Casing and Cementing.pdf_Drilling-books.
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About This Presentation
Libro de cañerías y cementacion de la industria petrolera y de perforación
Slide Content
ROTARY DRILLING SERIES
Unit I: The Rig and Its Maintenance
Lesson 1:
Lesson 2:
Lesson 3:
Lesson 4:
Lesson 5:
Lesson 6:
Lesson 7:
Lesson 8:
Lesson 9:
Lesson 10:
The Rotary Rig and Its Components
The Bit
Drill String and Drill Collars
Rotary, Kelly, Swivel, Tongs, and Top Drive
The Blocks and Drilling Line
The Drawworks and the Compound
Drilling Fluids,
Mud Pumps, and Conditioning Equipment
Diesel Engines and Electric Power
The Auxiliaries
Safety
on the Rig
Unit II: Norm.al Drilling Operations
Lesson 1:
Lesson 2:
Lesson 3:
Lesson 4:
Lesson 5:
Making Hole
Drilling Fluids
Drilling a Straight Hole
Casing and Cementing
Testing and Completing
Unit ill: Nonroutine Operations
Lesson r:
Lesson 2:
Lesson 3:
Controlled Directional Drilling
Open-Hole Fishing
Blowout Prevention
Unit IV: Man Management and Rig Management
Unit
V: Offshore Technology
Lesson 1: Wind, Waves, and Weather
Lesson
2: Spread Mooring Systems
Lesson
3: Buoyancy, Stability, and Trim
Lesson
4: Jacking Systems and Rig Moving Procedures
Lesson
5: Diving and Equipment
Lesson
6: Vessel Inspection and Maintenance
Lesson
7: Helicopter Safety
Lesson
8: Orientation for Offshore Crane Operations
Lesson
9: Life Offshore
Lesson
Io: Marine Riser Systems and Subsea Blowout Preventers
.,...,:",.,.•~~~
f~};~ACIO~~
.
ROTARY DRILLING SE ,
Casing and
Cementing
Unit II, Lesson 4
Third Edition
/UKiversiJad . f Jcchn~! de Salta
B B B LB 0·1 .. ~ C A
N•. INT,
·----------
f~CIIA DE INGRESO
-------
'flf.OCEDENCIA ...... ________ _
nmICACION _________ _
mmaJA..ii..,mr.fe.'5:!!.!!--.• "~
UN Sa.
INVENTARIO
PATRIMONIO
Orden N°.
FEIEX.
By William E. Jackson
Published by
PETROLEUM EXTENSION SERVICE
THE UNIVERSITY OF TEXAS AT AUSTIN
Division of Continuing & Innovative Education
Austin, Texas
Originally produced by
INTERNATIONAL ASSOCIATION
OF DRILLING CONTRACTORS
Houston, Texas
2001
Unit I: The Rig and Its Maintenance
Lesson 1:
Lesson 2:
Lesson 3:
Lesson 4:
Lesson 5:
Lesson 6:
Lesson 7:
Lesson 8:
Lesson 9:
Lesson 10:
The Rotary Rig and Its Components
The Bit
Drill String and Drill Collars
Rotary, Kelly, Swivel, Tongs, and Top Drive
The Blocks and Drilling Line
The Drawworks and the Compound
Drilling Fluids,
Mud Pumps, and Conditioning Equipment
Diesel Engines and Electric Power
The Auxiliaries
Safety
on the Rig
Unit II: Norm.al Drilling Operations
Lesson 1:
Lesson 2:
Lesson 3:
Lesson 4:
Lesson 5:
Making Hole
Drilling Fluids
Drilling a Straight Hole
Casing and Cementing
Testing and Completing
Unit ill: Nonroutine Operations
Lesson r:
Lesson 2:
Lesson 3:
Controlled Directional Drilling
Open-Hole Fishing
Blowout Prevention
Unit IV: Man Management and Rig Management
Unit
V: Offshore Technology
Lesson 1: Wind, Waves, and Weather
Lesson
2: Spread Mooring Systems
Lesson
3: Buoyancy, Stability, and Trim
Lesson
4: Jacking Systems and Rig Moving Procedures
Lesson
5: Diving and Equipment
Lesson
6: Vessel Inspection and Maintenance
Lesson
7: Helicopter Safety
Lesson
8: Orientation for Offshore Crane Operations
Lesson
9: Life Offshore
Lesson
Io: Marine Riser Systems and Subsea Blowout Preventers
.,...,:",.,.•~~~
f~};~ACIO~~
.
ROTARY DRILLING SE ,
Casing and
Cementing
Unit II, Lesson 4
Third Edition
/UKiversiJad . f Jcchn~! de Salta
B B B LB 0·1 .. ~ C A
N•. INT,
·----------
f~CIIA DE INGRESO
-------
'flf.OCEDENCIA ...... ________ _
nmICACION _________ _
mmaJA..ii..,mr.fe.'5:!!.!!--.• "~
UN Sa.
INVENTARIO
PATRIMONIO
Orden N°.
FEIEX.
By William E. Jackson
Published by
PETROLEUM EXTENSION SERVICE
THE UNIVERSITY OF TEXAS AT AUSTIN
Division of Continuing & Innovative Education
Austin, Texas
Originally produced by
INTERNATIONAL ASSOCIATION
OF DRILLING CONTRACTORS
Houston, Texas
2001
Library of Congress Cataloging-in-Publication Data
Feder,Judy, 1950-
Casing and cementing / by Judy Feder. -3rd ed.
p. cm. -(Rotary drilling series; unit
2, lesson 4)
ISBN 0-88698-191-3 (alk. paper)
1. Oil well casing. 2. Oil well cementing. I. Title. II. Series.
TN871.22.F44 2001
622'.3381-dc21 2001000765
©2001 by
The University of Texas at Austin
All rights reserved
First Edition published 1968. Second Edition 1982.
Third Edition 2001. Third Impression 2011
Printed in the United States
of America
CIP
This book or parts thereof may not be reproduced in any form without
permission
of Petroleum Extension Service, The University of Texas at
Austin.
Brand names, company names, trademarks,
or other identifying symbols
appearing
in illustrations and/ or text are used for educational purposes only
and do
not constitute an endorsement by the author or the publisher.
Catalog no. 2.20430
ISBN 0-88698-191-3
No state tax funds were used to publish this book.
The University of Texas at Austin is an equal opportunity employer.
Figures
Tables V
VIII
Foreword vn
Acknowledgments 1x
Units of Measurement x
Introduction 1
Casing 3
Casing Strings 4
Types
of Casing 5
Conductor Pipe 6
Surface Casing
7
Intermediate Casing 7
Liner String 8
Production Casing Io
To Summarize 1 1
String Design 12
Design Criteria: Primary Forces 12
Design Criteria: Secondary Forces 15
Design Criteria: Downhole Environment
To Summarize 16
Setting
the Casing 1 7
Preparation 17
Running the Casing 2 2
Stabbing, Making Up, and Lowering 2 7
Landing 32
API Standards 3 6
To Summarize 41
Casing Threads and Couplings 42
Proprietary or Premium Connections 45
To Summarize 48
Changing Technology 49
Cementing 51
Primary Cementing Basics 5 2
To Summarize 54
Oilwell Cements and Additives 5 5
Additives 5 7
Special Cements 62
To Summarize 64
Mixing 66
Water Quality 66
Water Quantity 66
Types
of Mixers 67
Contents
III
Feder,Judy, 1950-
Casing and cementing / by Judy Feder. -3rd ed.
p. cm. -(Rotary drilling series; unit
2, lesson 4)
ISBN 0-88698-191-3 (alk. paper)
1. Oil well casing. 2. Oil well cementing. I. Title. II. Series.
TN871.22.F44 2001
622'.3381-dc21 2001000765
©2001 by
The University of Texas at Austin
All rights reserved
First Edition published 1968. Second Edition 1982.
Third Edition 2001. Third Impression 2011
Printed in the United States
of America
CIP
This book or parts thereof may not be reproduced in any form without
permission
of Petroleum Extension Service, The University of Texas at
Austin.
Brand names, company names, trademarks,
or other identifying symbols
appearing
in illustrations and/ or text are used for educational purposes only
and do
not constitute an endorsement by the author or the publisher.
Catalog no. 2.20430
ISBN 0-88698-191-3
No state tax funds were used to publish this book.
The University of Texas at Austin is an equal opportunity employer.
Figures
Tables V
VIII
Foreword vn
Acknowledgments 1x
Units of Measurement x
Introduction 1
Casing 3
Casing Strings 4
Types
of Casing 5
Conductor Pipe 6
Surface Casing
7
Intermediate Casing 7
Liner String 8
Production Casing Io
To Summarize 1 1
String Design 12
Design Criteria: Primary Forces 12
Design Criteria: Secondary Forces 15
Design Criteria: Downhole Environment
To Summarize 16
Setting
the Casing 1 7
Preparation 17
Running the Casing 2 2
Stabbing, Making Up, and Lowering 2 7
Landing 32
API Standards 3 6
To Summarize 41
Casing Threads and Couplings 42
Proprietary or Premium Connections 45
To Summarize 48
Changing Technology 49
Cementing 51
Primary Cementing Basics 5 2
To Summarize 54
Oilwell Cements and Additives 5 5
Additives 5 7
Special Cements 62
To Summarize 64
Mixing 66
Water Quality 66
Water Quantity 66
Types
of Mixers 67
Contents
III
Pumping 70
Displacing the Drilling Mud 70
Pumping the Cement 71
Casing Accessories 7 3
To Summarize
79
Cement Volume Requirements 81
Calculating Open-Hole Capacity 82
To Summarize 8 3
Considerations After Cementing 84
Waiting on Cement 84
Checking the Cement Top 8
5
Pressure Testing 8 7
To Summarize
87
Glossary 89
Review Questions IOI
Answers 109
1. These joints of casing are ready to be run into the well, where
they will serve at least seven important functions. 3
2. Most wells require several strings of casing, each of which serves
a specific purpose important to the completion
of the well. 5
3. Conductor pipe in offshore operations extends the "hole" from
the seafloor, up through the water, to a point in the air just below
the drilling deck. 6
4-A liner is a relatively short string of casing that extends from the
bottom
of the open hole, up into another string. 8
5. Liner strings are nearly always suspended from the upper string
by means
of a liner hanger. 8
6. A tie-back string from the liner to the surface may be used if an
existing casing string has been weakened by drilling. 9
7. Whether on or offshore, preventive maintenance is key to pro-
tecting casing
as it is prepared to run into the well. 17
8. A thread protector should be in place any time a joint of casing is
handled. 18
9. Casing resting on stringers 19
10. Before casing is run, threads are inspected for damage that may
have occurred during shipping and racking.
20
r 1. Pipe is tallied three times: when it is shipped, when it arrives at
location, and after the casing string has been run.
22
12. Running casing 2 3
13. Stabbing casing 24
14. Special bucket and sling arrangement raise a joint of casing to
the rig floor
2 7
1 5. Thread compound may be applied over the entire surface of the
casing threads just before stabbing.
28
16. Hydraulic power tongs are placed around a joint of casing to
make
it up to a predetermined torque. 29
17. Casing elevators and casing spider support the casing as it is be-
ing lowered into the well. 3
1
18. Landing the casing involves transferring the casing string weight
to the wellhead, usually with a casing hanger that seats in the
casinghead and seals the annulus between the outer and inner
strings.
32
19. Downhole casing hangers are used to relieve some of the load on
the casinghead. 3 5
20. Casing with a coupling (A) and a threaded end (B) 42
2.1. Examples of API-threaded connections 4 3
22. Examples of premium-threaded connections 45
2 3. Halliburton cementing equipment from the 1920s 51
Figures
V
Displacing the Drilling Mud 70
Pumping the Cement 71
Casing Accessories 7 3
To Summarize
79
Cement Volume Requirements 81
Calculating Open-Hole Capacity 82
To Summarize 8 3
Considerations After Cementing 84
Waiting on Cement 84
Checking the Cement Top 8
5
Pressure Testing 8 7
To Summarize
87
Glossary 89
Review Questions IOI
Answers 109
1. These joints of casing are ready to be run into the well, where
they will serve at least seven important functions. 3
2. Most wells require several strings of casing, each of which serves
a specific purpose important to the completion
of the well. 5
3. Conductor pipe in offshore operations extends the "hole" from
the seafloor, up through the water, to a point in the air just below
the drilling deck. 6
4-A liner is a relatively short string of casing that extends from the
bottom
of the open hole, up into another string. 8
5. Liner strings are nearly always suspended from the upper string
by means
of a liner hanger. 8
6. A tie-back string from the liner to the surface may be used if an
existing casing string has been weakened by drilling. 9
7. Whether on or offshore, preventive maintenance is key to pro-
tecting casing
as it is prepared to run into the well. 17
8. A thread protector should be in place any time a joint of casing is
handled. 18
9. Casing resting on stringers 19
10. Before casing is run, threads are inspected for damage that may
have occurred during shipping and racking.
20
r 1. Pipe is tallied three times: when it is shipped, when it arrives at
location, and after the casing string has been run.
22
12. Running casing 2 3
13. Stabbing casing 24
14. Special bucket and sling arrangement raise a joint of casing to
the rig floor
2 7
1 5. Thread compound may be applied over the entire surface of the
casing threads just before stabbing.
28
16. Hydraulic power tongs are placed around a joint of casing to
make
it up to a predetermined torque. 29
17. Casing elevators and casing spider support the casing as it is be-
ing lowered into the well. 3
1
18. Landing the casing involves transferring the casing string weight
to the wellhead, usually with a casing hanger that seats in the
casinghead and seals the annulus between the outer and inner
strings.
32
19. Downhole casing hangers are used to relieve some of the load on
the casinghead. 3 5
20. Casing with a coupling (A) and a threaded end (B) 42
2.1. Examples of API-threaded connections 4 3
22. Examples of premium-threaded connections 45
2 3. Halliburton cementing equipment from the 1920s 51
Figures
V
Tables
VI
24-Primary cementing is performed immediately after the casing
has been run in the hole, to seal and separate each zone, and to
protect the pipe. 5 3
2 5. Cementing trucks transport dry cement blends to the well
site. 5 5
26. High-energy recirculating mixers provide thoroughly mixed slur-
ries at a wide range
of densities and rates. 67
2 7. Internal operation of a recirculating mixer 68
2 8. The demands and expense associated with offshore operations
have led to the development
of sophisticated, high-tech mixing
and data acquisition systems.
68
29. Internal operation of a batch mixer 69
30. A primary cementing job 71
3 1. Wiper plugs are placed in the cementing head to wipe mud
off the inside
of the casing and keep it separated from the ce-
ment.
72
32. A typical casing string with accessories 73
33. A guide shoe 74
34-An automatic fill-up shoe 74
3
5. A float collar prevents backflow of cement during the cementing
operation.
75
36. Multistage cementing devices are used to cement two or more
separate sections behind a casing string.
76
3 7. Bow (A) and solid body (B) centralizers 77
3 8. Scratchers (A) and wipers (B) help remove filter cake and gelled
mud from the well
as the casing is run. 78
3 9. Temperature survey showing the top of cement outside the cas-
ing
85
1. Fluid Displacement of Casing 2 5
2. Volume Gains in the Mud Pit from Casing Displacement 2 5
3. API Length Ranges of Casing 3 6
4. Specification for Casing and Tubing-AP! Casing List 3 7
5. Specification for Casing and Tubing-Tensile and Hardness
Requirements
39
6. Distance Between Plates for Electric Weld Flattening
Tests
40
7. Effects of Some Additives on the Physical Properties of
Cement 58
Foreword
F
or many years, the Rotary Drilling Series has oriented new
personnel and further assisted experienced hands in the rotary
drilling industry.
As the industry changes, so must the manuals in
this series reflect those changes.
The revisions to both the text and illustrations are exten
sive.
In addition, the layout has been "modernized" to make the
information easy to get; the study questions have been rewritten;
and each major section has been summarized to provide a handy
comprehension check for the reader.
PETEX wishes to thank industry reviewers-and our readers
for invaluable assistance in the revision of the Rotary Drilling Series.
Casing and Cementing introduces rig crew members to the
concept
of casing string design and the procedures for properly
handling pipe while
it is on the rack, being picked up, made up
into a string, and cemented in the hole.
This manual covers types
of pipe usually employed, string design considerations, running
techniques, cementing procedures, casing liner use, liner setting,
and cement strength determination.
Although every effort
was made-to ensure accuracy, this
manual
is intended only as a training aid; thus, nothing in it should
be construed
as approval or disapproval of any specific practice
or product.
Ron Baker
VII
VI
24-Primary cementing is performed immediately after the casing
has been run in the hole, to seal and separate each zone, and to
protect the pipe. 5 3
2 5. Cementing trucks transport dry cement blends to the well
site. 5 5
26. High-energy recirculating mixers provide thoroughly mixed slur-
ries at a wide range
of densities and rates. 67
2 7. Internal operation of a recirculating mixer 68
2 8. The demands and expense associated with offshore operations
have led to the development
of sophisticated, high-tech mixing
and data acquisition systems.
68
29. Internal operation of a batch mixer 69
30. A primary cementing job 71
3 1. Wiper plugs are placed in the cementing head to wipe mud
off the inside
of the casing and keep it separated from the ce-
ment.
72
32. A typical casing string with accessories 73
33. A guide shoe 74
34-An automatic fill-up shoe 74
3
5. A float collar prevents backflow of cement during the cementing
operation.
75
36. Multistage cementing devices are used to cement two or more
separate sections behind a casing string.
76
3 7. Bow (A) and solid body (B) centralizers 77
3 8. Scratchers (A) and wipers (B) help remove filter cake and gelled
mud from the well
as the casing is run. 78
3 9. Temperature survey showing the top of cement outside the cas-
ing
85
1. Fluid Displacement of Casing 2 5
2. Volume Gains in the Mud Pit from Casing Displacement 2 5
3. API Length Ranges of Casing 3 6
4. Specification for Casing and Tubing-AP! Casing List 3 7
5. Specification for Casing and Tubing-Tensile and Hardness
Requirements
39
6. Distance Between Plates for Electric Weld Flattening
Tests
40
7. Effects of Some Additives on the Physical Properties of
Cement 58
Foreword
F
or many years, the Rotary Drilling Series has oriented new
personnel and further assisted experienced hands in the rotary
drilling industry.
As the industry changes, so must the manuals in
this series reflect those changes.
The revisions to both the text and illustrations are exten
sive.
In addition, the layout has been "modernized" to make the
information easy to get; the study questions have been rewritten;
and each major section has been summarized to provide a handy
comprehension check for the reader.
PETEX wishes to thank industry reviewers-and our readers
for invaluable assistance in the revision of the Rotary Drilling Series.
Casing and Cementing introduces rig crew members to the
concept
of casing string design and the procedures for properly
handling pipe while
it is on the rack, being picked up, made up
into a string, and cemented in the hole.
This manual covers types
of pipe usually employed, string design considerations, running
techniques, cementing procedures, casing liner use, liner setting,
and cement strength determination.
Although every effort
was made-to ensure accuracy, this
manual
is intended only as a training aid; thus, nothing in it should
be construed
as approval or disapproval of any specific practice
or product.
Ron Baker
VII
Acknowledgments
...
...
...
T
he author expresses a sincere appreciation to the numerous
people who have helped with the preparation
of this edition
of Casing and Cementing. In particular, special thanks go to Rick
Covington
of Halliburton Energy Services, and Ed Banker of
Marubeni Tubulars, Inc. Their time and patience reviewing the
manuscript and updating information
was invaluable.
Thanks also go to Monte Montague, Betsy Mott, and Dave
Rees
of Halliburton, as well as Anjali Prasad andJohn Greenip of
Hydril, for locating and providing illustrations and photographs
for use in the manual.
John Greenip was most helpful in providing
assistance in reviewing the text.
All who have contributed time, thought, and effort into this
book have worked to make this new edition a success in providing
the most complete information about casing and cementing.
IX
...
...
...
T
he author expresses a sincere appreciation to the numerous
people who have helped with the preparation
of this edition
of Casing and Cementing. In particular, special thanks go to Rick
Covington
of Halliburton Energy Services, and Ed Banker of
Marubeni Tubulars, Inc. Their time and patience reviewing the
manuscript and updating information
was invaluable.
Thanks also go to Monte Montague, Betsy Mott, and Dave
Rees
of Halliburton, as well as Anjali Prasad andJohn Greenip of
Hydril, for locating and providing illustrations and photographs
for use in the manual.
John Greenip was most helpful in providing
assistance in reviewing the text.
All who have contributed time, thought, and effort into this
book have worked to make this new edition a success in providing
the most complete information about casing and cementing.
IX
X
Units of Measurement
T
hroughout the world, two systems of measurement dominate:
the English system and the metric system. Today, the United
States
is almost the only country that employs the English sys
tem.
The English system uses the pound as the unit of weight, the
foot
as the unit of length, and the gallon as the unit of capacity. In
the English system, for example, 1 foot equals 1 2 inches, I yard
equals 36 inches, and
I mile equals 5,280 feet or 1,760 yards.
The metric system uses the gram as the unit of weight, the
metre
as the unit of length, and the litre as the unit of capacity.
In the metric system, for example, I metre equals rn decimetres,
mo centimetres, or I ,ooo millimetres. A kilometre equals I ,ooo
metres. The metric system, unlike the English system, uses a
base
of rn; thus, it is easy to convert from one unit to another. To
convert from one unit to another in the English system, you must
memorize
or look up the values.
In the late 1970s, the Eleventh General Conference on Weights
and Measures described and adopted the Systeme International
(SI) d'Unites. Conference participants based the SI system
on
the metric system and designed it as an international standard of
measurement.
The Rotary Drilling Series gives both English and SI units.
And because the SI system employs the British spelling
of many of
the terms, the book follows those spelling rules as well. The unit
of length, for example, is metre, not meter. (Note, however, that
the unit
of weight is gram, not gramme.)
To aid U.S. readers in making and understanding the conver
sion
tC? the SI system, we include the following table.
English-Units-to-SI-Units Conversion Factors
Quantity
or Property
Length,
depth,
or height
English Units
inches (in.)
feet (ft)
yards (yd)
miles (mi)
Multiply
English Units By
25·4
2·54
0.3048
0.9144
1609.344
1.61
Hole and pipe diameters, bit size inches (in.)
Drilling rate
Weight on bit
Nozzle size
Volume
Pump output
and flow rate
Pressure
Temperature
Thermal gradient
Mass (weight)
Mud weight
Pressure gradient
Funnel viscosity
Yield
point
Gel strength
Filter cake thickness
Power
Area
Drilling line wear
Torque
feet per hour (ft/h)
pounds (lb)
3
mds of an inch
barrels (bbl)
gallons
per stroke (gal/stroke)
ounces (oz)
cubic inches (in.
3
)
cubic feet (ft
3
)
quarts (qt)
gallons (gal)
gallons (gal)
pounds
per barrel (lb/bbl)
barrels
per ton (bbl/tn)
gallons
per minute (gpm)
gallons
per hour (gph)
barrels
per stroke (bbl/stroke)
barrels
per minute (bbl/min)
pounds
per square inch (psi)
degrees
Fahrenheit (°F)
1
°F per 60 feet
ounces (oz)
pounds (lb)
tons (tn)
pounds
per foot (lb/ft)
pounds
per gallon (ppg)
pounds
per cubic foot (lb/ft
3
)
pounds per square inch
per foot (psi/ft)
o.8
0.159
159
0.00379
29·57
16.387
28.3169
0.0283
o.9464
3.7854
0.00379
2.895
0.175
0.00379
o.oo379
0.159
0.159
6.895
0.006895
OF -32
I.8
28.35
453.59
0-4536
0.9072
1.488
119.82
16.0
22.621
seconds
per quart (s/qt) 1.057
pounds
per mo square feet (lb/ mo ft
2
)
0.48
pounds
per mo square feet (lb/mo ft2) 0-48
3
mds of an inch o.8
horsepower (hp) 0.75
square inches (in.
2
)
6.45
square feet (ft
2
)
0.0929
square yards (yd
2
)
0.8361
square miles (mi
2
)
2.59
acre (ac) 0-40
ton-miles
(tn•mi)
foot-pounds (ft• lb)
14·3
17
1.459
To Obtain
These SI Units
millimetres (mm)
centimetres ( cm)
metres (m)
metres (m)
metres (m)
kilometres (km)
millimetres (mm)
metres
per hour (m/h)
decanewtons (
dN)
millimetres (mm)
cubic metres (m
3
)
litres (L)
cubic metres
per stroke (m
3
/stroke)
millilitres (mL)
cubic centimetres ( cm
3
)
litres (L)
cubic metres (m
3
)
litres (L)
litres (L)
cubic metres
(m
3
)
kilograms per cubic metre (kg/m
3
)
cubic metres per tonne (m
3
/t)
cubic metres per minute (m
3
/min)
cubic metres
per hour (m
3
/h)
cubic metres per stroke (m
3
/stroke)
cubic metres
per minute (m
3
/min)
kilopascals (kPa)
megapascals (MPa)
degrees Celsius (
0
C)
1°C per 33 metres
grams (g)
grams (g)
kilograms (kg)
tonnes (t)
kilograms
per metre (kg/m)
kilograms
per cubic metre (kg/m
3
)
kilograms per cubic metre (kg/m
3
)
kilopascals per metre (kPa/m)
seconds
per litre (s/L)
pascals (Pa)
pascals (Pa)
millimetres (mm)
kilowatts (kW)
square centimetres (
cm
2
)
square metres (m
2
)
square metres (m
2
)
square kilometres (km
2
)
hectare (ha)
megajoules
(MJ)
tonne-kilometres (t•km)
newton metres (N•m)
XI
Units of Measurement
T
hroughout the world, two systems of measurement dominate:
the English system and the metric system. Today, the United
States
is almost the only country that employs the English sys
tem.
The English system uses the pound as the unit of weight, the
foot
as the unit of length, and the gallon as the unit of capacity. In
the English system, for example, 1 foot equals 1 2 inches, I yard
equals 36 inches, and
I mile equals 5,280 feet or 1,760 yards.
The metric system uses the gram as the unit of weight, the
metre
as the unit of length, and the litre as the unit of capacity.
In the metric system, for example, I metre equals rn decimetres,
mo centimetres, or I ,ooo millimetres. A kilometre equals I ,ooo
metres. The metric system, unlike the English system, uses a
base
of rn; thus, it is easy to convert from one unit to another. To
convert from one unit to another in the English system, you must
memorize
or look up the values.
In the late 1970s, the Eleventh General Conference on Weights
and Measures described and adopted the Systeme International
(SI) d'Unites. Conference participants based the SI system
on
the metric system and designed it as an international standard of
measurement.
The Rotary Drilling Series gives both English and SI units.
And because the SI system employs the British spelling
of many of
the terms, the book follows those spelling rules as well. The unit
of length, for example, is metre, not meter. (Note, however, that
the unit
of weight is gram, not gramme.)
To aid U.S. readers in making and understanding the conver
sion
tC? the SI system, we include the following table.
English-Units-to-SI-Units Conversion Factors
Quantity
or Property
Length,
depth,
or height
English Units
inches (in.)
feet (ft)
yards (yd)
miles (mi)
Multiply
English Units By
25·4
2·54
0.3048
0.9144
1609.344
1.61
Hole and pipe diameters, bit size inches (in.)
Drilling rate
Weight on bit
Nozzle size
Volume
Pump output
and flow rate
Pressure
Temperature
Thermal gradient
Mass (weight)
Mud weight
Pressure gradient
Funnel viscosity
Yield
point
Gel strength
Filter cake thickness
Power
Area
Drilling line wear
Torque
feet per hour (ft/h)
pounds (lb)
3
mds of an inch
barrels (bbl)
gallons
per stroke (gal/stroke)
ounces (oz)
cubic inches (in.
3
)
cubic feet (ft
3
)
quarts (qt)
gallons (gal)
gallons (gal)
pounds
per barrel (lb/bbl)
barrels
per ton (bbl/tn)
gallons
per minute (gpm)
gallons
per hour (gph)
barrels
per stroke (bbl/stroke)
barrels
per minute (bbl/min)
pounds
per square inch (psi)
degrees
Fahrenheit (°F)
1
°F per 60 feet
ounces (oz)
pounds (lb)
tons (tn)
pounds
per foot (lb/ft)
pounds
per gallon (ppg)
pounds
per cubic foot (lb/ft
3
)
pounds per square inch
per foot (psi/ft)
o.8
0.159
159
0.00379
29·57
16.387
28.3169
0.0283
o.9464
3.7854
0.00379
2.895
0.175
0.00379
o.oo379
0.159
0.159
6.895
0.006895
OF -32
I.8
28.35
453.59
0-4536
0.9072
1.488
119.82
16.0
22.621
seconds
per quart (s/qt) 1.057
pounds
per mo square feet (lb/ mo ft
2
)
0.48
pounds
per mo square feet (lb/mo ft2) 0-48
3
mds of an inch o.8
horsepower (hp) 0.75
square inches (in.
2
)
6.45
square feet (ft
2
)
0.0929
square yards (yd
2
)
0.8361
square miles (mi
2
)
2.59
acre (ac) 0-40
ton-miles
(tn•mi)
foot-pounds (ft• lb)
14·3
17
1.459
To Obtain
These SI Units
millimetres (mm)
centimetres ( cm)
metres (m)
metres (m)
metres (m)
kilometres (km)
millimetres (mm)
metres
per hour (m/h)
decanewtons (
dN)
millimetres (mm)
cubic metres (m
3
)
litres (L)
cubic metres
per stroke (m
3
/stroke)
millilitres (mL)
cubic centimetres ( cm
3
)
litres (L)
cubic metres (m
3
)
litres (L)
litres (L)
cubic metres
(m
3
)
kilograms per cubic metre (kg/m
3
)
cubic metres per tonne (m
3
/t)
cubic metres per minute (m
3
/min)
cubic metres
per hour (m
3
/h)
cubic metres per stroke (m
3
/stroke)
cubic metres
per minute (m
3
/min)
kilopascals (kPa)
megapascals (MPa)
degrees Celsius (
0
C)
1°C per 33 metres
grams (g)
grams (g)
kilograms (kg)
tonnes (t)
kilograms
per metre (kg/m)
kilograms
per cubic metre (kg/m
3
)
kilograms per cubic metre (kg/m
3
)
kilopascals per metre (kPa/m)
seconds
per litre (s/L)
pascals (Pa)
pascals (Pa)
millimetres (mm)
kilowatts (kW)
square centimetres (
cm
2
)
square metres (m
2
)
square metres (m
2
)
square kilometres (km
2
)
hectare (ha)
megajoules
(MJ)
tonne-kilometres (t•km)
newton metres (N•m)
XI
/
Introduction
C
asing and cementing are essential to drilling oil and gas wells.
Lining a hole with casing keeps
it from caving in after it is
drilled, sealing the wellbore from encroaching fluids and gasses.
Cementing the casing in place attaches
it firmly to the well bore wall
and stabilizes the hole. Casing and cement
both serve additional,
important functions
in the well. These functions will be addressed
later in this manual.
Casing and cementing procedures have grown more sophis
ticated in recent years
as the search for new hydrocarbon-bearing
reservoirs takes wells deeper and into more hostile environments
(i.e., deep water, high pressures and temperatures, and sour gases).
Engineers and metallurgists work continually to refine casing
or
cementing designs and procedures to handle the challenges as
sociated with offshore and remote locations, extreme depths, and
severe conditions.
During the days of cable-tool drilling, numerous strings of
casing had to be set as a well was drilled. With the advent of rotary
drilling came better quality muds with greater ability to control
well pressures.
As a result, much more open hole could be drilled.
Casing is now generally set to serve a specific purpose and
is neither
arbitrary
nor compulsory for any hole conditions.
I
Introduction
C
asing and cementing are essential to drilling oil and gas wells.
Lining a hole with casing keeps
it from caving in after it is
drilled, sealing the wellbore from encroaching fluids and gasses.
Cementing the casing in place attaches
it firmly to the well bore wall
and stabilizes the hole. Casing and cement
both serve additional,
important functions
in the well. These functions will be addressed
later in this manual.
Casing and cementing procedures have grown more sophis
ticated in recent years
as the search for new hydrocarbon-bearing
reservoirs takes wells deeper and into more hostile environments
(i.e., deep water, high pressures and temperatures, and sour gases).
Engineers and metallurgists work continually to refine casing
or
cementing designs and procedures to handle the challenges as
sociated with offshore and remote locations, extreme depths, and
severe conditions.
During the days of cable-tool drilling, numerous strings of
casing had to be set as a well was drilled. With the advent of rotary
drilling came better quality muds with greater ability to control
well pressures.
As a result, much more open hole could be drilled.
Casing is now generally set to serve a specific purpose and
is neither
arbitrary
nor compulsory for any hole conditions.
I
Casing
C
asing and tubing account for r 5 to 20 percent of the com
pleted cost
of a well-often the greatest single item of expense
on the well. Failure
of casing or tubing results in expensive rework
and may lead to loss
of the well, or worse, loss of life. Selecting
casing sizes, weights, grades, and types
of threaded connections for
a given situation presents an engineering and economic challenge
of considerable importance.
Casing is strong steel pipe used in an oil or gas well to ensure
a pressure-tight connection from the surface to the oil
or gas
reservoir. Casing serves
at least seven important functions in the
well (fig. r):
r.
It prevents the hole from caving in or washing out.
2. It protects freshwater sands from contamination by fluids
from lower zones.
3. It keeps water out of the producing formation.
4. It confines production to the wellbore.
Figure 1. These joints of casing are ready to be run into the well,
where they will serve at least seven important functions.
3
C
asing and tubing account for r 5 to 20 percent of the com
pleted cost
of a well-often the greatest single item of expense
on the well. Failure
of casing or tubing results in expensive rework
and may lead to loss
of the well, or worse, loss of life. Selecting
casing sizes, weights, grades, and types
of threaded connections for
a given situation presents an engineering and economic challenge
of considerable importance.
Casing is strong steel pipe used in an oil or gas well to ensure
a pressure-tight connection from the surface to the oil
or gas
reservoir. Casing serves
at least seven important functions in the
well (fig. r):
r.
It prevents the hole from caving in or washing out.
2. It protects freshwater sands from contamination by fluids
from lower zones.
3. It keeps water out of the producing formation.
4. It confines production to the wellbore.
Figure 1. These joints of casing are ready to be run into the well,
where they will serve at least seven important functions.
3
4
CASING AND CEMENTING
5. It contains formation pressures and prevents fracturing
of upper and weaker zones.
6.
It provides an anchor for surface and artificial lift equip
ment.
7. It provides a flow path for produced fluids.
In offshore operations, casing also provides a conduit from the
seafloor
to a bottom-supported drilling unit, such as a jackup, on
the surface of the water.
Casing Strings Casing is manufactured in joints that range in length from r 6 to 48
feet (ft) or 4.9 to 14.6 metres (m). It ranges in diameter from 4.5 to
48 inches (in.) or r 14 to 122 millimetres (mm) or more. Joints of
casing are either screwed or ( occasionally) welded together as they
are lowered
into the hole. Several joints of casing, when joined,
constitute a
casing string.
Casing strings are run concentrically, from the surface through
the lowest interval with hydrocarbon-bearing potential. The bit
drills the hole to a certain depth, then casing is run in to line it and,
in
most cases, cement is pumped in to bind the casing firmly to the
walls of the hole. (Note, however, that there are instances when
casing is intentionally left uncemented.) Drilling continues
to the
next specified depth, and casing is once again run and cemented.
This process is repeated until the rig reaches total depth.
CASING
Because casing serves several different functions, itis usually neces- Types of Casing
sary to install more than one string of casing. Typically, a well will
require
at least three concentric strings of casing: conductor pipe,
surface casing, and production casing (fig.
2). Depending on the
formations encountered, it may also require intermediate casing.
In some cases a liner string may be set and tied back to the surface
to form a production string. Each type of casing serves a specific
purpose
important to the completion of the well.
/ /
I~-SURFACE
CASING
1
,1141,:1----INTERMEDIATE
"'1'------...:C=ASING
_:'.•~-
Figure 2. Most wells require several strings of casing, each of which
serves a specific purpose important to the completion of the well.
5
CASING AND CEMENTING
5. It contains formation pressures and prevents fracturing
of upper and weaker zones.
6.
It provides an anchor for surface and artificial lift equip
ment.
7. It provides a flow path for produced fluids.
In offshore operations, casing also provides a conduit from the
seafloor
to a bottom-supported drilling unit, such as a jackup, on
the surface of the water.
Casing Strings Casing is manufactured in joints that range in length from r 6 to 48
feet (ft) or 4.9 to 14.6 metres (m). It ranges in diameter from 4.5 to
48 inches (in.) or r 14 to 122 millimetres (mm) or more. Joints of
casing are either screwed or ( occasionally) welded together as they
are lowered
into the hole. Several joints of casing, when joined,
constitute a
casing string.
Casing strings are run concentrically, from the surface through
the lowest interval with hydrocarbon-bearing potential. The bit
drills the hole to a certain depth, then casing is run in to line it and,
in
most cases, cement is pumped in to bind the casing firmly to the
walls of the hole. (Note, however, that there are instances when
casing is intentionally left uncemented.) Drilling continues
to the
next specified depth, and casing is once again run and cemented.
This process is repeated until the rig reaches total depth.
CASING
Because casing serves several different functions, itis usually neces- Types of Casing
sary to install more than one string of casing. Typically, a well will
require
at least three concentric strings of casing: conductor pipe,
surface casing, and production casing (fig.
2). Depending on the
formations encountered, it may also require intermediate casing.
In some cases a liner string may be set and tied back to the surface
to form a production string. Each type of casing serves a specific
purpose
important to the completion of the well.
/ /
I~-SURFACE
CASING
1
,1141,:1----INTERMEDIATE
"'1'------...:C=ASING
_:'.•~-
Figure 2. Most wells require several strings of casing, each of which
serves a specific purpose important to the completion of the well.
5
CASING AND CEMENTING
Conductor Pipe Conductor pipe is the first string of casing installed in the well. It
prevents erosion of the hole around the base of the rig, and also
provides
the conduit to raise the circulating fluid high enough
above
ground level to return it to the mud pit.
The conductor string is usually not more than 2 o to 5 o ft ( 6. r
to r 5 m) long. Conductor pipe for onshore applications is usually
16 to 20 in. (406
to 508 mm) in outside diameter. For offshore
applications, outside diameter generally ranges from 30
to 48 in.
(762
to 1,219 mm).
Conductor pipe sometimes provides for attachment of a
blowout preventer in situations where gas sands may be en
countered at very shallow depths. The conductor pipe protects
subsequent casing strings from corrosion.
It may also be used to
support some of the wellhead load on locations where ground
support is inadequate.
When a well is drilled in a swamp or offshore, the conduc
tor pipe is generally driven into the ground with a pile driver. In
offshore operations, when drilling from bottom-supported rigs,
the conductor pipe
not only provides stability to the part of the
hole
that is near the seafloor, but it also extends the hole from the
seafloor,
up through the water, to a point in the air just below the
drilling deck of the rig (fig. 3).
Figure 3. Conductor pipe in offshore operations extends the "hole"from the seafioor, up through the
water, to a point in the air just below the drilling deck.
6
Surface casing is set deep enough to: Surface Casing
• prevent loose formations from caving in or washing out;
• seal
off weak zones from abnormal formation pressures;
•
protect freshwater formations from contamination by oil,
gas,
or salt water from deeper producing formations;
• provide solid
support for blowout preventers (BOPs);
• provide pressure integrity
in the event of blowouts or kicks;
and
• comply with government environmental regulations.
(NOTE: State and federal regulations for the protection of
underground reservoirs of fresh water are usually quite specific
about the setting depth of surface casing.)
The surface casing is the starting point for the casinghead
and
other fittings that will remain on the completed well.
The outside diameter of surface casing is slightly less than
that of the conductor pipe. Minimum setting depth is usually IO
percent of the expected total depth of the well, or 500 ft (152 m),
whichever
is greater. However, surface casing may be set several
thousand feet deep, depending
on local conditions encountered.
CASING
Intermediate casing may be 5 to 13%in. (127 to 340mm) in diameter Intermediate Casing
and may be set anywhere from the surface to total depth. When an
intermediate casing string is run, it is usually for one of two reasons:
1. to seal off weak zones from abnormal formation pres
sures
or heaving shales; or
2. to minimize hazards from lost circulation zones.
Sometimes an intermediate string
of casing is used to seal off
older producing zones in order to drill for deeper production.
The usual function of the intermediate string is to protect
against loss of circulation in shallow formations when heavyweight
mud is needed for high-pressure zones at some depth. Intermediate
casing is sometimes set
through high-pressure zones so that lighter
drilling fluid can be used to drill deeper.
The intermediate string
affords
better protection against well pressure than the surface string
because its smaller diameter holds
more pressure and because it
will not wear out from abrasion by the drill string.
When intermediate casing is used, it should be set deep enough
to reach formations able to hold the mud weight expected when
drilling deeper. This depth may be 5,000 ft (1,524 m) or more.
The number of intermediate strings set depends on the depth of
the well and the problems encountered in drilling.
7
Conductor Pipe Conductor pipe is the first string of casing installed in the well. It
prevents erosion of the hole around the base of the rig, and also
provides
the conduit to raise the circulating fluid high enough
above
ground level to return it to the mud pit.
The conductor string is usually not more than 2 o to 5 o ft ( 6. r
to r 5 m) long. Conductor pipe for onshore applications is usually
16 to 20 in. (406
to 508 mm) in outside diameter. For offshore
applications, outside diameter generally ranges from 30
to 48 in.
(762
to 1,219 mm).
Conductor pipe sometimes provides for attachment of a
blowout preventer in situations where gas sands may be en
countered at very shallow depths. The conductor pipe protects
subsequent casing strings from corrosion.
It may also be used to
support some of the wellhead load on locations where ground
support is inadequate.
When a well is drilled in a swamp or offshore, the conduc
tor pipe is generally driven into the ground with a pile driver. In
offshore operations, when drilling from bottom-supported rigs,
the conductor pipe
not only provides stability to the part of the
hole
that is near the seafloor, but it also extends the hole from the
seafloor,
up through the water, to a point in the air just below the
drilling deck of the rig (fig. 3).
Figure 3. Conductor pipe in offshore operations extends the "hole"from the seafioor, up through the
water, to a point in the air just below the drilling deck.
6
Surface casing is set deep enough to: Surface Casing
• prevent loose formations from caving in or washing out;
• seal
off weak zones from abnormal formation pressures;
•
protect freshwater formations from contamination by oil,
gas,
or salt water from deeper producing formations;
• provide solid
support for blowout preventers (BOPs);
• provide pressure integrity
in the event of blowouts or kicks;
and
• comply with government environmental regulations.
(NOTE: State and federal regulations for the protection of
underground reservoirs of fresh water are usually quite specific
about the setting depth of surface casing.)
The surface casing is the starting point for the casinghead
and
other fittings that will remain on the completed well.
The outside diameter of surface casing is slightly less than
that of the conductor pipe. Minimum setting depth is usually IO
percent of the expected total depth of the well, or 500 ft (152 m),
whichever
is greater. However, surface casing may be set several
thousand feet deep, depending
on local conditions encountered.
CASING
Intermediate casing may be 5 to 13%in. (127 to 340mm) in diameter Intermediate Casing
and may be set anywhere from the surface to total depth. When an
intermediate casing string is run, it is usually for one of two reasons:
1. to seal off weak zones from abnormal formation pres
sures
or heaving shales; or
2. to minimize hazards from lost circulation zones.
Sometimes an intermediate string
of casing is used to seal off
older producing zones in order to drill for deeper production.
The usual function of the intermediate string is to protect
against loss of circulation in shallow formations when heavyweight
mud is needed for high-pressure zones at some depth. Intermediate
casing is sometimes set
through high-pressure zones so that lighter
drilling fluid can be used to drill deeper.
The intermediate string
affords
better protection against well pressure than the surface string
because its smaller diameter holds
more pressure and because it
will not wear out from abrasion by the drill string.
When intermediate casing is used, it should be set deep enough
to reach formations able to hold the mud weight expected when
drilling deeper. This depth may be 5,000 ft (1,524 m) or more.
The number of intermediate strings set depends on the depth of
the well and the problems encountered in drilling.
7
CASING AND CEMENTING
Liner String
CASING
LINER
PACKER
AND
HANGER
LINER
CEMENT
Figure 4. A liner is a
relatively short string of
casing that extends from the
bottom of the open hole, up
into another string.
Figure 5. Liner strings
are nearly always suspended
from the upper string by
means of a liner hanger.
8
A liner is a relatively short string of casing that extends from the
bottom of the open hole up into another casing string. The upper
string overlaps the liner for about 100 ft (30. 5 m)
at its lower end
(fig. 4). Unlike
other casing strings, which are anchored from the
surface, liners are nearly always suspended from the upper string
by means
of a hanger device (fig. 5). They are often cemented in
place, but production liners are sometimes suspended in the well
without cementing.
~ RUNNING-IN STRING
CASING STRING
LINER HANGER
LINER
LANDING COLLAR
The principal advantage of a liner is the lower cost of a short
string
of pipe versus a complete string back to the surface. Liner
strings offer several additional advantages in deep wells.
1. They provide a means of testing a lower zone at less
cost than with a full string
of pipe.
2. They lessen the risk of becoming stuck off bottom be
cause running time
is shorter than for a full string.
3. If an existing string of casing has been weakened by
drilling, additional pipe may be tied from the
top of the
liner back to the surface to form a continuous casing
string
to the wellhead (fig. 6).
A liner is sometimes run as a protective string, serving the
same function
as an intermediate string.
TIE-BACK CASING
STRING
TIE-BACK
SECTION
CASING
Figure 6. A tie-back string
from
the liner to the suiface
may be used if an existing
casing string has been
weakened by drilling.
9
Liner String
CASING
LINER
PACKER
AND
HANGER
LINER
CEMENT
Figure 4. A liner is a
relatively short string of
casing that extends from the
bottom of the open hole, up
into another string.
Figure 5. Liner strings
are nearly always suspended
from the upper string by
means of a liner hanger.
8
A liner is a relatively short string of casing that extends from the
bottom of the open hole up into another casing string. The upper
string overlaps the liner for about 100 ft (30. 5 m)
at its lower end
(fig. 4). Unlike
other casing strings, which are anchored from the
surface, liners are nearly always suspended from the upper string
by means
of a hanger device (fig. 5). They are often cemented in
place, but production liners are sometimes suspended in the well
without cementing.
~ RUNNING-IN STRING
CASING STRING
LINER HANGER
LINER
LANDING COLLAR
The principal advantage of a liner is the lower cost of a short
string
of pipe versus a complete string back to the surface. Liner
strings offer several additional advantages in deep wells.
1. They provide a means of testing a lower zone at less
cost than with a full string
of pipe.
2. They lessen the risk of becoming stuck off bottom be
cause running time
is shorter than for a full string.
3. If an existing string of casing has been weakened by
drilling, additional pipe may be tied from the
top of the
liner back to the surface to form a continuous casing
string
to the wellhead (fig. 6).
A liner is sometimes run as a protective string, serving the
same function
as an intermediate string.
TIE-BACK CASING
STRING
TIE-BACK
SECTION
CASING
Figure 6. A tie-back string
from
the liner to the suiface
may be used if an existing
casing string has been
weakened by drilling.
9
CASING AND CEMENTING
IO
Production Casing The production casing, or oil string, is the last string of casing run
in the well. Its purpose
is to isolate the producing reservoir from
undesirable fluids in the producing formation and from other zones
penetrated bythewellbore. Production casing forms the protective
housing for the tubing and other equipment used in a well.
Pro
duction casing may also be referred to as the long string because
it is the longest (and heaviest) casing string in the well, running
continuously from the surface to the producing formation.
Production casing should be the best quality for the conditions
involved,
as it is usually subjected to maximum well pressures and
to high pressures from the formation. Similarly, because even a
small leak can develop into a blowout, the oil string's threaded con
nections should be appropriate for the pressures likely to develop.
The casing joints should be carefully made up as the pipe is run
into the well to guard against future leaks. Finally, the production
casing must be carefully cemented in place to ensure an absolutely
pressure-tight bond between the formation and the pipe.
To
summarize
Casing
• prevents the hole caving in or washing out
• protects freshwater sands from contamination
• keeps water
out of producing formations
• confines production to the wellbore
• contains formation pressures and prevents fracturing
of
upper, weaker zones
• provides an anchor for surface and artificial lift equipment
• provides a flow path for produced fluids
Types of casing
Conductor pipe-prevents hole erosion around rig and serves as a con
duit to raise circulating fluid high enough to return to mud pits
Suiface casing-prevents loose formations from caving; seals off weak
zones; protects freshwater formations; gives a firm base
on which
to install the BOP stack; provides pressure integrity in the event
of blowouts or kicks; is installed to comply with regulations
lnternzediate casing-seals off weak zones from abnormal formation
pressures
or heaving shales; minimizes hazards from lost circula
tion zones
Production casing-isolates the producing reservoir from undesirable
fluids in the producing formation and from other zones
Liner-a relatively short string of casing that extends from the
bottom
of the open hole up into another casing string
CASING
II
IO
Production Casing The production casing, or oil string, is the last string of casing run
in the well. Its purpose
is to isolate the producing reservoir from
undesirable fluids in the producing formation and from other zones
penetrated bythewellbore. Production casing forms the protective
housing for the tubing and other equipment used in a well.
Pro
duction casing may also be referred to as the long string because
it is the longest (and heaviest) casing string in the well, running
continuously from the surface to the producing formation.
Production casing should be the best quality for the conditions
involved,
as it is usually subjected to maximum well pressures and
to high pressures from the formation. Similarly, because even a
small leak can develop into a blowout, the oil string's threaded con
nections should be appropriate for the pressures likely to develop.
The casing joints should be carefully made up as the pipe is run
into the well to guard against future leaks. Finally, the production
casing must be carefully cemented in place to ensure an absolutely
pressure-tight bond between the formation and the pipe.
To
summarize
Casing
• prevents the hole caving in or washing out
• protects freshwater sands from contamination
• keeps water
out of producing formations
• confines production to the wellbore
• contains formation pressures and prevents fracturing
of
upper, weaker zones
• provides an anchor for surface and artificial lift equipment
• provides a flow path for produced fluids
Types of casing
Conductor pipe-prevents hole erosion around rig and serves as a con
duit to raise circulating fluid high enough to return to mud pits
Suiface casing-prevents loose formations from caving; seals off weak
zones; protects freshwater formations; gives a firm base
on which
to install the BOP stack; provides pressure integrity in the event
of blowouts or kicks; is installed to comply with regulations
lnternzediate casing-seals off weak zones from abnormal formation
pressures
or heaving shales; minimizes hazards from lost circula
tion zones
Production casing-isolates the producing reservoir from undesirable
fluids in the producing formation and from other zones
Liner-a relatively short string of casing that extends from the
bottom
of the open hole up into another casing string
CASING
II
CASING AND CEMENTING
String Design
Design Criteria:
Primary Forces
12
The goal of tubular design is to reach a target formation with a speci
fied size
of tubing. The size of tubing depends on the volume of oil
or gas to be produced and the manner in which it will be produced.
For example, a high-volume gas well and a pumping oilwell have
different size requirements. After tubing size has been selected, the
expected depth and pressure profile
of the well dictate the number
of casing strings and the pressure requirements of each.
Well environment may limit material selection.For example,
sour service requires special grades. Casing design engineers usually
select several potential weights
or grades of casing to make up a given
string, then base final casing selection
on availability and cost.
Engineers primarily design casing strings to withstand three forces:
• tension;
• collapse pressure; and
•
burst pressure.
Pipe is rated to withstand a certain
amount of each of these forces.
Almost all pipe is made
of steel. In the U.S., its strength is ex
pressed
in load per unit area (pounds of force per square inch, or
psi. Elsewhere, its strength is expressed in kilopascals or kPa). The
accepted industry standard is the American Petroleum Institute
(API) Specification 5C2,
Bulletin onPeiformance PropeniesofCasing,
Tubing, and Drill Pipe. Good engineering practice is to decrease
the rating by a safety factor
or design factor (these terms are used
interchangeably), so
that a failure will not occur if the actual load
is slightly greater
than the expected load.
Tension
Tension is the downward pull of the weight of the casing string on the
pipe body and
on the couplings. The uppermost joint of pipe in a string
must support the weight
of all sections of pipe below it. Therefore,
tension
is significant in all strings except the conductor string. Obvi
ously, tension is most important at the top of the string.
In the case of API connections, the connection is the weakest
part of the casing string. Joint strength is the amount of hanging
weight
that can be placed on a connection without failure. API
joint
strength is the calculated failure load of the connection.
Collapse Pressure
Collapse pressure is the amount of pressure required to cause the
wall
of the casing to collapse. Collapse occurs when the pressure
outside a joint
of casing is greater than the pressure inside the pipe.
Ensuring Safety
To assure an adequate margin of safety, most casing strings
are designed with a safety (
or design) factor of I. 50 to
2 .oo for tension.
The most commonly used tension fac
tor is 1.80. The tension design factor is the ratio of the
connection joint strength
to the applied axial load. The
following example illustrates the use of a safety factor.
Diameter= 7¼-inch (194-mm)
Steel grade = N-80
Weight= 26-4 psi (597 kPa/m
3
)
Connection: API Long threaded and coupled LT&C
Joint Strength = 490,000 pounds (lbs) or 2 r 8,050
decanewtons ( dN); can support a suspended load
of 490,000 lbs (218,050 dN)
Using a safety factor of 1.8 limits the load that can be
supported safely to 272,222 lbs (121,139
kPa/m
3
).
490,000 lbs+ 1.8 = 272,222 lbs
(218,050
dN + 1.8 = 121,139 kPa/m
3
).
Design factors for tension should take into account the
strength of the couplings, which is frequently lower than
the strength of the pipe body. Tension calculations are
based primarily
on load per unit of cross-sectional area
for
the grade of steel used.
Collapse pressure results from external hydrostatic pressure, and
it is significant in all strings except the conductor string. It is the
most important consideration at the bottom of the casing string,
where
the pipe can be subjected to the pressure of the outside pres
sure gradient.
One of the most common collapse failures occurs
during a
cement squeeze job.
Normally, designers apply a safety factor
of r. I 2 5 to the API
collapse rating.
For example, 7¼ in., 26-40 pounds per foot (ppf),
or 194 mm, 39.28 kilograms per metre (kg/m). N-80 casing has a
collapse pressure
of 3,400 psi (23,443 kPa/m). For a normal hydro
static head
of o. 5 psi per ft of depth ( I 1. 3 kPa ), this casing could be
used at a depth
of 6,800 ft (2,073 m) without a safety factor. Using
a design factor
of r. r 2 5, the depth is reduced to 6,800 ft + r. r 2 5 =
6,044ft(2,073 m+ 1.125 = 1,842 m). Calculations are based on the
maximum weight
of the column of fluid on the outside of the pipe,
minus the weight
of the column of fluid on the inside of the pipe.
CASING
String Design
Design Criteria:
Primary Forces
12
The goal of tubular design is to reach a target formation with a speci
fied size
of tubing. The size of tubing depends on the volume of oil
or gas to be produced and the manner in which it will be produced.
For example, a high-volume gas well and a pumping oilwell have
different size requirements. After tubing size has been selected, the
expected depth and pressure profile
of the well dictate the number
of casing strings and the pressure requirements of each.
Well environment may limit material selection.For example,
sour service requires special grades. Casing design engineers usually
select several potential weights
or grades of casing to make up a given
string, then base final casing selection
on availability and cost.
Engineers primarily design casing strings to withstand three forces:
• tension;
• collapse pressure; and
•
burst pressure.
Pipe is rated to withstand a certain
amount of each of these forces.
Almost all pipe is made
of steel. In the U.S., its strength is ex
pressed
in load per unit area (pounds of force per square inch, or
psi. Elsewhere, its strength is expressed in kilopascals or kPa). The
accepted industry standard is the American Petroleum Institute
(API) Specification 5C2,
Bulletin onPeiformance PropeniesofCasing,
Tubing, and Drill Pipe. Good engineering practice is to decrease
the rating by a safety factor
or design factor (these terms are used
interchangeably), so
that a failure will not occur if the actual load
is slightly greater
than the expected load.
Tension
Tension is the downward pull of the weight of the casing string on the
pipe body and
on the couplings. The uppermost joint of pipe in a string
must support the weight
of all sections of pipe below it. Therefore,
tension
is significant in all strings except the conductor string. Obvi
ously, tension is most important at the top of the string.
In the case of API connections, the connection is the weakest
part of the casing string. Joint strength is the amount of hanging
weight
that can be placed on a connection without failure. API
joint
strength is the calculated failure load of the connection.
Collapse Pressure
Collapse pressure is the amount of pressure required to cause the
wall
of the casing to collapse. Collapse occurs when the pressure
outside a joint
of casing is greater than the pressure inside the pipe.
Ensuring Safety
To assure an adequate margin of safety, most casing strings
are designed with a safety (
or design) factor of I. 50 to
2 .oo for tension.
The most commonly used tension fac
tor is 1.80. The tension design factor is the ratio of the
connection joint strength
to the applied axial load. The
following example illustrates the use of a safety factor.
Diameter= 7¼-inch (194-mm)
Steel grade = N-80
Weight= 26-4 psi (597 kPa/m
3
)
Connection: API Long threaded and coupled LT&C
Joint Strength = 490,000 pounds (lbs) or 2 r 8,050
decanewtons ( dN); can support a suspended load
of 490,000 lbs (218,050 dN)
Using a safety factor of 1.8 limits the load that can be
supported safely to 272,222 lbs (121,139
kPa/m
3
).
490,000 lbs+ 1.8 = 272,222 lbs
(218,050
dN + 1.8 = 121,139 kPa/m
3
).
Design factors for tension should take into account the
strength of the couplings, which is frequently lower than
the strength of the pipe body. Tension calculations are
based primarily
on load per unit of cross-sectional area
for
the grade of steel used.
Collapse pressure results from external hydrostatic pressure, and
it is significant in all strings except the conductor string. It is the
most important consideration at the bottom of the casing string,
where
the pipe can be subjected to the pressure of the outside pres
sure gradient.
One of the most common collapse failures occurs
during a
cement squeeze job.
Normally, designers apply a safety factor
of r. I 2 5 to the API
collapse rating.
For example, 7¼ in., 26-40 pounds per foot (ppf),
or 194 mm, 39.28 kilograms per metre (kg/m). N-80 casing has a
collapse pressure
of 3,400 psi (23,443 kPa/m). For a normal hydro
static head
of o. 5 psi per ft of depth ( I 1. 3 kPa ), this casing could be
used at a depth
of 6,800 ft (2,073 m) without a safety factor. Using
a design factor
of r. r 2 5, the depth is reduced to 6,800 ft + r. r 2 5 =
6,044ft(2,073 m+ 1.125 = 1,842 m). Calculations are based on the
maximum weight
of the column of fluid on the outside of the pipe,
minus the weight
of the column of fluid on the inside of the pipe.
CASING
CASING AND CEMENTING
Collapse Resistance: More or Less
Several factors can reduce the collapse rating of pipe.
Pipe in tension has reduced resistance to collapse, while pipe
in compression has greater resistance.
The API recognizes
the reduction
of collapse resistance due to axial tension
(Section 2.r.5, API Bulletin 5C3,
Bulletin of Formulas and
Calculations for Casing, Tubing, and Drill Pipe).
Ovality reduces collapse resistance. A perfectly round,
thin-walled tube,
if deformed by r percent out-of-round,
will have its resistance to collapse lowered by 2 5 percent.
Thus, the slightest crushing by tongs, slips, or downhole
conditions diminishes the collapse resistance of the tube
considerably.
Burst Pressure
Burst pressure is the pressure difference when the fluid pressure
inside the pipe
is greater than the fluid pressure outside the pipe.
The burst pressure rating is actually the internal yield pressure of
the pipe; i.e., the pressure at which the pipe body begins to per
manently deform. Burst pressure
is greatest at the top of a casing
string because the external pressure
on the casing is reduced to zero
at this point. Burst pressure is important where wellhead pressures
are relatively high,
as in high-pressure gas wells.
Burst strength, or minimum internal yield pressure, for the 7%
in. x 26-40 ppf, (194 mm x 39.28 kg/m) N-80 casing considered
in previous examples
is 6,020 psi (42 kPa). Using a safety factor of
1.r will permit a safe internal pressure of 5,470 psi (37,716 kPa).
A more conservative safety factor
is r .2 5, which results in a safe
working pressure
of 4,810 psi (33,165 kPa). Determining internal
pressure is possibly the most difficult
part of casing design. For this_
reason, many designers use the more conservative design factor.
Maximum shut-in surface pressure
to which casing will be
subjected makes a good internal pressure requirement. However,
determining
the maximum shut-in pressure prior to completion is
arbitrary and often depends on experience in a given area. Many
times it is set equal to the working pressure rating of the surface
equipment. Normally,
when the surface pressure is used as the
internal load limit,
the designer assumes that the hole remains full
of mud and that the mud density inside and outside the casing is
equal (i.e., that the hydrostatic pressure acting inside the casing
is equal
to the pressure acting on the outside of the casing at all
points
of the casing string, from top to bottom). In high-pressure
or deep wells, design engineers will assume either partial or full
evacuation
to better simulate a "worst-case" scenario. As with col
lapse pressure capacity,
tong marks or other damage to the outside
of the casing can greatly reduce the burst strength.
In addition to tension, collapse, and burst pressures, casing string
engineers may have
to consider buckling stress, axial compression,
bending, and torsion when designing a casing string.
Buckling stress is stress on the pipe that causes it to bend.
Buckling may occur due
to deviation of the hole and primarily af
fects the conductor and surface strings.
An exception is a situation
where the land shifts and causes the casing string
to shear.
Bending occurs when tension is increased on one side of the
pipe while compression
is increased on the other. Casing may bend
because
of the angle of the hole or because of a dogleg (an abrupt
deviation in hole angle).
Axial compression is compression of the pipe that occurs as a
result
of pressure that is parallel with the cylinder axis.For example,
if the casing hits a deviation in the hole or a sticky spot and stops,
the force pushing down
on the pipe produces axial compression.
In geothermal and steam injection applications, if the casing is
fixed on each end, an increase in temperature will cause the steel
to expand and tend to push against itself from either end, exerting
an axial compression stress.
Torsion is a twisting deformation of the casing about its axis such
that lines that were initially parallel to the
axis become helices. Torsion
is produced when part of the pipe turns or twists in one direction
while the other part remains stationary
or twists in the other direction.
Cementing the casing helps protect
it from torsional stress.
An important consideration when designing production casing
and liner strings
is the downhole environment. If the pipe will be
exposed
to carbon dioxide, sulfur, salt, or high temperatures, special
consideration
must be given to selection of the grade of steel used
in the casing or liner. For example, if the casing will be exposed
to hydrogen sulfide (H
2
S), the steel must be rated for H
2
S service.
Steel manufactured
to withstand exposure to H
2
S complicates well
design, because such steel has limited tensile strength.
In some
cases, expensive stainless steel casing
is used.
CASING
Design Criteria:
Secondary Forces
Design Criteria:
Downhole
Environment
Collapse Resistance: More or Less
Several factors can reduce the collapse rating of pipe.
Pipe in tension has reduced resistance to collapse, while pipe
in compression has greater resistance.
The API recognizes
the reduction
of collapse resistance due to axial tension
(Section 2.r.5, API Bulletin 5C3,
Bulletin of Formulas and
Calculations for Casing, Tubing, and Drill Pipe).
Ovality reduces collapse resistance. A perfectly round,
thin-walled tube,
if deformed by r percent out-of-round,
will have its resistance to collapse lowered by 2 5 percent.
Thus, the slightest crushing by tongs, slips, or downhole
conditions diminishes the collapse resistance of the tube
considerably.
Burst Pressure
Burst pressure is the pressure difference when the fluid pressure
inside the pipe
is greater than the fluid pressure outside the pipe.
The burst pressure rating is actually the internal yield pressure of
the pipe; i.e., the pressure at which the pipe body begins to per
manently deform. Burst pressure
is greatest at the top of a casing
string because the external pressure
on the casing is reduced to zero
at this point. Burst pressure is important where wellhead pressures
are relatively high,
as in high-pressure gas wells.
Burst strength, or minimum internal yield pressure, for the 7%
in. x 26-40 ppf, (194 mm x 39.28 kg/m) N-80 casing considered
in previous examples
is 6,020 psi (42 kPa). Using a safety factor of
1.r will permit a safe internal pressure of 5,470 psi (37,716 kPa).
A more conservative safety factor
is r .2 5, which results in a safe
working pressure
of 4,810 psi (33,165 kPa). Determining internal
pressure is possibly the most difficult
part of casing design. For this_
reason, many designers use the more conservative design factor.
Maximum shut-in surface pressure
to which casing will be
subjected makes a good internal pressure requirement. However,
determining
the maximum shut-in pressure prior to completion is
arbitrary and often depends on experience in a given area. Many
times it is set equal to the working pressure rating of the surface
equipment. Normally,
when the surface pressure is used as the
internal load limit,
the designer assumes that the hole remains full
of mud and that the mud density inside and outside the casing is
equal (i.e., that the hydrostatic pressure acting inside the casing
is equal
to the pressure acting on the outside of the casing at all
points
of the casing string, from top to bottom). In high-pressure
or deep wells, design engineers will assume either partial or full
evacuation
to better simulate a "worst-case" scenario. As with col
lapse pressure capacity,
tong marks or other damage to the outside
of the casing can greatly reduce the burst strength.
In addition to tension, collapse, and burst pressures, casing string
engineers may have
to consider buckling stress, axial compression,
bending, and torsion when designing a casing string.
Buckling stress is stress on the pipe that causes it to bend.
Buckling may occur due
to deviation of the hole and primarily af
fects the conductor and surface strings.
An exception is a situation
where the land shifts and causes the casing string
to shear.
Bending occurs when tension is increased on one side of the
pipe while compression
is increased on the other. Casing may bend
because
of the angle of the hole or because of a dogleg (an abrupt
deviation in hole angle).
Axial compression is compression of the pipe that occurs as a
result
of pressure that is parallel with the cylinder axis.For example,
if the casing hits a deviation in the hole or a sticky spot and stops,
the force pushing down
on the pipe produces axial compression.
In geothermal and steam injection applications, if the casing is
fixed on each end, an increase in temperature will cause the steel
to expand and tend to push against itself from either end, exerting
an axial compression stress.
Torsion is a twisting deformation of the casing about its axis such
that lines that were initially parallel to the
axis become helices. Torsion
is produced when part of the pipe turns or twists in one direction
while the other part remains stationary
or twists in the other direction.
Cementing the casing helps protect
it from torsional stress.
An important consideration when designing production casing
and liner strings
is the downhole environment. If the pipe will be
exposed
to carbon dioxide, sulfur, salt, or high temperatures, special
consideration
must be given to selection of the grade of steel used
in the casing or liner. For example, if the casing will be exposed
to hydrogen sulfide (H
2
S), the steel must be rated for H
2
S service.
Steel manufactured
to withstand exposure to H
2
S complicates well
design, because such steel has limited tensile strength.
In some
cases, expensive stainless steel casing
is used.
CASING
Design Criteria:
Secondary Forces
Design Criteria:
Downhole
Environment
CASING AND CEMENTING
16
To summarize-
Casing strings must withstand
• tension
• collapse pressure
• burst pressure
Tension is the downward pull of the weight of the casing string on
the pipe body and couplings.
Collapse pressure is the amount of pressure required to cause the
wall
of the casing to collapse.
Burst
pressure is the amount of pressure inside the casing required
to permanently deform the pipe body.
Secondary forces that act on casing
• buckling
• bending
• axial compression
• torsion
The process of setting casing involves preparation, running, stab
bing, making up, lowering, and landing.
Several preparatory steps are necessary before casing
is run in the
well
(fig. 7 ). During these procedures, it is important to protect the
threads and the pipe itself from damage. "Preventive maintenance"
goes a long way toward ensuring this protection.
CASING
Setting the Casing
Preparation
Figure 7. Whether on or
offshore, preventive mainte
nance is key to protecting
casing as it is prepared to
run into the well. (Courtesy
of Hydril)
17
16
To summarize-
Casing strings must withstand
• tension
• collapse pressure
• burst pressure
Tension is the downward pull of the weight of the casing string on
the pipe body and couplings.
Collapse pressure is the amount of pressure required to cause the
wall
of the casing to collapse.
Burst
pressure is the amount of pressure inside the casing required
to permanently deform the pipe body.
Secondary forces that act on casing
• buckling
• bending
• axial compression
• torsion
The process of setting casing involves preparation, running, stab
bing, making up, lowering, and landing.
Several preparatory steps are necessary before casing
is run in the
well
(fig. 7 ). During these procedures, it is important to protect the
threads and the pipe itself from damage. "Preventive maintenance"
goes a long way toward ensuring this protection.
CASING
Setting the Casing
Preparation
Figure 7. Whether on or
offshore, preventive mainte
nance is key to protecting
casing as it is prepared to
run into the well. (Courtesy
of Hydril)
17
CASING AND CEMENTING
18
Preventive Measures
The first thing to remember about casing is that it should have
thread protectors in place any time
it is handled. The thread protec
tor is a threaded cap or lightweight collar that is screwed onto the
ends of pipe, casing, or tubing to protect the threads from damage
(fig. 8).
Another protective measure is to avoid placing hooks in
the ends of the pipe, even if thread protectors are in place.
To prevent excessive rusting, all machined areas
of the casing
should be coated with a thin layer
of oil after inspection is complete.
Keep
the thread protectors on the casing when rolling it off the
rack and pulling it into the derrick. If the couplings are removed,
or if a coupling appears to be loose, tighten the couplings carefully
before pulling the pipe
into the derrick.
Rack casing
at least 18 in. (457 mm) off the ground. As crew
members roll
the casing onto the pipe rack, inspect each joint, arid
if it ·has any dents or scars, set it aside. Place rope slings around
pipe being rolled down skids to control and prevent it from being
dropped
or shock loaded. This is particularly true for higher grades
of steel, which are particularly susceptible to damage from shock
or impact loading. Avoid using fabricated buckets placed over the
pipe ends to lift the pipe, and keep your hands off the pipe as it
rolls down the skids.
Figure 8. A thread protector should be in place any time a joint of
casing is handled.
Place adequate spacers, or stringers, such as wooden two-by
fours, between each layer
of casing on the pipe rack so that the
joints of the upper layers can be easily rolled to the catwalk (fig.
9). Align
the stringers both vertically and horizontally to keep in
dividual casing joints parallel to one
another and to prevent them
from rolling and making side-to-side contact that could damage
the connections. The number of stringers must be adequate to
prevent bending the pipe or compressing the lower stringers.
CASING
Figure 9. Casing resting
on stringers
18
Preventive Measures
The first thing to remember about casing is that it should have
thread protectors in place any time
it is handled. The thread protec
tor is a threaded cap or lightweight collar that is screwed onto the
ends of pipe, casing, or tubing to protect the threads from damage
(fig. 8).
Another protective measure is to avoid placing hooks in
the ends of the pipe, even if thread protectors are in place.
To prevent excessive rusting, all machined areas
of the casing
should be coated with a thin layer
of oil after inspection is complete.
Keep
the thread protectors on the casing when rolling it off the
rack and pulling it into the derrick. If the couplings are removed,
or if a coupling appears to be loose, tighten the couplings carefully
before pulling the pipe
into the derrick.
Rack casing
at least 18 in. (457 mm) off the ground. As crew
members roll
the casing onto the pipe rack, inspect each joint, arid
if it ·has any dents or scars, set it aside. Place rope slings around
pipe being rolled down skids to control and prevent it from being
dropped
or shock loaded. This is particularly true for higher grades
of steel, which are particularly susceptible to damage from shock
or impact loading. Avoid using fabricated buckets placed over the
pipe ends to lift the pipe, and keep your hands off the pipe as it
rolls down the skids.
Figure 8. A thread protector should be in place any time a joint of
casing is handled.
Place adequate spacers, or stringers, such as wooden two-by
fours, between each layer
of casing on the pipe rack so that the
joints of the upper layers can be easily rolled to the catwalk (fig.
9). Align
the stringers both vertically and horizontally to keep in
dividual casing joints parallel to one
another and to prevent them
from rolling and making side-to-side contact that could damage
the connections. The number of stringers must be adequate to
prevent bending the pipe or compressing the lower stringers.
CASING
Figure 9. Casing resting
on stringers
CASING AND CEMENTING
20
Crew members must run casing into the hole in the proper order.
A misplaced joint may cause complete failure and loss
of the well.
For this reason, any joint of casing that cannot be clearly identi
fied should be set aside until its weight, grade, and type can be
positively identified.
If a graded or mixed string is being used, the pipe should be
placed
on the pipe rack in reverse order to the order in which it will
be
run into the well. The last joint to be stacked on the rack will
be the first to go into the well. If the casing string includes pipe of
different thread forms, the crossover lengths should be accessible
on the rack so that matching threads will fit properly.
The individual lengths of pipe in a casing string should be
numbered in the order in which they are to be run into the well.
Different weights
or grades should be clearly marked, as well as
the length of each joint.
Inspection
In some situations, specialists are called in to inspect and test cas
ing. Otherwise, thread protectors from
both ends of pipe in the
top layer of casing are removed, and the threads are cleaned and
inspected for damage
that may have occurred during shipping and
racking (fig. rn).
Figure Io. Before casing is run, threads are inspected for damage
that may have occurred during shipping and racking. (Courtesy of
Hydril)
First, remove the thread protectors. Then, clean off the ship
ping thread compound with a solvent and a soft-bristle brush. Use
isopropyl alcohol, methanol, or 1, 1, I-trichloroethane as solvents,
especially
in subfreezing temperatures. Do not use diesel fuel or
kerosene as a solvent because it can dilute the thread compound if
it is left in the thread grooves. After cleaning the threads, dry them
with compressed air, if it's available. A tool called a rabbit (with
the same OD as the casing ID) is run inside each joint of casing.
This is called drifting. This is to make sure that no joint of casing
is
bent or scaled. If the rabbit does not go through the inside of
the casing, that joint should be taken out and not used.
Mark and lay aside any damaged connections found during
this inspection so they will not be run. After drying the threads on
the good joints, apply fresh thread compound and install clean, dry
thread protectors.
This inspection procedure should be repeated
for each
row of pipe in the stack as it is uncovered.
Measuring Pipe
Although depth of producing formations and perforating intervals
are usually determined
by electric log measurements, an important
part of every casing job is the measurement, or tally, of the pipe.
Each casing joint must be measured, preferably with a graduated
steel tape
that shows feet, tenths, and hundredths of a foot ( or
metres, centimetres, and millimetres). The tape should be read to
the nearest hundredth of a foot (millimetre) from the top end of
the coupling to the first scratch of the run-out for round-thread
casing, or between the shoulders for extreme-line casing. Record
these measurements
on a tally sheet and block them in groups of
ten. Then, add columns of ten. Inspecting these totals quickly re
veals addition errors and where they occurred, for the group totals
should approximate
ten times the average length of each joint.
CASING
21
20
Crew members must run casing into the hole in the proper order.
A misplaced joint may cause complete failure and loss
of the well.
For this reason, any joint of casing that cannot be clearly identi
fied should be set aside until its weight, grade, and type can be
positively identified.
If a graded or mixed string is being used, the pipe should be
placed
on the pipe rack in reverse order to the order in which it will
be
run into the well. The last joint to be stacked on the rack will
be the first to go into the well. If the casing string includes pipe of
different thread forms, the crossover lengths should be accessible
on the rack so that matching threads will fit properly.
The individual lengths of pipe in a casing string should be
numbered in the order in which they are to be run into the well.
Different weights
or grades should be clearly marked, as well as
the length of each joint.
Inspection
In some situations, specialists are called in to inspect and test cas
ing. Otherwise, thread protectors from
both ends of pipe in the
top layer of casing are removed, and the threads are cleaned and
inspected for damage
that may have occurred during shipping and
racking (fig. rn).
Figure Io. Before casing is run, threads are inspected for damage
that may have occurred during shipping and racking. (Courtesy of
Hydril)
First, remove the thread protectors. Then, clean off the ship
ping thread compound with a solvent and a soft-bristle brush. Use
isopropyl alcohol, methanol, or 1, 1, I-trichloroethane as solvents,
especially
in subfreezing temperatures. Do not use diesel fuel or
kerosene as a solvent because it can dilute the thread compound if
it is left in the thread grooves. After cleaning the threads, dry them
with compressed air, if it's available. A tool called a rabbit (with
the same OD as the casing ID) is run inside each joint of casing.
This is called drifting. This is to make sure that no joint of casing
is
bent or scaled. If the rabbit does not go through the inside of
the casing, that joint should be taken out and not used.
Mark and lay aside any damaged connections found during
this inspection so they will not be run. After drying the threads on
the good joints, apply fresh thread compound and install clean, dry
thread protectors.
This inspection procedure should be repeated
for each
row of pipe in the stack as it is uncovered.
Measuring Pipe
Although depth of producing formations and perforating intervals
are usually determined
by electric log measurements, an important
part of every casing job is the measurement, or tally, of the pipe.
Each casing joint must be measured, preferably with a graduated
steel tape
that shows feet, tenths, and hundredths of a foot ( or
metres, centimetres, and millimetres). The tape should be read to
the nearest hundredth of a foot (millimetre) from the top end of
the coupling to the first scratch of the run-out for round-thread
casing, or between the shoulders for extreme-line casing. Record
these measurements
on a tally sheet and block them in groups of
ten. Then, add columns of ten. Inspecting these totals quickly re
veals addition errors and where they occurred, for the group totals
should approximate
ten times the average length of each joint.
CASING
21
CASING AND CEMENTING
Figure I 1. Pipe is tallied
three times: when it is
shipped, when it arrives
at location, and after the
casing string has been run.
(Courtesy of Hydril)
Running the Casing
22
Knowing how much casing is run into the hole is important
because it provides valuable information about casing depth. Cas
ing depth can be verified by multiplying the average length of the
casing, according to the tally, by the number of joints of casing
run into the hole. One common error when making this calcula
tion is to accidentally omit or add a joint. Less frequently, mo-ft
(30-m) mistakes are m~de. The more attention paid to measuring
the pipe, the less likely these mistakes are to occur.
The most important aspect of pipe measurement is determin
ing exactly how many lengths are on the job. This measurement
is made three times (fig. u):
1. The shipper counts the lengths of pipe when itis shipped
to the location.
2. The number oflengths is counted again when the casing
is received
at the well site.
3. The lengths of pipe remaining after the casing string
has been run are counted.
The number of joints of casing in the hole must be the dif
ference between
the total number of joints that came into the loca
tion (less any that may have been shipped away) and the number
of joints on hand at the end of the casing run.
Hole Conditioning
Before running and cementing casing, the driller should be sure that
the hole is in good shape and relatively free of cuttings and excess
filter cake. Failure
to condition the hole thoroughly or to treat the
mud properly can cause stuck pipe, poor cementing, or costly cement
squeeze work, and may even result
in having to redrill the hole.
Usually, drill pipe will have been
out of the hole for 12 to 24
hours while surveys and other information are obtained prior to
the decision to set casing.
Enough filter cake may have built up on
the permeable sections of the hole to close the annulus and form
an obstruction
that could cause the casing to stick or make circula
tion impossible. Cuttings
or sloughed shale may have settled in the
hole to such an extent
that casing cannot be run to bottom without
circulation. General procedure for hole conditioning
is to lower one
stand
of drill collars and a used bit into the hole, just in case bridges
are encountered.
When conditioning the hole, drill pipe measurements should
be carefully checked, even
to the extent of obtaining new figures and
totaling
them again. Once on bottom, total depth is double-checked,
and circulation is started.
The mud should be pumped through the
-well atleast twice while the mud engineer observes weight, viscosity,
and fluid loss.
If mud treatment appears necessary, circulation must
be maintained while slowly rotating and working the pipe until
the mud engineer is satisfied that the fluid is in suitable condition
for
running casing (fig. 12). A sweep of thick mud is sometimes
recommended to bring out any cuttings left in the hole.
Figure I 2. Running casing
CASING
23
Figure I 1. Pipe is tallied
three times: when it is
shipped, when it arrives
at location, and after the
casing string has been run.
(Courtesy of Hydril)
Running the Casing
22
Knowing how much casing is run into the hole is important
because it provides valuable information about casing depth. Cas
ing depth can be verified by multiplying the average length of the
casing, according to the tally, by the number of joints of casing
run into the hole. One common error when making this calcula
tion is to accidentally omit or add a joint. Less frequently, mo-ft
(30-m) mistakes are m~de. The more attention paid to measuring
the pipe, the less likely these mistakes are to occur.
The most important aspect of pipe measurement is determin
ing exactly how many lengths are on the job. This measurement
is made three times (fig. u):
1. The shipper counts the lengths of pipe when itis shipped
to the location.
2. The number oflengths is counted again when the casing
is received
at the well site.
3. The lengths of pipe remaining after the casing string
has been run are counted.
The number of joints of casing in the hole must be the dif
ference between
the total number of joints that came into the loca
tion (less any that may have been shipped away) and the number
of joints on hand at the end of the casing run.
Hole Conditioning
Before running and cementing casing, the driller should be sure that
the hole is in good shape and relatively free of cuttings and excess
filter cake. Failure
to condition the hole thoroughly or to treat the
mud properly can cause stuck pipe, poor cementing, or costly cement
squeeze work, and may even result
in having to redrill the hole.
Usually, drill pipe will have been
out of the hole for 12 to 24
hours while surveys and other information are obtained prior to
the decision to set casing.
Enough filter cake may have built up on
the permeable sections of the hole to close the annulus and form
an obstruction
that could cause the casing to stick or make circula
tion impossible. Cuttings
or sloughed shale may have settled in the
hole to such an extent
that casing cannot be run to bottom without
circulation. General procedure for hole conditioning
is to lower one
stand
of drill collars and a used bit into the hole, just in case bridges
are encountered.
When conditioning the hole, drill pipe measurements should
be carefully checked, even
to the extent of obtaining new figures and
totaling
them again. Once on bottom, total depth is double-checked,
and circulation is started.
The mud should be pumped through the
-well atleast twice while the mud engineer observes weight, viscosity,
and fluid loss.
If mud treatment appears necessary, circulation must
be maintained while slowly rotating and working the pipe until
the mud engineer is satisfied that the fluid is in suitable condition
for
running casing (fig. 12). A sweep of thick mud is sometimes
recommended to bring out any cuttings left in the hole.
Figure I 2. Running casing
CASING
23
CASING AND CEMENTING
Filling the Casing
Normally, the driller fills each casing joint with drilling mud as the
crew runs it into the well, unless automatic fill-up float equipment
is
being used. Casing should be filled as it is run for three reasons:
I. If the casing is filled as each joint is added, there will
be less time for the string to be motionless and become
stuck while completely filling when the pipe
is near the
bottom
of the hole.
2. Large-diameter casing may collapse if run too far into
the hole before being filled, due to greater pressure on
the outside
of the pipe.
3. For the buoyancy factor of the casing as it may float in
the mud and
is harder to get to bottom.
A lightweight fill-up line with a quick-opening valve
is com
monly used to
fill each joint of casing while the next length is being
picked up and prepared for stabbing (fig.
r 3).
Figure I 3. Stabbing casing (Courtesy of Hydril)
Fluid Displacement
When conventional versus automatic-fill types of float shoes and
collars are used, the amount
of fluid displaced from the hole as
each joint of casing is added to the string should equal the volume
of the external diameter times the length of the joint. Fluid returns
representative
of the displacement volume of the casing should
be obtained as each joint of casing is lowered into the well. The
amounts of fluid displaced, external volume only, per joint of pipe
added for typical sizes are given in table
I.
Table 1
Fluid Displacement of Casing
Casing Size, OD
inches (millimetres)
5 (127)
7 (177.8)
8¼ (219.1)
IO (254)
Fluid Displaced by One
42-F oot Length of Casing
barrels (cubic metres)
r.24 (.20)
2.01 (.32)
3.5o (.56)
4-73 (.75)
Mud returns should be carefully observed as each length of
casing is lowered into the hole to ensure circulation when the string
reaches total depth.
Mud gain in the pit should equal the volume
of steel in the string of casing lowered into the well. The values
in table
2 give some idea of the mud gain obtained when a string
of casing is run into a well and completely filled up. For example,
a
12,000-ft (3,658-m) string of 7-in. (177.8-mm) OD casing dis
places
12 x 8.38 bbl= mo bbl, (16 m
3
) and the pits will show that
amount
of gain if there has been no fluid loss.
Table 2
Volume Gains in the Mud Pit from Casing Displacement
Size and Weight
5 in., 17 lbs/ft
(127 mm, 25.3 kg/m)
7 in., 2 3 lbs/ft
(178 mm, 34.2 kg/m)
8¼ in., 3 2 lbs/ft
(219.1 mm, 47.6 kg/m)
IO in., 40.50 lbs/ft
(254 mm, 60.3 kg/m)
Fluid Displacement
Volumes of Casing and Couplings
7.27 bbl/r,ooo ft
(r.16 m3/300 m)
8.38 bbl/r,ooo ft
(1.33 m3/300 m)
l r.64 bbl/1,000 ft
(r.85 m3/300 m)
14.42 bbl/1,000 ft
(2.29 m3
/300 m)
CASING
Filling the Casing
Normally, the driller fills each casing joint with drilling mud as the
crew runs it into the well, unless automatic fill-up float equipment
is
being used. Casing should be filled as it is run for three reasons:
I. If the casing is filled as each joint is added, there will
be less time for the string to be motionless and become
stuck while completely filling when the pipe
is near the
bottom
of the hole.
2. Large-diameter casing may collapse if run too far into
the hole before being filled, due to greater pressure on
the outside
of the pipe.
3. For the buoyancy factor of the casing as it may float in
the mud and
is harder to get to bottom.
A lightweight fill-up line with a quick-opening valve
is com
monly used to
fill each joint of casing while the next length is being
picked up and prepared for stabbing (fig.
r 3).
Figure I 3. Stabbing casing (Courtesy of Hydril)
Fluid Displacement
When conventional versus automatic-fill types of float shoes and
collars are used, the amount
of fluid displaced from the hole as
each joint of casing is added to the string should equal the volume
of the external diameter times the length of the joint. Fluid returns
representative
of the displacement volume of the casing should
be obtained as each joint of casing is lowered into the well. The
amounts of fluid displaced, external volume only, per joint of pipe
added for typical sizes are given in table
I.
Table 1
Fluid Displacement of Casing
Casing Size, OD
inches (millimetres)
5 (127)
7 (177.8)
8¼ (219.1)
IO (254)
Fluid Displaced by One
42-F oot Length of Casing
barrels (cubic metres)
r.24 (.20)
2.01 (.32)
3.5o (.56)
4-73 (.75)
Mud returns should be carefully observed as each length of
casing is lowered into the hole to ensure circulation when the string
reaches total depth.
Mud gain in the pit should equal the volume
of steel in the string of casing lowered into the well. The values
in table
2 give some idea of the mud gain obtained when a string
of casing is run into a well and completely filled up. For example,
a
12,000-ft (3,658-m) string of 7-in. (177.8-mm) OD casing dis
places
12 x 8.38 bbl= mo bbl, (16 m
3
) and the pits will show that
amount
of gain if there has been no fluid loss.
Table 2
Volume Gains in the Mud Pit from Casing Displacement
Size and Weight
5 in., 17 lbs/ft
(127 mm, 25.3 kg/m)
7 in., 2 3 lbs/ft
(178 mm, 34.2 kg/m)
8¼ in., 3 2 lbs/ft
(219.1 mm, 47.6 kg/m)
IO in., 40.50 lbs/ft
(254 mm, 60.3 kg/m)
Fluid Displacement
Volumes of Casing and Couplings
7.27 bbl/r,ooo ft
(r.16 m3/300 m)
8.38 bbl/r,ooo ft
(1.33 m3/300 m)
l r.64 bbl/1,000 ft
(r.85 m3/300 m)
14.42 bbl/1,000 ft
(2.29 m3
/300 m)
CASING
CASING AND CEMENTING
26
Running Speed
Because many casing connections are not designed to withstand
the same drag forces
as drill pipe connections, casing cannot be
run at the same speed as drill pipe. Under normal conditions,
casing may be lowered into the hole
at rates of r,200 to 2,000 ft
per hour (ft/hr) or 336 to 610 m per hour (m/h) in hard rock and
about r,ooo ft/hr
(305 m/h) in soft formations. If there is a pos
sibility
oflost circulation, these speeds may be reduced by 3 o to 50
percent, depending on the experience of the operator and his or
her assessment of mud quality and hole condition. Most operators
run casing equipped with scratchers and centralizers more slowly
than they
run bare casing to avoid risking formation breakdown
and subsequent loss
of drilling fluid.
Pressure Surges
Casing in a wellbore is like a piston in a cylinder. The faster the
piston moves through the cylinder, the more the pressure builds
up.
If a downhole formation is weak and fractures easily, pressure
surges can break it down.
'-Vb.en this happens, mud is lost, and
expensive, time-consuming corrections must be made before op
erations continue.
These problems can be avoided by preventing
pressure surges.
Low pumping rates minimize pressure surges. Therefore,
pumping rates should be reduced immediately whenever there
is
any indication of lost returns.
In areas where mud quality may not be good, lowering the
casing very slowly should minimize pressure surges and prevent lost
circulation. Another preventive measure is
not to run the pump too
fast when lowering casing while circulation is being established.
Circulation
By circulating fluid through the casing string after reaching bot
tom, an operator can test the surface piping system, condition
the mud in the hole, and flush
out cuttings and wall cake prior to
cementing. Although most operators circulate prior to cement
ing, the length
of circulating time varies from as little as 5 or ro
minutes to as much as 4 hours. Adequate circulation distributes
an amount
of fluid equal to the volume inside the casing before
cement
is started into the well. This ensures that no objects that
could plug the string during cementing are dropped into the cas
ing while
it is being run.
Moving the casing string by reciprocation
or rotation, either
with
or without scratchers, commences as soon as possible after all
the casing.has been
run and continues during circulation. Some
operators use a system that can rotate and reciprocate the pipe
simultaneously. Movement usually continues until the cement
is
placed outside the string. If scratchers and centralizers are used,
the usual practice is to continue circulating and working the pipe
until wall cake and cuttings have virtually stopped coming
out of
the hole. One disadvantage of rotating casing is that it may not
withstand the torsional stress and may bend or twist if it is rotated
with too much force.
Before a length
of casing is stabbed, made up, and lowered, crew
members lift
it from the catwalk to the rig floor with an air hoist
line (fig.
14).
Once at floor level, a crew member uses a length of soft line
run across the V-door opening to catch the bottom of the joint
and slow its swing toward the rotary table.
CASING
Stabbing, Making Up,
and Lowering
Figure 14. Special bucket and sling arrangement raise a joint of casing to the rig floor.
27
26
Running Speed
Because many casing connections are not designed to withstand
the same drag forces
as drill pipe connections, casing cannot be
run at the same speed as drill pipe. Under normal conditions,
casing may be lowered into the hole
at rates of r,200 to 2,000 ft
per hour (ft/hr) or 336 to 610 m per hour (m/h) in hard rock and
about r,ooo ft/hr
(305 m/h) in soft formations. If there is a pos
sibility
oflost circulation, these speeds may be reduced by 3 o to 50
percent, depending on the experience of the operator and his or
her assessment of mud quality and hole condition. Most operators
run casing equipped with scratchers and centralizers more slowly
than they
run bare casing to avoid risking formation breakdown
and subsequent loss
of drilling fluid.
Pressure Surges
Casing in a wellbore is like a piston in a cylinder. The faster the
piston moves through the cylinder, the more the pressure builds
up.
If a downhole formation is weak and fractures easily, pressure
surges can break it down.
'-Vb.en this happens, mud is lost, and
expensive, time-consuming corrections must be made before op
erations continue.
These problems can be avoided by preventing
pressure surges.
Low pumping rates minimize pressure surges. Therefore,
pumping rates should be reduced immediately whenever there
is
any indication of lost returns.
In areas where mud quality may not be good, lowering the
casing very slowly should minimize pressure surges and prevent lost
circulation. Another preventive measure is
not to run the pump too
fast when lowering casing while circulation is being established.
Circulation
By circulating fluid through the casing string after reaching bot
tom, an operator can test the surface piping system, condition
the mud in the hole, and flush
out cuttings and wall cake prior to
cementing. Although most operators circulate prior to cement
ing, the length
of circulating time varies from as little as 5 or ro
minutes to as much as 4 hours. Adequate circulation distributes
an amount
of fluid equal to the volume inside the casing before
cement
is started into the well. This ensures that no objects that
could plug the string during cementing are dropped into the cas
ing while
it is being run.
Moving the casing string by reciprocation
or rotation, either
with
or without scratchers, commences as soon as possible after all
the casing.has been
run and continues during circulation. Some
operators use a system that can rotate and reciprocate the pipe
simultaneously. Movement usually continues until the cement
is
placed outside the string. If scratchers and centralizers are used,
the usual practice is to continue circulating and working the pipe
until wall cake and cuttings have virtually stopped coming
out of
the hole. One disadvantage of rotating casing is that it may not
withstand the torsional stress and may bend or twist if it is rotated
with too much force.
Before a length
of casing is stabbed, made up, and lowered, crew
members lift
it from the catwalk to the rig floor with an air hoist
line (fig.
14).
Once at floor level, a crew member uses a length of soft line
run across the V-door opening to catch the bottom of the joint
and slow its swing toward the rotary table.
CASING
Stabbing, Making Up,
and Lowering
Figure 14. Special bucket and sling arrangement raise a joint of casing to the rig floor.
27
CASING AND CEMENTING
Figure 15. Thread
compound may be applied
over the entire suiface of the
casing threads just before
stabbing.
Stabbing
Stabbing is the process of guiding the end of the pipe into a coupling
or tool joint when making up a connection. "When stabbed, the cas
ing should be lowered carefully
to avoid damaging the threads.
Casing should be stabbed vertically, preferably
with the assis
tance
of the derrickhand on the stabbing board. If the pipe misses
the coupling or tool joint, it should be lifted and stabbed again.
Attempting
to roll the pin into the box or coupling may damage
the threads
or seals and jeopardize the connection.
Drilling engineers recommend removing mill-installed cou
plings from the
bottom four to six joints of casing prior to stabbing,
then thoroughly cleaning the threads and reinstalling the cou-plings
with a good thread compound
to prevent joint back-off.
If necessary, thread compound should be applied over the
entire surface
of the casing threads just before stabbing (fig. 15).
Thread compound, also known as pipe dope, consists of solid particles
of copper, zinc, or graphite suspended in a lubricant. The lubricant
acts to prevent
galling, or fusion of metal due to excessive friction.
Applying thread compound may be necessary because even when
couplings are assembled
as tightly as possible, a small channel
sometimes occurs between the top
of the thread and the bottom of
the groove into which it fits. Fluid may be able to leak through this
channel
if it runs the length of the connection. Thread compound
blocks the channel and forms a complete seal in the connection.
Thread compound is mixed on the job site immediately prior
to running casing. The paste-like mixture hardens quickly. After
the compound
is spread on the first two-thirds of a casing joint's
male threads, the joint
is tightened to specified tightness. "When
the thread compound hardens, breaking the connection becomes
four times harder than making
it up. Thread compound is applied
with a brush, which should be kept free
of foreign matter. The
compound should not be thinned.
Making Up
One of the most important steps in running casing is makeup.
After a joint
of casing has been stabbed, conventional or power
casing tongs are used
to make it up, or screw it into another joint
and tighten
it to a predetermined torque (fig. 16). Applying the
CASING
Figure I 6. Hydraulic
power tongs are placed
around a joint of casing
to make it up to a
predetermined
torque.
(Courtesy of Hydril)
Figure 15. Thread
compound may be applied
over the entire suiface of the
casing threads just before
stabbing.
Stabbing
Stabbing is the process of guiding the end of the pipe into a coupling
or tool joint when making up a connection. "When stabbed, the cas
ing should be lowered carefully
to avoid damaging the threads.
Casing should be stabbed vertically, preferably
with the assis
tance
of the derrickhand on the stabbing board. If the pipe misses
the coupling or tool joint, it should be lifted and stabbed again.
Attempting
to roll the pin into the box or coupling may damage
the threads
or seals and jeopardize the connection.
Drilling engineers recommend removing mill-installed cou
plings from the
bottom four to six joints of casing prior to stabbing,
then thoroughly cleaning the threads and reinstalling the cou-plings
with a good thread compound
to prevent joint back-off.
If necessary, thread compound should be applied over the
entire surface
of the casing threads just before stabbing (fig. 15).
Thread compound, also known as pipe dope, consists of solid particles
of copper, zinc, or graphite suspended in a lubricant. The lubricant
acts to prevent
galling, or fusion of metal due to excessive friction.
Applying thread compound may be necessary because even when
couplings are assembled
as tightly as possible, a small channel
sometimes occurs between the top
of the thread and the bottom of
the groove into which it fits. Fluid may be able to leak through this
channel
if it runs the length of the connection. Thread compound
blocks the channel and forms a complete seal in the connection.
Thread compound is mixed on the job site immediately prior
to running casing. The paste-like mixture hardens quickly. After
the compound
is spread on the first two-thirds of a casing joint's
male threads, the joint
is tightened to specified tightness. "When
the thread compound hardens, breaking the connection becomes
four times harder than making
it up. Thread compound is applied
with a brush, which should be kept free
of foreign matter. The
compound should not be thinned.
Making Up
One of the most important steps in running casing is makeup.
After a joint
of casing has been stabbed, conventional or power
casing tongs are used
to make it up, or screw it into another joint
and tighten
it to a predetermined torque (fig. 16). Applying the
CASING
Figure I 6. Hydraulic
power tongs are placed
around a joint of casing
to make it up to a
predetermined
torque.
(Courtesy of Hydril)
CASING AND CEMENTING
30
proper torque to the connection is one of the key factors to suc
cessfully running a casing string.
The joint should be made up at
least three turns beyond the hand-tight position for sizes 4½ to 7
in.(114 to
178 mm), and at least 3½ turns (89 mm turns) for sizes
7¾ in. (194 mm) or larger. Making up the casing slowly at first
will ensure that the threads are properly engaged.
Most casing tongs are powered hydraulically, but some are
run by compressed
air. The power tong dies should be clean and
sharp to prevent the pipe body from slipping and tearing.
The dies
should be cleaned and inspected periodically during running.
Recommendations for casing makeup are published in API RP
5C1,
Care and Use of Casing and Tubing, 18th Edition, issued May
1999. Therecommendations cover makeup with both conventional
and power tongs.
The specifications also cover recommended
makeup torques and procedures for pulling a string
of casing.
Lowering
Casing should be lowered into the well one joint at a time. For
long casing strings, slip elevators (spiders) are recommended (fig.
17 ). The spiders should be clean, sharp, and extra long for heavy
casing strings.
Once a joint
is resting in the V-door, the box protector may
be removed from collared pipe.
An elevator plug, when used,
should be left in the box until the joint
is made up and lowered to
the floor.
The protector or elevator plug should be removed from
the box in the rotary.
The box should then be thoroughly doped
with a suitable thread compound.
When an automatic fill-up shoe is used, its operation should
be checked to verify proper functioning. Lowering the casing string
should never be stopped abruptly, because the dynamic loads as
sociated with braking quickly increase the total load
on the string.
Nor should the slips be used to slow down and stop pipe, because
that could damage both pipe and slips.
Figure 17. Casing elevators and casing spider support the casing as it
is being lowered into the well.
30
proper torque to the connection is one of the key factors to suc
cessfully running a casing string.
The joint should be made up at
least three turns beyond the hand-tight position for sizes 4½ to 7
in.(114 to
178 mm), and at least 3½ turns (89 mm turns) for sizes
7¾ in. (194 mm) or larger. Making up the casing slowly at first
will ensure that the threads are properly engaged.
Most casing tongs are powered hydraulically, but some are
run by compressed
air. The power tong dies should be clean and
sharp to prevent the pipe body from slipping and tearing.
The dies
should be cleaned and inspected periodically during running.
Recommendations for casing makeup are published in API RP
5C1,
Care and Use of Casing and Tubing, 18th Edition, issued May
1999. Therecommendations cover makeup with both conventional
and power tongs.
The specifications also cover recommended
makeup torques and procedures for pulling a string
of casing.
Lowering
Casing should be lowered into the well one joint at a time. For
long casing strings, slip elevators (spiders) are recommended (fig.
17 ). The spiders should be clean, sharp, and extra long for heavy
casing strings.
Once a joint
is resting in the V-door, the box protector may
be removed from collared pipe.
An elevator plug, when used,
should be left in the box until the joint
is made up and lowered to
the floor.
The protector or elevator plug should be removed from
the box in the rotary.
The box should then be thoroughly doped
with a suitable thread compound.
When an automatic fill-up shoe is used, its operation should
be checked to verify proper functioning. Lowering the casing string
should never be stopped abruptly, because the dynamic loads as
sociated with braking quickly increase the total load
on the string.
Nor should the slips be used to slow down and stop pipe, because
that could damage both pipe and slips.
Figure 17. Casing elevators and casing spider support the casing as it
is being lowered into the well.
CASING AND CEMENTING
32
Landing Landing the casing involves transferring the casing string weight
to
the wellhead, usually with a casing hanger that seats in the cas
inghead and seals the annulus between the outer and inner strings
(fig. r
8). Keys to successful landing are minimizing the amount
of stress placed on the other casing strings and the effects on the
string
of casing being slacked off.
The hanging load (the amount of weight transferred to the
casinghead) must take into account the strength
of the outer casing
strings and the load-carrying capacity
of the casinghead and casing
hanger.
The amount of slack-off must take into account the pos
sibility
of buckling the string. Similarly, the tensile strength of the
casing must be considered
if additional pull-up strain is taken.
TUBING
HANGER
TUBING
HEAD
TUBING
CASING
HANGER
CASING HEAD
INNER
2
CASING
INTERMEDIATE
CASING
SEALING
MEDIUM
CASING
HANGER
CASING HEAD
1
OUTER
CASING
Figure I 8. Landing the casing involves transferring the casing string
weight
to the wellhead, usually with a casing hanger that seats in the
casinghead and seals the annulus between the outer and inner strings.
The effects of slack-off on collapse or burst resistance must
also be considered. Casing
is in tension at the wellhead when it is
cemented, and it is subject to stretch as a result of its own weight.
An API committee on casing landing practices recommended
that when casing is landed, the weight on the casing hanger should
be the same
as the weight supported by the elevator (i.e., no weight
should be slacked off
or picked up). This recommendation has been
applied
to all wells where:
• mud weight was less than r
2. 5 pounds per gallon (ppg) ( r ,498
kilograms
per cubic metre, kg/m3);
• standard design factors
of tension and compression were
employed;
• wellhead equipment could support the load without damage
to the casing; and
• the surface casing could withstand the loads in compression
without failure, taking into consideration additional loads
brought about by future operations.
This analysis requires some estimate of the future produc
ing conditions in the well. The committee recognized that special
cases require special engineering analyses and special treatments
depending
on the circumstances involved.
Considering the amount
of slack off or pickup is particularly
important when landing casing
in a deep well, because hanging
loads are greater, m~re stretch
is involved, and temperature changes
can be excessive.
CASING
33
32
Landing Landing the casing involves transferring the casing string weight
to
the wellhead, usually with a casing hanger that seats in the cas
inghead and seals the annulus between the outer and inner strings
(fig. r
8). Keys to successful landing are minimizing the amount
of stress placed on the other casing strings and the effects on the
string
of casing being slacked off.
The hanging load (the amount of weight transferred to the
casinghead) must take into account the strength
of the outer casing
strings and the load-carrying capacity
of the casinghead and casing
hanger.
The amount of slack-off must take into account the pos
sibility
of buckling the string. Similarly, the tensile strength of the
casing must be considered
if additional pull-up strain is taken.
TUBING
HANGER
TUBING
HEAD
TUBING
CASING
HANGER
CASING HEAD
INNER
2
CASING
INTERMEDIATE
CASING
SEALING
MEDIUM
CASING
HANGER
CASING HEAD
1
OUTER
CASING
Figure I 8. Landing the casing involves transferring the casing string
weight
to the wellhead, usually with a casing hanger that seats in the
casinghead and seals the annulus between the outer and inner strings.
The effects of slack-off on collapse or burst resistance must
also be considered. Casing
is in tension at the wellhead when it is
cemented, and it is subject to stretch as a result of its own weight.
An API committee on casing landing practices recommended
that when casing is landed, the weight on the casing hanger should
be the same
as the weight supported by the elevator (i.e., no weight
should be slacked off
or picked up). This recommendation has been
applied
to all wells where:
• mud weight was less than r
2. 5 pounds per gallon (ppg) ( r ,498
kilograms
per cubic metre, kg/m3);
• standard design factors
of tension and compression were
employed;
• wellhead equipment could support the load without damage
to the casing; and
• the surface casing could withstand the loads in compression
without failure, taking into consideration additional loads
brought about by future operations.
This analysis requires some estimate of the future produc
ing conditions in the well. The committee recognized that special
cases require special engineering analyses and special treatments
depending
on the circumstances involved.
Considering the amount
of slack off or pickup is particularly
important when landing casing
in a deep well, because hanging
loads are greater, m~re stretch
is involved, and temperature changes
can be excessive.
CASING
33
CASING AND CEMENTING
34
How Temperature Affects Landing Casing
When tubing or casing is hanging in a well, if the strings
are
fixed at both ends, for every degree Fahrenheit change
in the temperature
of the pipe, there will be a 207-psi
(1,427-kPa) change in metal stress for each square inch
of
cross section. For example, consider 7-inch (178-mm), 26
lb/ft (38.7 kg/m) casing landed with 200,000 pounds (lbs)
(90,720
kg) on the casinghead and an average temperature
of r 50°F (65.5°C). This size and weight of pipe has a cross
section
of 7. 5 5 square inches (in.
2
)
(49 square centimetres
or cm
2
). If the casing cools off 40°F (4.4 °C), the string will
contract and the load on the casing hanger will increase
by an amount equal to
40°F x 7.55
in.2 x 207 psi= 62,500 lbs
(4.4°C
X 49 cm
2
X 1,427 kPa = 28,350 kg)
This amount should be added to the load on the hanger,
for a total load
of 262,500 lbs (r 19,070 kg) on the casing
hanger. APIJ-5 5 couplings have a yield strength
of 3 67 ,ooo
lbs ( r 6,647
kg), so the pipe will not pull apart. However,
the safety factor in tension will be lowered considerably.
On the other hand, if hot salt water is produced through
the string and the temperature rises 40°F (4.4°C), the same
numerical change
of tension will occur but in the opposite
direction. Tension at the wellhead in this instance will be
200,000 lbs (90,720
kg) less 62,500 lbs (28,350 kg). This
change in tension will tend to reduce the stretch in the
pipe and could conceivably cause the string to buckle
if it
is not fully supported by cement.
It is impossible to completely anticipate all the physical changes that
may occur during the life of a producing well. For this reason, the
API recommends landing the casing at the wellhead in exactly the
same position
as when it was cemented. The usual design factors
for tension, burst, and collapse have sufficient safety margins
to
handle most of the load changes that occur. If casing is being run
in a very deep well where temperature or pressure may fluctuate
widely, technical experts should
be consulted.
Most larger sizes of conductor and surface casing can handle
sizable compressive loads, particularly
if they have been cemented
or driven into place properly. Most API casing is assumed to be
able to carry as much load in compression, when laterally sup
ported,
as its rating in tension. If for some reason the compression
load is
too much and the full weight of the inner strings cannot
be supported by the outer strings, one or more of the following
procedures should be considered:
r. slack
off part of the weight of the inner string and hang
only part of the weight;
2. attempt to cement the inner string back to the surface,
so
as to have cement to support the load;
3. use a downhole hanger in order to hang some of the
weight on the outer string down the well and the re
mainder
at the casing hanger (fig. 19); or
4. consider running the lower part of the string as a liner,
and tie back
the upper section that would be lighter than
the original whole string.
ALL INTERMEDIATE 9%-INCH
CASING WEIGHT INTERMEDIATE
HANGS HERE -/
--_--_-__ -_-_-___ -_CASING
, ·
.· 13%-INCH
-. SURFACE
CASING
VERY SOFT
SURFACE
FORMATION
E PIPE
MAY
AUSEOF
ADS, LACK
RAL
T
KLES
SE WEIGHT
LACKED OFF
CEMENTING.
OCCUR EASILY.
CEMENT
ONLY ENOUGH WEIGHT
HANGS HERE TO KEEP TOP
OF STRING STRAIGHT
MOST WEIGHT
HANGS HERE
WHERE CEMENT
IS GOOD AND
SURFACE PIPE
HAS LATERAL
SUPPORT
PIPE DOES
NOT BUCKLE
BECAUSE IT
WAS LANDED
AS CEMENTED
SUBSEQUENT
DRILLING IN THIS HOLE
MAY DAMAGE
BUCKLED CASING.
SUBSEQUENT
DRILLING DOES NOT
CAUSE UNUSUAL WEAR
OF STRAIGHT CASING.
CASING
Figure 19. Downhole
casing hangers are used to
relieve some of the load on·
the casinghead.
35
34
How Temperature Affects Landing Casing
When tubing or casing is hanging in a well, if the strings
are
fixed at both ends, for every degree Fahrenheit change
in the temperature
of the pipe, there will be a 207-psi
(1,427-kPa) change in metal stress for each square inch
of
cross section. For example, consider 7-inch (178-mm), 26
lb/ft (38.7 kg/m) casing landed with 200,000 pounds (lbs)
(90,720
kg) on the casinghead and an average temperature
of r 50°F (65.5°C). This size and weight of pipe has a cross
section
of 7. 5 5 square inches (in.
2
)
(49 square centimetres
or cm
2
). If the casing cools off 40°F (4.4 °C), the string will
contract and the load on the casing hanger will increase
by an amount equal to
40°F x 7.55
in.2 x 207 psi= 62,500 lbs
(4.4°C
X 49 cm
2
X 1,427 kPa = 28,350 kg)
This amount should be added to the load on the hanger,
for a total load
of 262,500 lbs (r 19,070 kg) on the casing
hanger. APIJ-5 5 couplings have a yield strength
of 3 67 ,ooo
lbs ( r 6,647
kg), so the pipe will not pull apart. However,
the safety factor in tension will be lowered considerably.
On the other hand, if hot salt water is produced through
the string and the temperature rises 40°F (4.4°C), the same
numerical change
of tension will occur but in the opposite
direction. Tension at the wellhead in this instance will be
200,000 lbs (90,720
kg) less 62,500 lbs (28,350 kg). This
change in tension will tend to reduce the stretch in the
pipe and could conceivably cause the string to buckle
if it
is not fully supported by cement.
It is impossible to completely anticipate all the physical changes that
may occur during the life of a producing well. For this reason, the
API recommends landing the casing at the wellhead in exactly the
same position
as when it was cemented. The usual design factors
for tension, burst, and collapse have sufficient safety margins
to
handle most of the load changes that occur. If casing is being run
in a very deep well where temperature or pressure may fluctuate
widely, technical experts should
be consulted.
Most larger sizes of conductor and surface casing can handle
sizable compressive loads, particularly
if they have been cemented
or driven into place properly. Most API casing is assumed to be
able to carry as much load in compression, when laterally sup
ported,
as its rating in tension. If for some reason the compression
load is
too much and the full weight of the inner strings cannot
be supported by the outer strings, one or more of the following
procedures should be considered:
r. slack
off part of the weight of the inner string and hang
only part of the weight;
2. attempt to cement the inner string back to the surface,
so
as to have cement to support the load;
3. use a downhole hanger in order to hang some of the
weight on the outer string down the well and the re
mainder
at the casing hanger (fig. 19); or
4. consider running the lower part of the string as a liner,
and tie back
the upper section that would be lighter than
the original whole string.
ALL INTERMEDIATE 9%-INCH
CASING WEIGHT INTERMEDIATE
HANGS HERE -/
--_--_-__ -_-_-___ -_CASING
, ·
.· 13%-INCH
-. SURFACE
CASING
VERY SOFT
SURFACE
FORMATION
E PIPE
MAY
AUSEOF
ADS, LACK
RAL
T
KLES
SE WEIGHT
LACKED OFF
CEMENTING.
OCCUR EASILY.
CEMENT
ONLY ENOUGH WEIGHT
HANGS HERE TO KEEP TOP
OF STRING STRAIGHT
MOST WEIGHT
HANGS HERE
WHERE CEMENT
IS GOOD AND
SURFACE PIPE
HAS LATERAL
SUPPORT
PIPE DOES
NOT BUCKLE
BECAUSE IT
WAS LANDED
AS CEMENTED
SUBSEQUENT
DRILLING IN THIS HOLE
MAY DAMAGE
BUCKLED CASING.
SUBSEQUENT
DRILLING DOES NOT
CAUSE UNUSUAL WEAR
OF STRAIGHT CASING.
CASING
Figure 19. Downhole
casing hangers are used to
relieve some of the load on·
the casinghead.
35
CASING AND CEMENTING
API Standards The American Petroleum Institute (API) publishes specifications
for casing, tubing, and drill pipe.
These specifications are designed
only
as a guide to help purchasers obtain standardized equipment
and materials.
They are not designed to discourage purchase or
production of casing made to other specifications. API casing may
be
of either seamless or electric-resistance welded steel. Seamless
casing
is produced by running a solid square length of steel through
a series
of rollers and mandrels that form it into a straight, round
cylinder called a
billet. The billet is formed to an exact, specified
outside diameter, then pierced lengthwise to form a hollow tube.
Welded pipe
is produced by forming sheets of metal into hollow
tubes.
The edges of the tubes are welded together, and rollers
are used to straighten the pipe and size
it to the proper outside
diameter.
Length and Thickness
Minimum allowable wall thickness for casing is 87.5 percent of
the nominal wall thickness. API casing is designated by the length
range
of each joint (table 3). API Specification 5CT designates
casing by outside diameter, weight
per foot, grade of steel, wall
thickness, and type
of threads (table 4). Casing is most often run
in range 3 lengths.
Table 3
API Length Ranges of Casing
Length Minimum
Range, Length,
Range ft (m) ft (m)*
I 16-25 18
(4-9-7.6) (5.5)
2 25-35
28
(7.6-rn.6) (8.5)
3 35-48 36
(rn.6-14-6)
(II)
*Range length for 9 5 percent or more of a carload.
Source: AP! Specification 5CT
Maximum
Length
Variation,
ft (m)
6
(1.8)
5
(1.5)
6
(1.8)
(1) (2)
Designationb
Size Weight•
4½ 9.50
4½ 10.50
4½ 11.60
4½ 13.50
4½ 15.10
5 11.50
5 13.00
5 15.00
5 18.00
5 21.40
5 23.20
5 24.10
5½ 14.00
5½ 15.50
5½ 17.00
5½ 20.00
5½ 23.00
5½ 26.80
5½ 29.70
5½ 32.60
5½ 35.30
5½ 38.00
5½ 40.50
5½ 43.10
13% 48.00
13% 54.50
13% 61.00
13% 68.00
13% 72.00
16 64.00
16 75.00
16 84.00
16 109.00
18% 87.50
20 94.00
20 106.50
20 133.00
Table 4
Specification for Casing and Tubing (U.S. Customary Units)
API Casing List
(3) (4) (5) (6) (7) (8) (9) (10)
Type of
End Finish•
Outside Wall Grade Grade Grade
D
iameter Thickness Grade J55 Grade L80 Grade C9Qd
(in.) (in.) H40 K55 M65 C95 NBO T95d
4.500 0.205 PS PS PS
4.500 0.224 PSB PSB
4.500 0.250 PSLB PLB PLB PLB PLB
4.500 0.290 PLB PLB PLB PLB
4.500 0.337
5.000 0.220
PS PS
5.000 0.253 PSLB PSLB
5.000 0.296 PSLBE PLB PLBE PLBE PLBE
5.000 0.362 PLB PLBE PLBE PLBE
5.000 0.437 PLB PLB PLB PLB
5.000 0.478 PLB PLB PLB
5.000 0.500 PLB PLB PLB
5.500 0.244 PS PS PS
5.500 0.275 PSLBE PSLB
5.500 0.304 PSLBE PLB PLBE PLBE PLBE
5.500 0.361 PLB PLBE PLBE PLBE
5.500 0.415 PLB PLBE PLBE PLBE
5.500 0.500 p
5.500 0.562 p
5.500 0.625 p
5.500 0.687
p
5.500 0.750 p
5.500 0.812 p
5.500 0.875 p
13.375 0.330
PS
13.375 0.380 PSB PSB
13.375 0.430 PSB PSB
13.375 0.480 PSB PSB PSB PSB PSB
13.375 0.514 PSB PSB PSB
16.000 0.375 PS
16.000 0.438 PSB PSB
16.000 0.495 PSB PSB
16.000 0.656 p p p
18.625 0.435 PS PSB PSB
20.000 0.438 PSL PSLB PSLB
20.000 0.500 PSLB PSLB
20.000 0.635 PSLB
• P = plain-end; S = short round thread; L = long round thread; B = buttress thread; E = extreme-line
b Designations (columns 1 and 2) are shown for the purpose of identification in ordering.
(II) (12)
Grade G r ade
P110 Q125
PLB
PLB
PLB
PLB
PLBE
PLBE
PLBE
PLB PLB
PLB
PLB
PLB PLB
PLBE
PLBE
PLBE
PLBE PLBE
PSB
PSB
PSB
p p
c The densities of martensitic chromium steels (180 types 9Cr and 13Cr) are different from carbon steels. The weights shown are therefore
not accurate for martensitic chromium steels. A weight correction factor of 0. 989 may be used.
d Grade C90 and Grade T9 5 casing shall be furnished in sizes, weights, and wall thicknesses listed above or as shown on the purchase order.
API Standards The American Petroleum Institute (API) publishes specifications
for casing, tubing, and drill pipe.
These specifications are designed
only
as a guide to help purchasers obtain standardized equipment
and materials.
They are not designed to discourage purchase or
production of casing made to other specifications. API casing may
be
of either seamless or electric-resistance welded steel. Seamless
casing
is produced by running a solid square length of steel through
a series
of rollers and mandrels that form it into a straight, round
cylinder called a
billet. The billet is formed to an exact, specified
outside diameter, then pierced lengthwise to form a hollow tube.
Welded pipe
is produced by forming sheets of metal into hollow
tubes.
The edges of the tubes are welded together, and rollers
are used to straighten the pipe and size
it to the proper outside
diameter.
Length and Thickness
Minimum allowable wall thickness for casing is 87.5 percent of
the nominal wall thickness. API casing is designated by the length
range
of each joint (table 3). API Specification 5CT designates
casing by outside diameter, weight
per foot, grade of steel, wall
thickness, and type
of threads (table 4). Casing is most often run
in range 3 lengths.
Table 3
API Length Ranges of Casing
Length Minimum
Range, Length,
Range ft (m) ft (m)*
I 16-25 18
(4-9-7.6) (5.5)
2 25-35
28
(7.6-rn.6) (8.5)
3 35-48 36
(rn.6-14-6)
(II)
*Range length for 9 5 percent or more of a carload.
Source: AP! Specification 5CT
Maximum
Length
Variation,
ft (m)
6
(1.8)
5
(1.5)
6
(1.8)
(1) (2)
Designationb
Size Weight•
4½ 9.50
4½ 10.50
4½ 11.60
4½ 13.50
4½ 15.10
5 11.50
5 13.00
5 15.00
5 18.00
5 21.40
5 23.20
5 24.10
5½ 14.00
5½ 15.50
5½ 17.00
5½ 20.00
5½ 23.00
5½ 26.80
5½ 29.70
5½ 32.60
5½ 35.30
5½ 38.00
5½ 40.50
5½ 43.10
13% 48.00
13% 54.50
13% 61.00
13% 68.00
13% 72.00
16 64.00
16 75.00
16 84.00
16 109.00
18% 87.50
20 94.00
20 106.50
20 133.00
Table 4
Specification for Casing and Tubing (U.S. Customary Units)
API Casing List
(3) (4) (5) (6) (7) (8) (9) (10)
Type of
End Finish•
Outside Wall Grade Grade Grade
D
iameter Thickness Grade J55 Grade L80 Grade C9Qd
(in.) (in.) H40 K55 M65 C95 NBO T95d
4.500 0.205 PS PS PS
4.500 0.224 PSB PSB
4.500 0.250 PSLB PLB PLB PLB PLB
4.500 0.290 PLB PLB PLB PLB
4.500 0.337
5.000 0.220
PS PS
5.000 0.253 PSLB PSLB
5.000 0.296 PSLBE PLB PLBE PLBE PLBE
5.000 0.362 PLB PLBE PLBE PLBE
5.000 0.437 PLB PLB PLB PLB
5.000 0.478 PLB PLB PLB
5.000 0.500 PLB PLB PLB
5.500 0.244 PS PS PS
5.500 0.275 PSLBE PSLB
5.500 0.304 PSLBE PLB PLBE PLBE PLBE
5.500 0.361 PLB PLBE PLBE PLBE
5.500 0.415 PLB PLBE PLBE PLBE
5.500 0.500 p
5.500 0.562 p
5.500 0.625 p
5.500 0.687
p
5.500 0.750 p
5.500 0.812 p
5.500 0.875 p
13.375 0.330
PS
13.375 0.380 PSB PSB
13.375 0.430 PSB PSB
13.375 0.480 PSB PSB PSB PSB PSB
13.375 0.514 PSB PSB PSB
16.000 0.375 PS
16.000 0.438 PSB PSB
16.000 0.495 PSB PSB
16.000 0.656 p p p
18.625 0.435 PS PSB PSB
20.000 0.438 PSL PSLB PSLB
20.000 0.500 PSLB PSLB
20.000 0.635 PSLB
• P = plain-end; S = short round thread; L = long round thread; B = buttress thread; E = extreme-line
b Designations (columns 1 and 2) are shown for the purpose of identification in ordering.
(II) (12)
Grade G r ade
P110 Q125
PLB
PLB
PLB
PLB
PLBE
PLBE
PLBE
PLB PLB
PLB
PLB
PLB PLB
PLBE
PLBE
PLBE
PLBE PLBE
PSB
PSB
PSB
p p
c The densities of martensitic chromium steels (180 types 9Cr and 13Cr) are different from carbon steels. The weights shown are therefore
not accurate for martensitic chromium steels. A weight correction factor of 0. 989 may be used.
d Grade C90 and Grade T9 5 casing shall be furnished in sizes, weights, and wall thicknesses listed above or as shown on the purchase order.
CASING AND CEMENflNG
Yield and Tensile Strength
Steel used in API casing must conform to specifications covering
chemical and physical properties. Steel is an elastic material
that
stretches as longitudinal stress is applied. If the longitudinal stress
is less than
yield strength (the amount of force needed to perma
nently distort
the pipe), the steel will return to its original length
when the stress is removed.
On the other hand, if the longitudinal
stress
is greater than the yield strength, the steel will be plastically
deformed and will
not return to its original size and shape.
Tensile strength is the greatest longitudinal stress a substance
can bear without tearing apart. Casing
is tested at the mill for
chemical composition and yield and tensile strength.
For testing,
yield strength is defined
as the longitudinal stress required to pro
duce a total elongation of o. 5 percent of the length. Certain grades
must be tested for
other qualities such as hardness, grain siz~, and
toughness. API specifications for tensile strength requirements
are given
in table 5.
Flattening
Welded pipe requires flattening tests. These tests are performed
on each heat of steel used when producing welded pipe, on either
a full section
of pipe or a strip cut from the pipe. Strip specimens
must be a specified size depending on the size of the pipe, and
must be taken from a section of pipe representing the full wall
thickness
of the pipe. The strip specimens should be tested without
flattening.
(r)
Group
1
2
3
4-
Table 5
Specification for Casing and Tubing (U.S. Customary Units)
Tensile and Hardness Requirements
(2) (3) (4) (5) (6) (7) (8)
Yield Tensile Specified
Strength Strength Hardness Wall
Maximum Maximum Minimum Maximuma Thickness
Grade Type (psi) (psi) (psi) HRC BHN (inches)
H40 40,000 80,000 60,000
]55 55,000 80,000 75,000
K55 55,000 80,000 95,000
N80 80,000 110,000 100,000
M65 65,000 85,000 85,000
22 235
L80 1 80,000 95,000 95,000
23 241
L80 9Cr 80,000 95,000 95,000 23 241
L80 13Cr 80,000 95,000 95,000 23 241
C90 1, 2 90,000 105,000 100,000 25.4 255 0.5000
or less
C90
1,2 90,000 105,000 100,000 25.4 255 0.501 to
0.749
C90
1,2 90,000 105,000 100,000 25.4 255 0.750 to
0.999
C90
1, 2 90,000 105,000 100,000 25.4 255 1.000 and
above
C95 95,000 110,000 105,000
T95 1, 2 95,000 110,000 105,000 25.4 255 0.5000
or less
T95 1,2 95,000 110,000 105,000 25.4 255 0.501 to
0.749
T95 1,2 95,000 110,000 105,000 25.4 255 0.750 to
0.999
PllO 110,000 140,000 125,000
Q125 1-4 125,000 150,000 135,000 0.5000
or less
Q125 1-4 125,000 150,000 135,000 0.501 to
0.749
Q125 1-4 125,000 150,000 135,000 0.750 and
above
•
In case of dispute, laboratory Rockwell C hardness tests shall be used as the reference method.
Source: AP! Specification 5 CT
(9)
Allowable
Hardness
Variation
HRC
3.0
4.0
5.0
6.0
3.0
4.0
5.0
3.0
4.0
5.0
Yield and Tensile Strength
Steel used in API casing must conform to specifications covering
chemical and physical properties. Steel is an elastic material
that
stretches as longitudinal stress is applied. If the longitudinal stress
is less than
yield strength (the amount of force needed to perma
nently distort
the pipe), the steel will return to its original length
when the stress is removed.
On the other hand, if the longitudinal
stress
is greater than the yield strength, the steel will be plastically
deformed and will
not return to its original size and shape.
Tensile strength is the greatest longitudinal stress a substance
can bear without tearing apart. Casing
is tested at the mill for
chemical composition and yield and tensile strength.
For testing,
yield strength is defined
as the longitudinal stress required to pro
duce a total elongation of o. 5 percent of the length. Certain grades
must be tested for
other qualities such as hardness, grain siz~, and
toughness. API specifications for tensile strength requirements
are given
in table 5.
Flattening
Welded pipe requires flattening tests. These tests are performed
on each heat of steel used when producing welded pipe, on either
a full section
of pipe or a strip cut from the pipe. Strip specimens
must be a specified size depending on the size of the pipe, and
must be taken from a section of pipe representing the full wall
thickness
of the pipe. The strip specimens should be tested without
flattening.
(r)
Group
1
2
3
4-
Table 5
Specification for Casing and Tubing (U.S. Customary Units)
Tensile and Hardness Requirements
(2) (3) (4) (5) (6) (7) (8)
Yield Tensile Specified
Strength Strength Hardness Wall
Maximum Maximum Minimum Maximuma Thickness
Grade Type (psi) (psi) (psi) HRC BHN (inches)
H40 40,000 80,000 60,000
]55 55,000 80,000 75,000
K55 55,000 80,000 95,000
N80 80,000 110,000 100,000
M65 65,000 85,000 85,000
22 235
L80 1 80,000 95,000 95,000
23 241
L80 9Cr 80,000 95,000 95,000 23 241
L80 13Cr 80,000 95,000 95,000 23 241
C90 1, 2 90,000 105,000 100,000 25.4 255 0.5000
or less
C90
1,2 90,000 105,000 100,000 25.4 255 0.501 to
0.749
C90
1,2 90,000 105,000 100,000 25.4 255 0.750 to
0.999
C90
1, 2 90,000 105,000 100,000 25.4 255 1.000 and
above
C95 95,000 110,000 105,000
T95 1, 2 95,000 110,000 105,000 25.4 255 0.5000
or less
T95 1,2 95,000 110,000 105,000 25.4 255 0.501 to
0.749
T95 1,2 95,000 110,000 105,000 25.4 255 0.750 to
0.999
PllO 110,000 140,000 125,000
Q125 1-4 125,000 150,000 135,000 0.5000
or less
Q125 1-4 125,000 150,000 135,000 0.501 to
0.749
Q125 1-4 125,000 150,000 135,000 0.750 and
above
•
In case of dispute, laboratory Rockwell C hardness tests shall be used as the reference method.
Source: AP! Specification 5 CT
(9)
Allowable
Hardness
Variation
HRC
3.0
4.0
5.0
6.0
3.0
4.0
5.0
3.0
4.0
5.0
CASING AND CEMENTING
The flattening test consists of placing the pipe between par
allel plates, with the weld
at the point of maximum bending, and
flattening the pipe until opposite walls meet. Flattening tests are
performed
on rings of pipe at least 2 ½ in. ( 63. 5 mm) long, cut from
each end
of each length of pipe. API specifications for flattening
tests are listed in table
6.
Table 6
Distance Between Plates for Electric Weld Flattening Tests
(1) (2) (3)
Die Ratio Min. Distance Between
Grade in. (mm) Plates,in. (mm)
H40 16 and over 0.5 D
(406 and over) (12.7)
Less
than 16 D -0.830-0.0206 Dlt
(Less than 406) (21.1-.52 32)
]55 & K55 16 and over 0.65 D
(406 and over) (16.51)
3.93
to 16 D -0.980-0.0206 Dlt
(100 to 406) (24,9-.52 32)
Less than 3.93 D-1.104-0.0518 Dlt
(Less than 1 oo) (28.04-1.316)
M65 All D-1.074-0.0194 Dlt
(2 7.28--493)
N8ob 9
to 28 D-1.074-0.0194 Dlt
(229 to 711) (2 7.28-.493)
L8o 9 to 28 D-1.074-0.0194 Dlt
(229 to 7u) (2 7 ·2 8-.493)
C95b 9
to 28 D-1.074-0.0194 Dlt
(229 to 7u) (27,28-.493)
P110 All D -1.086-0.0163 Dlt
(2 7 .6-.414)
Q125c All D -1.092-0.014 Dlt
(27.74-.356)
a D -the specified outside diameter of pipe, in in. (mm); t = the specified wall
thickness
of the pipe, in in. (mm)
b If the flattening test fails at r 2 or 6 o'clock, the flattening shall continue until
the remaining portion
of the specimen falls at the 3 or 9 o'clock position. Pre
mature failure at r
2 or 6 o'clock shall not be considered basis for rejection.
c See SRII. Flattening shall be at least 0185D.
Source: API Specification 5CT
Leakage
API specifies that each length of casing be tested for leakage to a
given hydrostatic pressure.
The test pressure on casing up to 10¾
in. (2 73 mm) in diameter must be sufficient to. produce a fiber
stress equal to 80 percent
of the minimum yield strength of the
steel. Pipe larger than ro¾ in.
(273 mm) is subjected to test pres
sure that
is sufficient to produce a fiber stress equal to 60 percent
of the minimum yield strength. ·
To
summarize
Running casing
• keep thread protectors in place until ready to stab casing
• do
not use pointed hooks to lift casing
• clean and inspect all threads and couplings
• use rope slings to control pipe
as it is rolled down skids
• place adequate spacers (stringers) between layers
of casing
while
on rack
• measure (tally) the length
of each joint and number it prior
to running
• run a rabbit
(a drift) through each joint to ensure that it is
not bent or scaled
• condition the hole prior to running casing
• fill each joint of casing with mud as it is lowered into the well
• check to ensure that each casing joint displaces the correct
volume
of mud when it is lowered into the hole
• lower casing into the hole slowly
• periodically circulate mud through the casing
as it is run
into the hole
• apply thread compound to casing shoe, casing float coll~r,
and first few joints
of casing above float collar to prevent its
being backed off
as the shoe is drilled out
• apply proper torque when making up casing joints
• when landing casing, do
not overload the casing hanger
CASING
41
The flattening test consists of placing the pipe between par
allel plates, with the weld
at the point of maximum bending, and
flattening the pipe until opposite walls meet. Flattening tests are
performed
on rings of pipe at least 2 ½ in. ( 63. 5 mm) long, cut from
each end
of each length of pipe. API specifications for flattening
tests are listed in table
6.
Table 6
Distance Between Plates for Electric Weld Flattening Tests
(1) (2) (3)
Die Ratio Min. Distance Between
Grade in. (mm) Plates,in. (mm)
H40 16 and over 0.5 D
(406 and over) (12.7)
Less
than 16 D -0.830-0.0206 Dlt
(Less than 406) (21.1-.52 32)
]55 & K55 16 and over 0.65 D
(406 and over) (16.51)
3.93
to 16 D -0.980-0.0206 Dlt
(100 to 406) (24,9-.52 32)
Less than 3.93 D-1.104-0.0518 Dlt
(Less than 1 oo) (28.04-1.316)
M65 All D-1.074-0.0194 Dlt
(2 7.28--493)
N8ob 9
to 28 D-1.074-0.0194 Dlt
(229 to 711) (2 7.28-.493)
L8o 9 to 28 D-1.074-0.0194 Dlt
(229 to 7u) (2 7 ·2 8-.493)
C95b 9
to 28 D-1.074-0.0194 Dlt
(229 to 7u) (27,28-.493)
P110 All D -1.086-0.0163 Dlt
(2 7 .6-.414)
Q125c All D -1.092-0.014 Dlt
(27.74-.356)
a D -the specified outside diameter of pipe, in in. (mm); t = the specified wall
thickness
of the pipe, in in. (mm)
b If the flattening test fails at r 2 or 6 o'clock, the flattening shall continue until
the remaining portion
of the specimen falls at the 3 or 9 o'clock position. Pre
mature failure at r
2 or 6 o'clock shall not be considered basis for rejection.
c See SRII. Flattening shall be at least 0185D.
Source: API Specification 5CT
Leakage
API specifies that each length of casing be tested for leakage to a
given hydrostatic pressure.
The test pressure on casing up to 10¾
in. (2 73 mm) in diameter must be sufficient to. produce a fiber
stress equal to 80 percent
of the minimum yield strength of the
steel. Pipe larger than ro¾ in.
(273 mm) is subjected to test pres
sure that
is sufficient to produce a fiber stress equal to 60 percent
of the minimum yield strength. ·
To
summarize
Running casing
• keep thread protectors in place until ready to stab casing
• do
not use pointed hooks to lift casing
• clean and inspect all threads and couplings
• use rope slings to control pipe
as it is rolled down skids
• place adequate spacers (stringers) between layers
of casing
while
on rack
• measure (tally) the length
of each joint and number it prior
to running
• run a rabbit
(a drift) through each joint to ensure that it is
not bent or scaled
• condition the hole prior to running casing
• fill each joint of casing with mud as it is lowered into the well
• check to ensure that each casing joint displaces the correct
volume
of mud when it is lowered into the hole
• lower casing into the hole slowly
• periodically circulate mud through the casing
as it is run
into the hole
• apply thread compound to casing shoe, casing float coll~r,
and first few joints
of casing above float collar to prevent its
being backed off
as the shoe is drilled out
• apply proper torque when making up casing joints
• when landing casing, do
not overload the casing hanger
CASING
41
CASING AND CEMENTING
42
Casing Threads
and Couplings
Figure 20. Casing with
a
coupling (A) and a
threaded end (B)
API casing is available with either plain or threaded ends, with or
without the following couplings (fig. 20):
1. round short;
2. round long;
3. buttress;
4. buttress S.C. (short couplings);
5. X-line.
Casingcouplingsareusuallyscrewedontothepipepower-tight
(fig. 21). However, they may be screwed on handling-tight (that is,
tight enough that a wrench must be used for removal) to make
it
easier to remove them for cleaning and inspecting threads and
applying fresh thread compound before the pipe
is used.
CASING
i-..--_... __ -----_
Power-Tight
Makeup
API ROUND
Handling-Tight
Makeup
c:... J -~
I -~----
Power-Tight
Makeup
C..
APIBUTTRESS
7
API ROUND-THREAD CASING
~-
= FLUSH JOINT CASING
Handling-Tight
Makeup
L,..-__________________________ __:"':::~"":;;;;J-J"""'\....._ _ ___.
FLUSH JOINT INTEGRATED
~--,___=-' ________________ :J -
INTEGRATED SWAGED
r-----~c:~=-~-------------------------
--~
INTEGRATED SWAGED
Figure 21. Examples of API-threaded connections (Courtery of Hydril)
43
42
Casing Threads
and Couplings
Figure 20. Casing with
a
coupling (A) and a
threaded end (B)
API casing is available with either plain or threaded ends, with or
without the following couplings (fig. 20):
1. round short;
2. round long;
3. buttress;
4. buttress S.C. (short couplings);
5. X-line.
Casingcouplingsareusuallyscrewedontothepipepower-tight
(fig. 21). However, they may be screwed on handling-tight (that is,
tight enough that a wrench must be used for removal) to make
it
easier to remove them for cleaning and inspecting threads and
applying fresh thread compound before the pipe
is used.
CASING
i-..--_... __ -----_
Power-Tight
Makeup
API ROUND
Handling-Tight
Makeup
c:... J -~
I -~----
Power-Tight
Makeup
C..
APIBUTTRESS
7
API ROUND-THREAD CASING
~-
= FLUSH JOINT CASING
Handling-Tight
Makeup
L,..-__________________________ __:"':::~"":;;;;J-J"""'\....._ _ ___.
FLUSH JOINT INTEGRATED
~--,___=-' ________________ :J -
INTEGRATED SWAGED
r-----~c:~=-~-------------------------
--~
INTEGRATED SWAGED
Figure 21. Examples of API-threaded connections (Courtery of Hydril)
43
=
-------------------------==::::_-,.::1:;J.--.............. ____ __.
INTEGRATED SWAGED
C==~ ~=d
~--:1---..,..c----
-------
COUPLED
~----------------_ -_ -_ -____.
INTEGRATED SWAGED
FLUSH-JOINT INTEGRAL
----------6-
INTEGRATED SWAGED
Figure 21. Continued
As wells are drilled deeper and downhole pressures become higher,
standard API connections do
not always have the pressure capac
ity, strength
in tension, or outer diameter clearance that well de
sign engineers require. To meet these special needs, a
number of
proprietary, or premium connections have been developed (fig. 22).
--..:::::a..--
HYDRIL SERIES 500 TYPE 503
HYDRIL
WT
HYDRIL SERIES 500 TYPE 511
CASING
Proprietary or
Premium Connections
... -.... _Jr-.,..._ _ ___,
=-..,.__ :_J ________ ....,
------------------------
HY DR IL MAC-II
r-----=c;;;;;:;~=------------------___ __,
HYDRIL SERIES 500 TYPE 521
C = ~--
~ 1..,________________ _ ______________ ___,
~ = d
----
HYDRIL SERIES 500 TYPE 563 TUBING
--------------------------======-_J...--...... _____ _
HYDRIL SUPREME LX
HYDRIL CS, PH-6, PH-4
Figure 22. Examples of premium-threaded connections (Counery of Hydril)
45
-------------------------==::::_-,.::1:;J.--.............. ____ __.
INTEGRATED SWAGED
C==~ ~=d
~--:1---..,..c----
-------
COUPLED
~----------------_ -_ -_ -____.
INTEGRATED SWAGED
FLUSH-JOINT INTEGRAL
----------6-
INTEGRATED SWAGED
Figure 21. Continued
As wells are drilled deeper and downhole pressures become higher,
standard API connections do
not always have the pressure capac
ity, strength
in tension, or outer diameter clearance that well de
sign engineers require. To meet these special needs, a
number of
proprietary, or premium connections have been developed (fig. 22).
--..:::::a..--
HYDRIL SERIES 500 TYPE 503
HYDRIL
WT
HYDRIL SERIES 500 TYPE 511
CASING
Proprietary or
Premium Connections
... -.... _Jr-.,..._ _ ___,
=-..,.__ :_J ________ ....,
------------------------
HY DR IL MAC-II
r-----=c;;;;;:;~=------------------___ __,
HYDRIL SERIES 500 TYPE 521
C = ~--
~ 1..,________________ _ ______________ ___,
~ = d
----
HYDRIL SERIES 500 TYPE 563 TUBING
--------------------------======-_J...--...... _____ _
HYDRIL SUPREME LX
HYDRIL CS, PH-6, PH-4
Figure 22. Examples of premium-threaded connections (Counery of Hydril)
45
CASING AND CEMENTING
HYDRIL SERIES 500 TYPE 563 CASING
---------::J-l
HYDRIL SERIES 500 TYPE 533
--------=---------------_-:_-_-_-....
HYDRIL SERIES 500 TYPE 501
C
~~----JL_ ]
HYDRIL SERIES 500 TYPE 553
⇒
HYDRIL SERIES S00TYPE 513
c::;
-~ _______________________ :::~=====;;;..;.~ ......... ______ ___.
Figure 22. Continued
HYDRIL SERIES 500 TYPE 523
These connections generally are distinguished from standard API
connections by one
or more of the following features:
• metal seals,
• torque shoulders,
• specialized thread forms,
•
O-ring seals,
• tight machining tolerances.
Premium connections are designed specifically to offer greater
tension capacity
or improved diametric clearance, and better leak
resistance than API connections. Premium connections can be
grouped by application and design.
Tubing Connections
Tubing connections fall into one of two categories:
• Coupled design-uses couplings to join two pin-threaded pipe
ends.
• Integral upset design-uses hot-forged upsets on pipe ends, one
pin-threaded and one box-threaded, to connect two joints.
Casing Connections
There are three types of premium casing connections:
• Coupled design-uses couplings to join two pin-threaded pipe
ends.
This type of connection usually is as strong as the pipe
body in tension and exhibits internal and external pressure
resistance.
• Flush-joint-the threaded connection is machined into
the wall
of the pipe body. This design is used in situations
where diametrical clearance
is very critical, such as drilling
liner applications.
This type of connection is only about 50
percent as strong as the pipe body.
• Slim-line integral design-uses a hydraulic press to cold-form
both box and pin, to expand the box and reduce the pin di
ameters.
This technique allows a connection with outer and
inner diameters very nearly that
of the pipe body, and with
between 60-80 percent
of the strength of the pipe body.
Large OD Connections
Larger-diameter casing, such as conductor pipe and surface cas
ing, requires special connections with different design criteria.
These connections can be machined directly onto the pipe or onto
forgings and welded on the pipe body. Design criteria for these
connections include high collapse and pressure ratings, and
in the
case
of conductor pipe, the ability to be driven rather than simply
lowered into a predrilled hole.
Riser Connections
The development of subsea completion technologies and floating
drilling and production facilities require connections that have fatigue
strength
as well as tension strength and pressure resistance. Connec
tions on casing and tubing that run between the seafloor and a floating
vessel are subjected to
wave motion and must be able to function after
experiencing millions
of cycles of wave-induced motion.
CASING
47
HYDRIL SERIES 500 TYPE 563 CASING
---------::J-l
HYDRIL SERIES 500 TYPE 533
--------=---------------_-:_-_-_-....
HYDRIL SERIES 500 TYPE 501
C
~~----JL_ ]
HYDRIL SERIES 500 TYPE 553
⇒
HYDRIL SERIES S00TYPE 513
c::;
-~ _______________________ :::~=====;;;..;.~ ......... ______ ___.
Figure 22. Continued
HYDRIL SERIES 500 TYPE 523
These connections generally are distinguished from standard API
connections by one
or more of the following features:
• metal seals,
• torque shoulders,
• specialized thread forms,
•
O-ring seals,
• tight machining tolerances.
Premium connections are designed specifically to offer greater
tension capacity
or improved diametric clearance, and better leak
resistance than API connections. Premium connections can be
grouped by application and design.
Tubing Connections
Tubing connections fall into one of two categories:
• Coupled design-uses couplings to join two pin-threaded pipe
ends.
• Integral upset design-uses hot-forged upsets on pipe ends, one
pin-threaded and one box-threaded, to connect two joints.
Casing Connections
There are three types of premium casing connections:
• Coupled design-uses couplings to join two pin-threaded pipe
ends.
This type of connection usually is as strong as the pipe
body in tension and exhibits internal and external pressure
resistance.
• Flush-joint-the threaded connection is machined into
the wall
of the pipe body. This design is used in situations
where diametrical clearance
is very critical, such as drilling
liner applications.
This type of connection is only about 50
percent as strong as the pipe body.
• Slim-line integral design-uses a hydraulic press to cold-form
both box and pin, to expand the box and reduce the pin di
ameters.
This technique allows a connection with outer and
inner diameters very nearly that
of the pipe body, and with
between 60-80 percent
of the strength of the pipe body.
Large OD Connections
Larger-diameter casing, such as conductor pipe and surface cas
ing, requires special connections with different design criteria.
These connections can be machined directly onto the pipe or onto
forgings and welded on the pipe body. Design criteria for these
connections include high collapse and pressure ratings, and
in the
case
of conductor pipe, the ability to be driven rather than simply
lowered into a predrilled hole.
Riser Connections
The development of subsea completion technologies and floating
drilling and production facilities require connections that have fatigue
strength
as well as tension strength and pressure resistance. Connec
tions on casing and tubing that run between the seafloor and a floating
vessel are subjected to
wave motion and must be able to function after
experiencing millions
of cycles of wave-induced motion.
CASING
47
CASING AND CEMENTING
Premium connections require special handling and running
techniques to prevent damaging metal seals and determine cor
rect makeup torques.
They offer improved performance over API
connections
but at increased cost.
To
summarize-
Casing couplings and threads include
• round short
• round long
• buttress
• buttress short couplings (SC)
• X-line
Premium connections feature
• metal seals
• torque shoulders
• specialized threads
•
0-ring seals
• high machine tolerances
Casing connections include
• coupled design
• flush joint
• slim-line integral design
As drilling and completion technologies have advanced, require
ments for tubular design have become more stringent. Slim-hole
applications, which make use
of flush and slim-line connections
to minimize hole and pipe size, can save money. However, these
applications require more careful design
of the ·tubular string to
avoid failures.
Other types of well development have spurred tubular
connection development. Wells are now commonly drilled with
horizontal sections. Multilateral wells have multiple horizontal
sections that reach into different production zones. Extended
reach wells have very long horizontal sections. These types
of well
designs place additional stresses
on the casing.
The simple design techniques presented here are rudimentary.
Much more sophisticated (and complicated) design techniques are
available. These techniques use methods such
as t:riaxialstress analysis
to calculate the combined loads that a casing or tubing string may
experience throughout the service
life of the well. (Triaxial analysis
uses the theory
of conservation of volume, which recognizes that
a change in
axial, radial, or hoop stress changes the capacity of
the material to react to stress in one or both of the other principal
directions.)
Finite Element Analysis (FEA) can model the reaction
of the pipe body or the connection to the forces estimated to be
in a well environment.
These techniques require experienced and specially trained
engineers,
as well as computers, for they are all computationally
demanding. To be economically feasible, the extra costs involved
in sophisticated casing design must result in savings in time, mate
rial, and reduced failures in the field.
As drilling and completion
technology continues to evolve, more and better engineering
of
connections will continue.
Changing
Technology
CASING
49
Premium connections require special handling and running
techniques to prevent damaging metal seals and determine cor
rect makeup torques.
They offer improved performance over API
connections
but at increased cost.
To
summarize-
Casing couplings and threads include
• round short
• round long
• buttress
• buttress short couplings (SC)
• X-line
Premium connections feature
• metal seals
• torque shoulders
• specialized threads
•
0-ring seals
• high machine tolerances
Casing connections include
• coupled design
• flush joint
• slim-line integral design
As drilling and completion technologies have advanced, require
ments for tubular design have become more stringent. Slim-hole
applications, which make use
of flush and slim-line connections
to minimize hole and pipe size, can save money. However, these
applications require more careful design
of the ·tubular string to
avoid failures.
Other types of well development have spurred tubular
connection development. Wells are now commonly drilled with
horizontal sections. Multilateral wells have multiple horizontal
sections that reach into different production zones. Extended
reach wells have very long horizontal sections. These types
of well
designs place additional stresses
on the casing.
The simple design techniques presented here are rudimentary.
Much more sophisticated (and complicated) design techniques are
available. These techniques use methods such
as t:riaxialstress analysis
to calculate the combined loads that a casing or tubing string may
experience throughout the service
life of the well. (Triaxial analysis
uses the theory
of conservation of volume, which recognizes that
a change in
axial, radial, or hoop stress changes the capacity of
the material to react to stress in one or both of the other principal
directions.)
Finite Element Analysis (FEA) can model the reaction
of the pipe body or the connection to the forces estimated to be
in a well environment.
These techniques require experienced and specially trained
engineers,
as well as computers, for they are all computationally
demanding. To be economically feasible, the extra costs involved
in sophisticated casing design must result in savings in time, mate
rial, and reduced failures in the field.
As drilling and completion
technology continues to evolve, more and better engineering
of
connections will continue.
Changing
Technology
CASING
49
Cementing
0
ilwell cementing is the process of mixing and placing a
cement slurry in the annular space between a string of casing
and the open hole. The cement sets, bonding the casing to the wall
of the wellbore for additional stability.
The practice of cementing began around 1903 in California.
Early methods of mixing cement and placing it in the hole were
quite crude. Modern cementing practices debuted in 1920, when
Erle Halliburton cemented a well in Oklahoma's Hewitt Field for
W.G. Skelly (fig. 2 3). Today, the Halliburton jet mixer remains a
basic device for rapid mixing
of drilling mud, although it is seldom
used for mixing
cement slurry.
In 1903 there was only one type of cement and no additives.
Today there are eight classes of cement and more than 40 different
additives. Bulk-cement
handling is standard practice, and blends
are tailored
to specific jobs. Waiting-on-cement time has been
reduced from IO days to less than 24 hours.
Figure 23. Halliburton cementing equipment from the r920s (Courtesy of Halliburton)
0
ilwell cementing is the process of mixing and placing a
cement slurry in the annular space between a string of casing
and the open hole. The cement sets, bonding the casing to the wall
of the wellbore for additional stability.
The practice of cementing began around 1903 in California.
Early methods of mixing cement and placing it in the hole were
quite crude. Modern cementing practices debuted in 1920, when
Erle Halliburton cemented a well in Oklahoma's Hewitt Field for
W.G. Skelly (fig. 2 3). Today, the Halliburton jet mixer remains a
basic device for rapid mixing
of drilling mud, although it is seldom
used for mixing
cement slurry.
In 1903 there was only one type of cement and no additives.
Today there are eight classes of cement and more than 40 different
additives. Bulk-cement
handling is standard practice, and blends
are tailored
to specific jobs. Waiting-on-cement time has been
reduced from IO days to less than 24 hours.
Figure 23. Halliburton cementing equipment from the r920s (Courtesy of Halliburton)
CASING AND CEMENTING
Primary Cementing
Basics
52
There are three types of oilwell cementing. Primary cement
ing
is performed immediately after the casing has been run into
the hole, to seal and separate each zone, and to protect the pipe.
Secondary cementing is performed after the primary cement job,
usually
as part of a well servicing or workover operation. Plug
ging back to another producing zone, plugging a dry hole, and
formation squeeze cementing are examples
of secondary cement
ing procedures.
Squeeze cementing involves forcing cement to the
bottom
of the casing and up the annular space between the casing
and the wall
of the borehole to seal off a formation or plug a leak
in the casing. Squeeze cementing was introduced in the 1930s and
is now a common procedure for plugging perforations or shut
ting off water.
The discussion in this book is limited to primary
cementing.
Although several methods
of primary cementing exist, single-stage
and multistage cementing are the most commonly used.
Single
stage cementing, the most common cementing procedure, consists
of pumping a calculated volume of slurry into casing, after pipe has
been landed at the desired depth, and displacing the slurry around
the shoe and into the annulus in a circulating mode with another
fluid (i.e., water, mud,
or completion fluid) (fig. 24). Multistage
cementing
consists of pumping cement into the well in two or more
separate stages,
or batches, behind a casing string. This procedure
is used in wells that have critical fracture gradients or that require
good cement jobs
on long casing strings.
Several functions
of primary cementing are:
1. to structurally support and restrain casing;
2. to seal the annulus between pipe and formation against
fluid movement from one zone to another and to restrict
fluid movement between formations and the surface;
3. to provide well control by weight and rapid curing after
protective mud
is displaced;
4. to prevent pollution of freshwater formations;
5. to protect the casing's exterior from corrosion; and
6. to protect intermediate casing and liner pipe from torque
and shock loads when drilling deeper.
Figure 24. Primary
cementing
is performed
immediately after
the casing
has been run in the hole,
to seal and separate each
zone, and to protect the pipe.
(Courtesy of Halliburton)
Primary Cementing
Basics
52
There are three types of oilwell cementing. Primary cement
ing
is performed immediately after the casing has been run into
the hole, to seal and separate each zone, and to protect the pipe.
Secondary cementing is performed after the primary cement job,
usually
as part of a well servicing or workover operation. Plug
ging back to another producing zone, plugging a dry hole, and
formation squeeze cementing are examples
of secondary cement
ing procedures.
Squeeze cementing involves forcing cement to the
bottom
of the casing and up the annular space between the casing
and the wall
of the borehole to seal off a formation or plug a leak
in the casing. Squeeze cementing was introduced in the 1930s and
is now a common procedure for plugging perforations or shut
ting off water.
The discussion in this book is limited to primary
cementing.
Although several methods
of primary cementing exist, single-stage
and multistage cementing are the most commonly used.
Single
stage cementing, the most common cementing procedure, consists
of pumping a calculated volume of slurry into casing, after pipe has
been landed at the desired depth, and displacing the slurry around
the shoe and into the annulus in a circulating mode with another
fluid (i.e., water, mud,
or completion fluid) (fig. 24). Multistage
cementing
consists of pumping cement into the well in two or more
separate stages,
or batches, behind a casing string. This procedure
is used in wells that have critical fracture gradients or that require
good cement jobs
on long casing strings.
Several functions
of primary cementing are:
1. to structurally support and restrain casing;
2. to seal the annulus between pipe and formation against
fluid movement from one zone to another and to restrict
fluid movement between formations and the surface;
3. to provide well control by weight and rapid curing after
protective mud
is displaced;
4. to prevent pollution of freshwater formations;
5. to protect the casing's exterior from corrosion; and
6. to protect intermediate casing and liner pipe from torque
and shock loads when drilling deeper.
Figure 24. Primary
cementing
is performed
immediately after
the casing
has been run in the hole,
to seal and separate each
zone, and to protect the pipe.
(Courtesy of Halliburton)
CASING AND CEMENTING
54
To summarize
Cement
• supports and restrains casing
• seals
the annulus to restrict fluid movement
• provides well control
• prevents pollution
of freshwater formations
• protects
the casing from corrosion
• protects previously
run casing strings from torque and shock
loading
when drilling deeper
Five factors are important to a good cementing job
• cleaning the annulus without gouging, enhancing cement
bonding to the wellbor~;
• centering
the casing in the hole in order to form a uniform
sheath
of cement around the casing and minimize the chances
of a channeling effect on the cement job;
• strengthening
the cement in the annular space to allow for
proper perforation in the producing zone;
•
bonding the cement to the casing surface to eliminate the
possibility
of a microannulus; and
• providing
the necessary pipe movement, either rotation or
reciprocation, to increase turbulence, improve circulation,
and provide complete displacement
of the drilling fluid with
cement.
CEMENTING
Oilfield cements differ from construction concrete in that they Oilwell Cements
contain no coarse sand or gravel. The dry cement is finely ground and Additives
and available from manufacturers in various grades for different
downhole app4cations. To make the cement pumpable, water
is
added. The resulting mixture isslurrythathas predictable rheological,
curing, and final strength properties, assuming
it is uncontaminated.
Theoretically, only
10 to 20 percent water by weight (compared to
dry cement) is required to set and harden cement. However, 30 to
40 percent is usually used to prepare a pumpable slurry.
All oilwell cements are manufactured
in essentially the same
way. The differences are in the fineness of the grinds. Portland cement
is the most widely used cement in oilwells. It is produced according
to specifications set by the American Petroleum Institute.
Portland cement is manufactured by taking raw materials such
as limestone, clay or shale, and iron ore, grinding and mixing them,
and feeding
them into a kiln. In the kiln, high temperatures fuse,
or melt, the raw materials into a substance called cement clinker.
This clinker is then ground into a powdery mixture and combined
with small amounts
of gypsum or other compounds for specific
improvement
of the basic material. By varying the proportions
and chemistry
of the raw materials, manufacturers can produce
different classes
of portland cement.
Cement compositions are broadly classified as either neat or
tailored mixtures. Neat cement is cement without any additives that
may take up to 24 hours to harden. Tailored cement mixtures are
made
at bulk storage and blending facilities located near oilfields.
The dry cement blends are conveyed to the rig by cementing trucks
(fig.
2 5). Tailored mixtures are popular because of their lower cost
and
their improved characteristics for performing effectively in
deeper and hotter wells.
Figure 2 5. Cementing
trucks transport dry cement
blends to the well site.
(Courtesy of Halliburton)
55
54
To summarize
Cement
• supports and restrains casing
• seals
the annulus to restrict fluid movement
• provides well control
• prevents pollution
of freshwater formations
• protects
the casing from corrosion
• protects previously
run casing strings from torque and shock
loading
when drilling deeper
Five factors are important to a good cementing job
• cleaning the annulus without gouging, enhancing cement
bonding to the wellbor~;
• centering
the casing in the hole in order to form a uniform
sheath
of cement around the casing and minimize the chances
of a channeling effect on the cement job;
• strengthening
the cement in the annular space to allow for
proper perforation in the producing zone;
•
bonding the cement to the casing surface to eliminate the
possibility
of a microannulus; and
• providing
the necessary pipe movement, either rotation or
reciprocation, to increase turbulence, improve circulation,
and provide complete displacement
of the drilling fluid with
cement.
CEMENTING
Oilfield cements differ from construction concrete in that they Oilwell Cements
contain no coarse sand or gravel. The dry cement is finely ground and Additives
and available from manufacturers in various grades for different
downhole app4cations. To make the cement pumpable, water
is
added. The resulting mixture isslurrythathas predictable rheological,
curing, and final strength properties, assuming
it is uncontaminated.
Theoretically, only
10 to 20 percent water by weight (compared to
dry cement) is required to set and harden cement. However, 30 to
40 percent is usually used to prepare a pumpable slurry.
All oilwell cements are manufactured
in essentially the same
way. The differences are in the fineness of the grinds. Portland cement
is the most widely used cement in oilwells. It is produced according
to specifications set by the American Petroleum Institute.
Portland cement is manufactured by taking raw materials such
as limestone, clay or shale, and iron ore, grinding and mixing them,
and feeding
them into a kiln. In the kiln, high temperatures fuse,
or melt, the raw materials into a substance called cement clinker.
This clinker is then ground into a powdery mixture and combined
with small amounts
of gypsum or other compounds for specific
improvement
of the basic material. By varying the proportions
and chemistry
of the raw materials, manufacturers can produce
different classes
of portland cement.
Cement compositions are broadly classified as either neat or
tailored mixtures. Neat cement is cement without any additives that
may take up to 24 hours to harden. Tailored cement mixtures are
made
at bulk storage and blending facilities located near oilfields.
The dry cement blends are conveyed to the rig by cementing trucks
(fig.
2 5). Tailored mixtures are popular because of their lower cost
and
their improved characteristics for performing effectively in
deeper and hotter wells.
Figure 2 5. Cementing
trucks transport dry cement
blends to the well site.
(Courtesy of Halliburton)
55
CASING AND CEMENTING
API Classes of Cement
There are eight classes of oilwell cement, all of which are produced according to API
standards. Different cements are made to accommodate different downhole conditions.
For instance, API Class A cement sets very quickly and can be used to cement conductor
or surface pipe. Classes G and H cements, which have characteristics that allow them to
be used
at different depths, are the most often used classes of oilwell cement. In fact, 65
percent of all the oilwell cement used in the U.S. is Class H portland cement. The eight
classes
of API portland cement are:
Class A: intended for use from the surface to 6,000 ft of depth (1,829 m) when special
properties are
not required; available only in ordinary type.
Class B: intended for use from the surface to 6,000 ft of depth (1,829 m) when conditions
require moderate to high sulfate resistance; available
in both moderate and high-sulfate
resistance types.
Class C: intended for use from the surface to 6,000 ft of depth (1,829 m) when conditions
require high early strength; available
in ordinary, moderate, and high-sulfate-resistance
types.
Class D: intended for use from 6,000--10,000 ft of depth (1,829-3,048 m) under conditions
of moderately high temperatures and pressures; available in both moderate and high-sul
fate-resistance types.
Class E: intended for use from 10,000--14,000 ft of depth (3,048-4,267 m) under condi
tions
of high temperatures and pressures; available in both moderate and high-sulfate
resistance types.
Class F: intended for use from 10,000--16,000 ft of depth (3,048-4,877 m) under condi
tions
of extremely high temperatures and pressures; available in both moderate and high
sulfate-resistance types.
Class G: intended for use as a basic cement from the surface to 8,000 ft of depth (2,438 m)
as manufactured, or to be used with accelerators and retarders to cover a wide range of
well depths and temperatures; no additions other than calcium sulfate or water or both
' '
shall be interground or blended with the clinker during manufacture of Class G cement;
available
in moderate and high-sulfate-resistance types.
Class H: intended for use as a basic cement from the surface to 8,000 ft of depth (2,438 m)
as manufactured, and to be used with accelerators and retarders to cover a wide range of
well depths and temperatures; no additions other than calcium sulfate or water, or both,
shall be interground
or blended with the clinker during manufacture of Class H cement;
available
in moderate and high (tentative) sulfate-resistance types.
Class]: intended for use from 12,000--16,000 ft of depth (3,658-4,877 m) under condi
tions
of extremely high temperatures and pressures, or to be used with accelerators and
retarders to cover a range
of well depths and temperatures; no additions of retarder other
than calcium sulfate or water, or both, shall be interground or blended with the clinker
during manufacture
of Class J cement.
Additives are used
with basic cements to alter setting time, change
slurry density, lower water-loss characteristics, improve flow proper
ties, or improve the strength of the bond with the pipe. Table 7 shows
the effects of some additives on the physical properties of cement.
Proper selection of cement and additives involves choosing
an economical material that
• may be satisfactorily placed with the equipment available;
• achieves satisfactory
strength soon after placement;
• after placement, retains
the properties necessary to isolate
the zones behind the casing; and
• supports and protects the pipe.
Cement may be one of the API grades without additives, or
a basic cement to which chemicals and other substances are added
to satisfy specific conditions. Most additives should be blended at
a bulk-cement facility because, otherwise, it is difficult to disperse
the materials throughout the dry cement. When using small quan
tities of chemical additives, they may need to be dissolved in the
mixing water. Liquid additives, which provide the ability to easily
alter slurry composition on location, can be premixed directly into
the entire mixing water volume or metered into the mixing water
flow stream at the cement mixing unit.
Among types of cement additives are retarders, accelerators,
fluid loss additives, heavyweight
and lightweight additives, extend
ers, and bridging materials.
Retarders
In high-temperature formations, cement may thicken and set before
reaching its final placement. A retarder prolongs setting time so the
cement can be pumped into place without thickening prematurely.
Lignins, sugars, large amounts
of sodium chloride, and cellulose deriv
atives all
retard the cement's setting time. Commercial retarders in
clude chemicals similar to mud thinners, such as lignosulfonates.
When mixing retarders with cement, it is important to be sure
that the retarder is compatible with all the other substances in the
slurry. Particles that absorb water easily can also absorb some of
the retarder and limit or negate its effectiveness.
The API has established Classes G and Has basic cements
to be used specifically with retarders. However, if neither of these
cements is used, or if more than one additive is used in the slurry,
it is a good idea to test the retarder with other substances before
pumping it downhole.
CEMENTING
Additives
57
API Classes of Cement
There are eight classes of oilwell cement, all of which are produced according to API
standards. Different cements are made to accommodate different downhole conditions.
For instance, API Class A cement sets very quickly and can be used to cement conductor
or surface pipe. Classes G and H cements, which have characteristics that allow them to
be used
at different depths, are the most often used classes of oilwell cement. In fact, 65
percent of all the oilwell cement used in the U.S. is Class H portland cement. The eight
classes
of API portland cement are:
Class A: intended for use from the surface to 6,000 ft of depth (1,829 m) when special
properties are
not required; available only in ordinary type.
Class B: intended for use from the surface to 6,000 ft of depth (1,829 m) when conditions
require moderate to high sulfate resistance; available
in both moderate and high-sulfate
resistance types.
Class C: intended for use from the surface to 6,000 ft of depth (1,829 m) when conditions
require high early strength; available
in ordinary, moderate, and high-sulfate-resistance
types.
Class D: intended for use from 6,000--10,000 ft of depth (1,829-3,048 m) under conditions
of moderately high temperatures and pressures; available in both moderate and high-sul
fate-resistance types.
Class E: intended for use from 10,000--14,000 ft of depth (3,048-4,267 m) under condi
tions
of high temperatures and pressures; available in both moderate and high-sulfate
resistance types.
Class F: intended for use from 10,000--16,000 ft of depth (3,048-4,877 m) under condi
tions
of extremely high temperatures and pressures; available in both moderate and high
sulfate-resistance types.
Class G: intended for use as a basic cement from the surface to 8,000 ft of depth (2,438 m)
as manufactured, or to be used with accelerators and retarders to cover a wide range of
well depths and temperatures; no additions other than calcium sulfate or water or both
' '
shall be interground or blended with the clinker during manufacture of Class G cement;
available
in moderate and high-sulfate-resistance types.
Class H: intended for use as a basic cement from the surface to 8,000 ft of depth (2,438 m)
as manufactured, and to be used with accelerators and retarders to cover a wide range of
well depths and temperatures; no additions other than calcium sulfate or water, or both,
shall be interground
or blended with the clinker during manufacture of Class H cement;
available
in moderate and high (tentative) sulfate-resistance types.
Class]: intended for use from 12,000--16,000 ft of depth (3,658-4,877 m) under condi
tions
of extremely high temperatures and pressures, or to be used with accelerators and
retarders to cover a range
of well depths and temperatures; no additions of retarder other
than calcium sulfate or water, or both, shall be interground or blended with the clinker
during manufacture
of Class J cement.
Additives are used
with basic cements to alter setting time, change
slurry density, lower water-loss characteristics, improve flow proper
ties, or improve the strength of the bond with the pipe. Table 7 shows
the effects of some additives on the physical properties of cement.
Proper selection of cement and additives involves choosing
an economical material that
• may be satisfactorily placed with the equipment available;
• achieves satisfactory
strength soon after placement;
• after placement, retains
the properties necessary to isolate
the zones behind the casing; and
• supports and protects the pipe.
Cement may be one of the API grades without additives, or
a basic cement to which chemicals and other substances are added
to satisfy specific conditions. Most additives should be blended at
a bulk-cement facility because, otherwise, it is difficult to disperse
the materials throughout the dry cement. When using small quan
tities of chemical additives, they may need to be dissolved in the
mixing water. Liquid additives, which provide the ability to easily
alter slurry composition on location, can be premixed directly into
the entire mixing water volume or metered into the mixing water
flow stream at the cement mixing unit.
Among types of cement additives are retarders, accelerators,
fluid loss additives, heavyweight
and lightweight additives, extend
ers, and bridging materials.
Retarders
In high-temperature formations, cement may thicken and set before
reaching its final placement. A retarder prolongs setting time so the
cement can be pumped into place without thickening prematurely.
Lignins, sugars, large amounts
of sodium chloride, and cellulose deriv
atives all
retard the cement's setting time. Commercial retarders in
clude chemicals similar to mud thinners, such as lignosulfonates.
When mixing retarders with cement, it is important to be sure
that the retarder is compatible with all the other substances in the
slurry. Particles that absorb water easily can also absorb some of
the retarder and limit or negate its effectiveness.
The API has established Classes G and Has basic cements
to be used specifically with retarders. However, if neither of these
cements is used, or if more than one additive is used in the slurry,
it is a good idea to test the retarder with other substances before
pumping it downhole.
CEMENTING
Additives
57
Decreased
Density
Increased
Water Less
Required
More
Decreased
Viscosity
Increased
Thickening Accelerated
Time
Retarded
Setting Accelerated
Time
Retarded
Early Decreased
Strength
Increased
Final Decreased
Strength
Increased
Decreased
Durability
Increased
Decreased
Water Loss
Increased
x Denotes minor effect
Table 7
Effects of Some Additives on the
Physical Properties
of Cement
'E
('d
~
en
::l
0 I-<
Q.)
::l
~
u
i::::: 0
Q.)
('d
.1-J
'E s
('d
~
·p
Q.) -0 -~ 8
0
('d
Q) ('d
.1-J N
.1-J
s
i::::: -
.5:l ·c I-<
('d N
cu Q.)
Q
0 -
('d
Q.)
~ ~ ~ cJ.i ~ ~
® ® ®
X X
® ®
®
X ®
X X X X
X X X X X X X
X
X
X
X X X X
X X X X X X
X X
®
X X
®
X X X
® ®
®
X X
® Denotes major effect and/or principal purpose for which used.
en en
-; -;
·c ·c
Q.) Q.)
.1-J .1-J
('d ('d
Q.)
,jc ~ ~
-;
"'O
Q.)
en 0
·c
"'O en en
i::::: u
·c
cu
0 0
1-1
0
~
·p
('d
0 ~ ..c:
:a -
i:::::
('d
..c:
I-<
"S u
u
¢l + -
Q.)
u u
0
.1-J u "'O
s "S
~
I-<
§
~ a
Q.)
::l
en
-
.1-J
0
~
cu
('d
·o
~
en
~
.1-J
-t :.a
G
-;
Q) en
0
Q
0 0
~ u Cf) J ~ ~
X X X
®
X X
X ®
X X X
® ®
® ® ®
X X
® ®
® ® ®
X
® ® ®
X X X
® ®
®
X X X
X
X X
X
®
X ®
X
X X
X
* Small percentages of sodium chloride accelerate thickening. Large percentages may retard API class A cement.
+ Carboxymethyl hydroxyethyl cellulose
Accelerators
For low-temperature formations, an accelerator may be used to
speed up setting time. The accelerator acts as a catalyst, causing
the cement to absorb
or react with the water more quickly. The
faster the cement absorbs the water and crystallizes, the faster it
sets and develops strength. Among the most frequently used ac
celerators are calcium chloride, sodium chloride (table salt), and
certain forms
of gypsum.
Another way to make cement set faster
is to use less water
when mixing the slurry. However, reducing the water makes the
slurry thicker and harder to pump into place. So
if less water is
used, a dispersant may be added to the cement to chemically wet
the cement particles in the slurry and allow
it to flow easily without
much water.
Fluid Loss Additives
Fluid loss, or water control, additives prevent or minimize water loss
into the formation during slurry placement.
As fluid is forced out
of the cement, the density of the slurry increases and changes the
slurry characteristics.
If a large volume of water is lost, the slurry
becomes too
viscous, or dense, to pump. The cement particles left in
the annulus form a residue, or filter cake. This filter cake can bridge
the space between the casing and the formation and form blocks
that prevent the rest
of the cement from being properly placed.
If the filtrate, or water that filters into the formation, comes
in contact with water-sensitive clay, the clay absorbs the water and
expands
or swells to block the flow of formation fluids. Fluid loss
additives such
as dispersants and organic cellulose trap the filtrate in
the slurry and prevent the flow-stopping blocks from forming.
Dispersants are added to cement slurries to improve
both
flow and surface mixing properties. Dispersants reduce viscosity
and improve flow rates and mud displacement efficiency. Because
dispersants allow the slurry to flow easily without much water, they
may also be used instead
of accelerators, heavyweight additives,
and filtration-control additives. Some
of the most frequently used
dispersants include calcium lignosulfonate, salt, polymers, and
organic acids.
CEMENTING
59
Density
Increased
Water Less
Required
More
Decreased
Viscosity
Increased
Thickening Accelerated
Time
Retarded
Setting Accelerated
Time
Retarded
Early Decreased
Strength
Increased
Final Decreased
Strength
Increased
Decreased
Durability
Increased
Decreased
Water Loss
Increased
x Denotes minor effect
Table 7
Effects of Some Additives on the
Physical Properties
of Cement
'E
('d
~
en
::l
0 I-<
Q.)
::l
~
u
i::::: 0
Q.)
('d
.1-J
'E s
('d
~
·p
Q.) -0 -~ 8
0
('d
Q) ('d
.1-J N
.1-J
s
i::::: -
.5:l ·c I-<
('d N
cu Q.)
Q
0 -
('d
Q.)
~ ~ ~ cJ.i ~ ~
® ® ®
X X
® ®
®
X ®
X X X X
X X X X X X X
X
X
X
X X X X
X X X X X X
X X
®
X X
®
X X X
® ®
®
X X
® Denotes major effect and/or principal purpose for which used.
en en
-; -;
·c ·c
Q.) Q.)
.1-J .1-J
('d ('d
Q.)
,jc ~ ~
-;
"'O
Q.)
en 0
·c
"'O en en
i::::: u
·c
cu
0 0
1-1
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0 ~ ..c:
:a -
i:::::
('d
..c:
I-<
"S u
u
¢l + -
Q.)
u u
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.1-J u "'O
s "S
~
I-<
§
~ a
Q.)
::l
en
-
.1-J
0
~
cu
('d
·o
~
en
~
.1-J
-t :.a
G
-;
Q) en
0
Q
0 0
~ u Cf) J ~ ~
X X X
®
X X
X ®
X X X
® ®
® ® ®
X X
® ®
® ® ®
X
® ® ®
X X X
® ®
®
X X X
X
X X
X
®
X ®
X
X X
X
* Small percentages of sodium chloride accelerate thickening. Large percentages may retard API class A cement.
+ Carboxymethyl hydroxyethyl cellulose
Accelerators
For low-temperature formations, an accelerator may be used to
speed up setting time. The accelerator acts as a catalyst, causing
the cement to absorb
or react with the water more quickly. The
faster the cement absorbs the water and crystallizes, the faster it
sets and develops strength. Among the most frequently used ac
celerators are calcium chloride, sodium chloride (table salt), and
certain forms
of gypsum.
Another way to make cement set faster
is to use less water
when mixing the slurry. However, reducing the water makes the
slurry thicker and harder to pump into place. So
if less water is
used, a dispersant may be added to the cement to chemically wet
the cement particles in the slurry and allow
it to flow easily without
much water.
Fluid Loss Additives
Fluid loss, or water control, additives prevent or minimize water loss
into the formation during slurry placement.
As fluid is forced out
of the cement, the density of the slurry increases and changes the
slurry characteristics.
If a large volume of water is lost, the slurry
becomes too
viscous, or dense, to pump. The cement particles left in
the annulus form a residue, or filter cake. This filter cake can bridge
the space between the casing and the formation and form blocks
that prevent the rest
of the cement from being properly placed.
If the filtrate, or water that filters into the formation, comes
in contact with water-sensitive clay, the clay absorbs the water and
expands
or swells to block the flow of formation fluids. Fluid loss
additives such
as dispersants and organic cellulose trap the filtrate in
the slurry and prevent the flow-stopping blocks from forming.
Dispersants are added to cement slurries to improve
both
flow and surface mixing properties. Dispersants reduce viscosity
and improve flow rates and mud displacement efficiency. Because
dispersants allow the slurry to flow easily without much water, they
may also be used instead
of accelerators, heavyweight additives,
and filtration-control additives. Some
of the most frequently used
dispersants include calcium lignosulfonate, salt, polymers, and
organic acids.
CEMENTING
59
CASING AND CEMENTING
60
Heavyweight Additives
Heavyweight additives are weighting agents added to cement to
make
it dense enough to use in high-pressure zones. When drill
ing through these zones, heavy drilling muds are sometimes used
to help keep the well under control and prevent
it from blowing
out.
When cementing these wells, the cement slurry must be at
least
as heavy as the drilling mud. Heavyweight additives include
substances such
as barite, sand, and hematite. Barite is barium
sulfate, which
is also used as a weighting agent in drilling muds.
Hematite
is an iron oxide.
A heavy cement slurry may also be produced by using disper
sants.
The maximum cement slurry density that may be obtained
using dispersants
is about 17.5 ppg (2,097 kg/m
3
). By carefully se
lecting the dispersant ratio and weighting materials, slurryweights
up to 2 5 ppg (2,996 kg/m
3
) may be mixed and still be thin enough
to be pumped downhole.
Lightweight Additives
Lightweight additives reduce the weight of the slurry so the cement
can flow past low-pressure zones
or soft formations without losing
part of the slurry or damaging the wellbore.
One way to reduce the weight of the slurry is to add more
water to it, since water
is lighter than cement. However, adding too
much water will permanently reduce the strength
of the cement.
Excess water may also settle
out of the slurry and form undesirable
channels
or water pockets in the set cement. Lightweight additives
prevent the water from settling out. Bentonite
is a lightweight
additive that reacts chemically to hold the water and keep
it from
settling out, and also increases volume to produce a lighter, more
versatile slurry.
Other examples of lightweight additives include
pozzolans, silicates, hollow spheres, foam, diatomaceous earth,
expanded perlite, and natural hydrocarbons.
Extenders
The volume of slurry that can be mixed per sack of dry cement is
called the yield of the cement. Any additive that helps generate a
greater yield from a sack
of cement is called an extender. Extenders
increase the amount
of water required to mix the cement. Since
water
is lighter-weight and less expensive than cement, the ad
ditional water lightens the slurry and increases the yield per sack
of cement, making it less expensive.
Bridging Materials
Bridging materials are fibrous, flaky, or granular materials added
to cement slurry to prevent excessive loss
of cement into zones of
lost circulation. The most common bridging materials are Kolite,
Gilsonite, and Clinton Flake.
Kolite™ and Gilsonite™ are coarsely
ground hydrocarbon materials, while
Clinton flake is finely shred
ded cellophane.
Other Additives
In addition to the additives described above, other special additives
may be used to solve various problems encountered
in cementing a
well.For example, fine sand helps control strength loss encountered
in set cement at temperatures above 230°F (ur°C). A powdery
additive called
silica flour helps stabilize the cement to keep it strong
in high-temperature formations. Silica flour also helps the cement
provide an effective barrier between formations. Antifoam agents
control the foaming tendencies
of some cements.
Radioactive materials can be added
to slurries to locate the
cement behind the casing. Special logging instruments lowered
into the casing after the cement has set detect the radioactive
material.
Sodium chloride,
or salt, is a very versatile additive. Used in
small amounts, it accelerates the setting time of cement. Used in
large amounts, it retards the setting time. When used with other
additives, such as bentonite, it works as a mild dispersant. When
cementing through salt zones, using saturated saltwater to mix the
slurry will allow a better seal to form between the casing and the
wellbore and
will not enlarge the hole, as will a freshwater slurry.
Many more special additives are available to control special
or
unusual conditions present in a well.
CEMENTING
61
60
Heavyweight Additives
Heavyweight additives are weighting agents added to cement to
make
it dense enough to use in high-pressure zones. When drill
ing through these zones, heavy drilling muds are sometimes used
to help keep the well under control and prevent
it from blowing
out.
When cementing these wells, the cement slurry must be at
least
as heavy as the drilling mud. Heavyweight additives include
substances such
as barite, sand, and hematite. Barite is barium
sulfate, which
is also used as a weighting agent in drilling muds.
Hematite
is an iron oxide.
A heavy cement slurry may also be produced by using disper
sants.
The maximum cement slurry density that may be obtained
using dispersants
is about 17.5 ppg (2,097 kg/m
3
). By carefully se
lecting the dispersant ratio and weighting materials, slurryweights
up to 2 5 ppg (2,996 kg/m
3
) may be mixed and still be thin enough
to be pumped downhole.
Lightweight Additives
Lightweight additives reduce the weight of the slurry so the cement
can flow past low-pressure zones
or soft formations without losing
part of the slurry or damaging the wellbore.
One way to reduce the weight of the slurry is to add more
water to it, since water
is lighter than cement. However, adding too
much water will permanently reduce the strength
of the cement.
Excess water may also settle
out of the slurry and form undesirable
channels
or water pockets in the set cement. Lightweight additives
prevent the water from settling out. Bentonite
is a lightweight
additive that reacts chemically to hold the water and keep
it from
settling out, and also increases volume to produce a lighter, more
versatile slurry.
Other examples of lightweight additives include
pozzolans, silicates, hollow spheres, foam, diatomaceous earth,
expanded perlite, and natural hydrocarbons.
Extenders
The volume of slurry that can be mixed per sack of dry cement is
called the yield of the cement. Any additive that helps generate a
greater yield from a sack
of cement is called an extender. Extenders
increase the amount
of water required to mix the cement. Since
water
is lighter-weight and less expensive than cement, the ad
ditional water lightens the slurry and increases the yield per sack
of cement, making it less expensive.
Bridging Materials
Bridging materials are fibrous, flaky, or granular materials added
to cement slurry to prevent excessive loss
of cement into zones of
lost circulation. The most common bridging materials are Kolite,
Gilsonite, and Clinton Flake.
Kolite™ and Gilsonite™ are coarsely
ground hydrocarbon materials, while
Clinton flake is finely shred
ded cellophane.
Other Additives
In addition to the additives described above, other special additives
may be used to solve various problems encountered
in cementing a
well.For example, fine sand helps control strength loss encountered
in set cement at temperatures above 230°F (ur°C). A powdery
additive called
silica flour helps stabilize the cement to keep it strong
in high-temperature formations. Silica flour also helps the cement
provide an effective barrier between formations. Antifoam agents
control the foaming tendencies
of some cements.
Radioactive materials can be added
to slurries to locate the
cement behind the casing. Special logging instruments lowered
into the casing after the cement has set detect the radioactive
material.
Sodium chloride,
or salt, is a very versatile additive. Used in
small amounts, it accelerates the setting time of cement. Used in
large amounts, it retards the setting time. When used with other
additives, such as bentonite, it works as a mild dispersant. When
cementing through salt zones, using saturated saltwater to mix the
slurry will allow a better seal to form between the casing and the
wellbore and
will not enlarge the hole, as will a freshwater slurry.
Many more special additives are available to control special
or
unusual conditions present in a well.
CEMENTING
61
CASING AND CEMENTING
Special Cements Special cements such as pozzolanic cements, gypsum cements, ce
ments for permafrost regions, and refractory cements have been
developed for special environments.For example, in arctic regions,
permafrost cements bond the casing to the frozen wellbore.
In
geothermal or fireflood wells where temperatures may reach as
high as 2,000°F (1,093°C), special formulations or refractory ce
ments are used.
Thixotropic Cement
Thixotropic cements are blends of portland cement and calcium sul
fate hemihydra te designed primarily for cementing lost circulation
zones and porous
or fractured formations. A thixotropic slurry
becomes semisolid and thick like gelatin when
it is not moving, but
flows like a liquid when it is moved or agitated. The gel state of a
thixotropic cement may be broken repeatedly (up to
15 minutes
after being formed) by resuming displacement.
Bentonite gives the slurry thixotropic properties, and helps
keep
it in the annulus and out of porous formations. Bridging
substances such
as Gilsonite TM or walnut hulls may also be used to
make a slurry lighter and help seal certain zones.
It is quite com
mon to use both Gilsonite TM and bentonite with API Class G and
H cements to plug fractured zones.
Pozzolan Cement
Pozzo/an cement consists of a blend of Class A or H cement and a
natural
or artificial siliceous material called pozzolan. Pozzolan
cement mixtures produce lightweight slurries
that are stronger
than portland cement. Iron oxide or other heavyweight materi
als can be added to form high-density pozzolan cement slurries.
Water loss can be reduced by adding bentonite or powdered
cellulose.
Pozzolan cement can be used at all depths and temperatures.
Other advantages include:
• a wide range
of water ratios;
• predictable thickening time and compressive strengths;
• increased resistance to deterioration by sulfates;
• resistance to strength retrogression at high temperatures;
and
• economy.
The primary disadvantage ofusing pozzolan cement is that its
compressive strengths are lower than those
of portland cement.
Expanding Cement
Expanding cement is cement that expands as it sets to form a tighter
bond with the casing and the formation. Poor bonding
of the cement
to the formation
or the casing often occurs as a result of expan
sion and contraction
of the casing due to changes in temperature
and pressure. Expansion may occur during cementing and while
the cement
is setting. As the casing contracts back to its normal
size,
it may pull away from the cement in the annulus, leaving a
space called a microannulus. Expanding cement compensates for
this casing contraction.
Self-stress expanding cement swells while
it is still pliable,
after its initial setting
but before it has developed complete com
pressive strength.
The expanded cement exerts pressure against
the casing and conforms to the irregularities
of the formation to
provide a positive seal and reduce the possibility
of fluid migration
between zones.
Self-stressed cement can be prepared from most brands
of
portland cement and is compatible with conventional retarders
and other additives.
An added benefit is that the expansive reaction
provides resistance to attack by sulfate waters.
CEMENTING
Special Cements Special cements such as pozzolanic cements, gypsum cements, ce
ments for permafrost regions, and refractory cements have been
developed for special environments.For example, in arctic regions,
permafrost cements bond the casing to the frozen wellbore.
In
geothermal or fireflood wells where temperatures may reach as
high as 2,000°F (1,093°C), special formulations or refractory ce
ments are used.
Thixotropic Cement
Thixotropic cements are blends of portland cement and calcium sul
fate hemihydra te designed primarily for cementing lost circulation
zones and porous
or fractured formations. A thixotropic slurry
becomes semisolid and thick like gelatin when
it is not moving, but
flows like a liquid when it is moved or agitated. The gel state of a
thixotropic cement may be broken repeatedly (up to
15 minutes
after being formed) by resuming displacement.
Bentonite gives the slurry thixotropic properties, and helps
keep
it in the annulus and out of porous formations. Bridging
substances such
as Gilsonite TM or walnut hulls may also be used to
make a slurry lighter and help seal certain zones.
It is quite com
mon to use both Gilsonite TM and bentonite with API Class G and
H cements to plug fractured zones.
Pozzolan Cement
Pozzo/an cement consists of a blend of Class A or H cement and a
natural
or artificial siliceous material called pozzolan. Pozzolan
cement mixtures produce lightweight slurries
that are stronger
than portland cement. Iron oxide or other heavyweight materi
als can be added to form high-density pozzolan cement slurries.
Water loss can be reduced by adding bentonite or powdered
cellulose.
Pozzolan cement can be used at all depths and temperatures.
Other advantages include:
• a wide range
of water ratios;
• predictable thickening time and compressive strengths;
• increased resistance to deterioration by sulfates;
• resistance to strength retrogression at high temperatures;
and
• economy.
The primary disadvantage ofusing pozzolan cement is that its
compressive strengths are lower than those
of portland cement.
Expanding Cement
Expanding cement is cement that expands as it sets to form a tighter
bond with the casing and the formation. Poor bonding
of the cement
to the formation
or the casing often occurs as a result of expan
sion and contraction
of the casing due to changes in temperature
and pressure. Expansion may occur during cementing and while
the cement
is setting. As the casing contracts back to its normal
size,
it may pull away from the cement in the annulus, leaving a
space called a microannulus. Expanding cement compensates for
this casing contraction.
Self-stress expanding cement swells while
it is still pliable,
after its initial setting
but before it has developed complete com
pressive strength.
The expanded cement exerts pressure against
the casing and conforms to the irregularities
of the formation to
provide a positive seal and reduce the possibility
of fluid migration
between zones.
Self-stressed cement can be prepared from most brands
of
portland cement and is compatible with conventional retarders
and other additives.
An added benefit is that the expansive reaction
provides resistance to attack by sulfate waters.
CEMENTING
CASING AND CEMENTING
To summarize-
API classifies eight cements to accommodate different downhole
conditions.
The classes are:
A -for use from surface
to 6,000 ft (r,829 m)
B -for use from surface
to 6,000 ft (r,829 m) when sulfate
resistance is required
C -for use from surface to 6,000 ft (1,829 m)
when high-early
strength is required
D -for use from 6,000
to ro,ooo ft (r,829 to 3,048 m) under
moderately high pressure and temperature
E -for use from ro,ooo
to 14,000 ft (3,048 to 4,267 m) under
high pressure and temperature
F -for use from ro,ooo
to 16,000 ft (3,048 to 4,877 m) under
extremely high pressure and temperature
G -for use from 8,000 ft (2,438 m) as manufactured or with
accelerators
or retarders; no additions other than calcium
sulfate, water,
or both shall be blended with the clinker
during manufacture
H -for use from 8,000 ft (2,438 m) as manufactured or with
accelerators
or retarders; no additions other than calcium
sulfate, water,
or both shall be blended with the clinker
during manufacture; moderate
to high (tentative) sulfate
resistance
J -for use from u,ooo to 16,000 ft (3,658 to 4,877 m) under
high pressure and temperature; may be used with retarders
and accelerators
Additives
• alter setting time
• change slurry density
• lower water-loss characteristics
• improve
cement flow properties
• improve strength
of bond with casing
Additives include
• Retarders, which prolong setting time so cement can be
pumped without thickening prematurely
• Accelerators, which speed
up setting time in low-temperature
formations
• Fluid-loss additives, which prevent
or minimize water loss
into the formation
• Heavyweight additives, which increase the density
of cement
to contain formation pressure
• Lightweight additives, which reduce slurryweight
to prevent
formation fracture and loss
of cement into formations
• Extenders, which increase the volume (yield)
of cement
obtained from dry cement by increasing the volume of water
required to mix the
cement
• Bridging materials, which prevent excessive loss of cement
into lost circulation zones
•
Other additives include
(r) fine sand to control strength loss at high temperatures
(2) silica flour stabilizes cement in high-temperature for
mations
(3) antifoam agents
control foaming tendencies in some
cements
(4) radioactive materials allow cement to be located behind
casmg
(5) sodium chloride (salt) in small amounts is an accelerator;
in large amounts, it is a retarder
Special cements include
• Pozzolanic cements, which produce lightweight slurries
stronger than portland cement
• Thixotropic cements, which are blends of portland cement
and calcium sulfate hemihydrate and are used in lost circula
tion zones and
in porous or fractured formations
• Expanding cements, which swell,
or expand, as they set to
form a tighter bond with the casing and formation
• Self-stressing cements, which expand after they initially
set
but before they develop complete compressive strength
CEMENflNG
To summarize-
API classifies eight cements to accommodate different downhole
conditions.
The classes are:
A -for use from surface
to 6,000 ft (r,829 m)
B -for use from surface
to 6,000 ft (r,829 m) when sulfate
resistance is required
C -for use from surface to 6,000 ft (1,829 m)
when high-early
strength is required
D -for use from 6,000
to ro,ooo ft (r,829 to 3,048 m) under
moderately high pressure and temperature
E -for use from ro,ooo
to 14,000 ft (3,048 to 4,267 m) under
high pressure and temperature
F -for use from ro,ooo
to 16,000 ft (3,048 to 4,877 m) under
extremely high pressure and temperature
G -for use from 8,000 ft (2,438 m) as manufactured or with
accelerators
or retarders; no additions other than calcium
sulfate, water,
or both shall be blended with the clinker
during manufacture
H -for use from 8,000 ft (2,438 m) as manufactured or with
accelerators
or retarders; no additions other than calcium
sulfate, water,
or both shall be blended with the clinker
during manufacture; moderate
to high (tentative) sulfate
resistance
J -for use from u,ooo to 16,000 ft (3,658 to 4,877 m) under
high pressure and temperature; may be used with retarders
and accelerators
Additives
• alter setting time
• change slurry density
• lower water-loss characteristics
• improve
cement flow properties
• improve strength
of bond with casing
Additives include
• Retarders, which prolong setting time so cement can be
pumped without thickening prematurely
• Accelerators, which speed
up setting time in low-temperature
formations
• Fluid-loss additives, which prevent
or minimize water loss
into the formation
• Heavyweight additives, which increase the density
of cement
to contain formation pressure
• Lightweight additives, which reduce slurryweight
to prevent
formation fracture and loss
of cement into formations
• Extenders, which increase the volume (yield)
of cement
obtained from dry cement by increasing the volume of water
required to mix the
cement
• Bridging materials, which prevent excessive loss of cement
into lost circulation zones
•
Other additives include
(r) fine sand to control strength loss at high temperatures
(2) silica flour stabilizes cement in high-temperature for
mations
(3) antifoam agents
control foaming tendencies in some
cements
(4) radioactive materials allow cement to be located behind
casmg
(5) sodium chloride (salt) in small amounts is an accelerator;
in large amounts, it is a retarder
Special cements include
• Pozzolanic cements, which produce lightweight slurries
stronger than portland cement
• Thixotropic cements, which are blends of portland cement
and calcium sulfate hemihydrate and are used in lost circula
tion zones and
in porous or fractured formations
• Expanding cements, which swell,
or expand, as they set to
form a tighter bond with the casing and formation
• Self-stressing cements, which expand after they initially
set
but before they develop complete compressive strength
CEMENflNG
CASING AND CEMENTING
66
Mixing
Water Quality
Cement hydration (reaction with water) begins when water is
added to powdered cement. The cement gradually sets to a solid
as hydration continues. All brands of a given class of cement are
chemically similar,
but minor variations may be enough to alter
the desired response when used with certain additives; therefore,
cements should be tested under simulated well conditions to obtain
the best results.
Physical properties such
as setting time, compressive strength,
and tensile strength are primarily functions
of cement composition,
fineness
of grind, water-cement ratio, temperature, and pressure.
Both heat and pressure over 3,000 psi (20,685 kPa) shorten the
setting time.
The cleanest water available should be used to mix slurry. Any
water fresh enough to drink
is suitable for cement; but there must
be enough to mix all the cement for the job.
If water from local
lakes
or rivers is used, setting time should be tested before it is
pumped downhole. Impurities such as humic acid, chlorides, or
silt can affect setting time, particularly at hole depths of 10,000 ft
(3,048 m) or more. Rig water, too, should be checked before it is
used to mix slurry. It may contain phosphates, tannates, or other
thinners used for mud treating. These chemicals can seriously
retard the setting time
of cement. If there is any question regard
ing water quality, samples should be chemically tested
on some of
the cement to be used.
Water Quantity An effective cement job requires enough water to properly mix
the slurry, plus an allowance for pump priming, line testing, and
pump cleanup. All slurries are different; however, a common wa
ter-cement ratio is about
5. 5 gallons (gal) or 2 I litres (L) per sack
of cement. Based on this ratio, a 500-sack cement job would have
a base requirement
of 2,750 gal (1,041 L) of water. An additional
500 gal (1,893 L) for priming, testing, and cleanup, and 500 gal
(1,893 L)
as a minimum safety margin to allow for human error
brings the minimum water requirement for the 500-sack job to
3,750 gal (14,195 L).
CEMENTING
The hydraulic jet mixer was the first system used widely for mixing Types of Mixers
cement. It is seldom used today for cement mixing but remains a
vital piece
of equipment for mud mixing operations. The recircu-
lating mixer, which produces a smoother and more homogeneous
slurry,
is now the most common system for cement mixing (fig.
26).
It operates by forcing dry cement and water into a mixing
chamber.
The dry cement is wetted and mixed with the water. Then
the wet cement is then mixed with recirculated slurry. Circulation
with the slurry
is provided by an eductor and an agitating jet. After
the cement and water are thoroughly mixed with the recirculated
slurry, part
of the mixture is pumped to the displacement pumps,
and part
of the mixture, which is now slurry, is recirculated to be
mixed with more dry cement and water (fig. 2 7
).
The demands and expensive rig time associated with offshore
operations (fig.
28) have led to the development of sophisticated,
high-tech mixing and data acquisition systems
that mix slurries
far more thoroughly than conventional systems, at a wide range
of densities and rates. These systems use water jets, high slurry
recirculation rates, and high-horsepower agitators to improve the
slurries' rheological properties. Automatic density control systems
control slurry density to within
o. I ppg ( I 2 .o kg/m
3
) of the targeted
value throughout the cementing job. Special electronic systems
automatically control the proportioning
of liquid additives for
the cement slurry, and continuous metering systems deliver liquid
additives to the mixing water
in precise amounts.
Figure 26. High-energy
recirculating mixers provide
thoroughly mixed slurries
at a
wide range of densities
and rates. (Courtesy of
Halliburton)
66
Mixing
Water Quality
Cement hydration (reaction with water) begins when water is
added to powdered cement. The cement gradually sets to a solid
as hydration continues. All brands of a given class of cement are
chemically similar,
but minor variations may be enough to alter
the desired response when used with certain additives; therefore,
cements should be tested under simulated well conditions to obtain
the best results.
Physical properties such
as setting time, compressive strength,
and tensile strength are primarily functions
of cement composition,
fineness
of grind, water-cement ratio, temperature, and pressure.
Both heat and pressure over 3,000 psi (20,685 kPa) shorten the
setting time.
The cleanest water available should be used to mix slurry. Any
water fresh enough to drink
is suitable for cement; but there must
be enough to mix all the cement for the job.
If water from local
lakes
or rivers is used, setting time should be tested before it is
pumped downhole. Impurities such as humic acid, chlorides, or
silt can affect setting time, particularly at hole depths of 10,000 ft
(3,048 m) or more. Rig water, too, should be checked before it is
used to mix slurry. It may contain phosphates, tannates, or other
thinners used for mud treating. These chemicals can seriously
retard the setting time
of cement. If there is any question regard
ing water quality, samples should be chemically tested
on some of
the cement to be used.
Water Quantity An effective cement job requires enough water to properly mix
the slurry, plus an allowance for pump priming, line testing, and
pump cleanup. All slurries are different; however, a common wa
ter-cement ratio is about
5. 5 gallons (gal) or 2 I litres (L) per sack
of cement. Based on this ratio, a 500-sack cement job would have
a base requirement
of 2,750 gal (1,041 L) of water. An additional
500 gal (1,893 L) for priming, testing, and cleanup, and 500 gal
(1,893 L)
as a minimum safety margin to allow for human error
brings the minimum water requirement for the 500-sack job to
3,750 gal (14,195 L).
CEMENTING
The hydraulic jet mixer was the first system used widely for mixing Types of Mixers
cement. It is seldom used today for cement mixing but remains a
vital piece
of equipment for mud mixing operations. The recircu-
lating mixer, which produces a smoother and more homogeneous
slurry,
is now the most common system for cement mixing (fig.
26).
It operates by forcing dry cement and water into a mixing
chamber.
The dry cement is wetted and mixed with the water. Then
the wet cement is then mixed with recirculated slurry. Circulation
with the slurry
is provided by an eductor and an agitating jet. After
the cement and water are thoroughly mixed with the recirculated
slurry, part
of the mixture is pumped to the displacement pumps,
and part
of the mixture, which is now slurry, is recirculated to be
mixed with more dry cement and water (fig. 2 7
).
The demands and expensive rig time associated with offshore
operations (fig.
28) have led to the development of sophisticated,
high-tech mixing and data acquisition systems
that mix slurries
far more thoroughly than conventional systems, at a wide range
of densities and rates. These systems use water jets, high slurry
recirculation rates, and high-horsepower agitators to improve the
slurries' rheological properties. Automatic density control systems
control slurry density to within
o. I ppg ( I 2 .o kg/m
3
) of the targeted
value throughout the cementing job. Special electronic systems
automatically control the proportioning
of liquid additives for
the cement slurry, and continuous metering systems deliver liquid
additives to the mixing water
in precise amounts.
Figure 26. High-energy
recirculating mixers provide
thoroughly mixed slurries
at a
wide range of densities
and rates. (Courtesy of
Halliburton)
Figure 27. Internal
operation of a recirculating
mixer
Figure 28. The demands
and expense associated with
offshore operations have
led to the development of
sophisticated, high-tech
mixing and data acquisition
systems.
SLURRYTO
DISPLACEMENT
PUMPS
BULK CEMENT
CONTROL VALVE
TURBINE
AGITATORS
RECIRCULATING
CENTRIFUGAL
PUMP
The batch mixer is another type of cement mixer that is oc
casionallyused when a specified volume of cement is required. The
mixing tank in the batch mixer is filled with enough water for the
specified amount of cement. A mixing turbine agitates the water
as centrifugal pumps circulate the slurry through a prehydrator.
Then, dry cement is added through the prehydrator to achieve the
desired slurry density and volume. The prehydrator helps minimize
dust problems and improves mixing (fig. 29).
Some batch mixers have recirculating mixing units
mounted
onto the trailer with the batch tanks, enabling continuous mixing
into the batch mixer. Another application for the batch mixer is
using
it as an averaging tank by mixing into the batch tank with
a recirculating mixer unit while the downhole pump pulls slurry
from the tank.
This allows for more uniform slurry properties on
difficult-to-mix slurries or in cases where multiple mixing units are
mixing
at the same time. Disadvantages of a batch mixer include
volume limitations
and the need for a separate downhole pump.
WATER
INLET
-+
PREHYDRATOR
RECIRCULATING
CEMENT SUCTION
Figure 29. Internal operation of a batch mixer
TURBINE
AGITATOR
BAFFLES
BATCH
-----MIXING
TANK
CEMENTING
operation of a recirculating
mixer
Figure 28. The demands
and expense associated with
offshore operations have
led to the development of
sophisticated, high-tech
mixing and data acquisition
systems.
SLURRYTO
DISPLACEMENT
PUMPS
BULK CEMENT
CONTROL VALVE
TURBINE
AGITATORS
RECIRCULATING
CENTRIFUGAL
PUMP
The batch mixer is another type of cement mixer that is oc
casionallyused when a specified volume of cement is required. The
mixing tank in the batch mixer is filled with enough water for the
specified amount of cement. A mixing turbine agitates the water
as centrifugal pumps circulate the slurry through a prehydrator.
Then, dry cement is added through the prehydrator to achieve the
desired slurry density and volume. The prehydrator helps minimize
dust problems and improves mixing (fig. 29).
Some batch mixers have recirculating mixing units
mounted
onto the trailer with the batch tanks, enabling continuous mixing
into the batch mixer. Another application for the batch mixer is
using
it as an averaging tank by mixing into the batch tank with
a recirculating mixer unit while the downhole pump pulls slurry
from the tank.
This allows for more uniform slurry properties on
difficult-to-mix slurries or in cases where multiple mixing units are
mixing
at the same time. Disadvantages of a batch mixer include
volume limitations
and the need for a separate downhole pump.
WATER
INLET
-+
PREHYDRATOR
RECIRCULATING
CEMENT SUCTION
Figure 29. Internal operation of a batch mixer
TURBINE
AGITATOR
BAFFLES
BATCH
-----MIXING
TANK
CEMENTING
CASING AND CEMENTING
Pumping
Displacing the Drilling
Mud
70
When casing is run into a well, the hole is usually full of drilling
mud. To displace this mud,
itis common to pump ro to 50 bbl (r.6
to 8 m
3
) of specially formulated fluids known as flush or weighted
spacers before pumping the cement slurry.
Spacers are thick fluids
that displace the drilling mud ahead
of the cement in a slug or
piston-like manner. Flush fluids are much thinner and work through
a combination
of turbulent and surfactant action to separate the
drilling mud from the cement being pumped downhole while si
multaneously removing the coating
of mud left on the formation.
The spacer or flush removes wall cake and flushes mud ahead of
the cement, thereby lessening contamination and helping to ensure
a good bond between the cement and the wall.
Water constitutes an excellent flush fluid because
it is easy to
obtain,
it can be put into turbulent flow at low circulation rates,
and
it does not affect the setting time of the cement. Most mud
thinners will retard
or entirely preclude cement setting. Acetic acid
( r o percent) with a corrosion inhibitor and surfactant
is sometimes
used
as a flush fluid. It is fairly effective and normally does not cause
casing corrosion. Hydrochloric acid
(5 to r o percent) is sometimes
employed,
but corrosion is possible even though a water spacer is
used between the acid and cement. Viscous, weighted spacers are
commonly used
in applications where a reduction in fluid hydro
static pressure caused by low-density flushes cannot be tolerated.
The density of the flush or spacer must be considered in the job
design to ensure that well control
is properly maintained.
Figure
30 shows the progression of a typical primary cementing job.
Before the cement can be pumped, a
cementing head, or plug con
tainer, is attached to the top joint of casing to provide a connection
from the cementing pumps that enables cement to be circulated.
GUIDE SHOE JOB IN
PROGRESS
Figure 30. A primary cementingjob
CEMENTING
Pumping the Cement
71
Pumping
Displacing the Drilling
Mud
70
When casing is run into a well, the hole is usually full of drilling
mud. To displace this mud,
itis common to pump ro to 50 bbl (r.6
to 8 m
3
) of specially formulated fluids known as flush or weighted
spacers before pumping the cement slurry.
Spacers are thick fluids
that displace the drilling mud ahead
of the cement in a slug or
piston-like manner. Flush fluids are much thinner and work through
a combination
of turbulent and surfactant action to separate the
drilling mud from the cement being pumped downhole while si
multaneously removing the coating
of mud left on the formation.
The spacer or flush removes wall cake and flushes mud ahead of
the cement, thereby lessening contamination and helping to ensure
a good bond between the cement and the wall.
Water constitutes an excellent flush fluid because
it is easy to
obtain,
it can be put into turbulent flow at low circulation rates,
and
it does not affect the setting time of the cement. Most mud
thinners will retard
or entirely preclude cement setting. Acetic acid
( r o percent) with a corrosion inhibitor and surfactant
is sometimes
used
as a flush fluid. It is fairly effective and normally does not cause
casing corrosion. Hydrochloric acid
(5 to r o percent) is sometimes
employed,
but corrosion is possible even though a water spacer is
used between the acid and cement. Viscous, weighted spacers are
commonly used
in applications where a reduction in fluid hydro
static pressure caused by low-density flushes cannot be tolerated.
The density of the flush or spacer must be considered in the job
design to ensure that well control
is properly maintained.
Figure
30 shows the progression of a typical primary cementing job.
Before the cement can be pumped, a
cementing head, or plug con
tainer, is attached to the top joint of casing to provide a connection
from the cementing pumps that enables cement to be circulated.
GUIDE SHOE JOB IN
PROGRESS
Figure 30. A primary cementingjob
CEMENTING
Pumping the Cement
71
CASING AND CEMENTING
Figure 3 I. Wiper plugs
are placed in the cementing
head to wipe mud off the
inside of the casing and
keep it separated from
the cement. (Courtesy of
Halliburton)
72
A discharge line from the cementing pump is attached to the
cementing head on the rig floor.
Wiper plugs are also placed in
the cementing head to wipe mud off the inside
of the casing and
keep
it separated from the cement (fig. 31). First, a bottom plug is
installed. As the cement slurry from the pump discharge reaches
the cementing head, the bottom plug starts down the casing with
slurry behind it.
When the bottom plug reaches the float collar, it
stops. Pump pressure increases and ruptures the diaphragm in the
plug.
The slurry goes through the open valve in the float collar,
out the guide or float shoe, and into the annular space between
the casing and the hole.
During this time, the casing string
is being reciprocated or
rotated to help displace the mud. Once the calculated volume of
cement has been pumped, a retainer pin is pulled to release the top
plug from the cementing head.
The top plug follows the cement
into the casing and wipes cement off the inside walls.
It also helps
prevent the cement from mixing with the displacement fluid that
is pumped behind it. This plug is solid, so no fluid can flow past
it. As a result, when it seats, or bumps, on the bottom plug at the
float collar, pump pressure increases.
The increased pressure signals
that all the cement slurry has been displaced from the casing above
the top plug. At this point, the pump
is shut down and pressure is
bled off. With the pressure released in the casing, the valve in the
float collar closes to keep cement from backing up.
After cement
is in place, pressure should be relieved from
the inside
of the casing before the cement starts to set. If trapped
pressure
is maintained while the cement outside sets up, the casing
will remain in an expanded state.
If this pressure is then relieved
after the cement
is set up, the casing will contract and pull away
from the hardened cement, potentially damaging the cement bond.
Displacement
of cement out of the casing should progress
as fast as possible in order to create turbulence in the annulus
and remove the maximum amount
of mud. The operator should
use good judgment in determining the rate
of flow and take into
account the physical limitations involved. Computer simulators
should be used to ensure that the equivalent circulating density
(ECD) on the formation does
not exceed the formation fracture
gradient. Too much pressure on the casing and surface connections
may cause a rupture; too much flow (or pressure) in the annulus
may cause circulation loss due to formation breakdown; and too
much flow in the annulus may waste mud by overflowing the bell
nipple at the top
of the well.
CEMENTING
Casing accessories help guide casing into the hole, centralize it, Casing Accessories
and scrape mud off the wall of the hole (fig. 32). Among casing
accessories are guide shoes, collars, multistage cementing devices,
centralizers, and scratchers and wipers.
FLOAT SHOE
BOW CENTRALIZER
SOLID STRAIGHT
BLADE CENTRALIZER
SPIRAL STANDOFF
CENTRALIZER
NON ROTATING
FLOAT COLLAR
Figure 3 2. A typical casing string with accessories (Courtesy of
Halliburton)
73
Figure 3 I. Wiper plugs
are placed in the cementing
head to wipe mud off the
inside of the casing and
keep it separated from
the cement. (Courtesy of
Halliburton)
72
A discharge line from the cementing pump is attached to the
cementing head on the rig floor.
Wiper plugs are also placed in
the cementing head to wipe mud off the inside
of the casing and
keep
it separated from the cement (fig. 31). First, a bottom plug is
installed. As the cement slurry from the pump discharge reaches
the cementing head, the bottom plug starts down the casing with
slurry behind it.
When the bottom plug reaches the float collar, it
stops. Pump pressure increases and ruptures the diaphragm in the
plug.
The slurry goes through the open valve in the float collar,
out the guide or float shoe, and into the annular space between
the casing and the hole.
During this time, the casing string
is being reciprocated or
rotated to help displace the mud. Once the calculated volume of
cement has been pumped, a retainer pin is pulled to release the top
plug from the cementing head.
The top plug follows the cement
into the casing and wipes cement off the inside walls.
It also helps
prevent the cement from mixing with the displacement fluid that
is pumped behind it. This plug is solid, so no fluid can flow past
it. As a result, when it seats, or bumps, on the bottom plug at the
float collar, pump pressure increases.
The increased pressure signals
that all the cement slurry has been displaced from the casing above
the top plug. At this point, the pump
is shut down and pressure is
bled off. With the pressure released in the casing, the valve in the
float collar closes to keep cement from backing up.
After cement
is in place, pressure should be relieved from
the inside
of the casing before the cement starts to set. If trapped
pressure
is maintained while the cement outside sets up, the casing
will remain in an expanded state.
If this pressure is then relieved
after the cement
is set up, the casing will contract and pull away
from the hardened cement, potentially damaging the cement bond.
Displacement
of cement out of the casing should progress
as fast as possible in order to create turbulence in the annulus
and remove the maximum amount
of mud. The operator should
use good judgment in determining the rate
of flow and take into
account the physical limitations involved. Computer simulators
should be used to ensure that the equivalent circulating density
(ECD) on the formation does
not exceed the formation fracture
gradient. Too much pressure on the casing and surface connections
may cause a rupture; too much flow (or pressure) in the annulus
may cause circulation loss due to formation breakdown; and too
much flow in the annulus may waste mud by overflowing the bell
nipple at the top
of the well.
CEMENTING
Casing accessories help guide casing into the hole, centralize it, Casing Accessories
and scrape mud off the wall of the hole (fig. 32). Among casing
accessories are guide shoes, collars, multistage cementing devices,
centralizers, and scratchers and wipers.
FLOAT SHOE
BOW CENTRALIZER
SOLID STRAIGHT
BLADE CENTRALIZER
SPIRAL STANDOFF
CENTRALIZER
NON ROTATING
FLOAT COLLAR
Figure 3 2. A typical casing string with accessories (Courtesy of
Halliburton)
73
CASING AND CEMENTING
Figure 3 3. A guide shoe
(Courtesy of Halliburton)
Figure 34. An automatic
fill-up
shoe (Courtesy of
Halliburton)
74
Guide Shoes
A guide shoe or casing shoe is a heavy collar with a rounded nose that
is installed on the first joint of casing to be lowered into the hole,
to guide
it around obstructions (fig. 3 3). Regardless of whether
other casing accessories are used, a guide shoe
is always used. It
has an opening in the bottom that allows drilling mud to enter
the casing
as it is lowered. Cement later exits through the same
opening.
Three kinds of guide shoes may be used: the plain guide
shoe, the combination float and guide shoe, and the automatic
fill-up guide shoe.
Combination float and guide shoes are often used, particularly
on very long, heavy, expensive strings of pipe, to float casing into
the hole and ease some
of the load on the rig derrick. The float
device
is actually a back-pressure valve. As the casing is lowered
into the mud-filled hole, the mud cannot get past the closed valve.
However, the valve opens when mud
is pumped through the casing.
If the casing is empty and drilling mud is in the hole, the casing
tends to float, much like a boat floats in water. However,
if the cas
ing remains totally empty,
it can collapse under the pressure of the
mud in the hole.
For this reason, it is crucial to keep just enough
mud inside the casing to allow flotation yet prevent collapse.
A variation
of the guide and float shoe is the differential, or
automatic, fill-up shoe (fig. 34). This type of shoe allows a controlled
amount
of fluid to enter the bottom of a casing string while it is
being run into the hole. The valve in this shoe keeps mud from
getting into the casing at first,
but only to a point: As the casing
and differential fill-up shoe go deeper into the hole, mud pressure
causes the valve to open and mud to enter the casing. However,
the mud pressure in the casing finally closes the valve.
The valve
closes before the casing
is completely filled so that all the flotation
will
not be lost. As the casing string lengthens and goes deeper into
the hole, the valve opens again, allowing more mud into the casing
until the valve closes again. Opening and closing are repeated
as the
casing
is run. Automatic fill-up equipment protects low-pressure
formations from pressure surges while the casing
is being run. This
not only lowers the risk oflost circulation, but also eliminates the
need for filling the casing
as each joint is made up.
Float Collars
A float collar is similar to a float shoe in that it allows the casing to
float into the hole, byvirtue
of the casing being partially empty. The
outside fluid column exerts a pressure that closes the float collar's
back-pressure valve and prevents fluid from entering the casing
as it is lowered into the hole (fig. 35). The amount of flotation
depends on the amount
of fluid placed inside the casing string as it
is filled from the surface. Mud and cement can be pumped through
the valve because
it opens with pressure from above. When the
casing has been
run to the desired depth, circulation is established
through the casing and float valve.
A float collar may be installed
on top of either the first, second,
or third joint of casing to go into the hole. Most operators place
a float collar one
or more lengths above the casing shoe to leave
space inside the casing for contaminated cement.
The valve in the float collar also serves as a check valve in the
string to prevent
back.flow of cement after it is pumped outside
the string.
The float collar serves as a stop for the top plug when
cement
is displaced, enabling a quantity of slurry to stay inside
the string at the casing shoe and providing reasonable assurance
of good quality cement outside the casing at that point.
Some operators use a float shoe and baffle collar combination
instead
of a float collar in shallow applications. The purpose of the
baffle collar, which resembles a float collar without a back-pressure
valve,
is to stop the wiper plug and leave one or more joints of
casing filled with cement.
Float collars and shoes are generally attached to the casing
with thread-locking compounds rather than by welding, which
can weaken the casing and cause standard float shoes and collars
to
fail. Thread-locked joints, when properly prepared, withstand
greater torque before breaking
out than tack-welded casing. The
thread-locked joints may be broken out if the pipe has to be pulled
by heating them to around 6oo°F (316°C) and applying left-hand
torque.
J-5
5 grade pipe should not be welded except under very care
fully controlled conditions, and higher-grade material
not at all.
CEMENTING
Figure 3 5. A float collar
prevents backflow of cement
during the cementing
operation. (Courtesy of
Halliburton)
75
Figure 3 3. A guide shoe
(Courtesy of Halliburton)
Figure 34. An automatic
fill-up
shoe (Courtesy of
Halliburton)
74
Guide Shoes
A guide shoe or casing shoe is a heavy collar with a rounded nose that
is installed on the first joint of casing to be lowered into the hole,
to guide
it around obstructions (fig. 3 3). Regardless of whether
other casing accessories are used, a guide shoe
is always used. It
has an opening in the bottom that allows drilling mud to enter
the casing
as it is lowered. Cement later exits through the same
opening.
Three kinds of guide shoes may be used: the plain guide
shoe, the combination float and guide shoe, and the automatic
fill-up guide shoe.
Combination float and guide shoes are often used, particularly
on very long, heavy, expensive strings of pipe, to float casing into
the hole and ease some
of the load on the rig derrick. The float
device
is actually a back-pressure valve. As the casing is lowered
into the mud-filled hole, the mud cannot get past the closed valve.
However, the valve opens when mud
is pumped through the casing.
If the casing is empty and drilling mud is in the hole, the casing
tends to float, much like a boat floats in water. However,
if the cas
ing remains totally empty,
it can collapse under the pressure of the
mud in the hole.
For this reason, it is crucial to keep just enough
mud inside the casing to allow flotation yet prevent collapse.
A variation
of the guide and float shoe is the differential, or
automatic, fill-up shoe (fig. 34). This type of shoe allows a controlled
amount
of fluid to enter the bottom of a casing string while it is
being run into the hole. The valve in this shoe keeps mud from
getting into the casing at first,
but only to a point: As the casing
and differential fill-up shoe go deeper into the hole, mud pressure
causes the valve to open and mud to enter the casing. However,
the mud pressure in the casing finally closes the valve.
The valve
closes before the casing
is completely filled so that all the flotation
will
not be lost. As the casing string lengthens and goes deeper into
the hole, the valve opens again, allowing more mud into the casing
until the valve closes again. Opening and closing are repeated
as the
casing
is run. Automatic fill-up equipment protects low-pressure
formations from pressure surges while the casing
is being run. This
not only lowers the risk oflost circulation, but also eliminates the
need for filling the casing
as each joint is made up.
Float Collars
A float collar is similar to a float shoe in that it allows the casing to
float into the hole, byvirtue
of the casing being partially empty. The
outside fluid column exerts a pressure that closes the float collar's
back-pressure valve and prevents fluid from entering the casing
as it is lowered into the hole (fig. 35). The amount of flotation
depends on the amount
of fluid placed inside the casing string as it
is filled from the surface. Mud and cement can be pumped through
the valve because
it opens with pressure from above. When the
casing has been
run to the desired depth, circulation is established
through the casing and float valve.
A float collar may be installed
on top of either the first, second,
or third joint of casing to go into the hole. Most operators place
a float collar one
or more lengths above the casing shoe to leave
space inside the casing for contaminated cement.
The valve in the float collar also serves as a check valve in the
string to prevent
back.flow of cement after it is pumped outside
the string.
The float collar serves as a stop for the top plug when
cement
is displaced, enabling a quantity of slurry to stay inside
the string at the casing shoe and providing reasonable assurance
of good quality cement outside the casing at that point.
Some operators use a float shoe and baffle collar combination
instead
of a float collar in shallow applications. The purpose of the
baffle collar, which resembles a float collar without a back-pressure
valve,
is to stop the wiper plug and leave one or more joints of
casing filled with cement.
Float collars and shoes are generally attached to the casing
with thread-locking compounds rather than by welding, which
can weaken the casing and cause standard float shoes and collars
to
fail. Thread-locked joints, when properly prepared, withstand
greater torque before breaking
out than tack-welded casing. The
thread-locked joints may be broken out if the pipe has to be pulled
by heating them to around 6oo°F (316°C) and applying left-hand
torque.
J-5
5 grade pipe should not be welded except under very care
fully controlled conditions, and higher-grade material
not at all.
CEMENTING
Figure 3 5. A float collar
prevents backflow of cement
during the cementing
operation. (Courtesy of
Halliburton)
75
CASING AND CEMENTING
Multistage Cementing Devices
Multistage cementing devices are used to cement two or more
separate sections behind a casing string, often in jobs with weak
lower formations (fig. 36).
The lower section of casing is cemented
in the usual manner, using plugs that can pass through the stage
collar without opening the ports.
The multistage tool is then
opened hydraulically by special plugs, and fluid
is circulated to
the surface. Cement for the upper section
is placed through the
ports, which are subsequently closed by the final plug pumped
behind the cement.
Most commercially available stage collars are
designed to leave a full bore after cement remaining in the string
has been drilled out.
Figure 3 6. Multistage cementing devices are used to cement
-two or more separate sections behind a casing string. (Courtesy of
Halliburton)
Centralizers
Centralizers are cylindrical, cage-like devices fitted to the casing as
it is run in the hole to keep it centralized in the borehole (fig. 37).
Centralizers, which are particularly useful in deep or deviated holes,
serve several purposes:
r. to allow uniform cement
flow around the casing to help
protect it at all points;
2. to obtain a complete seal between the casing and the
formation to prevent migration
of fluids from permeable
zones;
3. to hold the casing away from the wall of the hole and thus
prevent differential-pressure sticking
of the pipe; and
4. to remove wall cake and prevent cement channeling in
the annulus.
There are two types of centralizers: bow and solid body.
Bow centralizers are widely used. Solid body centralizers are used
primarily in deviated
or horizontal holes.
Centralizers must have sufficient restoring
force (the force
exerted
by a centralizer against the borehole to keep the pipe away
from the borehole wall) to center the casing in the hole.
They must
have enough space to allow free passage
of the circulating fluid, yet
they must be spaced close enough together to prevent the casing
from contacting the formation wall, even in deviated holes.
Some centralizers are hinged and latch over the casing cou
plings. Others are held in position by stop collars
or set screws.
A B
CEMENTING
Figure 37. Bow (A) and
solid body (B) centralizers
(Courtesy of Halliburton)
77
Multistage Cementing Devices
Multistage cementing devices are used to cement two or more
separate sections behind a casing string, often in jobs with weak
lower formations (fig. 36).
The lower section of casing is cemented
in the usual manner, using plugs that can pass through the stage
collar without opening the ports.
The multistage tool is then
opened hydraulically by special plugs, and fluid
is circulated to
the surface. Cement for the upper section
is placed through the
ports, which are subsequently closed by the final plug pumped
behind the cement.
Most commercially available stage collars are
designed to leave a full bore after cement remaining in the string
has been drilled out.
Figure 3 6. Multistage cementing devices are used to cement
-two or more separate sections behind a casing string. (Courtesy of
Halliburton)
Centralizers
Centralizers are cylindrical, cage-like devices fitted to the casing as
it is run in the hole to keep it centralized in the borehole (fig. 37).
Centralizers, which are particularly useful in deep or deviated holes,
serve several purposes:
r. to allow uniform cement
flow around the casing to help
protect it at all points;
2. to obtain a complete seal between the casing and the
formation to prevent migration
of fluids from permeable
zones;
3. to hold the casing away from the wall of the hole and thus
prevent differential-pressure sticking
of the pipe; and
4. to remove wall cake and prevent cement channeling in
the annulus.
There are two types of centralizers: bow and solid body.
Bow centralizers are widely used. Solid body centralizers are used
primarily in deviated
or horizontal holes.
Centralizers must have sufficient restoring
force (the force
exerted
by a centralizer against the borehole to keep the pipe away
from the borehole wall) to center the casing in the hole.
They must
have enough space to allow free passage
of the circulating fluid, yet
they must be spaced close enough together to prevent the casing
from contacting the formation wall, even in deviated holes.
Some centralizers are hinged and latch over the casing cou
plings. Others are held in position by stop collars
or set screws.
A B
CEMENTING
Figure 37. Bow (A) and
solid body (B) centralizers
(Courtesy of Halliburton)
77
CASING AND CEMENTING
B
Figure 38. Scratchers (A)
and wipers (B) help remove
filter cake and gelled
mud from the well as the
casing is run. (Courtesy of
Halliburton)
Scratchers and Wipers
Scratchers are mechanical wall-cleaning devices that are attached
to casing to help remove filter cake and gelled mud from the well
as the casing is run (fig. 38). They are available in either recip
rocating
or rotating versions. Using scratchers provides better
bonding for the cement and helps isolate one zone from another
in the cemented area.
Wipers are basically scratchers with a pattern of closely spaced,
looped cable.
This pattern strengthens the cement sheath and
provides reinforcement in the annular space by lacing the cement
with steel cable.
Scratchers and wipers may be welded to the casing
but are
usually attached with mechanical stop collars
or clamps. Normally,
solid
or split scratchers are installed while the pipe is on the rack
prior to being run. Hinged centralizers and scratchers are usually
clamped
on the casing after it is made up and as it is run into the
hole.
Reciprocating scratchers are generally spaced at 15-to 20-ft
(5-to 6.1-m) intervals throughout the formations
of interest and
for 50 to
mo ft (15 to 30 m) above and below. Rotating scratchers
are usually placed throughout the entire pay zone and are activated
by rotating the casing. Using rotation rather than reciprocation
eliminates the chance
of sticking the casing off bottom.
Casing equipped with reciprocating wall cleaners
is worked
up and down for a distance
of 5 to 3 5 ft ( 1. 5 to 11 m), depending
on the spacing of the devices on the pipe. Casing should not be
lowered too fast
on the downstroke, since the displacement of the
pipe and circulation
of the fluid can produce excessive pressure
surges and cause formation breakdown. Usually the frequency
of
reciprocation is about two minutes per stroke.
Casing fitted with rotating scratchers is supported by slips
in the rotary and turned
at a speed of about 8 to 15 rpm. Limiting
rotation speed prevents damage to the casing from torsional stress.
Rotating pipe in deviated holes may cause the string to
flex and
damage the couplings with each
turn of the pipe. If there are a large
number of centralizers or scratchers on the casing, it can become
stuck
if it is rotated or reciprocated while pumping cement.
To
summarize-
Cement mixing considerations include
• Water quality-use cleanest available and test to ensure it
is suitable
• Water
quantity-use enough to properly mix the slurry, plus
an allowance for pumping
Types of mixers include
• hydraulic jet mixers, including high-tech offshore mixing
devices
• batch mixers, some
of which include recirculating mixing
units
Pumping considerations include
• proper displacement of drilling mud using spacers, which
are thick
• proper displacement
of drilling mud using flush fluids, which
are thin
To pump cement, use
• a cementing head (plug container)
• wiper plugs, bottom and top
CEMENTING
79
B
Figure 38. Scratchers (A)
and wipers (B) help remove
filter cake and gelled
mud from the well as the
casing is run. (Courtesy of
Halliburton)
Scratchers and Wipers
Scratchers are mechanical wall-cleaning devices that are attached
to casing to help remove filter cake and gelled mud from the well
as the casing is run (fig. 38). They are available in either recip
rocating
or rotating versions. Using scratchers provides better
bonding for the cement and helps isolate one zone from another
in the cemented area.
Wipers are basically scratchers with a pattern of closely spaced,
looped cable.
This pattern strengthens the cement sheath and
provides reinforcement in the annular space by lacing the cement
with steel cable.
Scratchers and wipers may be welded to the casing
but are
usually attached with mechanical stop collars
or clamps. Normally,
solid
or split scratchers are installed while the pipe is on the rack
prior to being run. Hinged centralizers and scratchers are usually
clamped
on the casing after it is made up and as it is run into the
hole.
Reciprocating scratchers are generally spaced at 15-to 20-ft
(5-to 6.1-m) intervals throughout the formations
of interest and
for 50 to
mo ft (15 to 30 m) above and below. Rotating scratchers
are usually placed throughout the entire pay zone and are activated
by rotating the casing. Using rotation rather than reciprocation
eliminates the chance
of sticking the casing off bottom.
Casing equipped with reciprocating wall cleaners
is worked
up and down for a distance
of 5 to 3 5 ft ( 1. 5 to 11 m), depending
on the spacing of the devices on the pipe. Casing should not be
lowered too fast
on the downstroke, since the displacement of the
pipe and circulation
of the fluid can produce excessive pressure
surges and cause formation breakdown. Usually the frequency
of
reciprocation is about two minutes per stroke.
Casing fitted with rotating scratchers is supported by slips
in the rotary and turned
at a speed of about 8 to 15 rpm. Limiting
rotation speed prevents damage to the casing from torsional stress.
Rotating pipe in deviated holes may cause the string to
flex and
damage the couplings with each
turn of the pipe. If there are a large
number of centralizers or scratchers on the casing, it can become
stuck
if it is rotated or reciprocated while pumping cement.
To
summarize-
Cement mixing considerations include
• Water quality-use cleanest available and test to ensure it
is suitable
• Water
quantity-use enough to properly mix the slurry, plus
an allowance for pumping
Types of mixers include
• hydraulic jet mixers, including high-tech offshore mixing
devices
• batch mixers, some
of which include recirculating mixing
units
Pumping considerations include
• proper displacement of drilling mud using spacers, which
are thick
• proper displacement
of drilling mud using flush fluids, which
are thin
To pump cement, use
• a cementing head (plug container)
• wiper plugs, bottom and top
CEMENTING
79
CASING AND CEMENTING
80
Casing accessories include
• guide shoes, which, when installed on the bottom of the first
joint
of casing to go into the well, guide the casing around
obstructions in the hole
• float collars, which, when installed three to
five joints above
the first casing joint, controls the amount
of mud allowed to
enter the casing
as it is run; note that empty casing will float
in buoyant drilling mud, which tends to ease the amount
of weight on the rig hoisting system. However, also note
that the casing must have drilling mud inside it as it is run
because the hydrostatic pressure of the mud in the hole can
crush casing
if it is empty
• multistage cementing devices, which are used to cement two
or more separate sections behind the casing string
• centralizers, which, when installed
on the casing string,
prevent the wall
of the casing from contacting the wall of
the hole, thus avoiding areas of cement voids
• scratchers, which, when installed
on the casing string and
when the string is rotated
or reciprocated, remove filter cake
and gelled mud from the wall
of the hole; removing cake and
mud ensures that the cement will bond better with the hole
CEMENTING
An important part of planning a cementing job is determining the Cement Volume
volume of slurry that will be required to achieve a predetermined Requirements
"height" in the annulus. Oilfield slurries range in density, depend-
ing on the amount of mixing water and additives in the cement and
the amount
of slurry contamination from drilling mud or other
foreign material. The volume of cement required for a particular
job
is based on calculated volumes, field experience, and regula-
tory requirements.
The most elementary method of estimating the top of cement
behind the casing and the amount
of cement needed to reach a
certain point
is to subtract the displacement volume of the pipe from
the volume calculation
of the open hole. Handbooks available from
cementing service companies list tables ofhole capacity and volume
between casing and hole, and between tubing and casing.
Calculated
or handbook volumes between casing and a larger
string
of pipe are quite accurate. On the other hand, volume de
terminations between pipe and open hole may be very inaccurate
because
of hole enlargement from washout, or hole closure from
wall cake buildup. Using
bit gauge diameter plus an extra margin
( calculated
on the basis of experience) for possible hole enlargement
should give a reasonable estimate
of volume requirement through
an interval of open hole.
Logging companies may
run open-hole caliper logs to ac
curately measure true borehole geometry. However, even when a
caliper survey
is available, additional cement slurry is needed for
complete fill because
of fluid loss by filtration. This excess factor
varies with local field conditions, drilling methods, types
of drilling
fluid, and admixes used with the cement.
80
Casing accessories include
• guide shoes, which, when installed on the bottom of the first
joint
of casing to go into the well, guide the casing around
obstructions in the hole
• float collars, which, when installed three to
five joints above
the first casing joint, controls the amount
of mud allowed to
enter the casing
as it is run; note that empty casing will float
in buoyant drilling mud, which tends to ease the amount
of weight on the rig hoisting system. However, also note
that the casing must have drilling mud inside it as it is run
because the hydrostatic pressure of the mud in the hole can
crush casing
if it is empty
• multistage cementing devices, which are used to cement two
or more separate sections behind the casing string
• centralizers, which, when installed
on the casing string,
prevent the wall
of the casing from contacting the wall of
the hole, thus avoiding areas of cement voids
• scratchers, which, when installed
on the casing string and
when the string is rotated
or reciprocated, remove filter cake
and gelled mud from the wall
of the hole; removing cake and
mud ensures that the cement will bond better with the hole
CEMENTING
An important part of planning a cementing job is determining the Cement Volume
volume of slurry that will be required to achieve a predetermined Requirements
"height" in the annulus. Oilfield slurries range in density, depend-
ing on the amount of mixing water and additives in the cement and
the amount
of slurry contamination from drilling mud or other
foreign material. The volume of cement required for a particular
job
is based on calculated volumes, field experience, and regula-
tory requirements.
The most elementary method of estimating the top of cement
behind the casing and the amount
of cement needed to reach a
certain point
is to subtract the displacement volume of the pipe from
the volume calculation
of the open hole. Handbooks available from
cementing service companies list tables ofhole capacity and volume
between casing and hole, and between tubing and casing.
Calculated
or handbook volumes between casing and a larger
string
of pipe are quite accurate. On the other hand, volume de
terminations between pipe and open hole may be very inaccurate
because
of hole enlargement from washout, or hole closure from
wall cake buildup. Using
bit gauge diameter plus an extra margin
( calculated
on the basis of experience) for possible hole enlargement
should give a reasonable estimate
of volume requirement through
an interval of open hole.
Logging companies may
run open-hole caliper logs to ac
curately measure true borehole geometry. However, even when a
caliper survey
is available, additional cement slurry is needed for
complete fill because
of fluid loss by filtration. This excess factor
varies with local field conditions, drilling methods, types
of drilling
fluid, and admixes used with the cement.
CASING AND CEMENTING
Calculating Open-Hole
Capacity
A rule-of-thumb method for calculating the capacity of an open
hole is to multiply the diameter in inches times itself, the result
beingthenumberofbarrels(bbl)per 1,oooft(305 m). For example,
the volume capacity of a rn-in. (2 54-mm) hole is approximately
rn x rn, or rno bbl (15.9 m
3
), per 1,000 ft (305 m). The method
may be extended to calculate volume between hole and casing by
multiplying
the casing diameter times itself and subtracting this
number from the figure obtained for hole capacity. For example:
Given 7-in.(178-mm)ODcasingina rn-in. (254-mm)diameterhole,
the casing will displace 7x7,
or 49 bbl (8 m
3
) per 1,000 ft (305 m).
rno bbl (15.9 m
3
) (the hole capacity per 1,000 ft (305 m) in a rn-in.
(254-mm) diameter hole) minus 49 bbl
(8 m
3
) (volume displaced
by casing)
51 bbl (8.1 m
3
) (volume between hole and casing for 1,000 ft (305
m)
of annular space)
*NOTE: When using the diameter-squared method, it is generally found
satisfactory to use a slightly larger diameter than bit or casing size, that
is, round off the diameter to the nearest whole inch larger.
Multiplying the number of barrels by 5 .6 gives the number
of cubic feet. These approximations are useful for open-hole deter
minations because most drilled holes are
not true gauge. Instead, they
are usually enlarged
as a result of one or more of the following:
• the
bit running slightly off center;
• hole washout;
and/ or
• sloughing shale.
After calculating the space
to be filled, the cement slurry
volume
must be determined to establish the volume of materials
to be employed in the slurry. Ratio of mixing water to cement,
type
of cement, and amount of additional additives included in the
slurry formulation are all factors
in this calculation. The cement
supplier usually provides the ratio of mixing water to cement.
After determining the
unit volume of the cement slurry being
used, comparing
the total slurry volume with the volume of space
behind the casing will yield an estimate
of the top of the cement
behind the casing.
The calculated top of cement is not a precise figure because
exact fill-up is seldom achieved. Calculated tops
of cement are
more applicable in hard-rock areas where hole conditions are more
predictable than in the Gulf Coast and similar areas.
Filtration loss· is considerable in areas where there are
nu
merous zones of high permeability. In these areas, proper additives
will reduce slurry water loss and afford
higher fill-up per sack.
Selecting the
proper amount of excess cement to use depends
on the reliability of hole volume data and prior experience. Usu
ally 15 to 2 5 percent excess cement is used when a caliper log is
available; this
amount should be raised to 50 to mo percent when
· the true hole diameter is not known.
To summarize-
To determine cement volume requirements (in English units only)
1. multiply hole diameter times itself to obtain hole capac
ity
in barrels per 1,000 ft (round off hole size to nearest
in.
upward-e.g. 12½ in.= 13 in.)
2. multiply casing diameter times itself and subtract this
number from hole capacity
3. divide hole depth by 1 ,ooo
4. multiply (3) by (2)
to obtain volume in bbl
Example:
13%-in. casing
in 17-in. hole; hole depth is 3,328 ft
Casing capaci-ty, bbl per I ,ooo ft
1. 13.625 x 13.625 = 185.64 or 186 bbl per 1,000 ft
Hole capacity, bbl per 1,000 ft:
2. 17 x 17 = 289 bbl per 1,000 ft
Thus:
289 -186 = 103 bbl per 1,000 ft between casing and hole
To determine volume between casing and hole in a hole 3,328-ft deep
3· 3,328 + 1,000 = 3.328
4. 3.328
x 289 = 961.8, or 962 bbl, volume between casing
and 3,328-ft hole
CEMENTING
Calculating Open-Hole
Capacity
A rule-of-thumb method for calculating the capacity of an open
hole is to multiply the diameter in inches times itself, the result
beingthenumberofbarrels(bbl)per 1,oooft(305 m). For example,
the volume capacity of a rn-in. (2 54-mm) hole is approximately
rn x rn, or rno bbl (15.9 m
3
), per 1,000 ft (305 m). The method
may be extended to calculate volume between hole and casing by
multiplying
the casing diameter times itself and subtracting this
number from the figure obtained for hole capacity. For example:
Given 7-in.(178-mm)ODcasingina rn-in. (254-mm)diameterhole,
the casing will displace 7x7,
or 49 bbl (8 m
3
) per 1,000 ft (305 m).
rno bbl (15.9 m
3
) (the hole capacity per 1,000 ft (305 m) in a rn-in.
(254-mm) diameter hole) minus 49 bbl
(8 m
3
) (volume displaced
by casing)
51 bbl (8.1 m
3
) (volume between hole and casing for 1,000 ft (305
m)
of annular space)
*NOTE: When using the diameter-squared method, it is generally found
satisfactory to use a slightly larger diameter than bit or casing size, that
is, round off the diameter to the nearest whole inch larger.
Multiplying the number of barrels by 5 .6 gives the number
of cubic feet. These approximations are useful for open-hole deter
minations because most drilled holes are
not true gauge. Instead, they
are usually enlarged
as a result of one or more of the following:
• the
bit running slightly off center;
• hole washout;
and/ or
• sloughing shale.
After calculating the space
to be filled, the cement slurry
volume
must be determined to establish the volume of materials
to be employed in the slurry. Ratio of mixing water to cement,
type
of cement, and amount of additional additives included in the
slurry formulation are all factors
in this calculation. The cement
supplier usually provides the ratio of mixing water to cement.
After determining the
unit volume of the cement slurry being
used, comparing
the total slurry volume with the volume of space
behind the casing will yield an estimate
of the top of the cement
behind the casing.
The calculated top of cement is not a precise figure because
exact fill-up is seldom achieved. Calculated tops
of cement are
more applicable in hard-rock areas where hole conditions are more
predictable than in the Gulf Coast and similar areas.
Filtration loss· is considerable in areas where there are
nu
merous zones of high permeability. In these areas, proper additives
will reduce slurry water loss and afford
higher fill-up per sack.
Selecting the
proper amount of excess cement to use depends
on the reliability of hole volume data and prior experience. Usu
ally 15 to 2 5 percent excess cement is used when a caliper log is
available; this
amount should be raised to 50 to mo percent when
· the true hole diameter is not known.
To summarize-
To determine cement volume requirements (in English units only)
1. multiply hole diameter times itself to obtain hole capac
ity
in barrels per 1,000 ft (round off hole size to nearest
in.
upward-e.g. 12½ in.= 13 in.)
2. multiply casing diameter times itself and subtract this
number from hole capacity
3. divide hole depth by 1 ,ooo
4. multiply (3) by (2)
to obtain volume in bbl
Example:
13%-in. casing
in 17-in. hole; hole depth is 3,328 ft
Casing capaci-ty, bbl per I ,ooo ft
1. 13.625 x 13.625 = 185.64 or 186 bbl per 1,000 ft
Hole capacity, bbl per 1,000 ft:
2. 17 x 17 = 289 bbl per 1,000 ft
Thus:
289 -186 = 103 bbl per 1,000 ft between casing and hole
To determine volume between casing and hole in a hole 3,328-ft deep
3· 3,328 + 1,000 = 3.328
4. 3.328
x 289 = 961.8, or 962 bbl, volume between casing
and 3,328-ft hole
CEMENTING
CASING AND CEMENTING
Considerations
After Cementing During cement pumping, the density of the cement is normally
higher than the density of the fluid displacing it from inside the
casing. This produces a pressure differential seen as surface pres
sure.
The surface pressure required to displace the wiper plug
to the float collar normally increases as cement rises in the an
nulus. After
bumping the plug, the pressure is increased 500 to
1,000 psi (345 to 6,895 kPa) above the final pumping pressure to
confirm that the plug is at the float collar and that all the slurry
has been displaced into
the annulus. This amount of pressure will
significantly expand
the casing. The expansion will have little or
no consequence as long as the pressure is released immediately
after testing
is complete, and before the cement sets. However,
if the cement hardens before the pressure is released, contraction
of the casing as a result of pressure release will severely damage
the bond between the casing and the cement. For this reason, the
first thing that must occur after the cementing pumps have been
shut down is to bleed off pressure.
Waiting On Cement After bleeding pressure, the time comes for waiting on cement, or
WOC. This is the time required for the cement to harden and
become strong enough to:
1. anchor the casing and withstand the shocks of subsequent
operations; and
2. seal permeable zones to prevent formation fluids from
migrating
to other zones.
Tests prove
that tensile strength of 8 psi (5 5 kPa) is sufficient
to anchor the pipe to the formation in most situations; similar tests
have shown
that a compressive strength of 130 psi (896 kPa) is
sufficient to provide hydraulic isolation between zones.
woe time begins when the plug bumps the float collar and
ends
when the cement plug is drilled out. Most U.S. woe re
quirements leave the waiting time open if a float valve is included
in the string, but require 8 to 12 hours of waiting time if there is
no float valve in the string. The usual waiting time before drilling
out is I 2 hours.
After
the cementing practices and procedures in a given area have
been established,
the top of cement for regular hole and pipe sizes
with a given slurry volume
may be fairly consistent. If there is any
question
of the height of cement in the annulus, the top should be
checked, usually by running a temperature survey or by running
a cement bond log.
Temperature Surveys
A temperature survey is an excellent meth9d of locating the top of
cement. As cement sets, it gives off heat. Therefore, the tempera
ture survey should be run 12 to 24 hours after mixing, when the
heat of the setting cement is most apparent. To locate the cement
top, an instrument is lowered into the well to make a temperature
log. Figure
39 shows a typical temperature log. The temperature
5500
~ ... -
COLLAR LOG
5600
CEMENTING
Checking the
Cement Top
APPROXIMATE TOP OF CEMENT
t-
w
w
u..
I
:c 5700
t-
C.
w
C
..J
..J
w
3:
5800
100° 110° 120° 130° 140° 150° 160°
TEMPERATURE -°F
Figure 39. Temperature survey showing the top of cement outside the casing
Considerations
After Cementing During cement pumping, the density of the cement is normally
higher than the density of the fluid displacing it from inside the
casing. This produces a pressure differential seen as surface pres
sure.
The surface pressure required to displace the wiper plug
to the float collar normally increases as cement rises in the an
nulus. After
bumping the plug, the pressure is increased 500 to
1,000 psi (345 to 6,895 kPa) above the final pumping pressure to
confirm that the plug is at the float collar and that all the slurry
has been displaced into
the annulus. This amount of pressure will
significantly expand
the casing. The expansion will have little or
no consequence as long as the pressure is released immediately
after testing
is complete, and before the cement sets. However,
if the cement hardens before the pressure is released, contraction
of the casing as a result of pressure release will severely damage
the bond between the casing and the cement. For this reason, the
first thing that must occur after the cementing pumps have been
shut down is to bleed off pressure.
Waiting On Cement After bleeding pressure, the time comes for waiting on cement, or
WOC. This is the time required for the cement to harden and
become strong enough to:
1. anchor the casing and withstand the shocks of subsequent
operations; and
2. seal permeable zones to prevent formation fluids from
migrating
to other zones.
Tests prove
that tensile strength of 8 psi (5 5 kPa) is sufficient
to anchor the pipe to the formation in most situations; similar tests
have shown
that a compressive strength of 130 psi (896 kPa) is
sufficient to provide hydraulic isolation between zones.
woe time begins when the plug bumps the float collar and
ends
when the cement plug is drilled out. Most U.S. woe re
quirements leave the waiting time open if a float valve is included
in the string, but require 8 to 12 hours of waiting time if there is
no float valve in the string. The usual waiting time before drilling
out is I 2 hours.
After
the cementing practices and procedures in a given area have
been established,
the top of cement for regular hole and pipe sizes
with a given slurry volume
may be fairly consistent. If there is any
question
of the height of cement in the annulus, the top should be
checked, usually by running a temperature survey or by running
a cement bond log.
Temperature Surveys
A temperature survey is an excellent meth9d of locating the top of
cement. As cement sets, it gives off heat. Therefore, the tempera
ture survey should be run 12 to 24 hours after mixing, when the
heat of the setting cement is most apparent. To locate the cement
top, an instrument is lowered into the well to make a temperature
log. Figure
39 shows a typical temperature log. The temperature
5500
~ ... -
COLLAR LOG
5600
CEMENTING
Checking the
Cement Top
APPROXIMATE TOP OF CEMENT
t-
w
w
u..
I
:c 5700
t-
C.
w
C
..J
..J
w
3:
5800
100° 110° 120° 130° 140° 150° 160°
TEMPERATURE -°F
Figure 39. Temperature survey showing the top of cement outside the casing
CASING AND CEMENTING
86
is recorded on the scale at the bottom of the chart, and depth is
recorded on the scale on the left vertical side of the chart. Start
ing at the top (5,500 ft, or 1,676 m, for the example in Figure 33),
the curves increase gradually with depth. However, about halfway
down,
at 5,650 ft (1,722 m), the curve shows a sudden temperature
increase.
This point of this sudden increase represents the top of
the cement.
Problems may occur
if the actual cement top is considerably
below
or above the expected top. A low cement top (possibly the
result of a large washed-out section that has consumed a lot of
cement) may allow formation fluid to enter the annulus above the
cement, resulting
in the need for a remedial cement job. Ahigher
than-expected top may mean that cement channeling around gelled
drilling
mud has left an uncemented area where fluids or gas may
communicate between zones.
Bond Logs
Bond logs are most often used to determine the quality of the
cement-to-casing bond, but they may also be used to determine
cement tops. Interpretation of these logs is very important. Gener
ally,
if a bond log shows a good bond, the primary cement job can
be assessed
as satisfactory. On the other hand, a poor bond job does
not necessarily indicate a poor cement job. Single-curve bond logs
do
not evaluate the cement-to-formation bond.Acementjobshould
be assumed
to be satisfactory unless good evidence exists to the
contrary. Radioactive tracer surveys are occasionally employed
to
obtain special engineering information or for research purposes.
CEMENTING
Casing and cementing jobs are almost always pressure-tested be-Pressure Testing
fore drilling ahead. In most areas, casing is pressure-tested after
the casinghead and blowout preventers have been installed. State
regulations regarding
the amount of pressure to be applied vary.
However,
the maximum pressure is limited by the API rating of the
casing. If possible, the test is carried to the maximum anticipated
pressure
that the pipe and surface fittings will have to withstand
. .
m service.
General practice is to use
the rig pumps to apply approximately
1,500 psi (rn,343 m) and hold
it for 30 minutes. A pressure drop
of 50 psi (345 k.Pa) during this time frame is considered satisfac
tory.
In some areas, particularly where high-grade casing is used,
the.test is certified by using specially contracted pressure-testing
equipment.
Some state regulations require perforating an imperme
able formation
near the casing shoe and running a drill stem test
to prove water-free production. If a liner is to be set below the
shutoff string, or if open-hole production is anticipated, a few
feet are drilled below
the cemented string, and the open hole is
tested. Usually, water shutoff tests
of this type are witnessed by a
representative from
the state office.
To
summarize
Considerations after cementing
• Immediately after pressure-testing to ensure bottom plug is
at float collar, release the pressure so that cement does not
set with pressure on it
• Give enough time for cement to set so that:
(1) casing is well anchored and can withstand subsequent
operations
(2) permeable zones are well sealed
• If required, run a temperature survey to locate cement top
• If required, run a cement bond log to confirm quality of
cement-to-casing bond
• Pressure-test casing and cement before drilling ahead to
ensure good cement job
86
is recorded on the scale at the bottom of the chart, and depth is
recorded on the scale on the left vertical side of the chart. Start
ing at the top (5,500 ft, or 1,676 m, for the example in Figure 33),
the curves increase gradually with depth. However, about halfway
down,
at 5,650 ft (1,722 m), the curve shows a sudden temperature
increase.
This point of this sudden increase represents the top of
the cement.
Problems may occur
if the actual cement top is considerably
below
or above the expected top. A low cement top (possibly the
result of a large washed-out section that has consumed a lot of
cement) may allow formation fluid to enter the annulus above the
cement, resulting
in the need for a remedial cement job. Ahigher
than-expected top may mean that cement channeling around gelled
drilling
mud has left an uncemented area where fluids or gas may
communicate between zones.
Bond Logs
Bond logs are most often used to determine the quality of the
cement-to-casing bond, but they may also be used to determine
cement tops. Interpretation of these logs is very important. Gener
ally,
if a bond log shows a good bond, the primary cement job can
be assessed
as satisfactory. On the other hand, a poor bond job does
not necessarily indicate a poor cement job. Single-curve bond logs
do
not evaluate the cement-to-formation bond.Acementjobshould
be assumed
to be satisfactory unless good evidence exists to the
contrary. Radioactive tracer surveys are occasionally employed
to
obtain special engineering information or for research purposes.
CEMENTING
Casing and cementing jobs are almost always pressure-tested be-Pressure Testing
fore drilling ahead. In most areas, casing is pressure-tested after
the casinghead and blowout preventers have been installed. State
regulations regarding
the amount of pressure to be applied vary.
However,
the maximum pressure is limited by the API rating of the
casing. If possible, the test is carried to the maximum anticipated
pressure
that the pipe and surface fittings will have to withstand
. .
m service.
General practice is to use
the rig pumps to apply approximately
1,500 psi (rn,343 m) and hold
it for 30 minutes. A pressure drop
of 50 psi (345 k.Pa) during this time frame is considered satisfac
tory.
In some areas, particularly where high-grade casing is used,
the.test is certified by using specially contracted pressure-testing
equipment.
Some state regulations require perforating an imperme
able formation
near the casing shoe and running a drill stem test
to prove water-free production. If a liner is to be set below the
shutoff string, or if open-hole production is anticipated, a few
feet are drilled below
the cemented string, and the open hole is
tested. Usually, water shutoff tests
of this type are witnessed by a
representative from
the state office.
To
summarize
Considerations after cementing
• Immediately after pressure-testing to ensure bottom plug is
at float collar, release the pressure so that cement does not
set with pressure on it
• Give enough time for cement to set so that:
(1) casing is well anchored and can withstand subsequent
operations
(2) permeable zones are well sealed
• If required, run a temperature survey to locate cement top
• If required, run a cement bond log to confirm quality of
cement-to-casing bond
• Pressure-test casing and cement before drilling ahead to
ensure good cement job
Glossary
accelerator n: a chemical additive that reduces the setting time of cement. See A
cement, cementing materials.
additive n: 1. in general, a substance added in small amounts to a larger amount of
another substance to change some characteristic of the latter. In the oil industry,
additives are used in lubricating oil, fuel, drilling mud, and casing cement.
2. in
cementing, a substance added to cement to change the cement characteristics
to satisfy specific conditions in the well. A cement additive may work
as an ac
celerator, retarder, dispersant,
or other reactant.
API gravity n: the measure of the density or gravity of liquid petroleum prod
ucts in the United States; derived from relative density in accordance with the
following equation:
API gravity at 60°F
= [ 141. 5 + relative density 6o/6o°F] - 13 1. 5
automatic fill-up shoe n: a device that is installed on the first joint of casing
and that automatically regulates the amount
of mud in the casing. The valve
in this shoe keeps mud from entering the casing until mud pressure causes the
valve to open, allowing mud to enter the casing.
axial compression n: pressure produced parallel with the cylinder axis when
casing hits a deviation in the hole
or a sticky spot and stops. The force pushing
down
on the pipe causes axial compression.
bending
n: occurs when tension is increased on one side of the pipe while com- B
pression is increased on the other.
billet
n: a solid steel cylinder used to produce seamless casing. The billet is
pierced lengthwise to form a hollow tube that is shaped and sized to produce
the casing.
boot n: a tubular device placed in a vertical position, either inside or outside
a larger vessel, through which well fluids are conducted before they enter the
larger vessel. A
boot aids in the separation of gas from wet oil. Also called a
flume
or conductor pipe.
bottom wiper plug n: a device placed in the cementing head and run down
the casing in front
of cement to clean the mud off the walls of the casing and to
prevent contamination between the mud and the cement.
accelerator n: a chemical additive that reduces the setting time of cement. See A
cement, cementing materials.
additive n: 1. in general, a substance added in small amounts to a larger amount of
another substance to change some characteristic of the latter. In the oil industry,
additives are used in lubricating oil, fuel, drilling mud, and casing cement.
2. in
cementing, a substance added to cement to change the cement characteristics
to satisfy specific conditions in the well. A cement additive may work
as an ac
celerator, retarder, dispersant,
or other reactant.
API gravity n: the measure of the density or gravity of liquid petroleum prod
ucts in the United States; derived from relative density in accordance with the
following equation:
API gravity at 60°F
= [ 141. 5 + relative density 6o/6o°F] - 13 1. 5
automatic fill-up shoe n: a device that is installed on the first joint of casing
and that automatically regulates the amount
of mud in the casing. The valve
in this shoe keeps mud from entering the casing until mud pressure causes the
valve to open, allowing mud to enter the casing.
axial compression n: pressure produced parallel with the cylinder axis when
casing hits a deviation in the hole
or a sticky spot and stops. The force pushing
down
on the pipe causes axial compression.
bending
n: occurs when tension is increased on one side of the pipe while com- B
pression is increased on the other.
billet
n: a solid steel cylinder used to produce seamless casing. The billet is
pierced lengthwise to form a hollow tube that is shaped and sized to produce
the casing.
boot n: a tubular device placed in a vertical position, either inside or outside
a larger vessel, through which well fluids are conducted before they enter the
larger vessel. A
boot aids in the separation of gas from wet oil. Also called a
flume
or conductor pipe.
bottom wiper plug n: a device placed in the cementing head and run down
the casing in front
of cement to clean the mud off the walls of the casing and to
prevent contamination between the mud and the cement.
CASING AND CEMENTING
C
break out v: 1. to unscrew one section of pipe from another section, especially
drill pipe while
it is being withdrawn from the wellbore. During this operation,
the tongs are used to start the unscrewing operation.
2. to separate, as gas from
a liquid
or water from an emulsion.
breakout cathead n: a device attached to the catshaft of the drawworks that is
used as a power source for unscrewing drill pipe; usually located opposite the
driller's side
of the drawworks. See cathead.
bridging material n: the fibrous, flaky, or granular material added to cement
slurry
or drilling fluid to aid in sealing formations in which lost circulation has
occurred. See
lost circulation, lost circulation material.
buckling stress n: bending of the pipe that may occur due to deviation of the
hole. The pipe may bend because of the angle of the hole or because of an abrupt
deviation such
as a dogleg.
burst pressure n: the internal pressure stress on casing or other pipe. Burst
pressure occurs when the pipe's internal pressure
is greater than its external
pressure, causing
the pipe to burst.
burst pressure rating n: the pressure at which a manufacturer has determined
that a pipe or vessel will burst from internal pressure.
burst strength n: a pipe or vessel's ability to withstand rupture from internal
pressure.
casing n: steel pipe placed in an oil or gas well as drilling progresses to prevent
the wall
of the hole from caving in during drilling, to prevent seepage of fluids,
and
to provide a means of extracting petroleum if the well is productive.
casing centralizer n: a device secured around the casing at regular intervals to
center
it in the hole. Casing that is centralized allows a more uniform cement
sheath
to form around the pipe.
casing shoe n: see guide shoe.
casing string n: the entire length of all the joints of casing run in a well. Most
casing joints are manufactured to specifications established by API, although
non-API specification casing
is available for special situations. Casing manufac
tured
to API specifications is available in three length ranges. A joint of range
1 casing
is 16 to 2 5 feet (4.8 to 7.6 metres) long; a joint of range 2 casing is 2 5
to 34 feet ( 7 .6 to IO. 3 metres) long; and a joint of range 3 casing is 34 to 48 feet
( IO. 3 to 14.6 metres) long. The outside diameter of a joint of API casing ranges
from4½ to 20 inches (11.43 to 50.8 centimetres).
cathead n: a spool-shaped attachment on the end of the catshaft, around which
rope for hoisting and moving heavy equipment
on or near the rig floor is wound.
See
breakout cathead, makeup cathead.
catline n: a hoisting or pulling line powered by the cathead and used to lift heavy
equipment
on the rig. See cathead.
cement n: a powder, consisting of alumina, silica, lime, and other substances
that hardens when mixed with water. Extensively used in the oil industry to bond
casing to the walls of the wellbore.
cement channeling n: an undesirable phenomenon that can occur when casing
is being cemented in a borehole. The cement slurry fails to rise uniformly be
tween the casing and the borehole wall, leaving spaces devoid
of cement. Ideally,
the cement should completely and uniformly surround the casing and form a
strong bond
to the borehole wall.
cement clinker n: a substance formed by melting ground limestone, clay or shale,
and iron ore in a kiln.
Cement clinker is ground into a powdery mixture and
combined with small amounts
of gypsum or other materials to form cement.
cement hydration n: reaction with water that begins when water is added to pow
dered cement.
The cement gradually sets to a solid as hydration continues.
cementing n: the application of a liquid slurry of cement and water to various
points inside
or outside the casing. See primary cementing, secondary cementing,
squeeze cementing.
cementing head n: an accessory attached to the top of the casing to facilitate
cementing
of the casing. It has passages for cement slurry and retainer chambers
for cementing wiper plugs.
cementing materials n pl: a slurry of portland cement and water and sometimes
one
or more additives that affect either the density of the mixture or its setting
time.
The portland cement used may be high early strength, common (standard),
or slow setting. Additives include accelerators (such as calcium chloride), retard
ers (such
as gypsum), weighting materials (such as barium sulfate), lightweight
additives (such
as bentonite), and a variety of lost circulation materials (such as
mica flakes).
centralizer n: also called casing centralizer. See casing centralizer.
Clinton flake n: finely shredded cellophane used as a lost circulation material
for cement.
collapse pressure n: the amount of force needed to crush the sides of pipe until
it caves in on itself. Collapse occurs when the pressure outside the pipe is greater
than the pressure inside the pipe.
compressive strength n: the degree of resistance of a material to a force act
ing along one
of its axes in a manner tending to collapse it; usually expressed in
pounds of force per square inch (psi) of surface affected or in kilopascals.
conductor pipe n: 1. a short string of large-diameter casing used to keep the
wellbore open and
to provide a means of conveying the up-flowing drilling fluid
from the wellbore
to the mud pit. 2. a boot. See boot.
density n: the mass or weight of a substance per unit volume. For instance, the D
density of a drilling mud may be 1 o pounds per gallon (ppg), 7 4.8 pounds per
cubic foot (lb/ft3), or 1,198.2 kilograms per cubic metre (kg/m3). Specific grav-
ity, relative density, and API gravity are
other units of density. See API gravlty,
relative
densiry, specific graviry.
GLOSSARY
91
C
break out v: 1. to unscrew one section of pipe from another section, especially
drill pipe while
it is being withdrawn from the wellbore. During this operation,
the tongs are used to start the unscrewing operation.
2. to separate, as gas from
a liquid
or water from an emulsion.
breakout cathead n: a device attached to the catshaft of the drawworks that is
used as a power source for unscrewing drill pipe; usually located opposite the
driller's side
of the drawworks. See cathead.
bridging material n: the fibrous, flaky, or granular material added to cement
slurry
or drilling fluid to aid in sealing formations in which lost circulation has
occurred. See
lost circulation, lost circulation material.
buckling stress n: bending of the pipe that may occur due to deviation of the
hole. The pipe may bend because of the angle of the hole or because of an abrupt
deviation such
as a dogleg.
burst pressure n: the internal pressure stress on casing or other pipe. Burst
pressure occurs when the pipe's internal pressure
is greater than its external
pressure, causing
the pipe to burst.
burst pressure rating n: the pressure at which a manufacturer has determined
that a pipe or vessel will burst from internal pressure.
burst strength n: a pipe or vessel's ability to withstand rupture from internal
pressure.
casing n: steel pipe placed in an oil or gas well as drilling progresses to prevent
the wall
of the hole from caving in during drilling, to prevent seepage of fluids,
and
to provide a means of extracting petroleum if the well is productive.
casing centralizer n: a device secured around the casing at regular intervals to
center
it in the hole. Casing that is centralized allows a more uniform cement
sheath
to form around the pipe.
casing shoe n: see guide shoe.
casing string n: the entire length of all the joints of casing run in a well. Most
casing joints are manufactured to specifications established by API, although
non-API specification casing
is available for special situations. Casing manufac
tured
to API specifications is available in three length ranges. A joint of range
1 casing
is 16 to 2 5 feet (4.8 to 7.6 metres) long; a joint of range 2 casing is 2 5
to 34 feet ( 7 .6 to IO. 3 metres) long; and a joint of range 3 casing is 34 to 48 feet
( IO. 3 to 14.6 metres) long. The outside diameter of a joint of API casing ranges
from4½ to 20 inches (11.43 to 50.8 centimetres).
cathead n: a spool-shaped attachment on the end of the catshaft, around which
rope for hoisting and moving heavy equipment
on or near the rig floor is wound.
See
breakout cathead, makeup cathead.
catline n: a hoisting or pulling line powered by the cathead and used to lift heavy
equipment
on the rig. See cathead.
cement n: a powder, consisting of alumina, silica, lime, and other substances
that hardens when mixed with water. Extensively used in the oil industry to bond
casing to the walls of the wellbore.
cement channeling n: an undesirable phenomenon that can occur when casing
is being cemented in a borehole. The cement slurry fails to rise uniformly be
tween the casing and the borehole wall, leaving spaces devoid
of cement. Ideally,
the cement should completely and uniformly surround the casing and form a
strong bond
to the borehole wall.
cement clinker n: a substance formed by melting ground limestone, clay or shale,
and iron ore in a kiln.
Cement clinker is ground into a powdery mixture and
combined with small amounts
of gypsum or other materials to form cement.
cement hydration n: reaction with water that begins when water is added to pow
dered cement.
The cement gradually sets to a solid as hydration continues.
cementing n: the application of a liquid slurry of cement and water to various
points inside
or outside the casing. See primary cementing, secondary cementing,
squeeze cementing.
cementing head n: an accessory attached to the top of the casing to facilitate
cementing
of the casing. It has passages for cement slurry and retainer chambers
for cementing wiper plugs.
cementing materials n pl: a slurry of portland cement and water and sometimes
one
or more additives that affect either the density of the mixture or its setting
time.
The portland cement used may be high early strength, common (standard),
or slow setting. Additives include accelerators (such as calcium chloride), retard
ers (such
as gypsum), weighting materials (such as barium sulfate), lightweight
additives (such
as bentonite), and a variety of lost circulation materials (such as
mica flakes).
centralizer n: also called casing centralizer. See casing centralizer.
Clinton flake n: finely shredded cellophane used as a lost circulation material
for cement.
collapse pressure n: the amount of force needed to crush the sides of pipe until
it caves in on itself. Collapse occurs when the pressure outside the pipe is greater
than the pressure inside the pipe.
compressive strength n: the degree of resistance of a material to a force act
ing along one
of its axes in a manner tending to collapse it; usually expressed in
pounds of force per square inch (psi) of surface affected or in kilopascals.
conductor pipe n: 1. a short string of large-diameter casing used to keep the
wellbore open and
to provide a means of conveying the up-flowing drilling fluid
from the wellbore
to the mud pit. 2. a boot. See boot.
density n: the mass or weight of a substance per unit volume. For instance, the D
density of a drilling mud may be 1 o pounds per gallon (ppg), 7 4.8 pounds per
cubic foot (lb/ft3), or 1,198.2 kilograms per cubic metre (kg/m3). Specific grav-
ity, relative density, and API gravity are
other units of density. See API gravlty,
relative
densiry, specific graviry.
GLOSSARY
91
CASING AND CEMENTING
92
dispersant n: a substance added to cement that chemically wets the cement
particles in the slurry, allowing the slurry to flow easily without much water.
dogleg n: I. an abrupt change in direction in the wellbore, frequently resulting
in the formation of a keyseat. 2. a sharp bend permanently put in an object such
as a pipe, wire rope, or a wire rope sling.
dope n: a lubricant for the threads of oilfield tubular goods. v: to apply thread
lubricant.
drift diameter n: 1. in drilling, the effective hole size. 2. in casing, the guaran
teed minimum diameter
of the casing. The drift diameter is important because
it indicates whether the casing is large enough for a specified size of bit to pass
through.
drill pipe n: heavy seamless tubing used to rotate the bit and circulate the drilling
fluid. Joints
of pipe approximately 30 feet (9 metres) long are coupled together
by means of tool joints.
dump bailer n: a bailing device with a release valve, usually of the disk or flap'
per type, used to place or spot material (such as cement slurry) at the bottom
of the well.
[ expanding cement n: cement that expands as it sets to form a tighter fit around
casing and formation.
extender n: 1. a substance added to drilling mud to increase viscosity without
adding clay
or other thickening material. 2. an additive that assists in getting a
greater yield from a sack
of cement. The extender acts by requiring more water
than that required by neat cement.
f filler material n: a material added to cement or ce:rp.ent slurry to increase its yield.
filter cake n: 1. compacted solid or semisolid material remaining on a filter after
pressure filtration
of mud with a standard filter press. Thickness of the cake is
reported in thirty-seconds of an inch or in millimetres. 2. the layer of concentrated
solids from
the drilling mud or cement slurry that forms on the walls of the borehole
opposite permeable formations; also called wall cake
or mud cake.
filtrate n: 1. a fluid that has been passed through a filter. 2. the liquid portion
of drilling mud that is forced into porous and permeable formations next to the
borehole.
Finite Element Analysis (FEA) n: can show the reaction of a pipe body or the
connection to forces estimated to be in a well environment.
flash set n: a premature thickening or setting of cement slurry, which makes it
unpumpable.
float collar n: a special coupling device, inserted one or two joints above the
bottom of the casing string, that contains a check valve to permit fluid to pass
downward
but not upward through the casing. The float collar prevents drilling
mud from entering the casing while it is being lowered, allowing the casing to
float during its descent and thus decreasing the load on the derrick. A float collar
also prevents backflow
of cement during a cementing operation.
float shoe n: a short, heavy, cylindrical steel section with a rounded bottom, at
tached
to the bottom of the casing string. It contains a check valve and functions
similarly
to the float collar but also serves as a guide shoe for the casing.
fluid loss n: the undesirable migration of the liquid part of the drilling mud
into a formation, often minimized or prevented by the blending of additives
with the mud.
fluid-loss additive n: a compound added to cement slurry or drilling mud to
prevent or minimize fluid loss.
flush fluids n pl: thin fluids that work through a combination of turbulent
and surfactant action to separate drilling mud from the cement being pumped
downhole, while simultaneously removing coatings of mud left on the forma
tion. Flush removes wall cake and flushes
mud ahead of the cement, thereby
lessening contamination and ensuring a good bond between the cement and
the wall.
galling adj: the result of the sticking or adhesion of two mating surfaces of metal, G
not protected by a film of lubricant, and tearing due to lateral displacement.
Gilsonite™ n: trade name for asphaltum mined, manufactured, or marketed
by or for American Gilsonite Company.
graded, or mixed, string n: a casing string made up of several weights or grades
of casing, and designed to take into account well depth, expected pressures, and
weight
of the fluid in the well.
guide shoe n: a short, heavy, cylindrical section of steel, filled with concrete and
rounded at the bottom, which is placed at the end of the casing string. It prevents
the casing from snagging on irregularities in the borehole as it is lowered. A
passage
through the center of the shoe allows drilling fluid to pass up into the
casing while it is being lowered and allows cement to pass out during cementing
operations. Also called casing shoe.
handling-tight coupling n: a coupling screwed onto casing tight enough so H
that a wrench must be used to remove the coupling.
hanging load n: the amount of weight transferred to the casinghead.
heavyweight additive n: a substance or material added to cement to make it
dense enough for use in high-pressure zones. Sand, barite, and hematite are
some
of the substances used as heavyweight additives.
hydration n: reaction of cement with water. The powdered cement gradually
sets to a solid
as hydration continues.
GLOSSARY
93
92
dispersant n: a substance added to cement that chemically wets the cement
particles in the slurry, allowing the slurry to flow easily without much water.
dogleg n: I. an abrupt change in direction in the wellbore, frequently resulting
in the formation of a keyseat. 2. a sharp bend permanently put in an object such
as a pipe, wire rope, or a wire rope sling.
dope n: a lubricant for the threads of oilfield tubular goods. v: to apply thread
lubricant.
drift diameter n: 1. in drilling, the effective hole size. 2. in casing, the guaran
teed minimum diameter
of the casing. The drift diameter is important because
it indicates whether the casing is large enough for a specified size of bit to pass
through.
drill pipe n: heavy seamless tubing used to rotate the bit and circulate the drilling
fluid. Joints
of pipe approximately 30 feet (9 metres) long are coupled together
by means of tool joints.
dump bailer n: a bailing device with a release valve, usually of the disk or flap'
per type, used to place or spot material (such as cement slurry) at the bottom
of the well.
[ expanding cement n: cement that expands as it sets to form a tighter fit around
casing and formation.
extender n: 1. a substance added to drilling mud to increase viscosity without
adding clay
or other thickening material. 2. an additive that assists in getting a
greater yield from a sack
of cement. The extender acts by requiring more water
than that required by neat cement.
f filler material n: a material added to cement or ce:rp.ent slurry to increase its yield.
filter cake n: 1. compacted solid or semisolid material remaining on a filter after
pressure filtration
of mud with a standard filter press. Thickness of the cake is
reported in thirty-seconds of an inch or in millimetres. 2. the layer of concentrated
solids from
the drilling mud or cement slurry that forms on the walls of the borehole
opposite permeable formations; also called wall cake
or mud cake.
filtrate n: 1. a fluid that has been passed through a filter. 2. the liquid portion
of drilling mud that is forced into porous and permeable formations next to the
borehole.
Finite Element Analysis (FEA) n: can show the reaction of a pipe body or the
connection to forces estimated to be in a well environment.
flash set n: a premature thickening or setting of cement slurry, which makes it
unpumpable.
float collar n: a special coupling device, inserted one or two joints above the
bottom of the casing string, that contains a check valve to permit fluid to pass
downward
but not upward through the casing. The float collar prevents drilling
mud from entering the casing while it is being lowered, allowing the casing to
float during its descent and thus decreasing the load on the derrick. A float collar
also prevents backflow
of cement during a cementing operation.
float shoe n: a short, heavy, cylindrical steel section with a rounded bottom, at
tached
to the bottom of the casing string. It contains a check valve and functions
similarly
to the float collar but also serves as a guide shoe for the casing.
fluid loss n: the undesirable migration of the liquid part of the drilling mud
into a formation, often minimized or prevented by the blending of additives
with the mud.
fluid-loss additive n: a compound added to cement slurry or drilling mud to
prevent or minimize fluid loss.
flush fluids n pl: thin fluids that work through a combination of turbulent
and surfactant action to separate drilling mud from the cement being pumped
downhole, while simultaneously removing coatings of mud left on the forma
tion. Flush removes wall cake and flushes
mud ahead of the cement, thereby
lessening contamination and ensuring a good bond between the cement and
the wall.
galling adj: the result of the sticking or adhesion of two mating surfaces of metal, G
not protected by a film of lubricant, and tearing due to lateral displacement.
Gilsonite™ n: trade name for asphaltum mined, manufactured, or marketed
by or for American Gilsonite Company.
graded, or mixed, string n: a casing string made up of several weights or grades
of casing, and designed to take into account well depth, expected pressures, and
weight
of the fluid in the well.
guide shoe n: a short, heavy, cylindrical section of steel, filled with concrete and
rounded at the bottom, which is placed at the end of the casing string. It prevents
the casing from snagging on irregularities in the borehole as it is lowered. A
passage
through the center of the shoe allows drilling fluid to pass up into the
casing while it is being lowered and allows cement to pass out during cementing
operations. Also called casing shoe.
handling-tight coupling n: a coupling screwed onto casing tight enough so H
that a wrench must be used to remove the coupling.
hanging load n: the amount of weight transferred to the casinghead.
heavyweight additive n: a substance or material added to cement to make it
dense enough for use in high-pressure zones. Sand, barite, and hematite are
some
of the substances used as heavyweight additives.
hydration n: reaction of cement with water. The powdered cement gradually
sets to a solid
as hydration continues.
GLOSSARY
93
CASING AND CEMENTING
I
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94
intermediate casing string n: the string of casing set in a well after the surface
casing
is set to keep the hole from caving and to seal off troublesome formations.
The string is sometimes called protection casing.
joint strength n: the amount of hanging weight that can be placed on a con
nection without failure.
Kolite TM n: coarsely ground hydrocarbon materials.
land casing v: to install casing so that it is supported in the casinghead by slips.
The casing is usually landed in the casinghead at exactly the position in which
it was hanging when the cement plug reached its lowest point.
landing depth n: the depth to which the lower end of casing extends in the hole
when casing
is landed.
last engaged thread n: the last pipe thread that is actually screwed into the
coupling thread in making up a joint
of drill pipe, drill collars, tubing, or casing.
If the pipe makes up perfectly, it is also the last thread cut on the pipe.
lightweight additives n pl: reduce the weight of the slurry so the cement can
flow past low-pressure zones
or soft formations without losing part of the slurry
or damaging the wellbore.
lightweight cement n: a cement or cement system that handles stable slurries
having a density less than
that of neat cement. Lightweight cements are used in
low-pressure zones where the high hydrostatic pressure
of long columns of neat
cement can fracture the formation and result in lost circulation.
lignosulfonate n: an organic drilling fluid additive derived from by-products of
a paper-making process using sulfite; added to drilling mud to minimize fluid
loss and
to reduce viscosity of the mud.
liner n: 1. a string of casing used to case open hole below existing casing. Liner casing
extends from the setting depth up into another string
of casing, usually overlapping
about
100 feet (30.5 metres) above the lower end of the intermediate or oil string.
Liners are nearly
always suspended from the upper string by a hanger device. 2. in jet
perforating guns, a conically shaped metallic piece that
is part of a shaped charge. It
increases the efficiency of the charge by increasing the penetrating ability of the jet.
3. a replaceable tube that fits inside the cylinder of an engine or a pump.
liner hanger n: a slip device that attaches the liner to the casing. See liner.
lost circulation n: the quantities of whole mud lost to a formation, usually in
cavernous, fissured,
or coarsely permeable beds, evidenced by the complete or
partial failure of the mud to return to the surface as it is being circulated in the
hole. Lost circulation can lead
to a blowout and, in general, reduce the efficiency
of the drilling operation. Also called lost returns.
lost circulation material n: a substance added to cement slurries or drilling mud
to prevent the loss of cement or mud to the formation. See bridging material.
lost circulation plug
n: cement set across a formation that is taking excessively
large amounts
of drilling fluid during drilling operations.
make up v: 1. to assemble and join parts to form a complete unit (e.g., to make
up a string
of drill pipe). 2. to screw together two threaded pieces. Compare
break out. 3. to mix or prepare ( e.g., to make up a tank of mud). 4. to compensate
for (e.g.,
to make up for lost time).
makeup cathead n: a device that is attached to the shaft of the drawworks and
used
as a power source for screwing together joints of pipe. It is usually located on
the driller's side of the drawworks. Also called spinning cathead. See cathead.
mandrel n: a cylindrical bar, spindle, or shaft, around which other parts are
arranged
or attached or which fits inside a cylinder or tube.
microannulus n: a space that is left as casing contracts back to its normal size
after pulling away from cement
in the annulus.
multistage cementingn: the action of pumping cement into the well in stages or
separate batches behind a casing string; a procedure used in wells that have critical
fracture gradients
or that require good cement jobs on long casing strings.
multistage cementing tool n: a device used for cementing in two or more separate
stages behind a casing string, usually for a long column that might cause formation
breakdown
if the cement were displaced from the bottom of the string.
neat cement n: a cement with no additives other than water.
oil string n: the final string of casing set in a well after the productive capacity
of the formation has been determined to be sufficient. Also called the long string
or production casing.
plug-back cementing n: a secondary-cementing operation in which a plug of
cement is positioned at a specific point in the well and allowed to set. Compare
squeeze cementing.
plug container n: see cementing head.
portland cement n: the cement most widely used in oilwells. It is made from
raw materials such
as limestone, clay or shale, and iron ore.
power-tight coupling n: coupling screwed on casing tightly enough to be
leakproof
at the time of makeup.
pozzolan n: a natural or artificial siliceous material commonly added to port
land cement mixtures to impart certain desirable properties. Added to oilwell
cements, pozzolans reduce slurry weight and viscosity, increase resistance
to
sulfate attack, and influence factors such as pumping time, ultimate strength,
and watertightness.
GLOSSARY
M
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p
95
I
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intermediate casing string n: the string of casing set in a well after the surface
casing
is set to keep the hole from caving and to seal off troublesome formations.
The string is sometimes called protection casing.
joint strength n: the amount of hanging weight that can be placed on a con
nection without failure.
Kolite TM n: coarsely ground hydrocarbon materials.
land casing v: to install casing so that it is supported in the casinghead by slips.
The casing is usually landed in the casinghead at exactly the position in which
it was hanging when the cement plug reached its lowest point.
landing depth n: the depth to which the lower end of casing extends in the hole
when casing
is landed.
last engaged thread n: the last pipe thread that is actually screwed into the
coupling thread in making up a joint
of drill pipe, drill collars, tubing, or casing.
If the pipe makes up perfectly, it is also the last thread cut on the pipe.
lightweight additives n pl: reduce the weight of the slurry so the cement can
flow past low-pressure zones
or soft formations without losing part of the slurry
or damaging the wellbore.
lightweight cement n: a cement or cement system that handles stable slurries
having a density less than
that of neat cement. Lightweight cements are used in
low-pressure zones where the high hydrostatic pressure
of long columns of neat
cement can fracture the formation and result in lost circulation.
lignosulfonate n: an organic drilling fluid additive derived from by-products of
a paper-making process using sulfite; added to drilling mud to minimize fluid
loss and
to reduce viscosity of the mud.
liner n: 1. a string of casing used to case open hole below existing casing. Liner casing
extends from the setting depth up into another string
of casing, usually overlapping
about
100 feet (30.5 metres) above the lower end of the intermediate or oil string.
Liners are nearly
always suspended from the upper string by a hanger device. 2. in jet
perforating guns, a conically shaped metallic piece that
is part of a shaped charge. It
increases the efficiency of the charge by increasing the penetrating ability of the jet.
3. a replaceable tube that fits inside the cylinder of an engine or a pump.
liner hanger n: a slip device that attaches the liner to the casing. See liner.
lost circulation n: the quantities of whole mud lost to a formation, usually in
cavernous, fissured,
or coarsely permeable beds, evidenced by the complete or
partial failure of the mud to return to the surface as it is being circulated in the
hole. Lost circulation can lead
to a blowout and, in general, reduce the efficiency
of the drilling operation. Also called lost returns.
lost circulation material n: a substance added to cement slurries or drilling mud
to prevent the loss of cement or mud to the formation. See bridging material.
lost circulation plug
n: cement set across a formation that is taking excessively
large amounts
of drilling fluid during drilling operations.
make up v: 1. to assemble and join parts to form a complete unit (e.g., to make
up a string
of drill pipe). 2. to screw together two threaded pieces. Compare
break out. 3. to mix or prepare ( e.g., to make up a tank of mud). 4. to compensate
for (e.g.,
to make up for lost time).
makeup cathead n: a device that is attached to the shaft of the drawworks and
used
as a power source for screwing together joints of pipe. It is usually located on
the driller's side of the drawworks. Also called spinning cathead. See cathead.
mandrel n: a cylindrical bar, spindle, or shaft, around which other parts are
arranged
or attached or which fits inside a cylinder or tube.
microannulus n: a space that is left as casing contracts back to its normal size
after pulling away from cement
in the annulus.
multistage cementingn: the action of pumping cement into the well in stages or
separate batches behind a casing string; a procedure used in wells that have critical
fracture gradients
or that require good cement jobs on long casing strings.
multistage cementing tool n: a device used for cementing in two or more separate
stages behind a casing string, usually for a long column that might cause formation
breakdown
if the cement were displaced from the bottom of the string.
neat cement n: a cement with no additives other than water.
oil string n: the final string of casing set in a well after the productive capacity
of the formation has been determined to be sufficient. Also called the long string
or production casing.
plug-back cementing n: a secondary-cementing operation in which a plug of
cement is positioned at a specific point in the well and allowed to set. Compare
squeeze cementing.
plug container n: see cementing head.
portland cement n: the cement most widely used in oilwells. It is made from
raw materials such
as limestone, clay or shale, and iron ore.
power-tight coupling n: coupling screwed on casing tightly enough to be
leakproof
at the time of makeup.
pozzolan n: a natural or artificial siliceous material commonly added to port
land cement mixtures to impart certain desirable properties. Added to oilwell
cements, pozzolans reduce slurry weight and viscosity, increase resistance
to
sulfate attack, and influence factors such as pumping time, ultimate strength,
and watertightness.
GLOSSARY
M
N
0
p
95
CASING AND CEMENTING
Q
pozzolan-cement mixture n: a mixture of pozzolan and cement.
premium connections
n pl: proprietary connections generally distinguished
from standard API connections by any
of the following features: metal seals,
torque shoulders, specialized thread forms,
O-ring seals, and tight machining
tolerances.
primary
cementing n: the cementing operation that takes place immediately
after the casing has been run into the hole; used to provide a protective sheath
around the casing, to segregate
the producing formation, and to prevent the
undesirable migration
of fluids. See secondary cementing, squeeze cementing.
production casing n: a string of casing set deeper than the surface casing to
protect a section
of the hole and to permit drilling to continue to a greater depth.
Sometimes called intermediate casing string.
psi
abbr: pounds per square inch.
quick-setting
cement n: a lightweight slurry designed to control lost circula
tion by setting very quickly.
R reciprocation n: a back-and-forth movement (as the movement of a piston in
an engine
or pump).
s
relative density n: r. the ratio of the weight of a given volume of a substance at
a given temperature to the weight of an equal volume of a standard substance
at the same temperature. For example, if I cubic inch of water at 39°F (3.9°C)
weighs r
unit and I cubic inch of another solid or liquid at 39°F weighs 0.95
unit, then the relative density
of the substance is 0.95. In determining the relative
density
of gases, the comparison is made with the standard of air or hydrogen.
2. the ratio of the mass of a given volume of a substance to the mass of a like
volume
of a standard substance, such as water or air.
restoring force
n: the force exerted by a centralizer against the borehole to
keep the pipe away from the borehole wall.
retarder
n: a substance added to cement to prolong the setting time so that the
cement can be pumped into place. Retarders are used for cementing in high
temperature formations.
scratcher
n: a device that is fastened to the outside ofcasing and that removes
mud cake from the wall
of a hole to condition the hole for cementing. By rotat
ing
or moving the casing string up and down as it is being run into the hole, the
scratcher, formed
of stiff wire, removes the cake so that the cement can bond
solidly to the formation.
secondary
cementing n: any cementing operation after the primary cementing
operation. Secondary cementing includes a plug-back job, in which a plug
of
cement is positioned at a specific point in the well and allowed to set. Wells are
plugged to shut off
bottom water or to reduce the depth of the well for other
reasons.
silica flour
n: a silica (Si O
2
)
ground to a fineness equal to that of portland ce
ment.
single-stage
cementing n: a common cementing procedure; consists of pump
ing a calculated volume
of slurry into casing after pipe has been landed at the
desired depth, and displacing the slurry around the shoe and into the annulus in a
circulating mode with another fluid, such
as water, mud, or completion fluid.
slip elevator
n: a casing elevator containing segmented slips with gripping teeth
inside. Slip elevators are recommended for long strings
of casing because the
teeth grip the casing and help prevent casing damage from the weight
of long,
heavy strings hanging from elevators. Slip elevators may also be used
as slips.
slurry
n: a plastic mixture of cement and water that is pumped into a well to
harden; there
it supports the casing and provides a seal in the well bore to prevent
migration
of underground fluids.
spacers
n pl: thick fluids that displace drilling mud ahead of the cement in a
slug
or piston-like manner.
specific gravity
n: see relative density.
squeeze cementing n: the forcing of cement slurry by pressure to specified
points
in a well to cause seals at the points of squeeze. It is a secondary cement
ing method that
is used to isolate a producing formation, seal off water, repair
casing leaks, and so forth. Compare
plug-back cementing.
stab v: to guide the end of a pipe into a coupling or tool joint when making up
a connection.
stabbing board
n: a temporary platform erected in the derrick or mast some 20
to 40 feet (6 to 12 metres) above the derrick floor. The derrickman or another
crew member works
on the board while casing is being run in a well. The board
may be wooden
or fabricated of steel girders floored with anti-skid material
and powered electrically to be raised
or lowered to the desired level. A stabbing
board serves the same purpose
as a monkeyboard but is temporary instead of
permanent.
stress
n: a force that, when applied to an object, distorts or deforms it.
stringer
n: an extra support placed under the middle of racked pipe to keep the
pipe from sagging.
sulfate resistance
n: the ability of a cement to resist deterioration by sulfate ions.
surface pipe
n: the first string of casing (after the conductor pipe) that is set in
a well, varying in length from a
few hundred to several thousand feet (metres).
Some states require a minimum length to protect freshwater sands. Compare
conductor pipe.
GLOSSARY
97
Q
pozzolan-cement mixture n: a mixture of pozzolan and cement.
premium connections
n pl: proprietary connections generally distinguished
from standard API connections by any
of the following features: metal seals,
torque shoulders, specialized thread forms,
O-ring seals, and tight machining
tolerances.
primary
cementing n: the cementing operation that takes place immediately
after the casing has been run into the hole; used to provide a protective sheath
around the casing, to segregate
the producing formation, and to prevent the
undesirable migration
of fluids. See secondary cementing, squeeze cementing.
production casing n: a string of casing set deeper than the surface casing to
protect a section
of the hole and to permit drilling to continue to a greater depth.
Sometimes called intermediate casing string.
psi
abbr: pounds per square inch.
quick-setting
cement n: a lightweight slurry designed to control lost circula
tion by setting very quickly.
R reciprocation n: a back-and-forth movement (as the movement of a piston in
an engine
or pump).
s
relative density n: r. the ratio of the weight of a given volume of a substance at
a given temperature to the weight of an equal volume of a standard substance
at the same temperature. For example, if I cubic inch of water at 39°F (3.9°C)
weighs r
unit and I cubic inch of another solid or liquid at 39°F weighs 0.95
unit, then the relative density
of the substance is 0.95. In determining the relative
density
of gases, the comparison is made with the standard of air or hydrogen.
2. the ratio of the mass of a given volume of a substance to the mass of a like
volume
of a standard substance, such as water or air.
restoring force
n: the force exerted by a centralizer against the borehole to
keep the pipe away from the borehole wall.
retarder
n: a substance added to cement to prolong the setting time so that the
cement can be pumped into place. Retarders are used for cementing in high
temperature formations.
scratcher
n: a device that is fastened to the outside ofcasing and that removes
mud cake from the wall
of a hole to condition the hole for cementing. By rotat
ing
or moving the casing string up and down as it is being run into the hole, the
scratcher, formed
of stiff wire, removes the cake so that the cement can bond
solidly to the formation.
secondary
cementing n: any cementing operation after the primary cementing
operation. Secondary cementing includes a plug-back job, in which a plug
of
cement is positioned at a specific point in the well and allowed to set. Wells are
plugged to shut off
bottom water or to reduce the depth of the well for other
reasons.
silica flour
n: a silica (Si O
2
)
ground to a fineness equal to that of portland ce
ment.
single-stage
cementing n: a common cementing procedure; consists of pump
ing a calculated volume
of slurry into casing after pipe has been landed at the
desired depth, and displacing the slurry around the shoe and into the annulus in a
circulating mode with another fluid, such
as water, mud, or completion fluid.
slip elevator
n: a casing elevator containing segmented slips with gripping teeth
inside. Slip elevators are recommended for long strings
of casing because the
teeth grip the casing and help prevent casing damage from the weight
of long,
heavy strings hanging from elevators. Slip elevators may also be used
as slips.
slurry
n: a plastic mixture of cement and water that is pumped into a well to
harden; there
it supports the casing and provides a seal in the well bore to prevent
migration
of underground fluids.
spacers
n pl: thick fluids that displace drilling mud ahead of the cement in a
slug
or piston-like manner.
specific gravity
n: see relative density.
squeeze cementing n: the forcing of cement slurry by pressure to specified
points
in a well to cause seals at the points of squeeze. It is a secondary cement
ing method that
is used to isolate a producing formation, seal off water, repair
casing leaks, and so forth. Compare
plug-back cementing.
stab v: to guide the end of a pipe into a coupling or tool joint when making up
a connection.
stabbing board
n: a temporary platform erected in the derrick or mast some 20
to 40 feet (6 to 12 metres) above the derrick floor. The derrickman or another
crew member works
on the board while casing is being run in a well. The board
may be wooden
or fabricated of steel girders floored with anti-skid material
and powered electrically to be raised
or lowered to the desired level. A stabbing
board serves the same purpose
as a monkeyboard but is temporary instead of
permanent.
stress
n: a force that, when applied to an object, distorts or deforms it.
stringer
n: an extra support placed under the middle of racked pipe to keep the
pipe from sagging.
sulfate resistance
n: the ability of a cement to resist deterioration by sulfate ions.
surface pipe
n: the first string of casing (after the conductor pipe) that is set in
a well, varying in length from a
few hundred to several thousand feet (metres).
Some states require a minimum length to protect freshwater sands. Compare
conductor pipe.
GLOSSARY
97
CASING AND CEMENTING
T
V
w
tensile strength n: the greatest longitudinal stress that a metal can bear without
tearing apart. Tensile strength of a metal is greater than yield strength.
tensile stress n: stress developed by a material bearing a tensile load. See stress.
tension n: the condition of a string, wire, pipe, or rod that is stretched between
two points.
thixotropic cement n: a blend of portland cement and calcium sulfate hemi
hydrate designed primarily for cementing lost circulation zones- and porous or
fractured formations.
thixotropy n: the property exhibited by a fluid that is in a liquid state when flowing
and
in a semisolid, gelled state when at rest. Most drilling fluids must be thixotropic so
that
the cuttings in the fluid will remain in suspension when circulation is stopped.
thread compound n: see dope.
thread protector n: a metal or plastic device that is screwed onto or into pipe
threads to protect them from damage when the pipe is not in use.
tie-back string n: casing that is run from the top of a liner to the surface. A
tie-back
string is often used to provide a production casing that has not been
drilled through.
top wiper plug n: a device placed in the cementing head and run down the cas
ing behind cement to clean the cement off the walls of the casing and to prevent
contamination between the cement and the displacement fluid.
torsion n: twisting deformation of a solid body about an axis in which lines that
were initially parallel to the axis become helices. Torsion is produced when part
of the pipe turns or twists in one direction while the other part remains station
ary
or twists in the other direction.
triaxial stress analysis n: a method used to calculate the combined loads that a
casing
or tubing string may experience throughout the service life of the well.
viscous adj: having a high resistance to flow.
waiting on cement adj: pertaining to the time when drilling or completion
operations are suspended so that the cement in a well can harden sufficiently.
water-cement ratio n: the ratio of water to cement in a slurry. It is expressed
as a percentage, indicating
the number of pounds of water needed to mix mo
lb (30.5 metres) of cement.
water control n: additives used to prevent or minimize water loss into a forma
tion during slurry placement.
weighting material n: a material that has a high specific gravity and is used to
increase the density of drilling fluids or cement slurries.
wiper n: a circular rubber device with a split in its side that is put around drill
pipe to wipe or clean drilling mud off the outside of the pipe as the pipe is pulled
from the hole.
wiper plugs n pl: rubber-bodied, plastic- or aluminum-cored devices used to
separate cement and drilling fluid as they are being pumped down the inside of
the casing during cementing operations. Wiper plugs also remove drilling mud
that adheres to the inside of the casing.
WOC abbr: waiting on cement; used in drilling reports.
yield n: the number of barrels of a liquid slurry of a given viscosity that can be y
made from a ton of clay. Clays are often classified as either high-or low-yield.
A ton of high-yield clay yields more slurry of a given viscosity than a low-yield
clay.
yield point n: the maximum stress that a solid can withstand without under
going permanent deformation either by plastic flow or by rupture. See tensik
strength.
yield strength n: a measure of the force needed to deform tubular goods to the
extent that they are permanently distorted.
zone of lost circulation n: a formation that contains holes or cracks large z
enough to allow cement to flow into the formation instead of up along the an
nulus outside of the casing.
GLOSSARY
99
T
V
w
tensile strength n: the greatest longitudinal stress that a metal can bear without
tearing apart. Tensile strength of a metal is greater than yield strength.
tensile stress n: stress developed by a material bearing a tensile load. See stress.
tension n: the condition of a string, wire, pipe, or rod that is stretched between
two points.
thixotropic cement n: a blend of portland cement and calcium sulfate hemi
hydrate designed primarily for cementing lost circulation zones- and porous or
fractured formations.
thixotropy n: the property exhibited by a fluid that is in a liquid state when flowing
and
in a semisolid, gelled state when at rest. Most drilling fluids must be thixotropic so
that
the cuttings in the fluid will remain in suspension when circulation is stopped.
thread compound n: see dope.
thread protector n: a metal or plastic device that is screwed onto or into pipe
threads to protect them from damage when the pipe is not in use.
tie-back string n: casing that is run from the top of a liner to the surface. A
tie-back
string is often used to provide a production casing that has not been
drilled through.
top wiper plug n: a device placed in the cementing head and run down the cas
ing behind cement to clean the cement off the walls of the casing and to prevent
contamination between the cement and the displacement fluid.
torsion n: twisting deformation of a solid body about an axis in which lines that
were initially parallel to the axis become helices. Torsion is produced when part
of the pipe turns or twists in one direction while the other part remains station
ary
or twists in the other direction.
triaxial stress analysis n: a method used to calculate the combined loads that a
casing
or tubing string may experience throughout the service life of the well.
viscous adj: having a high resistance to flow.
waiting on cement adj: pertaining to the time when drilling or completion
operations are suspended so that the cement in a well can harden sufficiently.
water-cement ratio n: the ratio of water to cement in a slurry. It is expressed
as a percentage, indicating
the number of pounds of water needed to mix mo
lb (30.5 metres) of cement.
water control n: additives used to prevent or minimize water loss into a forma
tion during slurry placement.
weighting material n: a material that has a high specific gravity and is used to
increase the density of drilling fluids or cement slurries.
wiper n: a circular rubber device with a split in its side that is put around drill
pipe to wipe or clean drilling mud off the outside of the pipe as the pipe is pulled
from the hole.
wiper plugs n pl: rubber-bodied, plastic- or aluminum-cored devices used to
separate cement and drilling fluid as they are being pumped down the inside of
the casing during cementing operations. Wiper plugs also remove drilling mud
that adheres to the inside of the casing.
WOC abbr: waiting on cement; used in drilling reports.
yield n: the number of barrels of a liquid slurry of a given viscosity that can be y
made from a ton of clay. Clays are often classified as either high-or low-yield.
A ton of high-yield clay yields more slurry of a given viscosity than a low-yield
clay.
yield point n: the maximum stress that a solid can withstand without under
going permanent deformation either by plastic flow or by rupture. See tensik
strength.
yield strength n: a measure of the force needed to deform tubular goods to the
extent that they are permanently distorted.
zone of lost circulation n: a formation that contains holes or cracks large z
enough to allow cement to flow into the formation instead of up along the an
nulus outside of the casing.
GLOSSARY
99
Multiple Choice
Review Questions
LESSONS IN ROTARY DRILLING
Unit II, Lesson 4: Casing and Cementing
Pick the best answer from the choices and place the letter of that answer in the blank provided.
r. Casing and tubing often account for what percentage of the total cost of the
well?
a. r to 5 percent
b. ro to
15 percent
c. r 5 to 20 percent
d. 2 5 to 50 percent
2. Casing-
a. prevents the hole from caving in.
b. contains formation pressures and prevents fracturing ofupper and weaker
zones.
c. confines production to the wellbore.
d. all of the above
3. Conductor pipe-
a. is usually the first string of casing installed in the well.
b. conducts produced fluids from the reservoir.
c. prevents erosion of the hole around the .base of the rig.
d. both a and c
4-Surface casing-
a. is usually the last string of casing run into the well.
b. provides a surface for the rig to rest on.
c. protects freshwater zones from contamination.
d. is usually run inside a liner.
5. Intermediate casing-
a. seals off weak zones.
b. minimizes hazards from lost circulation zones.
c. both a and b
d. neither a nor b
6. Aliner-
a. is a string of casing that runs from the surface to total depth.
b.
is usually suspended from an upper string by means of a hanger.
c. prevents surface formations from caving in.
d. lines the blowout preventer stack.
IOI
Review Questions
LESSONS IN ROTARY DRILLING
Unit II, Lesson 4: Casing and Cementing
Pick the best answer from the choices and place the letter of that answer in the blank provided.
r. Casing and tubing often account for what percentage of the total cost of the
well?
a. r to 5 percent
b. ro to
15 percent
c. r 5 to 20 percent
d. 2 5 to 50 percent
2. Casing-
a. prevents the hole from caving in.
b. contains formation pressures and prevents fracturing ofupper and weaker
zones.
c. confines production to the wellbore.
d. all of the above
3. Conductor pipe-
a. is usually the first string of casing installed in the well.
b. conducts produced fluids from the reservoir.
c. prevents erosion of the hole around the .base of the rig.
d. both a and c
4-Surface casing-
a. is usually the last string of casing run into the well.
b. provides a surface for the rig to rest on.
c. protects freshwater zones from contamination.
d. is usually run inside a liner.
5. Intermediate casing-
a. seals off weak zones.
b. minimizes hazards from lost circulation zones.
c. both a and b
d. neither a nor b
6. Aliner-
a. is a string of casing that runs from the surface to total depth.
b.
is usually suspended from an upper string by means of a hanger.
c. prevents surface formations from caving in.
d. lines the blowout preventer stack.
IOI
CASING AND CEMENTING
7. Production casing-
a. forms a protective housing for the tubing and other equipment used in a
well.
b.
is usually the first string of casing to be run into the well.
c. keeps surface formations from caving in.
d. none of the above
Identify
On the drawing below, identify the numbered parts.
8. I I.
9·
12.
IO.
102
REVIEW QUESTIONS
Fill in the Blanks
Fill in the blanks with an appropriate word or phrase. Pick the correct term from those listed
below. Some
of the terms or phrases may not be used.
axial compression
bending
burst pressure
compression buckling
tension
weakest
balloon pressure
buckling
collapse pressure
strongest
torsion
r 3. ____________ is the downward pull of the weight of the casing string
on the pipe body and couplings. In the case of API connections, the connection is the
part of the string. r 5.
is
the amount of pressure required to cause the wall of the casing to collapse.
r
6. ____________ is the pressure difference when the fluid pressure inside
the pipe
is greater than the fluid pressure outside the pipe. r 7. ___________ _
is stress on the pipe that causes it to bend. 18. ____________ occurs when
tension is increased
on one side of the pipe while compression is increased on the other.
19.
____________ is compression of the pipe that occurs as a result of pres-
sure
that is parallel with the cylinder axis. 20. ____________ is a twisting
deformation
of the casing about its axis such that lines that were initially parallel to the axis
become helices.
True or False
Put a T for true or an F for false in the blank next to each statement.
2 r. It is usually not necessary to use thread protectors on casing joints as they are
being unloaded from a truck
or boat at the rig.
22. Avoid placing sharply pointed hooks in the ends of the pipe, even if the thread
protectors are
in place.
2 3. Stringers separate layers of casing on the pipe rack.
103
7. Production casing-
a. forms a protective housing for the tubing and other equipment used in a
well.
b.
is usually the first string of casing to be run into the well.
c. keeps surface formations from caving in.
d. none of the above
Identify
On the drawing below, identify the numbered parts.
8. I I.
9·
12.
IO.
102
REVIEW QUESTIONS
Fill in the Blanks
Fill in the blanks with an appropriate word or phrase. Pick the correct term from those listed
below. Some
of the terms or phrases may not be used.
axial compression
bending
burst pressure
compression buckling
tension
weakest
balloon pressure
buckling
collapse pressure
strongest
torsion
r 3. ____________ is the downward pull of the weight of the casing string
on the pipe body and couplings. In the case of API connections, the connection is the
part of the string. r 5.
is
the amount of pressure required to cause the wall of the casing to collapse.
r
6. ____________ is the pressure difference when the fluid pressure inside
the pipe
is greater than the fluid pressure outside the pipe. r 7. ___________ _
is stress on the pipe that causes it to bend. 18. ____________ occurs when
tension is increased
on one side of the pipe while compression is increased on the other.
19.
____________ is compression of the pipe that occurs as a result of pres-
sure
that is parallel with the cylinder axis. 20. ____________ is a twisting
deformation
of the casing about its axis such that lines that were initially parallel to the axis
become helices.
True or False
Put a T for true or an F for false in the blank next to each statement.
2 r. It is usually not necessary to use thread protectors on casing joints as they are
being unloaded from a truck
or boat at the rig.
22. Avoid placing sharply pointed hooks in the ends of the pipe, even if the thread
protectors are
in place.
2 3. Stringers separate layers of casing on the pipe rack.
103
CASING AND CEMENTING
24.
25.
26.
27.
28.
29.
30.
31.
32.
33·
34·
35.
Matching
Usually, it is not necessary to number the joints of casing run into the well.
Rabbiting,
or drifting, a casing joint is done to determine if a casing joint is
dented, bent, or has excessive amounts of scale built up inside.
The length of each joint of casing to be run into the well shou_ld be measured,
or talleyed.
Generally speaking, it
is not all that important to condition the hole prior to
running casing.
Normally, each joint
of casing is filled with mud as it is run into the hole.
Usually, casing joints are
not lowered into the hole as fast as drill pipe joints
are lowered into the hole.
Pressure surges created by lowering the casing too fast can cause formation
breakdown and lost circulation.
Apply thread locking compound to the threads
of the first several joints of
casing to prevent them from backing off during later drilling operations.
Usually, power tongs are used to make up casing joints.
Landing the casing involves transferring the weight
of the casing string to the
wellhead.
A downhole casing hanger
is usually not used to relieve some of the load on
the casinghead.
The maximum yield strength of an API K5 5 joint of casing is 5 5 ,ooo psi.
Write the letter
of the correct definition in the blank next to each term.
36. Uses couplings to join two pin-thread pipe ends.
3
7. The threaded connection is machined into the wall of the pipe body.
38. Uses a hydraulic press to cold-form both box and pin, to expand the box and
reduce pin diameters.
39. Connections are machined directly on the pipe or onto forgings and welded
to the pipe body.
40. Require special handling and running techniques.
a. large OD connections d. premium connections
b. slim-line integral design
e. flush-joint
c. coupled design
REVIEW QUESTIONS
Multiple Choice
Pick the best answer from the choices and place the letter of that answer in the blank provided.
41. In 1903-
a. several classes of cement were available.
b. waiting on cement time was measured in hours.
c. only one type of cement was available.
d. several additives were available.
42. Secondary cementing is-
a. performed immediately after the casing has been run into the well.
b. performed after the primary cement job.
c. the forcing of cement behind the casing to seal off a formation or plug a
leak.
d. none of the above
43. Single-stage cementing consists of-
a. pumping a calculated volume of cement slurry into the casing.
b. displacing the slurry around the shoe and into the annulus.
c. both a and b
d. neither a nor b
44. Primary
cementing-
a. structurally supports and restrains casing.
b. seals the annulus between the pipe and formation.
c. prevents pollution of freshwater formations.
d. all of the above
45· Neat cement-
a. is cement with several additives.
b.
is an especially tailored mixture.
c. is cement without additives.
d. usually costs more than tailored mixtures.
46. A well is 12,342 ft (3,762 m) deep and is a high-temperature, high-pressure
well. Most likely, this well would be cemented with a
class-
a. D cement.
b. E cement.
c. F cement.
d. Gcement.
4 7. A cement retarder is designed to-
a. lengthen the time it takes for a cement to set.
b. shorten the time it takes for a cement to set.
c. strengthen the cement.
d. weaken the cement.
105
24.
25.
26.
27.
28.
29.
30.
31.
32.
33·
34·
35.
Matching
Usually, it is not necessary to number the joints of casing run into the well.
Rabbiting,
or drifting, a casing joint is done to determine if a casing joint is
dented, bent, or has excessive amounts of scale built up inside.
The length of each joint of casing to be run into the well shou_ld be measured,
or talleyed.
Generally speaking, it
is not all that important to condition the hole prior to
running casing.
Normally, each joint
of casing is filled with mud as it is run into the hole.
Usually, casing joints are
not lowered into the hole as fast as drill pipe joints
are lowered into the hole.
Pressure surges created by lowering the casing too fast can cause formation
breakdown and lost circulation.
Apply thread locking compound to the threads
of the first several joints of
casing to prevent them from backing off during later drilling operations.
Usually, power tongs are used to make up casing joints.
Landing the casing involves transferring the weight
of the casing string to the
wellhead.
A downhole casing hanger
is usually not used to relieve some of the load on
the casinghead.
The maximum yield strength of an API K5 5 joint of casing is 5 5 ,ooo psi.
Write the letter
of the correct definition in the blank next to each term.
36. Uses couplings to join two pin-thread pipe ends.
3
7. The threaded connection is machined into the wall of the pipe body.
38. Uses a hydraulic press to cold-form both box and pin, to expand the box and
reduce pin diameters.
39. Connections are machined directly on the pipe or onto forgings and welded
to the pipe body.
40. Require special handling and running techniques.
a. large OD connections d. premium connections
b. slim-line integral design
e. flush-joint
c. coupled design
REVIEW QUESTIONS
Multiple Choice
Pick the best answer from the choices and place the letter of that answer in the blank provided.
41. In 1903-
a. several classes of cement were available.
b. waiting on cement time was measured in hours.
c. only one type of cement was available.
d. several additives were available.
42. Secondary cementing is-
a. performed immediately after the casing has been run into the well.
b. performed after the primary cement job.
c. the forcing of cement behind the casing to seal off a formation or plug a
leak.
d. none of the above
43. Single-stage cementing consists of-
a. pumping a calculated volume of cement slurry into the casing.
b. displacing the slurry around the shoe and into the annulus.
c. both a and b
d. neither a nor b
44. Primary
cementing-
a. structurally supports and restrains casing.
b. seals the annulus between the pipe and formation.
c. prevents pollution of freshwater formations.
d. all of the above
45· Neat cement-
a. is cement with several additives.
b.
is an especially tailored mixture.
c. is cement without additives.
d. usually costs more than tailored mixtures.
46. A well is 12,342 ft (3,762 m) deep and is a high-temperature, high-pressure
well. Most likely, this well would be cemented with a
class-
a. D cement.
b. E cement.
c. F cement.
d. Gcement.
4 7. A cement retarder is designed to-
a. lengthen the time it takes for a cement to set.
b. shorten the time it takes for a cement to set.
c. strengthen the cement.
d. weaken the cement.
105
CASING AND CEMENTING
48. A cement accelerator is designed to-
a. lengthen the time it takes for a cement to set.
b. shorten the time
it takes for a cement to set.
c. strengthen the cement.
d. weaken
the cement.
49. Fluid loss additives are designed
to-
a. increase the amount of water loss to a formation.
b. extend
the yield of the cement.
c. control the amount of water lost to a formation.
d. increase the thickness
of the filter cake.
50. Heavyweight additives-
a. increase the weight of the cement to break down weak formations.
b. make
the cement heavy enough to flow on its own.
c. increase the weight of the cement to control high formation pressures.
d. increase the cost
of barium sulfate.
True or False
Put a T for true or an F for false in the blank next to each statement.
106
5 I. The water used to mix a cement slurry should be as clean as possible.
52. A common water.:.to-cement ratio is about 5.5 gal or 21 L per sack of ce
ment.
53. A recirculating
cement mixer is not used very often.
54·
55·
56.
57·
58.
59·
60.
A batch mixer has the advantage of being able to handle very large volumes
of cement.
Wiper plugs wipe mud off the outside of the casing and keep it separated from
the cement.
A float collar prevents backflow
of cement during the cementing operation.
Centralizers are designed
to keep the casing string centered in the wellbore.
Scratchers and wipers are usually welded
to the outside of the casing string.
WOC is the time required for cement to harden, anchor the casing, and seal
permeable zones.
Temperature surveys can locate
the bottom of the cement.
Identify
On the drawing below, identify the numbered parts.
61.
62.
65.
66.
REVIEW QUESTIONS
107
48. A cement accelerator is designed to-
a. lengthen the time it takes for a cement to set.
b. shorten the time
it takes for a cement to set.
c. strengthen the cement.
d. weaken
the cement.
49. Fluid loss additives are designed
to-
a. increase the amount of water loss to a formation.
b. extend
the yield of the cement.
c. control the amount of water lost to a formation.
d. increase the thickness
of the filter cake.
50. Heavyweight additives-
a. increase the weight of the cement to break down weak formations.
b. make
the cement heavy enough to flow on its own.
c. increase the weight of the cement to control high formation pressures.
d. increase the cost
of barium sulfate.
True or False
Put a T for true or an F for false in the blank next to each statement.
106
5 I. The water used to mix a cement slurry should be as clean as possible.
52. A common water.:.to-cement ratio is about 5.5 gal or 21 L per sack of ce
ment.
53. A recirculating
cement mixer is not used very often.
54·
55·
56.
57·
58.
59·
60.
A batch mixer has the advantage of being able to handle very large volumes
of cement.
Wiper plugs wipe mud off the outside of the casing and keep it separated from
the cement.
A float collar prevents backflow
of cement during the cementing operation.
Centralizers are designed
to keep the casing string centered in the wellbore.
Scratchers and wipers are usually welded
to the outside of the casing string.
WOC is the time required for cement to harden, anchor the casing, and seal
permeable zones.
Temperature surveys can locate
the bottom of the cement.
Identify
On the drawing below, identify the numbered parts.
61.
62.
65.
66.
REVIEW QUESTIONS
107
Answers to Review Questions
LESSONS IN ROTARY DRILLING
Unit 11, Lesson 4: Casing and Cementing
i. b
2. d
3· d
4· C
5. C
6. b
7. a
8. conductor casing
9. surface casing
rn. intermediate casing
1 1. production casing
12. cement
13. Tension
14. weakest
15. Collapse pressure
16. Burst pressure
1 7. Buckling stress
18. Bending
19. Axial compression
20. Torsion
21. F
22. T
23. T
24. F
25. T
26. T
27. F
28. T
29. T
30. T
31. T
32. T
33· T
34· F
35· T
36. C
37· e
38. b
39· a
40. d
41. C
42. b
43· C
44· d
45• C
46. b
47· a
48. b
49· C
50. C
51. T
52. T
53· F
54· F
55· F
56. T
57· T
58. F
59· T
60. F
61. plug container
62.
top plug
63.
bottom plug
64. float collar
65. centralizer
66. guide shoe
109
LESSONS IN ROTARY DRILLING
Unit 11, Lesson 4: Casing and Cementing
i. b
2. d
3· d
4· C
5. C
6. b
7. a
8. conductor casing
9. surface casing
rn. intermediate casing
1 1. production casing
12. cement
13. Tension
14. weakest
15. Collapse pressure
16. Burst pressure
1 7. Buckling stress
18. Bending
19. Axial compression
20. Torsion
21. F
22. T
23. T
24. F
25. T
26. T
27. F
28. T
29. T
30. T
31. T
32. T
33· T
34· F
35· T
36. C
37· e
38. b
39· a
40. d
41. C
42. b
43· C
44· d
45• C
46. b
47· a
48. b
49· C
50. C
51. T
52. T
53· F
54· F
55· F
56. T
57· T
58. F
59· T
60. F
61. plug container
62.
top plug
63.
bottom plug
64. float collar
65. centralizer
66. guide shoe
109
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