overcoming drag.
Some Operators, however, have demonstrated that they can rely on block weight to over-come
drag. Wytch Farm, for example, ran several 9⅝” casing strings completely empty, relying upon
block weight to push the casing down. It should be noted, however, that the Wytch Farm
situation is somewhat unique. The 9⅝” 40 ppf casing is effectively neutrally buoyant (actually,
the casing may literally be floating on the high side, although with minimal side force). Because
of the low drag forces, the casing can be pushed (and rotated) by the top drive.
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Figure: 28
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First Line Contingencies for Running Casing
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VERY SHALLOW, EXTREME NEGATIVE WEIGHT WELLS
MAY REQUIRE DRILL COLLAR HANG-OFF METHOD
Storm packer, with
drill collars hanging
below
STEP 1 :
Hang drill collars from storm packer,
set in vertical portion of casing.
This will provide weight at surface to
help 'push' casing in the hole.
Casing,
being run into hole
STEP 2 :
When drill collars enter high angle section,
they create drag, rather than help push casing.
STEP 3 :
Pick up storm packer on drillpipe,
and reset hanging drill collars in
vertical section, for more push.
STEP 4 :
Final situation at TD.
Hanging off drill collars inside casing
has provided sufficient surface weight
to overcome drag
Figure: 29
8.2.1.6
Hanging drill collars inside casing
Top Drive Pull-Down Systems
K&M has been involved in the design and use of a top drive ‘pull down’ system for use on
shallow ERD wells in Canada and offshore California. Slant rigs were being used to drill very
shallow ERD wells where there was insufficient surface weight available for slide drilling and
running casing. Because of the slant rig design, there was also only limited top drive weight that
could be transferred to the pipe. A hydraulic cable and pulley system was devised to ‘pull’ the
top drive down onto the pipe. This proved very effective at providing push to the casing string.
This approach would also be suitable for conventional top drive rigs for shallow ERD projects.
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8.2.2
Casing Floatation Techniques
Casing flotation, or selective flotation, was developed by K&M and Unocal in 1989, and has been
used since on numerous ERD wells worldwide. Since its inception, different variations of the
method have been applied to meet different applications. As this technique utilizes air in the
bottom of the casing, collapse avoidance must be carefully designed into the program. The
collapse design should be based on a dynamic situation with the running and circulating ECD’s
accounted for. The ECD related annular pressure increase can be significant on long ERD wells,
especially if (a) the casing clearance is small or (b) the design safety factor is marginal.
The general principle is that the casing in the tangent section is reduced in weight via buoyancy,
thereby reducing the drag forces. At some point during the casing running process, the buoyancy
starts to counter-act its benefits (i.e. the casing stops running into the ground). Additional weight
is then applied in the vertical section via the addition of drilling fluids. If more than one stage of
weighted fluids are utilized, they will be separated by a viscous plug.
It is important to understand that a flotation method does not allow circulation during the run
without losing all of the benefits of flotation. However, if the bulk of the casing is empty, then it
may be possible to rotate the casing if the casing is sufficiently buoyant.
The optimum flotation method will depend upon many factors. The more difficult wells may
require the use of a particular combination of flotation, inverted casing, rotation and/or push with
the top drive. If the application allows for a choice of methods, then it should be noted that airfilled pipe runs into the ground very slowly and the design selection should not use more air-filled
pipe than is required (with a reasonable safety factor). Selection of the methods should begin
with the following considerations:
•
Buoyancy of the casing. Different casing sizes have different buoyancy tendencies, which
depend upon the mud weight in use. Generally, 9⅝” casing is neutrally buoyant when empty.
Larger casing sizes will generally be positively buoyant (i.e. will float, literally) while smaller
sizes will be less buoyant. The following formula may be used to determine the running
weight of the air filled portion of the casing:
Where,
CA = Air equivalent weight of casing (for use in T&D model)
CB = Buoyed weight of casing (#/ft)
FB = Buoyancy factor
Df = Density of mud in well (ppg)
DP = Density of fluid in casing (ppg)
Wf = Weight per foot of fluid in casing (#/ft)
VC = Volume of casing (gal/ft)
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CB = CA x FB (mud filled)
Wf = Df x VC
CA (air) = CB – Wf
FB
If heavier/lighter fluid is used inside of the casing, then
CA (filled) = (CB – Wf) + (DP x VC)
FB
•
The collapse load may exclude or limit some flotation options. Collapse calculations should
consider the dynamic situations. In particular, the ECD induced collapse load while running
the empty casing should be modeled. This is especially important for tapered casing strings
(such as 10¾” over 95/8”), where there may be very little annular clearance, resulting in a
significant piston effect.
•
K&M is aware of at least two floated casing jobs where the “running” ECD’s were sufficient
to collapse the empty casing. In one situation, the casing was strong enough to prevent static
collapse, but the running ECD pressure load added an additional 1500+ psi.
•
The inability to displace light fluids into the annulus will also limit the available options.
8.2.2.1
Air Filled (Empty)
This method of casing flotation is non-selective in that no optimization is involved. This
approach is most applicable when the well is shallow, due to the fact that at some point the
casing’s buoyancy will start to resist downward movement. In fact, if the casing will stop
running into the hole using standard techniques at a particular depth, it will stop at the same depth
when completely air-filled. However, air-filled pipe does allow for other options. It will
significantly lighten the pipe and may allow it to be rotated from the surface. The lighter pipe
should also be able to be pulled from the hole, if required. If the casing is to be pushed to bottom
using the weight of the top drive, the required pushing load will also be significantly reduced as
compared to a standard run.
If the casing is positively buoyant, it may be necessary to modify the slips to stop the casing
‘floating’ out of the hole.
It should be noted that this is a very slow method of running casing and should be utilized for
very specific applications.
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Figure: 30
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8.2.2.2
Mud Over Air
This is the classic selective flotation technique as originally developed by K&M and Unocal in
1989. The air interval in the lower section is separated from the heavy upper mud interval by a
purpose designed ‘flotation collar’, or by a retrievable packer. When the casing is on bottom, the
flotation collar is hydraulically sheared out, and the heavy mud is allowed to ‘swap’ out with the
air and fill the casing. If a packer was used as the isolation device, it is retrieved at this time.
Circulation is then established and the well cementing operations commenced.
This method is not limited by the requirement to circulate light fluids into the annulus, such as in
a heavy mud over light mud float (discussed later in this chapter). It does, however, have
limitations for large diameter casing. For example, running 11¾” 54ppf casing empty in 12 ppg
mud will float (i.e. it is positively buoyant), and therefore, will not run in the vertical section of
the well without being ‘pushed’ (which is not advisable as it will want to float out of the hole).
8.2.2.3
Air Cavity Technique
The air cavity technique was developed for use with large casing strings, which would otherwise
float out of the hole. Drilling fluid is used to fill the casing until the casing has reached the end of
the build section (or thereabouts). The casing is then run empty, until a mechanical flotation
collar is installed at a strategic point and drilling fluid, or heavy mud is used for the final part of
the run. After reaching TD, the flotation collar is sheared out, and the internal fluids allowed to
swap out. The casing is then filled before breaking circulation (note that the retrievable system
may also be used). This technique provides weight to otherwise buoyant casing to allow it to run
into the hole under its own weight.
This technique is applied in one of the following scenarios:
• In a situation as described above, where the casing’s positive buoyancy will not allow the
casing to RIH through the vertical section.
• For S-bend wells, the lower portion of mud-filled casing will help pull the casing string down
through the final drop section. If air filled, the buoyant casing will resist running through this
lower angle section.
It should be noted that the application window for this technique is small. The mud in the lower
portion of the casing often prohibits enough air-filled pipe to be run before that weight overcomes
the available vertical loads. Careful modeling and benchmarking should be completed to ensure
the success of this technique.
As a general rule, the deeper the kick-off point, the better the chances of this technique working.
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8.2.2.4
Heavy Mud Over Light Mud
This technique was originally designed for use on deep-set surface casing runs in one of K&M’s
client wells. It relies on filling the casing in the tangent section with a ‘light’ fluid (relative to the
annular fluid), before filling the final portion with drilling fluids and/or heavy mud. In complex
flotation jobs, it may be necessary to ‘stack’ three different internal fluids.
Dependent upon the hydrostatic generated by the internal fluid column, it may be necessary to
mechanically isolate the internal hydrostatic from that in the annulus (i.e. if the former is greater,
then the system will u-tube through the float equipment).
If mechanical isolation is required, there are several methods that have been used.
•
If the light fluid has to be removed from the casing prior to circulating in order to avoid
formation damage or a well control situation, then a bridge plug system can be used to
separate the fluid. After retrieving the bridge plug, a trip to bottom will be required to
circulate the light fluid out of the casing. Note that provisions for dealing with the fluid that
is circulating over the top of the casing would be prudent.
•
A selective flotation collar can be used to separate the fluids. Once the casing is landed,
pressuring up inside of the casing shears the internal plug out of this device and it is pumped
to bottom during the circulation process.
•
An SSR bottom plug (with the ball in place) can be placed on top of the float shoe to prevent
the U-tube effect and then, standard bottom plugs can be used to separate the fluids.
If the annular hydrostatic exceeds the internal hydrostatic, then the floats will be held closed and
bottom cementing plugs can be used to separate the fluids. Note that plug separation of fluid
should NOT be used if an air cavity is beneath the plugs. The plug(s) will prevent the air from
swapping out inside of the casing.
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9
HYDRAULICS PLANNING
Good hydraulics planning is essential for ERD wells that have flowrate and/or pump pressure
limitations. This can apply to both shallow and long ERD wells, depending on the drilling rig
capability.
This section is intended to provide realistic guidelines for hydraulics planning. A good hydraulics
model is important for this application, as well as a good understanding of the drilling rig’s
capabilities and limitations. It is also important to understand the hydraulic requirements of
downhole equipment in your particular application.
9.1
HYDRAULICS MODELING
K&M’s hydraulics model has been field tested and shown to be reliable. It has compared well to
proprietary “leading edge” hydraulics models provided by mud companies. Hydraulics models,
in general, will tend to perform more accurately in larger hole, but will tend to under-estimate the
annular pressure drop for smaller hole sizes. Hydraulics modeling must use appropriate
rheologies, since shear-thinning fluids are likely to be in use in ERD applications.
The use of highly compressible SBM systems introduces significant complications for accuracy
of modeling. Even with access to proprietary software, this requires significant calibration with
actual results.
9.2
9.2.1
OPTIMIZATION OF HYDRAULICS PERFORMANCE
Identify Rig Hydraulic Limitations
The rig’s limitations, relative to the size of the wells being drilled, needs to be understood before
upgrades can be made. It is not uncommon for a rig’s theoretical pumping capacity to far exceed
that achieved in reality. It is also not unusual for the reliability of a mud pump system to fall off
considerably once embarking on an ERD program with higher pump rates and pressures.
The ‘bottleneck’ or critical path issues in the rig’s hydraulic system should be identified and
addressed early in the planning process to ensure that ample time is available for the
improvements to be realized. This is best accomplished by seeing the rig in operation during a
challenging hole section. Not only must the current bottlenecks be addressed, but the impending
ones as well. Common limitations are:
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Pressure Limits
• Pump equipment (liners, fluid-ends, etc.)
• High pressure lines (piping, swivel)
• Drillpipe (size, tooljoint design)
Flowrate Limits
• Pump equipment (liners)
• Shale shakers (overflow of mud)
• Movement of mud between pits
• Flowline (overflow or spillage)
9.2.2
Well Design
The well design and the hydraulics capabilities of the rig should be integrated with the proposed
drilling strategies. Designing the well, and then making the bit, BHA and mud strategies fit the
design will almost certainly negatively impact the program’s overall performance. A good well
design will factor the hydraulics capabilities and limitations into the overall design up front in the
planning. The likely bit and BHA strategies should be built into the well design from the
beginning. If possible, the well design should be iteratively modified to ensure that optimization
occurs.
The following guidelines and ideas are offered for consideration. These will differ for each
program and rig.
•
Do not consider each hole section in isolation. The strategies for each section should take
into account how the next section will be drilled and cased.
•
Deep build and turns are more easily achieved in 8½” hole rather than 12¼”. This is due to
better directional response of equipment and the more confined environment for the drill
string. This is especially the case if desired flowrates are more easily achievable in the
smaller hole size.
•
If it is desirable to case off any intermediate formations prior to entering the pay zone, then it
may be better to case off the tangent section prior to beginning any drop or turn into the pay
zone and allow the slow build/turn section to be drilled in the relatively stable 8½” hole.
•
If a turn is required in the next hole section, then the previous hole section can be designed to
best allow for this? For instance, if a big turn to align the wellbore is required prior to
entering the pay, the bit, BHA and hydraulics strategy for the previous hole section may
change considerably. If casing is set prior to the turn as suggested above, then that hole
section’s lateral directional control will not be critical. That being the case, then performance
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drilling assemblies can be used to reach TD of that section and a steerable assembly used in
the smaller hole size to align the well to the target.
•
Will ROP in a given hole section be particularly slow (e.g. if extensive slide drilling is to
occur)? Can the well design be improved to reduce the hole exposure risk or to improve
ROPs in this same section (via changes in hole size, casing points, mud system type weight,
or bit/BHA strategy)?
•
Are ECD’s a problem? For shallow wells in particular, there may be scope to increase the
hole size to improve the ECD situation at TD.
9.2.3
Drilling Fluid
The mud system should be purpose designed for optimum performance with the priorities for the
mud system clearly defined. The mud system design will be needed to consider hole cleaning
performance, ECD fluctuations, gel strengths, pump pressures and flowrates, and costs and
logistics issues.
The following are general mud guidelines for optimizing hydraulics performance:
• The mud system should have minimum low gravity solids, and minimum PV’s. This is
achieved by using premium solids control equipment throughout, maintaining the mud
properties in a pro-active manner, and using premium viscosifying agents.
The mud system needs to be a shear thinning fluid, for optimum hole cleaning performance
and maximum flowrates (via lower pump pressures). For WBM systems, this requires that the
premium polymer viscosifiers such as XCD and Xanthum Gum are used, and not bentonite.
For SBM and OBM systems, premium quality low-end rheology modifiers are necessary.
• The rheology should be based on 3 and 6 rpm Fann readings, and not YP. The mud should not
be too thick, with the 6 rpm set at about 1 – 1.2 times the hole size (in inches). As discussed
in Section 6, viscosity is not a key element to hole cleaning in high angle hole. Furthermore,
unnecessarily thick mud will reduce flowrates via excessive pump pressures.
•
For SBM/OBM systems, the OWR should be as high as practicably possible. For ERD
operations, K&M usually target 80: 20 OWR as a minimum. Although higher water content
may reduce cost/barrel of mud, it will negatively impact drilling operations and overall well
costs.
In an SBM/OBM system, the water effectively acts as low gravity solids, detrimentally
increasing high-end viscosity, and effectively increasing PV’s. Therefore, higher water
content results in higher pump pressures, lower flowrates and non-optimum mud properties.
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9.2.4
Drillstring Design
The selection of the drillstring is one of the most important factors in optimizing hydraulics, and
ultimately the drilling performance in an ERD well. Often, there will not be a choice, as
Operators will be forced to use the pipe that is available at the time. However, if this results in
performance limitations or hole cleaning problems, the cost impact will be far greater than the
incremental cost for rental or purchase of an optimized drillstring. Generally, when optimizing
the drillstring for hydraulics, the following key areas must be evaluated:
•
Hydraulics in 12¼” hole
•
ECD in 8½’ hole
•
Other technical issues related to pipe selection (i.e. torque, drag and buckling)
•
Costs and logistics implications (i.e. rental, purchase, handling equipment, finger-board,
racking capacity, etc.)
9.2.4.1
Drillpipe Size
As mentioned above, the main hydraulic considerations for drillpipe size will be pressure and
flowrate in the 12¼” hole, and ECD in the 8½” hole. Note that deep 17½” hole sections may also
be a design consideration.
An example pressure and flowrate analysis for a 12¼” hole section is shown in Figure 31. These
results are based on a 4500m MD (15,000’) 12¼” section, drilled with 10.5ppg mud. The top
chart is a snapshot of pressures when circulating at TD with various drillstring combinations.
This clearly shows the benefits of larger OD drillpipe.
However, in comparing different drillstring options, the hydraulic pressures should also be
matched to the pumps and liners that are to be used. This is shown in the bottom chart, which
defines the flowrates that are possible verses depth, with various pump liner sizes and drillstring
options.
The aim of this analysis is to determine the size of drillpipe required to allow adequate flowrates
to clean the 12¼” hole. It is important that adequate pressure drops are allowed for BHA
components and that the modeling is done with adequate safety factors. Where possible the
model should be calibrated with actual well data.
An example hydraulics analysis for an 8½” section is shown in Figure 32. These results are based
on the same well as above, with the 8½” section drilled to 5175m MD (17,000’). Generally the
pressure is not a concern as the flowrates are low, and ECD is more of an issue. Often mixed
strings will be required in order to manage ECD concerns (refer to Section 10 for further
discussion on ECD’s).
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12¼" Hydraulics Summary for Different Drillstrings Options
4500.0
5" Drillpipe
4000.0
5 1/2" Drillpipe
SPP (psi)
3500.0
5 7/8" Drillpipe
3000.0
2500.0
6 5/8" Drillpipe
2000.0
1500.0
600
650
700
750
800
850
900
950
1000
Flowrate (gpm)
1,100
LINER SIZES
6 5/8" Drillpipe
1,000
5 7/8 Drillpipe
7"
5 1/2" Drillpipe
Flowrate (gpm) at pump limits
5" Drillpipe
6-1/2"
900
7"
6-1/4"
800
6-1/2"
6"
700
7"
Assumptions :
6" liner limited to 770 gpm flowrate (90spm), and/or 3736 psi
6-1/2" liner limited to 900 gpm flowrate (90spm), and/or 3184 psi
7" liner limited to 1045 gpm flowrate (90spm), and/or 2744 psi
Mud Rheology - 52 / 37 / 28 / 22 / 16 / 10, MW - 10.5ppg
BHA pressure drop = 800 psi (motor / MWD)
600
2000
6-1/2"
7"
4000
6000
8000
10000
12000
14000
16000
Depth (ft MD)
Figure: 31
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Drilling Design and Implementation for Extended Reach and Complex Wells
8-1/2" STANDPIPE PRESSURE
3500
Assumptions:
MW - 8.6ppg
Rheology - 47/33/27/22/16/9
FEWD pressure loss 700psi
Bit nozzled for 500-600psi pressure drop for RST
25% rotational correction factor applied
SPP (psi)
3000
2500
2000
1500
300
350
400
450
500
550
500
550
GPM
8-1/2" ECD's
13.0
12.5
5 7/8" Drillpipe
ECD (ppg)
12.0
5 1/2" Drillpipe
11.5
5 1/2" x 4 1/2" Drillpipe
5" Drillpipe
11.0
10.5
300
350
400
450
GPM
Figure: 32
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Following are some general considerations related to drillpipe size and hydraulics planning.
5” vs. 5½”
Upgrading from 5” to 5½” drillpipe will reduce pump pressures significantly, especially if the
larger drillpipe also has large-ID tooljoints. Even for conventional applications, the allowable
flowrates will be increased. This is particularly critical for wells where PDC bits and steerable
motors are to be used in combination, because of the large hydraulics cost and requirements of
these circumstances.
As a benchmark, the upgrade from 5” to 5½” drillpipe is equivalent to installing a 3rd rig pump on
a 20,000 ft ERD well.
Upgrading from 5” to 5½” drillpipe is not usually very difficult. Typically, the fingerboards are
the biggest change-out item. Depending upon tooljoint selection, the setback capacity is not
usually significantly affected.
5½” vs. 65/8” Drillpipe
For large ERD wells, it is often automatically assumed that 65/8” drillpipe is a minimum
requirement, in order to achieve the “industry-accepted” minimum tolerable flowrate
requirements. For example, many believe that at least 1000 – 1200 gpm flowrates are required,
from surface to TD, for high angle 12¼” hole if feasibility is to be assured. If such high flowrates
are indeed required, then it is true that 65/8” drillpipe is necessary.
However, 5½” drillpipe is sufficient for most applications where the drilling strategies are
designed for optimum hole cleaning and a ‘systems’ approach is used throughout. K&M has
repeatedly demonstrated that ERD wells can be efficiently cleaned and drilled at fast overall
ROP, with much lower flowrates than the industry standard.
There are projects that can justify the use of 65/8” drillpipe for hydraulics reasons or possibly for
buckling reasons. Some of the mega-reach ERD wells can justify using 65/8” drillpipe because of
the performance benefit and because the rig has already been purpose built to accommodate such
large drillpipe. Depending upon the well objectives and circumstances, good planning and
drilling practices can make the need for 65/8” drillpipe redundant. The “industry accepted”
minimum flowrate requirements for ERD are largely based upon non-optimum practices and
traditional drilling methods.
The argument that “65/8” is necessary for ERD” (and a 3rd pump to provide the flowrate required)
is often sufficient to kill a project due to cost implications. The rig upgrades cost (and platform
weight and size implications) can be enormous.
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Upgrading to 65/8”drillpipe must consider derrick space, slower connections and increased torque
and drag. The use of 65/8” drillpipe (which is heavier and stiffer than 5½” drillpipe) will generate
higher torque. This higher torque caused many Operators to use pseudo-catenary well profiles,
for reduced torque, which in turn has added considerable angle and depth to the well, further
taxing the hydraulics system.
5⅞” Drillpipe
5⅞” drillpipe is becoming more popular as an intermediate size of pipe between 5½” and 6⅝”.
Many recent ERD projects that have purchased a new string of drillpipe have chosen 5⅞”. The
main advantages with 5⅞” are better hydraulics than 5½”, while not having all the disadvantages
of 6⅝”.
3½” vs. 4” Drillpipe
If ECD’s allow, some consideration should be given to upgrading from 3½” to 4” drillpipe when
drilling small diameter hole. 4” drillpipe will significantly improve hydraulics, as well as
improve torque and buckling performance.
9.2.4.2
Tooljoint Design and Dimensions
Tooljoint designs should use the largest allowable ID to reduce pump pressures and the smallest
O.D. to minimize annular pressures (ECD’s).
5” drillpipe is often ordered with standard S135 specifications. Standard S135 tooljoints have
notably smaller ID than G105 tooljoints (2¾” for S135 vs. 3¼” for G105). In many cases this is
not necessary from a strength viewpoint. The smaller tooljoint ID will have a marked effect on
pump pressures at the high flowrates required on ERD wells. If strength allows, the S135
drillpipe should be ordered with large ID tooljoints.
The larger OD tooljoints of 5½” drillpipe can have a dominating effect on ECD’s, despite their
relatively small combined length. A recent client study found that 7” OD tooljoints (on 5½”
drillpipe) contributed 75% of the ECD load, although they only comprised 2% of the pipe length.
9.2.4.3
HWDP Length
Quantities of HWDP are often run in ERD wells that far exceed their actual requirements. In a
60° well for example, drilling at 7,000 ft MD with 25kips WOB, the neutral point in the string is
somewhere around 3,000 ft MD (i.e. the neutral point is 4,000 ft above the bit). In higher angle
wells, the neutral point will be even further above this. Minimal use of HWDP for transition only
(i.e. one stand either side of the jars), will mean a maximization of the available hydraulics.
9.2.5
BHA Design
Following are some design considerations for maximizing available flowrate in the BHA design.
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9.2.5.1
MWD / FEWD Selection
The type of MWD / FEWD system that is used will affect the surface pressures while drilling and
while circulating off-bottom.
Negative pulse MWD systems require ± 800 psi pressure drop below the MWD tool for adequate
transmission of real-time data to surface on an ERD well. This should be taken into consideration
if hydraulics is a limitation, unless such a pressure drop is already necessary below the MWD for
operation of other systems. Negative pulse systems have faster data transmission rates but, in
general, positive pulse systems are preferred.
Given the long distance that the signal must travel, the attenuation of the pressure pulse should be
allowed for when setting up the MWD. This is especially the case if a SBM is used due to the
fluid’s compressible nature.
9.2.5.2
Adjustable Stabilizers
Hydraulically actuated adjustable stabilizer designs require a certain off-bottom pressure drop
below the tool for operation/actuation. This varies from ± 450 to 800 psi for the tools, but can be
optimized, if required. Since the pressure drop that these tools require for actuation is off-bottom,
it is not valid to utilize the on-bottom motor pressure drop as part of this value. The bit must be
nozzled to achieve the required pressure drop, which means that when the motor is on bottom,
both pressure drops are affecting the system.
Some tools are set on-bottom, and as such require less pressure differential for operation.
Typically, these tools will have a pressure drop of 250 - 450 psi, which is primarily due to a
restriction in the tool, which uses pressure to indicate its position. The pressure/flowrate also acts
to lock the tool into its set position.
9.2.5.3
Rotary Steerable Tools
RST’s are similar to adjustable stabilizers in that they require a pressure drop across the bit in
order to function correctly. This pressure drop will vary between 500 - 1000 psi depending on the
tool used. Additionally, the pressure drop across the tool also needs to be accounted for in
hydraulic calculations (100 - 500 psi depending on tool used).
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9.2.5.4
Steerable Motors with PDC bits
Steerable motors with PDC bits have a significant impact on the surface pressure. K&M client
wells have demonstrated time and again that flowrates must be in the upper flowrate range of the
steerable motor if a PDC bit is to be run efficiently. Operating in the lower flowrate range results
in excessive stalling problems, and WOB/ROP restrictions.
Furthermore, high torque, low speed motors are more effective than are higher speed (lower
torque) motors for use with PDC bits. This is especially true if flowrates and surface pressures
are limited.
It is common for the available hydraulics to be overlooked when selecting a BHA or bit. In
particular, the effective overall pressure drop for a steerable PDC system is often under-estimated.
When slide drilling, the pressure impact of a PDC steerable system is about 1200 - 1500 psi. This
total pressure drop is based on the following:
• Off-bottom pressure differential is ± 200 psi.
• Drilling pressure drop is 600 - 800 psi for high torque (low speed) motors, and 1000 - 1200 psi
for higher speed motors. This is close to the stall pressure for these motors, but is necessary
for a PDC bit run where WOB control is likely to be difficult due to drag.
• The stalling buffer that will be allowed for is 400 - 500 psi+.
9.2.5.5
Steerable Motors with Tricone Bits
Tri-cone bits on steerable systems do not require nearly as much pressure drop, as does a PDC
steerable system, because a tri-cone bit has smaller reactive torque than a PDC bit. Note that this
pressure drop is based on the motor-related pressure differential, and does not include the actual
pressure drop across the bit itself. In fact, with PDC bits having more nozzles than tri-cone bits,
and with those PDC nozzles generally run wide open, the pressure drop at a tri-cone motor
assembly can be higher than quoted below. The major differences are that the stall buffer can be
removed (or greatly reduced) and the bit stays on bottom drilling more efficiently.
Nevertheless, the effective pressure drop for a motor on a tri-cone assembly (not allowing for
TFA differences) is effectively 400 - 600 psi. This is based on the following:
• Off-bottom pressure differential is ± 200 psi.
• Drilling pressure drop is 200 - 400 psi for high torque (low speed) motors.
• No stalling buffer is required for this assembly due to the low reactive torque of a tri-cone bit.
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9.2.6
Bit Hydraulics
It is unusual for bit hydraulics to be considered on ERD wells. In some cases the bit hydraulics
are ignored in order to improve annular flowrates for better hole cleaning, forgetting that good
hole cleaning is of limited value if the bit will not drill. In other cases the bit is nozzled for
excessive HSI at the expense of hole cleaning.
Obviously, bit hydraulics will be dependent upon the actual bit design, the well design, mud
system and the lithology.
9.2.6.1
PDC Bits
Field experience suggests that PDC bits should be nozzled for high flowrates. High bit HSI is not
necessary if high flowrates are available. As long as there is ample flowrate to keep the bit clean
and the mud system is not working to the bit’s detriment (i.e. balling problems), this system will
generally drill beyond the capabilities of the hole cleaning system.
However, if high flowrates are not available, then the bit must be nozzled for at least moderate
HSI (2-3 HHP/in2) in order to effectively clean the bit and cutters. Essentially, good bit
hydraulics for a PDC bit is necessary to get the cuttings away from the cutters. If the flowrate is
sufficient to do this, then the hydraulics system should be designed for maximum flow rate. Flow
rates in excess of 550 gpm in 8½”, 700gpm in 9⅞”, and 900gpm in 121/4”, are representative of
acceptable flowrates for open nozzled PDC’s (dependent upon the lithology and the mud system).
9.2.6.2
Tri-cone Bits
It is K&M’s experience that tri-cone bits must be nozzled for HSI’s of at least 3-4 HHP/in2, and
preferably more. Tri-cone bits still have a definite place in ERD, especially for quality build
sections and correction runs deep in the well. When nozzled this way, the actual surface
pressures will be similar to a PDC assembly. This system will, however, drill more efficiently
without the need for a stall buffer.
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10 ECD MANAGEMENT
10.1 WHAT IS ECD
Equivalent Circulating Density (ECD) can be defined as the additional “mud weight” seen by the
hole, due to the circulating pressure losses of the fluid in the annulus. The following formula can
be used to calculate ECD:
ECD (ppg) = MW (ppg)
+
Annulus ΔP (psi)
--------------------0.052 x TVD (ft)
The main variable in this equation is annular pressure loss. This is affected by the following
factors:
•
Length of annulus or well
•
Annular clearance
•
Flowrate
•
Mud properties
•
Rotation of the pipe (refer to Section 10.1.1)
•
Swab and surge pressures
Surge pressures are often not accounted for in designing wells. They result from tripping casing
and drillpipe in the hole, and can cause very high ECD’s. Figure 33 below highlights the effect
that surge pressures can have on the formation.
Swab pressures are seen when pulling out of the hole and act in the opposite direction to surge
pressures. Although they counteract ECD’s, they can also be damaging to a wellbore, as they will
contribute to the fatigue stresses seen by the borehole wall.
The magnitude of swab and surge pressures will depend on the following:
•
Speed of the pipe
•
Viscosity of the mud
•
Flow-by area around the BHA or casing.
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Fracture
LOT
FIT
Surge
Drilling ECD
Mud
Pressure
Figure: 33
Effect of Surge Pressure
10.1.1 ECD and pipe rotation
The literature reports a relationship between ECD’s and pipe rotation in small hole sizes (≤ 8½”
hole). PWD have reportedly shown that ECD’s are increased on long wells when pipe rotary
speed exceeds 50 rpm. This is likely due to the increased distance that the fluid must travel to
surface due to a ‘spiraling’ flow path when pipe rotation is high (see Figure 34 below), and to a
lesser extent due to improved hole cleaning. As such, any hydraulics model will under-estimate
the annular pressure drop as it assumes that fluid movement is ‘straight up the hole’ rather than
spiraled. This can be critical if ECD’s are borderline (say for losses in the reservoir or wellbore
stability of brittle coals). As such, hole cleaning parameters (flowrate and pipe RPM) may have
to be compromised together if ECD’s are critical.
To account for pipe rotation in an eccentric hole, with conventional Herschel-Bulkey hydraulics
models, increase the travel distance by ± 25% (depending on the pipe RPM speed). That is,
increase the MD depth by 25%, while maintaining the same TVD depth. This 25% increase
corresponds with field results.
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High speed pipe rotation will cause fluid to spiral as it moves up the hole. This
increases the distance that the fluid must travel, and therefore increases ECD’s.
This occurs mainly in small hole sizes (i.e. 8½” or less).
Hydraulics models will not account for this, and will therefore underestimate ECD’s in
small hole sizes
Figure: 34
ECD Increase due to Pipe Rotation
10.2 WHAT ARE THE EFFECTS OF ECD
•
High ECD’s increase the risk of lost circulation, especially while (a) drilling 8½” or smaller
hole size, or (b) while running or circulating long casing strings. Further, reservoir damage
can be a side effect if ECD's are not minimized.
•
Wellbore instability can be caused by the constant flexing and relaxing of the wellbore when
the pumps are turned on and off. This is particularly the case if the formation is brittle (such
as coals or brittle shales).
Effectively, the wellbore is failed through fatigue, as would a paper clip when bent back and
forth. A paper clip can be bent back and forth once or twice without breaking, even if it is
bent quite severely. It will, however, break due to fatigue failure if it is bent enough times.
The time to failure is dependent upon (a) how severe the bending is, (b) how many times it is
bent, and, (c) the strength and elasticity of the material. It is the same with the wellbore and
ECD fluctuations. The wellbore can eventually fail, depending upon the lithology, and the
size and frequency of ECD fluctuations.
•
Casing collapse can be initiated by ECD’s while running buoyancy assisted casing strings on
long, deep ERD wells. Casing collapse calculations should account for the increased annular
pressure due to ECD’s while running casing, rather than just for a static on-bottom scenario.
Long mud-over-air casing flotation jobs have experienced collapsed casing due to the running
ECD’s alone.
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•
Surge pressure creates a “piston force” that behaves like drag. This can be critical for
marginal casing runs.
•
An indirect effect will be the impact on hole cleaning if losses are encountered due to ECD’s.
In an effort to reduce losses, flowrates will be reduced. This will result in poorer hole
cleaning and a build up of cuttings in the hole. In turn, ECD’s will become worse and a
vicious cycle is started.
•
The reduction in flowrate will also have a negative impact on torque and drag, and drilling
performance (less than ideal bit and motor performance at reduced flowrates).
10.3 WHY IS ECD A PARTICULAR CONCERN FOR ERD
ECD’s are generally a more significant issue on ERD wells than for conventional wells. This is
due to the following:
•
Long measured depth intervals relative to the vertical depths (refer to Figure 35)
•
ER wells are generally shallow by their nature. The shallow-type ERD wells are particularly
prone to ECD problems as their formations are often so shallow as to have little integrity.
•
ER wells generally use larger diameter drillpipe for hydraulics or buckling reasons.
•
More aggressive parameters (flowrate and rpm) are generally required for hole cleaning.
•
Longer exposure times with long intervals on ERD wells.
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1
Casing @ 10,000’ MD / 4000’ TVD
ECD = 11.7 ppg
2
3
4
5
Same 10 ppg mud & 350 psi annulus ΔP in both wells
6
ECD is much greater in shallow-TVD ER well
than vertical well at same MD
7
8
9
Casing @ 10,000’ MD/TVD
ECD = 10.7 ppg
10
11
0
1
2
Figure: 35
3
4
5
6
7
8
9
10 11 12
ECD Comparison at Different TVD’s
10.4 EXAMPLES OF ECD MAGNITUDES
In order to appreciate the importance of ECD management, it is first important to gain some
understanding of the magnitudes of ECD fluctuations that can occur in ERD wells.
Most of the following scenarios are supported by PWD measurements and will be dependent
upon fluid properties and flowrates. The quoted drilling pressure fluctuations are based on a
typical OBM suitable for hole cleaning in ERD wells, with 450 – 550 gpm flowrates, with pipe
rotation. As will be discussed later, careful planning can reduce the ECD pressure loads
significantly.
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WELL CONDITIONS
ECD MAGNITUDE
Example #1:
At 26,000’ MD (7,900m MD)
9,060’ TVD (2,750m TVD)
In 8½” hole, inside 9⅝” 47 ppf casing
•
Example #2:
As above, but shallower TVD
At 26,000’ MD (7,900m MD)
6,500‘ TVD (2,000m TVD)
In 8½” hole, inside 9⅝” 47 ppf casing
•
Example #3:
Very Shallow ERD Well
At 6,500’ MD (2,000m MD)
1,900‘ TVD (580m TVD)
In 8½” hole, inside 9⅝” 47 ppf casing
•
Example #4:
As above, but 6” hole size
At 6,500 ft MD (2,000m MD)
1,900 ft TVD (580m TVD)
In 6” hole, inside 7” 26 ppf casing
•
•
•
•
•
•
•
•
•
Drilling with 5” dp
Drilling with 5½” dp
Running 7” NV liner
Circulating 7” NV liner
ECD = 3 – 4 ppg
ECD = 4 – 5 ppg
ECD = 2 – 3 ppg
ECD = 3 – 5 ppg
Drilling with 5” dp
Drilling with 5½” dp
Running 7” NV liner
Circulating 7” NV liner
ECD = 4.2 – 5.6 ppg
ECD = 5.6 – 7 ppg
ECD = 2.8 – 4.2 ppg
ECD = 4.2 – 7 ppg
Drilling with 5” dp
Circulating 7” NV liner
ECD = 3.0 – 4.5 ppg
ECD = 4.5 – 5.0 ppg
Drilling with 3½” dp
Circulating 4½” NV liner
ECD = 4.0 – 5.5 ppg
ECD = 4.5 – 5.0 ppg
10.5 ECD MANAGEMENT – PLANNING PHASE
There are numerous options to help reduce ECD’s on ERD wells. Although not applicable for all
well types, the following examples are given as possible solutions to well designs if ECD’s
become critical.
The usual industry practice is to treat ECD’s as an after-thought. Unfortunately, just like
hydraulics and buckling issues, there is little that the field personnel can do to reduce ECD
problems at the rig-site, unless the well has been specifically designed with ECD minimization in
mind. It is important to note that the only real solutions for reducing ECD induced problems
are in the planning phase.
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10.5.1 Wellpath Design
The wellpath trajectory directly affects the total depth that must be drilled, and therefore directly
affects ECD’s at depth. Further, the trajectory affects the casing design to be used (e.g. a catenary
design will increase wellbore angle, and may therefore require an additional casing string for
stability or other requirements). A secondary related issue is possible mud weight implications
for a given wellpath. Increased mud weight (say, to compensate for higher angle) will increase
annular pressure fluctuations.
The wellpath should therefore be as short as possible, within the confines of other design
parameters (such as torque and drag, wellbore stability).
10.5.2 Hole Size Optimization
Standard hole sizes (i.e. 8½” hole through 9⅝” casing) are not necessarily optimum for ECD
management. There is usually scope for hole size optimization on very shallow ERD wells, given
that hole cleaning is more manageable (because of shorter well length and usually excess rig
hydraulics capability).
For example, increasing the hole size from 8½” to 9⅞” increases the annular area by 53% for 5”
drillpipe, and 108% for 7” casing. Hence, ECD’s can be dramatically reduced by upsizing from
8½” to 9⅞” hole. Longer wells are less able to upsize the final hole sections because this would
require the already-difficult-to-clean large hole sections to be even larger.
Alternately, use lighter weight intermediate casing strings, where possible. For example, 9⅝” 40
ppf casing could be used instead of 9⅝” 47 ppf casing. This would increase the cased hole
diameter from 8.681” to 8.835” (it would also allow 8¾” hole to be drilled instead of 8½”, if the
casing is special drift). This might not sound like much of an improvement. However, the
annular area around a 7” tooljoint has increased by more than 10%. Given the dominance of
tooljoints in ECD impact in 8½” hole size, this may be critical.
The same logic applies for 6” hole. Upgrading from 7” to 7⅝” casing will allow 6¾” hole to be
drilled instead of 6” hole. This will have a significant benefit on ECD’s, and even allows 4”
drillpipe to be used (with less ECD impact than 3½” drillpipe in 6” hole). Even if such large hole
sizes cannot be used, using 61/8” hole size (allowed by running 7” 26 ppf casing instead of 29 ppf
casing) can still have an important ECD benefit.
Another option is to drill with bi-center bits or string-reamers. This will provide improved
annular clearance in the openhole interval. However, this does not address the long section of
cased hole, which may dominate the ECD’s effect.
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10.5.3 Casing Plan
The casing plan can be adjusted in several ways to reduce ECD’s when drilling the deeper hole
sections.
10.5.3.1 Run Intermediate Casing as a Liner
Running the intermediate casing as a liner (instead of as a long string of casing) should be
considered if ECD’s are prohibitive for (a) circulating and cementing this casing string or (b)
drilling the next hole section. For example, the 9⅝” intermediate casing could be run as a liner,
and then tied-back (if necessary) after drilling the 8½” hole.
Obviously, this approach adds complexity to the well plan, and should not be considered lightly.
Hole cleaning in the large diameter ‘upper’ hole section should be thought through carefully,
since flowrates will probably be limited by the downhole tools (i.e. flowrate through an 8½”
bit/BHA is likely to be limited to 600 gpm by MWD/motor restrictions).
Also if high torque is a significant problem in the production hole, then the liner solution may be
ideal. Under these circumstances, Non Rotating Drillpipe Protectors (NRDPP’s) or Roller
Bearing Subs may be considered to reduce drilling torque. Having the larger hole size above the
liner top will allow the safe use of these torque reduction tools with minimal effect of ECD’s.
10.5.3.2 Use Alternative Casing Connections and Centralizers
The casing connections and/or centralizer type can have an influence on the downhole pressure
while running or circulating casing. This is especially the case if any balling or cuttings
accumulation occurs around these items. If ECD related problems are a concern while running or
circulating casing, then alternate centralizers and/or connections should be considered.
Reducing the number of centralizers to the minimum required for cementing objectives is the first
step to ECD minimization. If pipe rotation is not being utilized, then semi-rigid (double bow)
centralizers will reduce the ECD effect compared to solid body centralizers. Note that double
bow centralizers are recommended over ‘conventional’ bow centralizers because they are (a)
stronger and (b) have reduced running drag.
The use of flush or near-flush connections will reduce ECD’s, especially if the annular clearance
between the casing strings is small. For example, if 10¾” casing is run inside 13⅜ casing, the
annular clearance around the couplings is improved by 125% by using a Hydril 521 connection
rather than an LTC or BTC connection (Assuming 133/8” 68 ppf casing with 10¾” casing inside).
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10.5.3.3 Use different sizes of casing
Simply using smaller casing sizes may have significant benefits. For example, rather than
running 7” liner in 8½” hole, consider the use of 6⅝” liner (i.e. still allows 6” contingency hole
size below). This will reduce the ECD while running and cementing the liner; often the highest
ECD’s seen in the well.
10.5.3.4 Casing Flotation and ECD
Another ECD issue that is often overlooked on these wells are the ECD’s created while running
casing. This can be an issue when running long strings of 9⅝” (or other) casing using a selective
flotation technique. The collapse pressure may be acceptable in a static situation, but the running
ECD’s may be sufficiently large to collapse the casing.
When considering collapse, a dynamic scenario should always be considered, rather than a
static situation.
To consider the dynamic situation, determine the fluid displacement rate while running casing.
This rate becomes an effective flowrate and can be used in a standard hydraulics calculation.
10.5.4 Drilling Fluids
Drilling fluid selection and design is an important element for effective ECD management.
10.5.4.1 Rheologies
Careful attention should be paid to fluid properties for any ERD application. If ECD’s are
critical, the fluid should be as thin as possible within hole cleaning restraints, and then further
thinned prior to running and cementing casing. In particular, the fluid should have very good
shear thinning capability. It may be necessary that hole cleaning properties take a back seat to
ECD management with practices adopted to allow for this shortcoming.
Recent PWD runs on the North Slope of Alaska have confirmed downhole ECD fluctuations as
high as 5 ppg EMW when rotary drilling. In this case, the mud was a quality OBM system
designed for optimum hole cleaning. Due to significant ECD induced wellbore stability problems
and occasional lost circulation, the mud system was purpose designed to minimize ECD’s, while
still maintaining hole cleaning capability. PWD measurements showed the thinner mud system,
with lower gel strengths, to have ECD’s of about 1.5 ppg EMW when rotary drilling (a 3.5 ppg
EMW reduction). Although hole cleaning performance may have been compromised in theory,
the new mud was adapted to make up the difference by providing better hole condition and
practices.
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10.5.4.2 Gel Strengths
If ECD problems are a concern, designing, tracking and maintaining good gel strength properties
is critical. In particular, if lost circulation is a concern, then the method of breaking circulation
after a trip is a critical point. ECD surges on PWD recordings can be significant when circulation
first commences. Instantaneous pressure surges of 3 – 5 ppg EMW have been observed.
In conjunction with improved practices, the gel strengths should be designed for easy break
down. Ideally, the gel strengths should be relatively flat and easily broken when the fluid is
sheared (either by pipe rotation or by circulation).
Understanding gel strength performance at varying temperatures and pressures can also be
important to designing effective practices, which minimize ECD effects. This is more of an issue
for SBM systems.
Ester based and PAO systems in particular, have been observed in client wells to cause problems
when breaking circulation after a trip due to cooling of the mud in the riser and in the upper hole
section. This has brought about the practice of staging circulation into the hole in order to
prevent expensive ECD related losses. If ester systems are preferred for a deepwater location,
then a mixture of I-O and Ester may be optimum. The I-O component reduces temperature
gelling, while the ester may result in an environmentally superior fluid.
10.5.4.3 Sweeps
Sweeps are a part of our drilling culture from vertical wells that have made there way into most
other drilling operations. In high angle wells, sweeps have proven largely ineffective at bringing
cuttings out of the hole. Sweeps elongate along the high side of the hole, and with high-speed
rotation, have the capability of carrying large amounts of cuttings over a given distance (relative
to the standard drilling fluid). We don’t generally see an increase in cuttings returns at the time
the sweep is due to return and the sweep is rarely in tact when it reaches the surface.
This ability to carry large volumes of cuttings (even for short distances) is a concern from an
ECD perspective. Large annular pressure spikes, which dissipate over time, suggest that as the
sweep enters the annulus, high speed rotation picks up the cuttings and the sweep has the ability
to carry this high volume, thus creating a spike in annular pressure.
In general, we do not advocate the use of sweeps in directional wells. If they are required,
however, their use should take into consideration the possible effect of ECD’s on the exposed
formations.
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10.5.5 Drillstring Design
The drillstring design often plays a critical role in ECD management, especially on very shallow
ERD wells where (a) there is little formation integrity, and (b) large OD drillpipe is required to
overcome buckling problems.
Regardless of the well type, the drillstring design should always be scrutinized and optimized if
ECD’s are an issue.
For hole sizes larger than 8½” (i.e. 9⅞”, 12¼”, and larger), the choice of 5”, 5½” or 5⅞” drillpipe
will have minimal direct effect on ECD pressures and annular velocities. It is in 8½” hole size,
however, that ECD effects quickly become a significant issue. The relatively small annular area
is very sensitive to tooljoint and tubular diameters, especially when a cuttings bed is present to
further reduce annular area.
If ECD’s are a problem in the production hole, one effective approach is to use a tapered
drillstring to reduce annular pressure drops. ERD projects may require three or more separate
drillstring sizes (4” x 5” x 5½”) to manage ECD fluctuations, while maintaining the necessary
torque and hydraulics capabilities. In these particular wells, normal pumping operations would
have generated circulating annular pressures that exceed the fracture gradient. A purpose
designed mud system, a tapered drillstring and a tapered casing plan would all help to reduce
these pressures.
Tooljoint selection is also critical to ECD’s. As already mentioned, in 8½” hole, the tooljoint
clearance is quite small and will have a significant effect on annular pressures. Hole sizes larger
than 8½” are not as sensitive to tooljoint size.
It is common to apply HWDP or larger OD drillpipe in shallow ERD wells to overcome buckling
problems. Alternately, the drillpipe can be stiffened by the addition of Non Rotating Drill Pipe
Protectors (NRDPP’s). If NRDPP’s or larger OD drillpipe is used, then the ECD effect should be
allowed for. NRDPP’s add approximately 1 psi per unit, as a general rule. An option may be to
use ‘winged drillpipe’ to provide stiffness while not increasing drag (as will occur with HWDP).
The ‘winged drillpipe’ is significantly stiffer while not increasing ECD’s as much as the other
solutions.
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10.5.6 Bit and stabilizer design
The bit and stabilizer programs for ERD wells should be designed for maximum junk slot area.
This is primarily to reduce the risk of tripping problems when pulling through cuttings beds. It
will also reduce the risk of swabbing in a kick when pulling through cuttings beds.
Another important reason to maximize junk slot area on bits and stabilizers is to reduce the
pressure surge when reaming into the hole. PWD measurements show that downhole pressures
when reaming can be surprisingly large. ‘Opening’ up the bit and stabilizer designs will reduce
the magnitude of these surges.
This is a particularly important recommendation for very shallow wells, which may be negative
weight and expect to require rotation to enable tripping into the hole.
Although many engineers focus on the junk slot area of PDC bit designs, stabilizer designs are
often overlooked. In particular, careful attention should be given to the stabilizers on steerable
motors and MWD / FEWD equipment. These items often have much less junk slot area than the
bit. If possible, avoid the use of sleeve stabilizers (common on MWD/ FEWD equipment) and
replace them with integral blade or string stabilizers. This is often possible if planned in advance
with the service company. Clamp-on stabilizers should be avoided, if possible.
10.5.7 Pressure While Drilling (PWD) Technology
If ECD’s are critical, then PWD technology is a worthwhile addition to the BHA plans. PWD
technology will provide Operations and Engineering personnel with valuable information about
what is actually happening downhole with that particular well’s circumstances. Although realtime information is preferred, memory-only information can be used to improve planning and
practices towards the reduction of ECD problems. It is important to analyze both depth-based
and time-based logs.
10.6 ECD MANAGEMENT – OPERATIONAL PHASE
10.6.1 Flowrate and RPM
Reducing flowrates is generally the first option if ECD’s are an issue. It is important that any
reduction in flowrates is within the hole cleaning limitations of the drilling ‘system’. As
discussed in the ‘Hole Cleaning’ section, the minimum allowable flowrate will be dependent
upon many factors, such as mud rheology, rpm, slide frequency, hole size, ROP and other
practices.
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As discussed in Section 10.1.1, pipe rotation also affects ECD’s, especially in 8½” hole or
smaller. As with the flowrate above, reducing pipe rpm is also an option to lower ECD’s.
If ECD’s are critical, prior to drilling out the shoe, it may prove beneficial to measure the
magnitude of ECD variations with a range of flowrates and RPM’s. This should be done by
completing an ECD matrix with a PWD tool (see example below). Note that the mud will need to
be circulated for an adequate length of time to shear and warm it, and therefore obtain good
quality data.
RPM / GPM
400
500
600
0
40
80
10.6.2 ROP
Downhole annular pressure is directly related to the amount of cuttings that are in the hole (in the
flow regime or in suspension, but not what is sitting on the bottom of the wellbore). The weight
of these cuttings adds weight to the fluid, just as barite does. Hence, the more cuttings that are in
the hole, the higher the effective bottom hole pressure. Therefore, there is merit in controlling
ROP if ECD’s are critical.
10.6.3 Slide Drilling Practices
As explained in the ‘Hole Cleaning’ section, slide drilling results in the build-up of a cuttings
dune immediately above the BHA. Downhole MWD pressure tools have shown that bottom hole
pressure can increase sharply when pipe rotation is initiated after a long slide interval. This is
because of the instantaneous lifting of this cutting dune into the flow regime. There is also
increased risk of packing off during this time.
If ECD’s are an issue, then slide intervals should be broken up with pipe rotation so as to redistribute the cuttings more evenly up the hole.
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10.6.4 Backreaming
As with slide drilling, backreaming can cause a significant cuttings dune to form, which can
increase bottom-hole pressure (or pack off) if the cuttings dune is disturbed suddenly. This is
particularly true if the well has been circulated out prior to back reaming. Circulating out of the
hole cleans around the BHA, but the absence of rotation allows cuttings to fall out and build up
directly above the BHA. The initiation of backreaming, at this stage, must be done with care.
10.6.5 Down-Reaming
If ECD’s are critical, down-reaming should be avoided where possible. K&M regularly find that
wells that are down-reamed and backreamed deteriorate quickly.
The PWD recorded values when reaming can often be alarming, especially when you consider
that the worst-case values are actually below the bit (i.e. the PWD recorded values are actually
less than those just below the bit when reaming). Furthermore, reaming markedly increases the
risk of packing off, etc.
The best way to insure against having to ream is to ensure that the hole is clean before tripping. If
a cuttings beach (or other obstacle) is encountered when tripping into the hole, there is usually
little alternative to reaming.
10.6.6 Tripping Practices
As mentioned earlier, some mud systems tend to gel up when left static or if allowed to cool
down. If this is the case, it may be necessary to ‘stage’ into the hole when tripping back in. This
requires breaking circulation at intermediate points into the hole, rather than when back on
bottom.
It is a good practice in ERD wells to slowly increase the flowrate from a low level to the
maximum, rather than simply breaking circulation at the planned drilling flowrate. This is true,
as well, for rotary speeds. Whenever the pumps or the rotary are started up, they should be
brought on slowly to ensure a minimum effect on ECD and cuttings loading.
Pipe rotary should be initiated first in order to start the fluid moving in the hole. This will help to
break down the gel strength of the mud and minimize the surging effects as the pumps are
brought on line.
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10.6.7 Summary of ECD Management in Operational Phase
The table below is a summary of ECD management guidelines that apply to the operations phase.
OPERATION /
ECD MANAGEMENT GUIDELINES
EQUIPMENT
PWD
•
•
•
•
•
•
TRIPPING IN
•
BREAKING
•
CIRCULATION
REAMING TO
BOTTOM
Ensure the tool is calibrated with correct TVD's used to calculate ECD
Time and depth-based logs need to be annotated with operations taking place
Logs need to be provided to the appropriate people in a timely manner
Use PWD data to calibrate ECD models and to project ahead
Review time-based memory data for swab and surge while tripping
Use PWD data to maximize drilling parameters while ensuring that the ECD
does not exceed the formation fracture pressure
Be aware of the max allowable pipe speed with pumps on and off. This should
be defined at the well site based on PWD data
• Accelerate pipe slowly to avoid significant surge pressures
• Break circulation at regular intervals on the trip in.
The pumps should be started at as slow a rate as possible and built up to the
drilling flow rate – monitor PWD when data is available.
• If high ECD is a concern (confirm on PWD), consider starting drill pipe
rotation (10-20rpm) before starting up the pumps.
•
This is the worst case for surging the formation – avoid where possible.
• Break circulation as above and ream down carefully to avoid surging. Where
there are ECD concerns, ream using lower flow rates than while drilling.
• Reaming rate is to be determined at the well site based on ECD considerations.
BACK ON BOTTOM • Once on bottom after a trip, break circulation as above
•
Do not start drilling until the PWD indicates that the ECD has returned to
background levels.
DRILLING AHEAD • Minimize mud weight
•
Maintain low values for PV and LGS
• Monitor PWD readings and adjust parameters accordingly
MAKING
CONNECTIONS
TRIPPING OUT
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•
Surge pressures are important at connections and while tripping. The ECD
from circulating is combined with the surge effect. Pipe rotation will also
increase ECD.
• Back-ream each stand once to remove cuttings from around the BHA.
• Minimize speed while washing back down to bottom.
•
Ensure that maximum allowable trip speeds are known in both the open and
cased hole, with and without pumps on.
• Ensure the pipe is picked up slowly to limit the initial swab effect.
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OPERATION /
ECD MANAGEMENT GUIDELINES (CONT..)
EQUIPMENT
PUMPING SWEEPS • Should be avoided as sweeps can pick up large amount of cuttings that cause
pressure spikes and may fracture the formations.
BACKREAMING
•
RUNNING LINER
•
Keep a close watch on PWD and adjust parameters accordingly
• Break circulation and at the same time the string is picked up to avoid surge
pressures
• Back-reaming should be avoided where possible
Running speeds should be based on PWD memory data recorded while drilling
and tripping and the calibrated ECD model
• Lower mud rheology prior to POH with the last BHA
• Start and stage mud pumps up slowly
Small changes in pump pressure have a great effect on the well bore.
Break circulation and move pipe SLOWLY
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11 DIRECTIONAL DRILLING STRATEGIES
As discussed previously, the directional drilling strategies are vital components of the overall
drilling ‘system’, and in particular, the ‘hole cleaning system’. In fact, the directional drilling and
bit selection strategies are so important that it is the authors view that these aspects cannot be
treated simply as individual 3rd party services.
All too often, the bit and BHA selection is given too little thought as part of the ‘big picture’. Bit
selection decisions are usually based on instantaneous ROP, longevity, ‘cost/foot’ or sometimes
steerability. BHA selection is often based on required dogleg severity, ability to drill to TD in
one bit run, and sliding ability.
A BHA strategy should be developed that considers the key issues of the overall drilling and
hole cleaning system.
11.1 PRIORITIES FOR DIRECTIONAL DRILLERS
Before discussing the technical and practical issues, it is first important to discuss the priorities
and expectations for the directional drillers. Furthermore, these priorities and expectations must
be the same for the Operator’s personnel (both on-site Drilling Supervisors, as well as office
planning staff).
The traditional performance criteria upon which a directional drillers performance is judged, is
not conducive to good hole cleaning performance, or for “efficient” drilling. A directional driller
is expected to have (a) followed the planned wellpath as close as reasonably possible, and (b)
intersect the target(s). This in turn results in excessive slide drilling and a wellpath that is more
tortuous than necessary. Furthermore, the bit and BHA strategies are also locked into “steerable
BHA’s and whatever bit can be made to work”.
This commentary is not meant to be a criticism of directional drillers as these performance
expectations are generally those of the Operator. As such, ‘what the customer wants, the
customer gets’. Even if the directional driller knows that the best and most efficient method for
drilling an ERD well is not to “chase the line”, there is only so many times that he (or she) will
challenge the opposing views of a ‘traditional’ company man.
It is important that all parties are in agreement with respect to the directional drillers priorities,
including the company geologists and reservoir engineers. Their priorities should be to:
1. Intersect the target(s), with as smooth a wellbore as reasonably possible. Minimum dogleg
severity (both individual doglegs and cumulative) is key to minimizing torque, drag and
buckling problems.
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2. Pro-actively maintain good hole cleaning environment throughout the drilling process. This
involves planning BHA’s that will maximize rotary drilling and allow high continuous rotary
speeds. This includes using BHA’s that allow the hole to be cleaned up properly prior to and
during trips, with high speed, continuous rotary speeds. Furthermore, it is vital that BHA
planning take into account the rig’s capabilities, particularly hydraulics.
3. Drill a smooth, accurate build section, as this is critical for future torque and drag
management. Time and cost should be secondary priorities here. Sliding frequency and time
should be based around the long-term benefit, and not ROP.
11.2 PLANNING BHA STRATEGY
There is no substitute for including detailed BHA analysis in the well planning. In particular,
planning bit/BHA strategies for each individual well that are fit-for-purpose, appropriate, and that
consider the “systems approach for the big picture”, will reap performance rewards. Often a
multi-well program will have either subtle or significant differences in each well design.
However, the easy approach is often to use the “off-the-shelf solution that fits all”. If no planning
resources are available, then this latter approach is inevitable.
In order to define the BHA strategy for an ERD well, the following steps should be considered in
the planning process:
1. Identify the key issues on the well as a whole. This will give a big picture view of the
well, and allow key issues in the following step to be inter-linked.
2. Break the well up into hole sections and identify the key issues in each hole section. A
series of key issues are discussed in the following sub-sections. Note that not all of the
issues will apply to all hole sections.
3. Design BHA strategies around these key issues. Using the issues identified above as the
base for planning, investigate the different alternatives for each hole section (refer to
Section 11.4).
4. Ensure that other general BHA, bit and surveying issues have been considered
The goal is to design a directional strategy that complements the ‘system’, and not simply to
‘hit the target’ or ‘follow the line’.
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11.2.1 Key Issue – Hole Cleaning
How difficult will hole cleaning be in this particular section? This will depend on the hole size,
the mud system in use, the specific lithology to be drilled, the rig capability and the bit and BHA
strategy.
The BHA strategy should consider the following hole cleaning issues:
•
Flowrate and rpm are the keys to effective hole cleaning. How will these two parameters be
affected by the assembly in the hole?
•
No cuttings are likely to be removed from the hole while slide drilling, and although these
may be removed after returning to rotary drilling, it will now be more difficult to maintain
good hole cleaning as the hole has been loaded up with cuttings when sliding. It is always
harder to get back on top of the situation after it has been allowed to deteriorate.
•
Larger hole sizes are more difficult to clean. Therefore slide drilling or reduced parameters
are more easily tolerated in the smaller hole sizes.
•
Dispersive mud systems do not require as stringent hole cleaning practices if the formation is
also dispersive. For example, if drilling dispersive clays with a dispersive mud, then hole
cleaning may be a non-issue as the rock will predominately dissolve into the mud. This
explains how large diameter, high angle surface holes can often be drilled without problems
despite poor hole cleaning parameters.
On the other hand, if the same hole section must then drill a long interval of non-dispersive
formation (such as sand or limestone), then hole cleaning may become critical. This will
certainly be the case if the hole has enlarged further due to dispersion.
Highly inhibitive mud systems will require good hole cleaning practices, since little dispersion
will occur. This is, generally, lithology dependent.
If the hole cannot be effectively cleaned with the proposed BHA, it should not go in the hole.
11.2.2 Key Issue – Hydraulics
Is there sufficient hydraulics capability to efficiently drill with the proposed bit and BHA? This is
especially important if a PDC and a steerable motor combination is to be used. Hydraulics
planning must assume that up to 1200 – 1500 psi of incremental pressure is required for motor
operation with a PDC bit in slide mode (Refer to Section 9.2.5.4).
This is a factor that rarely seems to be considered in advance of drilling, regardless of well type.
Too often we have seen sub-optimal hydraulic conditions seriously affect bit/motor performance.
This leads to frequent wiper trips, multiple bit changes (often resulting in the mistaken conclusion
that “you can’t drill with PDC bits in this section”), motor change-outs and poor ROP.
Ensure BHA design accounts for the hydraulics capability of the rig and the resulting impact
on hole cleaning.
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11.2.3 Key Issue – Directional Control Required
Will directional control be required for inclination or azimuth (or both) in order to achieve the
target objectives? This is generally a function of the target location, shape and size (remembering
that at high angle-of-attack the target is usually much wider than it is ‘deep’ - see Figure 47).
Also, is a steerable system planned for use in the next section anyway? If so, is it necessary in
this section? This is particularly pertinent if a steerable BHA is being argued for azimuth control.
The requirement to have azimuth control in tangent sections will often drive Operators to use
steerable assemblies from the start. However, experience worldwide has shown that less than 5%
of slide drilling is used for azimuth control in tangent sections. Rotary assemblies with adjustable
stabilizers should generally be the first choice for tangent sections, with steerable or RST
assemblies being justified on a technical or commercial basis, if required.
It is essential that every assembly run in an ERD well have a fully developed contingency as a
backup. These contingencies should be available on the rig and ready to run in the case that the
primary plan is not successful. In particular, Operators often ‘put all their eggs in one basket’
with RST’s and have been caught out with no backup due to tool failures or a lack of success in a
particular application.
Any BHA recommendation for drilling a long tangent section should be supported with detailed
offset well performance. The directional drilling company should be keeping detailed reports that
highlight all directional drilling issues (trends, slide performance, slide direction, slide frequency,
slide results, rotary results, etc.).
The BHA strategy must allow adequate directional control to achieve the target objectives
efficiently, while still addressing the other key issues of the ‘system’.
11.2.4 Key Issue – Tortuosity
How will the BHA affect the cumulative dogleg and overall tortuosity of the wellbore?
Tortuosity is a measure of how “wiggly” the wellbore is, or the cumulative dogleg. In a normal
directional well, the tortuosity will probably not be critical in affecting future operations.
However, in a long, high angle ERD well, tortuosity in the upper hole sections will have a
significant impact on torque and drag in the lower hole sections.
Sliding and surveying practices will often hide tortuosity. This is clearly shown in Figure 36
below. Tortuosity can be minimized with the use of rotary assemblies or RST’s, or by breaking
up slide intervals with motors. Also, the use of At-Bit-Inclination on motors, and continuous
surveys helps to minimize doglegs and overall tortuosity. Consideration could also be given to
drilling a pilot hole as directional control is generally improved in smaller hole sizes (may also be
required for tool sizes).
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• Big-bend motors usually drop while rotating
• Slide 1, rotate 2 pattern
• Survey every 3 singles
Su
Po rvey Rota
int
te
Sli
de
Su
R
Po rvey ota
te
int
Sli
de
Sliding Pattern May Hide Tortuosity
Figure: 36
• DLS = 0°/100’
(NOT!)
Sliding Pattern Hiding Tortuosity
11.2.5 Key Issue – Torque, Drag and Buckling
Are there any Torque, Drag and Buckling issues that must be considered? This is particularly
relevant for a steerable BHA strategy if buckling or high drag means that slide drilling will be
inefficient or difficult (i.e. motor stalling or a loss of toolface).
The issues may not even apply to this particular hole section. As mentioned in the previous
section, it may be that the tortuosity associated with this hole section will be particularly harmful
for the drilling or casing runs in the next section. This is a common concern in ERD wells where
solutions that solve today’s problems may be to the detriment of the long-term product.
11.2.6 Key Issue – Bit Selection
Does the bit selection have to be compromised in order to provide “good steerability”? This
usually means that a rock bit is run, or a much heavier set PDC bit is used than would otherwise
be necessary. Rotary ROP’s are therefore compromised. Many operations run motors to improve
ROP, forgetting that the benefit gained by higher RPM can be lost by using heavier set bits.
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The use of heavier set bits has other negatives that should be considered:
•
Junk slot area is reduced and good bit hydraulics become even more critical than for more
open bit designs. If flowrates are already limited, then this may not be tolerable. The result
will be (a) reduced ROP and possible bit balling, and (b) reduced hole cleaning ability if
flowrates are further reduced.
•
The ‘shape’ of the junk slot area is also important. For example, full spiral wrap blades, or
full wheel bits may have similar junk slot area as a given straight bladed bit. However, these
bits are much more likely to experience cleaning and tripping problems.
•
The reduced junk slot area makes tripping more difficult. Effectively the bit acts as a plunger
when being dragged through the cuttings bed. The lower the junk slot area, the thinner the
cuttings bed must be to allow acceptable tripping. This may result in slower trips and
possibly more time performing remedial hole cleaning operations during trips (i.e.
backreaming). This is important if hole cleaning capability is limited.
11.2.7 Key Issue – Overall Drilling Cost and Efficiency
Some Operators have become dependent upon the use of steerable motors and/or the “one BHA
to TD” mentality without necessarily realizing the operational cost of doing so. In fact, the use of
steerable systems may never even be questioned. In some applications the steerable motor is
ideal, however, on long tangent sections it may be more efficient to drill with “adjustable rotary”
BHA's, making deep correction runs to correct for bit walk, if necessary.
A good analogy is car racing. For short distance ‘sprint’ racing, planned pit stops (for refueling
and tire change-outs) cannot be justified. For long distance races, however, the car racing teams
will actually plan to make one or more pit stops to refuel and to change-out the tires. This is
despite the fact that they could, if desired, start the race with sufficient fuel and use very hardcompound tires that will allow them to avoid pit stops. Why would they therefore start with less
fuel and soft compound tires, when it means that they will have to make a pit stop?
Because, the overall result is faster.
The same applies to ‘long distance’ drilling, as opposed to ‘short distance sprint’ drilling. As the
example in Table 1 clearly shows, multiple ‘fit for purpose’ BHA runs may be comfortably faster
than the one-BHA-to-TD strategy.
The importance of this concept is even more critical, if any of the following factors are relevant:
•
Does the quality of this hole section compromise the results or difficulties in subsequent
sections? A classic example is the build section of an ERD well. Inappropriate practices in
this section can have significant torque and drag ramifications later in the well. In attempting
to save 8 - 12 hours by using one BHA to TD in the surface hole, you may be risking many
days later in the well. The surface hole on an ERD well is not the place to take short cuts.
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•
Do the rig’s hydraulics capabilities diminish with depth? For most rigs, it is likely that
flowrates will be significantly less at TD than at the start of the section.
•
If the lithology varies significantly through the hole section, the suitability of bit/BHA
strategies must take this into account.
•
Are wiper trips likely or programmed? These should be incorporated into the bit/BHA
strategy. Again, continuing with the racing car analogy, a wiper trip may be analogous to be
forced to come in for a precautionary replacement of the brake pads. Given that you are
already in the pits, this is an ideal opportunity to take a few extra moments to change out the
tires and refuel as well.
•
Is a bit trip likely or programmed? This is particularly pertinent if tri-cone bits are being
used, and are being pulled on hours (or revolutions). Under these circumstances, using a oneBHA-to-TD approach (e.g. using the same steerable motor BHA throughout the section) may
be analogous to starting the race with a very heavy fuel load that is sufficient for the entire
race, despite knowing that you will be making multiple tire changes anyway. The extra
weight at the start of the race, due to the excess fuel, will result in slow driving in the first
half of the race, and probably excess wear and tear on the car.
•
Is reliability of all components such that the ‘long distance race’ can be realistically run with
the proposed strategy? The cost per foot economics will be very different if the chance of
success of a one-run-to-TD strategy is only 20% instead of 80% (based on previous bit, BHA,
MWD / FEWD or other tool reliability results).
Also, it is important on ERD wells that the most cost effective tools are used (FEWD, MWD,
motors, stabilizers, etc.). This does not necessarily mean the lowest price tools. Reliability and
functionality are a higher priority than the price of the tools. For example, drilling deep in an 8½”
hole may involve a 48-60 hour round trip if a tool fails or does not meet its objectives. It is very
easy to justify a more expensive contractor who has higher reliability in an ERD well. This is
especially true where a high rig day rate is involved.
Equipment availability is also a key issue in BHA selection. This is often seen as an issue with
specialized tools such as instrumented motors, inclination sub, FEWD tools and RST’s.
Advanced planning is a must, and occasionally additional funding will also be required to
guarantee the tools are secured, and aid in the setup of local repair and maintenance facilities.
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Scenario: Drilling a long tangent section at > 60°, in 9⅞” from casing point to TD.
Constraints on drilling:
• Hydraulics is surface pressure limited. Flowrates must be reduced with depth, especially when
slide drilling.
• Formation is quite soft, and PDC drillable. Bit hydraulics is critical to prevent balling.
Occasional harder stringers in reservoir section near TD.
Historical Performance:
Motor stalling and tool face control has been a problem when sliding on high angle wells.
Likewise, WOB is limited when rotary drilling due to motor stalling.
• MWD reliability and pump failures have been problems on previous wells, necessitating several
short or full trips.
Option #1: One-BHA-to-TD Strategy using Option #2: Adjustable Rotary BHA Strategy
Will ideally run to TD in one run, but allow for
Conventional Steerable BHA’s
Assumes heavier set PDC bit is used. Average one short azimuth correction run and then
ROP is based on sliding and rotary drilling resumed rotary run (total 3 runs)
performance.
•
ROP with ‘steerable PDC bit’: 20 m/hr (≈
66’/hr)
Interval: 3500 m (≈ 11,500 ft)
Total on-bottom Drilling Time = ≈ 175 hours
BHA trip time for failure (if required) = 16
hours
Wiper trips (made in lieu of BHA trips not
made). 2 trips at 8 hours each – 16 hours
TOTAL TIME (IDEAL) = 191 hours
TOTAL TIME (1 BHA failure) = 203 hours
ROP with aggressive PDC bit: 40 m/hr (≈ 132/hr)
Interval #1: 2500 m (≈ 8250 ft)
Total on-bottom Drilling Time = ≈ 63 hours
Round Trip for correction run = 16 hours
ROP for short correction run: 10 m/hr (≈ 33/hr)
Interval: 150 m (≈ 500 ft)
Total on-bottom Drilling Time = ≈ 15 hours
Round Trip for correction run = 16 hours
ROP with 2nd aggressive PDC bit: 30 m/hr (≈
100’/hr)
Interval #1: 850 m (≈ 2800 ft)
Total on-bottom Drilling Time = ≈ 28 hours
TOTAL TIME = 138 hours
Table : 1 Economic Analysis for a possible “one-run-to-TD” strategy
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11.3 SPECIFIC MOTOR ISSUES
There are many different issues that must be addressed when selecting the appropriate motor in a
particular application. The issues listed in the table below address specific issues with respect to
motor selection on ERD wells.
ISSUE
ER APPLICATION
SIZE
A motor should be appropriately sized for the hole section being drilled. For 17½” and
larger hole sizes, generally 11¼” motors are used. Many Operators also use 9⅝” motors
in 17½” hole. These motors are not only more flexible than 11¼” (i.e. improved dogleg
capability), but also provide efficiency as they can be run in 12¼” hole as well. Both
9⅝” and 8” motors are suitable for 12¼” hole. 6¾” motors are generally used in 8½”
hole and 4¾” in smaller hole sizes. The final motor selection will depend on many
factors, including those listed below.
LENGTH
In the last few years, extended or performance motors which are longer and more
powerful, have replaced the older standard motors with short power sections. In
general, this move is supported in ERD wells, particularly with the use of PDC bits.
However, standard motors are preferred if run with an adjustable stabilizer behind the
motor, to maximize the effect of the adjustable stabilizer.
NOZZLING
Nozzling of the rotor is an option on motors to increase the flowrate with which they can
be used. This will reduce the available torque and power output, and is generally
acceptable with tricone bits. However, this is not recommended when PDC bits are used
as loads can vary greatly with PDC bits and excessive stalling may result.
BEND SIZE
The motor bend should be minimized when possible. This is mainly due to rpm
restrictions that are introduced with bends over ± 1.0°. These restrictions can have a
significant impact on hole cleaning, particularly in 12¼” hole. It is important to get a
good understanding from the directional company of the ‘true’ rpm limits of their
motors both on and off-bottom. Bigger bend motors also tend to drop inclination more
(i.e. more sliding) unless stabilizer OD’s are carefully selected. For tangent sections, a ±
0.75° bend is appropriate.
ABI
At-Bit-Inclination (ABI) was first used in specialized geosteering applications, but has
become more commonly used in general applications in the last few years. On ERD
wells, ABI has proven very beneficial in shallow build sections, building to horizontal,
and horizontal intervals. As a general statement, all motors run in ERD wells will
benefit from having ABI measurements. They will help to minimize doglegs, the
amount of sliding, and improve overall torque and drag.
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ISSUE
ER APPLICATION
SPEED
Generally, we recommend the use of high torque / low speed motor configurations for
PDC bit applications in ERD wells, rather than higher speed configurations. Often the
directional drilling vendors will recommend higher speed motor configurations (say, 4:5
lobe motors), probably with extended power sections to compensate for the relatively
low torque capability. This is because, theoretically, the higher speed motor will
enhance PDC performance. If rig hydraulics is very good (with very high flowrates
throughout, and no surface pressure limitations), this may be the case.
In reality however, K&M has repeatedly found that torque capability is more important
on these wells, and therefore, we lean toward high torque/low speed motors (say, 7:8 or
9:10 lobes). Firstly, WOB control is relatively poor on high angle wells and therefore,
the motor must be able to accommodate high torque fluctuations. Secondly, the stalling
pressures (and buffers required by the driller) are less for higher torque motors. This is
critical if surface pressures are a limitation. Finally, high torque motors perform better
under less-than-ideal flowrates when PDC bits are used. Most rigs doing ERD work are
subject to significant flowrate and surface pressure constraints.
If tri-cone bits are to be used, then low speed motors are definitely recommended. Bit
RPM is of little benefit, while the higher speed motor simply shortens the bit-life due to
excessive revolutions. With rotary drilling predominates in ERD, and with the high
rotary speeds required for effective hole cleaning, this point becomes even more
pertinent. If an adjustable stabilizer is to be run above a motor, then the motor should be
as short as possible for maximum benefit from the adjustable stabilizer. This will require
the use of low speed/high torque motors, to compensate for shorter power sections.
ROTOR/
STATOR
The motor needs to be set up for the mud properties and temperature that will be seen in
the application it is to be run in. This is not as significant of a concern for shallow
sections drilled with WBM, but deeper sections drilled with OBM will have specific
design requirements for the motor. Stator rubber should be designed to be applicable to
the mud system being used. This requires upfront testing. The interference between the
rotor and stator will also have significant impact on the life of the motor at high
temperature. Ensure that the directional company supplying the motor has designed the
interference fit for the conditions for which the motor will be used. It is not an
encouraging sign to see motor rubber coming over the shakers at the first bottoms-up,
after a 48 hour round trip.
11.4 BHA ALTERNATIVES
Following are examples of possible BHA’s that can be used in different intervals of an ERD well.
As detailed previously, there are many factors that go into the final BHA selection and local
knowledge and experience should be used where possible.
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11.4.1 Shallow Build Sections
Shallow Build Section Option 1 – Steerable (with ABI)
ABI
MOTOR
MWD
This is by far the most common assembly used in shallow build sections, though the use of ABI on these
assemblies has only been a recent addition as the tools become commercially available. Note:
• Generally, tri-cone bits will provide the best directional control. Bit selection will depend on offset data
and the required length of the run.
• The near-bit motor stabilizer should be as close to gauge as possible.
• If ABI is not run, the motor should be a standard power section in order to get the MWD as close to the
bit as possible.
• The motor should have a bend adequate to produce the required build rate with 50% slide`/50% rotary.
• The stabilizer behind the motor should be sized to allow the assembly to build in rotary. In 17½” hole,
this may require a stabilizer as small as 14”. If the assembly is going to be used for a short tangent
section after the build, consideration may be given to running an adjustable stabilizer in this position
though K&M’s experience with this combination is generally bad.
• The ABI function will depend on which directional company’s tool is being used. Some tools have the
inclination sensors built into the bit box on the motor, while other tools come as a separate sub, which is
fitted between the bit and motor. If the sub tools are used, the motor bend should be set slightly higher
than required as the hole will be prone to washing out and build rates will not be as high. In addition,
the sub tool will be subject to high wear and should have adequate protection.
• The inclination provided by the ABI sensors will not be the same as those seen on the MWD, as the
tools will have a slightly different position or angle in the borehole. As such, the ABI measurements
should be used as a ‘relative’ measure and quickly related to the definitive MWD surveys as drilling
commences. Note also that the ABI readings will be slightly different when rotating and sliding.
• The question may be asked, how much of a benefit does the ABI tool really provide to the overall well?
Each application will vary, but it is recommended for wells in which the torque and drag in the lower
sections is critically close to limits (i.e. rig capability, casing running, etc.). The example is given
below of an early application of this technology on a very long ERD well drilled in Australia:
Well drilled to 9278m MD with 70° + tangent section
Used Anadrill AIM tool as a sub between the motor and bit
Allowed a 4.5° dogleg in the surface hole to be easily reamed back to a 2.5° dogleg
Cumulative dogleg in the surface hole was significantly reduced when compared to offset wells
drilled with quality surface hole practices, but without ABI.
This well had lower friction factors for all remaining operations compared to the offset wells.
• This assembly should not be used to drill a long tangent section after the build, as the bend in the motor
will most likely compromise rpm and therefore hole cleaning.
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Shallow Build Section Option 2 – Rotary Steerable Tools
RST
MWD
RST’s have been used to drill hole sizes up to 14¾”. The success of vertical kickoffs is limited, but it has
been done. Ideally, if a kickoff were attempted with an RST, there would already be some inclination in
the hole. The final set up of the BHA would depend on which tool is used and the modeling of the
directional drilling company. Refer to Section 11.5.9 for a general discussion of RST’s.
11.4.2 Tangent Sections
Tangent Section Option 1 – Steerable
MOTOR
MWD
Adjustable Stabilizer
As already discussed, steerable assemblies are not ideally suited to drilling long tangent sections on ERD
wells. However, they may be required or justified in certain applications and the following should be
noted:
• PDC bits will most likely be used as tangent sections and run lengths tend to be relatively long. As
such, sliding will become difficult the deeper the section gets (i.e. erratic toolface and stalling caused by
drillstring friction). If short correction runs are required, a tri-cone bit should be used, as sliding will be
more efficient (i.e. better toolface control).
• Motor bends should be minimized (preferably ± 0.75°). Higher bends will limit the allowable rpm for
hole cleaning and also leads to increased undercutting of the hole in rotary mode (i.e. more sliding).
• Assemblies should be designed to achieve the trajectory objectives with as much rotary drilling as
possible. The same principles of stabilizer spacing and OD apply as for pure rotary BHA’s (refer next
section). However, analyzing the design is more complex since the motor has increased flexibility, and
the near bit stabilizer must be run under-gauge.
• An adjustable stabilizer may be run as the first string stabilizer, but will have limited effect on the BHA
trend if an extended or performance motor is used. It should always be retracted when sliding.
• The motor should be selected to operate at the high end of its flowrate range. If flowrates are not
optimum, high torque motors will perform better (6/7 or 7/8 lobe).
• Avoid making continuous corrections to keep the well on the planned path. Allow the assembly to drill
as long as possible in rotary before making a correction (refer to Section 11.5.7).
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Tangent Section Option 2 – Rotary (with or without adjustable stabilizer)
1st String Stab
NB Stab
DC
2nd String Stab
MWD
Adjustable Stabilizer Options
Rotary assemblies are ideal for long tangent sections as they are simple and reliable and provide the best
conditions for effective hole cleaning. The main limitation is the lack of azimuth control, and limited
inclination control. The choice of an effective rotary assembly requires quality offset data from previous
wells drilled in the same location, and under similar conditions. Following are some general principles for
rotary assemblies:
• The Near-bit (NB) stabilizer and 1st string stabilizer act as fulcrum points and control the inclination
tendencies in rotary mode. Important factors include stabilizer OD and length between stabilizers.
• The 2nd string stabilizer centers the BHA in the hole, making the effect of the first two stabilizers more
predictable, and acts to minimize bit walk and vibrations. This stabilizer is often on the MWD itself
and should be designed for maximum junk slot area. The gauge is not critical.
• Any additional stabilizers will have little or no directional impact.
• Adjustable stabilizers are generally run as the 1st string stabilizer. If run in this position, a hold→build
range will be seen with a FG NB, and a drop→build range with a ⅛” or 1/16” UG NB stabilizer.
• With an adjustable stabilizer run in the NB position, and an UG 1st string stabilizer, the assembly should
have a drop→build range.
• Drillcollars bend around stabilizers due to gravity and the weight applied to the bit. The amount of
bending is governed by the stiffness and length of spacing. Note that stiffness is a function of OD4 (i.e.
8” drillcollar is twice as stiff as 6¾” collars). MWD’s are much more flexible than drillcollar due to
their thin wall. The closer the stabilizers are spaced, the less the bending in between.
• Walking bits can be used to give some measure of azimuth control.
The Following are examples of different rotary assemblies that can be used in tangent sections.
FG
1
Stiff Pony
FG
2
Drill Collar
3
FG – Full gauge
UG – Under Gauge
Packed Assembly: (Hold Inclination and Azimuth)
• Traditional tangent section BHA
• Short, stiff collar and full gauge stabilizers minimize the tendency of gravity and lithology to deflect bit.
• Lower dogleg severity than a steerable (in rotary mode)
• Assembly can be stiffened further with the use of long blades on the NB stabilizer, tandem NB
stabilizers or an extended bit gauge with a PDC bit.
• No active control without the use of an adjustable stabilizer (position 2)
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A
FG
Stiff Pony
1
3
1 or 2 Drill Collars
1
2
FG
C
Drill Collar
2
FG
B
UG
Collars above bit lie on the borehole wall
1
Rotary Build Assembly:
• Enhances BHA “sag” above the NB stabilizer to deflect the bit upwards.
• Higher WOB will increase bending and therefore increase the build rate
• Generally increases the bit walk tendency compared to a packed assembly
• A – Low Rate-of-build (ROB)
• B – Medium ROB
• C – Aggressive ROB (walk rate may be high)
UG
A
Stiff Pony
1
FG
Drill Collar
2
Drill Collar
B
FG
1
3
Drill Collar
2
Rotary Drop Assembly:
•
•
•
•
•
A – Undergauge NB stabilizer causes the bit gauge to push on the low side of the hole.
B – Eliminating the NB stabilizer and using a 20-30’ drillcollar above the bit results in an aggressive
dropping assembly (Pendulum)
Light WOB and high rpm will enhance the dropping tendency.
Very high WOB may actually cause these assemblies to build
A special NB adjustable stabilizer can be used to control the drop rate.
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Tangent Section Option 3 – Rotary Steerable Tools
RST
MWD
RST’s are technically the best option for drilling tangent sections as they maximize hole cleaning and ROP,
minimize tortuosity, and provide full directional control. The main issues with these tools are reliability
and cost. Reliability in long 12¼” intervals has improved considerably and RST’s are becoming more
common in this application. One of the benefits that is not always appreciated with these tools is the ability
to maximize parameters (flowrate, rpm, WOB) without compromising directional control. With a rotary
assembly, often the WOB or rpm will be restricted in an attempt to control build or walk rates. This can
result in a reduction in ROP, and compromises to the hole cleaning ‘system’. Refer to Section 11.5.9 for a
general discussion of RST’s.
11.4.3 Deep Build / Drop / Turn Sections
Deep Build / Drop / Turn Option 1 – Steerable
ABI
MOTOR
MWD / FEWD
Adjustable Stabilizer Option
Although steerable assemblies provide full directional control, their use in deep build/drop/turn sections
generally results in poor drilling efficiency and hole cleaning problems (particularly 12¼” hole).
Significant doglegs can also result if the well falls behind on inclination or azimuth, as there is generally
little room for error when close to the target(s).
• Hole cleaning will be compromised while sliding and due to rpm restrictions when cleaning up the hole.
• Deep build/drop/turn sections will start to become difficult with a motor and PDC bit. Weight stacking
and toolface control will result in poor drilling efficiency. This generally results in tri-cone bits having
to be run, which therefore limits the length of run.
• ABI tools will prove very beneficial, particularly building to horizontal. In many cases, FEWD tools
are run behind the motor, which pushes the MWD further behind the bit, and makes the use of ABI that
more critical.
• An adjustable stabilizer can be run behind the motor to provide more flexibility with rotary drilling. It
should always be retracted when sliding.
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Deep Build / Drop / Turn Option 2 – Rotary
DC / FEWD
MWD / FEWD
Adjustable Stabilizer Options
Rotary assemblies have some application in deep build and drop sections, though they are of limited value
when a change in azimuth is also required. The other main limitation is the build or drop rate that can be
obtained from a rotary assembly, and the flexibility to react as the inclination and formations change.
• For build, an adjustable stabilizer can be run as the 1st string stabilizer, with a full gauge NB.
• For drop, the NB stabilizer is run undergauge, or an adjustable stabilizer can also be used in this
position to provide a build/drop assembly. A pendulum assembly may also be used.
• ABI tools are again beneficial in this application to provide a measure of exactly what is happening at
the bit.
Deep Build / Drop / Turn Option 3 – Rotary Steerable Tools
RST
MWD / FEWD
Again, RST are the best technical option in this application, and in many ERD wells, the only option
available to efficiently drill this section. Refer to Section 11.5.9 for a general discussion of RST’s.
11.4.4 Horizontal Sections
Horizontal sections are similar to tangent sections, although they tend to be in 8½” hole and are
significantly more difficult to drill due to the characteristics of the varying lithologies being
drilled. In general, the following observations can be made from drilling horizontal intervals:
•
Multiple different formations are drilled and the bit and BHA dynamics will change in each.
This requires BHA’s to have adequate flexibility to counter strong drop or build trends.
•
Formations tend to be abrasive and hard which results in high torque, increased vibrations,
decreased tool reliability and high gauge wear on bits.
•
BHA’s will tend to drop strongly in soft unconsolidated formations. This is particularly true
for steerable motors.
•
BHA’s will tend to become stuck on a bed boundary and will be unable to drill through the
boundary going from a soft to a hard formation.
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•
Permeable reservoir sections often produce gauge or even undergauge hole. This may
preclude the use of full gauge stabilizers, which can lead to high torque, vibrations and spiral
hole.
•
FEWD tools will often be required in the BHA. These may include integral stabilizers, which
will impact directional performance and torque.
•
Losses will generally be an issue with high ECD’s. This impacts the selection of BHA
components, and in particular FEWD tools and stabilizer designs (i.e. it is important to note
the actual OD and junk slot area of tools going in the hole).
There are many issues to consider when selecting BHA’s for horizontal hole. There are also a
considerable number of different options and combinations that can be run. The final selection
will be based on the reservoir objectives and characteristics, tool cost and availability, and good
quality offset data. Some possible options are shown below with a brief discussion of the main
advantages and disadvantages of each.
ABI will be beneficial to any BHA run in horizontal hole and should be used when possible.
Horizontal - Steerable (Adjustable Stabilizer)
MOTOR
Advantages:
• Full directional control
MWD / FEWD
Disadvantages:
• Sliding difficult and time consuming - will have
to use tricone bits and therefore short runs
• Poor hole cleaning
• Increased tortuosity
Horizontal - Straight Motor (Adjustable Stabilizer)
MOTOR
MWD / FEWD
Adjustable stabilizer can be run above the motor as well – however it will be less responsive
Advantages:
• If high torque is an issue (or for improved ROP),
a straight motor can be used.
• Range of build / drop rates possible
• Simple and reliable
• Hole cleaning ok
2007 – Third Edition
Disadvantages:
• No azimuth control
• Generally limited build capability
• Special adjustable stabilizer required in below
motor application
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Drilling Design and Implementation for Extended Reach and Complex Wells
Rotary (with string Adjustable Stabilizer)
DC / FEWD
Advantages:
• Some degree of build/drop control
• Simple and reliable
• Hole cleaning ok
MWD / FEWD
Disadvantages:
• No azimuth control
• Limited build/drop flexibility
• Full gauge stabilizers may create excessive
torque (i.e. cannot run full gauge NB)
Rotary (with NB Adjustable Stabilizer)
DC / FEWD
Advantages:
• Range of drop/build rates possible
• Simple and reliable
• Hole cleaning ok
MWD / FEWD
Disadvantages:
• No azimuth control
• Generally limited build capability
Rotary (with Dual Adjustable Stabilizers)
DC / FEWD
Advantages:
• Increased build/drop flexibility
• Hole cleaning ok
MWD / FEWD
Disadvantages:
• No azimuth control
• Increased complexity
Rotary Steerable Tool
RST
Advantages:
• Full directional control
• Good ROP with aggressive PDC bits
• Hole cleaning ok
2007 – Third Edition
MWD / FEWD
Disadvantages:
• Reliability
• Cost
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11.5 GENERAL BHA CONSIDERATIONS
11.5.1 Jars
Every Operator tends to have a different approach to running jars in an ERD well. Some
Operators run the standard single jar, some run no jars, and others will run two jars (one above
the BHA and one further up in the tangent section).
The problem with jarring in ERD wells is that there is little or no slack-off weight available to jar
downwards (always jar down rather than up in a deviated well!). This is due to buckling of the
pipe brought about by friction in the hole.
K&M recommends running jars for several reasons:
•
If you don’t have them in the string they are definitely not going to help when you get stuck!
•
You may be stuck when shallow while POH, in which case there should not be as big of a
problem getting weight down to the jar.
•
There are no significant downsides to running a jar
•
They should be run in the HWDP above the BHA (i.e. 3 joints HWDP below and 5 joints
above)
11.5.2 BHA Weight
Traditional vertical well BHA design includes long sections of drill collars and HWDP. This is
mainly to keep the neutral point in the BHA and below the jars, and to ensure that the drillpipe is
not in compression when drilling. Note that these practices do not apply to ERD wells when
drilling at high angle.
BHA’s should be as short as possible with collars for MWD and FEWD tools only. A maximum
of 3 stands of HWDP should be run. The HWDP is required to provide a stiffness transition
between the drill collars and drillpipe, and for jar placement. The weight is minimized for the
following reasons:
•
•
•
•
Produces excessive torque and drag
Creates buckling problems further up the string
Increased pressure drop (may result in reduced flowrates)
With the drillpipe sitting on the low side of the hole, it has a much higher buckling resistance,
and compression in the pipe while drilling is not a significant issue.
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11.5.3 Stabilizer Designs
This discussion is not intended to be an authoritative analysis, or to recommend a particular
stabilizer design. Every directional driller seems to have a different experience and preference for
stabilizer designs. The following are, nonetheless, K&M’s experiences for the reader to consider.
•
•
•
•
•
•
•
In general, the amount of stabilization should be kept to 3 or less stabilizers for an ERD well.
This will be dependent upon specific requirements, but increased stabilization will only
increase torque and drag.
Stabilizers should be designed for maximum junk slot area. String or integral stabilizers are
preferred over sleeve stabilizers, which in turn are preferred over clamp-on type stabilizers.
The sleeve and clamp-on type stabilizers are commonly used on motors and MWD/FEWD
equipment to provide design flexibility in the field. These stabilizers reduce junk slot area
appreciably, and can often be replaced with better designs with some pre-planning.
Stabilizers should have tapered leading and trailing edges to prevent the stabilizer hanging up.
It is the authors preference that straight blade stabilizers are used for high angle wellbores, for
easier tripping through cuttings beds. The only exception to this is for a near-bit stabilizer
(for rotary BHA’s), where spiral-type stabilizers may be preferred for reduced right-hand
walk tendencies. It has been K&M’s experience that spiral near-bit stabilizers reduce righthand bit walk for rotary BHA’s designed to build angle. It is envisaged that this is because a
spiral stabilizer probably does not ‘walk’ up the side of the wellbore as aggressively as a
straight bladed stabilizer.
Spiral stabilizers will increase rotary torque compared to straight bladed stabilizers. This is
believed to be due to the greater contact area of spiral blades.
Spiral stabilizers may have application if bit/BHA whirl is a significant issue. It is envisaged
that the spiral type blades will not whirl as aggressively as a straight bladed stabilizer.
Any spiral stabilizers used in ERD applications should be a partial wrap design with
maximum junk slot area. The use of 360˚ wrap stabilizers is not recommended.
11.5.4 Adjustable Stabilizers
There are multiple BHA design options that can utilize adjustable stabilizers. Each design has
different applications and different advantages and disadvantages. Similarly, there are different
adjustable stabilizers on the market, which have different advantages, disadvantages and
applications. The final choice will depend on many factors.
Essentially, adjustable stabilizers are used to provide real-time inclination control while drilling in
rotary mode. These tools rely on the BHA design for their overall effectiveness. Adjustable
stabilizer assemblies do not provide azimuth control.
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There are two-position tools available for simple applications in a wide range of hole sizes (6” to
17 ½”). Advanced adjustable stabilizers with multiple tool settings, downhole feedback, memory
capability and large diameter variation are available for the more critical applications. These
tools are generally available in 12¼”, 9⅞” and 8½” hole sizes.
The different tools all have different setting mechanisms. These include cycling the pumps,
weight set with the bit on bottom, and mud pulse telemetry.
A new tool is currently being developed which is a 3-position hydraulic set tool with integral
inclinations measurements for running as a NB stabilizer.
11.5.5 BHA Prediction Modeling for Rotary Assemblies
Before a BHA is run in a directional well, there should be a clear understanding of what the BHA
will do when rotary drilling. The ability to provide quality software modeling of the BHA’s
rotary drilling performance is an important tool.
Directional drilling companies should be able to predict what the rotary drilling performance of a
BHA is, using reliable software systems. Some service companies have very good software
capability, while others do not have this capability at all.
Obviously, the accuracy of prediction will vary according to the lithology and other wellbore
conditions. However, with some local experience, BHA designs can be optimized for maximum
performance.
11.5.6 Advanced Rotary Slide Drill Technique
On high angle wellbores, slide drilling is usually more difficult than for conventional wells in the
same lithology. The high angle results in significant static friction that must be overcome for the
drillpipe to transfer weight to the bit. With static friction being greater than dynamic friction, the
static friction will grip the drillpipe until a critical point is reached, at which point the pipe slips
and WOB is suddenly released onto the bit. This results in poor tool face control and possibly
significant motor stalling problems if a PDC bit is in use. If the static friction is sufficiently high,
then sinusoidal buckling may occur, which will act to exaggerate the above process. The only
way to really prevent static friction from impeding slide drilling performance is to keep the pipe
constantly moving (and therefore in a dynamic friction environment).
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What is happening to the drillstring when sliding
in a high-drag environment on an ERD well
High static friction when sliding may cause pipe to ‘stackup’, preventing weight being transferred to the bit. This
may be severe if there is any sinusoidal buckling
occurring.
At some point the static friction is overcome, and
much of the compression in the drillstring is
suddenly released, dumping weight onto the bit.
The toolface is then lost and / or the motor stalls.
Figure: 37
Weight Transfer While Sliding in ERD Wells
The following technique has been used on a number of projects and has allowed slide drilling to
continue much further than would otherwise be the case. K&M client wells have also used this
unique technique to extend slide drilling capability and/or improve slide drilling performance on
high drag wells.
The method described below would only be applied once conventional slide drilling became
nearly impossible. It will no doubt prove less efficient than if conventional sliding is trouble free.
However, this method can increase overall sliding ROP if drag is high and smooth transfer of
WOB is not possible otherwise. There will be quite a lot of trial and error with initial attempts to
implement this method, and patience is required. The amount of ‘turns’ required will differ for
each well, depending upon the well profile, well depth, casing plan, drillstring and mud system,
etc. The process is quite labor intensive to the driller and requires continuous assistance by the
toolpusher or assistant driller at the driller’s console if it is to be performed well.
In essence, the drillstring should be thought of as a long, elastic ‘rubber-band’ and therefore what
is happening at surface is not what is happening near the bit. For example, rotary movements
made at surface when slide drilling really only move the pipe in the vertical portion of the hole.
The drag in the long tangent section prevents any surface movement from reaching the bit unless
these movements are significant.
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Procedures for Rotary Sliding Technique
• Once tool face orientation is obtained, pipe RPM is commenced at +/- 130 rpm for a specified
number of rotations which does not translate rotation to the BHA. Rig floor personnel
manually count the number of rotations. For the Wytch Farm M5 well at 28,700 ft (8,700m),
at least 20 surface rotations were required in each direction to rotate the BHA. For shorter
wells, the number of wraps will be reduced (to say 2-3 turns for shallow ERD wells).
• The rotary is then immediately reversed (i.e.. left hand turn applied) just prior to the torque
having reached the BHA. The left hand turn is made at the same speed, and for the same
number of turns (powered, not backlash).
• The rotary is then reversed again, and so on.
• Effectively, the drillstring is never allowed to become stationary in order to break static
friction forces that make slide drilling so inefficient.
• Eventually, the torque will work its way down to the bit, and tool face control will be lost. At
this point the bit is picked up off-bottom, and the process is then repeated.
100+ rpm rotation ‘to the RIGHT’.
Count the number of revolutions up to
just prior to amount required to disturb
the toolface
Figure: 38
2007 – Third Edition
Immediately apply 100+ rpm rotation ‘to the
LEFT’ for the same number of revolutions.
Repeat the process, without allowing the pipe
to become stationary. Eventually torque will
work down to the BHA and toolface will
have to be recovered.
Advanced Slide Drilling Technique for Deep Sliding
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Note also the AG-itator tool detailed in Section 18.1.10.
11.5.7 Chasing the Curve
Since the advent and widespread application of steerable motors, directional drillers have been
stewarded against two criteria, (a) their ability to hit the target, and (b) their ability to closely
follow to the originally designed wellpath trajectory. Hitting the target is certainly the primary
goal, but trying to stick to a vertical section when the well is falling behind can cause serious
problems in ERD wells. "Chasing the Curve" refers to the practice of trying to get back on the
theoretical vertical section line when the well falls behind on inclination.
Planned
Actual Wellpath – chasing the curve
Actual Wellpath – re-drawn
Chasing the original wellpath line will result
in increased torque and drag problems. The
wellpath should be re-drawn to the target
from the current location, rather than chasing
the original line
Figure: 39
Chasing the Curve
Excess shallow doglegs in an ERD well can have a severe impact on torque, drag and buckling
for drilling, casing and completion operations. As the tension below the doglegs increase, so too
does the resulting torque and drag. If the well falls below the designed vertical section in wells of
less than 70°, the well should be re-drawn to the target and the original design discarded.
Although this will increase the tangent angle, it will ultimately reduce the overall torque and drag
for the well.
For wells greater than 70°, and for negative weight wells, the tension below the doglegs begins to
reduce and, therefore, the effects of the critical doglegs are lessened. For these wells, however,
sticking to the planned vertical section is critical to keeping the tangent angle down to (a) ensure
that the well is serviceable in the future and/or (b) to minimize the effects of negative weight on
the well.
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As an alternative to simply drawing a single line to the target, the wellpath would be better
thought of and drawn as a cone as shown in Figure 40 below. This applies to both dimensions of
the target.
If planning a deep steerable run, a double cone may be more appropriate as this will allow for
increased walk rates if a rotary assembly is used in the upper portion of the hole.
Vertical Section
Plan View
Adjustable stabilizer BHA
Figure: 40
Steerable BHA
Drawing a Cone to the Target
11.5.8 Reporting Practices
Directional drilling reporting practices must be thorough if a directional drilling strategy is to be
optimized for a given project. The level of reporting should meet the following criteria for the
actual project as well as lead-up wells so that there is good quality offset well information that
can be used for planning and comparison purposes.
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Unless the Operator takes an active interest in this aspect of the reporting and implementation
side of directional drilling, the Operator may be surprised to find out how poor their directional
drilling company’s data collection and reporting practices are. Almost certainly, the individual
directional drillers will be keeping their performance data and results in their tally books.
However, unless the data is collected and reported back to the office personnel, there is little
scope for well-informed planning and optimization.
As a minimum, the following data should be collected and reported to the Operator’s files for
each BHA and hole section:
• Stand-by-stand summary of directional drilling operations, with:
% slide drilling and tool face orientation of each slide.
Results of surveys with estimated rotary and slide response (build, turn and total DLS).
Average sliding ROP and rotary ROP.
WOB, RPM, Flowrate and surface pressure for sliding and rotary intervals.
Comment on any tool face, stalling or WOB transfer difficulties. The number of times
that the bit is picked-up off-bottom for stalling or tool face should be itemized or estimated
for each slide interval.
If an adjustable stabilizer or RST is run the tool setting should be recorded.
• Comment on any driving issues. For example:
What stalling buffer (if any) was used for sliding and rotary drilling?
Was WOB or RPM or flowrate limited for any reasons (such as surface pressure or
flowrate limitations, torque/drag, ROP control, stalling of motor, unwanted build/drop or
walk tendencies)? Estimate compromised ROP effect on controlling these parameters.
Measurements of DWOB, DTOR, vibrations, ABI, PWD data (if any run).
This data should be summarized and analyzed if it is to be of value. For example, the overall
percentage of slide drilling for inclination and azimuth control should be well understood. This
will probably vary by hole section and lithology. Walk tendencies in rotary mode may be
analyzed to see if there is any correlation by bit, lithology, BHA, azimuth, etc. With this
knowledge available, well-informed decisions can be made about the best drilling strategies for a
given project.
11.5.9 Rotary Steerable Tools (RST’s)
RST’s have resulted in a step change in the performance of ERD wells in the last few years.
They have opened up new applications and allowed the technology envelope to be expanded with
longer and more complex wells being drilled. The main advantages with the use of RST’s
include:
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•
Continuous rotation maximizes hole cleaning efficiency and ROP
•
Full inclination and azimuth control with a broad range of dogleg capability
•
Not limited by weight stacking and buckling issues as are motors
•
Minimize tortuosity in the wellbore – smooth wellbore aids further torque and drag
So why aren’t these tools used for all wells in all applications? There are currently two main
limitations with RST’s:
•
Cost. Availability and demand is such that these tools are still costly and each application
will need to be economically justified based on the many parameters involved. However,
saying this, the price of these tools continues to be reduced as more competition comes into
the market, more tools become available and more Operators are using the tools. On ERD
wells, it is generally relatively easy to justify the cost of these tools in difficult applications
where alternative BHA strategies would result in poor drilling performance or additional hole
problems (i.e. hole cleaning, added tortuosity, buckling, etc.)
•
Reliability. RST’s have not had a good reputation in this area, and indeed some tools have
been pulled off the market for a period of time to address these issues. However, in the last
1-2 years, tool reliability has increased dramatically as the service companies define and fix
problems with the tools. In particular, the larger size tools for 12¼” hole have proven more
reliable, although this may simply be due to easier drilling conditions in these larger hole
sizes.
There are currently three main tools on the market, with several other tools available from smaller
companies which have had limited number of runs. The tools are described briefly below and a
comparison Table is shown on the following page. The detailed function and specifications of the
tools are not included in this section, as this should be obtained from the service company in
question.
Schlumberger PowerDrive – originally the Camco RST tool, this is a “push-the-bit” system,
which is available for both 8½” and 12¼” hole sizes.
BHI AutoTrak – This was the first tool on the market and is again a “push-the-bit” system and
available in both 8½” and 12¼” hole sizes. This tool is more complex than the PowerDrive, but
also has more functionality.
Sperry-Sun GeoPilot – This is the latest tool to come on to the market and differs from the other
two systems in that it is a “point-the-bit” system. It is currently only available for 8½” hole size.
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Hole size (nominal)
Schlumberger
Baker Hughes Inteq
Halliburton
PowerDrive
AutoTrak
Geopilot
8 ½"
12 ¼"
8 ½"
12 ¼"
8 ½"
6¾"
9"
6¾"
8¼"
6¾"
3.8 m – 8.7 m
3.8 m
11.8 m
12.7 m
Technical Specifications
Tool diameter
Tool length
o
o
o
o
6.1 m
o
Max build rate (nominal)
8 /30m
6 /30m
6.5 /30m
6.5 /30m
5 /30m
Temperature limit
250 oF
250 oF
300 oF
300 oF
300 oF
300 – 650
500 – 1500
370 - 630
530 - 1100
?
Tool pressure drop (psi)
~100
~100
500 typ
500 typ
~100
Bit press drop reqd (psi)
500 – 2000
500 - 2000
2000 max
2000 max
?
Rotary speed limits (rpm)
40 – 220
40 – 220
250 max
250 max
250
Max WOB (lbs)
no limit?
80k
55k
88k
55k
Flowrate limits (gpm)
Telemetry
Downwards
Upwards
Mud pump cycling
Mud pump cycling
Pumps and rot.
Electromagnetic link to MWD,
MWD
MWD
No
No
then mud pulse
Yes
Can it be used with any
vendors MWD/FEWD
(Short-Hop (SH) used with
Anadrill only)
package?
Bit to: Inclination
9.7 m
2.1 m
9.7 m
2.1 m
0.9 m
0.7 m
0.9 m
GR
19.9 m
12.1 m
19.9 m
12.1 m
5.1 m
4.7 m
13.8 m
RES
16.6 m
8.7 m
16.6 m
8.7 m
5.5 m
5.1 m
13.8 m
Directional
9.7 m
2.2 m
9.7 m
2.2 m
10.0 m
10.2 m
17.3 m
NO
SH
NO
SH
SH
SH
Table : 2 RST Comparison Table
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When comparing RST tools, the service companies should be contacted to supply the latest
information on their technology, as this is a field that is advancing rapidly. New tools are
continually being developed as well as tools for different hole sizes. Following are some general
considerations when planning for and using RST’s.
•
Specific RST bits designs should always be used. These are generally matched to the way the
tools works (i.e. “push-the-bit” or “point-the-bit”). Refer to Section 12.4.
•
Getting inclination measurements at the bit is critical, particularly in a horizontal or build to
horizontal application. GR and RES at the bit are also beneficial in geosteering applications.
•
Some applications have been seen where “push-the-bit” tools have been unable to break
through hard boundary layers at very low angles of attack (< 5°). Motors were required to
break through these boundaries. Thus it is felt that “point-the-bit” tools may be more
applicable in this application where multiple hard boundaries are penetrated at a very low
incident angle.
•
Sourcing, contracting and servicing of RST tools will be critical to their success. The
following should be considered:
Clearly define tool requirements upfront and ensure the service company will have the
adequate number of tools available.
Should be a minimum of three tools on location.
The method for servicing tools and getting them back to the operation should be worked
out in detail prior to spudding.
An RST expert should be available on location for the first few runs in a new application
or where normal directional personnel do not have adequate RST experience.
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12 BIT SELECTION STRATEGY
Bit selection is a fundamental factor in the BHA strategy, as well as the overall drilling and hole
cleaning systems. For an ERD application, bit selection should not simply be based on ROP,
footage or cost/ft. The bit’s interaction with every aspect of the ‘system’ is often not considered.
As such, bit selection must consider the ‘big picture’, and not just the perspective of the bit
salesman/engineer or the directional drillers.
The following must be considered as a minimum, over and above the usual bit selection issues.
•
What will be the directional response of the proposed bit in rotary and slide drilling? The
gauge pad design can have a significant effect on build and drop rates, especially on rotary
BHA’s.
•
Does the bit have any walk-minimization features that will help to keep it neutral in rotary?
This will be important on long rotary runs to keep the wellpath inside the target.
•
Is the bit appropriate if a steerable motor is to be run? Presumably the steerable BHA is run
with the intention of slide drilling (otherwise a steerable system should not be in the hole). If
so, how steerable is the bit in each formation that is to be encountered? Is the bit selection
compromised significantly compared to if a non-steerable system had been run?
•
Is the rig a semi-submersible or drillship? In wave conditions, tool face control will be
affected, even with a heave compensator.
•
Is the junk slot area maximized to prevent tripping problems? Remember that the bit must be
tripped through a cuttings bed over the entire high angle portion of the well. There is
increased risk of balling, swabbing/surging, pulling tight and/or packing-off in an ERD well.
•
Is balling a risk (especially if WBM is in use)? This is more important for ERD applications
(compared to low angle wells) because the shale intervals are much longer and the bit will be
pulled/run through cuttings beds. Furthermore, the bit hydraulics are often poorer on ERD
applications because the available flowrate and surface pressure is limited.
•
What is the vibration performance of the bit like (especially for PDC bits)? This is not
specifically for bit damage, but for preventing vibration-induced failures of the MWD or
other downhole equipment.
•
Is the bit’s design the limiting factor for ROP improvement? It is often the case, that a great
deal of time and effort is placed on trying to find faster bit designs, when the ROPs are
controlled due to other limitations such as hole cleaning, directional control, balling
problems, or other factors in the operation.
•
Is the bit design compromised for unrealistic bit run requirements? For example, a bit may be
selected that is capable of drilling a very long section in one run. However, it may be
unrealistic to expect such a long bit run, based on local experience due to downhole failures
(e.g.. MWD, FEWD, steerable motor, adjustable stabilizer) or other problems. As such, the
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bit may be overly heavy set for the individual lithologies, while never having the opportunity
to be fully tested over the entire interval. It may be better to use more aggressive bit designs
and drill quickly. If downhole tool reliability improves with time, then a one-bit-to-TD
strategy may then become more appropriate.
12.1 PDC BITS
PDC (Polycrystaline Diamond Compact) bits have the widest application in ERD wells. PDC bit
technology has advanced rapidly in the last 3-5 years and continues to do so. In particular cutter
technology has developed to the point that formations that were not considered PDC drillable
several years ago are now drilled regularly with PDC’s. Bit designs have also been improved to
extend durability, lower vibrations, improve steerability and many other factor involved in
optimizing bit performance.
The following sections are general observations and recommendations for PDC bits in relation to
ERD wells.
12.1.1 Matrix Verses Steel Bodied
Matrix bodied bits are recommended if erosion or abrasion is a concern. This may be either due
to drilling with high flowrates for very long periods (especially if there is any sand content in the
mud), or if drilling in very abrasive formations. Matrix bits are particularly well suited if run on a
steerable system in sand stones (e.g. in horizontal wells). This is because of the high gauge wear
that is associated with this application due to the side-loads imposed by the motor bend.
However, matrix bits do have distinct disadvantages that should be considered. Matrix bodies are
more brittle than steel bits. Because of this, the matrix designs require substantially thicker blade
designs for equivalent steel strength and reliability. Because of these features, matrix bits are
more prone to partial or complete structural bit-body failure (with subsequent risk of catastrophic
cutter loss or damage). Further, matrix bits generally have less junk slot area because the blades
and body must be thicker.
In the following applications there are clear reasons to run steel bodied bits for improved
performance or reduced risk:
• Steel bodied bits are recommended if the formation is prone to balling and if the bit requires
maximum junk slot area. A steel bodied bit can be designed to be heavier set than an
equivalent matrix design while still having substantial junk slot area.
• Steel bodied bits are recommended if mud erosion is not a concern for long runs. Generally,
erosion is less of an issue if the mud’s sand content is low.
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• Steel bits are recommended if there are hard stringers separated by soft fast drilling formation.
Partial or complete blade breakage is most likely to occur when the bit ‘slams’ into the hard
stringer.
• Similarly, steel bits are recommended if destructive vibration (such as whirl or stick slip) is a
problem in hard, non-abrasive formations (such as limestone). Again, matrix breakage is more
likely to occur in these formations.
12.1.2 Vibration Management
PDC bits are particularly prone to harmful vibrations. Some vibrations are bit-induced, while
others will be transmitted via the BHA or drillstring. Some ‘harmful’ vibrations will be
destructive to the bit (the PDC cutters in particular), while all vibration is likely to reduce ROP.
Further to this, is the increased risk of MWD or other BHA failures due to excess vibration. As
such, PDC bits should be designed for optimum stability.
This discussion is not intended to analyze this fast-moving technology (much of which is
dominated by proprietary design features). Some features are more effective than others, while
some features interact (positively or adversely) with directional drilling performance. When
selecting PDC bits for an ERD application, these effects must always be considered.
12.1.3 PDC cutter Design and Placement
As mentioned previously PDC cutter technology is advancing at tremendous rates. The design
goal for PDC bits in ERD applications is always to maximize the bit’s utility, and experience has
shown that premium quality cutters are a good investment in this regard.
PDC cutters are usually designed for impact or abrasion resistance. Historically, improving
impact resistance is at the expense of abrasion resistance and vice-versa. Recently some cutter
innovations have reduced the amount of compromise that is necessary. Generally, it is
recommended that non-planar cutters be used for impact resistance, with the maximum available
thickness diamond table for abrasion resistance.
Back-rake, cutter size and cutter placement can also be strategically manipulated to improve
ROP, longevity and steerability.
12.1.4 Gauge Length
The following recommendations are based on K&M’s experience in various ERD projects around
the world. The final selection of gauge length should be based on local field experience.
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ASSEMBLY
GAUGE LENGTH
If a packed rotary BHA is to be used to hold angle, then a relatively long gauge pad (>
PACKED
ROTARY BHA 3”) should be used. This will tend to act as a near-bit stabilizer and keep the assembly
propped-up.
ADJUSTABLE PDC bits for adjustable rotary BHA’s should have short gauge lengths, especially if
ROTARY BHA directional control has been unpredictable. In some formations, the bit’s gauge pad may
act as a near-bit stabilizer, changing the directional response of the BHA. Gauge lengths
less than 2.5” are recommended (preferably about 1.5” – 2”). This also applies to other
rotary BHA designs (e.g. pendulum assemblies).
It has also been noted in some applications that “Steering Wheel” bits, with a full gauge
ring around the entire circumference of the bit, have actually nullified the effectiveness
of the adjustable stabilizer even with a short gauge length.
STEERABLE
BHA’S
For steerable BHA’s the gauge length will have less effect than on rotary BHA’s, since
the bit is not drilling true to the center-line. In fact, increased gauge protection may be
necessary with steerable BHA’s due to the increased side forces and higher RPM
imposed on the bit, combined with the typical drop tendencies of these BHA’s.
However, in general, it has been seen that short gauge bits (1.5” – 2”) have been more
responsive, or steerable, than longer gauge bits. Gauge length, though, is only one of
many factors that makes a bit steerable (refer to Section 12.6).
SIDETRACKING For sidetracking, bits should have a very flat profile with as short a gauge as possible (1”
ASSEMBLIES – 1.5”). A specialized sidetracking bit should be kept on site for each hole section, as
they are not always easy to find if a sidetrack is required. Special care must be used
when tripping a sidetrack bit as they have a very small junk slot area and are prone to
cause swabbing.
RST’S
Refer to Section 12.4.
Care must be exercised when referring to gauge length as many manufacturers and Operators will
refer to both active and passive gauge. Active gauge refers to the PDC cutters that lie on the
gauge line and passive gauge is simply a measure of the flat pad length. The measurements in the
table above are for passive gauge.
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12.2 TRI-CONE BITS
Everyone seems to have a preferred vendor for tri-cone bits and decisions are likely to be driven
by experience with bearing reliability and/or cutting structure. Field observations suggest that
some major tri-cone bit manufacturers definitely appear to make much better bearings than other
companies.
Some tri-cone bits have more junk slot area than others. This is important when pulling through
long cuttings beds and should be considered if the rig has demonstrated limitations in its ability to
clean the hole up.
General recommendations include:
•
Always use premium, motor bearing bits. This applies even if the bit is to be run on a rotary
BHA. In these expensive wells, the additional bit cost is easily covered by the longer bit runs
that will result.
•
Always use quality gauge protection. This is as much for bearing life as for actually ensuring
gauge hole.
•
Tri-cone bits should be pulled on revolutions and not on hours. Accordingly, practices,
parameters and motor selection should be designed to maximize bit life.
12.3 BI-CENTER BITS
Bi-center type bits (including “Reaming While Drilling - RWD” type bits) definitely have their
place in drilling applications, particularly in top-hole and build sections. However, these bits are
generally not recommended for drilling long tangent sections of ERD wells, especially in “large
diameter” hole (> 9⅞”). The primary concern is the detrimental effect on hole cleaning and
drag/buckling due to the increased amount of slide drilling and tortuosity that results from the
certain drop tendencies seen with these bits in the rotary mode.
When drilling with a bi-center bit, the bit (and hole) diameter is much larger than any of the
stabilizers. Directional control in rotary mode is therefore poor. While it will be quite
unpredictable, it is likely that the BHA will have a strong drop tendency that can only be
countered by extensive slide drilling. Drop rates in rotary mode can be expected to be about 3° to
5°/100’, depending upon the lithology. This has serious hole cleaning and torque and drag
implications for ERD wells. In small diameter holes and in the vertical/build sections, this can be
accommodated because the hole cleaning environment is often more forgiving.
In tangent sections, it is advisable not to run a BHA that requires more than 10% slide drilling (by
footage) to hold angle. Even 10% slide drilling is too much if hole cleaning is an issue. These
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bits can be expected to require 30% - 50% slide drilling if used in the tangent section of an ERD
well depending upon the lithology. This slide drilling is usually to maintain angle.
The increased tortuosity that results from frequent slide drilling should be considered for its effect
on drag and buckling. Casing and liner runs will be particularly susceptible to the increased drag
that will result, especially if the casing is well centralized and at risk of ‘ploughing’ through
dogleg intervals.
A further consideration when using bi-center bits for drilling long tangent sections is that these
bits generate more destructive vibration than conventional PDC bits. Although the bi-center bit
may not show any signs of damage (usually because of the soft formation that these bits tend to
be used in), the vibration will be transmitted to the MWD and other BHA components. This
increases the risk of MWD or other downhole failures, resulting in more tripping and increased
downtime.
Note, under-reaming tools run above RST’s are now being used regularly and overcome the
problems listed above with bi-center bits.
Running Through Casing
Figure: 41
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12.4 RST BITS
RST’s require the use of specialized bit designs due to the mechanisms by which they achieve
their directional control. A “push-the-bit” RST system and “point-the-bit” system will require
different bit designs. Following are some general guidelines for selecting RST bits:
•
Do not be fooled by the RST vendor telling you that you can only use a particular bit design
from a particular company and they will not guarantee the performance if you use anyone
else’s bit. This is simply a marketing issue and often a conflict of interest, as the bit company
and directional company have the same owner. Select the bit that is the best for your
application based on quality offset data.
•
“Push-the-bit” systems work by applying side force to the bit. As such they require bits that
have a relatively flat profile, short gauge (1.5”-2”) and active gauge cutters. Basically these
bits need to have short aggressive gauge designs to be effective.
•
“Point-the-bit” systems work in a similar manner to a steerable assembly, with the bit
pointing in the required direction. In this case there is not as great a need to have an
aggressive gauge.
•
An important consideration with “Push-the-bit” designs is the vibration impact when using
bits with aggressive side cutting action. These bits should have stability features included in
the design to minimize the chance of excessive vibrations.
12.5 BIT HYDRAULICS
Bit hydraulics is critical to efficient drilling performance, regardless of the bit type or application.
Not only must ‘old’ cuttings be removed quickly to prevent them from being re-drilled, but also
to prevent them from adhering to the bit body and/or the cutting structure. When bit balling is
referred to, it should not only be thought of as the ‘classic’ globally balled bit as seen at surface
after being pulled out of the hole (which may only have become badly balled on the trip out). It
only takes a fine film of clay (or other cuttings accumulation) on the nose or at the cutter tips to
effectively reduce a PDC bit to a blunt object. This is referred to as “Micro-Balling”. Bit
hydraulics must be designed to clear cuttings away from the face of the cutters to prevent balling
and maximize ROP.
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Micro-balling is sufficient to blunt a PDC bit.
Only a small accumulation of cuttings on the leading edge
of the cutters is necessary.
This localized balling can reduce ROP to a standstill. Bit
hydraulics are critical at all times to prevent this
Figure: 42
Micro-Balling
As discussed earlier, PDC bits should be nozzled for maximum flowrate (i.e. largest nozzles),
with the following exceptions:
• If there is spare hydraulic capability, then higher HSI may be considered as long as the
flowrate will not be reduced.
• If high flowrates are not possible (say due to surface pressure constraints) then the bit should
be nozzled for some moderate HSI to compensate for reduced flowrates.
• If increased pressure drop is required for FEWD/FEWD or adjustable stabilizer tools.
Tri-cone bits should always be nozzled for at least moderate HSI (i.e. >3.0). Often large nozzles
are selected with the thought that higher flowrates are required for optimum hole cleaning.
However, there is no point having good hole cleaning if you can’t drill in the first place! The use
of extended nozzles, mini-extended jets or the more robust “hi-flow” nozzles, is also worth
considering to better focus the hydraulic energy in rock bits.
It is a common misconception that bit hydraulics are irrelevant in SBM/OBM systems. Although
the risk of balling is reduced, compared to WBM in sticky clays, bit hydraulics are still important
to drilling performance and bit life. Both PDC bits and tri-cone bits still require good face
cleaning, if ROP and bit life are to be optimized.
The use of highly compressible SBM systems can confuse hydraulics modeling, especially when
trying to optimize bit nozzles. The compressible nature of some SBM systems can cause the bit’s
pressure drop to be more or less than for WBM systems. We have seen SBM cases where the
bit’s pressure drop was significantly under-estimated with conventional hydraulics models. The
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use of PWD, that records internal and external pressures, is an effective way to optimize bit
hydraulics, by measuring the actual pressure drop.
‘Back-up’ cutters on the blade periphery (see Figure 43) are often used to increase cutter density
without the addition of extra blades. However, this is not recommended because of increased risk
of bit balling and/or heat checking due to poor cleaning of these additional cutters. Such back-up
cutters are particularly hard to clean and will therefore accumulate cuttings. Although the
primary cutters may be clean, the ‘dirty’ back-up cutters will soon prevent efficient cutting action.
Back-up cutters (or impact resisting studs)
are at increased risk of balling due to poor
cleaning or inadequate hydraulics in this
area.
Figure: 43
Balling of Back-up Cutters or “Impact Arrestors”
12.6 BIT SELECTION FOR STEERABLE APPLICATIONS
When selecting a bit specifically for a steerable application, the objectives and limitations of the
steerable run should be clearly understood. If the steerable run is only a short correction run, then
bit longevity may not be an important issue and a tri-cone bit may be preferable to a PDC bit. If
the run is for a long interval, then a PDC bit may be more appropriate. In all cases the bit
selection will be limited by lithology, but other factors must be considered if bit selection is to be
optimized.
When estimating the performance of various bit options for a steerable run on a high angle well,
several issues must be considered differently to ‘conventional’ low angle wells:
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•
Tool face control is more critical for high angle wells. This is not only because more slide
drilling may be necessary, but primarily because it is more difficult to maintain good tool face
control at high angles. This is because static friction between the wellbore and the drillstring
is more significant and smooth WOB transfer is more difficult to maintain. This is
exacerbated greatly if there is any buckling in the drillstring.
Buckling and stick-slip will affect PDC bits more than tri-cone bits because the sudden
slumping of WOB that occurs as the wellbore ‘releases it’s grip on the drillstring’ will
suddenly torque up a PDC bit. A tri-cone bit will allow a higher WOB range, which makes
weight transfer easier. The roller cone design also creates less reactive torque than the dragbit nature of a PDC bit. This will result in more time on-bottom as well as reduced sliding.
•
Following on from the above discussion on tool face control, if a heavy set PDC bit (more
blades) is being considered for steerability reasons, is it too heavy set that;
(a) the ROP benefits of PDC bits are largely negated?
(b) balling is an increased risk (especially if bit hydraulics are limited)?
(c) tripping problems are more likely because of the reduced junk slot area of the bit?
There are some specific “steerable” PDC bit designs on the market today that are of
considerable concern. These designs, while they may be effective at improving tool face
control, are a particular concern for tripping in high angle wellbores.
•
Bit and motor hydraulics are important elements to effective bit selection. PDC bits will be
more affected by poor ‘motor’ hydraulics. PDC bits and motors are only an efficient
combination if the motor can be run at the upper end of its flow range. Otherwise, excessive
motor stalling problems will result.
If hydraulics is a limitation, then the use of PDC bits with steerable motors are automatically
suspect for drilling tangent sections.
Under these hydraulically limited circumstances, consideration should be given to drilling
with a tri-cone bit (if a steerable BHA is necessary), or consider alternate rotary BHA
strategies. Under these conditions, the lower achievable ROP with a tri-cone bit may be
acceptable and hole cleaning constraints would, most certainly, limit permissible ROP with
PDC bit, anyway. The difference between the two ROP’s may be small, though tri-cone bit
longevity may come into play if it is required to drill a long interval.
Premium tri-cone bits are always recommended for these applications.
It is a misnomer that PDC bits should be designed for “less reactive torque”, as reactive torque is
not the problem. It must be remembered that torque = ROP for a PDC bit and so torque is
desirable. What is needed is smoother torque response to WOB fluctuations. Increased backrake
and spiral gauge pads tend to help with this problem. Cutter technology is also a means to
address this issue.
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13 SURVEYING AND GEOLOGICAL UNCERTAINTY MANAGEMENT
Survey uncertainty is an issue that has received much attention in recent times. It is beyond the
scope of this text to analyze the highly complex and scientific methods used to survey a well.
Suffice to say, however, that survey uncertainty is an important issue that must be dealt with in
ERD.
Survey uncertainty has become more important since the step out on wells has increased, and the
relative (and absolute) target sizes have been reduced. It is not unusual on an ERD well for the
surveying uncertainty to exceed the target size. Even with the most advanced gyroscopic
surveying tools, the survey uncertainty can be significant. Because of this, there are several
fundamental aspects of the well plan that must be adapted and the limitations of the current
available drilling and surveying technology should be clearly understood.
With growing ERD capabilities, and the need to reduce project economics, more ERD wells are
being drilled for exploration purposes. ERD exploration wells are typically used for small
satellite fields that often cannot justify the mobilization and drilling costs for a MODU well. An
ERD well may offer the convenience and savings of using an existing platform rig to drill to a
small satellite location. It also offers the potential for much earlier and cheaper production if the
prospect is successful. However, with the increased advent of exploratory ERD drilling, it is
important to recognize the inherent geological uncertainty involved with this type of work.
Geological uncertainty is also a real problem in conventional production ERD operations. In
particular, geological vertical uncertainty is a concern that often does not receive fair attention.
This section aims to highlight some of the main issues related to surveying and geological
uncertainty management in ERD wells. It purposely avoids going into too much detail, as
surveying can become a very complex and confusing topic and each Operator will generally have
their own standards and procedures in these areas.
13.1 THEORY AND DEFINITIONS
Survey accuracy is driven by the following technical requirements:
•
Intersection of geological targets
•
Collision avoidance (to avoid intersecting existing wells)
•
Blow-out contingency (intersect the old wellbore with a relief well)
With the increased survey uncertainty on ERD wells, all of these requirements can pose
significant challenges.
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13.1.1 Confidence Interval
Comparing tools and service companies is often difficult and confusing, because the terminology
and assumptions used for quoting accuracy vary widely.
The most important thing is to ensure that the “confidence interval” or “error band” is understood.
This can be quoted at 1,2 or 3σ.
•
1σ – 67% confidence that survey lies in the quoted error (33% chance of being outside)
•
2σ – 95% confidence that survey lies in the quoted error (5% chance of being outside)
• 3σ – 99% confidence that survey lies in the quoted error (1% chance of being outside)
Generally a confidence interval of 2σ is the minimum meaningful number. This equates to a 95%
confidence that the surveyed location is within its quoted error band. Hence, if a survey
uncertainty is quoted as 50’ (15m) TVD and 200’ (60m) lateral, then this statement is made with
95% confidence. There will still be 5% possibility that the surveyed position is outside this area.
Uncertainties quoted at 1σ (67% confidence) will produce seemingly more favorable numbers,
but it must be understood that the comparison is made with a lower confidence level.
Survey uncertainty quoted to 3σ will have the
largest value, but you have 99% confidence that
the actual wellbore position is within this circle
Survey uncertainty quoted to 2σ will have a
larger value than 1σ, but you have 95%
confidence that the actual wellbore position is
within this circle
Survey uncertainty quoted to 1σ will have the
lowest value, but you only have 67% confidence
that the actual wellbore position is within this circle
Figure: 44
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13.1.2 MWD Operation and Uncertainties
MWD survey tools derive azimuth from the horizontal components of the Earth's magnetic field,
measured with a set of magnetometers. Knowing that the horizontal component of the Earth's
magnetic field is directed to magnetic North, the ratio of the horizontal magnetic field
components measured is equal to tangent azimuth. In addition, inclination and toolface are
derived from accelerometer readings. If required, a magnetic toolface can be obtained from the
horizontal magnetic field components.
The uncertainties associated with MWD surveys can be divided into the following categories:
•
Sensor uncertainties - due to accelerometer and magnetometer imperfections. Excessive
sensor uncertainties are eliminated by proper calibration and calibration checks.
•
Running procedure uncertainties - mainly BHA deflection uncertainties. They may cause
significant TVD uncertainties, particularly in high inclination wells (see Figure 45).
•
Geomagnetic data uncertainties - uncertainties for local magnetic field strength, dip angle and
declination. The declination is used in all calculations and so the consequent uncertainty is
always present. Correction programs such as SUCOP are used to minimize uncertainty.
•
Drillpipe tally uncertainties and drillpipe stretch
For MWD tools in ERD wells, a major source of vertical uncertainty comes from the deflection of
the BHA between stabilizers. Deflection may be as high as 0.3°. The exact magnitude of the
deflection depends on the bottom hole assembly configuration. The effects of BHA deflection
must be accounted for using BHA sag corrections.
Inclination Sensor
X
The MWD collar should not be assumed to be oriented parallel to the hole
X
There will be flex and tilt within the BHA that is sufficient to have a significant effect on the
overall survey result – in this case the survey will read high and will require sag correction.
Figure: 45
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Magnetic interference correction techniques correct the raw measured data for magnetic
interference from the drillstring and enable the required length of NMDC to be reduced. These
correction techniques cannot correct for magnetic interference from non-drillstring components
such as nearby casings or magnetic formation anomalies. Magnetic interference correction
techniques will be of limited value in high inclination wells (>70°), or in East/West direction ±
20° (azimuth of 70-110° and 250-290°). In these instances the full-recommended length of
NMDC will most likely need to be run (gyro surveys also more likely to be run).
13.1.3 Gyro Operation and Uncertainties
Generally, only North Seeking gyro tools are used on ERD wells due to their improved accuracy
over conventional gyro tools. A North Seeking gyro uses a gyro to reference itself to True North.
This referencing is called gyrocompassing. It is based on the measurement of the horizontal
component of the Earth rotation vector, which becomes smaller for increasing latitudes, and
hence reduces the ability of these tools to accurately seek North. In general, they have an
application limit of a maximum latitude of 80 degrees North or South. They are generally run on
wireline and transmit survey data real time to surface. However, in an effort to save rig time and
wireline costs, battery powered drop tools are being used more frequently on ERD wells. These
tools are dropped prior to POH with the BHA, and survey to surface on the trip out.
North Seeking tools have two basic modes of operation:
•
Gyrocompassing mode, with the tool held stationary at each survey station whereby the
azimuth is calculated independently at each survey station.
•
Continuous mode. At the start of the survey interval the tool is referenced to True North by
gyrocompassing. After that, the tool is run continuously with integration of the azimuthal
tool rotation.
In addition to the gyro, these tools have a set of accelerometers for measuring the Earth's gravity
field, from which toolface and inclination are determined. In vertical wells a gyro toolface
similar to the magnetic toolface of a magnetic tool is measured.
Uncertainties of North Seeking gyro tools are a function of:
•
Tool uncertainty – inherent inaccuracy in the tool (gyro mass unbalances, accelerometer and
gyro scale factor, etc.)
•
Running uncertainty – wireline depth uncertainties, temperature effects, tool misalignment,
etc.
Quality control is again key to reducing Gyro survey uncertainty in ERD wells.
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13.1.4 Random and Systematic Errors
It is important to understand that quoted survey accuracy assumes that good surveying practices
are used and that there are no systematic errors that are being introduced into the equation. Many
of the surveying accuracy assumptions assume that sources of uncertainty are random, but that
these random errors may accumulate. This includes errors involved with the tool’s ability to
measure inclination and direction, as well as attempting to allow for errors as a result of
environmental forces (such as naturally occurring magnetic field fluctuations).
In reality, the survey errors may accumulate if there are systematic errors introduced. Common
errors include magnetic field disturbances due to the BHA design, and misalignment of the survey
tool inside the BHA or drillpipe. Systematic errors are particularly important, since the errors
will most likely build in the same direction (as opposed to randomly canceling each other out).
Systematic errors in gyro tools include Operator induced errors, survey station taken at intervals
equal to the distance between tool joints, pipe snaking due to pipe not being in tension when
surveying, and depth errors.
13.1.5 Survey Interval
To highlight the issues involved with surveying interval, an example is shown in Figure 46 for a
deep horizontal section drilled on an ERD well.
As can be seen, a definitive MWD survey taken on each stand fails to show significant doglegs
that had been put into the well. The continuous surveys provided from the MWD give a much
more accurate picture of what was happening in the hole. Without these continuous surveys, the
Operator would have not been able to identify these significant doglegs that ultimately led to
changes in the well plans.
This is generally only an issue in horizontal or build sections. For wells where torque and drag
are critical, consideration should be given to using an MWD that provides continuous surveys, or
surveying more frequently.
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92
Continuous Survey
91
Definitive Survey
Inclination
90
89
88
87
86
7400
7500
7600
7700
7800
7900
8000
m MD
Figure: 46
Survey Comparison
13.2 OPTIONS TO REDUCE SURVEY UNCERTAINTY
13.2.1 MWD Surveys
MWD survey quality varies from company to company and it is pointless comparing companies
in this manual given the speed with which the surveying quality and MWD companies are
advancing this technology. Not only is the actual hardware improving in accuracy, but software
programs that allow for magnetic anomalies are also being improved (i.e. SUCOP, Short Collar
Correction, MAC 2, etc.). It is important, however, that the local field and management
personnel have an appreciation and thorough understanding of the importance of these issues.
The following operational practices should be in place to ensure the surveying uncertainty with
MWD tools is minimized:
•
MWD tools must be thoroughly calibrated and painstakingly put through quality
control/assurance measures.
•
MWD tools and collars should be changed out on every trip (allows a cross-check of surveys)
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•
Field personnel must accurately model the ‘bend’ of the MWD collar as depth and angle
increases (see Figure 21).
•
Checks should be made for magnetic hot spots in NMDC’s.
•
Magnetic corrections should be applied to surveys
•
In-hole and In-Field Referencing (as discussed in following sections)
13.2.2 Gyro Surveys
It is strongly recommended that a high quality gyro survey be made at least at one intermediate
point in the well to act as a crosscheck and to allow for correction of the trajectory (if necessary).
This gyro survey point should be sufficiently deep in the well to be worthwhile, but shallow
enough to allow ‘enough room to maneuver’.
Current surveying technology and practices kept pace with ERD advancements. K&M was
involved in a comprehensive evaluation of the industry’s gyro surveying tools after large TVD
discrepancies were observed between the MWD and gyro surveys in three ERD wells. The
following are learnings to come from that exercise:
•
Gyro inclination technology is sensitive to a number of factors, the most notable being
inclination and temperature. On long high angle ERD wells (>75°), MWD surveys may
actually provide improved inclination accuracy over some gyro tools.
•
Stabilized azimuth readings produced more accurate lateral survey results.
•
Continuous surveying tools that are initialized at vertical and then benchmarked continuously
are the most accurate gyro tools.
13.2.3 In-Hole Referencing (IHR)
In-hole referencing is a technique that helps to compensate for uncertainties related to the Earth's
magnetic field, and hence reduces systematic errors over long tangent sections. It was first
developed for use on BP’s Wytch Farm Project. The method can be summarized as follows:
• A gyro survey is taken in the open hole tangent section (pump gyro tool down the drillpipe).
• A 100m (330 ft) interval of the tangent section is selected, such that the interval has less than
0.5°/30m walk, and gyro stations are selected at ± 20m stations across that interval.
• Every new BHA/probe that is run then takes roll test surveys at each gyro survey station in
this 100m interval. Four surveys are taken at each station, tool face settings 90° apart.
• The average azimuth difference (compared to the gyro survey) is then used to provide an
azimuth correction to all subsequent MWD surveys.
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The method potentially offers significant accuracy gains at little extra cost, but is highly
dependent on the quality of the gyro reference survey.
13.2.4 In-Field Referencing (IFR)
In-field referencing is a technique that was developed and patented by Sperry Sun for correcting
MWD data using real-time values of the local magnetic field. It was first used in 1995 at BP’s
Wytch Farm with positive results. On land, the method is cheap and easy to run. However,
development of a system for use offshore is far more complex and often not feasible. The method
also has limited application at higher latitudes where the magnetic field variations are far more
complex.
13.2.5 Geosteering
This technique was initially developed for horizontal wells and thin reservoirs, where it was
required to remain in a particular area of a reservoir (i.e. away from an oil water contact and as
close as possible to the top of the oil zone). Instead of steering with directional sensors to a predetermined well plan, the well is drilled and steered using FEWD data from different logging
tools in the string (i.e. GR, Res, Density/Neutron, etc.). The success of geosteering depends on
having an accurate reservoir model and log information to allow the location within the reservoir
to be determined from the FEWD logs.
As the directional sensors are no longer directly relied on for drilling the well, this eliminates
survey uncertainty as a significant issue. It also eliminates geological uncertainty as a major
issue.
13.3 TARGET DESIGN
13.3.1 Target Size and Shape
When designing targets for ERD wells, the importance of getting a target as large as possible
cannot be overstated. This is due to the increased survey uncertainty, geological uncertainty and
the reduction in the target size at high inclinations. This reduction is demonstrated in Figure 47
below.
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45°
Section
View
Plan
View
200’
Borehole
View
141’
Figure: 47
80°
200’
35’
Decrease in Target Size at High Inclination
As a rule, advocate the use of target shapes that represent the real geology. Geological prospects
are not usually as geometrically simple as a circle or a rectangle. Therefore a circle or square
target is often an indication that the target area has been defined for simplicity.
It is important that ample thought is put into the target area. The size, shape and orientation of the
target area are all important. It is also vital that all parties involved in the target definition
understand the logic that has shaped the target area and the consequences of missing the target in
any given direction.
On any given directional well, the target size and shape have a direct impact on the well cost. A
large target means that the directional drilling can be ‘loose’ and high ROPs will result. A small
target means that directional drilling will dominate the well time, with much slower overall ROP
due to slide drilling and BHA changes. Alternately, smaller targets may require the use of RST’s.
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Expansion
Target Area
Fault
Preferred
Target Area
Since the target area is bounded by
large faults to the South and East,
and there is possible expansion to
the West and North, the aim point
should be appropriately placed in
the North-West of the preferred
target area.
If the aiming point was in the
center of the preferred target area,
any deviation towards the hard
boundaries will have significant
time and cost implications.
Fault
Aim Point
Figure: 48
Possible Target Design Scenario
It is important that the consequences of missing the target, in every possible direction, are
considered. The target area should be considered in the following terms:
•
Critical Area:
•
Preferred Area: As the name suggests, this is the preferred area of intersection. It is a subset
of the critical area. The wellbore should be aimed at some point in this area,
though not necessarily at the center point. Reasonable effort should be
made to intersect the Preferred Area, but it should be clearly understood
how much additional effort and cost is necessary to justify this if the
wellpath is ‘walking’ away. For example, although this area may be the
preferred area, it may not justify extensive slide drilling or multiple BHA
changes to guarantee intersection.
•
Expansion Area: This area also falls within the Critical area, and is effectively the nonpreferred area. It is however part of the legitimate target area, and may be
intersected if the well is to ‘walk’ in this direction. The boundary between
the Preferred and the Expansion areas is a ‘soft’ boundary.
•
Excluded Area: This is outside the target area. However, it specifically refers to an area that
must be avoided at all cost. It will be separated from the target area by a
‘hard’ boundary (such as a large fault).
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This is the overall target area that the wellbore must intersect to be
considered successful.
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13.3.2 Allow for the Survey Uncertainty
It is common for many Operators to reduce the target area by the lateral survey uncertainty
(usually at 95% confidence) as shown below. In some cases, only the ‘reduced’ target area is
shown or referred to in the Drilling Program.
If this is done, however, the original and reduced target areas should be printed on the well plan
plots to reduce confusion. It must also be remembered that the original target area will be
constant, but the reduced area will vary with time, depth and surveying strategy. Hence the latter
is not absolute and so it should not be the only target area shown. The reduced target area should
be constantly redefined, as the survey plan and the well path change. For example, the following
possibilities may require that the survey uncertainty estimate be redefined:
•
Additional or fewer gyro surveys may be taken during the drilling operation, improving or
reducing the confidence of the survey accuracy.
•
The casing plan may vary, and therefore the gyro survey points may be different to the
original plan.
•
The MWD may overlay the gyro results particularly well, increasing confidence in the MWD
surveys. The survey uncertainty for that particular MWD tool (in that BHA design) may
therefore be improved. Alternately the reverse may occur.
150m
Ellipse of Uncertainty:
N-S = 15m
E-W = 70m
150m
DRILLING TARGET
(Target area after survey
uncertainty allowed for)
= 80m x 135m
GEOLOGICAL TARGET = 150 x 150m
Figure: 49
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Example of Geological and Drilling Targets
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13.4 REDUCING GEOLOGICAL UNCERTAINTY
Geological uncertainty is an issue that does not receive enough attention in ERD planning. While
surveying uncertainty may receive attention and concern, the geologist’s target size and
placement (vertically and laterally) are usually taken as gospel.
As already discussed, the target logic should be well understood by the drilling planning team.
As well as the target boundaries, the realistic TVD uncertainty must be well appreciated. It is rare
that the geologists and geo-physicists can predict TVD uncertainty within ± 15m (50’).
Geological TVD uncertainty is more of an issue for ERD wells (compared to vertical or low angle
wells) because of the high ‘angle of attack’ (AOA), relative to the target plane. At such high
angles of attack, a TVD discrepancy can have very serious ramifications, especially when
combined with the survey uncertainties that will be present. For example, at 80° AOA, the well
will have a lateral displacement of 58m (190’) for every 10m (33’) that the targets were to come
in low or high. As shown in Figure 50 below, drilling S-Turn wells is one way to minimize the
impact of Geological TVD uncertainty.
S-Turn wellpath
Build and Hold
Wellpath
Target at prognosed TVD
Target comes in low
Build and hold wellpath with high AOA misses the
geologically low target, whereas, the S-Turn wellpath is
less affected by geological TVD uncertainty
Figure: 50
Benefit of S-Turn Profile with Geological TVD Uncertainty
If there is a high degree of geological uncertainty, a pilot hole should be considered to better
define the geology before attempting to hit the target and land a horizontal well. Geosteering, as
discussed previously, is also an option to reduce geological uncertainty.
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14 CEMENTING
Without a quality production cement job, the entire value of the well can be lost very quickly,
particularly if zonal isolation is a critical parameter. Cementing on ERD wells can be complex
and difficult, and should not be an area glossed over in the planning process.
Following are some of the main reasons why cementing is more difficult on high angle ERD
wells:
•
Inability to move pipe while cementing
•
Viscous mud systems are generally required to drill ERD wells and these are difficult to
remove from the hole without pipe movement
•
Flow regimes works against good displacement
•
Low side channels due to the inability to displace mud and cuttings
•
High side channels due to free water and settling
•
Poor centralization as a minimum of centralizers are required to get casing down
•
ECD’s may restrict displacement rate (if circulation is lost during cementing then the quality
of the job must be questioned)
•
Limited remedial options
14.1 DISPLACEMENT INSIDE CASING
One of the main problems (which is more pronounced on long ERD wells) is the contamination
of cement and spacers as they are pumped through long strings of casing. As can be seen in
Figure 51 below, the middle of the slurry and spacers tends to get pumped out, causing
contamination and leaving cement on the casing ID.
Good internal displacement can be achieved by using multiple bottom plugs for spacer train and
cement separation. Refer to Section 14.7.
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FLOW PROFILE RESULTS IN CEMENT
SEPARATION AND CONTAMINATION
High velocity
fluid in center
Low velocity fluid near
wellbore or casing sides
Figure: 51
Fluid Flow Profile Inside Casing
14.2 DISPLACEMENT OUTSIDE CASING
On the outside of the casing, eccentricity works against the displacement of mud and cuttings
from the low side of the hole. The fluid takes the path of least resistance and will preferentially
flow on the high side over the top of the pipe. Without pipe rotation, this is very difficult to avoid
and leads to the formation of low side channels (see Figure 52 below). High side channels can
also form due to free water being released when the cement thickens.
Eccentricity works against good
displacement around the casing
Hole
Flow channels develop due to poor
displacement of mud and cuttings,
and free water in cement
High
Flow
Cement
Channel
Static Fluid
Casing
Figure: 52
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Displacement Difficulties Outside Casing
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Drilling Design and Implementation for Extended Reach and Complex Wells
14.3 CEMENTING CASING
Cementing ERD wells has not been overly successful where the cement jobs were critical and
pipe movement is not possible. In the viscous mud systems required to drill ERD wells, low side
channels are difficult to remove with circulation alone, and centralization is often secondary to
getting the pipe into the hole (centralization stiffens the pipe and often makes it more difficult to
run).
When designing a cement job for an ERD well, the best place to start is by making sure that the
hole and what is currently filling it, one working for your good cement job and not against it. In
that respect, leaving a very clean wellbore, with a thinned-down fluid that is not building a thick
filter-cake meets these requirements.
Spacer train technology, combined with engineered cement slurries, has been used successfully
by North Sea and Australian Operators. Spacer train technology attempts to utilize the forces that
are available without pipe movement to erode filter cake and settled mud. These forces include
chemical (surfactant) and rheological (varying high and low viscosity’s). Refer to Section 14.7
for further details.
Sacrificial cement is also common in these jobs whereby the first part of the lead slurry is used to
"sweep" the hole. Sacrificial cement should be weighted at least 2 ppg higher than the mud
weight in the hole in order for it to displace the mud and wall cake on the low side of the hole.
This same rule of thumb applies to the weighted portion of the spacer trains. The most successful
scavenger slurry is a nitrogen-foam slurry, however, if this equipment is not already on location it
is difficult to justify.
Where good shoe jobs are critical, “walking squeezes” can be utilized to maximize displacement
efficiency of already gelling cement slurry. Here, the tail slurry is designed with a gelation time
equal to the mixing and displacement time for the slurry. The last 20 bbls of the tail, prior to
bumping the top plug, are displaced at ±1 bpm to utilize plug flow displacement right at the shoe.
In summary, it is very difficult to obtain a good cement job on a high angle casing string without
pipe movement. Good practices for maximizing the chances of a good job are:
•
Start with a clean hole with thinned mud
•
Extensive hole circulation with the casing at TD
•
Large spacer train pumped ahead of the cement
•
Engineered cement rheologies and gel times (tail must set-up first)
•
Scavenger cement ahead of the primary lead and tail
•
Maximum cement displacement rates and a walking squeeze for the last 20 bbls of tail at the
shoe.
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14.4 CEMENTING LINERS
The best solution to curing cementing problems is to move the pipe. Rotating liner systems are
now reliable and strong enough to meet most applications in ERD wells. The global answer to
cementing ERD wells is if the cement job is critical, then run a rotating liner to ensure that the
job is successful. Premium high-torque casing connections can now be readily obtained that have
exceptional torque capability. Also, roller centralizers are available that allow for torque (and
drag) reduction in cased hole, and in open hole as well.
To avoid risky cleanout operations in liners, and maximize the internal displacement efficiency,
consideration should be given to using an inner string cementing technique that is now available
from most liner suppliers. As shown below in Figure 53, an extra long overlap prevents cement
from coming back up above the liner top. This eliminates up to two scrapper runs with a slim
workstring, which is a high-risk operation on long ERD wells. The internal displacement
efficiency is also improved as multiple balls and darts can be used to wipe the pipe and stinger
clean.
2 7/8” inner string hung
from liner running tool
±1500’ liner lap
Multiple plug
catcher
Drill Pipe
Liner
Figure: 53
Inner String Liner Cementing
The most common size of liner in 8½” hole is 7”. If the cement job is critical, and
production/completion constraints allow, consideration should be given to running a 6⅝” or 5½”
liner. The liner will be easier to rotate (less torque), less ECD will allow higher displacement
rates, and the general quality of the cement job will be improved with a thicker cement sheath.
There is the added advantage that the smaller liner will also run in the hole with less drag
(significantly more annular clearance).
Reamer shoes are recommended with liners, as they will aid rotating in the hole if it is required.
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14.5 OPEN HOLE CEMENT PLUGS
Setting successful cement plugs (for abandonment or sidetracking) in high angle openhole
sections is often difficult to achieve. Each Operator will tend to have their own procedures and
practices that have worked for them, but following are some general guidelines that have come
from many different operations:
• Hole Preparation - prior to spotting a base plug or cement plug, the hole should be cleaned
up using standard hole cleaning practices.
•
Cement Plug Base - the cement plug should have a base. This may take the form of a thick
hi-vis pill, an openhole packer or even another cement plug. A hi-vis pill should be 50-100m
in length and of a similar weight to the cement slurry.
•
Stinger - the cement plug should be set with a small stinger to minimize the disturbance to
the cement after setting a balanced plug. In 12¼” and 8½” hole, 3½” drillpipe or tubing will
be acceptable. A diffuser nose or upward facing jets should be run on the bottom of the
stinger to promote the upward flow of the cement.
•
Spacers - spacers should be circulated in front of the cement as per a normal casing job.
•
Slurry - The slurry should be designed with a weight similar to the mud in the hole (if
possible). Slurry rheology should be kept as low as possible to minimize contamination of
the slurry as the stinger is pulled through the plug after displacement. As large a volume of
cement as possible should used to minimize the effects of any contamination and provide
excess length to ensure the well is kicked off. Ensure the slurry has adequate thickening time
to pull the stinger back through it.
•
Plug Placement - The procedure used to spot the plug is critical.
•
Pipe rotation and maximum annular velocity (within ECD limits) should be used during
displacement to improve displacement efficiency.
•
Alternately, some success has been seen with setting sidetrack cement plugs on high angle
wells by placing the cement at low flowrates. The cement is displaced down the drillstring at
high flowrates, but is “dribbled” into open hole at only 1-3 bbl/min. Pipe rotation (120rpm) is
critical to the success of this technique.
•
Pulling stinger - On completion of the displacement, the stinger should be pulled through the
plug at as slow a rate as possible to minimize contamination and prevent the disturbance of
the plug.
•
Circulation - Reverse circulation should not be attempted as the resultant ECD’s may push
the plug down the hole.
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14.6 SLURRY DESIGN
Cementing circumstances in ERD wells are less than ideal. Not only is there likely to be a
cuttings bed on the low side that can act as a channel, but also casing centralization is likely to be
less than optimum, and the drilling fluids are likely to be less than ideal for cementing. To further
complicate cementing difficulties, the cementing and pumping volumes and times involved can
be very large.
With the usual downhole circulating temperature uncertainties, it is common that cementing
slurries are designed with large, conservative thickening times. In fact, the thickening times are
likely to be far too conservative, to the detriment of the cement job.
The planning time and effort that is put into cementing design is usually sadly lacking, especially
compared to the planning that takes place for other operations. It is not unusual that cementing
planning consists of little more than calculating volumes and pumping/thickening times (with
safety factors that are typically 20% more than the theoretical numbers). Furthermore, the
cementing contractor is usually only told (a) density, (b) fluid loss, (c) thickening times and
probably (d) 12 hour/24 hours compressive strength.
An important slurry design principle is that the cement slurry should set from the bottom upwards
for optimum cementing performance. If the cement sets from the top downwards, then the
hydrostatic pressure will be released on the lower cement, which is yet to set. Under these
circumstances, the formation of channels is much more likely. This is particularly true for gas
wells.
For critical cement jobs, it is recommended to use multiple slurries, with the later slurries having
earlier set-up times. Although separate lead and tail slurries are commonly in use already, often
the slurries are not specifically designed to set up in a particular order. Depending upon the
specific cementing objectives for a well, it may be appropriate that 3 or 4 or more separate
slurries are pumped, with each slurry designed to set before the slurry above it. This is shown in
Figure 54 below:
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MULTIPLE CEMENT SLURRIES, DESIGNED
TO SET FROM THE BOTTOM UPWARDS
1st (Lead) slurry,
designed to
set up last
2nd slurry, designed
to set up before the
slurry above it.
Tail (last) slurry,
designed to set up
first.
Figure: 54
Cement Slurries Designed to Set from Bottom Upwards
An additional requirement for cementing at high angles is that ‘free water’ should be tested and
controlled. At high angles, the cement ‘solids’ tend to settle to the low side, while the ‘free
water’ collects to the high side, resulting in a channel on the high side of the hole. Note that the
‘free water’ test/control is different to the standard ‘fluid loss’ test.
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14.7 SPACER TRAINS
ER wells require much better pre-flush planning than conventional wells as the circumstances are
often inherently poor for cementing. Several factors come into play that demand more effective
pre-flush arrangements:
• The drilling fluids used in ERD wells are often OBM or SBM type systems. These fluids are
inherently poor for cementing quality because the wellbore will be oil-wet, and a good
cementing bond requires water-wet conditions. The removal of oil based sludge and filtercake is also quite difficult.
• In order to break down the sludge and filter cake and to water wet the formation/casing, preflush spacers and/or long lead cement slurries are utilized. The key to the effectiveness of
these spacers is to maximize the time that they are exposed to the wellbore. In order to
establish the minimum exposure time, test should be carried out by the mud/cementing
company to evaluate the effectiveness of the chosen spacer system on the mud being used.
• The presence of a cuttings bed is likely, even if the hole has been backreamed prior to running
casing. As such, it will be necessary to remove these cuttings. In the absence of pipe rotation,
the only method available for this is the use of thin-thick pre-flush sweeps.
• The long casing lengths, combined with laminar flow regimes, result in the pre-flushes and
sweeps being deformed and, effectively, lost before the spacer(s) have even reached the casing
shoe (refer to Figure 51)
Because of these factors, it is important that the pre-flush spacers are (a) designed specifically for
the circumstances, (b) of sufficient size to be effective, and (c) are well confined while within the
casing.
The following are recommended:
•
Multiple spacer sweeps are required, in a specific sequence. In an OBM/SBM environment,
it will probably be necessary, as a minimum, to run a sequence of :
Base fluid spacer, as a buffer to the OBM/SBM fluid
Low-vis/Hi-vis sweep, for cleaning below the casing (weighted)
Surfactant, for water wetting of the wellbore (weighted)
Lead cement, possibly nitrified (for improved cleaning around the casing).
For critical cement jobs, under poor circumstances, K&M has used up to 7 spacers.
•
These spacers must be well confined while being pumped down the casing. This is achieved
by separating each spacer with standard pump-through, bottom wiper plugs.
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POSSIBLE 'SPACER-TRAIN' ARRANGEMENT
Spacer #5
Lead Cement
Extended, Nitrified
Spacer #4
Surfactant
Figure: 55
Spacer #3
High Vis Sweep
Spacer #2
Low Vis Sweep
Spacer #1
Base Fluid
Multiple Bottom Wiper Plugs
Since the typical cement head equipment can only handle two (2) wiper plugs, this method will
necessitate that the cement head be broken open several times to insert new wiper plugs. For this
reason, it will be necessary to plan the job so that the annular hydrostatic pressure exceeds the
bottom-hole casing pressure, so that the cement head can be opened up safely without the well
being on a vacuum.
Although this approach may sound unduly complex, it has improved cementing reliability and
quality in ERD wells.
14.8 ECD ISSUES
High ECD’s often limit ideal cementing parameters for both long strings and liners.
following should be considered if ECD’s are an issue:
The
•
Avoid tapered long strings (i.e. a tapered 10¾” x 9⅝” has a much higher ECD than 9⅝”).
•
Run the long string as a liner and tie back at a later point in the well. The tieback can be a
larger OD pipe.
•
Use smaller casing/liners or drill larger hole sizes (i.e. under-reaming or bi-center bits).
•
Minimize the number of centralizers run and ensure that both centralizers and stop collars are
designed with maximum flow-by area.
•
Ensure hole is clean, mud rheology as low as possible and use lightweight cement slurries.
Note that if circulation is lost during cementing, the quality of the cement job is in question.
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14.9 CASING CENTRALIZATION
Good centralization improves cementing, but the first goal must be to get the casing to bottom.
Casing running friction factors will be quite sensitive to the centralization program and tortuosity
of the wellpath. The centralizer type, placement frequency and overall number will all affect the
casing drag. Centralizers act to stiffen the casing and, if bow spring centralizers are used, can act
as “brakes” on the casing string (as the restoring force of the centralizer applies a normal force to
the wellbore wall). This can be clearly seen when the centralized portion of the casing enters and
exits a build/turn section. The following centralizer observations are made:
•
Centralization should be minimized (within cementing objectives)
•
If pipe rotation is not required, then semi-rigid or ‘double bow’ centralizers are
recommended. Since the outside diameter of these tools is equal to the hole size, the “brake”
action of a conventional bow spring centralizer does not exist.
•
If pipe rotation is required, then solid body centralizers are recommended. These should be
as short as possible to reduce casing stiffness. Zinc alloy centralizers have been shown to
reduce rotating torque when compared to Aluminum type centralizers.
•
To limit ploughing, it is recommended that the shoe track be centralized for maximum shoe
standoff and maximum shoe track flexibility. The optimum method for achieving this
involves placing 1-2 centralizers back-to-back at the very bottom of the shoe joint, to ‘lift the
nose up’. There should then be no centralizers at all for the next 2-3 joints (see Figure 56).
•
Roller centralizers are proving very effective in client wells at reducing friction factors across
critical intervals. In general, a two thirds reduction in friction factor is seen in cased hole, and
some degree of improvement will probably been seen in openhole if formation are
consolidated, although this should not be included in planning assumptions.
The conventional centralization (as above) will stiffen the casing shoe significantly. It is more likely to
hangup or plough when running in the hole through a build or turn, or while passing a ledge
This centralization is less likely to have problems running in the hole
Figure: 56
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Recommended Shoe Track Centralization
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Drilling Design and Implementation for Extended Reach and Complex Wells
15 WELL CONTROL
We will not attempt to re-write the book on well control in this text. However, well control
situations in highly deviated wells do present some unique challenges that are worthy of
discussion. Kicks in these wells are more probable, more difficult to detect, more difficult to kill,
and more likely to breakdown the wellbore. This section discusses the reasons for this higher
exposure, suggests methods to minimize exposure to kicks, and how to deal with any that may
occur.
15.1 WELL CONTROL BASICS
As a general review of well control basics, a ‘kick’ is the unplanned entry of formation fluids into
the wellbore. A primary function of drilling fluid is to apply sufficient hydrostatic pressure to the
formation to prevent this influx. Insufficient hydrostatic pressure across a permeable formation
containing fluids, can result in a kick. Kicks may consist of water, liquid hydrocarbons or gas.
To avoid formation breakdown, these gases must be allowed to expand as the kick moves up the
annulus and out of the well. It is not possible to know the exact composition of a kick while
downhole, therefore, kicks should always be treated as if they contain gas.
The following example is shown to demonstrate the basics of well control. Note that this is for a
vertical well killed with the Drillers Method.
• Vertical well
• 1 ppg kick intensity
• 1200 psi friction
pressure @ kill rate
Mud Weight 9 ppg
4680 psi
Hydrostatic
Open sand with insufficient MW
10 ppg gas sand at
10,000’ = 5200 psi
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Initial Shut-in Conditions
610 psi
9 ppg mud
Inside & out
Gas bubble
520 psi
• DP full of gas-free mud
• SIDPP used to calculate
kill MW
5200 psi in sand,
Annulus & DP
10,000’
If bubble rises without allowing expansion…
5200 psi
9 ppg mud
inside & out
5110 psi
Gas bubble at surface
(at original pressure)
9790 psi BHP!
(but will burst casing
or lose returns first)
10,000’
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Drillers Method: Hold BHP Constant
Casing
pressure
varies
1720 psi
held
constant
Choke
Pump mud
@ kill rate
Bubble allowed to
expand as it rises
9 ppg mud
inside & out
5200 psi
constant BHP
Pump
Kill Rate
SI
=
+
Press DPP Friction Press
= 520 + 1200 = 1720 psi
10,000’
Drillers Method: Bubble Out, Well Shut-in
520 psi
520 psi
Choke
Closed
9 ppg mud
inside & out
• DP & Casing pressures equal
• Well is not dead
• Must circulate-in kill MW
5200 psi BHP
10,000’
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15.2 WELL CONTROL - WHAT’S DIFFERENT ABOUT ERD WELLS
15.2.1 Taking a Kick
In general, the risk of taking a kick on an ERD well will be marginally higher than that on a
vertical or low angle well. This is based on the following:
• Increased risk of swabbing in a kick due to:
Static cuttings bed on the low side of the hole will decrease the flow-by area around the
bit and BHA
The bit selection and stabilizer designs typically used in ERD (say for improved
steerability performance) mean reduced junk-slot area
Because of ECD and pump pressure reasons, mud weights are typically run as low as
practicable on ERD wells, reducing the static overbalance pressure
The trip distances are much greater (and often more trips are made), and so the
opportunities for swabbing are increased
Thicker mud systems used for hole cleaning may increase the likelihood of swabbing
•
OBM or SBM is generally used for drilling ERD wells. Gas in particular will dissolve easily
into these muds. When excessive amounts of gas in solution are brought to the surface they
can be rapidly released from solution.
•
Losses are frequently seen on ERD wells with high ECD’s. If not monitored and managed
carefully, overbalanced conditions can be lost.
•
Many ERD wells from platforms include an exploration component as they are drilled into
distant parts of the field. The targets have usually been appraised with vertical exploration
wells, but the overburden between the platform and the target may contain overpressured
formations. For example, an ERD well drilled from a platform to an outlying location
encountered a kick in an overpressured formation, even though the previous 28 wells drilled
from that platform (in all directions) had not seen any overpressure.
•
With long sections of reservoir open there is increased exposure while drilling, tripping and
with the hole static. There can be a tendency for rig crews and third party personnel to
become complacent in monitoring the hole.
•
ER wells are often drilled from rigs with relatively small pit capacities. Drilling fluids may
be passing through an 800 bbl pit system at 1100 gpm, drilling a hole with a downhole
capacity of 3000 bbls. The mud must be restored to premium quality and volume built to
account for fluid seepage losses in a short time frame. It is not uncommon to see a large
stream of water or base fluid being added at the mixing or suction pits. An interruption in
barite or whole mud additions can result in lower density mud being pumped, possibly
initiating a kick.
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15.2.2 Detecting a Kick
Detecting a kick in an ERD well tends to be more difficult than a low angle or vertical well for
the following reasons:
•
Wellbore geometry is such that increased pressures at the initial shut-in are difficult, and in
the case of horizontal wells, impossible, to detect. For example, a 10 bbl gas kick in a
vertical wellbore may contribute 300’ TVD length of bubble. If the same kick is taken in a
75° tangent section the bubble height will only be 75’ TVD, and only 30’ TVD in an 85°
tangent. Theoretically there will be no increase in pressure while the bubble is in the
horizontal section of a well. This also has implications for killing the well as discussed
below.
•
With the use of OBM and SBM on ERD wells, gas solubility and mud compressibility,
combined with large openhole volumes, can make influxes very difficult to detect.
•
Pit monitoring (i.e. flow in and out of the well) is complicated on an ERD well:
Hole “Ballooning” - with ERD wells, it is normal for the pits to drop as the pumps are
brought on the hole, and rise as they stop. As the hole loads up with cuttings when
drilling commences, a pit gain can be seen as the cuttings displace the fluid on the low
side of the hole. Fluid compressibility also plays a role in “ballooning”. It can take some
time for fluid returns to start at the surface and for fluid flow to stop after the pumps have
been turned off, if a highly compressible fluid is being utilized.
Mud mixing - The mud pits are an area of great activity while drilling. Whole mud
additions are made, mud is dumped and a continuous stream of additives is building
volume. Rig personnel become accustomed to continuous pit fluctuations and may not
react to a pit gain caused by a kick. Furthermore, in the case of invert emulsions, if the
mud’s activity is not matched carefully with that of the formations, fluid gains and/or
losses can be experienced as fluid is either absorbed into or leached out of the rock.
The use of “flow-in” vs. “flow-out” numbers can be misleading. The differential between
flow rate out and flow rate in is measured using a paddle in the flow line. An alarm can
be set to sound if the difference between the two exceeds a preset boundary selected at
the drillers’ console. In practice, this differential continuously varies as the string is
raised and lowered and with rate of penetration. In long, highly deviated wells, the
proportionally larger system results in even greater fluctuations. The continuous
fluctuations of this system may result in a failure to note a developing problem.
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15.2.3 Killing a Well
The following differences must be considered when killing an ERD well:
•
With the wellbore shut-in, rotation of the drillstring is generally not possible. The same fluid
dynamics exist as those for cleaning a high angle hole. Therefore, without rotation the fluid
will tend to travel up the high side of the hole, bypassing some of the influx and lighter
weight mud on the low side. This inefficient displacement will result in the well having to be
circulated several times in order to get the kick out and heavier mud in. Note that a rotating
BOP may be justified in some kick prone areas.
•
Flowrates will be lower in a well kill situation which will also decrease the displacement
efficiency.
•
With the use of OBM and SBM on ERD wells, controlling the influx can be difficult as gas
comes out of solution.
•
The geometry of the well will affect the pressure schedule during the kill operation.
Basically, casing pressures will rise very slowly with the bubble in the tangent section, then
rapidly in the build and vertical section. A ‘deviated’ kill sheet must be used to keep the
Bottom Hole Pressure (BHP) constant when circulating the well (refer to discussion in
Section 15.3).
•
ER wells often utilize mixed drillstrings with different sizes of drillpipe. This must also be
factored into the kill schedule.
•
Mud volumes will be very large and it may be difficult, if not impossible, to weight up the
system to Kill Weight Mud (KWM) in a single pass.
•
Volumetric well kills in ERD wells are unreliable and very time consuming. Fluid migration
rates in high angle holes will be very slow and portions of the kick can be retained in
washouts as the kick moves up the hole.
15.2.4 Other Differences
The following are other well control considerations that are different for ERD wells:
•
In some ERD wells, there is an incentive to build angle and set surface casing as shallow as
possible. Setting shallow surface casing will generally mean that the maximum permissible
kick size will be smaller than for a vertical well with the same measured depth.
•
When tripping, it is normal practice to pump a slug to allow the pipe to be pulled dry. After
pumping a slug and pulling a few stands, often a slow trickle of fluid will be seen coming out
of the annulus and is often interpreted as ‘swabbing’. This misinterpretation often results in
the string being run back to bottom and the hole circulated. Invariably, no swabbed kick is
seen at bottoms up.
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In actual fact, as the first few stands are pulled, the hole is being filled from inside the drillpipe
due to the slug. The rise in annulus level is due to the delayed pressure pulse as the pressure
from the slug propagates down the drillpipe and up the annulus. This can take some time in a
highly deviated well and should be allowed for.
•
Pressure While Drilling (PWD) tools are now commonly used in ERD wells. If the data is
used in real time, tracking PWD data may prove useful in detecting kicks. Unfortunately,
their usefulness once the well kill operation commences will be limited as the threshold at
which pulser transmission commences will usually be above the pump rate used for a well
kill. The recorded data may, however, be useful in helping to understand the well kill
operation, after the fact.
•
If well kill procedures are considered in advance of spudding an ERD well, then it may be
possible to put plans into place for offsite KWM to be mixed and shipped to the rig in an
emergency.
•
Barite sag is a problem that has been suspected for some time, but difficult to quantify.
Regular use of PWD subs has revealed hydrostatic pressure measurements that demonstrate
barite sag is a common occurrence in ERD wells.
•
Gas trapped in high angle washouts in the hole may require higher annular velocities than
those used in well kills to dislodge it. After a well kill, the well should be circulated at high
rates through the choke manifold to remove these gas pockets.
15.3 KILLING ERD WELLS
Well kill operations in highly deviated ERD wells utilize the same methods as those used in
vertical wells; however, the actual kill process is often very different. The advantages and
disadvantages of the various well kill methods are discussed below in relation to ERD wells.
15.3.1 Wait and Weight Method
This method requires mixing Kill Weight Mud (KWM) in the pits and using the mud to pump out
the kick. This method, therefore, requires “waiting” while the pits are being “weighted” up.
Advantages:
• This method has the advantage of requiring one circulation of KWM before resuming
drilling. In practical terms, this advantage is rarely realized in ERD wells. Usually, the hole
will be killed with multiple circulations and circulated to an additional trip margin before
pulling out of hole.
• Use of KWM to pump out the kick minimizes the annulus pressure required to maintain
constant bottom hole pressure.
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Disadvantages:
• In many ERD wells, the lower annulus pressure benefit cannot be realized. A typical ‘S’ well
has casing set above the pay and a short production hole is drilled. A kick in the pay will be
circulated into casing before the benefit of “weight and wait” pressure management is seen.
• While mud is mixed or transported, the hole is inactive, barite is settling, mud is building gel
strength and the kick is migrating.
• A large volume of barite will probably be required to weight up the system to KWM. This
volume may not be available and further delays may be required before circulating out the
influx.
15.3.2 The Drillers Method
If a well is shut in on a kick, the kick can be pumped from the well using the constant bottom hole
pressure method and the mud in the pits. This is the “drillers method”.
Advantages
• The drillers’ method is a simple way of pumping the kick from the well. Once a drillpipe
pump pressure has been selected, the same pressure is maintained until the kick is pumped
from the hole.
• This method uses the mud that is in the pits, and therefore the kick can be pumped from the
hole with minimal delays.
• This method also avoids the difficult task of trying to displace the entire hole to KWM. It is
most applicable when a kick has been swabbed into the well.
Disadvantages
• If the well was not swabbed in, then the drillers’ method becomes a ‘two circulation’ method.
Drilling cannot recommence until the hole is displaced to a KWM. This requires using a
pumping schedule.
• The “Drillers method” imposes additional well bore pressure while circulating out the kick
compared to the “Wait and Weight method”. This is a particular disadvantage with wells that
have a low fracture gradient at the shoe, as often seen on ERD wells.
15.3.3 Engineers Method
The “Engineer’s method” is a compromise between the “Drillers method” and the “Wait and
Weight” method. The engineer’s method involves increasing mud weight to some quickly
attainable value and using that weight to pump out the kick. Mud weight is increased in
increments to KWM, depending on the mud mixing capability of the rig and the ability to rotate
the pipe.
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A variation of this method is adopted with some ERD wells. Kill weight mud is pumped and fails
to kill the well, due to the high side flow path. The remaining drill pipe pressure can then be used
to calculate both the equivalent mud weight in the hole and the mud weight increase required to
kill the well.
15.4 VERTICAL AND DEVIATED KILL SHEETS
For a vertical well, a pumping schedule is set up to circulate KWM into the well. As the KWM
fills the drillpipe, the choke is adjusted using the schedule to keep the Bottom Hole Pressure
constant. The same procedure is used for a deviated well, but the pump schedule to fill the
drillpipe with KWM is not a straight line. A deviated kill sheet should be used to account for the
TVD verses MD changes.
Using a vertical kill sheet on an ERD well will expose the wellbore to higher pressures than
necessary with the risk of breaking down the shoe. This is shown in Figure 57 below and a
worked example of a deviated well kill is shown in Appendix B.
Excess Pressure
Pressure schedule calculated using a
vertical kill sheet
Pressure
Pressure schedule calculated using a
deviated kill sheet
KWM enters drillpipe
KWM reaches the bit
Strokes
Figure: 57
Comparison of Pumping Schedule calculated with a Vertical and
Deviated Well Kill Sheet
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16 DEEPWATER ERD WELLS
In the last few years, ERD wells have become more common in deepwater applications with
subsea wellheads. These wells have proven to be some of the most complex and difficult wells
drilled in the industry. This is due to the combination of ERD challenges, in addition to the
already challenging deepwater drilling environment.
This section aims to highlight some of the main differences between conventional ERD wells and
deepwater ERD wells. The additional deepwater challenges arise in three main areas:
• Issues related to the long section of large diameter riser
• ECD issues
• Directional issues in the build section
These issues are discussed in detail in the following sections and are shown below in Figure 58.
Note that the issues are both directly and indirectly related to each another in various ways.
Riser Issues:
• Hole cleaning
• Mud temperature and rheology
• Torque, Drag and Buckling
Build Section Issues:
• Fast build rates required
• Unconsolidated formations
Figure: 58
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ECD Issues:
• Reduced overburden strength
• Cuttings loading in the riser
• Mud temperature and rheology
Critical Issues in Deepwater ERD wells
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16.1 RISER ISSUES
The degree to which the riser adds to the drilling challenges will depend on many design factors
(e.g. water depth, i.e. length of riser), diameter of the riser, well trajectory, fracture gradients,
mud type, etc.). The following riser related issues are noted:
• Hole Cleaning – As can be seen from previous sections, hole cleaning is one of the most
challenging aspects of an ERD well. On a deepwater ERD well, if you are successful in
getting the cuttings out of the high angle section of the well, there is now the added challenge
of getting the cuttings to the surface up a long, large diameter riser. Several factors are
working against efficient hole cleaning in the riser:
The large annular area between the drillstring and the riser ID results in very low annular
velocities (AV).
Generally, the flowrate cannot be increased to improve AV’s in the riser, due to ECD or
downhole tool limitations lower in the wellbore.
To overcome ECD limitations (due to lower fracture gradient and increased mud
rheology in the cold riser), the mud is often run thinner than is required. This will be
particularly detrimental to the cuttings carrying capacity in the vertical riser.
In order to improve hole cleaning in the riser, many Operators have used a mud pump or
cement pump to boost the flow in the riser. Consideration should also be given to pumping
sweeps in the riser. Again, the impact on ECD must be considered.
• Mud Temperature and Rheology – Depending on the well location and water depth, the
temperature at the base of the riser can be very low. Drilling fluid flowing slowly up a long
section of cold riser will cool considerably, and this can have a significant thickening effect on
the mud. This thicker mud will in turn negatively impact the ECD. Detailed hydraulics and
ECD planning is required for deepwater wells. It is important that the hydraulic models that
are used will account for the change in mud rheology with pressure and temperature variations
throughout the wellbore.
• Torque, Drag and Buckling – Depending on the well design, deepwater ERD wells are often
better off for torque and drag. This is due to the fact that the long vertical section in the riser
will contribute extra surface weight and make negative weight conditions less likely.
However, buckling of the drillstring in the large diameter riser is a concern both when drilling
and when running casing and liner. The buckling is complicated by the fact that deepwater
ERD wells usually have a high tangent angle, and therefore high drag forces increase the
chances of buckling. With little constraint for the drillpipe in the riser, buckling tolerance is
usually low.
This sensitivity to buckling will have a direct impact on the BHA strategy. In particular, the
depth to which sliding is possible will be reduced as compared to a conventional ERD well.
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Again depending on the well design, HWDP or drill collars may be used in the riser to
improve the buckling tolerance while drilling. For running casing and liners, consideration
should be given to using casing for the landing string, and then backing it off when landed.
Alternatively, flotation can be used to lower the casing drag and therefore reduce the buckling
loads.
16.2 ECD ISSUES
ECD’s are generally the most critical issue in deepwater ERD wells for the reasons listed below.
In normal ERD wells, ECD issues are generally restricted to 8½” hole or smaller. In deepwater
ERD wells, ECD’s can be a limitation in 12¼” and even 17½” hole. It is important to ensure that
the well design accounts for ECD’s from the early planning stages, to the operational practices
used. PWD tools are very valuable in these wells to help understand ECD’s, particularly in the
long vertical riser (i.e. cuttings loading and thicker mud).
•
Reduced Overburden Strength – Simply a function of geology, formation fracture gradients
tend to be lower on deepwater wells (i.e. basically the rock overburden has been replaced by a
water overburden). This results in less tolerance to mud weight and ECD’s for deepwater
wells.
•
Cuttings Loading in the Riser – On conventional ERD wells, cuttings contribute little to
ECD’s as they are supported by the bottom of the hole for the majority of their trip out.
However, when the cuttings enter the long vertical riser, their weight directly impacts the
ECD all the way up the riser as they are supported in the mud. In particular, this has a
significant impact on the larger hole sizes where the drilling is usually fast, and a high
volume of cuttings are being generated. As a result, the ROP will often need to be controlled,
which is not always complimentary to the directional requirements in the build section.
•
Mud Temperature and Rheology – As discussed in the previous section, the mud rheology
will often be thicker on deepwater ERD wells as the mud cools in the riser. This will have a
negative impact on ECD’s and must be designed for in the planning stages of the well.
The various methods of ECD minimization listed in Section 10.5 and 10.6 are all applicable here.
16.3 BUILD SECTION ISSUES
Again, simply a function of geology, targets for deepwater ERD wells tend to be relatively
shallow (TVD). This creates the follow challenges:
•
Fast Build Rates Required – In order to achieve these shallow targets with the stepout
required, there is often little choice but to build at high rates immediately below the seabed.
High build rates are often difficult to achieve with the stiffness of large OD BHA’s. There is
also little tolerance for falling behind the planned wellpath.
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•
Unconsolidated Formations – In addition to the above, formations immediately below the
seabed tends to be relatively soft and unconsolidated, and wash out easily. This results in
high ROP’s, but may also make it very difficult to build inclination.
A possible solution to the above problems would be the use of a pilot hole to improve
directional control and generate a reduced volume of cuttings (i.e. less ECD loading in the
riser).
Motors with ABI should also be used to optimize directional control.
One other major issue that is often specific to deepwater ERD wells, is the priority placed on rigtime due to the high cost for fit-for-purpose deepwater drilling rigs. Operators may be reluctant
to commit to the extra time for valid ERD practices, such as pilot holes (as mentioned above),
circulation time for hole cleaning, T&D measurements, etc.
It is important to understand that with ERD wells (deepwater or conventional) a little time
spent getting things right will make a significant difference in the overall time performance
and success of the well.
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17 COMPLETIONS AND WORKOVERS IN ERD
It is vital that issues related to the whole life of the well are taken into account from the very first
planning steps and then on through to implementation. These issues will encompass much of the
completion design, which should also take into account pertinent issues relating to later
workovers. The operational practices and engineering designs relating to drilling the well will
certainly affect various aspects of the completion and workover programs. Some relevant issues
to consider are:
•
Intervention into the well with production logging, stimulation or abandonment equipment
should be planned – how is it going to be done?
•
Mono-bore completions, having a single tubular size from surface to TD, often provide the
best means of long-term intervention into the well. Buckling of workover strings in large OD
casing or tubing is a serious concern for many of the completions that have been run in ERD
wells to date.
•
Capabilities of available workover rigs in the area, or rigs that are likely to be around when
workovers are likely to start. Workovers can become quite costly if they are undertaken with
a rig that is ill equipped to handle the ERD challenges.
•
Modular completions that run the expendable parts of the string as a separate unit can often
simplify later intervention. For example, if gas lift valves/mandrels, sub-surface safety valves
or production monitoring equipment are the most likely elements in the string to fail, then run
them above a second production packer or tubing anchor so that the entire completion doesn’t
have to be pulled to replace these elements. This may also allow a smaller workover unit to
be used as ERD completion strings can become quite long.
•
Ensure that the production models that are being used can take into account the large tangent
section that the fluid will have to travel through. If production velocities are low enough, this
section can act as a long separator and seriously affect the quality of the well’s production.
For example, if ESP’s are being run shallow in the well, it may be necessary to run a
“velocity string” from the top of liner to the bottom of the tubing.
•
Keep the completion as simple as possible at all costs. These wells are difficult to workover
with cement plugs, wireline operations, fishing, well clean-up, pipe buckling and a poor
displacement environment all acting to hinder the success of remedial operations.
•
Consider the viability of working the well over at all costs. There have been a number of
ERD wells that were constructed with abandonment as the only viable workover plan.
It would be possible to write an entire manual on ERD completion and workover practices;
however, the drilling principles and practices that are discussed in this text are all largely relevant
to these later operations. Hole cleaning, cementing and other issues all carry over into the
completion, recompletion and workover programs.
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There are a number of new technologies on the market that have been developed to overcome
some of the challenges associated with ERD completions and workovers:
•
Wireline and coiled tubing tractors have progressed significantly in the past 2-3 years.
These have allowed many completion and intervention options to be available to ERD
wells, which in the past were limited to less demanding wells.
•
Roller centralizers and clamps have been developed to help overcome drag and buckling
problems when running ERD completions. These tools are commercially available and
have proven very effective at lowering running friction factors and overcoming buckling
problems.
•
Rotational setting tools have been developed to allow weight to be rotated down the hole
in order to obtain the required setting weight at the tool. Rotation redirects the friction
vector in the hole and creates a nearly friction free environment along the axis of the
wellbore. That said, however, ERD wells rarely have enough string weight to transfer to
a downhole tool due to the angle of the well.
•
Tubing blow-out subs have been developed which allow circulation to be established
after a disk is blown from the sub. These disks are located in the side of a specially
designed tubing coupling and are generally run deep in an ERD completion as a
contingency for getting fishing tools into the well. Once circulation is possible, wireline
tools can be pumped down the hole.
•
Coiled tubing advancements in recent years have been substantial and its use for
intervention into ERD wells is viable. Unfortunately, the length of the coil often becomes
an issue, as ERD wells get deeper and deeper.
•
Expandable tubulars are becoming more common in various applications and will have a
major impact on future well designs. However, there are limitation on their use in very
long ERD wells as they cannot be floated, and generally cannot be rotated either.
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18 SPECIALTY TOOLS AND NEW TECHNOLOGIES
18.1 DIRECTIONAL DRILLING
18.1.1 Rotary Steerable Tools
Rotary Steerable Tools (RST) are making a major impact on ERD wells, in both performance
improvement and the ability to drill more complex and longer wells. In many applications they
have made steerable motors obsolete and will continue to capture more of the market as reliability
improves and costs reduce. These tools are intended to provide full inclination and azimuth
control without the need for slide drilling and provide major benefits in ERD wells. Refer to
Section 11.5.9 for a detailed discussion of RST tools.
Future developments include RST in small hole sizes (4¾” to 6¾”), and large hole sizes (16” to
18½”). “Point-the-bit” tools are relatively new, but are currently proving to be successful, and
these tools may become more widely used in the future.
18.1.2 Adjustable Stabilizers
There are several adjustable stabilizers on the market. The most advanced has a large diameter
variation (about 1¾”), and has multiple diameter settings. It is also unique in that it has its own
stand-alone pulser unit for real-time communication to surface. The tool is adjusted from surface
by a binary pump sequence. K&M’s client experience has been that the tool is quite effective and
relatively reliable (in more recent experience). It is available in 12¼”, 9⅞” and 8½” hole sizes.
For simpler wells and/or specific applications, the simple, more reliable tools may be more
appropriate. These are generally 2-position tools with about ¾” diameter variation. Some are
hydraulically activated, while one is mechanically set. These simpler adjustable stabilizers are
available in a wide range of hole sizes (6” to 17½”).
In an effort to maximize rotary drilling while still having a motor in the hole for azimuth control,
many Operators will run an adjustable stabilizer above a motor. In general, the adjustable
stabilizer will have minimal effect due to its distance behind the bit. One company has built an
adjustable stabilizer into a steerable motor in an effort to overcome this problem.
As with steerable motors, many of the traditional application for adjustable stabilizers are now
being done with RST’s.
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18.1.3 Steerable Motors
Longer power section motors are quite common now, so this will not be discussed this in detail.
It should be pointed out that there are some subtle differences between the different vendor’s
tools. No attempt is made to comment on tool reliability, as this is a moving target and very
much a function of local conditions and support.
The selection of motors will depend on what environment is to be used. Is high torque, high
RPM or high power required? This will depend on whether the motor is in the hole for increased
ROP or for slide drilling. This will also be a function of the formation type and variability, and
also the bit types used. Very aggressive bits and sticky and/or laminated formations may require
higher torque to prevent stalling. Formations that respond to higher RPM (rather than WOB) will
probably be better with higher speed/higher power configurations.
Regardless of motor choice, the motor should be capable of operating at high pipe RPM for
prolonged periods. This is especially so for the larger hole sizes.
Also, remember that high torque and high power motors are of little benefit if tri-cone bits are to
be used, regardless of hole size. In this case the motor should be as short as possible for the most
predictable rotary performance (in terms of directional control). This is especially important if an
adjustable stabilizer is being used behind the motor, as it will have the most effect if kept as close
to the bit as possible.
ERD wells generally use OBM or SBM in their lower sections. It is important that some preplanning is put into motor selection for these applications, to ensure the maximum motor life. In
particular, the stator rubber compound and interference fit between the rotor and stator are critical
design parameters.
Many of the vendors’ motors now have the option of being fitted with At-bit inclination (ABI).
This is a very beneficial feature for ERD wells, where torque and drag and therefore the
management of doglegs are critical.
18.1.4 Rotating Near Bit Stabilizers
Originally used in the North Sea, these tools have now been used extensively in many
applications around the world. Although a simple idea, they can have some quite dramatic results.
This is no more than a very short stabilizer that is placed between the bit and base of the motor.
The stabilizer is only slightly undergauge (1/32” to 1/16”).
Several Operators have reported significantly improved ROPs (both slide drilling and rotary
drilling). Less hole spiraling has also been reported on a regular basis. It is likely that a longgauge bit can achieve the same effect, except that this allows off-the-shelf bits to be used.
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However, other Operators have seen excessively high torque when running these tools, and it
appears that their benefits may vary dependent on the formations being drilled in a particular
location.
18.1.5 Pin Down Motors
A relatively new steerable motor assembly has been designed that is comprised of a pin-down
motor with a specially designed long-gauge PDC bit in a matched drilling system. By treating the
bit and motor as a system, it has been possible to overcome some of the directional limitations
previously experienced when long-gauge bits, or short-gauge bits with piggyback stabilization,
were used in combination with conventional motors.
Field results have shown benefits including increased ROP, improved hole quality with less hole
spiraling and thus less tortuosity, reduced vibration, better steerability, increased bit life, and
improved motor and MWD reliability.
18.1.6 At-Bit Inclination Tools
The advent of geosteering technology several years ago has resulted in the expanded development
of At-Bit Inclination (ABI) technology. These tools have several applications other than for
‘geosteering’ while drilling the horizontal section:
• ABI is ideal for landing the horizontal well section. Not only is this often the most critical
part of a horizontal well, but also it usually coincides with a formation change. Hence, the
directional drillers' “guessing” of build rates (based on previous slides) is somewhat risky.
The ABI technology takes away the guesswork of what is happening at the bit.
•
The use of ABI in the build section of critical ERD wells has now become more common.
The build section of the well is always critical for ERD wells, and the use of ABI reduces the
risk of falling behind or building ahead of the target curve (refer to Section 11.4.1).
• Slide drilling for inclination when formation changes are occurring. In this case, the
directional driller will be basing slide intervals based on previous slides, but these will be of
little guide because the formation was different. This is applicable at major formation
boundaries as well as in the presence of stringers.
• Slide drilling for inclination when slide drilling is particularly slow (as is often the case on
ERD wells). In this scenario, the Operator and directional driller are faced with the question
of “how long do we continue slide drilling?” If the slide is more effective than expected then
unnecessary time is wasted on the slide. If the slide is less effective, then returning to rotary
drilling (or worse tripping for a new BHA) will result in even more wasted time. Worse still,
valuable footage may have been consumed, requiring more severe build/drop on the next
correction.
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There are several types of ABI tools already available from several vendors, and the list of
options and hole sizes is growing. There are currently several options:
• Motor with integral ABI sensor
• Rotary ABI subs (can be used in front of motor with some additional planning)
• Adjustable NB Stabilizers (recently developed tool)
The design of these tools can be broken into at least two categories. Firstly, there are those that
rely on a ‘hard-wire” link to the MWD/pulser unit. Alternately, there are systems that use
electro-magnetic and acoustic methods to communicate back to the MWD/pulser unit. The latter
allows combining the ABI motor or rotary sub with an adjustable stabilizer or other equipment
between the ABI sensor and the MWD.
18.1.7 Steerable Turbines
A system often overlooked is the use of steerable turbines. These have advanced in recent years
and have application in horizontal wells. As with motors, these can be combined with adjustable
stabilizers for optimum directional control and ROP.
A downside of steerable turbines for ERD applications is (a) the high pressure differential
required for operation and (b) the heavy set bits that are likely to be used may be difficult for
tripping through cuttings beds.
18.1.8 Walking Bits
PDC bits that have been purpose designed to walk in a given direction (left or right) have been
further developed in recent years. The success of these designs has improved as bit design and
BHA dynamics becomes better understood. The magnitude of the walk rate will be highly
dependent upon many other factors, but the bit designs can be modified to amplify or reduce the
walk tendency of the bit. The application for this technology is to provide some rudimentary
‘steering’ capability with rotary BHA’s for wells where slide drilling is not possible or
economical (such as negative weight wells or for rigs with very limited hydraulics capability).
The scope for this technology may appear limited (in the long term) given the emergence of RST
technology. However, there is merit in a cheap method of obtaining rudimentary azimuth control
without the risk of tool failure.
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18.1.9 Downhole Thrusters
Downhole thrusters can be a valuable tool for improving slide-drilling performance. These act to
control WOB to the BHA placed below the thruster by absorbing any drillstring movement from
above. If working correctly, tool face control should be improved.
These tools require a good understanding of bit and BHA hydraulics, as the thruster will not
operate correctly if the pressure drops are not as expected.
The use of these tools is generally associated with smaller hole sizes (8½” or less).
18.1.10 AG-itator
Andergauge originally developed this tool as a percussion hammer tool to improve ROP in hard
rock applications. However, it was found to improve weight transfer to the bit and slide drilling
efficiency, by inducing vibration in the BHA to overcome static friction. The tool has mainly
been used in the North Sea and has had good success in improving sliding ROP and efficiency.
The tool generates an additional ±500psi pressure drop at surface, which must be taken into
account if hydraulics are limited. Tool sizes include range from 3⅜”, 4¾”, 6¾” and 9⅝”.
18.1.11 Anaconda
Still in the early stages of development, this is a composite coil-tubing project initially developed
as a joint venture between Halliburton and Statoil. The aim is to eventually be able to drill
significant stepout wells using composite coil tubing and tractors. For further details refer to
Harts E & P June 2000 “A Bold Vision”, or SPE 60750.
18.1.12 Drop Gyro’s
High accuracy continuous navigation gyros are now available. These tools allow an accurate
gyro survey to be obtained in high-inclination wellbore for minimal time and cost impact. Prior
to POH, the gyro tool is dropped into the string and pumped to bottom. It surveys the wellbore
automatically as the BHA is POH.
18.2 MWD TECHNOLOGY
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18.2.1 Directional MWD
There are some distinct differences in the capabilities of the MWD systems on the market. MWD
technology is advancing quickly and capability and reliability is always improving. No attempt is
made to differentiate MWD reliability, as K&M believes that this is very much a function of local
support and conditions. Rather than discuss each vendor’s tools, the subject will be broken into
distinct functions that are either new or have significant benefit.
18.2.2 MWD Directional Survey Accuracy
Actual sensor technology is pretty much common to each vendor. However, some vendors offer
continuous inclination output. This improves accuracy by increasing the number of data points.
It also allows the directional driller to see if rotary drilling is ‘knocking out’ some of the slide
drilling that has just been completed. As discussed in Section 13.1.5, continuous surveys can also
be very beneficial in giving a true picture of the doglegs in the hole.
A lot of emphasis has been placed on improving software analysis of the raw survey data. In
particular the ability to better correct for magnetic interference from the formation, BHA and
drillpipe.
When comparing MWD companies from this standpoint, ensure that each company is quoting
survey accuracy using the same basis (e.g. 95% confidence or 99% confidence).
18.2.3 Real Time Multi-Axis Vibrations
These tools have proved to be a significant benefit to ERD wells (and conventional wells).
Unlike previous MWD vibration shock-sensors, the emphasis is on multi-axis sensors (i.e. axial,
lateral and torsional vibration). Previous tools simply recorded or pulsed total shock, without
differentiating the nature of vibrations. Multi-axis vibration information is important in order to
differentiate between different modes of vibration, such as whirl (forwards or backwards), slipstick and bit-bounce.
The tools should not only indicate the type of vibration environment, but should also give some
indication of the severity of each axis.
Several commercial systems are now available. K&M client wells have used each and all can
provide useful information. It is, however, important to understand that this technology is only as
good as the ability of the driller and/or MWD Operator’s ability to interpret the real time output.
In this respect, it is important that the system is user friendly at surface. It is preferred that the
driller is the primary user with support from the MWD Operator, rather than relying on the MWD
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Operator for primary interpretation. This is because the driller is (a) actually controlling the
equipment and (b) the MWD Operator is not always present on the rig floor.
The use of real-time multi-axis vibrations sensors can allow drilling parameters to be varied to
optimize ROP and/or prevent bit and BHA failure. The latter is more relevant to ERD operations.
For example, if a sudden increase in vibration is observed, then the WOB and/or RPM can be
decreased or increased (depending on the vibration type) to prevent damage to the PDC bit and/or
the MWD. It may also be able to give an early indication of tri-cone bearing failure prior to
losing a cone.
This technology also provides valuable information when trying to assess why problems are
occurring (such as short PDC bit life, MWD failures, drillstring failures, etc.). This can then be
used to assess the correct bit and BHA to use for the next bit run or next well.
Surface based systems (that monitor drillstring vibration at surface) are a good supplement to an
MWD based system. However, there will be many destructive vibrations that do not transmit to
surface (such as whirl and bit bounce), and others that have become so dampened that they are
not visible at surface.
18.2.4 Real Time Downhole Annular Pressure (“Pressure While Drilling”)
PWD tools provide real-time information on the internal and annular downhole pressures. The
data can be used for the following applications:
•
Provide early-warning signs of packing off
•
Evaluate and manage ECD’s
•
Provide an indication of how clean the hole is
•
Provide valuable understanding of downhole hydraulics (which we believe to be very poorly
understood)
•
If downhole thrusters or drillstring by-pass subs are being considered to improve slidedrilling performance, the use of PWD is recommended (both during and prior to running the
thruster or by-pass sub). This is because these thrusters require some knowledge of the actual
bit and BHA pressure drop for correct operation. The pressure drop across a PDC and motor
combination can vary widely (as evidenced by the ability to stall motors), and a PWD tool
will probably help fast track the optimization of the thruster set up.
•
May be valuable in the case of well control.
Generally these tools will find more application in smaller hole sizes where annular clearances
are less (i.e. 8½” and smaller).
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18.2.5 Downhole WOB / Downhole Torque
Downhole WOB (DWOB) and Downhole torque (DTORQ) can provide valuable information
about what is really happening at the bit. This may be especially so if ROP is low (either rotary
drilling or slide drilling), as there are many variables that may be the cause of low ROP.
Several Operators have also found that the DWOB/DTORQ is a good tool for monitoring hole
cleaning. When hole cleaning is deteriorating, the DWOB and DTORQ diverge from the surface
values, indicating that a change of parameters or remedial operations is required. This method
relies on data to be gathered while on-bottom, rather than K&M’s preferred off-bottom method to
monitor hole cleaning. Hence there will be some bit and BHA interaction that will contribute to
the drag data. This method does, however, have advantages for negative-weight wells, where
slack-off without rotation may not be possible.
There are some limitations for the use of DWOB sensors. It is not uncommon for there to be two
or more stabilizers below the DWOB sensor, and so the DWOB may not actually measuring the
WOB, but rather the WOB at the MWD, since the stabilizers may be absorbing weight.
Also the tools require careful and regular calibration to ensure that they are providing accurate
and relevant data.
18.2.6 MWD Caliper
An MWD caliper may be a very valuable tool if wellbore instability is poorly understood, which
is probably the case for the first high angle wells in a given area. The value of this should not be
underestimated, especially given that almost all of the hole cleaning performance assumptions are
based on good hole condition. It only takes one significant washout to cause troublesome results
on an ERD well.
A recent K&M client ERD well has been plagued by a perceived hole cleaning problem.
Believing that wellbore instability was not a problem, all of the Operator’s attention had been
focused on solving the hole cleaning problem. Combined with directional drilling practices that
masked the real problem, the wellbore instability problem was not confirmed until ten wells had
been drilled, and several stuck pipe incidents had occurred. Caliper logs had not been performed
in the 12¼” section until the 10th well and it was only the eventual use of an extensive caliper log
combined with the directional drilling strategy described in this report that the real problem was
confirmed.
Real-time caliper information is not currently available, but this is probably of limited value
anyway. Memory recorded caliper information can be assessed after each bit run or at the end of
the well.
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At least two companies offer inferred caliper log information on their MWD/FEWD suites.
Although not of the same value as a wireline type caliper, this will probably still be effective
while being less difficult and costly to perform.
One downside to this technology from the above perspective is that the inferred caliper is looking
at the wellbore right after it is drilled. To obtain hole size information over time, reaming runs
must be made.
18.2.7 MWD Gyro’s
When kicking off a well from platform with many existing wells, often multiple gyro surveys are
required to obtain the azimuth that the MWD may not provide because of magnetic interference.
This can be a time consuming process. Gyro MWD are now available which overcome the
problem of magnetic interference and avoid having to run multiple gyro runs on wireline. There
is limited scope beyond this surface hole application for MWD gyros tools (i.e. do not actually
provide increased accuracy).
18.3 CASING AND CEMENTING
18.3.1 Expandable Slotted Casing
This technology is becoming more common and has developed into many different applications.
If pre-planned into the well design it allows short intervals of hole to be cased off and isolated
(mechanically and hydraulically if necessary) without losing a hole size. If run as a last-minute
contingency, then some hole size reduction will be required, but this will be minimized compared
to conventional options.
If run to prevent any hole size reduction, an oversized shoe track is required to allow the casing to
expand into the previous casing string.
This may offer numerous benefits, such as improved contingency options for the deepened
sections, improved production capability, or improved remedial workover options.
The length of the expanded interval is currently limited to relatively short lengths, but this may be
sufficient to isolate, mechanically or hydraulically, a troublesome interval.
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18.3.2 High Torque Casing Connections
As wells have become longer and the forces on the casing have increased, the industry has
developed casing connections that provide very high torque ratings. These are used extensively
on difficult wells (that often utilize flotation) to provide the contingency option of rotation.
Liners, which require rotation to get to bottom and throughout the cement job, also benefit from
the use of these high torque connections. The final selection of a casing connection will depend
on many different factors.
18.3.3 Casing Shoes
Reamer shoes, such as the one shown in Figure 59, have proven
beneficial in applications where rotation is required to get casing in
the hole. Particularly on liners, the reamer shoe will aid in working
through tight spots and running up over ledges.
Several suppliers provide different variations of these tools. It is
important to ensure that the shoes are PDC drillable to avoid extra
time to drillout with a dedicated run.
If it is likely that the casing or liner will have to be worked to
bottom, consideration should also be given to adding hydraulic
rupture disks on the side of the tool, in case the nozzles on the
bottom become packed off with cuttings.
Figure: 59
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18.4 DRILLPIPE
18.4.1 5⅞” Drillpipe Premium High Torque drillpipe
The industry has come a long way in the past few years toward developing a drillstring and
connections that are purpose built for ERD applications.
5⅞” has proven to be an optimum size of drillpipe for many ERD projects and is now being used
extensively around the world. Obviously, the final drillpipe selection will be based on many
factors such as torque and drag, buckling, hydraulics, ECD, cost and availability.
Double shouldered connections have been around for a while, although these have been known to
have reliability problems. Non-shouldering connections are now available that have proven to be
more reliable on K&M client wells. In these connections, the threads act both as the sealing and
torque bearing surfaces.
There are some disadvantages to using high torque drillpipe if it is not necessary. The overall
tripping time will generally be increased for various reasons. Rig crews complain that it is
difficult to make and break from the top drive with multiple bites required by the pipe handler.
Two bites with the rig tongs are also required to reach make-up torque. De-stabbing has also
been a problem with the threads hanging-up, but a simple Teflon de-stabbing guide can assist
with this problem. New drillpipe tongs are now becoming available which make the use of these
high torque connections much quicker.
18.4.2 Integral Bladed Drillpipe
The use of integral bladed drillpipe has become popular in the North Sea. This has proven
effective for improving hole cleaning. It can also improve slide-drilling performance due to its
increased stiffness.
18.4.3 165 ksi High Strength Material Drillpipe
A relatively new technology has been the development of 165 ksi strength drillpipe. If used
instead of S135 drillpipe tubulars, this higher strength material could theoretically allow thinner
walled tubulars to be used for ERD applications. This would allow reduced pump pressures due
to reduced drillpipe ID. It could also reduce drilling torque and drag because the drillstring will
be lighter.
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K&M has not used or investigated this technology to date. We are aware of some teething
problems, but it is a possible development in the future that may help extend current reach
limitations.
18.4.4 Composite and Titanium Drillpipe
A string of drillpipe made from either of these materials would be ideal for ERD and most likely
lead to an immense break-through that will help extend current reach limitations. The drillpipe
would be much lighter than conventional steel drillpipe, thereby reducing drilling torque and drag
and buckling problems dramatically. This in turn may also allow larger tubulars to be used for
reduced pump rates.
The main limitation is cost and it may be sometime before this major limitation is overcome
(particularly with Titanium).
18.4.5 Pin-Up Drillpipe
This technology has been around for some time. K&M engineers have investigated its use for
upgrading from 3½” to 4” drillpipe, without losing fishing capability options.
18.5 HOLE CLEANING
Given the importance and difficulties associated with hole cleaning in ERD wells, the industry
has focused much of its efforts on developing systems for improving and monitoring hole
cleaning.
18.5.1 Integral Bladed Drillpipe
This drillpipe has reportedly improved hole cleaning performance for numerous North Sea
Operators. The drillpipe has integral blades on the tubular section, which act to stir the cuttings
up when the pipe is in rotation. Some Operators have even reported that the pipe is so effective in
agitating the cuttings bed that the hole clean-up process must be staged (with gradually increasing
flowrate and pipe RPM), otherwise the hole will pack-off.
This drillpipe is also significantly stiffer, and therefore offers benefits for buckling prevention.
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18.5.2 Hydraulic By-Pass Sub
There may be difficulties cleaning the upper section of hole above the liner hanger when drilling
smaller hole (either 8½” or 6”) because of the reduced flowrates and larger hole size above the
liner hanger. For example, if 9⅝” casing has been set as a liner, then the drilling of the next
section will be in 8½” hole size. Drilling 8½” hole will be limited to 600 gpm by downhole
motor and MWD constraints, but the upper hole section of ± 12¼” probably cannot be cleaned
with this flowrate.
A by-pass sub in the drillstring, probably above the liner hanger for ECD reasons, will allow
increased flowrates in the larger hole size while limiting the flowrate through the BHA.
These are usually activated by dropping a ball. This sequence can be repeated several times for
some tools, while others are one-shot systems. It is recommended that a multiple setting tool be
used (i.e. a tool that can be opened and closed more than once). The by-pass can then be reopened by dropping another ball, with the balls being caught in a catcher.
Obviously if this were to be considered, it is important to have a good understanding of the
downhole hydraulics so that the correct amount fluid is directed to the bit and BHA.
18.6 TORQUE REDUCTION
18.6.1 Non Rotating Drillpipe Protectors
Non Rotating Drillpipe Protectors (NRDPP’s) have been around for some time now. These have
proven to be an effective method for reducing torque as well as reducing casing wear. They can
also be an effective way to stiffen the drillpipe for buckling prevention.
The development of these Protectors has continued and high temperature and open hole rubber
compounds are now available. They are more rugged than the original Protectors, but there is
still some risk of losing protectors and/or the aluminum stop rings down the hole, if improperly
used. It is very important that the placement and frequency of the Protectors is sufficient to
prevent over loading them. If you are unwilling to run a sufficient number of these, then do not
run any at all.
There are currently several different types of protectors available that have some advantages
compared to the original designs (i.e. higher side loading capability, added drag reduction
component, etc.).
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18.6.2 Roller Bearing Subs
Torque reducing “Roller Bearing Sub’s” are a more rugged and more effective alternative to
NRDPP’s. The torque reduction is greater than for the NRDPP’s, while substantially greater
side-loads can be absorbed by these tools, so less is required.
Because these ± 4’ tools are inserted between connections, they will modify the length of each
stand when racked back, and so derrick management may be more difficult. Alternatively, roller
centralizers’ tools are now available which can be run on the drillpipe itself.
As with the NRDPP’s, a minimum number of these is required to gain any worthwhile benefit.
A concern with these tools is that the cross-sectional area is somewhat greater, and so the
resultant ECD increase may be a problem.
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19 EXAMPLES OF OPTIMIZED ERD WELL DESIGNS
The following are real life examples of different ERD wells that K&M’s engineers have planned.
In each case the driving forces are described for the particular well or project. The original or
‘conventional’ solution is given for each, as well as an ‘optimized’ solution that was proposed.
19.1 EXAMPLE #1:
ERD PROJECT, UKRAINE
Scenario Description
• A large land-based oil and gas development in Ukraine required ERD drilling because the oil
fields underlie an environmental exclusion zone. The development relies on horizontal wells
in two separate oil reservoirs of relatively poor permeability.
• The original well design proposals used conventional hole sizes with 8½” horizontal hole.
The completion size is 2⅞” tubing. See Figure 60 below.
• Rig capability is limited, especially hydraulics capability. The rig has 5” drillpipe and
probably cannot be upgraded in the immediate future. Surface pumping capability is limited
by 2 x 1600 HP pumps with an effective surface pressure limit of 3400 – 3600 psi.
• Only WBM may be used for environmental reasons.
• There is minimal experience in the area with modern western drilling technology. The offset
well information is poor.
• The sandstone reservoir is relatively deep at 3200 – 3500m TVD (10500 – 11500’TVD) and is
hard and abrasive. Above this is mainly shale and claystone, although there is a salt interval at
2700 – 2900m TVD (8900 – 9500’ TVD) that has caused problems in the past. The oil
reservoirs are overlaid by a gas zone, which must be isolated for production reasons.
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UKRAINE EXAMPLE #1 : ORIGINAL PROPOSAL,
WITH CONVENTIONAL CASING PLAN
0
NOT TO SCALE
1000m
(3300 ft)
17-1/2" hole
13-3/8" surface casing to below EOB
12-1/4" hole to heel point. Build & turn from
30-60 degrees to horizontal.
2000m
(6600 ft)
Run 9-5/8" casing to heel point.
Salt / Clay trouble zone
3000m
(9900 ft)
4000m
(13200 ft)
8-1/2" horizontal hole,
1000-1500m
(3300 - 5000 ft)
Run 7" liner.
Hard, abrasive Sandstone reservoir section
Figure: 60
Ukraine Example – Original Well Design Proposal.
Solution – Change casing plan
The 12¼” hole section was of primary concern, given the rig’s limited hydraulics capability.
Combined with concerns about (a) time dependency of the open shales and the salt formation, (b)
the slow ROP while trying to build and turn to horizontal, (c) bit balling and (d) extensive slide
drilling, the proposed plan was considered to be inefficient and risky. Detailed hydraulics
modeling showed that there was insufficient surface pressure capability to pump at adequate
flowrates for efficient steerable motor operation with a PDC bit. This was particularly important
given the large build and turn required at the base of this section.
A further concern was the inability to reliably isolate the gas reservoir with the proposed casing
plan, given the lack of casing movement or rotation.
It was therefore important to design the well so that the 12¼” section could be drilled as fast as
possible to case off the salt and shale intervals. Ideally the 12¼” section would be drilled using
“adjustable rotary” BHA’s, allowing un-compromised bit designs (reducing the risk of balling),
and allowing higher flowrates because a steerable motor was not used. The base of the 12¼”
section was made to be below the salt formation, but above the build and turn section. The
extensive build and turn in the next hole section effectively made the need for a steerable motor
redundant in 12¼” section.
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With the salt and long shale intervals cased off, the build and turn section can be drilled in 8½”
hole with minimum concern of hole problems. This was important given the slow progress
expected in this interval. Further, directional control is improved in 8½” section. This approach
will allow better cement isolation of the gas cap since the casing can now be rotated.
After setting and rotating a 7” liner (with premium high-torque casing connections) in the build
and turn section, 61/8” horizontal hole is then drilled to TD. Because of buckling and hydraulics
problems with 3½” drillpipe, 4” drillpipe is used for the horizontal section. An innovative BHA
strategy is used, with straight motors with a Near-Bit adjustable stabilizer and a PDC bit. The
horizontal objectives do not require a conventional steerable BHA. Further, the gauge wear on
the proposed BHA will be significantly reduced (due to less side loading) and bit life extended.
There is however contingency for slide drilling if necessary.
It is acknowledged that the well design does not have any contingency hole size available.
However, with the original plan, the contingency hole size not only cost significant time, but also
the associated additional risks placed on the 12¼” section virtually forces the use of the
contingency hole size anyway. In this case, contingency is more harmful than beneficial.
UKRAINE EXAMPLE #1 : SOLUTION,
WITH OPTIMIZED CASING PLAN
0
NOT TO SCALE
1000m
(3300 ft)
17-1/2" hole
13-3/8" surface casing to below EOB
12-1/4" hole to below salt formation. Drilled in
100% rotary mode with adjustable rotary BHA
and aggressive PDC bits. Bit is allowed to walk
as it desires, since there is insufficient flowrate
for slide drilling in 12-1/4" hole. Corrections
made in build & turn in next section.
2000m
(6600 ft)
Salt / Clay trouble zone
Run 9-5/8" casing.
8-1/2" build & turn section.
3000m
(9900 ft)
Run and rotate 7" liner.
Hard, abrasive Sandstone reservoir section
Drill 6-1/8" horizontal hole.
4000m
(13200 ft)
Figure: 61
Ukraine Solution – Optimized Well Design.
The casing plan and drilling strategy takes into account the rig limitations and the specific
geology of each section. The BHA strategies must be built into the plan from the outset, rather
than simply being decided at the rig site.
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19.2 EXAMPLE #2:
SHALLOW ERD PROJECT, OFFSHORE WEST AFRICA
Scenario Description
• This example is based on a large oil development offshore West Africa. The platform location
is not optimum for drilling, but is based around previous shallow gas experience. Over the
long exploration and appraisal history of this field, there have been numerous well control
problems, and one rig has been lost due to a shallow gas blowout. Original planning by the
Operator and primary service company showed that the project was not feasible given the
shallow depth, well control and lost circulation problems, and drag and buckling issues.
• The oil reservoirs are shallow at 1600 – 2100’ TVD (485 – 640m TVD). The oil reservoir is
overlaid by a gas sand, which must be isolated because the reservoir section will be left
barefoot.
• Step outs for the development are expected to reach at least 7000’ (2120m) and well angles are
80°+. The well plan is limited by the drilling and casing plan that is required for well control
reasons, as well as realistic limitations inability to build angle in the very soft shallow
sediments.
• There are several abnormally pressured shallow gas sands. The 1st is encountered in the build
section, while the others are in the tangent section. The formation integrity is quite limited
and the consequences of lost circulation are serious considering the well control issues.
• Because of the shallow depths involved, the rig has ample torque and pumping capability.
Either OBM or WBM can be used.
• The original well design drills 8½” hole to the oil reservoir target. A 7” liner would then be
run to isolate the overlying gas sand and then 6” hole drilled to TD. The final hole section
would be left barefoot and a 2⅞” coiled tubing completion run. The target sizes are reasonably
large and there are no distinct hard-boundaries to the targets. Target placement is based on
overall field coverage, rather than specific structural objectives.
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OFFSHORE WEST AFRICA SHALLOW E.R. WELLS WITH SHALLOW GAS
ORIGINAL WELL DESIGN PROPOSALS
0
2000 ft
NOT TO SCALE
12-1/4" hole to above 2nd gas sand.
Run 9-5/8" casing.
Gas Sand #2.
Abnormally pressured
1000ft
Shallow Gas.
20" Casing
13-3/8" Casing in caprock above gas
8-1/2" hole to oil reservoir top.
Run 7" liner.
Oil Sands, overlain by gas sand
Drill 6" hole to TD.
Leave reservoir section barefoot.
Run 2-7/8" CT completion
Figure: 62
Shallow ERD Well Example – Original Well Design Proposal
Driving Issues
The actual casing points are relatively fixed, based on well control and reservoir isolation reasons.
Also, the platform conductor size is limited to 20”.
The primary concern with the above well design is that the ECD’s are un-manageable, especially
given the low formation integrity and the well control issues. ECD’s are particularly large while
drilling 8½” hole, running and circulating the 7” liner, and while drilling 6” hole. The ECD
increase while drilling in 8½” hole at TD is about 1.5 – 1.75 ppg EMW (or more when rotation is
allowed for), while the ECD increase while circulating the 7” liner is at least 4 ppg EMW
(cement rheology and casing centralization will increase the ECD’s further). For this well, the
large ECD fluctuations will probably cause the following problems:
• Lost circulation.
• Well control problems, as a result of lost circulation.
• Wellbore instability due to wellbore flexing and relaxing. Drag and Buckling are already
critical and cannot tolerate any significant instability induced hole cleaning problems.
• Probably poor cement isolation of gas sand above the oil reservoir due to poor cementing
flowrate because of the high ECD’s.
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Another concern is that drag and buckling are significant issues. Casing flotation is necessary to
RIH to TD (although the 7” liner could be rotated into bottom, this imposes additional risk of
pack-off and the high surface torque prevents this from being the primary method). Further, the
2⅞” coiled tubing completion is particularly prone to buckling above the 7” liner top.
Solution – Change the casing plan
After an extensive review of well design options, the casing plan was changed in the following
ways (See Figure 63 below).
• The 9⅝” casing was up sized to 10¾” casing (with near-flush high-torque connections for
improved clearance inside the 13⅜ casing for reduced ECD’s and for ability to rotate for a
good cement job).
• 9⅞” hole was drilled in the long tangent section (rather than 8½” hole). This reduces ECD’s
significantly while drilling and while circulating and cementing casing.
Options such as drilling with a bi-center bit or under-reaming were investigated. Bi-center
bits are not appropriate for this application since a very large amount of slide drilling would be
necessary to hold inclination (a bi-center bit BHA can be expected to drop at 3° to 5°/100’,
leading to significant tortuosity and hole cleaning problems). Under-reaming does not solve
the ECD problems while drilling the 8½” hole size and the ECD benefits of up-sizing are not
fully realized for the casing run and the next hole section. Also, the ability to run a long string
of 7” production casing is still questionable because of the ECD’s in the cased hole interval.
• 7⅝” casing is run (instead of 7”) with high-torque connections for rotation. The casing is run
as a long string back to surface since running as a liner causes buckling problems for the 2⅞”
CT completion. Because the additional casing length of a long string is only small (±1000’)
the cost difference is negligible. This option was not available for the original well design
because of the already high ECD’s involved.
• The larger production casing size of 7⅝” allows 6¾” hole to be drilled to TD. This reduces
ECD’s for this section thereby reducing the risk of losses and formation damage.
Because the target sizes are relatively large and because the target strategy is based on field
coverage rather than specific structural objectives, the need for tight azimuth control is not
necessary in the tangent section. This allows adjustable rotary BHA and aggressive PDC bits to
be used for this section. This is not only very important for ROP and hole cleaning, but
improving the junk slot area of the bit further reduces the risk of swabbing a kick. The high angle
and the high drag mean that slide drilling would have been difficult anyway.
By good drillstring design and using casing flotation (with rotation if necessary), the need for
OBM is negated. The use of WBM further reduces the risk of lost circulation to fractures and
faults. Also, there was some concern with using OBM given the risk of gas solubility problems
and the minimal allowable overbalance pressures.
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Drilling Design and Implementation for Extended Reach and Complex Wells
OFFSHORE WEST AFRICA SHALLOW E.R. WELLS WITH SHALLOW GAS
OPTIMIZED WELL DESIGNS FOR REDUCED
ECD, DRAG & BUCKLING PROBLEMS
0
20" Casing
13-3/8" Casing in caprock above gas
13-1/2" hole to above 2nd gas sand, using under-reamer
Run 10-3/4" casing with near-flush high-torque connections..
1000ft
2000 ft
NOT TO SCALE
9-7/8" hole, then run 7-5/8"
LONG string of casing. Use
buoyancy assisted flotation
to run casing. Rotate casing
during cement job (high torque
connections used).
Drill 6-3/4" hole to TD.
Leave reservoir section barefoot.
Run 2-7/8" CT completion
Figure: 63
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Shallow ERD Well Solution
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Drilling Design and Implementation for Extended Reach and Complex Wells
19.3 EXAMPLE #3:
INFILL ERD WELL, OFFSHORE AUSTRALIA
Scenario Description
• Platform based, infill-drilling program, offshore Australia. The proposed ERD well was only
the 2nd well for a new rig and crew that were unfamiliar to the region and to the Operator.
• The geology is relatively benign in that there is no significant well control or lost circulation
issues. However, the sandstone oil reservoir is highly permeable (10-20 Darcies) and depleted
due to production. The mud weights required for stability of the thick reactive overlying
shales result in over-balance pressures in the order of 1500 psi. Differential sticking has been
a problem in the reservoir. The overlying shales formations are very sticky and prone to
balling and quite time sensitive.
• Directional control has historically been quite difficult at this and surrounding fields. The
aggressive PDC bits required for good ROP and balling-resistance do not allow good tool face
control when slide drilling. Further, build and drop tendencies of the formation mean that
slide drilling was regularly necessary if steerable BHA’s were used.
• Only WBM can be used.
• The rig had 2 x 1600 HP pumps and flowrates were restricted at depth due to drillpipe size (5”
with S135 tooljoints) and limited allowable surface pressure of only 3400 – 3600 psi.
• Conventional well designs in this region drill 12¼” hole to just above the reservoir before
setting 9⅝” casing to isolate the troublesome shale formations. 8½” hole would then be
drilled to TD and a 7” liner set and cemented.
• Assuming good performance, the expected drill and complete time was about 40 days.
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OFFSHORE AUSTRALIA INFILL DRILLING ER WELL
CONVENTIONAL WELL DESIGN
NOT TO SCALE
0
1000m
(3300 ft)
2000m
(6600 ft)
3000m
(9900 ft)
All formation to above reservoir is soft,
sticky clays. ROP can be high, but
balling is a significant issue.
20" Conductor
17-1/2" hole,
13-3/8" casing at EOB
12-1/4" hole drilled to top of highly permeable
and depleted oil reservoir. Time sensitive
shales require water based mud weights
of 11 - 12 ppg depending on angle and
time exposure
Run 9-5/8" casing to isolate shales prior to
drilling into reservoir
Troublesome, time dependent shales.
Depleted, high permeability reservoir
Figure: 64
Drill short 8 1/2" hole in reservoir
Run & cement 7" liner
Infill ERD Well example from offshore Australia
Driving Issues
The 17½” x 12¼” x 8½” casing plan has historically been used for ‘difficult’ wells in this area,
while a simpler and cheaper 13½” x 9⅞” well design has been used for ‘simple’ low angle wells.
The experience on high angle wells had shown that the 12¼” hole section was time consuming
and the hole was usually in poor condition and intermediate casing was a necessity by the time
the troublesome shales had been penetrated. As such, ‘more aggressive” well designs had not
been considered because previous experience had demonstrated the need for a contingency hole
size.
Detailed engineering analysis of the performance of previous operations showed the following
observations:
• A detailed Offset Well Review was performed despite lots of experience in the region. This
revealed some important misconceptions that had been based on improper recollection of the
facts and practices in use when the field had previously been drilled. It also highlighted
important issues given the current technology that would be used for drilling and casing
operations.
• The primary scope for performance improvement was not through reducing Non Productive
Time (NPT), but rather improving the efficiency of the Productive Time operations.
• Flowrates on similar offset wells were invariably low by the end of the 12¼” section to the
point that hole cleaning and bit hydraulics were both poor. As a result ROPs were poor and
the hole could not be cleaned. The time dependent shales were therefore always open for long
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Drilling Design and Implementation for Extended Reach and Complex Wells
periods before the reservoir was reached. The formations themselves can be drilled very
quickly, as demonstrated by low angle wells where hydraulics are good.
• Directional control was historically poor on high angle wells and consumed much of the
necessary time to drill to the reservoir. A lot of slide drilling was always necessary to
maintain angle due to varying build and drop tendencies of the formations. Further, the
aggressive bit designs required to prevent balling resulted in severe motor stalling and tool
face problems, while there was insufficient rig hydraulics capability to operate a steerable
motor efficiently with such a PDC bit.
• A detailed analysis was performed of the Formation Evaluation (FE) needs for this project. It
turned out that there were other ways of meeting the FE objectives that were more efficient
and less imposing on the well design. These included obtaining sonic log information via
cased-hole. The cement job was modified to enable this.
Solutions
The contingency driven 12¼” hole size was actually forcing the need to set intermediate casing
because of time-related hole problems rather than simply providing the flexibility to set it if
necessary.
Instead of building in a large hole size for contingency, it was therefore decided to ‘obtain safety
factor’ through an aggressive design. If the well got into severe problems there was no
contingency to fall back upon. However, the well design was built on the premise that problems
were far less likely to occur in the first place.
The well design (see Figure 65 below) was reduced to 2 hole sections, with 13½” surface hole
and 9⅞” hole to TD. The troublesome shales were not to be separately isolated from the reservoir
on the basis that the section would be drilled fast enough that all operations could be finished
quickly.
The long tangent section was drilled with rotary BHA’s with adjustable stabilizers, with
aggressive PDC bits. Good ROPs were maintained at all times through 100% rotary drilling and
good bit hydraulics. A deep correction run was required to re-orient the direction into the small
target area. Even so, the drilling was significantly more efficient than if a ‘one-BHA-to-TD’
approach.
The resulting well broke all relevant time and performance records for the region despite a new
rig and a new crew, and several trips for rig and MWD failures. This 4686m MD (15,375’) well
was drilled and completed in 26.6 days despite this rig and crew only having drilled one well in
the region before this.
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OFFSHORE AUSTRALIA INFILL DRILLING ER WELL
OPTIMIZED, RECORD BREAKING DESIGN.
0
NOT TO SCALE
20" Casing
13-1/2" hole,
10-3/4"" casing set deeper
than previous.
1000m
(3300 ft)
9-7/8" hole drilled to TD.
Relied on drilling much quicker through better
hydraulics and improved drilling strategy.
Set 7-5/8" casing at TD.
2000m
(6600 ft)
3000m
(9900 ft)
Figure: 65
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Infill ERD Well optimized well design
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Drilling Design and Implementation for Extended Reach and Complex Wells
19.4 EXAMPLE #4:
ERD SATELLITE DEVELOPMENT, OFFSHORE AUSTRALIA
Scenario Description
• This development involved drilling ERD wells to a small satellite field from an existing
platform. Additional conductors were installed on the platform for the 4 planned development
wells. The satellite oil field is a sandstone reservoir with over-pressured gas sand above.
These wells are among the most challenging ERD wells drilled to date.
• The reservoir formation is relatively shallow. It is significantly harder than the overlying
shale formations, with slow drilling and frequent bit trips required on the offset wells. The
reservoir formation also has numerous coal seams that have been known to be quite unstable
and troublesome, with many stuck pipe and lost circulation incidents having occurred in the
reservoir on exploration and offset development wells.
• The overlying shale formations are reactive and stability is quite dependent upon well angle
with WBM. In SBM/OBM systems, the shale has proven to be relatively benign once the mud
weight is optimized. Mud weight in the reservoir must be sufficient for well control reasons
due to the thick gas cap, but further increases are limited by lost circulation in the coals.
• The drilling rig had 5½” premium drillpipe, a high torque top drive, but only 2 x 1600 HP
pumps and a 3800 psi surface pressure limit. The rig was capable of operating with SBM
systems.
Driving Issues
The initial build and hold designs were 70° - 75° wells. See Figure 66 below. Conventional well
designs for the region dictated that 9⅝” intermediate casing is set at the top of the reservoir
section.
A detailed offset well review was performed after initial well designs were prepared. Among
many of the observations made from this review, the following were key:
• The coal and shale stringers in the reservoir section were much more likely to suffer
significant wellbore instability problems if the angle was increased above 50° for the given
mud weight that was permissible. Wells below 50° in the reservoir had relatively few serious
coal-related problems, while most wells over 50° had significant problems. Almost all wells
used the same mud weight in this reservoir section (a narrow mud weight window bounded by
well control and lost circulation issues).
• Certain coal stringers were identified as key markers and as more troublesome than the others.
In particular, two coal seams were identified as being higher risk sections.
• Bit damage and slow ROP were regular problems in the reservoir section due to hard dolomite
stringers interspersed with soft sticky shales and abrasive sandstone stringers.
• There was significant geological uncertainty in the key reservoir tops.
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Drilling Design and Implementation for Extended Reach and Complex Wells
OFFSHORE AUSTRALIA E.R. SATELLITE FIELD DEVELOPMENT
ORIGINAL WELL DESIGN
WITH CONVENTIONAL CASING PLAN
0
NOT TO SCALE
26" Conductor
17-1/2" hole to EOB.
Set 13-3/8" hole
1000m
(3300 ft)
12-1/4" hole to top of reservoir section
to isolate shale formations.
Set 9-5/8" casing.
2000m
(6600 ft)
3000m
(9900 ft)
Reservoir formation has many
troublesome coals. Offset Well
Review shows coals to be unstable
above 50 degrees (for allowable
mud weights).
Also, this section is slow ROP and
short bit life.
Figure: 66
8-1/2" hole to TD.
Set & Cement 7" liner.
ERD Satellite Field Development – Original Plan
Solutions
In order to manage coal instability and to better accommodate the geological uncertainty, S-bend
well designs were adopted. The criteria for the S-bend plans required that the angle had to be
reduced to 45° (50° maximum) upon reaching the reservoir formation top (see Figure 67 below).
This design feature significantly reduced the overall well length (since the well was being drilled
to a set TVD below the target). Further the hard abrasive reservoir interval was reduced
dramatically, limiting the hole exposure time for the coal stringers.
The resulting well designs had significantly higher tangent angle sections, to the point that the
well was now negative weight. The tangent angle was now increased to ± 84°. As such, the
drilling and casing running strategies needed to be designed accordingly. 65/8” drillpipe was
purchased for buckling prevention in the 12¼” hole and inverted drillstrings were used. The 9⅝”
casing was run with a Mud-over-Air selective flotation technique to overcome drag. Innovative
PDC bits were purpose designed for the ability to walk in a given direction. This was as a
contingency against not being able to slide drill for azimuth corrections, given that the well was
negative weight. Slide drilling was in fact possible for the correction runs made with the use of
inverted drillstrings and advanced slide drilling techniques.
2007 – Third Edition
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Drilling Design and Implementation for Extended Reach and Complex Wells
OFFSHORE AUSTRALIA E.R. SATELLITE FIELD DEVELOPMENT
OPTIMIZED CASING PLAN TO MANAGE COAL
INSTABILITY AND SLOW ROP IN RESERVOIR
0
26" Conductor
17-1/2" hole to EOB.
Set 13-3/8" hole
1000m
(3300 ft)
12-1/4" hole deep enough to isolate key unstable coal seams.
Angle dropped to below 50 degrees by top of
reservoir formation for stability of the coals.
Run 9-5/8" casing with Mud-over-Air flotation technique.
Angle = 84 degrees
2000m
(6600 ft)
Reservoir formation has many troublesome coals.
Offset Well Review shows coals to be unstable above 50 degrees.
Also, this section is slow ROP and short bit life.
8-1/2" hole to TD.
Set & Cement 5-1/2" liner.
3000m
(9900 ft)
NOT TO SCALE
Figure: 67
ERD Satellite Field Development with optimized well design
Although K&M believed that these well designs were optimized, recent industry learnings and
actual drilling experiences on these wells showed these wells to still be deficient. At the time, the
industry did not understand the magnitudes and causes of the ECD fluctuations that can be
present in ERD wells. Although ECD’s were a consideration in the planning and practices used,
K&M (like almost everyone else) had no idea that the ECD’s were much higher than
conventional understanding of the time. Since this time, the use of PWD has demonstrated that
ECD’s are much greater than previously understood.
Two of the three ERD wells still experienced coal instability in the 8½” production hole, leading
to significant problems. Although ECD’s were thought to be responsible, hindsight would
demand that the design and practices would be different. The drillstring design, mud properties,
BHA strategies and parameters would all be revised to minimize ECD’s for the 8½” section.
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Drilling Design and Implementation for Extended Reach and Complex Wells
19.5 EXAMPLE #5:
SIGNIFICANT PROBLEMS ON ERD WELLS, OFFSHORE AUSTRALIA
Scenario Description
• A large ERD development offshore Australia had significant drilling problems, primarily in
the long 12¼” section. Significant ‘hole cleaning’ problems had occurred throughout the
project despite a purpose built drilling rig with excess capacity.
• When consulted for help with their apparent hole cleaning problems, the following issues were
noted:
The Operator’s objective was to drill the length of each hole section with only one BHA.
For the 12¼” section this required drilling with a heavy set PDC bit on a steerable BHA,
with a super-combo FEWD suite for logging the final portion of the long bit run.
Flowrates were always very high (generally > 1200 gpm).
A significant amount of slide drilling was performed for holding inclination throughout the
12¼” section. It was estimated that slide drilling comprised about 30% by distance drilled.
ROPs were in the order of 40 – 60 m/hr (130 – 200 ft/hr) in rotary drilling.
When asked whether wellbore instability was a possibility, the Operator confidently said
“no” based on previous experience. They were confident that the hole was in gauge,
although they were not asked how they knew this to be the case.
Tripping practices were poor. A significant amount of backreaming was performed
without having cleaned the hole up prior to pulling out. Likewise, the hole was not cleaned
out after backreaming had finished.
Solutions
Based on the above and K&M’s previous experience, it was felt that the drilling and tripping
practices needed specific attention. In particular:
1. The directional drilling practice of using a one-BHA-to-TD was not only unrealistic, but quite
harmful. The strategy was unrealistic in several respects. Firstly, the demonstrated tool
reliability did not suggest that there was any real likelihood that a single BHA could drill the
long interval to TD in one run without at least one failure in the motor, MWD or super-combo
FEWD. Secondly, the bit selection was badly compromised to drill through many different
formations in order to provide steerability and to drill the entire interval.
2. The strategy was harmful in that it resulted in extended and frequent slide drilling directly
leading to hole cleaning difficulties. Further, the bit selection that was necessary for
steerability made for difficulty tripping through cuttings beds due to the heavyset bit design.
3. Rotary BHA’s with adjustable stabilizers were recommended for better hole cleaning.
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Drilling Design and Implementation for Extended Reach and Complex Wells
4. Tripping practices were revised so that the hole was cleaned up as best as possible prior to
tripping. The hole was also to be cleaned up after any backreaming.
5. Hole condition monitoring was instigated to better monitor hole cleaning.
Initially only the 2nd and 3rd points were implemented because the Operator wanted to pursue the
objective of drilling to TD in one BHA run. Despite the above changes, hole cleaning problems
continued to occur in the 12¼” section. The hole cleaning problems still appeared to be largely
because of the extensive slide drilling performed.
It was not until the 10th well of the project that the recommended BHA design practices were
tested. Unfortunately, hole cleaning problems still occurred. However, because the drilling
strategy was now optimized, it was immediately clear that a wellbore instability problem was
present. Caliper logs confirmed severe hole enlargement in several sections of the well. It turned
out that the Operator had never confirmed wellbore stability assumptions in the high angle wells.
However, because the drilling practices were poor, the primary problem could not be identified.
The mud weight was subsequently increased, resulting in considerable improvement on the later
wells in the drilling campaign.
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Drilling Design and Implementation for Extended Reach and Complex Wells
20 RELEVANT TECHNICAL PUBLICATIONS
Included on the following pages are publications and articles on ERD and related topics. The list
of SPE papers is by no means complete, but should provide a broad range of ERD related topics.
The papers do not necessarily represent K&M’s opinions or experiences, but are presented for
thoroughness.
20.1 ER DRILLING - GENERAL
65000
High-Density Invert-Emulsion System with Very Low Solids Content to Drill ERD
and HPHT Wells
Luigi F. Nicora, Pierangelo Pirovano, Lamberti SpA, Nils Blomberg, Knut Taugbøl,
64620
Technology Applied to Extend the Drilling Reach of a Platform Workover Rig
G.A. McNair, S.D. Cassidy, Z. Zheng
62791
Development Process and Field Applications of a New Ester-based Mud System for
ERD Wells on Australia's Northwest Shelf
Daniel Eckhout, Shane Dolan, SPE, Ray Gogan, Hanjo Ledgister, Carol Mowat, Paul
Tipton, Bruce Ewen, William Dye
62767
Performance Improvement Techniques Used on Goodwyn A Platform
S.P. Dolan, W.J. Barrows, J.W. Dickson, D. Torry, R.F. Drury
62728
Analysis of extended reach drilling data using an advanced pressure and temperature
model
K.S. Bjørkevoll, B.-T. Anfinsen, Antonino Merlo, Nils-Harald Eriksen, Espen Olsen
62727
Geomechanical Analysis for Resak's Extended-Reach Drilling - A Case Example
Seehong Ong, Ahmad Shah Baim, Mohd Zaki Ibrahim, Ziqiong Zheng
59204
To the Limit and Beyond - The Secret of World-Class Extended-Reach Drilling
Performance at Wytch Farm
Tony Meader, Frank Allen, Graham Riley
56628
Analysis of Stuck Pipe in Deviated Boreholes
Bernt S. Aadnøy, Kenneth Larsen, Per C. Berg
56565
A Pragmatic Approach to Managing Wellbore Instability in Extended Reach Wells in
the Goodwyn Field
C.P. Tan, D.R. Willoughby
56564
An Integrated Solution of Extended-Reach Drilling Problems in the Niakuk Field,
Alaska: Part II- Hydraulics, Cuttings Transport and PWD
M. D. Green, C. R. Thomesen, L. Wolfson, P. A. Bern,
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Drilling Design and Implementation for Extended Reach and Complex Wells
56563
An Integrated Solution of Extended-Reach Drilling Problems in the Niakuk Field,
Alaska: Part I - Wellbore Stability Assessment
S. L. Dowson, S. M. Willson, L. Wolfson, G. G. Ramos, U. A. Tare,
56405
The Multiple Role of Unconventional Drilling Technologies. From Well Design to
Well Productivity
Ph. A. Charlez, P. Bréant
52854
Dieksand 2; an Extended Well Through Salt, Increases Production from an
Environmentally Protected Field
Ken Sudron, Heinz Berners Ulrich Frank, Werner Sickinger, Anthony Hadow, Govert
Klop,
52838
Shallow Kick-off Extended Reach Drilling in GOM
B. Meize, S. Chesebro,A. Stubblefield , C. Lenamond, R. Miller,
52775
Managing Peer Assists - Case Study of Improved Extended Reach Drilling
Performance
A. Judzis, D.S. Stoltz, L. Wolfson,
52188
Novel Approach to Borehole Stability Modeling for ERD and Deepwater Drilling
U.A. Tare,F.K. Mody
50900
Study on Design of ERD Well Trajectory
Ma, Shanzhou ,Huang, Genlu ,Zhang, Jianguo ,Han, Zhiyong
50876
Critical Aspects Experienced in Drilling a World Record ERD Well in South China
Sea
Zhang, Ming Jiang ,Zhang, Wu Nian
50557
Systematic Approach Enhances Drilling Optimization and PDC Bit Performance in
North Slope ERD Program
Larry Wolfson, Graham Mensa-Wilmot, Robert Coolidge,
50079
Planning, Execution and Lessons Learned From the GWA13 Extended Reach Drilling
Well - Goodwyn Gas/Condensate Field, NWS, Australia
Dolan, S.P, Crabtree, R.C, Drury, R.F., Gogan, R, Hattersley, G, Hindle, D.
Neufeld, B., Scaife, R.
49984
High Angle Drilling In Severely Depleted Reservoirs
Bonnett, Nigel ,Williamson, Bob ,Oakes, Peter
49111
An Example of the Drilling Analysis Process for ERD Wells
Millheim, Keith ,Maidla, Eric ,Kravis, Simon
48944
ER Drilling at the Uttermost Part of the Earth
Naegel, M. ,Pradie, E. ,Beffa, K. ,Ricaud, J. ,Delahaye, T.
48943
Extended-Reach Drilling -- What is the Limit?
Mason, C.J. Judzis, A.
2007 – Third Edition
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Drilling Design and Implementation for Extended Reach and Complex Wells
47785
Case History on Planning, Drilling and Completing the World Record ERW-XJ 24-3A14
Jiang, Zhang Ming
47287
Three History Cases of Rock Mechanics related Stuck Pipes while drilling ERD wells
in North Sea.
Charlez, P.A. ,Onaisi, A.
38583
Meeting the 10km Drilling Challenge
Modi, S. ,Mason, C.J. ,Tooms, P.J. ,Conran, G.
38466
ER Drilling Limitations: A Shared Solution
Rodman, D.W. ,Swietlik, G.
38270
Horizontal Well and ERD Technologies with Reported Problem Areas and Operational
Practice in North America and Europe
Crouse, P.C. ,Tada, H. ,Takeuchi, T.
37618
Pushing the ERD Envelope at Wytch Farm
Cocking, D.A. ,Bezant, P.N. ,Tooms, P.J.
37610
Field Applications of ERD Hole Cleaning Modeling
Hemphill, Terry ,Pogue, Tom
37600
Beyond 8 km Departure Wells: The Necessary Rig and Equipment
Gammage, J.H. ,Modi, S. ,Klop, G.W.
37576
Armada Development: Case History of ERD Pre-Drilling From a Semi-Submersible in
the Central North Sea
Teggart, B.G. ,Dunne, C.L. ,Wilkinson, R.D.
37573
ER Drilling: Managing Networking, Guidelines, and Lessons Learned
Judzis, Arnis ,Jardaneh, Kamal ,Bowes, Colin
36989
Further Advancements in ERD Drilling in Bass Strait
Krepp, A.N., Mims, M.G., Santostefano, V.
36406
ER Drilling Experience at Tabu B
Longwell, III, H.J. ,Seng, Ng Kin
35993
BHA Design Algorithm for ERD Wells
Agawani, Mamdouh M. ,Rahman, Sheik S. ,Maidla, Eric E.
35666
Reduction of Drill String Torque and Casing Wear in ERD Wells Using Non-Rotating
Drill Pipe Protectors
Moore, N.B. ,Mock, P.W. ,Krueger, R.E.
35103
How a 23000' MD ERD Horizontal Well Was Drilled In Less Than 24 Days
Omsberg, N.P. ,Morgan, D.R.
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35054
An Investigative Study on Horizontal Well and ERD Technologies with Reported
Problem Areas and Operational Practice in North America and Europe
Ikeda, S. ,Takeuchi, T. ,Crouse, P.C.
31144
Experience with Horizontal Wells in the Statfjord Field
Kostol, Petter ,Berg, Dag P.
30463
Experience With Drilling C-26A, A World Record ERD Horizontal Well in the
Oseberg Field, North Sea.
Andresen, Svein ,Hovda, Sigve ,Olsen, Tor Lie
30451
Advances in ERD Drilling - An Eye to 10 km Stepout
Ryan, G. ,Reynolds, J. ,Raitt, F.
30140
Brief: Critical Technologies for Success in Extended-Reach Drilling
Payne, M.L. ,Cocking, D.A. ,Hatch, A.J.
29944
Very Long Reach Drilling Technology Application in North Sea
Lal, Manohar ,Guild, G. John
29923
Planning and Execution of a Record-ER Well in Japan
Benesch, J. M. ,Camacho A., G. ,Matsuzawa, S. ,Dawson, C. R.
29920
Recent Advances and Emerging Technologies for ERD Drilling
Payne, M. L. ,Wilton, B. S. ,Ramos, G. G.
28833
Drilling to the Limit / Long Reach Oil Strike ERD Appraisal/Development Well Tern
TA-05
Meertens, Rob ,Kloss, Peter
28777
ER Drilling Advancements Dramatically Improve Performance on Bass Strait Wells
Santostefano, Vince, A. N. Krepp
28293
Critical Technologies for Success in ERD Drilling
Payne, M.L. ,Cocking, D.A. ,Hatch, A.J.
28005
ER, Horizontal, and Complex Design Wells: Challenges, Achievements and CostBenefits
Blikra, Harald ,Drevdal, K.E. ,Aarrestad, T.V.
27526
Onshore Exploration and Development of California Offshore Resources Through
ERD Drilling
Starzer, M.R. ,Mount II, P.B. ,Voskanian, M.M.
27463
Application of Innovative ERD and Horizontal Drilling Technology in Oilfield
Development
Bell Jr., R.A. ,Hinkel, R.M. ,Bunyak, M.J. ,Payne, J.D. ,Hood III, J.L.
27461
Designer Directional Drilling to Increase Total Recovery and Production Rates
Eck-Olsen, Johan ,Samuell, John ,Reynolds, Jim
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26350
Pushing the Limits for ERD Drilling: New World Record From Platform Statfjord C,
Well C2
Alfsen, Turid E. ,Heggen, Steinar ,Blikra, Harald ,Tjotta, Helge
25750
North Sea Advances in ERD Drilling
Eck-Olsen, Johan ,Sletten, Haakon ,Reynolds Jr., J.T. ,Samuell, J.G.
25749
Drilling Extended-Reach/High angle Wells Through Overpressured Shale Formation
Guild, G.J. ,Jeffrey, J.T. ,Carter, J.A.
23866
Long-Reach, High angle Drilling in the Gulf of Mexico: A Case History of Eugene
Island Block 370 Well B-11
Gadberry, R.L. ,Switzer, S.S.
23850
Increasing Extended-Reach Capabilities Through Wellbore Profile Optimisation
Banks, S.M. ,Hogg, T.W. ,Thorogood, J.L.
23849
New World Record in Extended-Reach Drilling From Platform Statfjord `C'
Njaerheim, Asgeir ,Tjoetta, Helge
23014
Drilling Extended-Reach Wells, Northwest Shelf, Australia
Scott, P.W. ,Lintern, G.A. ,Embury, J.E.
21984
World Record in ERD Drilling, Well 33/9-C10, Statfjord Field, Norway
Rasmussen, B. ,Sorheim, J.O. ,Seiffert, E. ,Angeltvadt, O. ,Gjedrem, T.
21983
Increasing Reach From 3,000 m to 5,000 m
Scott, P.W.
20818
Extended-Reach Drilling From Platform Irene
Mueller, M.D. ,Quintana, J.M. ,Bunyak, M.J.
20094
Extended-Reach Drilling From Platform Irene
Mueller, M.D. ,Quintana, J.M. ,Bunyak, M.J.
17564
ER Appraisal Well: A Case History
Locke, H.A. ,Johnson, J.B. ,Jewkes, D.C.
17183
Rotation of a Long Liner in a Shallow Long-Reach Well
Gust, D.A. ,MacDonald, R.R.
13473
Long Reach Drilling in the Gulf of Mexico: A Case History
Whitson, Charles D. ,Sandison, George F.
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20.2 HOLE CLEANING IN ERD
65502
Critical Cuttings Transport Velocity in Inclined Annulus: Experimental Studies and
Numerical Simulation
Y. Masuda, Q. Doan, M. Oguztoreli, S. Naganawa, T. Yonezawa, A. Kbayashi, A.
Kamp
63269
A Three-Layer Modeling for Cuttings Transport with Coiled Tubing Horizontal
Drilling
Hyun Cho, Subhash N. Shah, Samuel O. Osisanya
63050
Selecting Drilling Fluid Properties and Flow Rates For Effective Hole Cleaning in
High angle and Horizontal Wells
Rishi B. Adari, Stefan Miska, Ergun Kuru, Peter Bern, Arild Saasen
62794
Drilling Practices and Sweep Selection for Efficient Hole Cleaning in Deviated
Wellbores
D.J. Power, C. Hight, D. Weisinger, C. Rimer
59731
Field Applications of ERD Hole Cleaning Modeling
A.T. Hemphill, Tom Pogue
59143
Improved Hole Cleaning and Reduced Rotary Torque by New External Profile on
Drilling Equipment
J.G. Boulet, J.A. Shepherd, J. Batham, L.R. Elliott
57716
State-of-the-Art Cuttings Transport in Horizontal Wellbores
A.A. Pilehvari, J.J. Azar, SPE, S.A. Shirazi
56406
Effect of Drillpipe Rotation on Hole Cleaning During Directional-Well Drilling
R. Alfredo Sanchez, J.J. Azar, A.A. Bassal, A.L. Martins
53942
Layer Modeling for Cuttings Transport in Highly Inclined Wellbores
A.M. Kamp, M. Rivero
52793
Cuttings Flux Measurement and Analysis for Extended-Reach Wells
Gerhard Thonhauser, Keith K. Millheim, Andre L. Martins,
50677
Cuttings Flow Meters Monitor Hole Cleaning in ERD Wells
Naegel, M. ,Pradie, E. ,Delahaye, T. ,Mabile, C. ,Roussiaux, G.
50582
Hole Cleaning During Deviated Drilling - The Effects of Pump Rate and Rheology
Saasen, A. McCollum, Frank L. ,Kamaruddin, Abdul Wahab ,Longwell, Harry J. III
37626
The Effect of Drillpipe Rotation on Hole Cleaning During Directional Well Drilling
Sanchez, R.A. ,Azar, J.J. ,Bassal, A.A. ,Martins, A.L.
37610
Field Applications of ERD Hole Cleaning Modeling
Hemphill, Terry ,Pogue, Tom
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36383
A Three-Layer Hydraulic Program for Effective Cuttings Transport and Hole Cleaning
in Highly Deviated and Horizontal Wells
Nguyen, D. ,Rahman, S.S
35099
Hole Cleaning Modelling: What's 'n' Got To Do With It?
Kenny, Patrick ,Sunde, Egil ,Hemphill, Terry
29425
Hole Cleaning in ERD Wells: Field Experience and Theoretical Analysis Using a
Pseudo-Oil (Acetal) Based Mud
Gao, Erhu ,Young, A.C.
29381
Hole Cleaning Program for ERD Wells
Guild, G.J. ,Wallace, I.M. ,Wassenborg, M.J.
28308
Unique Hole Cleaning Capabilities of Ester-Based Drilling Fluid System
Kenny, Patrick
27486
Simple Charts To Determine Hole Cleaning Requirements in Deviated Wells
Luo, Yuejin ,Bern, P.A. ,Chambers, B.D.
27464
Hole Cleaning in Large, High angle Wellbores
Rasi, Marco
20.3 TORQUE, DRAG AND BUCKLING
68505
Extending the Reach and Capability of Non Rotating BHAs by Reducing Axial
Friction
W. Rasheed
67727
Lateral Buckling of Pipe with Connectors in Curved Wellbores
Robert F. Mitchell
63270
Reinventing the Wheel - Reducing Friction in High angle Wells
Colin J. Mason, Larry G. Williams, Geoff N. Murray
62784
The Benefits of Monitoring Torque & Drag in Real Time
Bart E. Vos, Frank Reiber
60701
New Downhole Tool for Coiled Tubing Extended Reach
Kjell-Inge Sola, Bjørnar Lund
59213
A Proven Liner Flotation Method for Extended-Reach Wells
Kevin Trahan, Jamie MacDonald, Steve Webster, Colin Mason
59146
Lateral Buckling of Pipe with Connectors in Horizontal Wells
R.F. Mitchell
57896
A Buckling Criterion for Constant-Curvature Wellbores
Robert F. Mitchell
2007 – Third Edition
Page 286
Drilling Design and Implementation for Extended Reach and Complex Wells
56562
Microbeads as Lubricant in Drilling Muds Using a Modified Lubricity Tester
P. Skalle, K.R. Backe, S.K. Lyomov, L. Kilaas, A.D. Dyrli, J. Sveen
55682
Effect of Coiled-Tubing Initial Configuration on Buckling Behavior in a ConstantCurvature Hole
Weiyong Qiu, S.Z. Miska, L.J. Volk
55039
Buckling Analysis in Deviated Wells: A Practical Method
R.F. Mitchell
52842
Casing Running Milestones for Extended-Reach Wells
C.J. Mason, F.M. Allen, A.A. Ramirez, L. Wolfson, R. Tapper
52840
The Buckling Behavior of Pipes and Its Influence on the Axial Force Transfer in
Directional Wells
E. Kuru, A. Martinez, S. Miska, W. Qiu
52836
On-Line Torque & Drag: A Real-Time Drilling Performance Optimization Tool
Frank Reiber, Bart E. Vos, Svein E. Eide
50931
An Analysis of Helical Buckling of Long Tubulars in Horizontal Wells
Deli, Gao ,Liu, FengWu ,Xu, BingYe
48939
Techniques for Solving Torque and Drag Problems in Today's Drilling Environment
Aston, M.S. ,Hearn, P.J. ,McGhee, G.
47804
Reduce Torque, Drag and Wear - Material Selection for Centralizers Used in Highly
Inclined and Horizontal Wells
Kinzel, holger ,Colvard, R.L
46009
Effect of Coiled Tubing Initial Configuration on Buckling Behavior in a Hole of
Constant Curvature
Weiyoung, Qiu ,Miska, Stefan ,Volk, Leonard
39795
Drill Pipe/Coiled Tubing Buckling Analysis in a Hole of Constant Curvature
Qui, Weiyong ,Miska, Stefan ,Volk, Leonard
39322
Field Curves for Critical Buckling Loads in Curving Wellbores
Hill, T.H. ,Chandler, R.B
39321
A Robust Torque and Drag Analysis Approach for Well Planning and Drillstring
Design
Adewuya, Opeyemi A. ,Pham, Son V.
37477
Torsional Load Effect on Drill-String Buckling
Wu, Jiang
37264
Performance of a New Biodegradable Ester Based Lubricant for Improving Drilling
Operations with Water Based Muds
Argillier, J-F. ,Audibert, A. ,Janssen, M. ,Demoulin, A.
2007 – Third Edition
Page 287
Drilling Design and Implementation for Extended Reach and Complex Wells
36862
Development of a New Non-Polluting Ester Based Lubricant for Water Based Muds:
Laboratory and Field Tests Results
Argillier, J-F. ,Audibert, A. ,Janssen, M. ,Demoulin, A.
36761
Buckling Analysis in Deviated Wells: A Practical Method
Mitchell, R.F.
36434
The Effects of Pressure and Rotary Speed on the Drag Bit Drilling Strength of Deep
Formations
Kolle, J.J
36384
Prediction of Helical / Sinusoidal Buckling
Hishida, H. ,Ueno, M. ,Higuchi, K. ,Hatakeyama, T
36382
A New Approach to Calculate the Optimum Placement of Centralizers includes
Torque and Drag Predictions
Kinzel, Holger ,Koithan, Thomas ,Lirette, Brent
35102
Advanced Torque and Drag Considerations in Extended-Reach Wells
Payne, M.L. ,Abbassian, F.
30521
Interactions between Torque and Helical Buckling in Drilling
He, X. ,Halsey, G.W. ,Kyllingstad, A.
29460
An Analysis of Helical Buckling of Tubulars Subjected to Axial and Torsional
Loading in Inclined Wellbores
Miska, Stefan ,Cunha, J. C.
29164
Experimental and Analytical Study of Sinusoidal Buckling in Vertical Wells
Salies, J.B. ,Cunha, J.C.S. ,Azar, J.J. ,Soren Jr., J.R.
28713
Experimental and Mathematical Modeling of Helical Buckling of Tubulars in
Directional Wellbores
Salies, J.B. ,Azar, J.J. ,Sorem, J.R.
27491
Torque and Drag: Key Factors in ERD Drilling
Aarrestad, T.V. ,Blikra, Harald
27490
Solution of Common Stuck Pipe Problems Through the Adaptation of Torque Drag
Calculations
Haduch, G.A. ,Samuels, D.A
26752
Field Test of a Downhole-Activated Centralizer To Reduce Casing Drag
Kinzel, Holger ,Calderoni, Angelo
26713
A Joint Industry Research Project To Investigate Coiled-Tubing Buckling
Tailby, R.J. ,Cobb, D.O. ,Riva, M.C. ,Jones, Colin ,Rydland, J.A. ,Christensen, O.S.
26336
Coiled Tubing Buckling Implication in Drilling and Completing Horizontal Wells
Wu, Jiang ,Juvkam-Wold, Hans C.
2007 – Third Edition
Page 288
Drilling Design and Implementation for Extended Reach and Complex Wells
25503
Study of Helical Buckling of Pipes in Horizontal Wells
Wu, Jiang ,Juvkam-Wold, H.C.
25370
Helical Buckling and Lock-Up Conditions for Coiled Tubing in Curved Wells
He, Xiaojun ,Kyllingstad, Age
23903
Drillpipe Protectors Successfully Used To Reduce Casing Wear in Deep, Directional
Well
Schneider, F.F. ,Collins, G.J.
23878
Analysis of Buoyancy-Assisted Casings and Liners in Mega-Reach Wells
Ruddy, K.E. ,Hill, Douglas
23848
Two Double Azimuth-Double "S"-Shaped Wells Planned and Drilled Using Torque
and Drag Modeling
Wilson, T.P. ,Yalcin, Oguz
21942
The Critical Buckling Force and Stresses for Pipe in Inclined Curved Boreholes
Schuh, F.J.
21308
Authors' Reply to Discussion of Tubing and Casing Buckling in Horizontal Wells
Chen, Yu-Cho ,Lin, Yu-Hsu ,Cheatham, John B.
26336-P
Coiled Tubing Buckling Implication in Drilling and Completing Horizontal Wells
Wu, Jiang ,Juvkam-Wold, Hans C.
29457-P
Comprehensive Analysis of Buckling With Friction
Mitchell, R.F.
29462-P
Effects of Well Deviation on Helical Buckling
Mitchell, R.F.
20.4 HYDRAULICS AND ECD’S / PRESSURE WHILE DRILLING
67717
Field Validation of Transient Swab/Surge Response with PWD Data
G. Robello Samuel, Ashwin Sunthankar, Glen McColpin, Peter Bern, Tim Flynn
67618
Influence of Drillpipe Rotation and Eccentricity on Pressure Drop Over Borehole With
Newtonian Liquid During Drilling
G. Ooms, B.E. Kampman-Reinhartz
62960
Major Advancements in True Real-Time Hydraulics
M. Zamora, S. Roy, H.Y. Caicedo, T.S. Froitland, S.T. Ting
62167
A Generalized and Consistent Pressure Drop and Flow Regime Transition Model for
Drilling Hydraulics
W.J. Bailey, J.M. Peden
2007 – Third Edition
Page 289
Drilling Design and Implementation for Extended Reach and Complex Wells
59265
Experimental Study of Slimhole Annular Pressure Loss and Its Field Applications
Haige Wang, Yinao Su, Yangmin Bai, Zhenguo Gao, Fengmin Zhang
56638
Influence of Drillpipe Rotation and Eccentricity on Pressure Drop over Borehole
during Drilling
G. Ooms, J.M. Burgerscentrum, B.E. Kampman-Reinhartz
49114
Using Downhole Annular Pressure Measurements to Anticipate Drilling Problems
Hutchinson, Mark ,Rezmer-Cooper, Iain
39282
Temperature and Pressure Effects on Drilling Fluid Rheology and ECD in Very Deep
Wells
Rommetveit, R. ,Bjorkevoll, K.S.
37588
Pressure While Drilling Data Improves Reservoir Drilling Performance
Ward, C.D. ,Andreassen, E
30488
Drill Pipe Rotation Effects on Frictional Pressure Losses in Slim Annuli
Hansen, Svein A. ,Sterri, Njal
24598
The Influence of Drilling Conditions on Annular Pressure Losses
Marken, C.D. ,He, Xiaojun ,Saasen, Arild
20.5 DIRECTIONAL DRILLING
71840
Using Rotary Closed-Loop Drilling to Increase Operational Efficiency and Reduce
Operational Risk
John A Johnson, Hartmut Gruenhagen
68088
Steerable Motor with Integrated Adjustable Gauge Stabiliser Provides Improved
Directional Drilling Performance in the Middle-East
L. Lawrence, J. Stymiest, R. Russell
68086
New Drilling System Brings Significant Improvements to Drilling Performance and
Hole Quality in Middle-East Fields
Ali M. Dahche, Stewart Swick, Richard Russell
67818
Tortuosity versus Micro-Tortuosity - Why Little Things Mean a Lot
Tom M. Gaynor, David C-K Chen, Darren Stuart, Blaine Comeaux
67760
First Simultaneous Application of Rotary Steerable/Ream-While-Drill on Ursa
Horizontal Well
L.F. Eaton, Scott McDonald, Edgar M. Rodriguez
67756
Innovations in Reservoir Navigation
J. Coghill, M. Benefield, A. Poppitt, J. Skillings
67715
Drilling with Rotary Steerable System Reduces Wellbore Tortuosity
P. Weijermans, J. Ruszka, H. Jamshidian, M. Matheson
2007 – Third Edition
Page 290
Drilling Design and Implementation for Extended Reach and Complex Wells
63248
An Improved Steerable System: Working Principles, Modeling, and
Testing
Tom Gaynor, David C-K Chen, Chris Maranuk, Jack Pruitt
63247
Point-the-Bit Rotary Steerable System: Theory and Field Results
Stuart Schaaf, C.R. Mallary, Demos Pafitis
62779
Development of Stable PDC Bits for Specific Use on Rotary Steerable Systems
S. Barton
62781
Specialized PDC Bit Improves Efficiency of Rotary Steering Drilling Tools in
Demanding Directional Drilling Programs
Graham Mensa-Wilmot, Tony Krepp, Richard Hill
60752
A Concept of a New Steerable Drilling System for Coiled Tubing
C. A. Maranuk, T. M. Gaynor, D. C-K Chen, J. Pruitt
60750
Anaconda: Joint Development Project Leads to Digitally Controlled
Composite Coiled Tubing Drilling System
Roy Marker, John Haukvik, James B. Terry, Martin D. Paulk, E. Alan
Coats,
Tom Wilson, Jim Estep, Mark Farabee, Scott A. Berning, Haoshi Song
59259
Automatic Inclination Controller: A New Inclination Controlling Tool for Rotary
Drilling
Liu Yinghui, Su yinao
59217
Use of a Rotary Steerable Tool at the Valhall Field, Norway
Sigurd Kinn, Peter Allen, Martin Slater
59194
At-Bit Inclination Measurements Improves Directional Drilling Efficiency and Control
Torger Skillingstad
59110
Application of Rotary Steerable System/PDC Bits in Hard Interbedded Formations: A
Multidisciplinary Team Approach to Performance Improvement
Harald Fiksdal, Clive Rayton, Zvonimir Djerfi
56958
Realizing True Value From Rotary Steerable Drilling Systems
Johnstone, J. A, Allan, D
56937
Experiences and Learning Points From the Use of Steerable Rotary Drilling Systems
on Northern North Sea Platforms.
Ernest K. Poku.
56443
Development of Remote-Controlled Dynamic Orientating System
T. Urayama, T. Yonezawa, A. Nakahara, A. Ikeda, T. Nakayama, D. D. Gleitman
2007 – Third Edition
Page 291
Drilling Design and Implementation for Extended Reach and Complex Wells
52879
Dual Torque Concept Enhances PDC Bit Efficiency in Directional and Horizontal
Drilling Programs
Graham Mensa-Wilmot, Tony Krepp, SPE, Ita Stephen,
49948
Adjustable Stabiliser Drilling: A Demanding North Sea Horizontal Case History
Success
Greener, M. ,Anderson, C. ,McLellan, W. ,Hough, S.
39329
Rotary Steerable System Improves Reservoir Drilling Efficiency and Wellbore
Placement in the Statfjord Field
Andreassen, E. ,Blikra, H. ,Hjelle, A. ,Kvamme, S.A. ,Haugen, J.
39326
Development of Steerable Ream While Drilling Technology and Its Application in
High Angle Wells in GOM
Cook, John ,Doster, Michael ,Dykstra, Mark ,McDonald, Scott
30462
Application of a Highly Variable Gauge Stabilizer at Wytch Farm to Extend the ERD
Envelope
Odell II, A.C. ,Payne, M.L. ,Cocking, D.A.
27484
A Systems Approach to Downhole Adjustable Stabilizer Design and Application
Underwood, L.D.
27483
Bottomhole Assembly Design and Response on Statfjord CO2 ERD Well
Tjoetta, Helge ,Blikra, Harald ,Hardman, Paul ,Skjelvik, Hakon
20454
Downhole Adjustable Gauge Stabilizer Improves Drilling Efficiency in Directional
Wells
Eddison, A. ,Symons, J.
20.6 DRILLPIPE
67722
Titanium Drill Pipe for Ultra-Deep and Deep Directional Drilling
Jackie E. Smith, R. Brett Chandler, Patrick L. Boster
67764
Cost Effective Composite Drill Pipe: Increased ERD, Lower Cost Deepwater Drilling
and Real-Time LWD/MWD Communication
J.C. Leslie, Jeff Jean, Lee Truong, Hans Neubert, James C. Leslie II
52882
Hardbanding And Its Role in Deepwater Drilling
John G. Mobley
52187
Hardbanding and Its Role in Directional/Horizontal Drilling
John G. Mobley
48888
Composite Drill Pipe for Oil and Gas Eand P Operations
Lou, Alex Y. ,Souder, Wallace W.
39319
Purpose-Built Drillpipe for ERD Drilling
Payne, M.L. ,Bailey, E.I.
2007 – Third Edition
Page 292
Drilling Design and Implementation for Extended Reach and Complex Wells
37648
Replacing 5” and 3½” Inch Drill Pipe With a Single String of 4” Drill Pipe
Mehra, Sachin ,Smith, J.E.
37646
ER Composite Materials Drill Pipe
Hareland, G. ,Lyons, W.C. ,Baldwin, D.D. ,Briggs, G. ,Bratli, R.K.
37353
Drill-Pipe Bending and Fatigue in Rotary Drilling of Horizontal Wells
Wu, Jiang
29349
Designing and Qualifying Drill Strings for ERD Drilling
Hill, T.H. ,Guild, G.J. ,Summers, M.A.
23990
Drillpipe for Horizontal Drilling
Smith, J.E.
23847
Dual-Diameter Drillpipe Offers Advantages in High angle Drilling
McNeely Jr., B.M.
20.7 DOWNHOLE VIBRATION
67697
Improving Drilling Performance by Applying Advanced Dynamics Models
M.W. Dykstra, M. Neubert, J.M. Hanson, M.J. Meiners
59235
Lateral Drillstring Vibrations in Extended-Reach Wells
G. Heisig, M. Neubert
59230
A Stick-slip Analysis Based on Rock/Bit Interaction: Theoretical and Experimental
Contribution
N. Challamel, H. Sellami, E. Chenevez, L. Gossuin
57555
Cost Savings through an Integrated Approach to Drillstring Vibration Control
P.C. Kriesels, W.J.G. Keultjes, P. Dumont, Issam Huneidi, O.O. Owoeye,
R. A. Hartmann
39002
Drill String Vibration: How to Identify and Suppress
Sotomayor, Gabriel P.G. ,Placido, Joao Carlos ,Cunha, J.C
28908
Experience in the Detection and Suppression of Torsional Vibration From Mud
Logging Data
Fear, M.J. ,Abbassian, Fereidoun
28325
Slimhole Vibration Case Study
Murray, P.J. ,Kingman, J.E.E. ,Huddy, R.L. ,Leon, J.G
27538
Performance Drilling: A Practical Solution to Drillstring Vibration
Gallagher, John ,Waller, Mike ,Ruszka, John
26132
Lateral Vibration and Bending Stress of a Joint of Drill Pipe under Self-excited
Whirling
Zhang, Yanglie ,Xiao, Zaiyang
2007 – Third Edition
Page 293
Drilling Design and Implementation for Extended Reach and Complex Wells
25773
Techniques for Successful Application of Dynamic Analysis in the Prevention of
Field-Induced Vibration Damage in MWD Tools
Field, D.J. ,Swarbrick, A.J. ,Haduch, G.A
25689
Benefits of Complementary Surface Vibration and MWD Drilling Mechanics
Measurements in a Horizontal Well
Robson, M.S. ,Fambon, Luc ,Sancho, Jean ,Sutcliffe, B.C.
18652
Case Studies of the Bending Vibration and whirling Motion of Drill Collars
Vandiver, Kim J. ,Nicholson, James W. ,Shyu, Rong-Juin
17273
Measurement of BHA Vibration Using MWD
Close, D.A. ,Owens, S.C. ,MacPherson, J.D.
20.8 CASING WEAR
35666
Reduction of Drill String Torque and Casing Wear in ERD Wells Using Non-Rotating
Drill Pipe Protectors
Moore, N.B. ,Mock, P.W. ,Krueger, R.E.
27532
Recent Advances in Casing Wear Technology
Hall, R.W., Jr. ,Garkasi, Ali ,Deskins, Greg ,Vozniak, John
23903
Drillpipe Protectors Successfully Used To Reduce Casing Wear in Deep, Directional
Well
Schneider, F.F. ,Collins, G.J.
22003
Evaluation of New Tool Joint Hardfacing Material for Extended Connection Life and
Minimum Casing Wear
Marx, C. ,Retelsdorf, H.J. ,Knauf, P.
20.9 SURVEYING
67752
Continuous Direction and Inclination Measurements Revolutionize Real-Time
Directional Drilling Decision-Making
William G. Lesso, Jr., Iain M. Rezmer-Cooper, Minh Chau
63274
Development of a Robust Gyroscopic Orientation Tool for MWD Operations
R.A. Estes, D.M. Epplin
56699
Local Geomagnetic Field Modelling Closes the Gap Between MWD and Gyro
Directional Surveying
Tor Inge Waag, Torgeir Torkildsen, Inge M. Carlsen
37664
A New Rate Gyroscopic Wellbore Survey System Achieves the Accuracy and
Operational Flexibility Needed for Today's Complex Drilling Challenges
Noy, K.A. ,Leonard, J.G.
2007 – Third Edition
Page 294
Drilling Design and Implementation for Extended Reach and Complex Wells
19030
Surveying Techniques With a Solid-State Magnetic Multishot Device
Thorogood, John L. ,Knott, David R.
18051
Instrument Performance Models and Their Application to Directional Surveying
Operations
Thorogood, John L.
17247
Certifying Agencies, Classification and Surveying Societies, Governmental and
Regulatory Agencies, and Standards Writers
Gordon Jr., T.G.
17214
A Field Comparison of the Directional Accuracy of MWD in Comparison With Six
Other Survey Tools
Gabris, P.M. ,Hansen, R.R. ,Bartrina, J
17213
Accurate Surveying: An Operator's Point of View
de Lange, J.I. ,Twilhaar, G.D. Nijen ,Pelgrom, J.J.
16680
A Method To Analyze Directional Surveying Accuracy
Holmes, A.
16679
A Three-Axis Laser Gyro System for Borehole Wireline Surveying
Gibbons, F.L. ,Hense, U.
20.10 CEMENTING IN ERD
62893
Cementation of Horizontal Wellbores
S.A. McPherson
59133
Casing Centralization in Horizontal and Highly Inclined Wellbores
A. Blanco, V. Ciccola, E. Limongi
57560
Successes in Production-Liner Cementing in Oil-Based Mud: A Case Study
Bader Al Khayyat, Jesse A. Morris, Sharifudin Salahudin, Kris Ravi, Juvenal Faria
30514
Plug Cementing: Horizontal to Vertical Conditions
Calvert, D.G , Heatherman, J.F , Griffith, J.E
21970
Keys to a Successful Cement Job for a Horizontal Liner on Statfjord A Platform, Well
A-37A: A Case History
Torsvoll, A. ,Olaussen, S.R. ,Almond, S.W.
17628
Successful High Angle Completions, Cementing, and Drilling's Impact
Fontenot, J.E.
20.11
2007 – Third Edition
Page 295
Drilling Design and Implementation for Extended Reach and Complex Wells
20.12 WELL CONTROL IN HIGH ANGLE WELLBORES
29860
An Advanced Kick Simulator for High Angle and Horizontal Wells - Part II
Vefring, Erlend H. ,Wang, Zhihua ,Rommetveit, Rolv ,Bach, Graham F
29345
An Advanced Kick Simulator for High Angle and Horizontal Wells-Part I
Vefring, E.H. ,Wang, Zhihua ,Gaard, Sigurd ,Bach, G.F.
20.13 COMPLETIONS IN ERD
62952
Using Fibre-Optic Distributed Temperature Measurements to Provide Real-Time
Reservoir Surveillance Data on Wytch Farm Field Horizontal Extended-Reach Wells
G.A. Brown, B. Kennedy, T. Meling,
62041
Unique ESP Completion and Perforation Method Maximizes Production in World
Record Step-Out Well
W.R. Blosser J.E. Davies, P.S. Newberry, K.A. Hardman
59211
World's First Downhole Flow Control Completion of an Extended-Reach, Multilateral
Well at Wytch Farm
H. Gai, J. Davies, P. Newberry, S. Vince, A. Al-Mashgari
57565
Trial of an Expandable Sand Screen to Replace Internal Gravel Packing
Mark van Buren, Léon van den Broek, Calum Whitelaw
48935
Significant Production Enhancement of ER, Prolific Gas Lift Oil Wells -- Case History
of Systematic Problem Resolution
Hahn, D. ,Yu, D. ,Tiss, M. ,Dunn, R. ,Murphy, D.
36622
Pulse Communication Technology Enables Remote Actuation and Manipulation of
Downhole Completion Equipment in ERD and Deepwater Applications
Hopmann, Mark ,Smith, Mike
36580
Flow Diagnosis in an ERD Well at the Wytch Farm Oilfield Using a New Toolstring
Combination Incorporating Novel Production Technology
Lenn, Chris ,Bamforth, Steve ,Jariwala, Hitesh
36579
Advances in the Completion of 8km ERD ESP Wells
Jariwala, H. ,Davies, J. ,Hepburn, Y.
30437
Reservoir Engineering Aspects of the Captain Extended Well Test Appraisal Program
Pallant, M. ,Cohen, D.J. ,Lach, J.R.
30404
Coiled Tubing ERD Technology
Bhalla, Kenneth
29998
A Brief Description of Extended Well Testing (EWT) System
Wu, Si
2007 – Third Edition
Page 296
Drilling Design and Implementation for Extended Reach and Complex Wells
28559
Experience With Completion and Workover of Horizontal and ERD Wells in the
Statfjord Field, North Sea
Kostal, P.L. ,Otvang, Knut
28558
Use of Coiled Tubing During the Wytch Farm Extended-Reach Drilling Project
Summers, Tim ,Larsen, Henrik A. ,Redway, Mark ,Hill, Gardiner
28528
Operating Experience With ESP's and Permanent Downhole Flowmeters in Wytch
Farm Extended-Reach Wells
Brodie, A.D. ,Allan, J.C. ,Hill, Gardiner
2007 – Third Edition
Page 297
2007 – Third Edition
Drilling Design and Implementation for Extended Reach and Complex Wells
OFFSET WELL REVIEW (OWR) FORMAT
SECTION
CONTENT
•
Purpose and scope of the report
•
Include a summary upfront, which highlights the main learnings from the OWR
INTRODUCTION
• Details of the wells selected for review and why
AND SUMMARY
FIELD AND
GEOLOGY
OVERVIEW
•
Overview of the field with a location map
• Formation tops and lithology description (fractures, faults, dips, etc.)
• Discussion of pore pressure, fracture gradient and temperature profile
•
Casing designs (i.e. setting depths, sizes, etc.), wellpath design, mud types etc.
WELL DESIGNS • What were the drivers in designing the wells as they were?
• Did the designs change with time?
DRILLING
•
PERFORMANCE
DRILLING
PARAMETERS
AND PRACTICES
DRILLING
FLUIDS
Summary of time performance.
downtime.
Highlight drilling rates and major areas of
•
Summarize flowrates, rpm, hole cleaning practices, tripping practices, etc.
• Did any hole problems result due to these practices?
•
•
Summarize mud systems that were used, mud properties, and mud weight profiles.
Hole problems, losses, LCM, friction factors, etc.
DIRECTIONAL • BHA’s run
• Directional performance (i.e. build rates, directional trends, etc.)
DRILLING
•
BITS
TORQUE AND
DRAG
Bit record
• Comparison of bit performance (PDC, tri-cone, ROP’s, durability, etc.)
• Bit hydraulics, balling, hard drilling (volcanics, pyrite)
•
Friction factors
• Drilling torque and drag
• Casing running
FORMATION
•
EVALUATION
•
CEMENTING
HAZARDS
Details of wireline, FEWD and coring
Problems encountered (stuck tools, washouts, packoff’s, etc.)
•
Cementing slurry design, casing centralization, operational procedures
• Losses and other problems
•
Losses, stuck pipe, well control, wellbore stability, H2S and CO2
•
APPENDICES
Stick charts (Well name, spud date, RT and water depths, MD, inc, azi, TVD,
Lithology, hole and casing sizes depths, mud type and weight, PIT / LOT, bit type,
ROP and drilling parameters, directional/surveying issues, hole cleaning issues,
stuck pipe, T&D issues, rig issues, casing running, logging issues, etc.)
• Mud logs, calliper logs, chert maps, etc.
2007 – Third Edition
Appendix A - Page 1
Drilling Design and Implementation for Extended Reach and Complex Wells
PRELIMINARY WELL DESIGN (PWD) FORMAT
SECTION
CONTENT
•
Purpose and scope of the report
INTRODUCTION
• Include a summary upfront, which gives an overview of the final PWD and
AND SUMMARY
highlights the key areas of the well (include a well schematic)
FIELD AND
GEOLOGY
OVERVIEW
•
•
•
•
WELL DESIGN
OVERVIEW
•
•
•
•
•
•
•
17½” HOLE
•
•
•
•
•
Overview of the ERD well position in the field
Formation tops and lithology description, highlight target requirements
Discussion of pore pressure, fracture gradient and temperature profile
Surface location (slot allocation, etc.)
Casing design (casing sizes and depths, alternatives)
Wellpath design (alternative build rates and profiles)
Drilling Fluids (OBM, WBM, approximate weights)
Friction Factors for T&D planning (what’s the basis?)
Key Issues and priorities
Directional Strategy (wellpath, general BHA/bit strategy, etc.)
Drill Fluids (mud type and weight range, etc.)
Hydraulics (pressure and ECD, pump capability, drillpipe sizes, etc.)
Torque and drag (tripping weights, buckling, torque, negative weight, etc.)
Power Requirements (backreaming at TD)
Attach T&D and hydraulics plots
•
Casing Running (drag risk plots, flotation, rotation, rollers, other contingencies)
Cementing issues (general cementing and centralization plan)
12¼” HOLE
•
As for 17½” hole
9⅝” CASING
•
As for 13⅜” Casing
8½” HOLE
•
As for 17½” hole
LINER
•
As for 13⅜” Casing
13⅜” CASING
CLEANOUT AND • Cleanout and completion running (drag risk plots, rollers, buckling, etc.)
COMPLETION
EQUIPMENT
•
SPECS
•
INDUSTRY
•
BENCHMARKING •
Required rig equipment (top drive, pumps, drawworks, power, solids control, etc.)
Other equipment required (drillpipe size, drilling tools etc.)
Comparison with other relevant ERD wells to establish feasibility
Compare well design and rig capabilities
TIME AND COST • ± 40% time and cost estimate based on Preliminary Well Design
ESTIMATES
2007 – Third Edition
Appendix A - Page 2
Drilling Design and Implementation for Extended Reach and Complex Wells
DETAILED WELL DESIGN (DWD) FORMAT
SECTION
FIELD AND
GEOLOGY
OVERVIEW
CONTENT
•
•
•
•
WELL DESIGN
OVERVIEW
•
•
•
•
•
•
•
17½” HOLE
•
•
•
Key issues in each hole section
Reservoir schematics
Graphs of pore pressure, fracture gradient and temperature profile
Wellpath Summary (KOP, build rates, tangent angles, collision avoidance etc.)
Casing Summary (casing sizes, depths, weight and grade, summary of main drivers)
Cementing Summary (cement tops, slurry design, special requirements, etc.)
Drilling Fluids Summary (mud type and weight, priorities, properties, etc.)
Bit and BHA Summary (listing of BHA’s and components, contingencies, etc.)
Key Issues (list the key issues and main priorities in this section)
Overview of Solutions (discuss solutions to the key issues)
Detailed Procedure Outline (step by step procedure of how the section is to be
completed, include hole cleaning and tripping guidelines, etc.)
Special Notes and Offset Calibration (other issues, provide calibration data for the
section to show where it has been done before)
Attach T&D and hydraulics plots
•
Key Issues (list the key issues in this section)
Overview of Solutions (discuss solutions to the key issues)
Detailed Procedure Outline (step by step procedure: prior to casing run, casing run
and cementing)
Special Notes and Offset Calibration (other issues, provide calibration data for the
section to show where it has been done before)
Attach T&D and hydraulics plots
12¼” HOLE
•
As for 17½” hole
9⅝” CASING
•
As for 13⅜” Casing
8½” HOLE
•
As for 17½” hole
LINER
•
As for 13⅜” Casing
•
•
13⅜” CASING
•
CLEANOUT AND • As for 13⅜” casing, but procedure outline will most likely not be very detailed as
the cleanout and completion is usually not finalized until later in the well.
COMPLETION
EQUIPMENT
•
SPECS
•
Final equipment specs (top drive, pumps, drawworks, power, solids control, etc.)
Other equipment specs (drillpipe size, casing, directional drilling tools etc.)
TIME AND COST • ± 20% time and cost estimate based on Detailed Well Design
ESTIMATES
2007 – Third Edition
Appendix A - Page 3
2007 – Third Edition
2007 – Third Edition
2007 – Third Edition
2007 – Third Edition
2007 – Third Edition
2007 – Third Edition
2007 – Third Edition
2007 – Third Edition
2007 – Third Edition
2007 – Third Edition
2007 – Third Edition
2007 – Third Edition
2007 – Third Edition
2007 – Third Edition
2007 – Third Edition
2007 – Third Edition
2007 – Third Edition
2007 – Third Edition
2007 – Third Edition