FINAL
INJECTION WELL CONSTRUCTION
PRACTICES AND TECHNOLOGY
Contract No. 68-01-5971
Submitted to
Dr. Jentai Yang
Office of Drinking Water
October 1982
Prepared for
U.S. ENVIRONMENTAL PROTECTION AGENCY
OFFICE OF DRINKING WATER
By
Geraghty & Miller, Inc.
Booz, Allen & Hamilton. Tnc
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PREFACE
This document describes construction practices and
technologies related to Class I, Class II, and selected
Class III and Class V injection wells as defined by the
U. S. Environmental Protection Agency. Topics covered
include siting, drilling, completion, equipment and mater-
ials, corrosion control, well evaluation/logging, and
formation testing. To avoid substantial repetition in the
text, the basics of these topics are presented generically
in Chapters 2 through 7.
The reader should note that the discussion of certain
types of equipment, practices, or materials is not meant
to infer their general usage in injection practices; rather,
the document attempts to present state-of-the-art conditions
in the topic areas as well as to provide a discussion
of traditional practices where pertinent. Of necessity much
of the information presented in this document is derived
from the oil and gas production literature where the ad-
vanced technologies are being developed and used. In
general, these oil-field practices and technology are
adopted and modified as needed for use in Class I, Class III
and Class V injection wells.
Class-specific, injection-well construction practices
are highlighted in Chapters 8 through 10. In these chap-
ters, specific construction practices and well designs are
described for individual injection well applications. Dis-
cussions are intended to augment, where possible, the
preceeding generic chapters. Design parameters critical to
well integrity are emphasized in order to indicate problem
areas potentially important to the regulator.
The level to which design discussions are presented
will vary due to the state of technology development.
Various Class III and Class V wells are in the research and
development phase and little design data are,- therefore,
available; that information which is available is constantly
changing with the technology development process. Even
those technologies that are commericalized, such as uranium
leaching, are not standardized as in petroleum operations
and tend to develop on a trial and error basis.
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Finally, this document is not intended to be a compre-
hensive "how-to" type treatment of injection-well construc-
tion, rather it is a reference material that describes the
different aspects of design and construction of injection
wells. Where required due to limits on size, information
more directly related to well integrity, the major area of
interest for the regulator, has been emphasized in the
document. Extensive referencing is provided to effectively
guide the reader to the accepted literature base when more
detailed information is required. No attempt has been made
to list all references available.
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ACKNOWLEDGEMENT
This report was prepared under Work Assignment No. 13
of EPA Contract No. 68-01-5971. The Geraghty & Miller,
Inc., Project Manager was Mr. William E. Thompson; the
Task Manager was Mr. Jeffrey S. Mahan. The EPA Task Manager
was Mr. Edwin Hockman.
The report was prepared by several authors from
Geraghty & Miller, Inc., and Booz, Allen & Hamilton, Inc.
Each author had primary responsibility for one or more
chapters of the report as follows:
Jeffrey S. Mahan
Dorothy A. McGlincy
Richard H. Kuhlthau
William E. Thompson
Don L. Warner
Stephen Bailey
(Booz Allen Task Manager)
David Zimomra
- Chapters 1, 5, and 10
- Chapters 3, and 10
- Chapters 7, and 8
- Chapter 8 and Report
Editor
- Chapter 2
- Chapters 6, and 9
- Chapters 4, and 9
A professional review panel was developed to oversee
the technical accuracy of the report. This panel consisted
of:
John M. Jones
Edward Kaufman
Jim Collins
Seth Abbot
Frank Wheeler
Dwight K. Smith
Jack Talbot
Vincent P. Amy
Schlumberger Well Services
Pan American Energy Corp.
Cities Service Oil Company
ARCO Oil & Gas Company
Exxon Company USA
Halliburton Services
Jack Talbot and Associates
Geraghty & Miller, Inc.
All drafting was completed by Mrs. Susan Strock.
editing was done by Mrs. Pamela Thompson.
Text
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CONTENTS
Page
1. INTRODUCTION 1
1.1 RATIONALE FOR CONSTRUCTION REQUIREMENTS. ... 2
1 .2 SUMMARY OF CHAPTERS 3
2. INJECTION-WELL SITE EVALUATION 9
2.1 SITE-EVALUATION DATA 9
2.1.1 Rock Types 9
2.1.2 Structural Geology 10
2.1.3 Engineering Properties of Rocks .... 11
2.1.4 Properties of Subsurface Fluids .... 18
2.1.5 Subsurface Resources 24
2.2 ACQUISITION AND USE OF GEOLOGIC AND
HYDROLOGIC DATA FOR WELL-SITE EVALUATION ... 24
2.2.1 Data Obtainable from Existing
Sources Prior to Drilling 25
2.2.2 Surface Geophysical Surveys 25
2.2.3 Data Obtainable During Well
Construction and Testing 25
REFERENCES. 27
3. DRILLING AND CASING METHODS 28
3.1 DRILLING TECHNOLOGY 28
3.1.1 Cable-Tool Drilling 28
3.1.2 Rotary Drilling 31
3.1.3 Reverse-Circulation Rotary Drilling . . 38
3.1.4 Other Drilling Techniques 41
3.2 DRILLING PROBLEMS 41
3.2.1 Deviated Holes 43
3.2.2 Lost Circulation 43
3.2.3 Hole Sloughing 44
3.2.4 Well Kicks 45
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3.3 WELL-COMPLETION TECHNIQUES
45
3.3.1 Casing Selection 46
3.3.2 Casing Installation 51
3.3.3 Primary Cement Selection 53
3.3.4 Primary Cementing Techniques 56
3.3.5 Secondary Cementing Methods 60
REFERENCES 67
4. CONSTRUCTION MATERIALS 69
4.1 CASING 69
4.1.1 Steel Casing 71
4.1.2 Plastic Casing 78
4.2 CEMENT 84
4.2.1 General Manufacture, Composition,
and Characteristics of Completion
Cement 84
4.2.2 Specialty Cements and Cement
Additives 90
4.3 ANCILLARY EQUIPMENT AND MATERIALS 98
REFERENCES 105
5. DOWNHOLE, WELLHEAD, AND ANCILLARY EQUIPMENT .... 107
5.1 BOTTOM-HOLE CONFIGURATIONS 107
5.1.1 Open-Hole Completion 107
5.1.2 Screened Completion . Ill
5.1.3 Perforated Casing Completion 113
5.1.4 Well Stimulation 113
5.2 WELL-COMPLETION PRACTICES 115
5.2.1 Tubing and Packer Completion 115
5.2.2 Tubing with Open Annulus Completion . . 125
5.2.3 Tubingless Completion 127
5.3 WELLHEAD EQUIPMENT 127
5.3.1 Wellhead Design and Installation. . . 127
5.3.2 Metering/Monitoring Requirements. . . 129
5.3.3 Flow Regulation Equipment 131
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5.4 INJECTION FLUID HANDLING AND SURFACE
EQUIPMENT 131
5.4.1 Pretreatment 131
5.4.2 Pumping Equipment 133
REFERENCES 137
6. CORROSION AND CORROSION CONTROL , . 139
6.1 TYPES OF CORROSION 140
6.1.1 Oxygen Corrosion. 141
6.1.2 Carbon-Dioxide Corrosion 143
6.1.3 Hydrogen-Sulfide Corrosion 144
6.1.4 Acid/Alkaline Corrosion 146
6.1.5 Galvanic Corrosion 146
6.1.6 Nonmetallic Corrosion 148
6.2 DETECTION AND MEASUREMENT OF CORROSION .... 148
6.2.1 Weight-Loss Specimens 149
6.2.2 Electrical-Resistance Probes 151
6.2.3 Electrochemical Tests 151
6.2.4 Well-Logging Methods 152
6.3 CORROSION CONTROL 153
6.3.1 Protective Coatings . 154
6.3.2 Preinjection Treatment. . 155
6.3.3 Chemical Inhibitors 157
6.3.4 Cathodic Protection 161
REFERENCES 165
7. FORMATION AND WELL EVALUATION AND TESTING 167
7.1 FORMATION AND FLUID SAMPLING 167
7.1.1 Sampling and Analysis of Drill
Cuttings 167
7.1.2 Coring. 168
7.1.3 Fluid Sampling 169
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7.2 GEOPHYSICAL LOGGING 170
7.2.1 Electric Logging 176
7.2.2 Radioactivity Logging 184
7.2.3 Acoustic Logging 189
7.2.4 Other Geophysical Logging Techniques. . 192
7.2.5 Logging Programs 201
7.3 DRILL-STEM, PRESSURE, AND INJECTIVITY
TESTING 20 3
7.3.1 Drill-Stem Testing 203
7.3.2 Wireline Formation Testing 208
7.3.3 Pressure Testing (Fracture Pressure
Determination) 209
7.3.4 Injectivity Testing 210
REFERENCES 215
8. CLASS I INJECTION WELLS 223
8.1 INDUSTRIAL DISPOSAL WELLS 223
8.1.1 Description of the Practice 223
8.1.2 Injection-Well Site Evaluation 224
8.1.3 Well Design 231
8.2 MUNICIPAL DISPOSAL WELLS 237
8.2.1 Description of the Practice 238
8.2.2 Well Design 238
REFERENCES 243
9. CLASS II INJECTION WELLS 245
9.1 SALT-WATER DISPOSAL 245
9.1.1 Description of the Practice 245
9.1.2 Well Design 248
9.2 ENHANCED OIL RECOVERY 250
9.2.1 Description of the Practice 250
9.2.2 Well Design 259
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9.3 LIQUID HYDROCARBON STORAGE 264
9.3.1 Description of the Practice 264
9.3.2 Well Design 264
REFERENCES. 267
10. SELECTED CLASS III AND CLASS V INJECTION WELLS . . 269
10.1 FRASCH SULFUR INJECTION WELLS 269
10.1.1 Description of the Practice 269
10.1.2 Well Design 269
10.2 FRESH-WATER SOLUTION-MINING WELLS 27 2
10.2.1 Description of the Practice 272
10.2.2 Well Design 273
10.3 CHEMICAL-SOLVENT SOLUTION-MINING WELLS. ... 279
10.3.1 Description of the Practice 279
10.3.2 Well Design 282
10.4 IN-SITU COMBUSTION OF FOSSIL FUELS 287
10.4.1 Description of the Practice 287
10.4.2 Well Design 290
10.5 GEOTHERMAL ENERGY DEVELOPMENT ........ 295
10.5.1 Description of the Practice. ..... 295
10.5.2 Well Design. 301
REFERENCES 304
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LIST OF TABLES
Page
1.1 FACTORS CONSIDERED IN EVALUATING CONTAMINATION
POTENTIAL 4
2.1 COMMON WATER ANALYSES PERFORMED ON SUBSURFACE
WATER SAMPLES 20
2.2 METHODS OF OBTAINING DATA ON THE CHARACTERISTICS
OF INJECTION WELLS 26
3.1 DRILLING-FLUID CHARACTERISTICS 35
3.2 ITEMS TO CONSIDER IN PLANNING FOR PRIMARY
CEMENTING 55
3.3 FACTORS THAT CONTRIBUTE TO CEMENTING FAILURES . . 57
4.1 API YIELD-STRENGTH SPECIFICATIONS FOR VARIOUS
GRADES OF STEEL CASING AND TUBING 72
4.2 CHEMICAL (PERCENT) AND HEAT TREATMENT REQUIRE-
MENTS FOR RESTRICTED YIELD STRENGTH CASING
AND TUBING 74
4.3 MINIMUM PROPERTIES OF CASING 7 5
4.4 TUBING MINIMUM PERFORMANCE PROPERTIES 76
4.5 SUITABILITY OF CASING AND TUBULAR GOODS TO
VARIOUS CORROSION ENVIRONMENTS 79
4.6 OPERATING CONDITIONS OF FIBERGLASS CASING .... 81
4.7 OPERATING CONDITIONS AND PHYSICAL PROPERTIES
OF FIBERGLASS TUBING 82
4.8 TYPICAL PHYSICAL PROPERTIES OF THERMOPLASTIC
WELL CASING MATERIALS AT 73.4° F 83
4.9 TYPICAL COMPOSITION OF PORTLAND CEMENT 86
4.10 API CEMENT CLASSIFICATION 87
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4.11 TYPICAL COMPRESSIVE STRENGTH OF CEMENT 88
4.12 HIGH-PRESSURE THICKENING TIME OF CEMENT 89
4.13 CEMENT PROPERTIES AND CHARACTERISTICS 91
4.14 APPLICATIONS, ADVANTAGES AND LIMITATIONS OF
SELECTED SPECIALITY CEMENTS 95
4.15 SUMMARY OF CEMENT ADDITIVES ........... 96
4.16 BRAND NAMES OF CEMENT ADDITIVES ......... 97
4.17 CEMENT EQUIPMENT AND MECHANICAL AIDS 99
6.1 GALVANIC SERIES FOR SELECT METALS IN SEA WATER . 147
6.2 CORROSION RATE OF METALS AND ALLOYS FOR "SOUR"
(HYDROGEN SULFIDE CONTAINING) SALT WATER .... 150
6.3 COMMON CHEMICALS USED FOR INJECTION FLUID
NEUTRALIZATION ......... 158
6.4 ALKALI AND ACID REQUIREMENTS FOR pH
NEUTRALIZATION 159
6.5 CORROSION INHIBITORS 160
6.6 CHEMICALS USED AS BACTERICIDES 162
7.1 GEOPHYSICAL WELL LOGGING METHODS AND THEIR
APPLICATION 172
7.2 SOME GEOPHYSICAL WELL LOGGING SERVICES AVAIL-
ABLE FROM THREE COMPANIES PROVIDING WELL
LOGGING SERVICES 175
8.1 FACTORS TO BE CONSIDERED FOR GEOLOGIC AND
HYDROGEOLOGIC EVALUATION OF A SITE FOR
INJECTION 225
9.1 CLASS II INJECTION WELLS 246
9.2 ANALYSIS OF NATURAL BRINES SHOWING MAJOR
CONSTITUENTS 247
9.3 ALLOWABLE TEMPERATURE CHANGE AT SHOE 260
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LIST OF FIGURES
Page
2.1 Generalized geologic sections of Cambrian and
Ordovician strata in northeastern Illinois. ... 12
2.2 Specific gravity of sodium-chloride solutions
containing different levels of total dissolved
solids 22
2.3 Hydraulic pressure gradient in a column of
water 23
3.1 Components of the string of tools for cable-
tool drilling 29
3.2 Sand pump and bailer used in cable-tool
drilling , 30
3.3 Components of the rotary drilling operation ... 33
3.4 Drill bits used in rotary drilling 39
3.5 Principles of reverse-circulation rotary
drilling 40
3.6 Examples of borehole deviations 42
3.7 Principles of casing and cementing a borehole . . 47
3.8 Well casing program and typical depth of
setting different casings 48
3.9 Conditions associated with improper and proper
methods of landing casing ..... 54
3.10 Techniques used in primary cementing 58
3.11 Squeeze-cementing operation using packer to
control pressure and flow 62
3.12 Principles of high-pressure squeeze cementing . . 63
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3.13 Principles of low-pressure squeeze cementing. . . 64
3.14 Generalized pressure-recording chart for squeeze
cementing using the hesitation techniques .... 65
4.1 Casing and cementing program for a Class I
injection well 70
4.2 Standard API coupling connections for joining
steel casing 77
4.3 Casing centralizers 100
4.4 Scratches and wall cleaners 101
4.5 Guide shoes, float collars and packer shoes . . . 103
4.6 Cement plugs 104
5.1 Well completion by the open-hole method 108
5.2 Well completion by the screen and gravel pack
method 109
5.3 Well completion by the cased and perforated
method 110
5.4 Example of slotted casing and wire-wrapped
well screens 112
5.5 Friction pressure loss of common tubing and
casing for fluid viscosity of one centipoise. . . 117
5.6 Weight-set packer 120
5.7 Rotation-set packer 122
5.8 Principles of open-annulus completion 126
5.9 Simplified wellhead assembly showing meters
and valves 128
5.10 Details of typical wellhead assembly 130
5.11 Open injection-fluid treatment system 132
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b. 1 2 Closed injection-fluid treatment system 134
5.13 Schematic drawing of complex injection-fluid
treatment system 135
6.1 Example of cathodic protection scheme for
well casing 164
7.1 Schematic diagram of spontaneous potential
log showing lithologic correlations 178
7.2 Conventional resistivity survey with lithologic
correlation 183
7.3 Schematic diagram of gamma log showing lith-
ological correlations 186
7.4 Acoustic televiewer log showing natural
fractures 193
7.5 Dipmeter log showing fracture correlation .... 195
7.6 Schematic diagram showing principles of
dipmeter logging 197
7.7 Drill-stem testing tools 205
7.8 Schematic diagram of a drill-stem test 206
7.9 Schematic diagram of a wireline formation-
testing pressure curve 211
7.10 Schematic diagram of pressure change during
hydraulic fracturing test
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7.11 Schematic diagram of step-rate injectivity
test 213
8.1 Methodology to make regional evaluation of
suitability for Class I injection we lis 226
8.2 Geologic features significant in evaluation
of Class I injection-well siting 228
d. i Methodology to make site-specific evaluat ion
of suitability for Class I injection wo 1 1 . . . . 2 30
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8.4 Schematic diagram of Class I injection well
showing geology 234
8.5 Schematic diagram of Class I injection well
at Gary, Indiana 236
8.6 Schematic diagram of Class I injection well
at West Palm Beach, Florida 240
9.1 Schematic diagram of the stream flood process . . 252
9.2 Schematic diagram of the forward in-situ
combustion process 253
9.3 Schematic diagram of the reverse in-situ
combustion process 255
9.4 Schematic diagram of the surfactant-polymer
displacement process 256
9.5 Schematic diagram of the carbon dioxide
injection process 258
9.6 Diagram of steam injection well used in the
Cat Canyon Field, California 262
9.7 Diagram of fire-flood injection well used in
the Lynch Canyon, California 263
9.8 Diagram of hydrocarbon-storage injection well . . 265
10.1 Schematic diagram of a Frasch sulfur well .... 270
10.2 Basic single-well systems for solution mining . . 274
10.3 Typical salt solution-mining well 275
10.4 Schematic diagram of the hydraulic borehole
slurry mining 278
10.5 Examples of in-situ uranium leading wells .... 284
10.6 Well patterns for in-situ leach mining of
uranium 285
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10.7 Well programs for in-situ leach mining of
copper 286
10.8 Schematic diagram of in-situ retorting of oil
shale 288
10.9 Schematic diagram of the modified in-situ
retorting process for oil shale 289
10.10 Conceptual diagram of in-situ combustion of
coal 291
10.11 Conceptual diagram of coal gasification in
steeply dippling beds 292
10.12 Conceptual diagram of packed bed coal
gasification 293
10.13 Schematic diagram of an in-situ coal con-
version well 296
10.14 Known and potential hydrothermal resources. . . . 297
10.15 Geopressured basins in the United States 299
10.16 Conceptual diagram of a dry rock geothermal
energy recovery 300
10.17 Design of geothermal energy wells 303
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1 . INTRODUCTION
Sections 146.12, 146.22, and 146.32 of the Underground
Injection Control (UIC) regulation provide the basic cri-
teria to be considered when permitting injection wells.
However, these basic criteria allow the Director to evaluate
the construction features of existing and future injection
wells with a degree of discretion. Accordingly, technical
guidance is needed to assist the regulator's efforts to
develop effective UIC programs and to implement and admin-
ister the UIC regulations. The purpose of this document
is to assist in this need, by serving as a reference for
injection-well planning and construction.
This document provides a discussion of traditional
injection-well construction practices and technologies,
and where applicable, the rationale for adopting and apply-
ing present technologies. Construction requirements in
this document are broadly defined, and include: siting,
drilling, completion, equipment and materials, corrosion
control, and well evaluation/logging and formation testing.
These topic areas are generically discussed in Chapters 2
through 7. In Chapters 8, 9, and 10, specific character-
istics of Class I through Class III and Class V injection
wells are discussed and specific examples are presented that
illustrate these characteristics.
The basis of this document will be the review and
analysis of existing sources of information concerning
all aspects of injection-well design and construction.
However, since the document is intended to assist in the
permitting of injection wells so as to ensure the "pre-
vention of movement of fluids into or between underground
sources of drinking water," emphasis will be placed on
citations related to achieving this purpose. Consequently,
to the extent that the scope of this document is constrained
by level of effort and length of presentation, information
relating to issues peripheral to the protection of drinking
water will be de-emphasized. Sources of information for
this document include materials found in libraries of
the American Petroleum Institute, U. S. Geological Survey
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and the U.S. Environmental Protection Agency. Comprehensive
computer literature searches were used to augment the
library search in all areas of injection-well construction.
In addition, experts in the field were contacted to assure
that state-of-the-art information was collected.
1.1 RATIONALE FOR CONSTRUCTION REQUIREMENTS
As a result of growing concern over the contamination
of the nation's ground-water resources, Congress has in-
cluded in the Safe Drinking Water Act of 1979, a statutory
mandate for the establishment of minimum requirements
for effective State programs designed to protect underground
sources of drinking water from subsurface injection of
contaminants. The resultant UIC regulations are intended
to broaden and strengthen these State programs as well
as to establish minimum national requirements that reflect
good engineering practice. It is also clear that many
differences exist between States, including injection
applications and geological conditions. For this reason,
the regulations are designed to allow a State to exercise
maximum flexibility in preventing contamination of drinking-
water sources. Therefore, specific engineering practices
or construction requirements are not in most cases rigidly
specified. Rather, accepted engineering practices are
described in order to provide the regulator with a frame-
work to specify construction requirements on a case-by-
case basis that should minimize the contamination potential.
As a result, the list of construction requirements developed
reflect the possible types of well or formation failures
and the factors leading to their occurrence.
Injection well operation can lead to contamination
of an underground source of drinking water (USDW) through:
(1) escape of injected fluid through the borehole into a
USDW as a result of insufficient casing, corrosion, or other
failure of the injection well casing; (2) vertical escape of
injected fluid outside the well casing from the injection
zone into an USDW; (3) vertical escape of injected fluid
from the injection zone through confining beds that are in-
adequate because of high primary perme ahi 1 i ty, solution
channels, faults, or induced fractur e s; ( 4 ) vertica 1
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escape of injected fluid from the injection zone through
nearby wells that are improperly cemented or plugged or that
have insufficient or corroded casing; and (5) lateral
migration of injected fluid originally placed in a saline-
water zone, into a fresh ground-water zone in the same
aquifer as the injection interval. Indirect contamination
of fresh ground-water can also occur when injected fluid
displaces salty formation water vertically, causing it to
flow upward into an CJSDW. The vertical flow of the saline
water could be through paths of natural or induced perme-
ability in confining beds or through inadequately cased
wells drilled through the fresh-water/ salt-water interface.
In addition to these potential problems for failure,
injection operations can hydraulically modify the injection
interval and possibly the ground-water system and introduce
into the subsurface, fluids that are different in chemical
composition from that of the natural fluids. Impacts
that could occur include: degradation of high-quality
ground water; contamination of other resources, e.g.,
petroleum, coal, or chemical brines; stimulation of earth-
quakes; chemical reaction between injectant and natural
water; and chemical reaction between injectant and geologic
materials in the injection interval.
Because of the complexity of the construction process,
the engineering principles related to the possible failure
modes defined above are a concern of the regulator. The
relationship of the principle failure modes of injection
wells to the construction considerations listed in the
regulations is presented in Table 1.1. These broadly
defined construction considerations indicate various
aspects of well design, construction, and operation that
should be carefully evaluated to determine the potential
for failure of an injection system in the UIC permitting
process.
1.2 SUMMARY OF CHAPTERS
This document is organized into ten separate but
inter-related chapters. Chapters 2 through 7 are a pres-
entation of the basic practices, materials and technology of
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TABLE 1.1
FACTORS CONSIDERED IN EVALUATING
CONTAMINATION POTENTIAL
Contamination Mode
Construction Consideration
Migration through the
borehole into fresh
water aquifer.
Vertical migration
along the borehole.
Vertical migration
through incompetent
confining zones.
Vertical migration
through nearby wells,
Lateral migration into
a zone of fresh water.
Drilling
Casing
Cement ing
Well Equipment
Logging
Corrosion Control
Testing/Monitoring
Cementing
Logging
Well Equipment
Siting
Formation Evaluation
Record Keeping
Area of review
Monitoring
Logg1ng
Moni tor i ng
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considerations for injection wells are presented in Chapters
8, 9, and 10. These chapters are intended to be a brief
introduction to the well practices and cannot be an exten-
sive discussion of each. For more information the regulator
should familiarize himself with the vast literature base
available.
Chapter 2, Injection Well Site Evaluation, describes
site evaluation data, its acquisition, and use for typical
Class I injection wells. Specific siting considerations
for other injection wells, such as those covered in Class
II, Class III, and Class V are described where pertinent in
Chapters 9 and 10.
Site evaluation data discussed include information on
rock types, structural geology, engineering properties of
rocks, properties of subsurface fluids, and subsurface
resources. These hydrologic and geologic data are first
acquired from existing sources or surface geophysical
surveys prior to drilling. If this data indicates a feas-
ible site and construction is approved, additional data can
be obtained during drilling and testing of the injection
well. Actual data requirements will vary with the complex-
ity of the geology, and the adequacy of existing informa-
tion. Methods of data collection during and immediately
after drilling include: coring and collection of cuttings,
well logging, drill-stem testing, and injectivity or pump
testing. Laboratory testing of formation fluids and the
future injectant can also be done to obtain an indication of
compatibility problems that could lead to formation plugging
or dissolution.
Chapter 3, Drilling and Casing Methods, describes
drilling methods, selection and installation of casing,
and methods of cementing casing in the borehole. Special
conditions or hazards encountered in these operations
are also discussed.
Rotary, cable tool, reverse-rotary and other methods
used for drilling injection wells are described. Hazards
related to drilling operations include hole deviation,
lost circulation, hole sloughing, and blowouts are dis-
cussed .
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Casing selection considerations are described in-
cluding setting depth, total diameter of the drilled well,
formation temperature and pressure, and the volume and
quality of injected fluid. The fundamentals of casing
installation are discussed including hole preparation,
casing make-up, running, and landing. The use of specific
equipment such as float shoes, centralizers, and scratchers
is covered. Selection of cement volume and mixture for use
in the construction process is discussed including the use
of additives and washing fluids. Both primary and secondary
cementing techniques are described including the use of
special equipment. Applications in extreme downhole envi-
ronments are considered.
Chapter 4, Construction Materials, describes the
basic materials used in well construction and their physical
and corrosion resistance properties. The discussion in-
cludes casing and tubular goods, cements, cement additives,
and related equipment used in well construction.
The physical properties of tubing are summarized
including axial loading or compressive strength, internal
pressure or burst strength, and external pressure or
collapse strength. Also, the corrosion resistance prop-
erties of various metal alloys, fiberglass, plastic, and
coatings used in tubular goods are described.
A wide range of cement types and properties are
described including applications in extremely high tempera-
ture or high fluid-loss environments. The discussion
includes the use of cement additives such as accelerators,
retarders, and density adjusters that are critical in
tailoring cementing methods to specific applications.
Equipment use in constructing the injection well
is described including centralizers, float shoes, collars,
scratchers, plugs, and cement baskets. Displacement fluids
and washes used in cementing are also described.
Chapter 5, Downhole, Wellhead and Ancillary Equipment,
describes the selection and installation of equipment
required to construct and operate injection wells. The
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chapter initially addresses bottom-hole configurations or
completions including open-hole, screened/liner, and per-
forated casing options. The various completion types used
in conjunction with these options are covered including
tubing and packers, tubing with open annulus, and tubingless
completions. Well stimulation techniques used in well
development are also described including hydraulic frac-
turing, acidization, and surging.
Equipment used in many injection-wel1 completions
is described including tubing, packers, and wellheads.
Surface equipment for water handling, monitoring, pumping,
and corrosion control is also discussed. This includes a
brief discussion of pretreatment, surge protection, and
annular inhibition.
Chapter 6, Corrosion and Corrosion Control, provides
an overview of the types of corrosion, the means of detec-
tion and possible control measures. The types of corrosion
considered include oxygen, carbon dioxide, hydrogen sulfide,
acid/alkaline, and galvanic corrosion. Detection and
measurement methods to assess corrosion behavior include
weight loss specimens, electrical resistance probes, elec-
trochemical tests, and well logging.
Corrosion control measures for injection wells can
initially involve the selection of corrosion resistant
materials such as stainless steel casing and protective
coatings. Pre-injection treatment, chemical inhibition,
and cathodic protection are also considered in the chapter.
Chapter 7, Formation and Well Evalution and Testing,
addresses the techniques used to determine subsurface
conditions including well integrity and formation charac-
teristics. Coring and sampling procedures are described
including sampling and analysis of drill cuttings and
formation coring and fluid sampling. Borehole geophysical
techniques that are used to evaluate well construction
features are described. These techniques include the
numerous electrical, nuclear, and acoustic methods as
well as caliper, electromagnetic, temperature, noise, and
7
-------
radioactive tracer logging techniques. In addition, there
are several pressure evaluation procedures, such as drill-
stem and injectivity testing, which can be used to assess
formation and well characteristics. The principles and
applications of these various techniques are discussed in
the chapter. These tests help in determining fracture
pressures and injection rates for prospective injection
intervals.
Chapter 8, Class I Injection Wells, describes the
basic practice of industrial and municipal deep-well dis-
posal. Injection-well site evaluation and formation fluid
compatibility are specifically addressed. various examples
are provided that indicate key well design parameters and
include, steel pickling wastes and nylon manufacturing
process wastes.
Chapter 9, Class II Injection Wells, describes the
basic practices and well-design characteristics used in
hydrocarbon related injection wells including salt water
disposal, enhanced recovery, and liquid hydrocarbon storage.
Chapter 10, Class III and Class V Injection Wells,
describes the basic practices, and where available, well
design characteristics used in a wide variety of energy
and mineral production technologies. These technologies
include: Frasch sulfur, fresh water solution mining,
chemical-solvent solution mining, in-situ combustion of
fossil fuels, and geothermal energy production.
Chapters 8, 9 and 10 present discussions of key param-
eters affecting the contamination potential from both
formation failure and well leakage. Key parameters include
extreme high temperature environments, subsidence, and
corrosive injectants.
Throughout the literature and in the field various
terms are used to describe the same condition or equipment,
i.e., well bore and borehole. For the sake of clarity,
this document attempts to use only one term throughout.
It is recognized, however, that the term used herein may
be inconsistent witn common practice in certain areas or
for certain well-construction practices. The regulator,
therefore, should attempt to familiarize himself witn
these "local usages."
8
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2. INJECTION-WELL SITE EVALUATION
The following section describes site-evalution data,
its application, and its use as generally applied to under-
ground injection operations. Detailed siting considerations
vary widely for the specific classes of injection opera-
tions, a result of their individual technical and resource
characteristics. (These class-specific siting considerations
are discussed in Chapters 8, 9, and 10) . The need for
collecting and reporting the following data must, therefore,
be considered on a case-by-case basis and may not be equally
applicable to the various classes of injection activities.
2.1 SITE-EVALUATION DATA
Knowledge of the site-specific and regional aspects of
the geologic and hyarologic characteristics is fundamental
to the evaluation of the suitability of the site for injec-
tion, as well as the suitability of design, construction,
operation, and monitoring. In defining the geologic en-
vironment, the subsurface rock units are described in terms
of their lithology, thickness, areal distribution, struc-
tural configuration, engineering properties, and potential
resource value. The chemical and physical properties of
subsurface fluids and the nature of the local and regional
subsurface flow system which comprise the hydrologic en-
vironment must also be defined.
2.1.1 Rock Types
Rocks are described in terms of their origin and
their lithology, the latter characteristics being defined by
their composition and texture. By origin, the three broad
rock types are classified as igneous, metamorphic, and
sedimentary. While nearly all rock types can, under favor-
able circumstances, serve as injection zones, sedimentary
rocks are most likely to have suitable geologic and en-
gineering characteristics. These characteristics are
sufficient porosity, permeability, thickness, and areal
extent to permit the rock to act as a liquid-storage res-
ervoir at safe injection pressures.
9
-------
Unfractured shale, clay, siltstone, anhydrite, gypsum,
and salt provide good seals against upward or downward flow
of fluids (salt, anhydrite, and gypsum units may also be
used as injection intervals during solution mining of these
minerals). Limestone and dolomite may also be satisfactory
confining beds; but these rocks commonly contain fractures
or solution channels, and their adequacy should be deter-
mined in each case.
Study of the composition, sequence, thickness, age, and
correlation of the rocks in a region is stratigraphic
geology or stratigraphy. The basic means of display of data
used in stratigraphic studies is the columnar section, which
is a graphic representation of the rock units present at a
location or in a region. Figure 2.1 is a generalized
columnar section for northeastern Illinois. This partic-
ular example was selected because it shows a variety of rock
types, is typical of the east-central states, and is easily
interpreted and discussed.
2.1.2 Structural Geology
Structural geology is concerned with the folding and
fracturing of rocks and the geographic distribution of
these features. Structural geologic characteristics of
a region and, on a smaller scale, of a particular site
are significant because of their role in influencing sub-
surface fluid flow, the engineering properties of rocks,
and the localization of mineral deposits and earthquakes.
Sedimentary rocks may be folded into synclines (downward
or trough-like folds) or anticlines (upwards folds). Syn-
clinal basins of a regional scale (hundreds of miles)
are viewed as particularly favorable for injection.
Faults are fractures in the rock sequence along which
there has been displacement of the two sides relative
to one another. Such fractures may range from inches
to miles in length and displacements are of comparable
magnitudes. Faults may occur singly or in systems s o
complex that it is not possible to completely define them.
Faults may act either as barriers to fluid movement
or as channels for fluid movement. However, 1ittIe detail
is kn o w n about how or wh y s ome fault s a r e b a r r i e r a n d
-------
others are flow channels. In theory, no fault in a sed-
imentary rock sequence will be an absolute barrier, but
a fault may be of such low permeability relative to the
aquifer it cuts, that it is, for practical purposes, a
barrier. Since it will seldom be possible for a geologist
to initially state whether a fault is a barrier or a flow
path, for purposes of preliminary evaluations it would be
appropriate to consider any significant fault to be a flow
path. A significant fault might be defined as one that is
of sufficient length, displacement, and vertical persistence
to provide a means of travel for injection fluids to an
undesirable location such as an underground source of
drinking water. If, as a consequence of this initial
assumption, the fault would be an environmental hazard it
may be necessary to either test the fault directly rising
field injection techniques or abandon the site for injection.
Within the past decade observations and research
have led earth scientists and engineers to the conclusion
that, under certain circumstances, subsurface fluid injec-
tion can stimulate movement along some faults. When move-
ment occurs, stored seismic energy is released as an earth-
quake. Although much remains to be learned about this
subject, it appears that the circumstances favorable to
earthquake generation are relatively rare (Warner and Lehr,
1977) .
Fractures also exist along which there has been no
movement. This type of fracture may be referred to as
a crack or joint to distinquish it from a fault. Cracks and
joints are important sources of porosity and permeability in
some aquifers, but can be undesirable when they channel
fluids rapidly away from an injection well in a single
direction or where they provide flow paths through confining
strata. The presence and nature of fractures is determined
by examination of rock cores obtained during drilling, by
well logging and testing methods, and from experience with
other wells drilled in the same region.
2.1.3 Engineering Properties of Rocks
To make a quantitative evaluation of the mechanical
response of the subsurface environment to injection, the
engineering properties of the injection zone including
1 1
-------
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-------
porosity, permeability, compressibility, temperature, and
state of stress must be determined.
Porosity
Porosity is the ratio of the volume of void spaces
in a rock to total volume of the rock expressed as a decimal
fraction or percentage.
[dimensionless] (2-1)
Vt
where:
0 = Porosity
Vv = Volume of Rock
Vt = Total volume of Rock Sample
Porosity may be expressed as either total porosity or
effective porosity. Total porosity is a measure of all void
space; effective porosity is a measure of the volume of
interconnected voids. Effective porosity is more closely
related to the hydraulic properties of a rock unit since
only interconnected pore spaces are available to fluids
flowing through the rock.
Additionally, porosity may be either primary or sec-
ondary. Primary porosity includes original intergranular or
intercrystalline pores and is also associated with fossils
and bedding planes. Secondary porosity results from frac-
tures, solution channels, and recrystallization and dolo-
mitization. Intergranular porosity occurs principally in
unconsolidated sands and in sandstones, and depends on the
size distribution, shape, angularity, packing arrangement,
mineral composition, and degree of natural cementation of
the grains.
Porosity can be measured in the laboratory on con-
solidated rock cores taken during drilling. Core analysis
of unconsolidated material is difficult, but techniques have
13
-------
recently been developed to obtain cores from such formations
and to perform laboratory analyses upon them with some
assurance that the results are representative of the in-situ
formation properties (Mattax and Clothier, 1974).
Porosity contributed by fractures and solution channels
is also difficult to measure in the laboratory. A major
deficiency of core analysis is that samples being measured
comprise only a small fraction of the interval of interest
and may not be representative of the rock in place. To
determine the porosity of strata in place, various borehole
geophysical methods can be used (see Chapter 7).
The porosity of sedimentary rocks range from over 35
percent in newly deposited sand to less than 5 percent in
lithified sandstone. Dense limestone and dolomite may
have almost no porosity. Porosity is not a direct measure
of the overall reservoir quality of a rock unit, but a
reservoir with high porosity is generally better than one
with low porosity.
Permeability
The permeability of a rock is the measure of its
capacity to transmit a fluid under an applied potential
gradient. The term hydraulic conductivity is frequently
used interchangeably with the term permeability, but they
are not truly interchangeable. (Hydraulic conductivity is a
measure of the quantity of water at a specified temperature
tnat will flow through a unit cross-sectional area of a
porous material per unit of time under a unit hydraulic
gradient.)
p = [V/L2! (2-2)
Ad
where:
P = Coefficient of Permeaoi1ity
- Flow Rate
I = Hydraulic Gradient
A(-j - Cross-Sectional Area
-------
As with porosity, intergranular permeability is in-
fluenced by the grain properties of rocks (sand, sandstone,
siltstone, shale, etc.). Whereas porosity is not theoret-
ically dependent on grain size, permeability is strongly
dependent on this property. The smaller the grains, the
larger will be the surface area exposed to the flowing
fluid. Since it is the frictional resistance of the surface
area that lowers the flow rate (i.e. the smaller the grain
size, the lower the permeability), shales are generally good
confining intervals. As with effective porosity, permea-
bility also results from interconnected solution channels
and fractures as well as from interconnected intergranular
spaces.
Permeability values from core samples of units used
for injection range from over one hundred gallons per day
per square foot (gpd/ft^) (greater than 1 x 10~3 cm/sec)
to less than 0.1 gpd/ft^ (less than 1 x 10~6 cm/sec);
but, an average value of less than 1 gpd/ft (1 x 10~5
cm/sec) for an overall interval would be considered to be
very low, and a value of 0.5 to 5 gpd/ft^ (l x 10~4 to 1
x 10"~3 cm/sec) would be good to very good. Shales, which
are considered to be suitable confining strata, have perme-
abilities on the order of 10~^ gpd/ft^ (less than 1 x
10~9 cm/sec), or thousands of times less than an adequate
injection interval. As with porosity, permeability can be
measured on core samples in the laboratory or by tests
performed in the borehole (see Chapter 7).
In evaluating the suitability of an injection or
confining unit, injection-zone thickness is as important as
permeability. Saturated injection-zone thickness multiplied
by permeability is the transmissivity of the rock unit, the
rate at which fluid at the existing fluid viscosity and
density is transmitted through a unit width of aquifer at a
unit hydraulic gradient. The unit of transmissivity (T) is
gallons per day/foot, square feet/day or square meter/
second.
The permeability of an injection zone to two or more
fluids of differing capillary properties is not the same as
the permeability to a single fluid. When two fluids, for
example water and oil, are flowing simultaneously through a
rock, the permeability to either is lower than it would be
if the rock were fully saturated with one of the fluids.
1 5
-------
Compressibi1ity
The compressibility of an elastic medium is defined as:
8 = ~ 9V [F/L2]"1 (2-3)
V 3 P
where:
6 = Compressibility of Medium
V = Volume
P * Pressure
The compressibility of an aquifer includes the com-
pressibility of the rock material and of the contained
fluids. To account for the compressibility of both,- en-
gineers often arbitrarily use a compressibility which ranges
from 5 x 10~6 to 1 x 10-^ psi-"' [3.4 x 10-2 to 6.9 x 10-2
(N/m2)-!] compared with the compressibility of water alone
which is about 3 x 10~® psi-^ [2.1 x 10~2 (N/m2)-^) (Amyx,
et al. 1960). Van Everdingen (1968) uses this procedure in
arbitrarily selecting a fluid and rock compressibility of 6
x 10~6 psi-^ [4.1 x 10~2 (N/m2)""^] for the example cal-
culations that he presents.
A parameter related to compressibility is the storage
coefficient (S) which is defined by Lohman (1972). The
storage coefficient is the volume of water an aquifer
releases or takes into storage per unit surface area per
unit change in hydraulic head. Storage-coefficient values
are d imens ionless and normally range from 5 x 10~5 to
5 x 10~3 for confined aquifers. The storage coefficient
may be estimated, or it may be determined from aquifer
tests.
Temperature
The temperature of the aqu i f er and its con t: a i n•?ci
i 1 u i ds is important b ecause of th c e £ f e cts that te m: > e r a tun :•
has on fluid properties. The temperature of shallow ground
-------
water is generally about 2°F to 3°F (1.2°C to 1.8°C) greater
than the mean annual air temperature. Below the shallow
ground-water interval, the temperature increases at an
average rate of about 1.5°F per 100 feet of depth (3°C per
100 meters) but the rate of increase is variable and may
range from as much as 5°F (9.8°C) to less than 1°F (2.0°C)
per 100 feet of depth (9.8°C to less than 2.0°C per 100 m)
(Levorsen, 1967). This temperature increase with depth is
termed the geothermal gradient. The geothermal gradient is
determined from temperature measurements made in deep wells
and is calculated by dividing the difference between the
temperature at a point in the subsurface and the mean annual
surface temperature by the depth to the observation point.
Geothermal gradient maps for the United States have been
prepared by the American Association of Petroleum Geolo-
gists, Tulsa, Oklahoma, and can be obtained from that
organization.
State of Stress
In a sedimentary-rock sequence, the total normal
vertical stress increases with depth of burial under
increasing thickness of overburden. It is commonly assumed
that the normal vertical stress increases at an average
of about 1 psi per foot of depth (2.26 N/m^ per meter).
The lateral stresses may be greater or lesser than the
vertical stresses, depending on geologic conditions (Warner
and Lehr, 1977). In areas where crustal rocks are actively
compressed, lateral stresses may exceed vertical ones. In
areas where cru&tal rocks are not in active compression,
lateral stresses may be less than the vertical stresses.
Prior to drilling a well, lateral stress may be estimated
from hydraulic-fracturing data of nearby wells and/or
knowledge of the tectonic state of the region in which the
well is located. Only now is the tectonic state of various
regions being determined. For example, Kehle (1964) con-
cluded, as a result of hydraulic fracturing data from four
wells, that the stresses at well locations in Oklahoma and
Texas were representative of an area that was tectonically
in a relaxed state. Sbar and Sykes (1973) characterized
much of the eastern and north-central United States as being
in a state of active tectonic compression.
To predict the pressure at which hydraulic fracturing
or fault movement would be expected to occur, it is neces-
sary to estimate the state of stress at the depth of the
17
-------
injection zone. On the other hand, determination of the
actual fracturing pressure allows computation of the state
of stress (Kehle, 1964).
The general equation for total normal stress across
an arbitrary plane in a porous medium is (Hubbert and
Willis, 1972):
S = p + a [F/L2] (2-4)
where:
S = Total Stress
p = Fluid Pressure
a = Effective or Intergranular Normal Stress
Effective stress, as defined by Equation 2-4, is the
stress available to resist hydraulic fracturing or the
stress across a fault plane that acts to prevent movement on
that fault. The equation shows that if total stress
remains constant, an increase in fluid pressure reduces the
effective stress and a decrease in fluid pressure increases
effective stress. When the effective stress is reduced to
zero by fluid injection, hydraulic fracturing occurs. In
the presence of a fault along which shear stress already
exists, fault movement will occur before normal stresses
across the fault plane are reduced to zero.
2.1.4 Properties of Subsurface Fluids
To evaluate the chemistry of aquifer water and the
compatabi1ity of the injection fluid, it is necessary to
obtain samples after a well is drilled; samples from pre-
viously drilled wells may provide a good indication of what
will be found. Geophysical logs are also useful for esti-
mating the dissolved-solids content of aquifer water in
intervals that are not sampled (see Chapter 7). The range
of dissolved ions present in ground water is so great that a
complete chemical analysis is seldom performed. In most
instances, an analysis will be made for the principal ions
and others on a selected basis. Other fluid properties that
may be important in site evaluations are viscosity, density,
u r e s •> u r, and compre s s i b Hit v .
-------
Chemistry
Chemical analyses of ground water are useful for
correlation of stratigraphic units, interpretation of
subsurface-flow systems, and calibration of borehole logs.
The chemistry of contained water is important because of the
possibility of reaction with injection fluid and effects on
the integrity of well components.
Table 2.1 lists the chemical and physical determina-
tions that may be made for the naturally occurring water in
an injection zone. The routine determinations characterize
the general geochemical nature of the water. The additional
analyses suggested for an injection zone are for the purpose
of predicting the reactivity of that water with the injec-
tion fluid, and would be selected on the basis of reactions
that are suggested by the chemistry of the two fluids.
Samples of water taken from shallow fresh-water aquifers
should be analyzed more completely for minor elements so
that their baseline quality is well established and the
presence of any introduced contaminants can be detected.
Viscosity
Viscosity is the property of a fluid to resist flow,
and is important in determining the rate of flow of a fluid
through a porous medium. The common unit of viscosity
is the poise, centipoise or Newton-second per square meter.
Both temperature and dissolved solids content can have a
significant effect on viscosity. In most cases, the effects
will tend to be offsetting, since temperature and dissolved
solids content both commonly increase with increasing depth.
Density
The density of a fluid is a measure of its mass per
unit volume. While liquid density increases with increasing
pressure and decreases with increasing temperature, the
changes are very small within the range of pressures and
temperatures of interest to injection-well operators. For
example, the density of water decreases only 0.04 gm/cm^
when temperature increases from 60°F to 210°F (15.5°C to
98.8°C), and increases only about 0.04 gm/cm-^ from 0 to
19
-------
TABLE 2.1
COMMON WATER ANALYSES PERFORMED ON
SUBSURFACE WATER SAMPLES
(Warner and Lehr, 1977)
Injection-Interval
Determination Routine Analysis Water Analysis
Alkalinity
X
X
Aluminum
X
Barium
X
Calcium
X
X
Chloride
X
X
Dissolved Oxygen
X
Hydrogen ion (pH)
X
X
Iron
X
X
Magnes ium
X
X
Manganese
X
Potassium
X
X
Sod i uro
X
X
Specific Conductance
X
X
Specific gravity
X
X
Sulfate
X
X
Total Dissolved Solids
X
X
-------
1 4 , 000 psi (0 to 9.65 x 10^ N/m^). a more important
influence on water density is the total dissolved solids
content. Figure 2.2 shows the effect of various amounts of
sodium chloride on density as expressed as specific gravity
at 60°P (15.5°C). Since natural brines may differ signif-
icantly from sodium-chloride solutions, it may be desirable
to develop empirical relationships between density and
dissolved solids.
Pressure
A knowledge of fluid pressure in the zone proposed
for injection is important. Fluid pressure can be measured
directly in the borehole at the depth of the injection
zone by performing a drill-stem test (see Chapter 7).
Fluid pressure at the injection zone can also be measured
indirectly by determining the static water level in the
borehole and computing the pressure of the fluid column at
the depth of interest.
Figure 2.3 shows how fluid pressure increases with
depth in a borehole filled with fresh water having a spe-
cific gravity of 1.0. When the average specific gravity
of the water is other than 1.0, the rate of pressure in-
crease varies accordingly. For example, a borehole filled
with water having a dissolved-solids content of 65,000
mg/1 has a specific gravity of 1.035. Fluid pressure,
therefore, increases at a rate of 0.45 psi/ft (1.035 x
0.433 psi/ft) (1.02 x 10^ N/m^ per meter), and would be
450 psi (3.1 x 10® N/m^) at the bottom of a 1,000-ft-
deep (304.8 m) water-filled hole.
Anomalous formation pressures may be encountered
at sites selected for injection; the existence of unusually
high or low pressures and the possible reasons for their
existence should be recognized. Hanshaw and Zenn (1965)
list ten possible causes of anomalous pressure: (1) high
hydraulic head, (2) rapid loading and compaction of sedi-
ments, (3) tectonic forces, (4) temperature effects, (5)
osmotic-membrane phenomena, (6) "fossil" pressure cor-
responding to previous greater depth of burial, (7) infil-
tration of gas, (8) mineral-phase changes involving water,
(9) solution or precipitation of minerals, and (10) water
from magmatic intrusions. Of these mechanisms, the first
five most commonly occur. Large scale injection or ex-
traction of fluids can also cause anomalous pressure con-
ditions .
21
-------
1.15
I. 10
.05
00
-
-
i i i
i i i i
i i i i
i i i i
i i i i
0
50,000 100,000 150,000
TOTAL SOLIDS (PPM)
200,000 250,000
Figure 2.2. Specific gravity of sodium-chloride solutions containing
different levels of total dissolved solids
-------
XjlLft
i
Jr~
/
/
j—
c.
/
/
.7
j—
J—
j"*
j-'
/
°-433=!Sr ^ 0R psi/ft
0.433
0.433
0.433
0.433
0.433
0.433
0.433
0.433
0.433
4.33 psi/10 feet
Figure 2.3. Hydraulic pressure gradient in a column
of water (Warner and Lehr, 1977)
23
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Compressibility
All pore space in strata used for injection is already
fluid-filled. Injection fluid is emplaced by displacing
and compressing ground water and by compressing the rock
material of the aquifer. The compressibility of water
varies both with temperature and pressure; however, water
compressibility will_ generally be within-the range of 2_,8
x 10 b to 3.3 x 10 psi , [1.9 x 10 1 to 2.28 x 10
(N/m )~ ].
2.1.5 Subsurface Resources
It is the goal of both regulatory agencies and well
operators to prevent jeopardizing underground sources
of drinking water, oil or gas, coal, and other subsurface
resources. Therefore, the occurrence and distribution
of all significant subsurface resources may be determined.
This determination is made from reference to published
reports and by consultation with public officials, com-
panies, and individuals familiar with subsurface resources
of the area. Also, the actual drilling will show the
location and nature of resources present at the well site.
2.2 ACQUISITION AND USE OF GEOLOGIC AND HYDROLOGIC DATA
FOR WELL-SITE EVALUATION
To predict the performance of injection wells and
their effects on the environment, the type of evaluation
data described above must be estimated prior to well con-
struction, and the actual geologic characteristics and
values for rock and fluid properties determined during
well construction and testing. After the geologic and
engineering data are obtained, they may be evaluated qual-
itatively by professionals or they may be used in cal-
culations to predict the probable performance of a we11
constructed at the site.
S4
-------
2.2.1 Data Obtainable from Existing Sources Prior to
Drilling
Prior to drilling, the geologic and engineering data
needed for site evaluation are obtained, where available,
from Federal and State geological surveys, State oil and
gas agencies, State water resources agencies, and some
universities. In addition, private companies in the petro-
leum industry acquire and sell well logs, other subsurface
data, and services. In some cases it may be feasible to go
to individual oil companies or consultants for subsurface
data that are not publicly available.
2.2.2 Surface Geophysical Surveys
It is possible to obtain considerable original sub-
surface geological information without drilling by the
use of surface geophysical methods, including seismic,
electrical, magnetic, and gravity surveys. However,
it can be anticipated that surface geophysical surveys
will not be widely used for injection-well site studies
because of the nature of the data obtained and its costs.
2.2.3 Data Obtainable During Well Construction and Testing
A wealth of subsurface geologic and engineering
information can be obtained during the drilling and the
testing of any well. The extent to which information should
be obtained depends on the availability of existing data
in the immediate vicinity of the well. Where extensive
data are available, such as in a developed oil field, a
minimal amount of new information will usually be acquired.
At a site where no wells have previously been drilled
within miles, it may be necessary to collect all the impor-
tant information during installation of a test boring or
well.
Methods of data collection during drilling of the
test well are presented in Table 2.2. Such data can be
used to make quantitative calculations concerning injection-
zone performance.
25
-------
TABLE 2.2
METHODS OF OBTAINING DATA ON
THE CHARACTERISTICS OF INJECTION WELLS
A. Coring and collection of cuttings
B. Formation fluid sampling
C. Well logging including:
1. Sample (cuttings and core) logs.
2. Driller's logs.
3. Drilling time logs.
4. Mud logs.
5. Geophysical logs:
a. electrical logs;
b. elastic wave logs;
c. radiation logs;
d. other.
6. Miscellaneous logs:
a. caliper logs;
b. dxpmeter logs;
c. deviation logs;
d. product ion-injection logs.
D. Drill-stem testing.
E. Injectivity or pump tes t ing.
-------
REFERENCES
Amyx, J. W. , D. M. Bass, and R. L. Whiting, 1960. Petrol-
eoum reservoir engineering. McGraw-Hill Book Co.,
New York,- New York.
Bauschbach, T. C., 1964. Cambrian and Ordovician strata
of northeastern Illinois. Illinois Geological Survey,
Report of Investigations 218.
Hanshaw, B. B., and E. Zenn, 1965. Osmotic equilibrium
and overthrust faulting. Geological Society of Amer-
ica Bulletin, 76(12):1379-1385.
Hubbert, M. K., and D. G. Willis, 1972 . Mechanics of
hydraulic fracturing, jj2 Underground waste mange-
ment and environmental implications, T. D. Cook,
Ed. American Association Petroleum Geologists, Memoir
18.
Kehle, R. 0., 1964. The determination of tectonic stresses
through analysis of hydraulic well fracturing. Jour-
nal of Geophysical Research, 69(2): 259-273.
Levorsen, A. I., 1967. Geology of petroleum. W. H. Freeman
and Co., San Francisco.
Lohman, S. W., 1972. Ground-water hydraulics. U. S.
Geological Survey, Prof. Paper 708.
Mattax, C. C., and A. T. Clothier, 1974. Core analysis of
unconsolidated and friable sands. Society of Petroleum
Engineers, SPE Paper No. 2986.
Sbar, M. L. , and M. L. Sykes, 1973. Contemporary compres-
sive stress and seismicity in eastern North America;
an example of intra-plate tectonics. Geolog ical
Society of America Bulletin, 84(6):1861-1882.
van Everdingen, A. F., 1968. Fluid mechanics of deep-well
disposal, _in Subsurface disposal in geologic basins-
a study of reservoir strata, J. E. Galley, Ed. Amer-
ican Association Petroleum Geologists, Memoir 10.
Warner D. L., and J. H. Lehr, 1977. An introduction to
the technology of subsurface wastewater injection.
U. S. Environmental Protection Agency, EPA-600/2-77-
240 .
27
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3. DRILLING AND CASING METHODS
Chapter 3 outlines a general description of drilling
techniques, their selection, and their capabilities. The
installation of casing and methods of cementing it in the
borehole are provided. Special conditions encountered in
these operations are also discussed.
3.1 DRILLING TECHNOLOGY
Various methods are used to drill injection wells.
The choice of drilling method depends upon the purpose
of the well, the geology of the well site, the character
of the formations to be drilled, the depth of the injection
zone, the availability of drilling equipment, and other
site-specific factors. Injection wells are generally
drilled in a manner similar to oil, gas, or water wells.
The three major methods used for drilling are the
cable-tool method, the rotary method, and the reverse-rotary
method. The other less widely used methods will be dis-
cussed briefly.
3.1.1 Cable-Tool Drilling
Cable-tool drilling was the method used to drill the
first oil wells in the United States (Campbell and Lehr,
1973). Drilling is performed by lifting and dropping a
heavy string of tools suspended at the end of a cable. The
tools consist of a bit, drill stem, drilling jars, and
rope socket (Figure 3.1). As the string strikes consol-
idated rock, the bit chips the rock into fragments; in
unconsolidated sediment, the bit loosens the material.
Water is added to the borehole in dry formations to cool the
bit and to form a slurry of cuttings which is removed by
a sand pump or bailer (Figure 3.2). A check valve retains
the slurry in the bailer for removal.
Cable-tool, drilling in unconsolidated sediment differs
from drilling in consolidated rock. A casing is usually
driven into tne unconsolidated sediment, the bit is used
to loosen the sediment plug inside the casino, water is
-------
Drill line
Rope .
socket
Tool
joint
0
D
k
w
Dot
—Tool joint
-*—Drilling jars
Wrench
square
Drill
stem
Water
course
0
Wrench
square
Tool joint
a m
Drill bit
Figure 3.1.
Components of the string of tools for
cable-tool drilling (Johnson Division,
UOP, Inc., 197 5)
29
-------
SAND
PUMP
BAILER
Q
l-j'Jf'1 i .i. Sami ;-u;n:/ ami oa 1 l*r -i 1
aril 1 tii'] (Jonnson iuviaion ,
19 7b)
-------
added to the pipe, and the slurry is bailed out. The
driving, drilling, and bailing are continued until the
casing reaches the final depth. The driven casing cannot
always be pushed to the total depth of the well in one
length. Casing lengths are limited primarily by friction on
the outside and by potential buckling of the pipe. Conse-
quently, it is common to telescope smaller diameter casings
in the well for continued drilling to the total depth.
Cable-tool drilling rates are affected by the resis-
tance of the rock, the weight of the drill tools, the
diameter of the bit, the length of the stroke, the number
of strokes per minute, and the thickness and depth of
accumulated cuttings in the borehole (Johnson Division,
UOP, Inc., 1975). With increased depth, more time is re-
quired to remove drilling tools, bail out the slurry, and
reinsert the tools. Longer cable lengths require reduced
tool weights and shorter strokes. Although a record depth
of 11,145 feet (3,397 m) has been documented (Campbell and
Lehr, 1973), such labored drilling has limited well depth to
less than a few thousand feet. The cable-tool method is
seldom used for construction of injection wells because
other drilling methods permit faster completion times, and
permit cementing programs to protect underground sources
of drinking water. Many old oil and gas wells, constructed
by the cable-tool method, may subsequently be converted
to injection wells.
The cable-tool method is advantageous when accurate
formation samples are necessary. The formation cuttings
are not as contaminated with drilling fluid (mud) nor
are they as finely crushed as in rotary drilling. Exact
depths of formation changes are easier to identify. Other
advantages include a low operating cost, low demand for
water, and rigs that are well suited to rugged terrain
(Campbell and Lehr, 1973; Johnson Division, UOP, Inc.,
1975).
3.1.2 Rotary Drilling
The rotary drilling method is the technique most widely
used for injection-well drilling (Warner and Lehr, 1977).
Rotary drilling became popular in the early 1900s because
the method is faster than cable-tool drilling and deeper
31
-------
holes of larger diameter can be drilled. The rotary-
drilling method is used for water-well and injection-well
drilling, but the wealth of research and data available
comes from the oil and gas industry.
Rotary drilling consists of a rapidly rotating bit
which cuts the borehole while drilling fluid is circulated
down the drill pipe to remove the cuttings from the hole.
The drilling fluid is forced out through the bit to cool
and lubricate it. The fluid, carrying cuttings, flows
upward to the surface through the annulus formed between
the outside of the drill pipe and the borehole. The drill-
ing fluid flows through a ditch or shale shaker where
samples may be collected. It then flows into a pit where
cuttings settle out and it is finally pumped back down
the hole (Campbell and Lehr, 1973; Johnson Division, UOP,
Inc., 1975; Warner and Lehr, 1977).
The components of a rotary-drill operation are il-
lustrated in Figure 3.3. At the base of the borehole
is a drill bit which is attached to the lower end of a
strong-walled pipe called a drill string. The drill string
consists of one or more drill collars and several rods.
The drill collars concentrate weight near the bit to keep
the hole as straight as possible. The drill rods are
then attached to the kelly at the top.
The kelly passes through the opening in the rotary
table on the drill rig. The kelly is designed to engage
the drive bushings in the rotary table and force the entire
drill string to turn with the rotary table. As the rotary
table and drill string rotate, the kelly slips through
the drive bushings feeding the bit downward, thus drilling
the hole. The upper end of the kelly connects to a water
swivel and the entire string hangs from the swivel suspend-
ed from a traveling block in the derrick (Johnson Division,
UOP, Inc., 19 75).
Various drilling fluids are used in rotary drilling
including water, water mixed with clay, oil-based fluids,
air, gas, or foam. The drilling fluids most commonly
used are emulsion muds which are a suspension of solids and
droplets of liquids in a second liquid, or drilling muds
which are a suspension of solids in a liquid. A common
arilling mud is composed of bentonite clay and water (Camp-
bell and Lehr, 1973; Petroleum Extension Service, 1975).
-------
[-*
Sheave
Crown block
Figure 3.3. Components of the rotary drilling operation
33
-------
The drilling fluid is used to clean the borehole and
keep it free of cuttings. The ability of a drilling fluid
to transport cuttings out of the hole is dependent upon the
rate of circulation of the fluid and the characteristics of
the fluid itself. Some drilling fluids keep cuttings in
suspension when circulation stops during bit changes and
drill-rod connections, whereas others (air, gas, and water-
based drilling fluids) allow cuttings to settle. The
borehole should be properly cleaned before circulation is
stopped to prevent settling of cuttings. Cuttings carried
to the surface in the drilling fluid are collected for
analysis to allow geologic interpretation.
Hydrostatic pressure exerted by the column of drilling
fluid helps prevent the borehole wall from caving and
prevents inflow of formation water, oil, or gas. Minimum
drilling-fluid weights are desirable to allow maximum
drilling rates and to lessen lost-circulation problems.
With increased formation pressures, however, the weight of
the drilling fluid must be increased.
A build-up of drilling fluid on the borehole wall
produces a wall cake (filter cake or mud cake). This
layer of wall cake helps to prevent the borehole wall from
caving. Wall cake also prevents drilling-fluid loss (lost
circulation) to the formation during drilling. Special
drilling fluid additives such as polymers, sawdust, and lime
are used to produce wall cake that is highly effective in
preventing lost circulation. It is important to control the
build-up of wall cake to prevent sticking of drilling tools
or other equipment in the hole.
The decision to use a particular type of drilling
fluid is dependent on expected downhole temperature ana
pressure, total borehole depth, geologic formations, total
diameter of casing, thickness of cement seals, constraints
of time ana money, and availability of drilling rigs and
associated equipment. A summary of drilling fluid infor-
mation is presented in Table 3.1.
The bit and drilling fluid are interdependent factors
of the rotary-drilling operation. The two basic types of
bits used for drilling are the roller-type tor rock forma-
tions, and the a rag-type for unconsolidated format i ons . The
rol ler: bit exerts a crushing and chippino act ion on consul 1-
uatea rock. Drag bits shear and scrape unconsolidated and
3 4
-------
TABLE 3.1
drilling-fluid characteristics
Type of Drilling Fluid Primary Benefit or Limitation
WATER-BASED MUDS
1)
Fresh-water
muds (none
or few chem-
ical addi-
tives )
2)
Chemically-
treated muds
3) Salt-water
muds
This is a common type of fluid
used for drilling the surface hole
and generally uses formation clays
for the mud. Large volumes of rel-
atively soft fresh water are needed,
These muds are inexpensive but
are usually used only for shallow
formations.
These fluids are used as defloccu-
lants, generally in areas of soft
water and natural clays. Chemic-
ally treated muds are beneficial
for reducing viscosity, gel
strength and filtration rate but
they cannot withstand temperatures
above 93°C (200°F). These muds are
not effective when contaminated by
calcium or salt.
Salt-water muds minimize excessive
hole enlargement during drilling of
a salt formation. Seawater muds
are generally used for offshore
drilling operations. Limitations
of these muds include high costs,
potential corrosion problems, ben-
tonite yield is reduced, and for-
mation evaluation methods are less
effective (especially specific
potential logs).
35
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TABLE 3.1 (Cont'd)
Type of Drilling Fluid
Primary Benefit or Limitation
4) Oil-emulsion
muds (oil-
in-water
muds)
Oil-emulsion muds lessen sloughing
of shale formations, limit hole
enlargement, increase bit life, and
increase drilling rates. Oil-
emulsion muds are more expensive
than other water-based muds.
II. OIL-BASED MUDS
Invert emulsion
muds (water-in-
oil) and oil
based muds
These muds allow for more rapid
drilling rates than water-based
muds. There is no swelling or
shrinkage of clays, pipe stick-
ing is reduced, and shale prob-
lems lessened. Oil-based muds
are more temperature stable than
water-based muds and are beneficial
in salt formations by limiting
hole enlargement. Mud costs
are high and there is a potential
for water-contamination problems.
III. AIR-GAS FLUIDS
1) Air or natural
gas
Air or natural gas provides
maximum penetration rates with
low costs. There is no forma-
tion damage and no wallcake
buildup. The method is advan-
tageous in areas of cavernous
limestone or highly fractured
rock which would cause lost
circulation in conventional
rotary drilling.
-------
TABLE 3.1 (Cont'd)
Type of Drilling Fluid Primary Benefit or Limitation
Mist is used when there is too
much natural formation fluid
to drill with air. This
method requires 30 to 35 per-
cent more air pressure than
in dry air drilling with the
potential result of sloughing.
Foam lifts cuttings from hole
and provides good hole clean-
ing capabilities in addition
to reducing hole sloughing.
Bit life is generally improved
over dry air drilling.
4) Aerated mud Aerated muds are used when it
is impossible to drill with
air, lost circulation is
minimized but corrosion may
be severe. This method
requires the use of good
quality, low gel strength
mud with sufficient surface
casing to limit destruction
of upper hole.
2) Mist
3) Foam
37
-------
soft formations. A jet of drilling fluid is run through the
drill bit to cool it, to clean it, and to flush cuttings
from the borehole. Figure 3.4 illustrates the various types
of bits used in rotary drilling.
Rotary drilling is generally considered the fastest,
most convenient, and least expensive drilling method,
especially in unconsolidated formations (Freeze and Cherry,
1979). This technique provides the opportunity to drill
wells of various diameters and greater depths than with
cable-tool drilling.
Several disadvantages inherent in the rotary-drilling
operation involve the mixing of formation cuttings from
different depths which can cause inaccurate descriptions
of formations, clogging of permeable formations by wall-cake
build-up in the borehole, and contamination of cement.
Other problems can arise because certain types of drilling
fluids and additives interfere with geophysical logging
(Campbell and Lehr, 1973).
3.1.3 Reverse-Circulation Rotary Drilling
Reverse-circulation rotary drilling is accomplished
by utilizing gravity to run the drilling fluid down the
annulus around the drill pipe. The drilling fluid picks
up the cuttings at the bottom of the hole and is pumped
up through holes in the drill bit. The fluid and cuttings
move upward inside the drill-string assembly and are pumped
to a settling pit, then finally back to the borehole annulus
(Johnson Division, UOP, Inc., 1975). Figure 3.5 presents
a schematic drawing of reverse-circu1 ation operations.
This drilling method is not commonly used for injection
wells except in areas of high water production or high
hydrostatic head.
Drilling fluid, made with bentonite or other additives,
is rarely used in reverse-circulation drilling. The drill-
ing fluid used is more the consistency of muddy water than
of mud. Since water is lost to all permeable formations, a
cons iderable amount of make-up water may be necessary in
this type of operation and it must be ava i 1 ;:;i le at the site.
Such high water losses commonly occur a bo v.* the water ta:;l.e
(Cair.pbe 11 and Lehr, 19 7 3).
-------
A. FISHTAIL
B.
THREE-WAY
DRAG BITS
C. PILOT
ROLLER-TYPE
ROCK BIT
Figure 3.4.
CARBIDE BUTTON BIT
Drill bits used in rotary drilling (Speedstar
Division, n.d.)
39
-------
Figure 3.5. Principles of reverse-circulation rotary
drilling (Johnson Division, UOP, Inc.,
1975)
-------
Reverse-circulation drilling is an inexpensive method,
especially when making large diameter holes [up to 60
inches (1.5 m)]. Favorable conditions for the use of this
method include drilling in sand, silt or clay, and in areas
where the static water level is 10 feet (3.04 m) or more
below the ground surface (Campbell and Lehr, 1973; Johnson
Division, UOP, Inc., 1975).
3.1.4 Other Drilling Techniques
Other drilling techniques, both conventional and
experimental, are used to drill injection wells. Several
adaptations of the conventional rotary operation used are
air-rotary, foam-rotary, mist-rotary, air-percussion
rotary, and jet drilling. The primary objective of using
air-drilling, foam-drilling, or mist-drilling fluids is to
increase penetration rates. The addition of percussion
techniques to conventional rotary rigs also increases
penetration rates which generally lowers drilling costs.
Novel techniques are primarily used for special situa-
tions and many are still in the experimental stages. These
methods have been introduced to drill more efficiently, more
rapidly, and more economically. The experimental techniques
include turbodrilling ; electrodr ill ingchemical, explosion,
implosion and erosion drilling; pellet and modified turbine;
electric arc; electron beam; forced flame; jet piercing;
laser; plasma; spark; ultrasonic; and e1ectrohydraulic
drilling (Campbell and Lehr, 1973). It is beyond the scope
of this chapter to evaluate these techniques; however, these
methods may prove to be effective and popular in future
injection-well drilling.
3.2 DRILLING PROBLEMS
Many serious proDlems including deviated holes, lost
circulation of drilling fluids, hole sloughing, and well
kicks may be encountered during drilling. Any one of these
problems can lead to several other problems if allowed
to go unchecked (Society of Petroleum Engineers of AIME,
1973, rev. ed.; Moore, 1974; and Petroleum Extension Ser-
vice, 1975, rev. ed.). Prevention and alertness is stressed
as the best practice for limiting drilling problems.
41
-------
ROTARY BOREHOLE UNIFORMLY DOG"LEGGED HOLE
DEVIATING IN ONE PLANE
Figure 3.6. Examples of borehole deviations (Petroleum
Extension Service, 1968)
42
-------
Drilling fluid chemistry, fluid pressure, and casing pro-
grams are variables used to control drilling problems, yet
ultimately the physical characteristics of the site will
dictate the measures to be used.
3.2.1 Deviated Holes
It is generally recognized that no borehole is per-
fectly straight but all have deviations from the vertical.
Deviated holes normally do not pose problems to well con-
struction or to cementing unless there are sudden changes in
angle and angle direction. These abrupt changes are termed
dog-legs and can be so severe that casing cannot be run into
the hole, geophysical logging cannot be performed, and stuck
drill pipe (keyseating) can occur. Drilling operations in
such holes can cause severe wear on the drill pipe, drill
collars, and casing which can result in fatigue failures.
Severely deviated holes can pose problems with well com-
pletion such as gravel packing, cementing, and remedial
operations. Figure 3.6 illustrates the difference between
uniformly deviating holes and a dog-legged hole.
Directional surveys are run to determine the amount and
direction of deviation, but total deviation is not nearly as
important as the changes in angle direction over short
distances in the borehole. Multishot directional surveys
and gyroscopes have been developed to provide information
concerning both angle and direction of the borehole.
3.2.2 Lost Circulation
One of the most common problems in rotary drilling is
lost circulation of the drilling fluid. Lost circulation
can occur at any depth where total pressure exerted by the
drilling fluid exceeds the formation pressure. Drilling
fluids then migrate into the formation. If circulation is
not reestablished, drilling may stop because cuttings are
not removed, the hole collapses, or the drill bit cannot cut
new hole because it is not lubricated. This problem occurs
in various environments including cavernous rocks, very
coarse and permeable sand and gravel, naturally fractured
43
-------
formations, or formations which are fractured by the hydro-
static pressure of the drilling fluid. Both Moore (1974) and
the Petroleum Extension Service (1975, rev. ed.), provide
detailed information concerning circulation losses in
various geologic environments.
Common solutions to lost circulation in shallow forma-
tions include changing the drilling fluid properties by
using flocculating agents such as lime, or cement; chemical
additives such as polymers, soda ash, and sodium hydroxide;
or inert fillers such as sawdust, cotton seed hulls, nut
shells, or cellophane. Coarse materials such as shells,
etc., added to the drilling fluid can help plug the forma-
tion openings which are taking fluid. In severe cases of
lost circulation, the entire zone may be cemented or cased
to prevent further losses (Moore, 1974; Petroleum Extension
Service, 1975, rev. ed.).
3.2.3 Hole Sloughing
Sloughing typically occurs in shale and clay forma-
tions when the formation pore pressure exceeds the hydro-
static pressure within the borehole, or when there is
turbulent flow in the annulus which promotes sidewall
erosion (Moore, 1974). Problems associated with hole
sloughing include keyseating, hole enlargement, excessive
build-up of solids in the drilling fluid, and hole bridging
(Warner and Lehr, 1977). Sloughing of the borehole wall
tends to increase drilling fluid volumes and can also cause
difficulties in successfully logging the borehole (Petroleum
Extension Service, 1975, rev. ed.).
To prevent sloughing or limit its adverse effect to
borehole stability, lime or gypsum may be added to the
drilling fluid. Oil-emulsion and oil-based drilling
fluids can be used to limit water hydration of the clay
minerals.
Drilling-fluid density may be increased to add wall
support (Warner and Lehr, 1977). Increas ing tne circulation
rate of the drilling fluid provides more rapid removal of
clay or shale so 1 ias.
Hole enlargement can also occur in soluole evaporite
rormat ions. A common met nod tor preventing t h i -s proolcrr.
i:5 the of ua 11-saturat ed drilling i (Warner ar.»i
-------
3.2.4 Well Kicks
A kick occurs whenever formation pore pressure ex-
ceeds hydrostatic pressure and is great enough to raise
the drilling fluid to the surface. Kicks can occur during
all stages of well construction including completion,
remedial operations, or servicing. A kick that is not
controlled can result in a blowout causing fluid flow from
the well. Well blowouts can be dangerous to drilling
personnel and can sacrifice the integrity of the well. The
general causes of blowouts include insufficient drilling-
fluid weight, failure to keep the borehole filled with
fluid, swabbing effects (pressure surges caused by running
drill pipe or casing), lost circulation, or thinning
of drilling fluid by gas or water (Moore, 1974; Society
of Petroleum Engineers of AIME, 1973, rev. ed. ) .
Warning signals alert the crew to implement actions to
prevent a blowout. Warning signals include any of the
following: (1) well kicks; (2) sudden increase in drilling
rates; (3) increase in fluid volume at the surface; (4)
decrease in pump pressure and increase in pump speed; (5)
continued drilling-fluid flow after the pump is shut down;
(6) formation gas or water in the drilling fluid; or (7)
proper volumes of replacement drilling fluid not accepted
in the borehole as the drill string is pulled out.
Procedures for control of well kicks and blowouts
necessitate proper surface equipment including chokes,
back-pressure valves, and blowout preventers. Kicks
while running or pulling pipe can be eliminated by reduc-
ing the rate of pipe movement or by pumping a safety
margin of fluid into the hole to compensate for withdrawn
pipe volume (Petroleum Extension Service, 1975, rev. ed.).
3.3 WELL-COMPLETION TECHNIQUES
The geology of the site dictates whether the well
must be screened or perforated through the injection zone
to keep out unconsolidated sediments, or whether the well
can be an open-hole completion. Following the decision
on the type of well comple tion, the method of drilling
is chosen, and the depth and size of the well is then deter-
mined. The size and type of casing is determined by starting
45
-------
with the injection casing at the bottom of the well and
working up to the surface.
Figure 3.7 depicts the various steps in well con-
struction. Step 1 shows the bit ready to break ground
(spudding), and Step 2 shows the hole being drilled by the
rotary method. The first string of casing is lowered into
the borehole and cemented into place by pumping a cement
slurry through the bottom of the casing and up the annulus
(Step 3). The cement is allowed to harden.
If other casings are put deeper in the hole, a smaller
diameter drill bit is inserted and the hole is drilled
deeper (Steps 4 and 5). A smaller diameter casing is placed
in the borehole and cemented (Step 6). Following the
hardening of the cement, a smaller diameter drill bit is
inserted and the plugs are drilled out (Step 7). The well
is drilled to a depth where the next casing will be placed
(Step 8).
The drilling, casing, and cement program continues
until the injection interval is drilled out. The injection
interval is either screened, or the casing is perforated,
or an open hole is drilled in the formation. Downhole
equipment is installed and injection operations are initi-
ated. Deep injection wells commonly have several casings
cemented in the borehole. Figure 3.8 shows the various
casing types and typical depths for setting casing.
3.3.1 Casing Selection
The selection of casing size and casing material
is determined before drilling is begun. Casing selection is
influenced by several variables including the setting depth,
total diameter of drilled well, formation temperature and
pressure, and quantity and chemical quality of injected
f 1 u id .
Casing is used to prevent the hole from caving, and
when cemented properly, to prevent contamination of under-
ground sources of drinking water, to conl: me i n j ec t ion
fluids to the oorehole , and to prov id e a m 1i1 o d o £ c o n -
trolling inject ion pressure (Warner and Lent:, 1977). Of
primary concern in casing selection is the anility of trie
46
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CASING AND CEMENTING METHODS
Figure 3.7. Principles of casing and cementing a bore-
hole (Clement and Parker, 1977)
47
-------
Conductor
casing
Surface
casing
Intermediate
casing
Packer
Injection
casing
liner
Open borehole
0
Cement
Casing
2
Typical depths (ft.)
20 - 200
200 " 2,000
2,000 +
2,000 - 30,000
Figure J.8. Well casing program and typical depth of
setting different casings
-------
casing to withstand the forces of internal pressure, ex-
ternal pressure, and axial loading or tension (Smith, 1976;
Petroleum Extension Service, 1978; Warner and Lehr, 1977).
The strength of the casing must be considered during in-
sertion into the borehole (running), during the transference
of weight from the derrick to the wellhead (landing), and
during cementing operations.
Smith (1976) reports that lengths of casing (strings)
are designed with a safety factor of 1.5 to 1.8 for tensile
strength, 1.0 to 1.25 for internal pressure stress, and
1.125 for collapse stress. Computer programs are available
from manufacturers for use in the design of casing strings
which consider the influencing factors mentioned above
(Smith, 1976). Warner and Lehr (1977) provide mathematical
equations and steps to determine internal pressure, external
collapse pressure, and maximum allowable suspended weight in
the borehole.
Many injection wells, especially Class I and Class
II wells, are completed with more than one string of casing
cemented in the hole. Three casing strings are commonly
used, the surface string, one or more intermediate strings,
and the injection string. Conductor pipe and liner strings
may also be used. The various casing strings are described
below.
Conductor Casing
Conductor casing is used to stabilize the top of
the borehole to prevent washing out around the base of the
rig; it can also serve as a conduit to raise circulating
fluid for return to the pit and it can be used for the
attachment of a blowout preventer. Conductor pipe may
serve to protect lower casing strings from corrosion and
to support some of the well head load in areas of inadequate
ground support (Petroleum Extension Service, 1978). This
string of casing may be installed by driving and may not
be cemented in the hole. Common pipe and hole sizes are
16-inch (40.6 cm) pipe in a 20-inch (50.8 cm) hole and 20-
inch (50.8 cm) pipe in a 26-inch (66.0 cm) hole (Clement
and Parker, 1977).
49
-------
Surface Casing
When conductor pipe is not used in a well, the surface
casing is usually the string of casing set in the hole
to protect the well from caving by unconsolidated sediments
and to protect fresh-water aquifers from injection-fluid
contamination. The setting depth of the surface casing
may be only 200 feet (61 m) or it may be as deep as 4,500
feet ( 1 , 372 m) (Petroleum Extension Service, 1978). The
surface string must be deep enough to reach competent
formations which will not fracture or break down from the
optimum density of drilling fluid needed to reach the
intermediate casing depth or the bottom of the hole. Common
diameters of surface casing are 13-3/8 inch (34.0 cm) casing
in a 17-1/2 inch (44.5 cm) hole, 10-3/4 inch (27.3 cm)
casing in a 15 inch (38.1 cm) hole, and 9-5/8 inch (24.5 cm)
casing in a 12-1/4 inch (31.1 cm) hole (Clement and Parker,
1977). These diameters will vary depending upon bottom-hole
diameters and bit sizes, tubing sizes, the diameter of
workover equipment, and the nature of the formations pene-
trated .
Intermediate Casing
Intermediate casing strings are used to protect the
nole by sealing off weak formations that could fracture from
the use of heavy drilling fluids. This string is especially
important for protecting against lost circulation in shal-
lower formations and it can be used to block off nigh
pressure zones to allow the use of lighter drilling fluids
deeper in the borehole. Common pipe and nole sizes are
9-5/8 inch (24.5 cm) casing in a 12-1/4 inch (31.1 cm) hole,
8-5/8 inch (21.9 cm) casing in a 12-1/4 inch (31.1 cm) nole,
or 7-3/4 inch (19.7 cm) casing in a 9-1/2 inch (24.1 cm)
nole (Clement and Parker, 1977).
Injection _Casin_()
-------
cemented to ensure a pressure-tight bond around the casing.
Tne injection casing is usually subjected to the greatest
pressures in the well and consequently is constructed of the
strongest material. The injection casing is set through or
to the top of the injection zone. Common casing and hole
sizes are 7-5/8 inch (19.4 cm) in a 9-1/2 inch (24.1 cm)
hole, or 5-1/2 inch (14.0 cm) casing in a 7-7/8 inch (20.0
cm) hole (Clement and Parker, 1977).
Shyrock and Smith (n.d.) suggest two to three inches
(5.1 to 7.6 cm) of additional borehole diameter around the
casing couplings for all casing strings, to allow the
development of adequate cement sheath around the pipe.
Specific details on casing materials and strengths are
presented in Cnapter 4.
Liner
From the bottom of the intermediate casing to deeper
parts of the well, hangs a section of casing that is called
a liner. Liners are not always used, but are advantageous
due to lower costs of shorter casing strings. Liner size
depends upon the number to be set and the size of the
injection equipment to be used. Common liner and hole sizes
are 8-5/8 inch (21.9 cm) casing in a 9-1/2 inch (24.1 cm)
hole, 7 inch (17.8 cm) casing in an 8-3/4 inch (22.2 cm)
hole, 5-1/2 inch (14.0 cm) casing in a 6-3/4 inch (17.1 cm)
hole, 5 inch (12.7 cm) casing in a 6-1/2 inch (16.5 cm)
hole, and 4-1/2 inch (11.4 cm) casing in a 6-1/8 inch (15.6
cm) hole (Clement and Parker, 1977).
3.3.2 Casing Installation
The casing and cementing lesson published by the
Petroleum Extension Service (1978) provides a thorough,
step-by-step discussion of casing installation including
information on casing design, field handling and main-
tenance of casing, hole preparation, casing tools, and
associated problems. The following discussion is adapted
from that paper.
Drill pipe will generally be out of the hole for
12 to 24 hours while logging surveys are performed. During
51
-------
this time, the hole may have sloughed and bridged prevent-
ing running of casing. Also, the drilling fluid may have
formed a cake on the walls which can cause casing strings to
stick, creating conditions for a poor cementing job, in-
creasing well cost for squeeze cementing, or leading to
redrilling. It is good practice to recondition the borehole
after logging by running drill collars and a used bit into
the hole to clear bridges. The drilling fluid is then
circulated at least twice to clean out the borehole.
Casing is installed in stages where there is more than
one string. The general procedure begins by suspending the
casing lengths from the derrick. The threads are cleaned
and lubricated. A guide shoe is attached to the bottom of
the first casing length of each string to slip the casing
past small ledges of debris in the borehole. The guide shoe
is made of heavy steel and concrete.
Centralizers and scratchers are attached outside
the casing to aid in the cementing operations. Scratch-
ers are used to clean the borehole of the wall cake to
assure a strong bond between the cement and the hole wall.
Like the centralizers, the scratchers also help to center
the string and to distribute cement uniformly around the
casing.
After casing lengths have been joined, the string of
casing is run into the borehole. The method generally used
for running strings is called floatation. A float collar
placed on the bottom lengths of casing keeps drilling
fluid out of the casing string and produces the bouyancy
necessary to float the casing in a dri11ing-f1uid filled
hole. The casing is filled with drilling fluid periodically
to limit potential collapse of the string by the high
external pressure of the drilling fluid surrounding the
pipe.
Casing is run slowly to prevent formation damage and
lost circulation from pressure surges. Casings equipped with
scratchers and centralizers are generally run more slowly
than casings without. Before landing the casing and ce-
menting the string, dri11ing-f1uid is circulated through the
casing until wall cake and cuttings stop coming out of the
ho 1 e.
The transfer of the weight of the casing string from
erriek to the wellhead is referred to as landing the
u nr
-------
casing. The casing is attached to the wellhead by a casing
hanger which also seals the annulus between the outer
and inner strings. To prevent buckling, bursting, col-
lapsing, or stretching the string during landing, the
weight transfer usually occurs during the cementing oper-
ation. Figure 3.9 shows potential problems associated with
improperly landed casing.
3.3.3 Primary Cement Selection
The primary cement is the first cement put into the
borehole after the casing string is run. The cement fills
the annular space between the casing string or strings and
hole wall. The major functions of the primary cement are to
restrict movement of fluids between the surface and the
subsurface, to support the casing, to prevent pollution of
underground sources of drinking water, and to prevent casing
corrosion. Table 3.2 presents factors which must be
considered when designing the primary cementing program.
A large amount of literature is available on cementing
from advances in the petroleum industry. This information
should be consulted for additional data concerning cementing
methods, additives, equipment, and quality control (Smith,
1976; Allen and Roberts, 1978; Petroleum Extension Service,
1978; Warner and Lehr, 1977).
To prevent contaminating the cement, the borehole
is flushed with preflushes to remove wall cake and drilling
fluid before cementing the casing. Scratchers may be used
to mechanically remove wall cake. Cement functions can
be greatly impaired if the drilling fluid (especially
those containing special additives) is allowed to mix
with the cement slurry.
The selection of cement and cement additives is based
on depth and temperature. The additives selected are
valuable in allowing the cement to set-up faster, in chang-
ing the density and strength of the base cement, in limit-
ing slurry loss to formations, in reducing cost, and in
increasing resistance to corrosion. (Cements and cement
additives are discussed in Chapter 4.)
The best method for determining the volume of cement
necessary is to make a caliper survey of the hole diameter.
The Petroleum Extension Service (1978) reports that the
53
-------
igure 3.9. Conditions associated with improper and
proper methods of landing casing
(Petroleum Extension Service, 1978)
-------
TABLE 3.2
ITEMS TO CONSIDER IN PLANNING FOR
PRIMARY CEMENTING
(Smith, 1976)
Factors of Influence
BOREHOLE
Diameter, depth, temperature, deviation, formation
properties.
DRILLING FLUID
Type, properties, weight, compatibility with cement.
CASING
Design, size of thread, setting depth, floating equip-
ment, centralizers, scratchers, stage tools.
RIG OPERATIONS
Time and rate of placing casing, circulation time
before cementing.
CEMENT COMPOSITION
Type, volume, weight, properties, additives, mixing,
pretesting of well blend with field water.
MIXING AND PUMPING UNITS
Type of mixer, cementing head, plugs, spacers, move-
ment during cementing, displacing fluids.
55
-------
number of barrels of grout per 1 ,000 feet of hole can be
estimated by multiplying the diameter of open hole (in
inches) by itself. The outside casing diameter (in inches)
is squared and subtracted from the open-hole calculation to
yield the general cement requirements of the hole. Fre-
quently, the hole will take more cement slurry than calcu-
lated because some cement is lost to the formation.
Water of drinking quality is generally used for mixing
cement. A dependable source assures adequate quantities of
cement for the well. The temperature of water can influence
the mixing and set-up rate of the cement. Additional
information on cement mixing is available in the Petroleum
Extension Service (1978) and Smith (1976). The density of
the cement slurry is generally monitored and recorded
throughout the cementing operation to assure that proper
water to solids ratio is maintained. The slurry density is
usually greater toward the end of the job to permit stronger
bonds around the shoe joint.
Cementing plugs are frequently used to separate the
cement from any drilling fluid or displacing fluid (Allen
and Roberts, 1978) used to place the cement slurry. A
bottom plug can precede the cement to clear drilling
fluid from the inside of inner casings. A top plug, which
serves as a shutoff when the cement is in place and which
separates the displacing fluid from the cement, may also
be used (Smith, 1976).
Table 3.3 presents several failures that can occur
during the cementing operations. Factors which contribute
to these failures are also presented in the table.
3.3.4 Primary Cementing Techniques
Various methods are used for cementing well casing.
Each tnay be applied to special situations, but the normal
displacement method is the most frequently used. Smith
(1976) serves as a basis for trie following section in which
the various methods are briefly discussed. F i g u r e 3 . 1 0
presents ti'ie various techniques generally used in prur.ary
cemen t l ng .
When using the normal aisplacement method, cement is
pumped through the casing and out of the casing into
-------
TABLE 3.3
FACTORS THAT CONTRIBUTE TO
CEMENTING FAILURES
(Smith, 1976)
Type of Failure
Contributing Factor
Premature setting in
casing
Failure to bump
plug
Incomplete mixing
Gas leakage in
annulus
Channeling
Too-rapid setting
of cement
Contaminants in mixing water.
Incorrect temperature estimate.
Dehydration of cement in annulus.
Use of improper cement.
Plugged cement shoe or collar.
Insufficient retarder.
Lodging of plug in head.
Running of top plug on bottom.
No allowance for compression.
Incorrect displacement calculations
Mechanical failure.
Insufficient water or pressure.
Failure of bulk system.
Insufficient hydrostatic head.
Gelation at cement/drilling fluid.
Failure of cement to cover gas
bearing zones.
Cement dehydration.
Contact of pipe with formation.
Poor drilling fluid properties
(high plastic viscosity and
high yield point).
Improper water ratio.
Incorrect temperature assumption.
Mechanical failures.
Wrong cement or additives for
well conditions.
Hot mixing water.
Slurry allowed to remain static
to perform rig operation.
Improper choice of drilling fluid/
cement spacers.
57
-------
Bottom
plug
Stage-»-fN
tool
NORMAL
DISPLACEMENT
METHOD
TWO
STAGE
CEMENTING
INNER
STRING
CEMENTING
OUTSIDE
CEMENTING
— - j l-
IDY7LX7;
1
Weak
zones
Special
float
shoe
REVERSE
CIRCULATION
CEMENTING
ft
I
DELAYED SET
CEMENTING
<
MULTIPLE
STRING
CEMENTING
Figure 3.10.
Techniques used
(Smith, 19 76)
in primary cementing
58
-------
the annulus between the casing and borehole wall, or between
a larger diameter casing and the casing string being cement-
ed. Special adaptors and continuous cementing heads are
used for this single-stage method. All casing strings
including the conductor pipe, surface pipe, intermediate
strings, and injection string may be cemented with this
technique.
The cement slurry is generally mixed and pumped
at the fastest possible rate without delays or interruptions
to keep the slurry in turbulent flow, to remove wall cake,
and thereby, to increase chances for a secure bond to the
formation walls. Too much pressure on the casing and
surface connections may cause ruptures, however, and too
much flow in the annulus may cause formation damage which
could contribute to formation loss.
The stage cementing method performs primary cementing
in several steps, or stages. It is typically used for wells
having critical fracture gradients when weak formations are
exposed and will not support hydrostatic head during ce-
menting. Stage cementing is also used in wells requiring
long columns of cement. A major disadvantage of stage
cementing is the immobility of the casing after the first
stage of cementing. This increases the possibility of
drilling-fluid channeling and limits the amount of drilling
fluid removed from the annulus.
Inner-string cementing, a third method, is used for
large diameter casing. Tubing or drill pipe is commonly
used as an inner string to pump the cement. This procedure
reduces the cementing time and the volume of displacement
fluid required to pump the plug. It prevents having to
drill out the large volume of cement that a large casing
would hold if it has been cemented in the conventional
manner.
Remedial work sometimes uses the annulus method of
cementing. This technique is commonly used for conductor or
surface casing to bring the top of the cement to the sur-
face. This is done by pumping cement through tubing or a
smaller diameter pipe run between the casings or between
casing and the hole wall.
When it is not possible to pump the cement slurry in
turbulent flow without breaking down the weak zones above
the casing shoe, the reverse circulation cementing technique
59
-------
may be used. This method involves pumping the slurry-
down the annulus and displacing the drilling fluid back
up through the casing. It allows for a wider range in
slurry compositions, so that heavier, or slow-setting
cement, can be placed at the lower portion of casing, and
lighter, or accelerated cement, can be placed at the top of
the annulus. A major drawback of this method is that
the period of drilling fluid displacement cannot be detected
from pump pressure. This leads to errors in the calculation
of annular volume of required amounts of cement slurry, and
of volume of displacing fluid necessary to achieve complete
cement placement.
To obtain a more uniform cement sheath around the
casing, delayed-set cementing is used. A slow-setting cement
slurry containing a filtration-control additive is placed in
the borehole before running the casing. The cement is
pumped down the drill pipe and up the annulus. The drill
pipe is then removed from the well, and the casing is sealed
at the bottom and lowered into the unset cement slurry.
After the slurry is set, the well can be completed using
conventional methods. This technique has been used in
tubingless completion wells by placing the slurry down one
string and lowering multiple tubing strings into the unset
cement.
One disadvantage of this method is that the longer
set-up times increase well construction costs. Cements used
in the delayed-set technique usually contain 6 to 8 percent
bentonite and a dispersant to control filtration. Adequate
quantities of retarder are used to delay setting time for 18
to 36 hours. (See Chapter 4 for further information).
Special problems encountered during cementing include
problems intrinsic to high temperature zones, gas zones,
soluble formations, deep wells, geothermal wells, steam
injection wells, deviated wells, and wells using multiple
strings (Allen and Roberts, 1978; Smith, 1976). These
problems are discussed as they apply to specific types of
injection wells in Chapters 8, 9, and 10.
3.3.5 Secondary Cementing Methods
Secondary cementing i s used when 1eaks deve1op i n
primary cement or when abandoning operations needed.
-------
Oil-well literature provides a great deal of information
on these procedures (Clement and Beirute, 1977; Allen and
Roberts, 1978; Smith, 1976)
Squeeze cementing is a remedial method in which a cement
slurry is forced into a formation or into an area in the
annulus to fill perforations, to repair casing holes, to
seal leaking liner tops, to seal lost circulation zones, to
supplement primary cementing jobs, or to abandon holes. A
typical squeeze operation is presented in Figure 3.11.
There are two general methods in squeeze-cementing
operations, high and low pressure techniques. The high
pressure technique involves formation fracturing while
pumping the cement slurry under pressure. This technique
has many disadvantages, including high fluid loss, making
the low pressure technique more desirable (Figure 3.12) and
more commonly used. Low fluid-loss cement is pumped into
the perforated zone and sufficient pressure is applied to
form a cake of dehydrated cement in the perforations (Figure
3.13). Final squeeze pressures are recommended to be 200 to
300 psi (1.38 x 106 to 2.0 x 106 N/m2) less than formation
fracture pressures (Allen and Roberts, 1978). In addition,
Allen and Roberts note that a full column of 15.5 lb/gal
(1.88 kg/1) cement frequently exerts enough pressure
to fracture the formation with no additional surface pres-
sure .
Squeeze operations begin when cement is spotted over
perforations in the casing using tubing and packers.
Pressure is added with occasional hesitations (refer to
Figure 3.14) to dehydrate cement in perforations. After the
final pressure is reached, the pump is shut down to assure
no pressure bleed-off. Reverse circulation of cement may
then be used to wash out excess cement from perforations.
Fractured and vugular formations and long perforation
sections present the most severe squeeze problems. Long
perforation intervals [over 50 feet (15.2 m)] are difficult
to squeeze successfully in one operation because the top
perforations tend to seal off faster than deeper perfor-
ations, a result of cement dehydration. Water is squeezed
out of the cement slurry and wall cake forms. Such dif-
ferential dehydration is successfully combated by use of
high fluid-loss cement (Clement and Beirute, 1977). Vug-
ular, carbonate formations and highly fractured rocks accept
61
-------
Figure 3.11. Squeeze-cementing operation using oacker
to control pressure and flow (Smith, 1976)
62
-------
0
Figure 3.12. Principles of high-pressure squeeze
cementing (Smith, 197 6)
63
-------
Figure 3.13. Principles of low-pressure squeeze
cementing (Smith, 1976)
-------
TIME, MINUTES
'Figure 3.14. Generalized pressure-recording chart for squeeze cementing
using the hesitation technique (Allen and Roberts, 1978)
-------
large volumes of cement without adequate support for cement
slurries to bridge against. Thixotropic cements are often
used in these situations.
-------
REFERENCES
Allen, T. 0., and A. P. Roberts, 1978. Production opera-
tions, Volume I. Oil and Gas Consultants, Inc., Tulsa,
Oklahoma.
Campbell, M. D., and J. H. Lehr, 1973. Water well technol-
ogy. McGraw-Hill Book Co., Inc., New York, New York.
Clement, C., and R. M. Beirute, 1977. Outline simpli-
fies squeezing and plugging. Oil and Gas Journal,
Basic Cementing Reprint Series.
Clement, C., and P. Parker, 1977. Slurry and pumping
guidelines smooth casing-cementing jobs. Oil and
Gas Journal, Basic Cementing Reprint Series.
Freeze, R. A., and J. A. Cherry, 1979. Groundwater. Pren-
tice-Hall, Inc., Englewood Cliffs, New Jersey.
Johnson Division, UOP, Inc., 1975. Ground water and wells.
Edward E. Johnson, Inc., St. Paul, Minnesota.
Moore, P. L., 1974. Drilling practices manual. PennWell
Publishing Company, Tulsa, Oklahoma.
Petroleum Extension Service, 1968. Lessons in rotary
drilling: drilling a straight hole. The University of
Texas at Austin.
Petroleum Extension Service, 1975, rev. ed. Drilling
mud. The University of Texas at Austin.
Petroleum Extension Service, 1978. Casing and cementing.
The University of Texas at Austin.
S'hyrock, S. H., and D. K. Smith, n.d. Geothermal cementing,
the state-of-the-art. Halliburton Services Company,
Technical Report C-1274.
Smith, D. K., 1976. Cementing. American Institute of
Mining, Metallurgical and Petroleum Engineers, Inc.,
Dallas, Texas.
Society of Petroleum Engineers of AIME, 1 973 , rev. ed.
Reprint Series No. 6a.
67
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•Speedstar Division of Koehring Company, n.d. Well drilling
manual. The National Water Well Association.
Warner, D. L., and J. H. Lehr, 1977. An introduction
to the technology of subsurface wastewater injection.
U.S. Environmental Protection Agency, EPA-600/2-77-240.
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4. CONSTRUCTION MATERIALS
In completing injection wells, materials of sufficient
strength and durability can be selected that will insure the
raecnanical integrity of the well and thereby prevent envi-
ronmental degradation and economic loss. Construction
materials used for completing injection wells are generally
classified into three groups which include: casings (tub-
ular goods), cements and cement additives, and ancillary
equipment and materials such as centralizers, scratchers,
and annulur fluids. Other equipment and materials such as
packers, valves and fittings, screens, and drilling fluids
are described in Chapters 3 and 5.
4.1 CASING
Casing is the pipe material placed inside the borehole
that transmits fluids through the well into the injection
zone. Casing is usually distinguished from tubing with
respect to its function and its location in the well.
Casing refers to the outer pipe string, often cemented in
place to maintain structural integrity in the borehole
(see Figure 4.1). Tubing usually refers to the innermost
pipe string through which injection usually takes place. It
is often separated from concentric strings of casing by an
annulur fluid and can be removed easily from the well.
However, in tubingless completions, the innermost casing can
also be referred to as the injection casing.
The primary functions of casing are to prevent the
hole from caving, to confine the injection fluid to the
well, to prevent contamination of underground sources of
drinking water, and to provide a method of pressure control.
In completing injection wells, four types of casing may be
used, but may not always be necessary. These include:
conductor casing, surface casing, intermediate casing, and
injection casing (see Chapter 3 for more details on casing
str ings).
The selection of casing used in completing an injection
well is generally based on internal and external pressure on
the well, axial loading (compressive and tensile stresses)
exerted on the well, temperature of injection fluid and well
environment, and corrosive action of injection fluids
69
-------
Figure 4.1. Casing and cementing program for a Class
I injection well
-------
and/or fluids or formations surrounding the well. Any or
all of these stresses, if incompatible with casing charac-
teristics can cause failure of the well and subsequent
release of injection fluids into surrounding formations or
underground sources of drinking water. Internal pressure
can cause the casing material to burst, while external
pressure can result in collapse of the pipe body. Compres-
sive stresses, as a result of buoyancy or tensile stresses
due to the hanging weight, can cause joint failure. In
addition to physical stresses, corrosion can be the primary
cause of mechanical-integrity failure of the well (Warner
and Lehr, 1977; Allen and Roberts, 1978).
Every injection well is exposed to some degree of
corrosion. Generally, it is impossible or too expensive
to completely control all corrosion. However, from a
material selection viewpoint, there are steel alloys and
nonmetal casings available which may improve the ability
of the injection well to resist corrosion (see Chapter
6 for a detailed discussion of corrosion and its control).
The physical properties of casing, including collapse
resistance, internal yield pressure, joint yield strength,
and pipe-body yield strength, are of primary importance
in determining performance. These properties affect the
ability of the injection well to maintain mechanical in-
tegrity. Collapse resistance and internal-yield pressure
are critical in determining the ability of the casing
to withstand external and internal pressures exerted on
the pipe, respectively. Similarly, joint-yield strength
and pipe-body yield strength determine the ability of
casing to withstand axial loadings exerted on the pipe
body.
4.1.1 Steel Casing
The most commonly used material for casing is steel.
Table 4.1 lists several grades of steel as specified by the
minimum yield strength of the material by the American
Petroleum Institute (API). The API has also developed
specifications for the chemical characteristics of casing
which include the requirement that the material be made from
open-hearth, electric furnace, or basic oxygen steel with
maximum allowable percentages of phosphorus (0.040 percent)
and sulfur (0.060 percent) [API Specification 5A (1979), 5AC
71
-------
TABLE 4.1
API YIELD-STRENGTH SPECIFICATIONS FOR VARIOUS
GRADES OF STEEL CASING AND TUBING
(API SPEC 5A, 1979; 5AC, 1979; 5AX, 1976)
Yield Strength (psi)
Grade
Min.
Max.
H-40
40,000
80,000
J-55
55,000
80,000
K-55*
55,000
80,000
C-75
75,000
90,000
L-80
80 ,000
95,000
N-80
80,000
110 ,000
C-95*
95,000
110,000
P-105
105,000
135,000
P-110*
110,000
140,000
* Specifications apply to use of this grade of material for
casing only.
-------
(1979) and 5AX (1976)]. For restricted yield-strength
casing, API has developed more detailed specifications
concerning the chemical properties of the material as shown
in Table 4.2. In general, metallurgical properties of
specific brands are held as proprietary information by the
manufacturer and are not sought out by purchasers as a basis
for selection. Usually selection is based on the physical
properties of the material.
Table 4.3 and 4.4 present detailed descriptions of
the performance properties for several grades and sizes
of standard API pipe. The joint-yield strengths presented
in Table 4.3 assume a standard API eight-round thread-type
joint. However, yield strengths may vary if other couplings
such as buttress or extra clearance couplings are used.
Figure 4.2 shows the standard API coupling connections
used in joining steel casing. The different types of API
couplings include:
1. Non-Upset Connection (NU). A coupling wherein the
joint has less strength than the pipe body, 10-round
thread form (10 threads per inch).
2. External Upset Connection (EUE). A coupling
wherein the joint has greater strength than the pipe body,
8-round thread form.
3. Special Clearance Couplings. Standard API coup-
lings which have been turned down to allow more clearance
between coupling and outer casing or borehole. Special
clearance coupling-type thread forms such as buttress-thread
connections have been developed for NU casing which, unlike
the API NU connection, have 100 percent joint strength.
(Allen, and Roberts, 1978).
4. Integral Joint/Extreme-Line Type Connections.
These connections, are of a single male and female type
union. Several different types are available which provide
extra clearance and sealing characteristics.
All joints must be filled with a thread lubricating
compound during make-up. However, several proprietary
special joints have been manufactured which rely on a
metal-to-metal seal (Armco, 1981).
73
-------
TABLE 4.2
CHEMICAL (PERCENT) AND HEAT TREATMENT REQUIREMENTS
FOR RESTRICTED YIELD STRENGTH CASING AND TUBING
f API SPEC 5AC, 1979)
Phos-
Carbon Mang
anese
Molybdenum Chromium
Nickel
Coppe
r phorus
Sulfur
Silicon
Heat
ir ade Ty pu
nu n . max, min.
max .
mi n.
max. min. max.
max.
max.
max.
max.
max.
Treatment
-7i L
0.50
1 .90
0.15
0.40 * *
*
*
0.04
0.06
0.35
Normalized and
-75 2
0.40
1. 50
0.04
0.06
0.35
tempered
Quenched and
-IS i
u~*
r-
o
CO
T
o
o
1 .00
0.15
0.25 0.80 1.10
0.04
0.06
tempered
Normalized and
-a 0 ...
0 .40
1 .90
0.25
0.35
0.04
0.06
0.35
tempered
Quenched and
0.4b
1 .90
0.04
0.06
0.35
tempered
Quenched and
tempered
rV/r (jrjiJc C*
-75, Type 1, chromium
, nickel
and
copper combined shall
not exceed
0.50
percent.
-------
TABLE 4.3
MINIMUM PROPERTIES OF CASING
(API SPEC. 5C2, 1980)
-J
tn
FOOT
NOM
(IBS )
WALL
THICK-
NtSS
(INI
UN.)
0 224
0 260
0 290
0 33)
4 090
4.052
4.000
1920
JIJi
3 966
) 927
3 in
3 796
1 761
1150
13 00
1$ 00
16 00
21 40
24 10
0 220
0 263
0 291
0.312
0 417
0 600
4 580
4 494
4 401
4 271
4 121
4000
4 4)5
4 369
4.263
4 151
4 001
3179
6 St)
6 66)
6 56)
9 18 J
ttt)
14 00
19 90
17 00
20 00
2)00
0 244
6 2 71
0 304
6 311
6416
6012
4 966
4 692
4 7)1
4 6)0
4 667
4.626
4717
4 163
4 941
6 060
6 090
6 090
20 00
24 00
26 00
32 00
0 266
0 392
0 417
fl 479
6 046
9 621
9 791
9 979
9 924
9 769
9.166
9.996
7 386
7 390
7 390
7 310
17 00
20 00
23 00
29 00
29 00
32 00
35 00
36 00
0 2)1
0272
0317
0 362
0406
049)
0466
0 946
6 636
1496
6)66
• 276
6 164
6 094
6004
9 920
9 41)
6 331
• 241
• 191
• 096
9 666
9 67*
9 799
7 656
7 656
1996
7 991
7 696
7 656
7 956
7.656
3310
4010
4960
7990
10170
14)20
3060
4140
9650
6670
10000
11960
13900
7290
10460
12710
14400
•060
12010
19190
17100
66)0
13490
17990
19106
3120
4040
4910
•070
6440
10460
6260
••)•
imo
• 6)0
16000
12620
7460
11060
14920
6670
70)0
66)0
• 760
617*
1032*
•290
•200
11(00
• 710
l«14(
1)200
24 00
26 40
29 70
)3 10
39 00
42 60
47 10
D 300
0 326
0 379
0 4)0
0 900
0 962
0 629
7 025
6 999
6 679
9 769
9 629
6 501
6 375
• 900
6 644
• 790
• 640
6 900
6 376
• 250
I 500
• 900
• 500
• 500
6 900
I 900
9900
24 00
26 00
32 00
)9 00
40 00
44 00
49 00
0 264
0 304
0 362
0.400
0 460
0 900
0 957
6097
6017
7 921
7 925
7 729
7 625
7611
7 972
7192
7 796
7 700
7 600
7.500
7 399
9 625
9 625
• 629
9 925
9 925
9 925
9 629
0 312
0 362
0 395
0 439
0 472
0 649
9 001
9 921
6 935
9 645
• 765
6 679
9 599
6 526
6 3 79
10 626
10 625
10 925
10 625
10 926
10 929
51 00
66 60
50 10
95 >0
0 2)9
0 360
0 400
0 4S0
0 496
0 646
0 595
10 I 5?
10 050
9 960
9 060
9 760
9 660
9 6(0
10 036
9 694
9 794
9 694
9 604
9 604
9 404
4700 O 33]
41 00 0 1)5
54 00 0 435
60 00 0 499
10 921
10 844
10 )24
10 616
1 2 750
12 /50
12 750
12 150
49 00 0 330
54 50 0 390
61 00 0 430
66 00 0 480
72 00 0 614
65 00 0 3)5
76 00 0 436
94 00 0 496
12615
12 616
12 416
12 347
16 260
16 124
15 010
12 559
12 469
12 369
12 269
12 191
15 062
14 936
14 622
14 3)6
14 376
14 3)5
14 3)6
143)5
84 00 0 434
104 60 0 1.UO
1 13 00 0 636
1 7 765
I'J 1 24
I'd DUO
It 1)0
17 000
1) 000
1)000
20 000
16 9 36
16 812
16 542
21 OUO
21 000
21 000
2270
3270
4)20
3770
5210
6760
• 230
6710
10666
)6)0
1410
7020
•600
10160
11)66
41 SO
••It
7620
67)0
11646
1)420
6210
6516
10766
13010
16110
)210
4670
6320
6430
10240
11290
3400
4790
• 560
6110
10610
12040
3710
6120
7210
• 660
12400
14300
6)40
7966
11060
1)910
(•650
4020
8)50
6690
6200
4100
6920
6950
6670
4360
6010
7730
9690
• 3*0
• 400
10720
2960
3750
4630
6360
3090
3610
4750
6620
3330
4130
6090
7330
4430
6)10
79)0
I960
2090
2700
)670
4630
6660
7490
1510
2070
2660 3070
4360
4790
6)10
10690
12410
14420
4240
4170
• 700
7770 S2I0
• 500 19140
10140 torn
10140 10110
••40
12040
12M0
12660
11400
13140
14170
14170
4270
4110
• 320
7260 1740
••10 1190
•210 6660
91 >0
10010
117)0
I0M0
12(40
13510
••TO 7440
11(0 1010
•41* 10040
••)•
10461
11020
102)0
12120
13900
1740
4316
4660
(140
• 7«0
7160
• 490
• ••0
(MO
• )40
7240
• 110
•OIO
•240
• 240
7(30
• 100
ll>0
107*0
10070
10170
SHORT THRtAO
N 60 C 96 MIO
6960
11220
12460
12700
12700
••60 6020
•4S0 (160
7400 7100
6610 9160
9t)0 10)20
••40 10490
7190
0190
•310
10900
122S0
124(0
14)1
10(60
12(20
14110
144)0
60(0 6410
••SO 7)00
7610 1120
6460 9040
7710
• •70
• 140
10740
10040
11160
124)0
6390
5930
6440
7430
9760
6330
9(70
79)0
(620
7610
• 160
•410
• 700
•440
10900
31)0
)6I0
4030
•010
• 990
• 7(0
10460
3070
3660
4010 6460
2730
3090
3450 4710
6040
2110
2410
3060
1069
11(6
13)6
-------
Table 4.4
Tubing Minimum Performance Properties
(Allen & Roberts 1978)
TuBinf Stlt
Nomiml Weight
Mail
Ttircadts and Coupled
integral Joint
Collapse
Inter-
Joint Yield Stren9th
T 4 C
T «. C
int
Thick-
Inutft
Drift
1 Coup
Outstde Dia.
Drift
Bo*
Resis-
Vidd
T fc C
T I C
int.
Norn
OD
Nen-
Upset
Jt
Grade
ness
Oil
Dia
Non-
Upiet
Upset
Dia
OO
tance
Pres-
Hon
Upset
Jt
(•n |
(•n.)
Upiel
(•«-)
<»n.)
l»n.)
Upset
Spec
(in.)
(in.)
Ob/ft)
(in.)
<•«.)
(•n.)
(P»<>
Ob)
Ob)
(0
5 780
92 S50
3 SOO
7 70
J 55
216
3 068
2 94 3
4 250
5 9 70
S 940
R9 4 70
1 SOO
9 20
9 30
J 55
254
2 992
2 86 7
4 2S0
4 500
4 180
f -'CIO
l> ^hO
109 3 ¦'('
147 4f;o
3 SOO
10 20
J 55
?89
2 922
2 79 7
4 250
R 3 "tO
J 950
177 2S0
3 soo
7 70
C 75
216
J Oh8
2 943
4 250
i- 540
8 U.U
1 22 010
soo
9 20
9 30
C 75
254
? 9Q?
2 KM
4 250
4 SOO
4 1H0
1 n fwin
\ JQ IdQ
1-.M '».n
' soo
10 20
C '"5
2R9
2 922
? 79 7
4 250
1 1 .u.o
10 840
1 7 ! 1 .<0
¦ MX)
1: ?0
l 2 95
C 75
J75
2 7SO
2 625
4 250
4 5 00
4 180
14 JSO
14 < ¦ 0
2 3C1 "'JO
2 'S 1:0
"1 *-00
7 70
\ 80
216
3 0*'<8
2 94 3
4 250
7 H '0
H t»40
1 .U'l 1 40
.1 soo
'i ;'0
9 30
\ 80
254
2 W7
2 Hti 7
4 250
•1 500
4 1 BO
' r • '0
10 ISO
159 CNC! 20: 220
•¦00
10 20
N 80
- H9
2 92?
? 79
4 250
1 2 ' 70
1 1 SbO
1 !«•_ 100
3 500
1: 'U
1 2 95
N 80
3 75
2 7S0
7 f.75
4 250
4 50014 1 HO
15 i 0
IS CXX'I
74f\ 390
1 2^4 5 30
t SOO
20
9 .10
P 105
254
2
2 8<>
4 2SO
4 500
4 180
1 1 050
' 1 3 '' '.0
2f* 'X'1
2" ''70
1 •
1; 70
1 ? r»5
p t ryt,
."1 7S
2 .'SO
? (¦?'
4 250
4 SOO
4 180
20
! V*
s '0
- -i .. . 4
.1 -1
i
4 (XX)
9 SO
H 40
276
3 S4fl
1 423
4 7 50
A (>,0
j .» 'ISO
L« X )
¦4 OOO
11 00
H 40
2t>7
3 4 /*,
3 35 1
S I.KJO
4 M .JO
; 4 SHO
•. 1..'. 0
4 1*10
9 ">0
J ss
J * 4fl
I 4 2
4 750
¦„ "0
I 5 4 40
'.no
4 •**)
11 00
J ss
vf.2
,i 4 n,
I 15 1
s rx«
; t,i. too
•« . .;
4 i*. K )
5
«S2
3 4 ,T(, ' .1 ,!-S 1 1
5 CJOO
H 4 ' 0
H SOO
4 -*;<
1 so
S HU
2 21.
V4H
.1 42 <
4 .'SO
(. 59 0
1 / 010
'44 :'i • 0
I
4 'Xjo
1! (10
S HO
.52
'.1
'! .IS 1
5 (XX)
M
! M 1 '0
. '40
|
' i 1
1:
>« 4.:; ' y
• 1 r.
(Hi.
\ ,.,V1
' Mil
I
4 *. *!¦¦¦)
i 4
' 1; .*
* ¦ i-i
j
•
4 ¦
¦ . ''.I.]
1; /'
- ¦ 1
r'
• , 1
,
i • H *
: - 4 1 .
.1 ¦ .
' *• *
i
I
¦
\ , •, *
¦ H 4 ¦'
1
-------
API NON-UPSET TUBING
Sizes: 1.050 in.- 4 l/2in.
' / y> y>
ROUND-THREAD CASING
Sizes: 4 1/2 in. * 20 in.
(21 1/2 in. and 24 1/2 in.
API EXTERNAL-UPSET TUBING
Sizes: 1.050 in. * 4 1/2 in.
r/y/,
flP779^
ZZZZ
API BUTTRESS-THREAD CASING
Sizes: 4 1/2 in. - 20 in.
API EXTREME-LINE CASING
Sizes: 5 in. - 10 3/4 in.
Figure 4.2. Standard API coupling connections for
joining steel casing (Halliburton
Services, 1981)
77
-------
The corrosion rate of steel casing is highly dependent
upon the environment surrounding the well and the chemical
characteristics of the injection fluid. Table 4.5 presents
materials well suited for hydrogen-sulfide, carbon-dioxide,
and oxygen corrosion environments. Although many of these
materials are quite expensive, their use may prove econom-
ical, particularly for the bottom-most strings which contact
the injection zone directly. In a recent study (McGright,
et al., 1980) casing materials in injection wells associated
with geothermal applications were investigated to determine
their ability to resist corrosion from brine. The study
concluded that API Grade J-55 casing was not suitable for
long life requirements of the injection zone, but API Grade
N-80 and C-75 exhibited a better resistance. API Grade C-75
in particular, with a lower maximum yield strength [90,000
psi (6.2 x 10® N/m2) vs. 1 10 ,000 psi (7.6 x 10° N/m^) for
N-80], could eliminate the susceptability to delayed failure
resulting from hydrogen-sulfide cracking or stress-corrosion
cracking.
4.1.2 Plastic Casing
Casing is also made of nonmetal materials. Plastics
are organic materials with plastizers, inert fillers,
and hardners which give improved mechanical and physical
properties. Two major groups of plastic casing have been
developed which are applicable to injection-well completion,
thermoset plastic and thermoplastic. Themoset plastics are
permanently "set" once they are shaped and cannot be subse-
quently reformed by either chemical action or application of
heat. Thermoset plastics include epoxy and vinyl-epoxy
resins which can be reinforced with fiberglass.
Thermoplastics, on the other hand, can be formed
and reformed repeatedly by the application of heat followed
by cooling. Thermoplastics include acrylonitrile-butadiene-
styrene (ABS), polyvinyl chloride (PVC), chlorinated PVC
(CPVC), and styrene rubber (SR). Both thermoset and thermo-
plastic casing are highly resistant to electrochemical
corrosion, but are susceptible to s o1 vat ion (dhy sical
absorption by a plastic or an organ ic solvent) (NWWA,
19 80; Allen and Roberts, 1978).
Although weaker and
pressure influences than
more sens it ivo to temperature and
metallic cj:;irw materials, plastic
-------
TABLE 4.5
SUITABILITY OF CASING AND TUBULAR GOODS
TO VARIOUS CORROSION ENVIRONMENTS
(Allen and Roberts, 1978)
ACCEPTABLE FOR HYDROGEN SULFIDE
1.
Low and medium alloy carbon steels, <1 percent
nickel, not finished
2.
J-55, C-75, N-80, SOO-90
3.
300 series stainless steel Annealed
4.
Incoloy 800 (Ni-Cr-Fe)
5.
Incoloy 825 (Ni, Fe, Cr, Mo)
6.
Inconel 600 (Ni, Cr)
7.
Inconel X-750 (Ni-Cr-Al)
8.
Monel 400 (Ni-Cu) Annealed
9.
K-monel 500 (Ni-Cu-Mo)
10.
Hastelloy C (Ni-Cr-Mo)
11.
MP35N (Co-Ni, Cr, Mo)
12.
Stellites (Co-Cr-W)
13.
Colomonoys (Ni-Cr-B)
14.
Cemented carbides (Tungsten Carbide)
UNACCEPTABLE FOR HYDROGEN SULFIDE
1. Low and medium alloy steels, >1 percent nickel
or cold finished
2. Free machining steels, >0.08 percent sulfur
3. Stainless steel, cold finished or precipitation
hardened
4. K-monel, cold finished
ACCEPTABLE FOR CARBON DIOXIDE
1. Stainless steels, except free mechining
2. Monels (Ni-Cu)
3. Nickel-iron (Ni-resist)
4. Al-bronze (Cu-Al)
ACCEPTABLE FOR OXYGEN
1. Stainless steels
2. Monels
3. Nickel-iron
4. Al-bronze
79
-------
casing is extremely well suited for the injection of highly
corrosive fluids. The most commonly used thermoset casing
consists of epoxy-resin fiberg1ass-reinforced material.
Based on temperature resistance and strength, epoxy resins
are superior to other types of resins (Allen and Roberts
1978). Tables 4.6 and 4.7 include the specifications and
physical properties for one brand of commercially available
thermoset casing. Maximum pressures and temperatures for
epoxy resin-fiberglass reinforced casing are approxi-
mately 300 psi (2.1 x 106 N/m2) and 150°F ( 6 5 . 5 0C),re-
spectively. Joint make-up for epoxy resin is similar to
the coupling and connection techniques used for steel.
Epoxy resin has been replacing the use of thermoplastic
casing such as PVC, because of improved strength and higher
temperature rating (Allen and Roberts, 1978). (The API has
tentatively established specifications for reinforced
thermosetting resin casing and tubing under API Spec 5AR,
1975.)
Table 4.8 describes typical physical properties of
thermoplastic materials. Maximum operating temperatures for
ABS, PVC, and SR casing are approximately 100°F (37.7°C).
Thermoplastic casing of similar wall thickness and diameter
as thermoset casing is generally weaker. However, compared
to steel, thermoplastic casing has a greater resiliency,
flexibility, and abrasion resistance. Joint make-up for
thermoplastic casing can be formed through either tra-
ditional threaded and coupled connections or by solvent
cement ing.
Perhaps the single most important factor limiting the
use of thermoplastic casing in completion of injection wells
is sensitivity to temperature. For example, the heat of
hydration of some cements used for completing the injection
well could increase the surrounding temperature enough to
cause a solvent cement joint to fail, or could reduce the
strength of the casing. As a result,- the n c 0 of concen-
trated quick-drying cement is not recommended for use in
wells cased with thermoplastic materials (NWWA, 1 y 8 0 ) .
However, within given operating temperatures, the strength
and durability of thermoplastic casing has permitted its use
in water-well completions to depths of over 2000 feet (blO
in) (American Society for Testing and Mat er i a 1s, 1 9 77; .
kv 1111 respect to c o r r o s i o n resistance :¦, t; i e r ¦ n o u e t a no
tisermopl ast ic materials are uniquely superior t<> n.e t a 1 1 i e
mat'-r iais. Since plastics are nonconductor;-, they are not
-------
TABLE 4.6
OPERATING CONDITIONS OF FIBERGLASS CASING
(Koch Fiberglass Products Co., 1981)
TBS-210 TBS-810 TBS-1010
3 in. 4 in. 3 in. 4 in. 3 in. 4 in.
SPECIFICATIONS:
Wt-lbs/ft
0.D., inches
1.D., inches
Wall, inches
Upset O.D.
.88 .95
3.50 4.50
3.36 4.36
.08 .10
3.80 4.90
1.40 1.80
3.65 4.70
3.36 4.36
.15 .175
4.225 5.225
1.90 2.95
3.76 4.86
3.36 4.36
.20 .25
4.376 5.65
OPERATING CONDITIONS:
Pressure, psi
Collapse, psi
Temperature, °F
Tensile pounds
across joint 11
Pipe body, psi 11
300
300
800
100
75
500
150
150
150
000
15,000
18,000
700
16,000
20 ,000
800 1,000 1,000
250 1,000 1,000
150 150 150
19,000
26,000
81
-------
TABLE 4.7
OPERATING CONDITIONS AND PHYSICAL PROPERTIES
OF FIBERGLASS TUBING
(Koch Fiberglass Products Co., 1981)
K-1250,
Gray
K-2000,
Black
2-3/8
2-7/8
3-1/2
4-1/2
2-3/8
2-7/8
3-1/2
4-1/2
L n.
in.
in.
in.
in.
in.
in.
in.
SPECIFICATIONS:
Wt-1bs/f t
1 . 20
1.40
2.40
3.05
1.40
1.70
3.00
3.73
O.D., in.
2.39
2.85
3.50
4.58
2.50
2.93
3.73
4.70
I.D., in.
2.00
2.43
3.00
4.00
2.00
2.43
3.00
4.00
Wall, in.
0 .19
0.21
0.25
0.29
0.25
0.27
0.31
0.35
Upset O.D., in.
3.25
3.75
4.75
5.25
3.25
3.83
4.88
5.75
OPERATING CONDITIONS AT
15 0 ° F :
Pressure, psig
1 ,500
1,500
1,500
1,500
2,000
2,000
2,000
2,000
Collapse, psig
1,250
1,100
1,000
1,000
2,000
1,750
1,500
1,500
Tensile pounds
9,000
10,500
11,000
12,000
10,000
12,500
15,000
12,000
Temperature, *F
150
150
150
150
150
150
150
150
Pressure, psig
1 ,875
1,875
1,875
-
3,000
3,000
3,000
-
Hill test, mill
test tensile, lbs
9,000
10,500
11,000
-
10,000
12,500
15,000
-
PHYSICAL PROPERTIES:
Ultimate failure,
internal, psig
3,800*
4 ,050
3,600
-
6 ,000
4,600
4,500
-
short term, psig
3,800**
4,200
3,900
-
4,200
5,000
4,600
-
Ultimate collapse
4,500*
3,200
4,400
-
9,400
9,600
10,200
-
pressure, psig
4,500**
3,100
4,200
-
9,100
9,250
9,500
-
Ultimate tensile
43,000*
55,550
78,000
-
50,000
57,750
79,000
-
across joint, lbs
36,000**
48,750
70,000
-
39,000
48,000
75,000
-
Modulus of elasticity
ln tens ion
Linear coefficient
of thermal expansion
In./lOOO f t / ° F
Specific gravity
Flow factor, Hazen
W l 1 1lam5
3.4 x 10<
0.09
1.90
3.5 x 106
0.09
1.90
150
150
-------
TABLE 4.8
TYPICAL PHYSICAL PROPERTIES OF THERMOPLASTIC
WELL CASING MATERIALS AT 73.4°F
(NWWA, 1980)
ASTM
Test
Cell
per
ABS
Class,
D-1788
PVC
Cell Class,
per D-1784
SRR
Cell Class,
per D-18922
Property
Method
434
533
12454-B&C
14333-C&D
4434AA
Specific gravity
D-792
1.05
1.04
1.40
1.35
1.05
Tensile strength, psi
D-638
6,000*
5,000*
7,000*
6,000*
3,100*
Tensile modulus of
elasticity, psi
D-638
350,000
250,000
400,000*
320,000*
320,000
Compressive strength, psi
D-695
7,200
4,500
9,000
8,000
5,000
Impact strength, Izod,
ft-lb/inch notch
D-256
4.0*
6.0*
0.65
5.0
0.9
Deflection temperature
under load (264 psi), "F
D-648
190*
190*
158*
140*
180
Coefficient of linear
expansion, in/in-°F
D-696
5.5 x 10~5
6.0 x 10~5
3.0 x 10"5
5.0 x 10"5
4.8 x 10~5
* These are minimum values set by the corresponding ASTM Cell Class designation. All others represent
typical values.
-------
susceptible to corrosion by galvanic and electrochemical
effects. They are also resistant to chemical attack by oil
and water and are unaffected by microbial agents. Plastic
casing has been used for such applications as injection of
waste pickle liquors (Bayazeed and Donaldson, 1973) and
for injection of acids in uranium leaching mines (Koch
Fiberglass Products Company, 1981). However, such materials
may be susceptible to organic solvents such as acetone,
methyl ethyl ketone, toluene, trichloroethylene, turpentine,
and xylene (NWWA, 1980; Allen and Roberts, 1978). Plastics
can also be used for liners for metallic casing to protect
against corrosion.
4.2 CEMENT
Well-construction service companies indicate that the
single most important factor in insuring well integrity is
obtaining a satisfactory pr iinary-cement ing job. Primary
cementing involves the placement of cement in the annulus
Detween tne borehole and the outermost casing and/or the
concentric strings of casing, to restrict fluid movement
between formations as well as to support and to bond the
casing (Warner and Lehr, 1977). In addition, the low perme-
ability of cement protects the casing from corrosive salt-
water zones and microbial agents and isolates high pressure
or lost-circulation zones.
4.2.1 General Manufacture, Composition, and Character-
istics of Completion Cement
The most common cement used in well completion is
Portland cement. Portland cement is manufactured by calcin-
ing raw materials consisting of limestone, clay, and shale
(or other materials high in calcium chloride) in a rotary
Kiln at temperatures between 2600°F to 280G°F ( 14 2 7 0 C to
153a°C) (Moore, 1974). The resulting material (clinker) is
finely ground with a controlled amount of gypsum ( 1 . [5 to 3
percent by weight) to form the finished cement. In add it ion
to the raw materials, other substances such as sand, baux-
ite, or iron oxides may be added to adjust the chemica1
composition of the clinker and to achieve specific types oL
Portland cement.
4
-------
Cement contains four compounds that aid in the forma-
tion of a rigid structure (hydration). Generically, the
compounds contain lime, silica, alumina, and iron expressed
as:
1. Tricalcium silicate (C3S) is the major compound
found in most Portland cement and is the principal strength
producing material. It is responsible for early strength
development ranging from 1 to 28 days.
2. Dicalcium silicate (C2S) is a slow-hydrat ion
compound and accounts for the gradual gain in strength which
occurs over an extended period of time.
3. Tricalcium aluminate (C3A) promotes rapid hydration
and controls the initial set and thickening time of the
cement slurry. It increases the susceptibility of cement to
sulfate attack; high sulfate-resistant cement must have 3
percent or less C3A.
4. Tetracalcium aluminoferite (C4AF) is a low heat-of-
hydration compound. High concentrations of C4AF tend to
promote strength retrogression. An excess of iron oxide will
increase the amount of C4AF and decrease the amount of
C3A in the cement.
Table 4.9 presents typical compositions of various
classes of cements according to the relative concentration
of the four compounds (Moore, 1974). In addition, the table
shows the fineness of the grind of each class of cement and
lists cement properties that may be desired and the associ-
ated controlling factors.
Table 4.10 provides specifications for the API oil-
well cement classes in terms of mixing-water requirements,
cement-slurry weight, well depth, and static temperature.
In addition, sulfate resistance, susceptibility to extreme
temperatures and pressures, and compatibility with cement
additives are identified for several classes of cement.
Two important criteria in selecting a cement are
compressive strength development and thickening time (pump-
ability time) (see Tables 4.11 and 4.12). Both of these
criteria are primary factors determining the waiting on
85
-------
TABLE 4.9
TYPICAL COMPOSITION OF PORTLAND CEMENT
(Moore, 1974)
Wagner
Compounds (percent) Fineness
API Class C3S C2S C3A C4AF (Sq.Cm./Gram)
A 53 24 >8 8 1600 - 1800
B 47 32 <5 12 1600 - 1800
C 58 16 8 8 1800 - 2200
D & E 26 54 2 12 1200 - 1500
G & H 50 30 5 12 1600 - 1800
Property:
High early strength
Better retardation
Low heat of hydration
Resistance to sulfate attack
How Achieved:
Increasing the C3S content,
finer grinding
Control C3S, C3A contents
and grind coarser
Limiting the C3S and C3A
content
Limiting the C3A content
-------
TABLE 4.10
API CEMENT CLASSIFICATION
(API Spec 10A, 1979)
M i x i ng
Slurry
Static
water
weight
Well depth
temperaturi
API Class
gal/sack
lb/gal
ft
° F
A
5.2
15.6
0- 6,000
80-170
B
5.2
15.6
0- 6,000
80-170
C
6.3
14.8
0- 6,000
80-170
D
4.3
16.3
6-12,000
170-260
E
4.3
16.3
6-14,000
170-290
F
4.3
16.3
10-16,000
230-320
G
5.0
15.8
0- 8,000
80-200
H
4.3
16.3
0- 8,000
80-200
Class A: Intended for use when special properties are not
required. Available only in ordinary type (Type I).
Class B: Intended for use when conditions require moderate
to high sulfate-resistance. Available in both moderate
(Type II) and high sulfate-resistant types.
Class C: Intended for use when conditions require high
early strength. Available in ordinary and moderate
(Type III) and high sulfate-resistant types.
Class D: Intended for use under conditions of moderately
high temperatures and pressures. Available in both mod-
erate and high sulfate-resistant types.
Class E: Intended for use under conditions of high temper-
atures and pressures. Available in both moderate and high
sulfate-resistant types.
Class F: Intended for use under conditions of extremely
high temperatures and pressures. Available in both mod-
erate and high sulfate-resistant types.
Class G: Intended for use as a basic cement as manufac-
tured, or can be used with accelerators and retarders to
cover a wide range of well depths and temperatures.
Available in moderate and high sulfate-resistant types.
Class H: Intended for use as a basic cement and can be used
with accelerators and retarders to cover a wide range of
well depths and temperatures. Available in moderate and
high sulfate-resistant types.
87
-------
TABLE 4.11
TYPICAL COMPRESSIVE STRENGTH
OF CEMENT (psi at 24 hr)
(Allen and Roberts, 1978)
Curing Conditions Class
Temperature Pressure A C D G H
(° F) (psi)
60
0
615
780
~
440
325
80
0
1,470
1,870
*
1,185
1,065
95
800
2,085
2,015
*
2,540
2,110
110
1,600
2,925
2,705
*
2,915
2,525
140
3,000
5,050
3,560
3,045
4,200
3,160
170
3,000
5,920
3,710
4,150
4,830
4,485
* Not recommended at this temperature
-------
TABLE 4.12
HIGH-PRESSQRE THICKENING TIME
OF CEMENT
(Allen and Roberts, 1978)
( f:
Circulating Class
Temperature A CD G H
91 >4:00 >4:00 - >3:00 3:57
103 3:36 3:10 >4:00 2:30 3:20
113 2:25 2:06 >4:00 2:10 1:57
125 1:40 1:37 >4:00 1:44 1:40
89
-------
cement (WOC) time, which is the time required to permit
the cement to attain sufficient strength to anchor the
casing and withstand stresses of subsequent drilling and
operation, and to seal permeable zones and confine fracture
pressures (Allen and Roberts, 1978). These, as well as
other required properties and characteristics of cements,
can be obtained through blending specialty cements or
by the addition of specific cement additives.
4.2.2 Specialty Cements and Cement Additives
Required properties of the cement to obtain a solid
primary-cementing job and to insure the structural in-
tegrity of the injection well are shown in Table 4.13.
However, such properties are not inherent in all cements
to the degree required by specific applications to different
environments. For example, high temperatures experienced
during primary cementing can cause the cement to set pre-
maturely and inhibit complete placement of the cement.
Therefore, several specialty cements and cement additives
have been developed to achieve certain properties or alter
basic characteristics of standard cement classes. Although
sold under numerous trade names, specialty cements bas-
ically include: pozzolan slurries, lightweight cements,
thixotropic cement, oil-based cement, expanding cement, and
calcium aluminate (refractory) cement. (These specialty
cements are described along with applications, advantages,
and limitations of each type in Table 4.14.)
In general, the creation of new cements or tailor-
ing of standard classes of cement to meet new technology
requirements is virtually unlimited, a result of the num-
erous additives that have been developed. The major cement
additive classifications include, accelerators, retarders,
density adjusters, lost-circulation materials, filtration
(fluid loss) control, and dispersants. A summary of cement
additives and additional specialty cements is shown in Table
4.15. (The summary is presented to provide an overview of
oasic cement additives and does not represent a detailed
listing of the numerous additives that have been manu-
factured . ) Several brands of such a d d i t i v e s have be e n
deve1opca indiviaua 11y by cement ing sorvice industrles ( seo
Ta o1e 4.16).
-------
TABLE 4.13
CEMENT PROPERTIES AND CHARACTERISTICS
(Allen and Roberts, 1978; Parker, et al, 1977)
Property/Char-
acteristics
Description
Importance
Slurry
viscosity
Thickening
time
A measure of the
thickness of the
slurry expressed
in units of con-
sistency; cement
is a non-Newtonian
fluid; viscosity
is a function of
shear rate.
Time that the ce-
ment remains pump-
able in the well.
Viscosities should be
kept low for turbulent
flow and thus enhance
drilling fluid removal,
High viscosity enables
plug flow cementing.
Should be long enough to
be pumped into place and
short enough to permit
operations to resume
quickly; normally 2.5 to
3 hours.
Water ratio
Mixing water
Ratio of the weight
of water used to the
weight of cement;
determined by mini-
mum to permit pump-
ability but avoid
solids separation.
Water mixed with
cement to produce
slurry.
Set volume of cement
should be equal to
slurry volume; free
water should be less
than 1 percent.
Fresh water is prefer-
able to avoid unwanted
acceleration or retar-
dation of cement due to
inorganic or organic
compounds, respectively,
91
-------
TABLE 4.13 (Cont'd)
Property/Char-
acteristics Description Importance
Strength
Development
Dens ity
Compressive strength
of the set cement
measured in psi.
Pressure and temp-
erature affect the
rate of strength
development. Com-
pressive strength
increases as dens-
ity increases.
Weight per volume
(lb/gal) of the ce-
ment slurry; density
should be low enough
to be supported by
weak formations and
heavy enough to con-
trol well pressures;
the density of the
cement should be
greater than drill-
ing fluids to ensure
adequate displace-
ment .
Required to support the
casing and seal perme-
able zones and confine
fracture pressures;
usually compressive
strength of 500 psi
is required before
drilling operations
can proceed.
Affects other proper-
ties such as thickening
time, compressive
strength and permea-
bility.
Fluid loss
The loss of water
from the slurry
to the formation
during cement place-
ment; measured as a
rate.
Control of fluid loss is
important in order to
avoid density and vis-
cosity increases which
can inhibit pumpability,
block off cement flow,
or stick casing; fluid
loss control is a par-
ticular concern where
gas communication is
likelv.
9 2
-------
TABLE 4.13 (Cont'd)
Property/Char-
acteristics
Description
Importance
Permeability
The measure of the
ease with which a
fluid flows through
the connecting pore
spaces of rock or
cement.
The lower the permea-
ability of the cement
the greater the com-
pressive strength and
protection of the casing
to corrosive formation
fluids.
Sulfate
res istance
Ability of a cement
to resist deterior-
ation in the pres-
ence of sulfate ions;
sulfite resistance is
controlled by concen-
tration of tricalcium
aluminate (C3A):
. 3 percent C3A
high sulfate re-
sistance
. 8 percent C3A
moderate sulfate
resistance.
Sulfate reacts with C3A
to form sulfo-aluminates
which upon enlargement
develop cracks, in the
cement, increasing per-
meability and decreasing
strength.
Heat of
Hydration
Heat generated by
the chemical re-
actions of the
setting cement;
heat developed by
cement setting in
a 2-inch annulus
will increase temp-
erature 30° to 40°F,
Of particular concern in
permafrost regime; in-
creased temperature can
melt ice lenses and
prevent bonding.
93
-------
TABLE 4.13 (Cont'd)
Property/Char-
acteristics Description Importance
Bonding
The state of bond
between cement and
casing and/or forma-
tion; bonding is en-
hanced by cement
expansion; bond
strength is estimated
with shear-bond and
hydraulic-bond tests.
Mechanically supports
casing in wellbore and
blocks migration of
fluids; bond strength
increases with com-
pressive and tensile
strength.
-------
Cement
Slurry
weight
(lb/gal)
Pozzolan
13-15
Light Weight
12-14
TABLE 4.14
APPLICATIONS, ADVANTAGES AND LIMITATIONS OF
SELECTED SPECIALTY CEMENTS
(Parker, et al., 1977)
Composition
Application
Advantages
Limitations
Blend of Class A or H
with Pozzolan - either
natural diatomaceous
earth (Diacel A) or
manmade fly ash,
properties can be
further modified
with bentonite or
lime.
Blend of portland
cement and calcined
shale.
Used primarily for casing
cementing, but also used
for squeeze cementing
and lost circulation
plugs.
Used both as a filler
and completion cement,
and in weak formations
which could not with-
stand hydrostatic
pressure of normal-
weight portland
cement.
Wide range of water rations.
Predictable thickening time
and compressive strength.
Can be used at all depths
and temperatures.
Highly sulfate resistant.
Resist strength retrogression
at high temperatures.
Compatible with all additives.
Very economical.
Wide range of predictable
retardation densities.
Economical filler slurries.
Densified slurries achieve
adequate compressive strength.
Sulfate resistant with low
permeability.
Compressive strengths
are lower than
Portland cements.
Thixotropic
11-15
V.
Oil-Based
(Uses no
water)
Blends of portland
cement and sulfate
hemihydrate? and
most important is
ability to form a
gel structure upon
cessation of move-
ment .
Blend of liquid hydro-
carbon (Diesel), sur-
factants, and either
Class A or H Cement;
water is obtained from
zone being cemented.
Designed for cementing
lost-circulation zones,
vuggy or fractured
formations and diffi-
cult squeeze cementing.
Other applications:
Cement casing to
eliminate staging.
Seal off permeable
zones.
Reduce gas cutting.
Used to shut off water
encroachment, leak ing
casing or lost
circulation zones.
May be used to 240*F bottom
hole circulating temperatures.
Self-supporting - eliminates
fallback or need for "topping
out."
Reduces gas cutting.
Early compressive strength.
Pumpable as long as water
is not contacted.
Forms a viscous slurry
upon contact with water.
High early compressive
strength.
Pumpable as long as water
is not contacted.
Gel cannot be broken
after 15 minutes.
Cannot be mixed with
salt or conventional
retarders.
High fluid loss.
Limited availability of
diesel or kerosine.
Difficult to keep system
water-free.
Setting may be difficult
to control.
Flammable.
Expanding
Calcium Aluminate
(Refractory)
Blend of portland
cement and calcium
sulfoaluminate,
which expands upon
setting.
Portland cement
blended with lime-
stone and bauxite.
Additives include
40 percent silica
flour to improve
strength retro-
gression.
Used to improve bonding
between cement and
casing and/or formation,
also used for squeeze
cementing to seal
perforations or holes
in casing.
Used for cementing wells
in both cold and high
temperature environ-
ments; well suited for
geothermal or fire flood
wells.
Expands upon setting and
and rapidly after setting.
Improves bonding.
Resists strength retro-
gression up to 700*F with
silica flour or firebrick.
Rapid compressive strenght
development.
Resists corrosive water.
Limited to below 200*F
Deterimentally affected
by conventional
retarders.
Not recommended for use
with salt.
Requires larger retarder
concentrations above
200"F.
Expensive.
-------
TABLE 4.15
SUMMARY OF CEMENT ADDITIVES
(Shyrock and Smith, 1981)
Type of Chemical Type of
Additive use Composition Benefit Cement
Accelerators
Reducing WOC time.
Setting surface pipe.
Setting ceaent plugs.
Combating lost circulation.
Calcium chloride
Sodium chloride
Gypsum
Sodium silicate
Dispersants
Sea water
Accelerated setting.
High early strength.
All API Classes
Pozzolans
Diacel systems
Weight-reducing
additives
Increasing thickening
time for placement.
Reducing slurry
viscosity.
Reducing weight.
Combating lost
circulation.
Lignosulfonates
Organic acids
Modified lignosulfonates
Bentonite-attapulgite
Gilsonite
Diatomaceous earth
Perlite
Pozzolans
increased pumping time.
Better flow properties.
Lighter weight.
Economy.
Better fillup.
Lower density.
API Classes D, E, G, i H
Pozzolans
Diacel systems
All API Classes
Pozzolans
Diacel systems
Heavy-weight
additives
Controllin
lost circ
lation
Filtration
control
Combating high pressure.
Increasing slurry weight.
Bridging.
Increasing fillup.
Combating lost circulation.
Squeeze cementing.
Setting long liners.
Cementing in water-
sensitive formations.
Hematite
Ilmenite
Barite
Sand
Dispersants
Gilsonite
Walnut hulls
Cellophane flakes
Gypsum cement
Bentonite-diesel oil
Nylon fibers
Polymers
Dispersants
CMHEC
Latex
Higher density.
Bridged fractures.
Lighter fluid columns.
Squeezed fractured zones.
Minimized lost circulation.
Reduced dehydration.
Lower volume of cement.
Better fillup.
API Classes d, e, g, t a
All API Classes
Pozzolans
Diacel systems
All API Classes
Pozzolans
Diacel systems
Dispersants
Special cements
or additives
Reducing hydraulic horse-
power .
Densifying cement slurries
for plugging.
Improving flow properties.
Primary cement ing.
Organic acids
polymers
Sodium chloride
Lignosulfonates
Sodium chloride
Thinner slurries.
Decreased fluid loss
Better mud
Better pla.
Better bonding to salt,
shales, sands.
All API Classes
Pozzolans
Diacel systems
All API "la
Silica Jlour
H ign-temper ature ceaentlng.
Silicon dioxide
Stabilized strength.
ijowet
Mud mi
i nfi ibi tor
Neutralizing irud-rr*eaiing wi'.tv a[m: 1 Ji 1
co.id 11 ;on«.
a-. i»# : eact u«r>»
-------
TABLE 4.16
BRAND NAMES OF CEMENT ADDITIVES
(Allen and Roberts, 1978)
Product Trade Names
Product
Classi fication
Halliburton
Do we 11
B.J.
Western
Chemical or
Material Description
Accelerators
CaCl2
S-l
A-7
CaCl2
Calcium chloride
HA-5
D—43
A—8
WA-4
Blend of inorganic accelators
D-12
A-2
Diacel A
Diacel A
Diacel A
Salt
Salt
A-5
Salt
Sodium chloride, granulated
H-TLW blends
l:l(etc)
1:1(etc)
-
111 Talc
-
Fluid Loss
Halad 9, 11, 14
D-60
Aquatrol 13, 15
CF-1
Low temp, fluid loss control
-
D-59
-
CF-2
Low temp, fluid loss control
Diacel LVL
D-8
R-6
Diacel LWL
Carboxymethyl Hydroxyethyl
Liquid Turbulence
-
D-73
_
_
Cellulose
Inducers
CFR-2
D-65,45
Turbo-Mix D-16
TF-4
Polymer
CFR-1
-
Turbo-Mix D-30
TF-5
"
Weighting
Barite
D-31
W—1
Barite
Barite
Material
Hi Dense 3
D—76
-
WM-2
Hematite
Hi Dense 2
D-18
W-3
Hmenite
Hmenite
Spacers and
Mud-flush
CW-7
Mud-sweep
WMW-1
Mud thinner-spacer
Washes
Sam 4
oil-base mud
J-22 and 0-4
ASP-4
Oil-base spacer
spacer
"
"
ASP-4
Water-base spacer
Latex
LA-2
D-15, D-78
D-5
CLX-1
Latex cement
Extenders
Howco Gel
Bentonite
B.J. Gel
Bentoment
Bentonite
Gilsonite
Kolite
D-7
Gilsonite
Gilsonite
Bconolite
-
Lo-Dense
Thrifty-Lite
Anhydrous sodium metasilicate
Poztnix A
Litepoz 3
Dianix a, g, m
Pozment a
Artificial pozzolans
-
Litepoz 1
Diamix A, M, G
Pozment N
Natural Pozzolans
Poztnix 140
Litepoz 180
Thermoset
-
Pozzolan-lime mixtures
Howcolight HLC
D-79
Lo dense
Thrifty-ment
H-poz blends
Anti-Foam
NF-P
D-46
D-6
AF-4
Powdered anti-foam agent
NF-1
D-47
D-6
AF-L
Liquid anti-foam agent
Hud Decontaminant
Mud Kil-1
K-21
Firm set I
Shur set I
Mud kill patented by Gulf Oil
Mud Kil-2
K-21
Firm set II
Shur set II
Mud kill patented by Gulf Oil
Silica Sand
Silica flour (reg.)
J-84
D-8
SF-3
325 Mesh silica flour
Silica flour
D—30
-
SF-4
Okla. #1 sand
(coarse)
Thixotropic Cement
Thixotropic cement
Reg. fill-up cement
-
Thixoraent
Thixotropic slurries
Lost Circulation
Gilsonite
Kolite D2Y
D-7 Gilsonite
Gilsonite
_
Cellophane flakes
D-29 jel flakes
Cello-Flake
Cell-O-Seal
-
"
"
-
Kwik-Seal
"
Retarders
Kembreak
Kembreak
Kembreak
WR-1
Low temp, cetarder
HR-4
D-22
Retroset 2
WR-2
Low temp, retarder (calcium
lignosulfonate)
HR-7
D-13
Retroset 5
WR-4
Low temp, retarder
HR-12
D-28
Retroset 8
WR-6
High temp, organic retarder
Diacel LWL
D-8
Retroset 6
Diacel LWL
Diacel LWL carboxymethyl
Hydroxethyl cellulose
HR-20
D—99
RIO, Rll
-
High temp, retarder
D-93
WR-7
Borax
97
-------
4.3 ANCILLARY EQUIPMENT AND MATERIALS
During construction of the well, casing installation
and primary cementing are facilitated by the use of ancil-
lary equipment and materials which include centralizers and
scratchers, float shoes and collars, plugs and cement
baskets, and displacement fluids and washes/spacers.
Additionally, annulus fluids surrounding the injection
tubing may be required to control injection-fluid placement,
to protect against corrosion, and to monitor injection pres-
sure to detect tubing leakage. The following section will
highlight such materials indicating their relative impor-
tance and their function in well-construction technology.
(Not included with this discussion are other equipment and
materials such as packers, valves and fittings, screens,
and drilling fluids which are described in Chapters 3
and 5.)
Most ancillary equipment is utilized to obtain satis-
factory primary cementing. Table 4.17 provides a summary of
equipment that can be used in cementing the casing in the
borehole. However, not all of the equipment shown in Table
4.17 is utilized in constructing every well, as some of the
equipment has very specific applications.
Mechanical devices attached to the outside of the
casing enable the casing to be centered in the hole, and
thereby facilitate equal distribution of cement surrounding
the casing. These devices, referred to as centralizers,
(Figure 4.3) are particularly useful for long strings of
pipe or for running casing into deviated holes. Some
centralizers have built in flanges that cause increased
turbulent flow of the cement, which enhances wall cake
removal.
Scratchers and wall cleaners may also be attached to
the outside of the casing to help remove wall ca*e ana help
prepare the formation for bonding with the cement. There
are basically two types, reciprocating and rotating,
which cons i s t of a steel collar and either bristles or
wire loops. Scratchers also re inforce the cement sheath
(F igure 4.4).
Several different typos of floating guide shoes,
collars, and p1 a in open end guide shoes are avail aole.
Plain open end guide shoes are used to guide tne ca.3 i r.u pai-t
-------
TABLE 4.17
CEMENT EQUIPMENT AND MECHANICAL AIDS
(Shyrock and Smith, 1981)
Cementing Equipment and Types
FLOATING EQUIPMENT
1, Guide Shoes
Guides casing into well.
Minimizes derrick strain.
First joint of casing
2. Float Collars
AUTOMATIC FILL-UP EQUIPMENT
1. Float Shoes
FORMATION PACKER TOOLS
1. Formation Packer Shoes
2. Formation Packer Collars
Prevents cement flow back.
Create pressure differentials to
improve bond.
Catches cementing plugs.
Sane as Float Collars and Guide Shoes
except fill-up is controlled by
hydrostatic pressure in annulus.
Packer expands to protect lower zones
while cementing.
1 joint above shoe in wells less than
6,000 ft; 2 to 3 joints above shoe in
wells greater than 6,000 ft.
Same as Float Collars or Guide Shoes.
First joint of casing
As hole requirements dictate.
CEMENTING STAGE TOOLS
1. 2-Stage
2. 3-Stage
3. Full Opening Tools
When required to cement two or more
sections in separate stages.
Based on critical zones and formation
fracture gradients.
PLUG CONTAINERS
1. Quick Opening
2. Continuous Cementing Heads
To hold cementing plugs
until released.
Top joint of casing at surface of well.
CEMENTING PLUGS
1. Top and Bottom Wiper Plugs
2. Ball Plugs
3. Latch Down Plugs
Mechanical spacer between drilling
fluid and cement (bottom plug) and
cement and displacement fluid (top
plug).
Between well fluids and cement.
CASING CENTRALIZERS
1. variable Types
Center casing in hole or provide
minimum stand-off to improve
distribution of cement in annulus,
prevent differential sticking.
1 per 1 to 3 joints.
SCRATCHERS OR WALL CLEANERS
1. Rotating
Remove wall cake and circulatable
drilling fluid from borehole.
Place through producing formations and
50 to 100 ft above. Rotate pipe 15 to
20 RPM.
2. Reciprocating
Aid in creating turbulence.
Improve cement bond.
Placement is same as rotating Reciprocate
pipe 10 to 15 ft off bottom.
BRIDGE PLUGS
1. wire Line
2. Tubing
CEMENTING BASKETS AND EXTERNAL PACKERS
For permanent or temporary plugging
in open hole.
For casing or liner where mechanical
support is necessary until the cement
column sets.
May be placed in well on wire line on
tubing or below retrievalbe squeeze
packers.
Below stage tools or where weak formations
occur downhole.
99
-------
A
Pi
-t-m
EUE TUBING CENTRALIZE R
SLIM HOLE TYPE
Figure 4.3.
Casing centralizers (Halliburton
Services,- 19 81)
1 0 0
-------
RWC WALL CLEANER
CABLE TYPE WALL CLEANER
ROTO WALL CLEANER
Figure 4.4. Scratcfters and wall cleaners (Halliburton,
1981 )
101
-------
any obstruction in the hole. Float guide shoes and float
collars serve as a means of floating the casing into
the hole and as a back-pressure valve to help prevent any
back-flow of cement after it has been placed. Other such
equipment, including automatic fill-up float shoes or
formation packer shoes, may be used. Formation packers may
be particularly useful in completions where low pressure
formations must be protected against cement contamination
(Figure 4.5).
Cementing plugs which are usually made of rubber and
aluminum may be used. Top and bottom plugs are used in
order to separate the cement from the drilling and dis-
placement fluids. The bottom plug precedes the cement down
the casing and wipes drilling fluid from the casing walls.
Upon seating on the shoe or collar, the center of the plug
ruptures permitting cement to flow through. The top plug is
released after all the cement is in the casing ahead of the
displacement fluid. The top plug provides a pressure tight
seal upon seating with the bottom plug (Figure 4.6).
Various fluids can also be used to achieve efficient
drilling-fluid removal and cement placement. The fluids
basically consist of spacers and washes, and displacement
fluids. Spacers and washes enhance drilling-fluid removal
and improve cement bonding. These fluids are usually
mixtures of water and surfactants and perhaps scouring
agents such as barite, placed in the casing ahead of the
cement slurry (Western Co., 1981).
Displacement fluids are put behind the top plug and
exert pressure to cause the cement slurry to displace
through the casing and up the annulus between the casing and
the borehole. For surface and intermediate casing strings,
drilling fluid is normally used as the displacement fluid.
Depending upon the completion program, freshwater or salt
water is used for cementing the injection casing. Either a
sugar water or other retarding additive is sometimes placed
immediately above the top plug in small diameter casing to
inhibit setting of cement that may have bypassed the top
plug (Alien and Roberts, 197d). Other equipment used to
complete primary cementing includes stage tools, cementing
neads, p 1 uy containers, cement baskets, and jet mixers
(Moore, 1y 7 4 ) .
-------
GUIDE SHOE
O
FORMATION FACKER SHOE
SUPER SEAL FLOAT COLLAR
Figure 4.5. Guide shoes, float collars and packer
shoes (Halliburton, 1981)
103
-------
Diophrogm
- Molded rubber
Molded 'ubb«r
Ca*t oiuminum
remforfiog plot*
5 W Bottom plug
5 W Top piwQ
Figure 4.6. Cement: plugs (Moore, 19 74 )
(3 4
-------
Allen, T. 0., and A. P. Roberts, 1978. Production opera-
tions, Volumes 1 and 2. Oil and Gas Consultants, Inc.,
Tulsa, Oklahoma.
American Petroleum Institute (API), 1975. Specification
for reinforced thermosetting resin casing and tubing.
Spec. 5AR, 1st Edition, Dallas, Texas.
American Petroleum Institute (API), 1976. Specification
for high-strength casing, tubing, and drill pipe.
Spec. 5AX, 10th Edition, Dallas, Texas.
American Petroleum Institute
for casing, tubing and
Edition. Dallas, Texas.
(API), 1979. Specification
drill pipe. Spec. 5A, 34th
Specif ication
and tubing.
Specif ication
ives. Spec.
API), 1980. Bulletin on
casing, tubing, and drill
Edition, Dallas, Texas.
Materials (ASTM), 1977.
thermoplastic well casing
standard dimension ratios
, Philadelphia, Pennsyl-
American Petroleum Institute (API), 1979.
for restricted yield strength casing
Spec. 5AC, 11th Edition, Dallas, Texas.
American Petroleum Institute (API), 1979.
for oil-well cements and cement addit
10A, 20th Edition. Dallas, Texas.
American Petroleum Institute (
performance properties of <
pipe. Bull. 5C2, 17th ]
American Society for Testing &
Standard specification for
pipe and couplings made in
(SDR). ANSI/ASTM F 480-76
vania.
Armco Steel Corporation, 1981. An introduction to oil
country tubular products. Houston, Texas.
Bayazeed, A. F., and E. C. Donaldson, 1973. Subsurface
disposal of pickle liquor. U.S. Bureau of Mines,
No. 7804.
Halliburton Services, 1981. Halliburton cementing tables.
Duncan, Oklahoma.
105
-------
Koch Fiberglass Products Co., 1981. Blue streak fiberglass
pipe and fittings. Wichita, Kansas.
McGright, R. D., et al. , 1970 . Well casing materials
in Lawrence Livermore Laboratory industrial support
program test results on scale control, corrosion,
H2S abatement, and injection at the Salton Sea geo-
thermal field. UCID-18596, Livermore, California.
Moore, P. L., 1974 . Cements and cementing i_n Drilling
practices manual. D. K. Smith, Ed. PennWell Books,
Tulsa, Oklahoma.
National Water Well Association (NWWA) and Plastic Pipe
Institute (PPI), 1980. Manual of the selection and
installation of thermoplastic water well casing.
Worthington, Ohio.
Shryock, S. H., and D. K. Smith, 1981. Geothermal cement-
ing: the state-of-the art. Halliburton Services,
Duncan, Oklahoma.
Warner, D. L., and J. H. Lehr, 1977. An introduction to
the technology of subsurface wastewater injection.
U.S. Environmental
Western Company, 1981.
product bulletins.
Protection Agency, EPA-600/2-77-240.
Stimulation and cementing services
Ft. Worth, Texas.
-------
5. DOWNHOLE, WELLHEAD, AND ANCILLARY EQUIPMENT
This section describes the selection and installation
of downhole, wellhead, and ancillary equipment necessary for
the operation of a leak-free injection system. As such, the
following components are considered: bottom-hole config-
urations, completion practices, wellhead equipment, and
water handling and surface equipment.
5.1 BOTTOM-HOLE CONFIGURATIONS
Selection of a bottom-hole configuration or bottom-hole
completion method is an initial step in planning a well.
Depending primarily on characteristics of the injection
zone, a wide variety of bottom-hole completion methods are
used, but generally can be categorized as those applied to
competent formations and those applied to incompetent
formations. Competent formations include limestone, dolo-
mite, and consolidated sandstone that will stand unsupported
in a borehole. The most commonly encountered incompetent
formations are unconsolidated sand and gravel that will cave
into the borehole if not artificially supported. There are,
of course, formations that are generally competent but
require some support to prevent sloughing of occasional
incompetent intervals or to prevent fractured blocks from
falling into the borehole (Warner and Lehr, 1977). The type
of injection fluid used, and the possibility of well deepen-
ing or multiple-interval injection also affect the selection
of completion method.
To date, injection wells have been completed using
one of three methods or close variations of them: open-
hole completion in competent formations; screened, or
screened and gravel-packed in incompetent sand and gravel
(also known as liner completion); and fully cased and
cemented with the casing perforated in either competent
or somewhat incompetent formations (Figures 5.1, 5.2,
and 5.3).
5.1.1 Open-Hole Completion
In open-hole comple t ion, casing is set just above
the prospective injection interval, either before or after
107
-------
Figure 5.1. Well completion by the open-hole? method
(Barlow, 19 72)
-------
Figure 5.2. Well completion by the screen and
gravel pack method (Barlow, 19 72)
109
-------
Common cement
6 5/8 in. steel casing
Diesel-oil- filled
annulus
Packer
Perforations
3^-
JL
^f-.v
A;c
rX£"
y
Vr-*
&
fM
-Vv
,v.V
14 in. hole
9 5/8 in. steel casing
3 1/2 in. glass-reinforced
plastic tubing
Acid-proof cement
6 5/8 in. glass-reinforced
plastic casing
Acid-proof cement
figure 5.3. Well completion by the cased and per-
forated method (Barlow, 1972)
-------
the injection zone is drilled, though the usual procedure
is to set casing in advance (Petroleum Extension Service,
1971, 1977a). Advantages associated with open-hole com-
pletion include: the entire injection interval is exposed
to the borehole; little casing and no screen is subject
to corrosion by the formation or the injection fluids;
no expense is incurred for perforation; the well can easily
be deepened; and the well can be converted to a liner
or perforated completion, or it can be underreamed to
obtain a larger bore for gravel pack (Warner and Lehr,
1977; Allen and Roberts, 1978; Petroleum Extension Service,
1971). In addition to limitation of its use to only com-
petent formations, other disadvantages of this method
include limited selective injection into different zones and
frequently required cleanout if the formation tends to
slough. Also, the casing must be run without logging data
on the immediate injection interval if set before pene-
tration of the injection zone (Allen and Roberts, 1978).
5.1.2 Screened Completion
Screens or liners are used as a means of formation
support and sand control. Screens can be set immediately
against the formation or can be set in an underreamed
formation with gravel packing. Two types of screens are
presented in Figure 5.4 and range from slotted pipe to
fine-mesh welded screens. Depending upon the corrosiveness
of the injection fluid, alloys such as stainless steel,
bronze, galvanized steel, or plastics can be used as
screening material. A detailed discussion of liner instal-
lation is presented by the Petroleum Extension Service
(1971) .
Many of the advantages and disadvantages of open-hole
completion are also characteristic of the screened comple-
tion, or the screened and gravel-packed completion. An
important benefit of the screen is that it provides some
degree of wall support, an advantage in unconsolidated
formations. Such support is also necessary in partially
consolidated formations used as injection zones, as in the
Gulf Coast of Texas and Louisiana, and in California (Warner
ana Lehr, 1977). Screened wells limit injection of fluids
into selected intervals. If the screen is to be removed
for plug-back, hole deepening, or squeeze cementing opera-
tions, difficulties can be encountered depending on the
1 1 1
-------
SLOTTED CASING
WIRE WRAPPED SCREEN
igure 5.4. Example of slotted casing and wire-
wrapped well screens (Johnson Division,
UOP,' Inc. , 1975)
-------
mechanical condition of the screen and the forces acting
upon the screen by the formation.
5.1.3 Perforated Casing Completion
In a perforated casing completion, the injection
casing is installed and cemented through the full depth of
the well. Selected injection zones are accessed by per-
forating the casing and the cement with a series of solid
projectiles or small shaped-explosive charges. Shot holes
are generally less than one-half inch in diameter and will
penetrate the casing and several inches of cement and/or
rock. This method of completion has been applied to wells
in both hard and soft rock areas, and may be most useful for
recompletion when additional injection capacity is needed
or when it is necessary to abandon the original injection
zone (Warner and Lehr, 1977).
Advantages of the perforated completion method include:
adaptability to special sand control techniques; adapt-
ability to multiple completion techniques; and provision of
maximum support to the formation wall. The technique
is not adaptable to special drilling practices that min-
imize formation damage since the injection well is drilled
to total depth before the casing is set. The injection
casing must be properly cemented to achieve zone segregation
and to minimize formation damage in the injection zone.
Cement and other borehole fluids that contact the formation
during drilling and cementing operations increase the
chances of formation damage that may impair flow rates and
lead to higher injection-pressure requirements.
5.1.4 Well Stimulation
Well stimulation refers to chemical and/or mechanical-
hydraulic treatment methods used to improve flow character-
istics of the borehole and the adjacent formation. Stim-
ulation methods can be applied to new wells after completion
and before operation, but can be applied to older wells to
maintain or to improve performance. This practice is often
referred to as reworking, reconditioning, redevelopment, or
rehabilitation.
1 13
-------
The five basic stimulation methods are surging or
swabbing, shooting, vibratory explosion, pressure acidizing,
and hydraulic fracturing. Specific characteristics of the
formation to be treated, the method of completion, and the
method of operation influence the selection of the stimu-
lation approach. Surging is used in developing shallow
wells in unconsolidated sands where screened or liner
completion is used to remove fine sediment from the vicinity
of the well screen (NWWA, n.d.; Johnson Division, UOP, Inc.
1975). Shooting and other explosive stimulation methods
traditionally were used to increase permeability in tight
formations, but have been largely eliminated from use.
Stimulation methods used frequently in injection wells
include those that improve formation permeability at the
borehole and those that impact the injection zone at a
distance from the well. Methods that affect the immediate
borehole include washes, jet acidization, and detergent
washing. These methods are used to remove drilling fluids
or other deposits from the borehole face, or to improve
permeability within a few inches of the borehole where
formation damage from drilling may have occurred (Warner
and Lehr, 1977). Hydraulic fracturing or pressure acidiza-
tion techniques are designed to increase formation permea-
bility significant distances from the well.
Pressure acidization or acid fracturing techniques have
been extensively applied in injection wells, particularly
in carbonate formations (Petroleum Extension Service,
1977b; Krueger, 1978; Williams and Whiteley, 1978; Gidley,
1978; Williams and Nierode, 1978). Injection of acid into
an acid-soluble formation allows dissolution to enlarge
voids and increase the permeability of the formation.
Various additives are used in acidization treatments to
prevent the corrosion of casing. Corrosion inhibitors are
used to prevent the acid from deteriorating steel casing
while the acid is in the well. Acids used frequently are
hydrocholoric (15 to 2b percent), acetic or formic (10
percent), and hydrofluoric (Petroleum Extension Service,
1981 ) .
Hvdraul ic fracturing is discussea extensively in the-
pet role um literature (Allen and Roberts, 197b; Hubbert and
Willi s, 1 970; Krueger, 1 978; Petroleum Extons ion Service,
1981), and is used in developing fractures in tight sand-
stones or in carbonates to increase permeability. Hydraulic
-------
fracturing employs fluid pressure to develop or extend
fractures or cracks in the injection zone. Instead of using
an acid to dissolve the matrix, cracks are kept open by
injecting entrained proppants such as sand, walnut hulls,
or other specialty materials. The fracturing fluids
used are generally water-based, such as potassium chloride
gels, although other fluids have been used.
A major concern in hydraulic fracturing is the deter-
mination of fracture orientation and fracture magnitude. If
the fracture extends across the confining beds above or
below an injection zone and proppants are injected, a path
of migration can be formed. Further research is being
conducted in this field to enable better predictions of
fracture behavior and fracture propagation in confining
zones. Production histories of oil and gas wells indicate
the vertical extent of fractures, when in fact they do
occur, is limited even if the fracture treatments have
employed higher rates and volumes.
5.2 WELL-COMPLETION PRACTICES
Well completion refers to the method of providing a
path for transporting the injection fluid to the injection
zone. Primarily, well completion depends on the character-
istics of the injection fluid, injection pressure, volume
injected, length of service, and plans for recompletion
(Petroleum Extension Service, 1977a). To a large extent,
downhole environments dictate the completion practice.
The three basic completion practices used in injection
wells are tubing and packer, tubing with open annulus, and
tubingless. Variations on these practices have been adapted
to meet a wide range of site-specific applications including
injection into multiple annuli, and injection into a tubing
with production through the annulus.
5.2.1 Tubing and Packer Completion
Tubing and packer completion can be used with open-
nole, screened, and perforated casing bottom-hole configura-
tions. Figures 5.2 and 5.3 are examples of such completion
with perforated and screened/gravel-packed configurations.
This type of completion isolates the casing from high
115
-------
pressures and corrosive fluids and the packer prevents
injection-fluid circulation in the tubing/casing annulus.
In this example, the only points of well equipment and
injection fluid contact are at the packer seal and the
injection tubing, assuring a leak free system. However,
tubing and packer components are exposed to the injection
fluid and are subject to chemical degradation, especially
where highly corrosive fluids are injected. Plastic coated,
fiberglass, or corrosion resistant metal alloy tubing may be
appropriate in certain applications (Donaldson, et al.,
1974). Further protection from corrosion is possible by
filling the annulus with noncorrosive fluids (Petroleum
Extension Service, 1977a; Donaldson, et al., 1974).
Tubing and packer completion may be used more frequent-
ly than other methods because tubing can be replaced more
easily than casing, it provides an additional level of
protection to resources outside the casing, and it provides
an additional opportunity for monitoring through the tubing/
casing annulus (Warner and Lehr, 1977). Design criteria
for tubing and packer systems reflects both the physical
requirements of the equipment (capacity, axial loading,
external pressure, internal pressure, joint stress, and
vertical pressure differential), and also the corrosion
resistant properties of the materials.
Tubing Selection, Handling, and Installation
Tubing-size selection is based on a series of technical
and economic decisions which ultimately affect the casing
diameter and drilling program of the entire well system.
The primary technical consideration in this selection
is the volume of injection fluid and its rate of injection.
These considerations determine the velocity of flow and
consequently,- the amount of pressure dissipated through
the tubing (friction pressure). The friction pressure loss
for 100 feet (30.5 m) of tubing of various sizes can be
calculated using Figure 5.5. This figure assumes injection
of water at standard temperature and pressure, an "average"
friction factor for the tubing, and laminar flow. Friction
pressure losses for circumstances significantly different
tii an the assumed ones would have to do calculated t rom
£ r i c 11 o n 1 o s s equations given in t e x t s on 11 u i d rn e c h a n i c s .
-------
I poo
900
800
700
200 -
600
TUBING
DRILL PIPE
500
A
- 1 1/4 in.
F - 3 1/2 ia " 13.3 lb.
400
B
- 1 1/2 in.
CASING
C
- 2 3/8 in.
G -4 1/2ia - 11.6 lb.
300
D
- 2 7/8 in.
H "5 1/2 in." 17.0 lb.
E
- 3 1/2 in.
1-7 in. -23.0 1b.
3 4 5 6 7 8 10 20 30 40
FLOW RATE-BARRELS PER MINUTE
60 SO 100
Figure 5.5. Friction pressure loss of common tubing
and casing for fluid viscosity of one
centipoise (Warner and Lehr, 1977)
117
-------
Materials used for tubing include steel, reinforced
plastics, fiberglass, and stainless steel. Sprayed-on
plastic linings are also used, provided a satisfactory
seal can be made at the tubing couplings. Plastic tubing,
particularly glass-reinforced, is used in shallow wells
since plastic tubing in tension has a low resistance
to collapse and bursting. Bimetallic tubing has a thin-gage
liner of resistant metal swedged to the base-metal wall and
has been used successfully in some wells. The liner is
folded over the end of the pipe and welded in position. As
with plastic-lined steel pipe, couplings utilizing a liquid-
tight gasket seal are used to prevent contact between
the injection fluid and the unprotected steel of the cou-
pling threads (Warner and Lehr, 1977). Final selection
depends largely on the nature of the injection fluid and the
physical requirements of the injection well.
Tubing should be inspected before it is run to identify
such problems as mill defects, poorly machined threads, or
shipping and handling damage to the pipe body, coupling or
threads. Hydrostatic pressure tests of tubing and connec-
tions may be performed as the tubing is run in the hole. A
successful pressure test is not conclusive proof of a lack
of mill defects, since these may show up only after a number
of cycles of pressure or temperature change.
Tubular goods can be damaged easily during handling,
especially in particular grades. Approved practices for
running tubing are recommended Dy the American Petroleum
Institute (1980). These recommendations cover all aspects
of tubing handling including hoisting the tubing, thread
preparation, stabbing, joint make-up, and lowering.
In general, tubing failure can occur from improper
selection, improper handling, as well as improper installa-
tion. Damage may result in failure of the well system and
contamination of underground sources of drinking water.
Packer Selection and Installation
Packers are mechanical devices used t o provi de a
seal between the tubing and the casing or the tubing and the
open nole. Packers can be used to separate multiple in-
jection zones, to protect casing from injection pressure and
riuias, to isolate a given injection zone, to isolate casing
leaks, or to facilitate subsurface safety control.
1 1 6
-------
The two basic classes of packers are retrievable
and permanent or drillable. Most packer assemblies are
made up of several elements including the sealing element,
slips, valves, friction blocks or drag springs, and safety
joints.
In conventional packers, the sealing element is a
hollow rubber cylinder or sleeve which when compressed
causes the rubber to expand, contacting and pressing
against the casing. Sufficient force will cause the sealing
element to close the annulus between the tubing and the
casing. Slips are used to support the packer inside the
casing and to prohibit its movement. Some packers have two
sets of slips, which work in opposite directions, prohib-
iting movement regardless of applied weight or differential
pressure (Petroleum Extension Service, 1980).
In selecting a packer for an injection well, the
following factors are considered: retrievability, re-
liability, differential pressure and temperature (i.e.,
formation or injection fluid conditions), corrosiveness of
the injection fluid, well depth or bottom-hole completion,
the overall objectives of the operation, and the tubing
program and wellhead equipment. Each of the general packer
types has site-specific applications. In extreme environ-
ments, those with high temperatures or with highly corrosive
fluids, specialty packers are available from the manu-
facturers .
There are a variety of
injection wells and other
A number of these packers
discussed below.
packers currently used for
well completion purposes,
and their applications are
Weight-set packers are intended to hold against down-
ward forces of tubing and formation pressure only and are
suited for shallow, low-pressure applications where differ-
ential pressure from below is unlikely. A typical weight-
set packer is shown in Figure 5.6. The weight of the tubing
is used to expand the seal element and hold the packer.
When employed in injection-well applications, the upward
pressure exerted on the packer seal from the injection fluid
must not exceed the combined forces of the weight of the
tubing and annular pressure. Annular pressure can be
increased or hydraulic hold-downs can be employed if a
pressure differential exists.
119
-------
Figure 5.6. Weight-set packer (Allen and Roberts,
1978)
-------
Tension-set packers are similar in design to weight-set
packers run upside down. The packer is set by putting
tension on the injection tubing. This type of packer is
well suited for injection-well use since the injection
pressure adds to the tubing tension and maintains the seal.
Tension-set packers are sometimes used in shallow applica-
tions where the weight of the tubing is not sufficient to
use a weight-set packer.
Rotation-set packers or mechanical-set packers are set
and released by rotating the tubing. A schematic diagram of
a rotation-set production packer is presented in Figure 5.7.
This packer works independently of pressure or tubing
force in either direction (Petroleum Extention Service,
1977c).
Conventional hydraulic-set packers use fluid pressure
to drive a piston cylinder to activate the seal mechanism.
The hydraulic pressure is applied through the injection
tubing after the tubing is set in the packer. Hydraulic
packers are more expensive than the other varieties and are
best suited to complex multiple zone completions or applica-
tions in which nigh setting forces are required.
Inflatable or balloon packers can be used to develop a
seal in either an open hole or a cased well. Inflatable
packers are often used in wells with partially collapsed
casing or in specialty injection operations where high
pressure differentials are not experienced (Warner and Lehr,
1977). They are useful as formation packers or as external
casing packers.
Permanent or drillable packers can be set by wireline,
mechanical, or hydraulic means and generally will hold
greater pressure differentials than most retrievable
packers. As the name suggests, the packer must be broken up
or drilled out because standard retrieval is not possible.
Regardless of the type of packer used or the method
used of setting it, verification of seating must be made.
In most packer types, the packer can be considered seated
if it will support the weight of the tubing. In the case
of tension-set packers, seating is indicated if the tension
on the setting line or string of tubing is greater than
that required to lift the tools in the hole (Petroleum
Extension Service, 1980).
121
-------
Upper seal -
Sealing -
element
Slips-
Upper - M
split nut pcn
Lower -m
split nut
"o
Screw
thread
¦ Inner
mandrel
I
Figure 5.7. Rotation-set packer (Allen and
Roberts, 1978)
-------
Once the packer is seated properly, the installation
can be tested for leakage. Most packer installations
are tested for leakage initially by applying pressure to
the tubing and watching for a pressure decline which
may indicate a leak in the packer. If the packer has not
been set to hold pressure, fluid may flow up the annulus.
Monitoring pressure in the casing annulus will determine
pressure leaks around the packer (Petroleum Extension
Service, 1980).
Special Considerations/Hazards
In high temperature and pressure environments, or in
situations where injection fluid temperatures vary, tubing
expansion and contraction can unseat the packer or lead to
leakage at the packer tubing interface. To lessen the
negative impacts of tubing expansion or contraction, temper-
ature or pressure differentials must be minimized or
special hardware must be employed. The use of specially
weighted annular fluids and surface adjustment of injection
fluid temperatures can help minimize problems. In cases
where these procedures are impractical or insufficient to
fully mitigate problems, use of expansion receptacles is
warranted.
Expansion receptacles are used to allow tubing to move
freely during expansion and contraction while maintaining a
tight seal in a fully seated packer. This is particularly
important in deep wells in situations where large changes in
temperatures are likely. These tubing/packer connections
can eliminate the high tensile or compression stress exerted
on tubing where statically attached to the packer (Petroleum
Extension Service, 1977, 1971; Allen and Roberts, 1978).
High temperature environments can directly affect
packer seals and the operation of release mechanisms.
Conventional packer sealing elements, such as Hycar rubber,
are generally functional up to 300°F to 350°F (148.7°C to
176.5°C). For higher temperature applications, special
sealing elements and specialty packers are used. For
example, double sealing elements, metal back ups, and
advanced materials (e.g. Teflon) are used to handle in-
creased temperature, pressure and corrosiveness (Allen and
Roberts, 1978). These are readily available from the
manufacturers.
123
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High-performance packer seals are designed to resist
corrosion and high differential pressures. Harder rubber
and narrower seal clearances are used for high-pressure
operations. Exposure to chemical changes, and differen-
tial pressures can cause changes in rubber characteristics
and resiliency, and can dissolve the seal in some cases.
Annular Fluids
Annular or packer fluids are used to eliminate down-
hole pressure differentials and to inhibit corrosion.
Packer fluids provide hydrostatic head by exerting pressure
across the packer seal. This pressure can be adjusted
by varying the density of fluids to eliminate large pressure
differentials above and below the packer. In deep wells
where potentially high temperatures are encountered, packer
fluids can be selected that remain stable and do not convert
to corrosive chemicals or contain them. (This is partic-
ularly important in deep wells since the high tensile
strength steel used tends to be more vulnerable to corrosion
than ordinary steel.)
The basic categories of packer fluids are suspended
solids-free liquids, water-based muds, and oil-based muds.
Solids-free liquids include oil-based and water-based
solutions and allow the addition of corrosion inhibitors
where appropriate. Oil or diesel fuel are examples of
solids-free packer fluid. Oil-based fluids are less dense
than aqueous fluids resulting in a lower hydrostatic head,
limiting their application in high pressure wells. Clear
water-based or aqueous-chemical solutions can be used
where higher densities are required. Salts can be added to
adjust densities from 8.4 lD/gallon (1 kg/1) freshwater up
to 16 lb/gallon (1.9 kg/1) for a high density calcium
chloride/zinc solution. Some salt solutions can be cor-
rosive and can require inhibitors (e.g. sodium chromate) for
use with freshwater-based fluids.
Water-based packer fluids can be used in certain
injection wells; however, in high temperature wells aging
accelerates, the pH drops, and the solids settle. As a
result, the corrosion protection quality of the fluid is
diminished and the settled solids may inhibit workovers.
Oil-based packer fluids, such as emulsions or muds,
can be used over a wide density range [7.8 to 22.0 lb/gallon
1 24
-------
(0.93 to 2.6 kg/1)], and are considered noncorrosive.
Gelling agents are available to prevent solids from settling
and causing workover problems. Additives with oil can be
used to wet the casing and to inhibit corrosion (Petroleum
Extension Service, 1980).
In each of these categories, fluid selection is a
function of the cost, density, and corrosiveness. Also, the
temperature ranges encountered will impact the selection of
packer fluids. The relative advantages and limitations of
packer fluids are outlined by the Petroleum Extension
Service (1980).
5.2.2 Tubing with Open Annulus Completion
This special type of completion has been used in
applications with highly corrosive injection fluids such as
steel pickling liquors (Donaldson, et al., 1974; Bayazeed
and Donaldson, 1973). A packer is not used at the bottom of
the injection tubing as a conventional seal for the annulus;
instead, electrodes can be installed at the annular fluid/
injection fluid interface to detect any movement of in-
jection fluid into the annulus (Donaldson, 1978) (Figure
5.8) .
To eliminate migration into the annulus, a hydraulic
seal is established by injecting noncorrosive fluid into it
or by floating a noncorrosive fluid of different density in
it. In one case in which pickling liquor was injected,
water was pumped continuously into the annulus at a pressure
slightly greater than the injection pressure, allowing a
constant flow of water through the annular space. The
conductivity of the water at the bottom of the tubing
was monitored to detect accidental entry of acid (Donaldson,
1978). Fiberglass or compatible metal alloy injection
tubing is used for its resistance to low pH injection
fluid. The injection tubing, as shown in Figure 5.8, is
extended below the casing shoe into the open-hole config-
uration, never exposing corrosive injection fluid to the
well casing at any point.
Another variation of the hydraulic seal is illustrated
by Barlow (1972) in Figure 5.1. In this application,
an interface is established between a hydrocarbon fluid
in the annulus and an aqueous injection fluid. Special
125
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Monitoring fluid
16 in. steel
pipe
10 3/4 in. steel pipe
Cement
Waste pickle liquor inlet
Ground elevation
Glacial drift
7in. steel pipe
4 1/2 in fibercast tubing
7 in. alloy pipe
Disposal zone
Bottom of well
Total depth 4,291 ft.
Figure 5.8. Principles of open-annulus completion
(Donaldson, >:*t al., Iy74)
-------
fiberglass-reinforced, plastic casing is used in the
bottom of the hole in the interface zone. Acid-proof
cement is also used in the lower part of the casing string.
5.2.3 Tubingless Completion
In a tubingless completion, fluids are injected di-
rectly through permanently installed injection casing.
This method can be used with any of the bottom-hole con-
figuration practices described. A principle disadvantage
of this method is that permanent casing material is exposed
directly to the injection fluid. Although plastic coatings
or liners can be used, the competence cannot be guaranteed
and they increase the cost of the well significantly (Don-
aldson, 1978).
Tubingless completion is used in applications where
low pressures are encountered, such as uranium leaching,
oil-shale, and modified in-situ retorts. Also, tubingless
completion has been used in injection well operations where
the lifespan is very limited or where the injection fluid
is noncorrosive.
Periodic pressure tests of the well or other mechan-
ical integrity tests may be run to determine if leakage
is occurring. Since no tubing/casing annulus exists,
there is no possibility of an ongoing leakage check as
there is with annular pressure monitoring.
5.3 WELLHEAD EQUIPMENT
The wellhead is the link between the injection-fluid
feed system and downhole equipment. The wellhead may
consist of as little as a master valve on the tubing.
Figure 5.9 illustrates a simple wellhead system with basic
meters, filters, and valves.
5.3.1 Wellhead Design and Installation
Wellhead equipment is located at the surface and
is designed to support and to seal casing or tubing and to
1 27
-------
Figure 5.9. Simplified wellhead assembly showing
meters and valves (API, 1.978)
-------
permit controlled flow to or from the well. Installation of
wellhead equipment is done during the drilling and comple-
tion processes.
The wellhead is attached to the surface casing to
establish a foundation for blowout control equipment.
If intermediate casing is run, the top length of the string,
supported in a casing hanger, is set in and hung from
a casing flange. Each successive string of casing and
tubing is supported and sealed within another spool added to
the wellhead stack. The complete wellhead arrangement,
therefore, consists of a flange and a series of spools, each
supporting an individual string of casing (Figure 5.10).
5.3.2 Metering/Monitoring Requirements
The wellhead assembly has the capability of flow
metering and injection-pressure monitoring. In addition, an
annular pressure metering point is generally built into the
wellhead assembly.
Wellhead meters are available in a variety of types.
The orifice meter is most useful where large volumes of
fluid are injected. In a controlled fluid injection proj-
ect, positive displacement meters (such as rotating disc,
vane, and turbine type) can be used.
Records of key injection-we11 parameters, total
volume, injection rate, injection pressure, pretreatment
measures (additives), and annular pressure, are generally
kept to analyze the performance of the system and detect
mechanical failures. Problems with an injection well can be
indicated by gradual trends on pressure/rate charts or by
sudden increases or decreases in annular or injection
pressures. A sudden change in annular pressure may indicate
a tubing or packer leak or it could be a result of a casing
failure, allowing fluid entry from a natural or charged
fluid zone. An increase in wellhead pressure or a decrease
in injection fluid volume could be the result of formation
plugging, tubing and packer restriction, increases in the
formation pressure, or breakthrough to a neighboring well
or into another formation (American Petroleum Institute,
1978).
129
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•TUBING HANGER
•TUBING HEAD
TUSING
CASING HANGER
CASING HEAO
INNER CASING
INTERMEDIATE CASING
SEALING MEDIUM
CASING HANGER
CA'jING HfcAO
OUTER CASING
Figure 5.10. Details of typical wellhead assembly
(AP1, 19 81)
-------
Metering and pressure recording devices require peri-
odic maintenance and monitoring or erroneous data could be
obtained. Strainers, screens, and filters require regular
flushing to prevent clogging with solids. Also, orifice
meters need routine checking with a dead weight tester to
assure accurate readings (American Petroleum Institute,
1978).
5.3.3 Flow Regulation Equipment
In addition to varying the injection rate, flow regula-
tion is accomplished by the use of special shut-off or check
valves and by the use of flow control chokes. Automatic
shutoff valves are used at the wellhead to close automat-
ically in response to pressure changes. The automatic
shut-off mechanism is composed of the valve body, the
actuator (closing mechanism), and the pilot (sensing assem-
bly). The function of this mechanism is to protect both the
downhole equipment and the ground-water system. When a
pressure change occurs, indicating a leak, the shut-off
valve arrests the flow. Check valves can be designed to
close gradually to avoid destructive hydraulic phenomena
like water hammer effects.
5.4 INJECTION FLUID HANDLING AND SURFACE EQUIPMENT
In some instances, pretreatment and filtration, surge
protection, and pumping of the injection fluid may be
required. Surface equipment may also be required in provid-
ing a constant flow of corrosion resistant water to the
annulus.
5.4.1 Pretreatment
Injection fluid pretreatment is done to limit corros-
iveness, to limit the levels of suspended solids, and to
assure compatibility with formation fluids as well as with
the formation. Two surface configurations are used in
pretreatment and injection fluid handling, open and closed.
An open system (Figure 5.11) can be used with fluids that
131
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Waste
0.
Liquid level meter
Weir N\
\ \ I
V X:
^Valve controller
D" Pressure recorders
—k———
Z Collecting sump
x Flow control
valve
-
' 1
0j| fank
— Well annulus
— Injection tubing
Injection well
Figure? 5.11. Open injection-fluid treatment system (Donaldson, 1978)
-------
are free of suspended solids and that will not be chemically
altered by contact with oxygen. In this example, the fluid
is injected with gravity feed and is controlled by a meter-
ing valve.
More reactive injection fluids are pumped through a
closed injection system (Figure 5.12). Pumps are used
to generate sufficient pressure to maintain an acceptable
flow rate. Filtering and pH adjustment limits corrosion and
plugging. A surge tank is employed to assure consistent
delivery of fluid and to eliminate shocks to the system that
could result in pressure surges or water-hammer effects.
Highly complex systems, as pictured in Figure 5.13, are the
result of further pretreatment needs (Donaldson, 1978).
Effective filtration can be particularly important when
injecting into noncavernous formations. Injecting into
strata possessing interstitial permeability may require
removal of particulate matter larger than 3 microns.
5.4.2 Pumping Equipment
Pumps are used for fluid injection if gravity flow
into the well is not adequate to provide the desired flow
rate. Positive displacement, plunger-type positive dis-
placement, centrifugal, and piston-type pumps are in use.
Centrifugal pumps include single stage and multi-stage
horizontal and vertical pumps and are well suited for
lower-pressure service [i.e., less than 300 psi (2.1 x 10^
N/m^)]. Turbine and single-stage centrifugal pumps capable
of high-pressure operation are also available. Centrifugal
pumps generally have heavy casing walls which are important
for the injection of corrosive fluids. Also, centrifugal
pumps with limited pressure ratings are less apt to over-
pressure a formation.
The type of pump and drive best suited for an injec-
tion project is determined during system design by evalu-
ating the expected operating volume and pressure. Economic
factors such as fuel availability, initial cost, maintenance
cost, operation cost, and parts availability are also
considerations. Pumps that are fitted for salt-water
service or injection of other corrosive fluids may have
to be designed using special materials (metallic materials
133
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pH Control
Sump
Figure 5.12. Closed injection-fluid treatment system (Donaldson, 1978)
-------
Figure 5.13. Schematic drawing of complex injection-fluid treatment system
(Donaldson, 1978)
-------
like stainless steel, aluminum, bronze, cast iron, or
non-metallic materials, like ceramics), for all parts that
contact the injection fluid.
The pump drive can be equipped for automatic shutdown
in the event of abnormal operating conditions that include
high pump discharge pressure, low pump discharge pressure,
low fluid level in the suction tank, or excessive pump
vibration. It is important that automatic shutoff mechan-
isms operate in an incremental mode so that surges are
avoided.
1 j 6
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REFERENCES
Allen, T. 0., and A. P. Roberts, 1978. Production opera-
tions, Volume 1. Oil and Gas Consultants, Inc., Tulsa,
Oklahoma.
American Petroleum Institute (API), 1978. Subsurface salt
water injection and disposal. Vocational Training
Services Book 3.
American Petroleum Institute (API), 1980. Recommended
practice for care and use of casing and tubing.
Spec. RP5C1, 11th edition, Dallas, Texas.
American Petroleum Institute (API), 1981. API specification
for wellhead equipment. Spec. 6A, 13th Edition, Dallas,
Texas.
Earlow, A. C. , 1972. Waste disposal well design, _in Under-
ground waste management environmental implications.
American Association of Petroleum Geologists, Memoir
18, Tulsa, Oklahoma.
Bayazeed, A. F., and E. C. Donaldson, 1973. Subsurface
disposal of pickle liquor. Bureau of Mines, RI 7804.
Donaldson, E. C., 1978. Subsurface disposal of oilfield
brines and petro-chemical wastes, Volume I. U. S.
DOE, Environmental Control Symposium.
Donaldson, E. C., R. D. Thomas, and K. H. Johnson, 1974.
Subsurface waste injection in the United States,
fifteen case histories. Bureau of Mines, IC 8636.
Gidley, J. L., 1978. Stimulation of sandstone formations
with the acid-mutual solvent method, jji Well com-
pletions, Volume II. Society of Petroleum Engineers
Reprint, Series No. 5a.
Hubbert, M. K., and D. G. Willis, 1970. Mechanics of
hydraulic fracturing in well completions. Society of
Petroleum Engineers Reprint, Series No. 5.
137
-------
Johnson Division, UOP, Inc., 1975. Ground-water and wells.
Edward E. Johnson, Inc., St. Paul, Minnesota.
Krueger, R. F., 1978. Advances in well completion and
stimulation during JPT's first quarter century,
Society of Petroleum Engineers, Well completions,
Volume 1. Reprint, Series No. 5a.
National Water Well Association (NWWA), n.d. Well drilling
operation.
Petroleum Extension Service, 1971. Well completion, i_n
Lessons in well servicing and workover. The University
of Texas at Austin.
Petroleum Extension Service, 1977a. Well completions.
Drilling technology series, 1257. University of
Texas at Austin.
Petroleum Extension Service, 1977b. Acidizing, what's
it all about. Production technology series, 1265.
The University of Texas at Austin.
Petroleum Extension Service, 1977c. Retrievable production
packers. Production Technology Series, 1255. Uni-
versity of Texas at Austin.
Petroleum Extension Service, 1980. Well servicing and
repair, i_n Lessons in well servicing and workover.
University of Texas at Austin.
Petroleum Extension Service, 1981. Testing and completing,
in Lessons in well servicing and workover. University
of Texas at Austin.
Warner, D. L., and J. H. Lehr, 1977. An introduction
to the technology of subusurface wastewater injection.
U. S. Environmental Protection Agency, EPA-600/2-
77-240.
Williams B. B., and D. E. Nierode, 1978. Design of acid
fracturing treatments in well completions, Volume II.
Society of Petroleum Engineers, Reprint Ser ies No, 5a.
Williams B. B. and M. E. White ley, 1 9 78. Hydrof1uoric
acid reaction with a porous sandstone, in Well com-
pletions, Volume 2. Society of Petroleum Engineers,
Reprint Series No. 5a.
1 j 8
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6. CORROSION AND CORROSION CONTROL
The effects of corrosion on injection-well systems
require serious attention during design and construction.
Corrosion can cause deterioration and eventual destruction
of injection-well components, such as tubing and casing,
resulting in the leakage of injection fluids into an under-
ground source of drinking water or other resources. In
addition, corrosion products may plug the injection well or
the formation into which fluids are being injected.
Technically, corrosion refers to the destruction by
reduction of a base-metal material to a more stable com-
ponent, such as an oxide or a sulfide, by a chemical or
electrochemical reaction with its environment. Certain
metals, such as magnesium, zinc, aluminum, and iron, are
more reactive than others, and hence corrode more readily.
The term corrosion is also used to describe other forms
of degradation of materials. A common example of this
phenomena is the dissolution of plastic materials by organic
solvents. Although not electrochemical in nature, this form
of corrosion results in deterioration and loss of material
due to chemical attack.
In injection-well systems, corrosion involves both
the internal corrosion of tubing, casing, and wellhead
equipment from electrochemical reaction of the metals with
the injection fluids, and the external corrosion of casing
from contact with the soil or the water in which the well is
placed. For electrochemical corrosion to occur, it is
necessary for conditions to be established which develop an
electrolytic cell composed of an anode, a cathode, an
electrolyte, and an external connection. Typically, cor-
rosion-control practices are intended to remove one or more
of these conditions.
The anode and the cathode normally exist at two dif-
ferent places on the metal surface. The anode is the
area where the oxidation of metal or corrosion occurs,
and the cathode, is the area where reduction of metal (plat-
ing-out) takes place. For example, in the corrosion of
steel, iron is oxidized to the ferrous ion at the anode and
the ion goes into solution:
139
-------
Pe°—* Fe++ + 2e~
(6-1)
Electrons liberated at the anode by oxidation flow through
the metal to the cathode area. At the cathode, the hydro-
gen ion in the adjacent aqueous solution picks up the
two electrons from the metal to form hydrogen gas which
bubbles off:
2H+ + 2e~—* H2 (gas) (6-2)
These two electrode reactions result in a difference in
electric potential between the anode (positive potential)
and the cathode (negative potential).
An electrolyte is needed to provide the medium for
current flow between the anode and the cathode. Water
and its dissolved mineral salts serves this purpose.
In solution, dissolved salts separate into two types of
ions, anions (negatively charged) and cations (positively
charged). These ions are responsible for the ability of
water to permit corrosion currents to flow, with anions
moving to the anode and cations moving to the cathode.
The rate of corrosion is influenced by a variety of
factors, including the characteristics of the metal, the
substances in and conductivity of the electrolyte, the
deposition of corrosion products, the polarization of the
electrodes, the temperature of the corrosion environment,
and the presence of mechanical action such as velocity of
water movement over the metal. More detailed discussions of
corrosion theory can be found in books by Evans (1960),
Uhlig (1962), and Weber (1972).
6.1 TYPES OF CORROSION
There are many types
in injection-well systems,
corrosion which occur from
substances in water. The
corrosion can be explained
trochemical reactions invol
ros ion enco u n t e red in i n j
1 4 ii
of corrosion which can occur
The majority are electrolytic
exposure to various dissolved
various types of electrolytic
by referring to the basic elec-
ved . The ot her types of cer-
ection - w e 1 1 systems pr imarl1y
-------
consist of the deterioration of non-metals, such as plastic
injection tubing, caused by organic solvents in injection
fluids.
6.1.1 Oxygen Corrosion
Oxygen dissolved in water causes rapid corrosion
of metal (Allen and Roberts, 1978). The effect of dis-
solved oxygen is realized at the anodic area of the metal
where the insoluble metallic hydroxide (rust) is precip-
itated. The oxygen corrosion reaction for iron in the
absence of other influencing constituents proceeds as
follows (Ostroff, 1965):
Fe + 2H+—* Fe++ + 2H° (6-3)
2H° + 1/202 *¦ h2°
2Fe++ + 1/202 + H2° —5k 2Fe+++ + 20H"
The corrosion rate is limited by the rate at which
oxygen is delivered to the anodic area. In a closed injec-
tion system (out of contact with air), the reaction will
continue only until the dissolved oxygen in the injection
fluid is consumed (Warner and Lehr, 1977). In open systems,
where air can enter the injection fluid, corrosion continues
as the oxygen supply is replenished. In general, with
increasing dissolved oxygen levels the corrosion rate
progresses until a point is reached at which the flow of
oxygen becomes limited by the barrier of metallic hydroxide
developed on the anodic surface.
Oxygen corrosion is enhanced by the presence of dis-
solved cnloride and sulfate salts. Generally, corrosive-
ness increases with increasing salt concentration until
a maximum is reached after which corrosiveness decreases.
The initial increase is due to the electrolyte conduc-
tivity increase, and the subsequent decrease results from
the decreased solubility of oxygen (Uhlig, 1962).
141
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Carbonate minerals inhibit oxygen corrosion, acting
to counter the acceleration effect of salts in water
containing dissolved oxygen. The degree of inhibition
is dependent on the relative concentrations of carbonate
alkalinity and the chloride and sulfate salts. When calcium
is associated with the carbonates, there is further capacity
for protective action (AWWA, 1971).
The rate of corrosion due to dissolved oxygen generally
increases with increasing temperature. Basically, higher
temperatures cause more rapid chemical-reaction rates.
However, when the temperature becomes high enough to de-
crease oxygen solubility, the corrosion rate can be ex-
pected to decrease in open systems. In a closed system,
the oxygen cannot escape and the corrosion rate continues
to increase with increasing temperature (Ostroff, 1965).
The velocity of the injection fluid can also affect
the rate of corrosion. As the velocity increases, the
replenishment of oxygen to the metal surface becomes higher
and consequently the corrosion rate increases. Also,
further increases in velocity of the injection fluid can
cause mechanical scouring of corrosion products, thus
removing any protective film that might help reduce the
corrosion rate.
Injection-fluid pH also affects the rate of corrosion
of solutions containing oxygen. For iron, the corrosiveness
of a fluid generally increases as pH decreases. In the
pH range of 4 to 9.5, the iron surface is coated by cor-
rosion reaction products, and corrosion progresses as oxygen
diffuses through this layer. Below a pH of 4, the corrosion
products dissolve and consequently, more rapid corrosion
ensues (Ostroff, 1965).
Oxygen corrosion pits the metal surface at an even
depth. The pit develops at a localized anodic point and
continues by virtue of a large cathodic area surrounding the
anode (AWWA, 1971). Pits may be sharp and deep or shallow
and broad. Additionally, a corrosion product may form over
these pitted areas. In down-hole oxygen corrosion, distinct
lumps called tubercules of oxygen corrosion product may
occur. These are caused by aggregation of iron bacteria and
mixed carbonates and hydrated metal oxides.
A special type of oxygen corrosion is caused by dif-
ferential aeration cells, a result of differences in oxygen
142
-------
concentration between two parts of the system. Differences
in dissolved oxygen concentrations cause differences in the
solution potential of the same metal. In differential
aeration cells, corrosion occurs at the area of the metal
where oxygen concentrations are low. An adjacent area of
relatively higher oxygen concentration serves as the cathode
in the reaction.
Corrosion products, chemical precipitates, or other
debris on a metal surface hinder oxygen diffusion by cover-
ing the metal at local areas. These circumstances can
result in the development of oxygen concentration cells
with corrosion taking place under the deposit.
The growth of microorganisms in injection wells can
also result in the formation of localized oxygen concentra-
tion cells by effectively shielding parts of the metal
surface from oxygen (Ostroff, 1965). Corrosion can there-
fore occur under areas of tubing or casing covered by
slimes or masses of bacterial growth.
6.1.2 Carbon-Dioxide Corrosion
Carbon dioxide dissolved in water can contribute
to the corrosion of steel, but for equal concentrations it
is much less corrosive than oxygen (Ostroff, 1965). Carbon-
dioxide corrosion of well components is of particular
concern in enhanced-oil-recovery operations involving
carbon-dioxide miscible injection systems. In these flood-
ing operations, carbon dioxide is injected before, after,
or alternating with water.
When dissolved in water, carbon dioxide forms carbonic
acid:
CO2 + H2O H2CO3 (Carbonic Acid) (6-4)
This carbonic acid causes a reduction in pH of the water
which makes it quite corrosive to steel (API, 1958):
Fe° + H2CO3—* H2 + FeCC>3 (Iron Carbonate
Corrosion Product) (6-5)
143
-------
The acidity of the solution, and therefore the cor-
rosion rate, is influenced by the partial pressure of carbon
dioxide. At higher pressures, more carbon dioxide will
dissolve in water creating a stronger acid. If the partial
pressure values are above 30 psi (2.1 x 10^ N/m^") , the
well stream is probably corrosive; 7 to 30 psi (4.8 x
104 to 2.1 x 10^ N/m^) may be corrosive, and 0 to 7 psi
(0 to 4.8 x 104 N/m^) is noncorrosive (API, 1958). In
carbon-dioxide miscible injection, pressures rarely fall
below 1200 psi (8.3 x 10^ N/m^) (Allen and Roberts, 1978).
The rate and amount of corrosion caused by dissolved
carbon dioxide is also dependent upon the oxygen content,
the salts dissolved in the water, the temperature, and
the fluid velocities. Water that contains both dissolved
oxygen and carbon dioxide is more corrosive to steel than
water which contains only an equal concentration of one of
these gases (Ostroff, 1965). In waters containing magnesium
and calcium bicarbonates, increases in temperature can cause
the evolution of carbon dioxide and result in increased
corrosion. At the same time, carbonates of these salts can
precipitate out on the metal surface, resulting in the
formation of a protective coating, which may reduce cor-
rosion rates. As with other types of corrosion, higher than
normal fluid velocities can cause erosion of corrosion
products that normally stifle the corrosion reaction,
allowing corrosion to continue unabated.
Carbon-dioxide corrosion may appear as a uniformly
thinned metal surface or as sharp, well-defined pits.
Surfaces constantly bathed in a dissolved carbon-dioxide
solution will tend to exhibit uniform thinning, whereas
pitting is caused by carbon dioxide dissolved in droplets of
water condensed on the injection-tubing wall (API, 1958).
6.1.3 Hydrogen-Sulfide Corrosion
Hydrogen sulfide gas dissolved in water, even in
small amounts, can create a very corrosive environment
(Allen and Roberts, 1978). Dissolved hydrogen sulfide forms
a weak acid and in the absence of oxygen will attack iron
and non-acid resistant alloys (Warner and Lehr, 1977);
moreover, it becomes severely corrosive to acid-resistant
alloys when oxygen is present. Hydrogen sulfide is often
present in oil-field production brines that are subsequently
1 A 4
-------
disposed by well injection. This practice has resulted in
instances of severe corrosion in injection tubing, espec-
ially when the brines become contaminated with oxygen during
surface handling (API, 1958). The general mechanism of this
type of corrosion as it affects iron and steel is stated
as follows (API, 1958):
Fe° + H2S —* FeSx (Iron Sulfides) + H2 (6-6)
Other metals react in essentially the same manner to produce
metallic sulfides. The corrosion rate in water containing
hydrogen sulfide is also influenced by the presence of
dissolved salts and dissolved carbon dioxide (Ostroff,
1965); when these substances are present, hydrogen sulfide
corrosion rates increase.
Hydrogen-sulfide corrosion of steel or iron results
in the deposition of black scale (iron sulfide) on the
metal surface. The scale tends to cause a local acceler-
ation of corrosion because steel is anodic to the iron
sulfide (Allen and Roberts, 1978). This reaction results in
deep pits with underlying deep cracks in the metal. Crack-
ing is due to embrittlement caused by atomic hydrogen formed
in the corrosion process. Hydrogen diffuses into the steel
where it reacts with itself to form molecular hydrogen.
These larger molecules are trapped and cause the steel to
split, blister, or crack. This damage may lead to stress
fatigue of the material.
Microorganisms can contribute to corrosion caused
by hydrogen sulfide attack. Sulfate-reducing bacteria
are most important from a corrosion standpoint. Corrosion
induced by such bacteria may be found in the internal
portions of injection wells (such as in the casing/tubing
annulus), as well as on the outside of injection casing.
Sulfate-reducing bacteria are anaerobic bacteria
and grow under scale, debris, or other bacterial masses
where oxygen cannot penetrate (Baumgartner, 1962). These
bacteria reduce sulfate ions in water to hydrogen sulfide by
using cathodic hydrogen. As the bacteria obtain hydrogen
from the cathode (e.g., the metal surface of the casing) to
support the reaction, the rate of corrosion is increased and
ferrous sulfide corrosion products are created. The overall
reaction takes the form (Ehrlich, 1972):
145
-------
4Fe° + H2SO4 + 2H2O—^FeS + 3Fe(OH)2 (6-7)
6.1.4 Acid/Alkaline Corrosion
Direct contact between acids and injection-we 11
tubing can cause many metal materials to dissolve. In
fact, acidic wastes are often the cause of corrosion
failure in injection systems (Warner and Lehr, 1977).
The acid reacts with the metal causing ions to go into
solution. A difference in electric potential is set up
between two different areas on the metal. The rate of
corrosion is a function of the strength of the acid and the
metal involved. For example, copper has much less tendency
to dissolve than iron or zinc (API, 1958). Stainless steel
tubing provides corrosion resistance to some acids. Rubber
and plastic-lined tubing are also suitable for resisting
acid corrosion.
Highly alkaline solutions may also be corrosive.
For example, at extremely high concentrations of sodium
hydroxide, iron corrodes forming soluble sodium ferrite,
NaFe02 (Ostroff, 1965). Carbon or stainless steel is
preferred for tubing injecting highly alkaline fluids.
6.1.5 Galvanic Corrosion
Galvanic corrosion occurs where two different metals
or alloys come into contact in the same environment.
For example, using a stainless steel or K-Monel packer with
a steel tubing may result in the corrosion of the tubing.
This type of corrosion is distinguished from electrolytic
corrosion in that the corrosion is a result of the dif-
ference in electrical potential between two dissimilar
metals instead of two different areas on the surface of the
same metal. Almost all metals have different solution
potentials, so that when the two metals come together, the
difference in potential results in current flow in the
presence of an electrolyte.
The galvanic series for metals and alloys in sea
water is shown in Table 6.1. Coupling an active metal (e.g.
zinc) with a less active metal (e.g., stainless steel) will
cause galvanic corrosion of the more active metal (Ostroff,
1965 ) .
1 4 b
-------
TABLE 6.1
GALVANIC SERIES FOR SELECT METALS IN SEA WATER
(Jellinek, 1958)
Active or Anodic End
Zinc
Alclad 3S
Aluminum
Low steel
Alloy steel
Cast iron
Stainless steels (active)
Type 410
Type 430
Type 30 4
Type 316
Ni-resist
Muntz metal
Yellow brass
Admiralty brass
Aluminum brass
Red brass
Copper
Aluminum bronze
Composition G bronze
90/10 Copper-nickel
70 + 30 Copper-nickel-low iron
70 + 30 Copper-nickel-high iron
Nickel
Inconel
Stainless steels (passive)
Type 410
Type 430
Type 304
Type 316
Monel
Hastelloy C
Noble or Cathodic End
147
-------
The corrosion rate increases when connected metals
are more widely separated in the galvanic series. In
addition, the corrosion rate per unit area of the corroding
metal is almost proportional to the total area of the
noncorroding metal (Allen and Roberts, 1978). Therefore, if
the area of the active metal is very large compared to the
area of the less active metal, corrosion will not be so
severe.
6.1.6 Nonmetallic Corrosion
Nonmetallic materials used in injection wells are
totally immune to corrosion by electrochemical and galvanic
effects. However, plastic and fiberglass-reinforced casing
and tubing and the rubber seal materials in packer mecha-
nisms are susceptible to chemical attack by certain nona-
queous or organic solvents. Deterioration of these materials
occurs by a process called solvation, which is the physical
absorption of an organic solvent by the material. Common
solvents include acetone, methyl ethyl ketone, toluene,
trichloroethylene, turpentine, and xylene. The extent of
chemical attack depends on the temperature and stress in the
surrounding environment.
6.2 DETECTION AND MEASUREMENT OF CORROSION
Tubing and casing materials should be compatible with
the injection operation, the fluid to be injected, and the
environment in which the well is constructed. To determine
the proper materials for construction, it may be desirable
to measure the corrosiveness of the injection fluid in the
laboratory. Despite the consideration the control of
corrosion receives during the well design, there often is a
need to recognize corrosive environments during well con-
struction and to detect and measure corrosion in an oper-
ating injection well.
Before initiating a corrosion-prevention program it
is necessary to determine if corrosion is present, the
cause of corrosion, and the rate and severity of corrosion.
The rate and effects of corrosion should be measured before
and after application of prevention measures to determine
tne effectiveness of a corrosion-prevention program.
14b
-------
Several methods are available for the detection and the
measurement of corrosion in injection wells including:
weight-loss specimens, electrical resistance probes, elec-
trochemical tests, caliper survey logs, electromagnetic logs
of casing thickness, casing potential logs, and ultrasonic/
radioactive logs. This section focuses primarily on the
first three techniques. (More detailed discussion of
logging methods to measure corrosion is provided in Chapter
7.)
6.2.1 Weight-Loss Specimens
The most common of all corrosion rate measurement
tests involves exposing pieces of metal similar to those in
the injection system to the corrosion environment. A
small, metal coupon is exposed to well fluids for a defined
period of time, then is removed, cleaned, and weighed to
determine the amount of metal loss (Allen and Roberts,
1978). Down-hole coupon installation can be made by using
standard wireline equipment. Corrosion rates are usually
measured in mils per year (mpy) penetration or metal loss.
A low corrosion rate may be serious if the pitting type of
corrosion is occuring, whereas a high rate with a general
area type of metal loss may be relatively insignificant.
The visual appearance of the coupon after exposure
may indicate the type and cause of corrosion (Ostroff,
1965). For example, a black sulfide coating shows the
presence of hydrogen sulfide in the system. Ferric oxide
indicates oxygen is present, and carbon dioxide corrosion
can be detected by ferrous carbonate deposits. An example
of how a coupon test can be used to evaluate corrosion rates
of various metals in a salt-water injection well where
hydrogen sulfide containing brines are being disposed is
provided in Table 6.2. It should be noted that the alloy
compositions and the conditions of exposure are not com-
prehensive. Thus, with the exception of a few metals
and alloys of changeless performance, any indicated usage
should be correlated in detail with all related corrosion
data.
At one time, coupons were widely used and considered
to be the best method for estimating internal corrosion,
especially in oil-field production and injection-well
operations. The principle disadvantages of coupons concern
149
-------
TABLE 6.2
CORROSION RATE OF METALS AND ALLOYS FOR
"SOUR" (HYDROGEN SULFIDE CONTAINING)
SALT WATER
(Gulf Oil Corporation, 1948)
Corrosion rate*
Metal or Alloy
(Mils per year)
Nickel
1.0
K Monel
1.1
Nickel plated steel
2.8
Antimonial admiralty
3.2
Type 316 18-8 (Mo)
5.5
Aluminum 6061-T6
6.9
Type 304 18-8
10 .2
Type 347 18-8 (Cb)
10 .8
70-30 Copper Nickel (70%
Cu, 30% Ni)
14.0
Carbon Steel J-55
15.6
Carbon Steel N-80
16.0
Alclad
16.2
Croloy 2-1/4
17.8
Galvanized steel
23.3
Croloy 5
23 .4
9% Nickel
25.4
Copper Steel (0.26 Cu)
25.8
Yoloy (2 Ni, 1 Cu)
25.9
5% Nickel
27.3
12 Chrome cast
28.7
3% Nickel
29 .0
0.40 Carbon cast
29.7
Croloy 9
30 .1
Carbon Steel H-40
32,6
Crology 12
*3 "3 £
Corten (0.48 Ni, 1.04 Cr
, 0.41 Cu)
35.6
Ampco Grade 8 (88 Cu, 10
Al, 1 Fe)
36.0
Cr-Mo-Si steel (2.09 Cr,
0.56 Mo, 1.17 Si)
38.1
Everdur 1010
6 2.2
Copper plated steel
64.6
Red brass alloy 24 (85 O
u, 15 Z n)
67 .1
Copper
107 . 8
* Corrosion rates of insulated coupons 4.5 by 1.5 in. in
SWD line, Darst Creek Field, Texas. 60 days exposure.
Corrosion rates are average of 4 coupons. Salt water
tests: pH-7; HjS-200 mg/1; total solids-26,000 mg/l;
temperature-12 0 F; velocity-2 ft/sec.
1 5 0
-------
the time required to obtain results and that coupons show
corrosion only at the point of their installation (Allen
and Roberts, 1978).
6.2.2 Electrical-Resistance Probes
Electrical-resistance corrosion probes, which are
based on an adaption of the Wheatstone bridge, measure
changes in electrical resistance of a metal specimen as it
corrodes (Ostroff, 1965). Probes are availale in a variety
of sizes, thicknesses, metals, and alloys.
The probe, with its attendant portable instrument box,
is call a Corrosometer. Several probes can be monitored at
convenient time intervals with one instrument; this is
particularly valuable when it is necessary to measure
corrosion rates at different points within the system at the
same time.
The Corrosometer has found its principle applications
in injection systems involving gas streams because the
probe does not have to be submerged in water to function.
A disadvantage of the Corrosometer is that it is usually
limited to the measurement of uniform corrosion. The
Corrosometer can give misleading results if a deposit
forms on a probe (Allen and Roberts, 1978). It also is a
sensitive and delicate instrument not easily repaired, and
it is difficult to operate by the untrained.
6.2.3 Electrochemical Tests
A corrosion-rate meter can be used to measure corrosion
current and corrosion rate because metal loss is directly
proportional to current flowing from the test electrode
(Allen and Roberts, 1978). An instantaneous corrosion-rate
meter has the capacity to detect very low rates of uniform
corrosion and record data for multitest points on a con-
tinuous basis. Some progress has been made in using cor-
rosion-rate meters to predict pitting-type corrosion.
The corrosion-rate meter is particularly useful to
study the changes throughout an injection-well system
caused by the introduction of corrosion inhibitors, air
151
-------
leaks, or other changes. The test probes must be sub-
merged in liquid and positioning must be done with care in a
flowing stream to avoid shadowing one electrode by another
(Allen and Roberts, 1978). The electrodes may experience
short-circuiting resulting from corrosion products or solids
in the injection fluid.
6.2.4 Well-Logging Methods
Caliper surveys, electromagnetic logs, casing potential
logs, and ultrasonic/radioactive-measurement logs are
techniques commonly used for evaluating active corrosion.
Brief descriptions of these methods are provided below.
(More complete discussions can be found in Chapter 7.)
Caliper surveys are run to inspect the internal surface
of tubing or casing. Mechanical feelers contact the inside
metal surface and will physically detect metal loss due
to pitting and metal thinning. Caution should be exercised
when running calipers through coated tubing to prevent
pipe coating damage. In addition, caliper feelers may
remove protective scales and allow corrosion to occur in
the feeler tracks.
Casing-thickness logs can be developed by using an
instrument which relies on an electromagnetic field to
measure the thickness of metal at any point in the casing.
This type of log can be used to calculate external metal
loss when the loss of metal on the inside of the casing
has been measured with an internal caliper.
Current flow in well casing can be measured with
a logging tool with two sets of contactor knives. Polarity
of the voltage reading between the two contacts indicates
at any given point whether current is flowing from the
casing to the earth or from the earth to the casing.
Corrosion is indicated where current is leaving the pipe. A
potential log is the best approach to find active corrosion
on the outside of the casing and to show effectiveness of
cathodic protection (Allen and Roberts, 1978).
devices can be used
Finally, ultrasonic or radioactive
wall thickness and detect thinning of metal.
mav not detect
to measure a w ^ uiii.
Their principle limitations are that they
small pits and that the measurement is made on1y a t one
point.
-------
6.3 CORROSION CONTROL
Corrosion can be prevented or minimized by the appli-
cation of a number of different design considerations
and operating techniques which include: material used,
protective coatings, preinjection treatment, chemical
inhibitors, or cathodic protection. The original design
concept can be chosen to reduce the severity of corrosion
by the use of corroson-resistant tubing and casing mater-
ials. Provisions can be made during well design for
the application of certain mitigative procedures; for
example, the well could be designed to allow for applica-
tion of corroson inhibitors to the casing/tubing annulus
if the need arises during operation.
Metals resistant to corrosion are available for virtu-
ally all corrosive environments encountered in injection
operations. The problem with many of these corrosion
resistant metals (extreme examples of which are platinum and
gold) is their cost. Iron and steel may corrode, but their
lower cost, ease of fabrication, and strength have helped
them become the most commonly used metals in injection
operations (Allen and Roberts, 1978). There are other
metals and alloys which cost slightly more than iron or
steel but provide resistance to corrosion in specific
applications.
The choice of metals to resist corrosion in a specific
application is affected by the corrosive environment, as
well as the physical requirements for the material. In
a hydrogen sulfide environment, the effect of hydrogen
embrittlement on strength and durability of a metal is
the primary concern (Allen and Roberts, 1978). Low-carbon
steels and other higher cost alloys are useful in preventing
sulfide attack. High strength carbon steel is not recom-
mended because of greater tendency toward sulfide cracking
(API, 1958). For carbon dioxide and oxygen environments,
where embrittlement is not a concern, metals should be
selected based on control of metal loss. These metals are
typically more expensive alloys, such as stainless steel and
monels; consequently, economics might dictate that other
methods of corrosion control be used. For corrosion
resistance to most acids and alkalies, compatible stainless
steel is usually employed for injection tubing strings.
Tables of suitable metals and alloys for hydrogen sulfide,
carbon dioxide, and oxygen corrosion are provided in Chapter
4.
153
-------
Downhole applications of nonmetal, corrosion-resistant
materials are limited to certain types of plastics. Other
nonmetal materials, such as cement-asbestos and ceramics,
do not possess the temperature resistance and strength
properties necessary for injection tubing. The most exten-
sively used plastic pipe and tubing is fiberglass pipe
reinforced with epoxy resin (Donaldson, 1972). This mater-
ial is highly resistant to corrosive fluids, and also
affords relatively good resistance to corrosive attack
by acids and alkalies (Ostroff, 1 965). PVC and other
plastic pipe also offer this corrosion-resistant capability,
but have lower strength and temperature ratings than rein-
forced fiberglass materials. A disadvantage of epoxy-rein-
forced fiberglass and other plastic tubing materials is
their relatively poor resistance to attack by organic
solvents and dissolved chlorine.
6.3.1 Protective Coatings
Coatings prevent corrosion by removing or separating
the corrosive environment from the metal. Paints, plastics,
cement, rubber, and ceramics have been used to provide
such barriers (Allen and Roberts, 1978). In addition, some
metal coatings, like zinc on steel, cathodically protect the
base metals.
Organic, inorganic, or metallic coatings are selected
on the basis of temperature, pressure, and the corrosiveness
of the environment. A major problem with protective coat-
ings is that a break in the coating which exposes the base
metal causes serious corrosion (Ostroff, 1965).
Considerable use has been made of organic coatings for
protection against the interior corrosion of tubing in wells
handling brine (API, 1958). Organic coatings include paint
(which are applied as thin films), plastic (baked phenolics,
PVC, polyurethane), and heavier bituminous coating (coal-tar
enamels). Surface preparation and proper application is
very important in the success of the coatings.
Inorganic cement linings are also used extensively
for tubing in wells handling brines (API, 195b; Allen
and Roberts, 1978). Cement linings are not recommended for
use with highly acidic solutions. Moreover, cement linings
are permeable to water and corrosion products tend to form
-------
between the lining and the subsurface metal. This buildup
of corrosion products can eventually lead to the cracking
and the sloughing of the lining (API, 1958).
For corrosion control in injection-well operations,
the only metallic coatings of importance are zinc and
aluminum on steel (Allen and Roberts, 1978). They may be
used on buried steel components where oxygen corrosion
is moderate, but their best application is for atmospheric
exposure of surface equipment (Allen and Roberts, 1978).
6.3.2 Preinjection Treatment
Frequently, the removal of corrosive agents from
injection fluid by preinjection treatment methods can be
the best means of corrosion control. The most common,
preinjection treatment used involves degasification and/or
neutralization.
Degasification
Degasification involves the complete removal of cor-
rosive dissolved gases from water. The most common method
of degasifying water in preinjection treatment is to
selectively remove dissolved oxygen, since prevention
of corrosion due to acid gases, carbon dioxide and hydrogen
sulfide, is usually cheaper than gas removal (Allen and
Roberts, 1978). Oxygen degasification can be accomplished
by chemical scavengers, vacuum deaeration, or counter-flow
gas stripping.
Chemical scavengers for oxygen removal are based on
a chemical reaction between oxygen and another chemical.
A commonly used chemical is sodium sulfite which is particu-
larly useful for removing small amounts of oxygen from
large volumes of water. Dissolved oxygen is removed in
the oxidation of sulfite to sulfate:
Na2S03 + 1/2 02 —x Na2S04 (6-8)
In practice, 10 ppm of sodium sulfite are used to remove
1 ppm of dissolved oxygen (Ostroff, 1965). Catalysts,
155
-------
such as cobalt chloride, are used to increase the rate of
the reaction. The presence of hydrogen sulfide in the
water reduces the effectiveness of sodium sulfite to scav-
enge oxygen. Sulfate-reducing bacteria should also be
prevented from growing in water-handling systems in which
sulfite is used to scavenge oxygen.
The sulfite ion can also be formed in water by adding
sulfur dioxide gas. Sulfur dioxide can be added from
bottled liquid containers or on-site gas generators.
Bottled liquid is economical for treating small systems
with low oxygen concentrations. The use of sulfur dioxide
for oxygen removal has the potential disadvantage of pro-
ducing corrosive acids in solution and also of creating
barium or calcium scales that may plug the injection forma-
tion.
Oxygen can be removed from water by running it through
a vacuum in a packed tower. The low pressure and the
small amount of oxygen in vapor contacting the water causes
the dissolved oxygen to bubble out of solution (Allen
and Roberts, 1978). The vacuum can be produced by pumps or
steam injectors. Several passes through the vacuum deaera-
tion column are necessary to reduce oxygen to less than
0.1 ppm (Allen and Roberts, 1978). Any free carbon dioxide
will also be removed, which may result in scale deposition
from the accompanying pH change. If further oxygen re-
duction is needed, chemical scavengers can be added after
vacuum deaeration. Vacuum deaeration is applicable where
chemical treatment is uneconomical, or where the addition
of scavengers would form barium or calcium scale.
A counter-flow gas stripping column can be used to
cause dissolved oxygen to escape from water to a natural
gas stream. Either a packed column or a tray-type column
can be used, although the tray-type is preferred (Allen
and Roberts, 1978). Efficient removal of oxygen has been
reported for a vacuum deaeration system supplemented by
hydrocarbon gas stripping (Frank, 1972). Oxygen was re-
duced from 4.7 ppm to 0.05 ppm which reduced the corrosion
of steel by almost 90 percent.
Inject iqn-_Fluid__Neutral lzat ion
Neutralization of an acidic or basic f 1 u id pr i o r
to injection can ne an effective way to control corrosion.
-------
Common chemicals that may be considered for neutralization
are listed in Table 6.3. A potential problem with adding
chemicals to neutralize pH is that insoluble precipitates
may form, and these solids can cause the physical plugging
of the injection zone. Recommended dosage rates for
acid and alkali neutralization are shown in Table 6.4.
Caustic soda, although the most expensive of the
alkali sources for acid neutralization, is usually preferred
because it reacts instantaneously and creates less sludge.
For neutralizing alkalies, sulfuric acid is most often
used (Warner and Lehr, 1977).
6.3.3 Chemical Inhibitors
The addition of chemical inhibitors may be a simple
and inexpensive means of reducing corrosion in tubing, well
casing, and ancillary equipment. It must be stressed,
however, that addition of chemical inhibitors is a supple-
ment to other measures such as equipment selection or
preinjection treatment.
There are two major groups of chemical inhibitors.
The first group includes a wide variety of inorganic and
organic compounds that are used to chemically or physically
inhibit the corrosion reaction. The second group are
bactericides used to kill microorganisms, like sulfate-
reducing bacteria which contribute to corrosion.
Corrosion Inhibitors
The conditions of the environment and type of corrosion
govern the choice of corrosion inhibitor (Ostroff, 1965).
Usually, the choice of inhibitor is based on the experience
of the corrosion engineer along with trial and error test-
ing. Some typical corrosion inhibitors are shown in Table
6.5. Generally, organic inhibitors form films on the metal
surface, protecting the metal from attack. Some of the
inorganic compounds, like the chromates, are anodic inhib-
itors (Ostroff, 1965). Many of these organic and inorganic
inhibitors are considered toxic substances, and therefore
must be used with caution to prevent contamination of
potential potable water sources.
157
-------
TABLE 6.3
COMMON CHEMICALS USED FOR
INJECTION FLUID NEUTRALIZATION
(Warner and Lehr, 1977)
Injection-Fluid
Neutralizing
Characteristic
Chemical
Acid
Lime slurries
Limestone
Soda Ash
Caustic Soda
Ammonia
Waste Alkali
Alkaline
Sulfuric Acid
Hydrochloric Acid
Carbon Dioxide
Flue Gas
Sulfur
Waste Acid
-------
TABLE 6.4
ALKALI AND ACID REQUIREMENTS FOR pH NEUTRALIZATION
(Warner and Lehr, 1977)
Alkali
Approx.
Dosage
(lb/lb H2S04)
Dolomitic Limestone
High Calcium Limestone
Dolomite Lime, Unslaked
High Calcium Limestone,
Unslaked
Dolomitic Lime, Hydrated
Hugh Calcium Lime, Hydrated
Anhydrous Ammonia
Soda Ash
Caustic Soda
0.95
1.06
0.53
0.60
0.65
0.80
0.35
1.10
0.80
Acid
Approx.
Dosage
(lb/lb CaC03)
H2SO4, 66°Be
HC1, 200 Be
Flue Gas, 15%
Sulfur*
CO 2
1.0
2.0
3.0
0.3
* Would produce a reducing condition which might require additional treatment to
produce an oxygen-containing effluent.
-------
TABLE 6.5
CORROSION INHIBITORS
(Gatos, 1956)
Approximate
Concentrations
(percent)
Corrosion
Environment
Metallic
System
INORGANIC
Calgon
Disodiura hydrogen
phosphate
Potassium dichromate
Potassium dihydrogen
phosphate + sodium
nitrate
Potassium permanganate
Sodium benzoate
Sodium carbonate
Sodium chromate
Sodium dichromate
+ sodium nitrate
Sodium metaphosphate
Sodium nitrite
Sodium orthophosphate
Sodium silicate
ORGANIC
Formaldehyde
Erthritol
F.thy lam 1 ine
MercaptoDenzoth:azole
0i »> i 0 dCld
Phenyl acndine
t'yr id me » pneny 1 -
r.ydr 32 : ru*
£u l nci i no *? t h loci idp
T«r t r jm«r t rvy I .immon iu
Small amount
0.5
small amount
+ 5
0. 1
0.5
Small amount
0.07
0.1 + 0.05
Small amount
Q .005
1
0.01
Small amount
Smal1 amount
0.5
Small amount
0.5
water systems
Citric acid
Tap water, 68-194'F
Sea water
0.3N NaOh solution
0.03% NaCl solution
Gas condensate wells
CaCl2 brine
Water
Ammoni a
Water
Waterf pH ¦ 7.25
Oil f leld brine
Oil wells
K2SO4 solutions
HCi solutions
Ht'l solutions
Po 1 yhyd ric alcohols
H2SO4 soljt ions
HC 1 noljt 1 on:;
iN H2SO4
:;C >. '-toi Jt n-r.ft
Steel
Steel
Iron-brass
Steel
Aluminum
Mild steel
Iron
Cu, brass
Heat-exchange
devices
Mild steel
condensers
Mild steel
Iron
Steel pipe
Oil well
equ:pmen t
Mi Id steel
Ferrous metal
Iron jnd st«»e
1 6 U
-------
The simple addition of corrosion inhibitors alone
may not be sufficient to solve all corrosion problems.
Corrosion caused by oxygen associated with salts cannot
be effectively treated with inhibitors (API, 1958) and for
these systems it may be necessary to remove the oxygen as
well.
Inhibitors are added to the well tubing as well as to
the casing tubing annulus. There are several methods
available for adding corrosion inhibitors during well
operation. One method involves filling the annulus during
well completion with a solution containing either an oil- or
water-soluble corrosion inhibitor (Donaldson, 1972).
Inhibitors can also be slug injected while operations are
shut down for a short time. Inhibitors can also be placed in
fluid circulated above the cement in the casing-borehole
annulus.
Bactericides
To prevent the growth of microorganisms which can
contribute to corrosion, bactericides can be employed.
Some inorganic chemicals are used as bactericides, such as
chlorine, chromates, and compounds of mercury or silver.
However, most currently used bactericides are organic
chemicals (Warner and Lehr, 1977). Some typical chemical
compounds used as bactericides are shown in Table 6.6.
Bactericides may be added by continuous feed or slug
treatment. Service companies that supply bactericides
for oil-field use should be consulted when selecting a
preparation for microbial control in an injection well.
It should be noted that many bactericides exhibit
varying amounts of toxicity to humans, and thus, injection
of these substances into underground formations should
be practiced in such a way to prevent contamination of
potential sources of drinking water.
6.3.4 Cathodic Protection
Cathodic protection consists of applying an electric
current to the surface of the protected metal to overpower
161
-------
TABLE 6.6
CHEMICALS USED AS BACTERICIDES
(Ostroff, 1965)
Type of
Bactericide
Example
Compound
Physical Concentration
Form Range (ppm)
Chromium
Mercury
S ilver
Amine
Diamine
Quaternary
Ammonium
Chlorinated
Phenols
Aldehydes
Mercurials
Sodium chromate Solid 500
Mercuric chloride Solid 50 - 300
Silver nitrate Solid 0.05
Coco primary Solid 10 - 40
amine acetate
Coco trimethy- Liquid 5-25
lene diamine
Alkyl trimethyl Liquid 25 - 100
quaternary ammo-
nium chloride
Sodium tetrachlor- Solid 12 - 50
phenate
Gluteraldehyde Liquid 20 - 75
Methyl mercuric Solid 250
acetate
Peroxygens
Peracetic acid
.iquid
162
-------
the voltage of the corrosion cell and to prevent the re-
sulting discharge of electrical currents from the metal into
the ground. The result is that all areas of the metal
become cathodic and corrosion stops. All previously anodic
areas are suppressed as long as adequate current is applied.
In injection-well operations, cathodic protection is used
primarily for the external protection of well casings. It
is typically applied to supplement other corrosion pre-
vention techniques, such as cementing casing through poten-
tially corrosive salt-water zones.
Cathodic protection requires a direct current which
may be generated by using an external source of alternating
current and a rectifier for converting to direct current.
On-site thermoelectric generators may also be used to
directly produce direct current. Current is discharged into
the soil from a group of anodes called a ground bed.
Required current will vary from 1-1/2 amperes for 1500 feet
(457 m) of 6 inch (15.2 cm) casing to as much as 20 amperes
for multicased, deep wells. The voltage can usually be
adjusted as required from 6 to about 24 volts, depending on
the needed current and the resistance of the ground bed
(Allen and Roberts, 1978).
The ground bed can be installed so that there is
a minimum electrical resistance between the anode and
the surrounding soil (API, 1958). To optimize current
distribution on the casing, the ground bed can be placed
about 100 feet (30.5 m) from the wellhead and moved as far
as possible from other pipe lines. Where possible, place-
ment of the ground bed in areas of low soil resistance is
desirable; a low-resistance material is usually packed
around the anodes to serve as backfill.
Figure 6.1 depicts a typical cathodic protection
installation for a well casing. A horizontal ground bed
is shown. Vertically oriented ground beds, called anode
wells, are also used to protect injection wells. These
anode wells, which are drilled to about 300 feet (91.4
m) , provide better vertical distribution of current, and
less power is required than horizontal ground beds (Allen
and Roberts, 1978).
163
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Figure 6.1. Example of cathodic protection scheme
for well casing (Allen and Roberts,
19 78)
1 b
-------
REFERENCES
Allen, T. 0. and A. P. Roberts, 1978. Production oper-
ations, Volume 2. Oil and Gas Consultants, Inc.,
Tulsa, Oklahoma.
American Petroleum Institute (API), 1958. Corrosion of oil-
and gas-well equipment. Dallas, Texas.
American Water Works Association, Inc. (AWWA), 1971. Water
quality and treatment: a handbook of public water
supplies McGraw-Hill Book Co., Inc., New York, New
York.
Baumgartner, A. V., 1962. Microbiological corrosion,
in Proceedings of the fifth biennial secondary recovery
symposium. Society of Petroleum Engineers.
Donaldson, E. C., 1972. Injection wells and operations
today, _in Underground waste management and environ-
mental implications. U. S. Geological Survey and
American Association of Petroleum Geologists.
Ehrlich, G. G., 1972. Role of biota in underground waste
injection and storage, jin Underground waste management
and environmental implications. U. S. Geological Survey
and American Association of Petroleum Geologists.
Evans, U. R., 1960. The corrosion and oxidation of metals.
St. Martins Press, Inc., New York, New York.
Gatos, H. C., 1956. Inhibition of metallic corrosion
in aqueous media, _in Corrosion, Volume 12.
Jellinek, 1958. How oxidation occurs. Chemical Engineer-
ing, 65(17):125-130.
Ostroff, A. G. , 1 965 . Introduction to oilfield water
technology. Prentice-Hall, Inc., Englewood Cliffs,
New Jersey.
Uhlig, H. H., 1962. Corrosion and corrosion control.
John Wiley & Sons, Inc., New York, New York.
Gulf Oil Corporation, 1948. Production Department, Houston,
Texas.
165
-------
Warner, D. L. and J. H. Lehr, 1977. An introduction to
the technology of subsurface wastewater injection.
D. S. Environmental Protection Agency, EPA-600/2-
77-240.
Weber, W. J., 1972. Physiochemical processes for water
quality control. Wiley-Interscience, New York, New
York.
1 6 6
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7. FORMATION AND WELL EVALUATION AND TESTING
A variety of techniques and procedures are available to
evaluate formation conditions and injection-well design
and construction. These techniques include formation
and fluid sampling, geophysical logging, and various
pressure evaluation procedures such as drill-stem testing
and injectivity testing. The principles and applications of
these techniques are discussed in the following chapter.
7.1 FORMATION AND FLUID SAMPLING
Drilling a borehole offers an excellent opportunity
to collect data relevant to a number of important parameters
of the formations penetrated. Procedures utilized may
include sampling cuttings produced during drilling or
obtaining larger intact samples through coring. Formation-
fluid samples may also be collected.
7.1.1 Sampling and Analysis of Drill Cuttings
Cable-tool and rotary drilling techniques (see Chapter
3) produce cuttings which can be collected and analyzed.
Cuttings produced during cable-tool drilling accumulate in
the hole and are removed at intervals, [generally every five
to ten feet (1.5 to 3.0 m)] by bailing. The cuttings
obtained provide samples representative of the formation
penetrated.
Cuttings produced during rotary drilling are carried to
the surface by the drilling fluid. Cuttings are separated
from the drilling fluid by diverting the stream through a
sieve or into a shale shaker. It is possible to separate
large fragments by this method; however, it may not be
possible to separate much of the finer material such as
clay. Care must be taken to identify the depth from which
the sample is produced. Cuttings arriving at the surface do
not represent the rock being cut at the time they are taken
from the mud. Estimates of the lag time required for
cuttings to come to the surface must be made to determine
the depth at which samples have been produced and can be
made by knowing the size of the borehole and the pumping
167
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rate. Fragments produced during rotary drilling do not
all rise with the drilling fluid at the same rate, and
samples taken at one point in time may contain fragments
produced over a range of depths. This problem can be
minimized by observing penetration rates and by taking
samples only after stopping drilling and cleaning the
borehole by circulating drilling fluid for a period of
time.
Cuttings are normally examined at the site under
low-power magnification to identify rock type, grain size,
color, and mineralogy. Testing the samples with acid can be
used to determine carbonate material. More detailed dis-
cussions on sampling and analysis of drill cuttings are
available in many petroleum geology and drilling textbooks
ie, Dickey, 1979; Moore, 1974.
7.1.2 Coring
Geologic cores taken while drilling provide lithologic
and hydrologic information superior to that obtained from
the analysis of drill cuttings. However, coring is an
expensive procedure and is employed only when drilling
formations of special interest. Coring is accomplished
through the use of a special drilling bit and a coring
barrel which is attached to the end of the drill pipe.
As the bit cuts into the rock, an inner core is left intact
and pushed into the core barrel. The length of the core is
limited by the length of the core barrel, a maximum of 90
feet (27.4 m). Obtaining intact cores from unconsolidated
or partly cemented materials is difficult and frequently
requires special equipment, such as rubber sleeve retainers.
Cores are commonly 3.5 inches (8.9 cm) in diameter, but can
range between 1 and 5 inches (2.54 and 12.7 cm).
Techniques are also available to take cores from
the sides of a borehole after drilling is completed. These
sidewall cores are gene rally taken to provide information
about formations from which cores were not taken during
drilling. Sidewall coring is accomplished by running
a wireline coring device which contains hollow cylinders,
These hollow cylinders are driven into the format ion by
an explosive charge. The cores are relative! y sma .1 1 ,
ranging between 7/8 and 1-3/4 inches (2.22 and 4.4 cm 1 in
diameter and between 1 and 1-3/4 inches (2.54 and 4.4 cm) in
1 b b
-------
length. Sidewall coring is limited to rather soft mater-
ials.
Examination of conventional cores can provide sub-
stantial amounts of data valuable to the design and the
construction of injection wells. Visual examination of
cores can reveal fractures, bedding features, and solution
cavities; laboratory examination can determine porosity,
grain size, permeability, and formation-fluid quality. The
application of data taken from conventional cores is limited
by a number of factors. For example, cores may be affected
by drilling fluids. Cores which have been taken at depth may
have been subjected to considerable pressure, and measure-
ments made in an unpressurized environment may not reflect
the in-situ characteristics of the material.
Data obtained from sidewall cores are not as reliable
as that obtained from conventional cores due partly to
the relatively small size of the sample. Formations are
disturbed substantially during coring, and the more perme-
able formations sampled have generally been invaded with
drilling fluid. Consequently, sidewall cores are not used
extensively for directly evaluating porosity, permeability,
or saturation characteristics of rock. They do provide
valuable data, however, on grain size and rock type (Ander-
son, 1975; API 1960).
Expense and inherent limitations prohibit the use of
coring programs solely to determine formation characteris-
tics. Instead, they are used with other evaluation tech-
niques including geophysical logging, drill-stem tests,
and pressure tests. The particular value of cores lies with
the data made available for use in cross-referencing with
other evaluation techniques (Wilson and Hensel, 1978; Shirer,
et al., 1978; Collins, 1976). Coring programs can be of
particular value in injection-well design by providing a
sample of the injection zone for testing to determine waste
and formation compatibility (Donaldson, 1972; Hewitt, 1963;
Keelan and Koepf, 1977).
7.1.3 Fluid Sampling
Formation-fluid samples can be obtained by a number of
methods, including bailing, drill-stem testing, swabbing, and
air-lift methods. In holes drilled by cable-tool methods,
169
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bailing may be used to obtain formation water samples but
care must be taken to insure that the water sample taken is
representative of the formation of interest and not of
another formation also draining into the borehole. This
problem is reduced in holes in which casing is driven since
the casing acts to isolate the lowest formation from the
other water-producing formations.
Drill-stem testing methods can be used to obtain fluid
samples in uncased holes. Single or double packer arrange-
ments are used to isolate the zone from which the fluid is
sampled. Wireline devices utilize principles similar to
drill-stem testing and are also used to obtain fluid
samples. The usefulness of formation-fluid samples obtained
by drill-stem or wireline procedures is limited by the
extent to which they are contaminated by drilling fluid.
Swabbing is a method for obtaining fluid samples from
cased holes. A swab is seated against the casing. When the
swab is pulled upward, fluid is drawn to the surface
(API, 1966).
7.2 GEOPHYSICAL LOGGING
Geophysical logging is a generic term applied to a
variety of techniques by which formation and well-con-
struction characteristics can be evaluated through the
interpretation of specific physical measurements made within
the borehole. These measurements are made by a logging tool
which provides a continuous measurement of the selected
physical parameter during the ascent (or descent) of the
tool from the borehole. These measurements are electrically
transmitted to the surface where they are recorded. The
physical measurements generally are not direct measurements
of the geologic or hydraulic parameter of interest but are
measurements of related physical characteristics which can
be interpreted to provide an evaluation of the desired
parameter.
During injection-well construction, geophysical logging
can be used to evaluate a number of important formation
characteristics. Logging is commonly used for litholoyic
and stratigraphxc identification and for the correlation
of formations encountered with formations known to exist.
Logging can also be used to measure formation porosity and
170
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to help identify the nature and extent of fractures.
Permeability can be qualitatively determined from logging.
Techniques are available for quantitative determination of
permeability but are subject to numerous limitations which
make the quantification of permeability more feasible
using nonlogging methods. Although subject to a number of
constraints, logging may also be used to determine form-
ation-water quality. In addition, logging can be used
to determine a number of well-construction features such as
the nature and the extent of cement bond, fluid flow behind
the casing, and the condition of the casing.
A large number of logging techniques are available
for use in the evaluation of formation and well parameters.
Table 7.1 summarizes many of these techniques according to
the actual physical parameter measured and its potential
applications. Each of the major logging companies offers
many of these techniques under a variety of trade names.
A categorization of the techniques according to the trade
names used by major service companies is presented in Table
7.2.
A combination of logs is generally used within a
single borehole to evaluate many formation characteristics
as well as to evaluate a single parameter. The choice of
logs comprising a particular logging suite depends on local
lithology, data requirements, and availability of specific
logging tools. The specification can be allowed consider-
able flexibility since a variety of tools can accomplish
similar goals. Many of the parameters can be measured using
other techniques which may offer a more meaningful evalu-
ation or a less expensive approach.
The following section discusses the principles and
applications of many of the logging techniques available for
use at injection—well sites. The section is concluded with
a discussion concerning the formulation of suites of logs to
meet many of the requirements for formation and well-
construction evaluation. For a detailed discussion of
logging principles and applications, a variety of additional
resources are available. The major service companies offer
texts discussing the principles and applications of their
services (Schlumberger, 1972 and 1974; Welex, n.d.). In
addition, a variety of textbooks on the subject are avail-
able (Wyllie, 1963; Pirson, 1970; Merkee, 1979; Petroleum
Extension Service, 1971). Numerous articles concerning
individual techniques are also available. An effort has
171
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TABLE 7.1
GEOPYSICAL WELL LOGGING METHODS AND
THEIR APPLICATIONS
(Modified from Warner and Lehr, 1977)
Method Property Appl
ELECTRICAL
Spontaneous
Potential (SP)
Electrochemical and
electrokinetic po-
tentials
ication
Formation-water re-
sistivity; shales,
and nonshales; bed
thickness; shaliness
a. Water and gas/oil
saturation.
b. Porosity of water
zones.
c. Formation-water
resistivity in
zones of known
poros ity.
d. True resistivity
of formation.
e. Resistivity of
invaded zone.
a,b,c,d. Very good
for estimating for-
mation resistivity
in either fresh
water, oil base
muds, or air filled
holes.
a,b,c,d. Especially
good for determin-
ing formation
resistivity of
thin beds.
Resistivity close
to the borehole
for calculating
poros i ty.
Bed thickness.
Nonfocused Resistivity
Electric Log
Focused Resistivity
Induct ion
Log
Focused Resistivity
Res i!
Logs
Resistivity
Focused and Resistivity
Nonfocused
Microres is-
tivitv Logs
-------
TABLE 7.1 (Cont'd)
Method
Property-
Application
ACOUSTICAL
Transmission
(sonic veloc-
ity and
amplitude
logs
Reflection
RADIATION
Gamma Ray
Spectral
Gamma Ray
Gamma-Gamma
Neutron-
Gamma
Neutron-
Thermal
Neutron
Neutron-
Epithermal
Neutron
Compressional and
shear wave veloc-
ities
Compressional and
wave attenuations
Amplitude of
reflected waves
Natural radio-
activity
Natural radio-
activity
Bulk density
Hydrogen content
Hydrogen content
Hydrogen content
Porosity; lithology;
elastic properties,
bulk and pore com-
pressibilities.
Location of frac-
tures; cement-bond
quality.
Location of vugs,
fractures; orien-
tation of fractures
and bed boundaries;
casing inspection.
Shales and nonshales;
shaliness.
Lithologic identifi-
cation.
Porosity; lithology.
Porosity
Porosity; gas from
liquid.
Porosity; gas from
liquid
173
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TABLE 7.1 (Cont'd)
Method
Property
Application
RADIATION (cont'd)
Pulsed Neu-
tron Capture
Decay rate of ther-
mal neutrons
Water and gas/oil
saturations; re-
evaluation of old
wells.
Spectral
Neutron
Radioactive
Tracer Log-
ging
Induced gamma ray
spectra
Injected radio-
activity
Location of hydro-
carbons; lithology.
Leakage, flow behind
casing.
OTHER
Nuclear
Magnetism
Temperature
Log
Noise
Cas ing
Inspect ion
Caliper
Amount of free
hydrogen; relax-
ation rate of
hydrogen
Temperature
Sound
Electro-magnet ic
propert ies
Borehole Well
pos it ion
Effective porosity
and permeability of
sands; porosity for
carbonates
Formation tempera-
ture .
Flow behind casing.
Well condition.
Borehole diameter;
well condition.
174
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TABLE 7.2
SOME GEOPHYSICAL WELL LOGGING SERVICES AVAILABLE
FROM THREE COMPANIES PROVIDING WELL LOGGING SERVICES
(Warner and Lehr, 1977)
COMPANY
Welex
Schlumberger
Dresser-Atlas
Electric Log
Induction Electric Log
Dual Induction Guard Log
Guard Log
Contact Log
FoRxo Log
Acoustic Velocity Log
Compensated Acoustic
Velocity Log
Fracture Finder Log
Micro-Seismogram Log
Density Log
Compensated Density Log
Simultaneous Gamma Ray-
Neutron Log
Side Wall Neutron Log
Electrical Log
Induction Electrical Log
Dual Induction Laterolog
Dual Laterolog
Microlog
Microlaterolog
Proximity Log
Sonic Log
BHC Sonic Log
Amplitude Log
Variable Density Log
Formation Density Log
Compensated Formation
Density Log
Gamma Ray-Neutron Log
SNP Neutron Log
Electrolog
Induction Electrolog
Dual Induction Focused Log
Laterolog
Minilog
Micro-Laterolog
Proximity Log
Acoustilog
BHC Acoustilog
Fraclog
Variable Amplitude Density
Log
Densilog
Compensated Densilog
Gamma Ray-Neutron Log
Epithermal Sidewall Neutron
Log
-------
been made to include a number of these citations in the
following discussions.
7.2.1 Electric Logging
Electric logs were one of the first geophysical-logging
techniques developed and applied to determine characteris-
tics of geologic formations. Among the most commonly
applied techniques, electric logging is based on measuring
natural electric potential or resistivity and, accordingly,
is classified as spontaneous potential logging and resis-
tivity logging.
Spontaneous Potential Logging
The spontaneous potential log, also known as self
potential or SP log, is used to correlate stratigraphy,
provide a qualitative indication of the amount of clay or
shale present, identify permeable beds, and indicate
formation-water resistivity (Doll, 1949; Wyllie, 1948;
Alger, 1971). The SP log measures the natural electric
potential established between the borehole fluid and the
formation fluid with relationship to a fixed potential
electrode located at the surface. The relative potentials
observed are dependent on formation lithology, and borehole
and formation-fluid characteristics.
While a variety of phenomena are involved in producing
the potentials oberved in SP logging, electrochemical poten-
tials are generally considered most important. These
potentials result from differences in ionic concentrations
(salinities) between the borehole fluid and the formation
fluid. When fluids of different ionic concentrations are
placed next to each other, ions will migrate from the fluid
of high concentration to the fluid of low concentration.
Generally negative ions have a higher mobility and their
migration results in the development of a positive potential
in the fluid of higher concentration. However, if materials
such as clay or shale are present, a second phenomenon
influences the potentials developed between the borehole
fluid and the formation fluid. Clay materials act as ion-
selective membranes which preferentially allow cations
1 7 6
-------
(positive ions) to migrate. Clay consequently acts to
reverse the normal trend and to allow more cations to
migrate from the higher salinity fluid into the lower
salinity fluid. Thus, in the case in which formation fluid
is more saline than borehole fluid, the SP logging will
produce the greatest positive measurement as the probe
passes clay beds and progressively more negative measure-
ments as clay content decreases.
A schematic diagram of an SP log is shown in Figure
7.1. The maximum positive deflection reflects potentials
developed next to a clay or shale and is known as the shale
baseline. Similarly sands reproduce more negative readings
with a clean sand, yielding a maximum negative reading
identified as the sand baseline. However, any shift in
concentration differences between formation and borehole
fluids will affect the shape of the SP curve since ion
migration and, therefore, observed potentials are propor-
tional to the relative difference between the salinities of
the two fluids. In addition, an inversion in the curves
will result if formation fluids are less saline than bore-
hole fluids.
As Figure 7.1 shows, SP logs can be used to identify
clay beds and give an indication of the relative amount of
clay present in sand and sandstone layers. By determining
relative clay content, SP logs can help to qualitatively
identify permeable beds. These logs also indicate the
relative thickness of beds and can be used to correlate
formations encountered during drilling with local strati-
graphy.
Since the magnitude of deflections observed during SP
logging is proportional to the ratio of formation-fluid and
borehole-fluid ionic concentration, estimates of formation-
water quality can, in some instances, be determined.
Equations are available which relate the resistivity of the
two fluids to the observed SP deflection; and if drilling
fluid resistivity is known, formation-fluid resistivity can
be calculated. These calculations yield fluid resistivity
which can be used only to determine ionic concentration if
the relative proportions of specific ions are known.
177
-------
SPONTANEOUS POTENTIAL CURVE
millivolts
— ^ ~ 4-
Sand line
Shale line
Sand
Shaly
Sand
Shale
Clean
sand
Sandy
sha ie
Dana
shale
sand
it rr
igure 7.1.
LITHOLOGY
Schematic diagram of spontaneous potential
log showing .lithologic correlat ions
17«
-------
Resistivity
Logging
Resistivity logging is one of the most commonly applied
logging techniques used for stratigraphic correlation,
formation-fluid resistivity measurements, porosity and
fracture determination, pore pressures identification, and
permeable beds identification. Resistivity logging provides
a measurement of the ability of a formation to impede the
flow of electricity and is inversely related to electrical
conductivity. Formation resistivity is related both to
formation lithology and to fluid content. In most cases,
geologic materials are poor conductors of electricity, and
thus the ability of a formation to conduct electricity is
primarily a function of the relative amount and ionic
content of fluids present in the formation. However, in
formations in which metallic ores or clays with exchangeable
ions occur or in which fluid content or ionic concentration
is low, formation materials may also contribute substan-
tially to the conduction of electrical currents.
It is common practice to relate formation resistivity
to formation-fluid resistivity using a formation factor
which is the ratio of formation resistivity to the fluid
resistivity when 100 percent saturated with water (Archie,
1942). The formation factor for nonconductive geologic
materials has been shown to be primarily a function of
formation porosity, except in cases in which water con-
ductivity is low. The relationship between observed forma-
tion resistivity, fluid resistivity, and formation factor or
porosity is responsible for a number of potential applica-
tions of resistivity logging. If formation-resistivity
measurements and a value for the formation factor are
available, formation-fluid resistivity can be calculated to
indicate water quality at injection-well sites. However,
water resistivity cannot be translated directly into a total
dissolved solids determination unless the relative propor-
tion of each ionic species is known. The application of
resistivity techniques for determining water quality for low
conductivity/high quality ground water is tenuous because
iji such circumstances formation factors are dependent on
both porosity and water quality.
Measurements of resistivity can be similarly applied
to estimate porosity. If formation-fluid resistivity is
1 79
-------
known, measurements of formation resistivity can be used
to calculate the formation factor (which can be used to
calculate porosity if sufficient information is available
concerning lithologic characteristics of the formation).
This application is subject to the previously discussed
limitations concerning the altered relationship between
porosity and the formation factor in formations containing
high quality water. Resistivity logging is not widely
applied to porosity determinations because a number of
superior logging methods are available.
A variety of different resistivity logging tools
are in use, but most are based on similar principles
and procedures. Electrodes are used to establish a fixed
current in the materials in and near the borehole, and
potential electrodes are utilized to measure potential
differences along the flow path of the induced electric
current. Ohm's law is used to calculate resistivity from
these measurements. The tools provide a continuous mea-
surement of resistivity which is recorded at the surface
as the tool is pulled from the hole. The observed re-
sistivity reflects the changes in lithology and fluid
salinity which occur within the borehole.
The first resistivity devices to be developed and
used extensively were the point, the normal, and the lateral
resistivity tools. These tools utilize different spacings
between current electrodes to alter the radius of investi-
gation. Generally, the larger the spacing between elect-
rodes, the larger is the radius of investigation. Though a
variety of spacings have been used, a number of standard
spacings are common. The single point tool utilizes only a
single electrode so no spacing distance is involved. The
normal resistivity tools utilize either a 16 inch (40.6
cm) short or a 64-inch (162.6 cm) long electrode spacing.
The spacing utilized most commonly in lateral devices is
18.67 feet (5.7m).
Normal and lateral devices have a number of inherent
disadvantages. Most importantly, as the electrode spacing
is increased and the radius of investigation correspondingly
increased, the ability to detect and to measure resistivi-
ties in thin beds is lost. This progressive loss of vert-
ical resolution in normal and lateral devices as the
depth of investigation increases led to the development of
resistivity devices which focus current beams transmitted
through the formation to increase the depth of investigation
1 8 0
-------
while maintaining a high degree of vertical resolution.
These focused resistivity tools have now nearly replaced the
normal and lateral resistivity devices. The two basic
focused-resistivity tools are the guard-log devices and the
laterolog system (Doll, 1971a).
Another general type of resistivity device is the
induction logging device which electromagnetically induces a
current in the formation (Doll, 1949). The device is
instrumented to measure the strength of the electromagnetic
field resulting from the induced current. Since the induced
current is directly related to formation conductivity these
devices are commonly referred to as conductivity tools.
Induction logging devices are particularly useful in bore-
holes containing nonconductive drilling fluid since they do
not depend on electrical contact with the formation through
fluids in the borehole.
Special resistivity tools include the microresistivity
tools. These tools are only adaptations of the other basic
resistivity techniques, and are the micro-normal, the
micro-lateral, and the focused micro-logs. These tools have
been developed to investigate conditions at the immediate
periphery of the borehole and are frequently referred to as
wall-resistivity tools.
Resistivity measurements made during logging are
influenced by the true formation resistivity, materials
within the borehole, and the diameter of the borehole. Most
resistivity logs must be run in boreholes which contain a
sufficiently conductive fluid to ensure electrical contact
between the electrodes and the surrounding formation
materials. However, if the fluids are too conductive, the
electrical currents induced by the resistivity tool may
follow a path within the borehole rather than through the
formation and thereby yield anomalous formation resistivity
readings. Increases in borehole diameter generally accent-
uate such problems.
The drilling process can produce changes within
the formation that can profoundly affect resistivity meas-
urements. Drilling fluids have a tendency to penetrate
permeable formations, resulting in the formation of wall-
cake and a zone of invasion within the formation containing
drilling-fluid filtrate (see Chapter 3). This creates
a number of zones which exhibit different formation resis-
tivities and may result in inaccurate interpretations of
formation and fluid characteristics, if not accounted for.
181
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A variety of resistivity logging tools which have
varying radii of investigation have been developed to
compensate for the effects of drilling-fluid invasion.
Tools with large radii of investigation measure formation
resistivity at points sufficiently removed from the borehole
to minimize the effect of drilling-fluid filtrate. In
addition, tools are available with medium and shallow depths
of investigation which can be used to identify the extent
and resistivity of invaded zones. These measurements can,
in turn, be used to compensate measurements made by tools of
larger radius of investigation and thereby provide more
reliable estimates of true formation resistivity.
Representations of resistivity logs taken during a
conventional resistivity survey (short, long, normal, and
lateral devices) are presented in Figure 7.2. As shown in
the figure, resistivity profiles run to determine formation
resistivity commonly involve shallow, medium, and deep
(short to large radii) investigating devices. One analyti-
cal technique used to calculate formation resistivity with
multiple resistivity readings is discussed by Tixier, et al.
(1965).
In addition to providing formation-resistivity measure-
ments that can be used for fluid resistivity or porosity
determinations, resistivity surveys can be used to provide
lithologic determinations and stratigraphic correlations.
Figure 7.2 shows the variations in measured resistivity
which correspond to changing lithology. Certain resistivity
tools provide better results for this purpose. The focused
devices generally show greater vertical resolution than the
long, normal, or lateral device. Point-resistance devices
are also available which show stratigraphic delineation, but
these devices provide a resistivity reading which is not
representative of true formation resistivity due to the
influence of borehole fluids.
Resistivity surveys can be used to identify permeable
beds using mi crores istivity devices which can detect the
presence of wallcake or drilling-fluid filtrate (Doll,
1971b). Thick layers of wallcake normally form at the face
of permeable formations where filtrate is able to penetrate
the formation. In addition, microresistivity devices can be
used to determine the formation factor. In formations in
which the fluids in the pore space near the borehole have
1 8 2
-------
Figure 7.2. Conventional resistivity survey with
lithologic correlation (Petroleum
Extension Service, 1971)
1 83
-------
been replaced completely by drilling-fluid filtrate, measure-
ment of formation resistivity can be used to compute the
formation factor using the resistivity of filtrate at the
surface.
Resistivity logging can be used to identify areas of
fracturing (Beck, et al., 1977; Pickett and Reynolds,
1969). When microresistivity devices cross fractures
during logging, they generally show a resistivity anomaly
due to the fluids contained within the fracture. Such
surveys can be used to provide a qualitative identification
of fracturing; because microresistivity tools are side wall
devices which only investigate a portion of the borehole
wall, they cannot be relied upon to locate all fractures.
The dipmeter, also known as the fracture identification log,
is a sophisticated application of microresistivity logging
which provides better results when locating fractures and is
discussed in this chapter (Section 7.2.4).
7.2.2 Radioactivity Logging
A variety of geophysical logging techniques which
measure either the natural radioactivity or the attenuation
of radioactive signals emitted from a radioactive source
have been developed. These measurements can be used to
identify specific geologic materials based on their char-
acteristic natural radiation, or to assess density or fluid
content and, therefore, porosity based on the ability to
attenuate radioactive signals. The radioactive logging
techniques available for use at injection-well sites include
gamma, gamma-gamma, and neutron logging.
Gamma and Spectral-Gamma Logging
Gamma logging is a technique for measuring the natural
radioactivity of geologic materials that is useful for
correlating stratigraphy and determining clay content.
Unstable isotopes of a variety of elements which spontan-
eously decay and emit radioactivity occur naturally in
geologic materials. The most effective means of detecting
1 H 4
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these unstable isotopes is through the measurement of the
gamma radiation emitted during decay. Isotopes of uranium,
thorium, potassium, and their various decay products are
responsible for most of the radioactivity measured during
gamma logging. The amount of radiation detected is directly
proportional to the amount of these isotopes present in a
specific formation. Shales and clayey materials commonly
emit more gamma radiation than most other geologic materials
because of the abundance of potassium. Consequently, gamma
logging is frequently used to detect clay and shale and to
determine the relative amount of clay within a specific
formation. In contrast, clean sand formations usually
exhibit a very low level of radioactivity unless radioactive
contaminants are present. The schematic diagram of a gamma
log shown in Figure 7.3, illustrates the high radioactivity
measured during gamma logging opposite shales or shalely
materials.
Since specific rock types exhibit characteristic levels
of gamma radiation based on mineral content, individual
formations can be distinguished and their lithology tent-
atively identified using a gamma log. Within a specific
area, individual beds will exhibit a typical level of
radioactivity. Thus, gamma logs can provide a fairly
specific "fingerprint" of individual formations which can be
used for stratigraphic correlation. Gamma logs are also
used extensively to provide background measurements of
radioactivity necessary for other radioactivity logging
techniques.
In addition to standard gamma-logging techniques, a
second gamma-logging technique, known as gamma spectro-
metry, can be utilized. Radioisotopes emit radiation with
energies characteristic of that isotope. Gamma spectrometry
utilizes this phenomenon to identify specific isotopes
present in a formation by providing a means of studying the
energy distribution of gamma photons measured during conven-
tional gamma logging. Gamma spectrometry increases the
relative amount of information provided by the more conven-
tional gamma-logging technique and greatly increases the
ability to determine lithology and provide stratigraphic
correlations. The ability to determine relative amounts of
potassium, uranium, and thorium frequently provides a means
of detecting unique signatures of individual clay types. In
addition, the detection of anomalously high uranium kicks
associated with many fracture systems becomes possible.
185
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Gamma ray
RADIATION INTENSITY INCREASES
SURFACE FORMATIONS (3C- 70") AfFECTED
BY COSMIC RAY PENETRATION
SAND OK LIME
SANO OB LIME
SHAIY SANO
OR LIME
SANO Oft Um£ WITH
SHALT STREAKS GRADING
TO SHALE AT KtnQM
MAJtUMf SHALE
SANO OR LIME
CAPROCK. CALC1TE O* GYPSUM
SANO OR LIME
Figure 7.3.
Schematic diagram of qarama log showi
lithologic correlations
1 H b
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This capability can facilitate the identification of frac-
tured zones of clayey material.
Gamma-Gamma Logging (Density Logs)
The gamma-gamma log measures the apparent density of
geologic material which, in turn, can be used to determine
porosity and to indicate lithology. The gamma-gamma logging
device employs a radioactive source that emits gamma rays
and a sensor that detects the portion of these gamma rays
which are back-scattered into the borehole. The observed
back-scattering results from collisions between the gamma
rays and the electrons in the formation. The proportion of
gamma rays that are back-scattered depends on the density of
electrons present in the formation material and thus is
proportional to formation density. The gamma device act-
ually measures the bulk density of a material, or the actual
density of the formation based on the relative amount and
density of the geologic matrix and the fluids contained
within the matrix. If a density value for both the form-
ation matrix and the fluid contained within the matrix can
be assumed, the porosity of that formation can be estimated
(Alger, et al., 1963; Tittman and Wahl, 1965; Wahl, et al.,
1964; Holm and Kleinegger, 1976).
Standard estimates of electron density for both form-
ation matrix materials and fluids are generally available;
and, if general lithologic and formation-fluid characteris-
tics are known, gamma-gamma logs provide an effective means
of determining porosity. When used with other logging
techniques, gamma-gamma logging can yield relevant inform-
ation for determining lithology, shale content, and fluid
saturations.
The radius of investigation of gamma-gamma logs
is shallow, [only 6 inches (15.24 cm)]; consequently, the
logging tool must be pressed tightly against the wall of the
borehole, limiting the ability of the tool to evaluate
more than 25 percent of the borehole. Density logs can
be significantly affected by wall cake and irregularities
in borehole contours because of this shallow depth of
investigation. In fact, this sensitivity to wall cake
thickness enables their use to determine that parameter.
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Neutron Logging
Neutron-logging tools are used to determine porosity
and lithology (Wahl, et al., 1970; Tittman, et al., 1966
Ahmed, 1977; Calvier, et al. , 1971). They contain a
radioactive source that emits high-energy neutrons and a
sensor that detects radiation resulting from the interaction
of the emitted neutrons with formation materials (lower
energy neutrons and gamma photons).
Although neutrons and gamma photons are present at a
variety of different energy levels, neutron-logging tools
contain sensors which detect certain energy levels only.
The names of the neutron-logging tools generally indicate
which type of radiation is being measured and include
neutron-gamma, neutron-thermal neutron, and neutron-epither-
mal neutron logging tools. In addition, a specialized
application of neutron logging, known as pulsed neutron
logging, or decay-time logging, is available. This tech-
nique employs a source which emits a discrete pulse of
neutrons and a detector that is sensitive to gamma rays
emitted by the interaction between the pulses of neutron and
the formation.
Since the neutron emitted by the source is affected by
the hydrogen atoms present in the formation, neutron
logs essentially provide a measurement of the amount of
hydrogen present. If the hydrogen contained in the forma-
tion is present primarily in formation fluids, neutron logs
indicate the amount of pore fluid present which can be
translated directly into a measurement of porosity in a
saturated formation. However, neutron logs will not yield
accurate measurements of porosity in materials such as
shale or hydrated gypsum that contain hydrogen that is not
associated with pore fluids.
Neutron logs can be run in both cased and uncased
holes, and their use has been suggested in the evaluation of
the condition of borehole cement by identifying areas of
high porosity. The use of neutron techniques for cement
logging however is limited, since cements are generally
nydrated chemical complexes and, therefore, do not allow
easy interpretation.
Pulsed neutron logs were originally developed to
identify hydrocarbons by differentiation of fluids which
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contain chloride (i.e., saline water), and those which do
not (i.e., oil and gas). These logs offer the capability of
identifying saline water and might be useful in distinguish-
ing fresh from saline-water bearing zones. Because these
logs can be run in cased holes, they may be useful in
identifying areas of fresh-water degradation.
It must be noted that special precautions must be taken
if a neutron-logging device is lost in the borehole. The
borehole must be abandoned and grouted to the surface; some
states require the installation of monitor wells around the
neutron source. A monument must be installed at the aband-
oned well to denote the presence of radioactive material.
7.2.3 Acoustic Logging
Logging techniques which measure the acoustic proper-
ties of geologic materials are known as acoustic or sonic
logs. These techniques utilize logging devices containing
one or more transmitters which emit high frequency pulses of
acoustic energy and a number of receivers spaced at varying
distances from the transmitter. The transit time of the
sonic wave, which is the reciprocal of sonic velocity, and
the amplitude or attenuation of the sonic wave is measured.
A variety of lithologic parameters influence the character-
istics of the sonic wave (Pickett, 1963), and the measure-
ment of these acoustic parameters allows the determination
of porosity and the presence of fractures, if sufficient
additional information is present. The various acoustic
logs include the sonic velocity, sonic amplitude, and
variable density logs, as well as the acoustic-borehole
televiewer.
Sonic-Velocity Logging
Sonic-velocity logs are used to determine formation
porosity by measuring the time required for a sonic wave
to travel between two receivers (Tixier, et al., 1959 and
1960). The velocity of a sonic wave through a geologic
formation depends on properties of both the rock matrix and
the formation fluids. The sonic velocity for typical
formation liquids (i.e., oil and water) are essentially
the same, and in cases in which no gas is present, sonic
1 89
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velocity depends primarily on porosity and rock-matrix
properties. This dependence on formation porosity is
responsible for the principle use of sonic velocity logs to
determine porosity.
There are several limitations in the use of sonic-
velocity logs for determining porosity. Since sonic velo-
city depends on the matrix properties of the rock as well
as on formation porosity, accurate determinations require
knowledge of formation lithology. The use of sonic-velocity
logs to determine porosity is also limited in unconsolidated
or poorly compacted materials because the rock matrix
does not transmit acoustic energy well and sonic velocity is
more readily influenced by formation fluids. In addition,
sonic-velocity logs do not provide a measurement of secon-
dary porosity in fractured or vugular formations. However,
sonic-velocity logging can provide a means of measuring
secondary porosity by substracting sonic velocity-log
porosity measurements from total porosity measurements made
with other logs.
Sonic-Amplitude Logging
Sonic-amplitude logs measure the attenuation of a
sonic wave as it travels through a formation. A variety of
formation properties determine wave attenuation, but poor
compaction of unconsolidated materials and formation vugs
and fractures appear to have major impacts on the ability to
transmit the elastic energy of a sonic signal. In addition,
when applied in cased holes, some waves will be attenuated
based on the nature of the cement bond. This characteristic
response allows sonic-amplitude logs to be useful when
identifying areas of fracturing in uncased holes or when
determining the quality of cement bonding in cased holes.
Experience has shown that compression and shear sonic-
waves emitted by the tool are attenuated differently by
horizontal and vertical fractures. Compression waves are
attenuated most in areas of vertical and high-angle frac-
tures, while horizontal or low angle fractures affect shear
waves to a greater extent. Thus, attenuation in either the
compression or shear components of the sonic wave can be
useful in determining extent or orientation of formation
fractures. The identification of fractures from the inter-
pretation of amplitude logs is qualitative and must be
accomplished with drilling and core data. Amplitude logs
1 9 0
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may fail to distinguish between actual fractures and bedding
planes, shale or clay streaks, or "healed" fractures
(Pickett, 1963; Morris, et al., 1964; Koerperich, 1978).
Sonic-amplitude logging techniques have also been
applied in cased holes to determine the extent of cement
bonding to the casing (Grosmangin, et al., 1961; Bade, 1963;
Fertl, et al., 1974). Cement-bond logs operate on the
principle that the energy loss of a sonic pulse trav-
eling through a casing that is firmly bonded to cement will
be greater than the loss of energy of a pulse traveling
through a free casing. In this manner, sonic amplitude
logs, by identifying areas of the casing in which the
acoustic signal is poorly attenuated, can identify areas
of poor cementing. Application of these logs to injection
wells with tubing requires that the tubing be removed so the
acoustic signal can be applied directly to the casing.
Variable-density logging is a specialized sonic-
amplitude logging technique for fracture detection in
uncased holes and cement-bond evaluation in cased holes.
Acoustic Televiewer
The acoustic televiewer produces an "acoustic picture"
of the surface of a borehole (Zemaneck, et al., 1970; Wiley,
1981). It has been used primarily as a tool for examining
the condition of borehole wall and can be used to determine
the presence and extent of induced and natural fractures at
the face of the borehole. The televiewer can also be
applied within cased wells to determine the condition of the
casing.
The acoustic televiewer operates by emitting a pulsed,
concentrated beam of high frequency sound energy from
an acoustic transducer. The pulses of sound energy are
directed toward the wall of borehole where a portion of
each pulse is reflected back to the televiewer. The
physical properties of the borehole wall determine the
amount of acoustic energy reflected. Smooth and/or hard
surfaces reflect acoustic energy better than rough ana/or
soft surfaces. Thus, smooth surfaces will result in the
transmission of a higher energy signal. These signals
are displayed on an oscilloscope. A two dimensional image
of the borehole wall showing areas of various brightness
191
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is produced (Figure 7.4). The televiewer log is obtained by-
photographing the oscilloscope presentation.
The acoustic-borehole televiewer provides a means
of detecting and assessing natural and induced fractures,
as well as other nonconformities such as vugs. In cased-
hole applications, the televiewer will show pits or holes in
the casing. Effective use of the televiewer requires a
homogeneous liquid such as water or drilling fluid within
the borehole. In the past, the high solids content of
some drilling fluids has proved problematic to the effec-
tive operation of the televiewer. The televiewer tool
also requires near-perfect centralization within the bore-
hole and a slow, constant logging speed.
Acoustic televiewers were used during the 1960s for
borehole inspection. However, there was not enough sus-
tained interest in their use to justify maintaining the
services. Borehole televiewer services entered a period
of relative disuse and now are difficult to obtain. With
the renewed interest in fracture identification and eval-
uation from increased oil exploration, the use of secondary
recovery techniques, and other energy-related interest,
the use and availability of acoustic-borehole televiewer
services may increase.
7.2.4 Other Geophysical Logging Techniques
A number of other geophysical techniques are available
for use in formation and well evaluation. These techniques
include dipmeter, nuclear magnetism, caliper, casing inspec-
tion, temperature, noise, and radioactive tracer logging
methods. Each is discussed below.
Dipmeter
Dipmeter surveys are run to determine the strike
and dip of the formation through which a borehole passes
and, accordingly, can provide valuable information in
identifying structural and stratigraphic features of the
local geography. Additionally, dipmeter surveys are capable
of identifying areas of fractures and are frequently re-
ferred to as fracture identification logs (Brown, 197b;
Beck, et al., 1977).
1 92
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7040
7050 —
7060
7070 —
7080
Figure 7.4. Acoustic televiewer log showing natural
fractures (Zemanek, et al., 1970)
193
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The dipmeter tool consists of a set of three or four
contact electrodes (pads) located on individual extension
arms, spaced equally in the plane perpendicular to the
borehole. Older tools have employed microresistivity
devices as contact electrodes, while newer tools utilize
1aterolog-type devices which allow greater penetration
and resolution. These electrodes produce individual re-
sistivity/conductivity measurements for each pad. In
addition to the contact electrodes, the dipmeter tool also
contains two caliper arms to measure borehole diameter and
devices to measure the inclination of the borehole and the
orientation of the tool as it rotates during descent into
the borehole. The typical dipmeter log will contain num-
erous curves for deviation, azimuth, relative bearing,
caliper and resistivity/conductivity (Figure 7.5).
The direction and angle of formation dip can be iden-
tified by comparing each electric logging curve provided
by the dipmeter survey. Each of the curves can be cor-
related by finding points common to each. If the formation
bedding plane is not identical to the plane common to the
individual electrodes, the curves will be displaced by a
distance characteristic of the dip and strike of the for-
mation. Analysis of dipmeter curves to quantify dip and
strike requires visual correlation of the microresistivity
curves and solution of the spatial configuration by mechan-
ical simulations, nomograms, or stereographic projections.
Interpretation of dipmeter results is now possible by
computer analysis of data recorded digitally on magnetic
tape. Discussions of dipmeter tools and analytic techniques
are available from service company publications (Schlum-
berger, 1970).
The most important application of dipmeter surveys
to injection-well construction is as a tool for fracture
identification and evaluation. A dipmeter survey locates
fractures by observing anomalies in formation conductivity.
Fluid-filled fractures at or near the surface of the bore-
hole will generally result in localized areas of hiah
conductivity which may be detected by one or more of the
dipmeter electrodes (depending on the orientation of the
fracture and position of the electrodes). As each electrode
crosses a fracture, it shows a higher conductivity curve
than shown bv an electrode in contact with unfractured
1 94
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Figure 7.5. Dipmeter log showing fracture correlation
(Brown, 1978)
195
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formation material. The various patterns of conductivity
anomalies resulting from different electrode positions as
the tool crosses the fractured zone are shown in Figure
7.6. The four-curve presentation is used to distinguish
between permeable bedding planes and vertical fractures
(Figure 7.5). Permeable bedding planes will show sharp
excursions to the left on all four curves. Vertical frac-
tures will usually be seen on only one or two curves at a
time. The four-curve presentation is also used to orient
vertical fractures with respect to compass bearing.
Dipmeter surveys (fracture identification logs) offer
many advantages over other techniques of fracture identifi-
cation. Dipmeter results give a qualitative measure of
fracturing as well as an indication of the dip and strike
of the fracture. The microfocused device utilized by
dipmeter tools gives greater resolution and a deeper range
of penetration. They are sensitive to hairline fractures
but not affected by healed fractures which may affect
other techniques and give anomalous results.
Nuclear Magnetism Logging
Nuclear magnetism logging (NML) is a technique in
which an external magnetic field is used to align (polarize)
spinning hydrogen nuclei in a different orientation than
found in the earth's magnetic field (Brown and Gamson, 1966;
Hull and Coolidge, 1960; Timur, 1969; Loren and Robinson,
1970; Loren, 1972; Herrick, et al., 1979). After the
external magnetic field is removed, the return of the nuclei
to a normal orientation is observed. These observations
allow the determination of fluid content, porosity, and
formation permeability as well as the relative amounts of
hydrocarbons and water. It is the only logging measurement
which offers a means of making a direct measurement of the
hydrogen found in the formation fluids and not that which is
adsorbed onto or chemically bound in the rock matrix itself.
NML signals can also be used to determine specif ic fluid
saturat. ions.
-------
Bedding plane or
fracture
Electrode pads
1 and 3 read low;
2 and 4 read high.
RESISTIVITY INCREASES
12 3 4
1
2
All curves
read high.
I 2 and 4 read low;
I and 3 read high.
2 and 3 read low;
I and 4 read high.
4 reads low;
I, 2 and 3
read high.
Schematic diagram showing principles of
dipmeter logging (Brown, 1978)
197
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Caliper Logging
The caliper log is a record of borehole or casing
diameter as it varies with depth. Caliper logging tools
have two to six arms or feelers which detect changes in
hole diameter as the tool is raised in the hole. Changes
in hole diameter are relayed electronically to the surface
where they are recorded. Average hole diameter and/or
the extension of individual feelers may be recorded.
Caliper logs are commonly used because they provide
informat ion essential to format ion evaluation and wel 1
design. A record of diameter over the entire depth of
a borehole allows the estimation of the amount of cement
required for completion and facilitates the use of other
geophysical logs which are dependent on hole diameter
measurements for accurate interpretation.
Caliper logs also provide information valuable for
lithologic interpretation. Changes in hole diameter are
caused by drilling techniques and lithology. Lithologic
characteristics which affect the diameter of the hole
include the degree of cementation or compaction, porosity,
presence of clay, bed thickness, vertical spacing from the
adjacent bed, and the presence and orientation of formation
fractures and vugs. For example, holes with enlarged
diameter may result from caving and indicate sands or poorly
consolidated material. Stretches of borehole with well
defined, constant diameter indicate hard rock or well-con-
solidated formations. Formations containing swelling clays
may result in loss of diameter. A build-up of wall cake,
indicating highly permeable beds, may also result in a loss
of hole diameter. Caliper logs can be instrumental in
locating fractures and solution channels in carbonate
materials. By identifying areas of structural weakness and
nonconformity, caliper logs are useful in determining packer
locations for effectively sealing the formation.
Caliper logging also has applications in cased holes.
Extremely sensitive caliper logging tools can be used
to identify casing joints and rough, corroded areas in
casing. Caliper logs can be used to detect exaggerated
distortions in the diameter of casing. Such measurements
can be useful in determining potential areas of leakage or
behind casing fluid movement.
1 9 8
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Casing Inspection Logs
Logging tools are available to assess the condition
of the casing in cased holes. The electromagnetic casing
log operates by measuring changes in the magnetic properties
of the casing (Smolen, 1976; Cuthbert and Johnson, 1975;
Haire, 1977). This is accomplished in the simpliest case by
lowering a permanent magnet wrapped with a coil of wire.
Changes in magnetic properties (largely determined by
metallic mass) of the material moving through the magnetic
field will cause a current to flow through the wire coil,
producing voltages which can be measured and recorded. This
tool can identify areas of casing damage or corrosion by
detecting changes in magnetic properties. This type of
logging tool can also be used to locate casing collars and
to provide a depth reference in the hole by marking each
casing collar. Gamma logs are generally used as a comple-
ment to collar logs to provide a reference with the sur-
rounding geologic formation. Electromagnetic casing logs
can be used to locate casing perforations or length of
screen within the well.
Another type of casing inspection log relies on de-
tecting electrical flux leakage and eddy currents produced
by casing irregularities. Still another variety which
relies on phase shifting a low-frequency electromagnetic
signal can be used to determine corrosion damage, collars,
etc.
Temperature Logs
The temperature log locates areas of fluid movement
in both cased and uncased holes by recording temperatures
(Guyod, 1946; Peacock, 1965; Cooke, 1979; Welex, n.d.). A
number of factors determine the temperature variation over
the depth of the well. A natural temperature gradient will
exist in the formation through which the borehole pene-
trates. However, a number of other factors can influence
the temperature and these additional influences make the
application of temperature logging to formation and well
evaluation useful.
Movement of fluid into a borehole from a permeable
formation will upset the normal temperature gradient in
the well. If two or more beds are contributing water
199
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with different temperatures into a well, measurements of
temperature gradients can be used to estimate the relative
flow from each bed.
In cased holes, temperature logs can detect flow
behind the casing. In an injection well, fluid which flows
along the casing and is lost through a hole in the casing or
around a packer at the bottom of the well will upset
normal temperature gradients within the well. If pumping is
stopped and the temperatures inside the well are allowed to
equilibrate with the surrounding formation, a temperature
log should identify areas behind the casing in which fluid
flow has accrued (Geraghty & Miller, Inc., 1982).
Temperature logs are run in cased holes shortly after
cementing to determine certain aspects of the cementing
job; as the cement sets, it generates heat. Temperature
logs are commonly run to identify the top of the cement and
may also identify extended areas behind the casing where
cement is not present.
Noise Logging
Noise logging is a relatively new geophysical technique
which utilizes a sensor to detect sound energy created by
the turbulent flow of fluids moving through channels, leaks,
or flow constrictions (McKinley, et al., 1973; Robinson,
1976; McKinley and Bower, 1979). The application of
noise logging of greatest interest to injection-well oper-
ators is the detection of fluid flow behind the casing.
Noise logs are obtained by lowering the device into
the cased hole, recording a noise signal at discrete points
within the well to determine the nature of flow in and
around the borehole. The device records both the amplitude
and the f requencv of the acoust i c wave. The frequencies
of greatest interest in examining fluid flow in wells
range between 300 and 6,000 Hz.
Radioactive Tracer Logging
Radioactive tracer logging is used to determine the
path taken by injection fluids by introducing a radioactive
2 0 0
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fluid into the well. The path of the tracer can be deter-
mined by identifying areas of increased radioactivity.
Radioactivity is measured by a gamma-ray sensor (background
measurements of natural gamma activity must be made prior
to injecting the tracer) to identify resulting variations
in formation radioactivity after injecting the tracer.
The tracer must be of sufficient radioactivity that its
presence can be detected over background levels of radio-
activity. Radioactive materials with a relatively short
half-life are generally used to minimize long-term effects
of the test. The most commonly used tracer is iodine 131
which has a half-life of 8.04 days.
The injection of radioactive tracers has numerous
applications, including permeability studies, evaluation
of planned fracturing, and measurement of flow between
wells. One of their primary uses in injection wells is to
detect movement of fluid through a leak at any point in the
casing or beneath the bottom of the casing or into channels
in the cement of the borehole.
7.2.5 Logging Programs
The formulation of logging programs for formation
evaluation at specific injection-well sites is dependent
on lithology, formation-fluid content, and specific data
requirements at the site. If a complete logging program
is planned to provide an extensive analysis of formation
characteristics, a resistivity survey, one or more por-
osity logs, and various other logs including caliper,
spontaneous potential, and gamma-ray logs will likely
be included. However, such extensive logging programs
may not be appropriate at injection-well sites where
logging requirements are reduced by other data collect-
ing programs or by the existing data base.
Resistivity surveys used in the more extensive
logging programs typically include shallow, medium, and
deep investigating logs. In conductive formations, the
medium deep investigating tools are generally inductive
devices while the shallow investigating tool may be either a
laterolog or a spherically-focused induction device. In
resistive formations, induction devices are not used because
of reduced effectiveness in such environments and are
replaced by guard or laterolog devices. In some areas the
older, short-normal and long-normal and lateral devices may
201
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still be in use. Microresistivity devices may also be
included in logging programs at some injection-well sites
for special analysis of wall cake and other borehole fea-
tures. Spontaneous potential logs are also typically
included in electrical surveys.
The choice of a porosity log (or logs) for inclusion
within a specific logging program depends on lithologic
complexity and an existing knowledge of formation lithol-
ogy. In simple lithologies for which basic matrix-1ithology
parameters can be assumed, a single porosity log may be
used. Choice of the specific log must be based on the
characteristic limitations each technique exhibits in
particular materials. For example, sonic logs should not
be used to determine porosity in unconsolidated and poorly
compacted sands since they perform poorly in such environ-
ments .
In situations in which the lithology is complex and
poorly understood, it is advisable to include two or more
porosity logs. Lithologic determinations are necessary
to provide correct matrix parameters, and programs including
several porosity logs increase the reliability of measure-
ments and help to determine lithology (Pirson, 1957; Raymer
and Biggs, 1963; Burke, et al. , 1969; Poupon, et al., 1971;
Harris, et al., 1971). Lithologic determinations are
possible because the response of sonic, density, and neutron
logs vary independently according to matrix compositions.
Comparison of different porosity logs taken in the same
material can yield reliable estimates of matrix mineral
composition and porosity since individual log responses are
well known. In some instances computers may be used to
facilitate such analyses.
The inclusion of other logging techniques in a specific
logging program is related to the special needs of the
injection-we 11 construction program. Perhaps the most
common need is for fracture identification and evaluation.
For this purpose dipmeter surveys (fracture identification
logs), the acoustic borehole televiewer, or spectral gamma
logs may be included in the logging program.
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7.3 DRILL-STEM,
PRESSURE, AND INJECTIVITY TESTING
A variety of techniques are available to test an
injection well under actual flow conditions. These tech-
niques can be utilized prior to setting casing to evaluate
the performance of a well. Specific data to determine
formation pressures, fluid characteristics, fracture pres-
sures, and various formation hydraulic characteristics
can be collected. These techniques include drill-stem
testing, wireline formation testing, pressure and in-
jectivity testing.
7.3.1 Drill-Stem Testing
Drill-stem testing is a technique that provides a
means of temporarily completing a well to allow formation
fluids to flow under natural formation pressures. While
developed originally to collect fluid samples, drill-stem
testing is now used to determine a number of other character-
istics including injection formation pressures, average
effective permeability, borehole damage, and permeability
changes or barriers.
An assembly connected to the drill stem which contains
a packer (or packers) to isolate a particular formation
is lowered into the borehole. A valve located in the
assembly is closed to prevent drilling fluid from entering
the drill stem and thereby maintains atmospheric pressure
within the drill-stem pipe as it is lowered into the bore-
hole. Once the packers are seated and the formation
undergoing evaluation isolated, the valve is opened to
allow drilling fluid and formation fluids to flow into
the drill stem.
The drilling fluid in the isolated zone of the bore-
hole is under the pressure exerted by the column of fluid
before seating the packers and will flow into the drill
stem as it is opened. If the formation is permeable,
fluids will enter the borehole and follow the drilling
fluid up into the drill stem. If left unchecked, the
drilling fluid and formation fluid will continue to enter
the drill pipe until the weight of the column of liquids
equals the pressure exerted by the fluids in the forma-
tion. However, the valve is generally closed in a short
203
-------
time and the pressure is allowed to build again as forma-
tion fluids flow into the isolated portion of the borehole.
A pressure guage is located in the assembly which measures
changes in pressure over time. These pressure changes
are recorded downhole and the instrument and recording
brought to the surface after the test. The valve can
be opened or closed several times and the pressure changes
recorded. After the pressure testing is completed, the
valve is closed and the packer(s) is released. The drill
stem and attached testing equipment are raised out of
the hole, bringing with it the fluid samples contained
in the drill stem. The fluid sample, which may contain
both drilling and formation fluids, is collected for analy-
sis.
Drill-stem tools with a variety of different designs
offer a variety of drill-stem testing techniques. Various
drill-stem tools are presented in Figure 7.7. In addition
to single and double packer arrangements (straddle packers),
the packers themselves may vary significantly in the way
they are expanded to seal the borehole. A variety of valve
arrangements, pressure controlling systems, and procedures
are also available. (Petroleum Extension Service, 1968 ;
Edwards and Winn, 1974).
A schematic diagram of a pressure recording taken
during a drill-stem test is presented in Figure 7.8. This
diagram shows the general form and inflection points of a
typical pressure record. As the tool is lowered into the
hole and the weight of the drilling-fluid column increases,
the pressure rises in the drill-stem tool. The tool is
seated, and the initial hydrostatic drilling-fluid pressure
can be observed (A). The drill-stem valve is opened, and the
pressure is allowed to fall as formation fluids begin to
flow into the borehole. The valve is then closed and the
pressure is allowed to build. This sequence of events is
called the initial flowing and shut-in period and is in-
tended to relieve any over-pressured conditions resulting
from drilling or setting the drill-stem packer. After the
valve is closed, the pressure builds toward the static
reservoir pressure (B).
Next the valve is opened
ing and shut-in period. The
opens, and formation fluids
flow pressure as the column
to initiate the second flow-
pressure d r ops as the valve
begin to Clow, raising the
o f fluid in t h e drill-ste m
204
-------
Y, SUB (OPTIONAL)
DRILL PIPE
-IMPACT REVERSE
'HANDLING SUB &
CHOKE ASSEMBLY
9 CLOSED IN
PRESSURE VALVE
-REVERSE CIRCULATION
PORTS
TESTER VALVE
W BY-PASS PORTS
^ »—B.T. PRESSURE
VS RECORDER
•HYDRAULIC JAR
^ V R SAFETY JOINT
-BYPASS PORTS
-EXPANDING SHOE
PACKER ASSEMBLY
• ANCHOR PIPE
SAFETY JOINT
-FLUSH JOINT
ANCHOR
-B.T. PRESSURE
RECOROER
(BLANKED OFF)
-IMPACT REVERSE
SU8 (OPTIONAL)
-DRILL PIPE
-HANDLING SUB &
CHOKE ASSEMBLY
-DUAL CLOSED IN
PRESSURE VALVE
-REVERSE CIRCULATION
PORTS
TESTER VALVE
-BY PASS PORTS
-B.T. PRESSURE
RECORDER
-HYDRAULIC JAR
-V R SAFETY JOINT
-BYPASS PORTS
.-UPPER BODY —
I PRESSURE EQUALIZER
-PRESSURE EQUALIZER
PORTS
-EXPANDING SHOE
PACKER ASSEMBLY
-FLUSH JOINT
ANCHOR
EQUALIZING TUBE
. B.T. PRESSURE
RECOROER
(BLANKED OFF)
-EXPANDING SHOE
PACKER ASSEMBLY
-FLUSH JOINT
ANCHOR
-ANCHOR SHOE
-TUBING
* IMPACT REVERSE
SUB (OPTIONAL)
-TUBING
.HANDLING SUB &
CHOKE ASSEMBLY
DUAL CLOSED IN
-PRESSURE VALVE
•REVERSE CIRCULATION
PORTS
TESTER VALVE
-BYPASS PORTS
B.T. PRESSURE
K RECORDER
¦ HYDRAULIC JAR
-V R SAFETY JOINT
-BY-PASS PORTS
-HOOK WALL
PACKER
-COLLAR
-PERFORATED
TAILPIPE
B.T. PRESSURE
RECOROER
(BLANKED OFF)
THREAD PROTECTOR
OPEN HOLE OPEN HOLE
SINGLE PACKER TEST STRADDLE PACKER TEST HOOK WALL PACKER TEST
Figure 7.7. Drill-stem testing tools (Petroleum
Extension Service, 1978)
205
-------
TIME ~
Figure 7.8. Schematic diagram of a drill-stem test (Allen and Roberts, 1978)
-------
pipe increases (C). Flow is allowed to continue for suf-
ficient time to allow adequate analysis of pressure data,
then the valve is closed (D). A gradual rise in pressure is
observed which will approach the original shut-in pressure
of the formation (E). Depending on the objective of the
test, the valve can be opened again to allow an additional
flow period to validate the original test and to allow
for more sophisticated analysis of test results. After
the test is completed, the packers are unseated and the
pressure returns to that exerted by the column of drilling
fluid in the borehole (F). The tool is then lifted out of
the hole and the pressure drops accordingly. The actual
duration of the test is variable, but generally ranges
between two and four hours in addition to the time required
to lower and raise the equipment.
Analysis of the transient pressure response observed
during drill-stem testing can be used to quantify many
of the tested formations hydraulic parameters. An equation
developed by Horner (1951) serves as a basis for much
of this analysis. The equation assumes radial flow, homog-
enous formation, steady-state conditions, infinite reser-
voir, and single phase flow and shows that:
= Pv -
162.6 Q/fcB
Kh
log
T + 0
(7-1)
where,
Pf = formation pressure during build-up T(psig)
Pr = actual reservoir pressure (psig)
Q = rate of flow (bbl/d) before shut-in
M- = fluid viscosity, centipoise
B = formation volume factor
K = permeability of formation, millidarcys
h = formation thickness, feet
T = time flow, minutes
9 = time of shut-in, minutes
If it is assumed that during the flow period steady-
state, single-phase flow occurred, the equation may be
rearranged to show that:
207
-------
M =
162.6 Qm B
Kh
pr - Pf
(7-2;
log
T + 0
The (M) value can be shown to be a constant for steady-state
T + Q
flow. If it is plotted against log g , a straight
line with a slope of m should accordingly result. Such
plots are commonly done in drill-stem transient pressure
analysis. If extrapolated to infinity, the plot should
provide the static bottomhole pressure. By determining the
slope of this line, the permeability (K) or transmissivity
(Kh) can be computed since the other components of M are
easily identified. These measurements of permeability are
generally considered superior to those obtained from core
analysis since they represent an average value over a larger
extent of the formation. These plots can also be used to
identify changes in formation permeability or flow barriers
since such conditions will result in an abrupt change in the
slope of the line. Similar analysis can be used to deter-
mine loss of permeability in the formation near the borehole
resulting from drilling procedures.
The analysis of drill-stem test data can be used to
determine a number of additional parameters and has been
widely documented in the literature. In addition to the
numerous textbooks on petroleum geology and engineering,
reference material which can be used for summary as well as
detailed discussions of drill-stem analysis are available
(Murphy, 1977; Mathews and Russel, 1967; Earlougher, 1977 ;
Society of Petroleum Engineers, 1967 and 1980).
7.3.2 Wireline Formation Testing
In the 1950s, wireline formation testing tools were
developed to provide a quick and inexpensive means for
obtaining fluid samples and rudimentary pressure data.
The tool is run into the borehole and is seated in selected
formations for which data is required. The tool can be
used to evaluate several formations during one run and
accordingly is referred to as a repeat format ion-testing
tool. The tool contains several small chambers for collect-
ing fluid samples, limiting the number of samples obtained
208
-------
by the number of collection chambers available. The tool
is seated by expanding a piston at the desired depth which
pushes the tester into the side of the borehole. A small
valve on the side of the tool is pushed into the forma-
tion to collect fluid samples. The apparatus contains
a pressure guage which transmits pressure curves back
to the surface during testing.
The use of the wireline formation tester is limited
by the capacity of the fluid collection chamber and by
the nature of the pressure data collected. Special care
must be taken to insure that fluid samples taken during
sampling are representative of true formation fluids and
not of the drilling-fluid filtrate which has invaded
the formation. To avoid collecting filtrate, fluid samples
are withdrawn during a pretest. This liquid is not
collected, but fluid pressure in the formation adjacent
to the borehole is monitored and recorded. This recording
provides data useful to formation evaluation. After the
pretest liquid is withdrawn, formation fluid samples are
withdrawn and collected at a high flow rate. Pressure
data is again collected and finally the valve is closed.
Shut-in pressures which approach natural formation pressures
are then recorded. A schematic diagram of a pressure
recording from a wireline formation tester is presented in
Figure 7.9. In a manner similar to the interpretation of
drill-stem testing, pressure and fluid samples taken during
wireline-formation testing provide information relevant
to determining formation characteristics (Moran and Finklea,
1962; Schultz, et al. , 1 975 ; Smolen and Litsey, 1 979 ).
7.3.3 Pressure Testing (Fracture Pressure Determination)
The hydraulic fracture pressure of the injection
formation can be empirically determined through pressure
tests (Earlougher, 1977). The general approach is to
gradually increase the pressure at the surface of the
formation while injecting a testing fluid until the pore
pressure overcomes natural compressive forces and matrix
tensile strength, and fractures are initiated in the rock
matrix.
A diagram representing pressure changes at the face
of the injection formation during a hydraulic fracture
209
-------
operation is shown in Figure 7.10. At the beginning of the
test, the pressure measured at the bottom of the hole is
equal to formation pressure (P0)> Pressure is raised in
the hole until the critical pressure is reached at which
fracturing occurs.
Once the fracture is initiated, pressure will drop
slightly back to a pressure (Pf) required to propagate the
fracture away from the borehole during continued pumping.
When the pump is turned off the pressure at the surface
returns to normal, but pressures at the bottom of the hole
remain high at a slowly declining shift in pressure (Ps).
In practice, pressure testing to determine fracture
pressure is performed by increasing the injection rates
incrementally and by observing downhole pressures; conse-
quently, the test is frequently referred to as a step
rate injectivity test. As shown in Figure 7.11, fracture
pressure can be determined by plotting a graph of injection
rate versus injection pressure and by identifying the
inflection point at which the increased permeability from
induced fracturing results. Generally, six to eight rates
are used to bracket the estimated fracture pressure.
7.3.4 Injectivity Testing
Injectivity testing offers a means of evaluating
the performance of the injection formation(s) during the
final stages of injection-we11 construction. Although
considerable information may be available concerning in-
jection-zone properties based on previously run coring,
geophysical logging, and drill-stem testing programs,
actual performance of the injection zone is uncertain until
pumping tests are run. Pumping tests can provide data to
determine transmissivity and storativity coefficients.
Evaluation of these coefficients is critical for determining
injection rates and pressures and for predicting the pro-
tracted regional effects of continued injection on local
formations. Pumping tests can also identify formation
damage occurring during drilling and completion procedures
which may require remedial measures such as hydraulic
fracturing or other well stimulation techniques.
The hydraulic properties of the injection formation
may be evaluated by either pumping from or injecting into
v 1 f)
-------
Flow rate
Figure 7.9. Schematic diagram of a wireline for
mation-testing pressure curve (Smolen
and Litsey, 19 79)
211
-------
\
Po
- Initial
pc
- Critical
Pf
- Fracture
ps
- Shut-in
TIME
Figure 7.10. Schematic diagram of pressure change during hydraulic fracturing
test (Smolen and Litsey, 1979)
-------
INJECTION RATE, BARRELS PER DAY
Figure 7.11. Schematic diagram of step-rate in-
jectivity test (Allen and Roberts,
1978)
213
-------
the formation. The methods of data analysis are essentially
the same for either approach. However, it is considered
advisable to duplicate operating conditions as much as
possible and formation testing is usually accomplished using
injection. Truck-mounted pumps are used for this purpose
and treated and filtered water is injected. Care must be
taken to insure compatibility between the injection fluid
and the formation fluids and matrix. Commonly, the in-
jection test begins by injecting at a rate which is a
fraction of the final estimated rate. After injecting for a
specified period of time, the injection rate is increased
incrementally over a series of similar injection periods
until the desired injection rate is obtained. Then in-
jection is stopped and the reservoir is allowed to return to
its original state. Injection rate and pressures are
recorded throughout the test, and may also be recorded
during the pressure falloff period after injection is
stopped. The data recorded during injectivity testing may
be subjected to a variety of analyses (Matthews and Russel,
1967; Lohman, 1972; Kruseman and DeRidder, 1970; Wither-
spoon, et al., 1967).
-------
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8. CLASS I INJECTION WELLS
Class I injection wells include industrial and munici-
pal disposal wells which inject fluid beneath the lowermost
formation containing an underground source of drinking
water. Historically these wells and well practices have
been referred to as deep well injection or waste-disposal
wells.
8.1 INDUSTRIAL DISPOSAL WELLS
Industrial disposal wells include those facilities
that inject industrial wastes regardless of their toxicity
or hazard to health. The use of injection wells for the
disposal of industrial wastes has received increasing
acceptance in recent years. Surveys of industrial well-
injection practices (Donaldson, 1964; Ives and Eddy, 1968;
Warner, 1972; U.S Environmental Protection Agency, 1974;
Reeder, 1975) indicate that prior to 1950, no wells were
designed specifically for the injection of industrial
wastes. During the early 1950s, a few chemical companies
began to apply well injection to the disposal of their
wastes, and by 1974, 209 industrial waste-disposal wells
were operating. While there are no current inventories of
operating industrial waste-disposal wells, it is estimated
that the number of wells may have doubled since 1 974 .
8.1.1 Description of the Practice
The increased use of industrial waste-disposal wells
has been motivated by the high cost associated with dispos-
ing of wastes by other means. For example, the disposal of
waste into surface-water bodies has been constrained by more
restrictive effluent standards. In addition, the safe dis-
posal of hazardous materials has proved to be increasingly
problematic.
The major users of industrial waste-disposal wells are
the chemical and allied products industries and oil refin-
eries. Other industries which use these wells include food
and paper, primary and fabricated metals, and machinery,
electronics, and photographic industries. The geographical
223
-------
distribution of these wells corresponds closely with the
geographical concentration of major industries and adequate
hydrogeologic conditions. The Texas/Louisiana region,
followed by the Great Lakes States, have the largest numbers
of industrial wells. Corresponding to the wide variety of
industries utilizing injection wells for the disposal of
their waste, the chemical characteristics of wastes injected
into subsurface formations vary dramatically, and include
inorganic salts, inorganic acids, caustic solvents, and a
variety of organic compounds (Donaldson, 1972).
A recent survey of geologic formations used for indus-
trial waste-disposal wells indicates that a wide variety of
reservoir rocks are used (U.S. Environmental Protection
Agency, 1974). The majority of wells are completed into
sands and sandstones; carbonate rocks are the second most
commonly used formations. Depths of injection strata vary
considerably, but 90 percent are deeper than 1,000 feet
(304.8 m) below land surface.
8.1.2 Injection-Well Site Evaluation
Selection of an environmentally acceptable site is
extremely critical for Class I injection wells. Selection
of an injection site begins with an evaluation at the
regional level, then is narrowed to the vicinity of the
site, and finally focuses upon the immediate well location.
Table 8.1 lists factors that may be used to make the region-
al and local site evaluations.
Regional Evaluation
Figure 8,1 is a flow diagram which outlines a procedure
for the regional evaluation of an injection-well site.
The "yes-no" statements are oversimplified but, in concept,
the diagram represents the procedure that is followed
(whether consciously or not) in such evaluations.
Ideally, suitable regions for C lass I wells should
satisfy the following criteria: (1) extensive sedimentary
sequence to provide an adequate injection zone and confin-
ing strata; (2) reasonably free of complex and extensive
faulting and folding; (3) injection zones containing saline
... 2 4
-------
TABLE 8.1
FACTORS TO BE CONSIDERED FOR GEOLOGIC AND
HYDROLOGIC EVALUATION OF A SITE FOR INJECTION
(Warner and Lehr, 1977)
REGIONAL GEOLOGIC AND HYDROLOGIC FRAMEWORK
Physiography and general geology, structure, strati-
gaphy, ground water, mineral resources, seismicity,
hydrodynamics.
LOCAL GEOLOGY AND GEOHYDROLOGY
A. Structural geology
B. Geologic description of subsurface rock units
1. General rock types and characteristics.
2. Description of injection horizons and con-
fining beds. Lithology, thickness and
vertical and lateral distribution, porosity
(type and distribution as well as amount),
permeability (same as for porosity), res-
ervoir temperature and pressure, chemical
characteristics of reservoir fluids, forma-
tion breakdown or fracture pressure, hydro-
dynamics .
3. Fresh water aquifers at the site and in
the vicinity. Depth, thickness, general
character, quality of contained water,
amount of use and potential for use.
4. Mineral resources and their occurrence at
the well site and in the immediate area.
Oil and gas (including past, present and
possible future development), coal, brines,
other.
225
-------
evaluation
OF REGIONAL
RATIGRAPHY ,
REGIONAL GEOLOGICAL
MAPS, SUBSURFACE
DATA, ETC.
LARGE BASIN
THICK SEDIMENT
SEQUENCE
NO
O
YES
EVALUATION OF
REGIONAL
STRUCTURE
REGIONAL STRUCTURE
MAPS, SUBSURFACE
DATA, ETC.
REGION FREE
rOF MAJOR FAULTING
OR INTENSIVE
FOLOING
YES
EVALUATION OF
REGIONAL
VHydrodynamic:
SLOW MOVEMENT
UNDER NATURAL
kH0RIZ. GRADIENT
YES
EVALUATION OF
REGIONAL
SEISMICITY
REGIONAL GROUND
WATER STUDIES,
SUBSURFACE DATA, ETC.
NO
-------
water and not
coal, etc.);
ground-water
interfering with
(4) negligible
discharge area;
mineral resources (oil, gas,
or low fluid flow, and not
and (5) low seismic risk.
The criteria used in a regional evaluation are perhaps
best discussed by application to an example. For this
purpose, the entire conterminous United States can be
subjected to a superficial evaluation (Warner and Lehr,
1977).
Synclinal sedimentary basins and the Atlantic and Gulf
Coastal Plains (Figure 8.2) are particularly favorable
sites for Class I wells. They contain relatively thick
sequences of salt-water-bearing sedimentary rocks and the
subsurface geology of these basins is well known. Other
areas may be generally unfavorable as sites for injection
because sedimentary-rock cover is absent or thin. Exten-
sive areas where relatively impermeable igneous-intrusive
and metamorphic rocks are exposed at the surface are shown
in Figure 8.2; with the possible exception of small areas,
these can be eliminated from consideration for injection.
The exposure of igneous and metamorphic rocks in the
Arbuckle Mountains, Wichita Mountains, Llano and Ozark
uplifts, south of the Canadian Shield, and others are not
extensive, but are significant because the sedimentary
sequence thins toward them and the salinity of the formation
water decreases toward the outcrops around them.
Regions shown in Figure 8.2 where a thick volcanic
sequence lies at the surface generally are not suitable
for Class I injection wells. Although volcanic rocks
have fissures, fractures, and interbedded gravel that
will accept injected fluids, they generally contain fresh
water.
The immense and geologically complex Basin and Range
Province is a series of narrow basins and intervening,
structurally positive ranges. Some of the basins might
provide injection sites, but their geology is mostly un-
known .
The geology of the West Coast is relatively complex.
Small Tertiary sedimentary basins in southern California
yield large quantities of oil and gas, and probably are
geologically satisfactory sites for Class I injection
wells. There are similar basins along the coast of northern
227
-------
/..
' 3lc'"",: ^v—v
vV--:;
5*^% / f
i /»•* 'j 1 ^
; ^L^l/! \ r-A_
1 \ j Sauna jfl
.} \ j
- »AO«»U v# UKM'C MflrMJ
**£« OuHM•!
~ tiC'-C»-: 51'4-i, »oi )•»<
'1^*1 O n«n
. /• " aiSkqma
i^mo; , / „~4——
j
J — 'MCHU^
^ WTS
( s
i ^ ••©- I
\ r' -V '/T
N«v \VJ
Figure 8.2. Geologic features significant in evaluation of Class I injection-
well siting (Warner, 1968)
-------
California, Oregon, and Washington, but little is known
about their geology.
Areas not underlain by major basins or prominent
geologic features may be generally satisfactory for Class
I injection wells if they are underlain by a sufficient
thickness of sedimentary rocks that contain saline water,
and if potential injection zones are sealed from fresh-
water bearing strata by impermeable confining beds.
Local Site Evaluation
Factors for consideration in local site evaluation
are listed in Table 8.1. Figure 8.3 is a flow diagram that
illustrates the local site evaluation procedure, but should
not be considered a rigid format.
Briefly, a potential injection site and injection
zone should have the following characteristics: (1) suffi-
cient thickness, with adequate porosity and permeability
to accept liquid at the proposed injection rate without
necessitating excessive injection pressures; (2) preferably
homogeneous (without high-permeability lenses or streaks);
(3) large enough areal extent to minimize injection pressure
and prevent the injection fluid from reaching discharge
areas; (4) overlying and underlying strata (confining
beds) sufficiently thick and impermeable to confine liquid
to the injection; (5) generally simple structural geologic
conditions (i.e., reasonably free of complex faulting
and folding); (6) area of low seismic activity and minimal
earthquake damage; (7) slow lateral movement of fluid in
the injection zone to prevent rapid movement of waste away
from the injection site; (8) formation-fluid pressure low
to normal to limit rates of undesirable reactions (e.g.
corrosion); (10) injection fluid compatible with formation
fluids and minerals; (11) formation water of no apparent
economic value (i.e., not potable, unfit for industrial or
agricultural use, or not containing minerals in economically
recoverable quantities); (12) adequate horizontal and
vertical separation from potable water zones; (13) will
not endanger present or future mineral resources (e.g.
coal, oil, gas, brine); (14) will not affect existing or
planned gas-storage or fresh-water storage projects; and
(15) no unplugged or improperly abandoned wells penetrating
229
-------
REVALUATION OF
LOCAL
^STRATIGRAPHY
DISPOSAL
'FORMATION OF
IADEQUATE THICKNESS,!
'"XTENT, PERMEAB1L"
sJTY AND POROSIT
YES
'CONFINING BEDS
OF
DEOUATE THICKNESS,
EXTENT AND
PERMEABILITY,
resT
EVALUATION
OF LOCAL
STRUCTURE
T
NO
I
\£VALUATION OF 7
\ LOCAL /—
\HYDRO DYNAMICS/
EVALUATION
LOCAL
^HYDRODYNAMICS/
l
HOMOGENEOUS
FORMATION, ADEQUATE
POROSITY, PERMEABILITY;
LOW FLUID PRESSURE;
SLOW HORIZ. MOVEMENT;
DOWNWARO OR ZERO
VERTICAL GRADIENT;
NO UNPLUGGED OLD
\ WELLS NEARBY .
€ TAILED GEOLOGICAL
MAPS, SUBSURFACE
DATA.ETC.
DETAILED
SUBSTRUCTURE MAPS
SUBSURFACE DATA,
ETC.
/ EXTENSIVE V YES f N
^FAULTING, INTENSIVE>-»—( c )
\ FOLDING /
YES ' '
.EVALUATION OF
\ RESOURCE
\PRIORIT IES
PIEZOMETRIC MAPS,
^RECHARGE/DISCHARGE
DATA, ETC.
NO
—
¦0
NATURAL RESOURCES
AND
RESOURCE USES
S SUBSURFACE
/disposal conflict-'
ING WITH RECOVERY OF
COAL, OIL, GAS, MINERALS
POTEHTIAL GAS OR
FRESH-WATER STORAGE,
FRESH-WATER RESOURCES
\OR BRINE FOR
DESALINATION
NO ESTABLISH ZONING
» '
1."FAVORABLE" ZONES
2 "RESTRICTED"
cb
0
siting MAY BE PROHIBITED, no
SUBSURFACE DISPOSAL ALLOWED
Figure 8.3. Methodology to make site-specif ic
evaluation of suitability for Class I
injection wells (van Everciinaon and
Freeze, 1971.)
-------
the disposal formation in the vicinity of the injection
s ite.
More detailed geologic and engineering properties are
examined at the local level than at the regional level. As
illustrated, in a regional examination one objective is to
identify an adequate thickness of rocks for an injection
zone and confining strata. At the local level, the objec-
tive is to identify specific potential injection zones and
confining strata and to predict their performance under
projected operating conditions. This same rationale applies
to other criteria, such as structural geology, hydrodynam-
ics, and subsurface resources.
The procedure for local evaluation of an injection-well
site should first provide documentation of the results
of the analysis of the items listed above prior to drilling
a well. Then, if the site is suitable for construction,
each item should be reanalyzed as information is obtained
during drilling and testing. The final decision whether
injection is feasible or not is based on the sub-surface
data that have been acquired during drilling and testing and
which have been used to project the response to sustained
injection of the subsurface geologic and hydrologic system.
8.1.3 Well Design
It is difficult to identify design features that can be
considered typical for Class I industrial waste-disposal
wells, since these wells differ greatly according to their
purpose and location. All such wells have some common fea-
tures and are drilled in a similar way, but the individual
well is specially designed to deal with local hydrogeologic
conditions, unusual types of wastes, or unique chemical
reactions.
The problems associated with waste and formation
compatibility have received considerable attention (Don-
aldson, 1972; Sadow, 1972; and Hower, et al., 1972). These
problems can be categorized as waste fluid and formation
fluid interactions. These may lead to a severe reduction
in formation permeability or to a loss of structural integ-
rity within the formation itself. Waste and formation
compatibility problems are specific to the particular
231
-------
formation and waste involved. Their prediction and solution
require site-specific studies. Specific problems associated
with such compatibility include plugging of the injection
formation with suspended solids, precipitation and polymer-
ization of the waste fluid, growth of biologic organisms
within the formation, and dissolution of the formation
matrix.
In some cases, the injection fluid may react directly
with the rock matrix. One common problem is the swelling
of clays from contact with the injection fluid. Affected
clays can significantly reduce the permeability of the
formation. In other instances, polar-organic compounds
can be adsorbed by the rocks, particularly silicates,
and can significantly reduce the permeability of the forma-
tion.
The injection of acids may result in dissolution
of the rock matrix. In the case of certain cemented mater-
ial, dissolution can result in the migration of particles
which then block pore spaces and reduce permeability.
Many of the wastes injected into industrial waste-
disposal wells are highly corrosive and require special
consideration during the design of all aspects of a dis-
posal system. Generally, corrosive wastes are injected
through a tubing string placed inside the well casing.
Corrosion-resistant metal alloys may be used but the use
of fiberglass-epoxy tubing has been more popular because
of its greater resistance to corrosive materials. For
further protection against corrosion, the annular space
may be filled with a corrosion-inhibiting solution.
Several examples of industrial waste-disposal wells
are presented below, selected to cover basic differences
in design by site-specific conditions and disposal needs.
Injection wells used since the mid-1950s by a northern
Florida facility which manufactures nylon have received
considerable attention (Batz, 1964; Dean, 1965}, The
facility is one of the original industrial waste-disposal
systems developed and operated in the United States, and
provides an i nteres t ing case s tudy identifying early con-
struction features and the problems first encountered in trie
construction and the operation of disposal wells. The waste
svstom &ssocicit6d with t») 0 if. 3. n u £ <3, c t u r ? * of n v 1 o n consists o £
-------
a dilute aqueous solution of organic acids, alcohols,
keytones, esters, mineral acids, and inorganic salts.
The original idea of waste injection developed from a
written report on the local subsurface geology and ground-
water resources which identified a number of limestone
formations containing saline water at a depth of approxi-
mately 1 ,400 feet (427 m), overlain by a dense clay layer
approximately 200 feet (61 m) thick. A schematic diagram of
the geological formations encountered is presented in Figure
8.4.
The well was designed with an 18 inch (5.7 cm) diameter
carbon-steel casing cemented to the upper Floridan lime-
stone, below which a 12 inch (30 cm) diameter carbon-steel
casing was cemented into the upper layers of the lower
Floridan limestone unit. An 11-7/8 inch (30.2 cm) bit was
used to drill out the remaining 200 (61 m) feet of the lower
limestone unit. An open hole configuration was used to
complete the well.
The original well design called for an 8 inch (20.3 cm)
diameter stainless-steel tubing set in a packer in the
bottom of the well. However, when the stainless-steel
tubing was installed the packer failed to seat properly,
and to avoid pulling the liner back out of the hole, an
alternative design was implemented to fill the annular space
with diesel oil pumped under pressure to prevent formation
water from entering the annulus. Several problems arose
during installation and completion of the well which were
overcome by trying different procedures. Shortly after
operation began, for example, a power failure occurred,
shutting down the pumps and resulting in the loss of the
entire charge of oil in the annulus through the top of the
well. Attempts to reestablish the column of oil in the
annulus proved unsuccessful. The tubing was pulled out of
the hole, and was found to have collapsed. A new injection
tubing of smaller diameter and greater structural strength
was placed in the hole and the packer was repaired so that
it seated correctly. In addition, a 3/4 inch (1.9 cm) pipe
was placed in the annulus between the tubing and packer,
extending from the surface to just above the packer, to
continually monitor the annular fluid at the bottom of the
hole.
The injection well has operated successfully for a
number of years, and a second well was constructed in
233
-------
18 in. steel casing
Cement lining —
Annulus filled with
diesel fuel
Stainless steel liner
12 in. steel casing
Liner hanger
*7/.
nq
B
+36 ft above mean sea level
v.- o .*• '•« ! °. ,
*•»'*.*.*. o~ J" * r *•*"«" '** ^ •
• Clay sand and gravel
420 ft!
Up per FensacoFa clay;
= 5 70 ft.-
Sand
I—^ 600ft.r^S
:LoweFPensacoTa clay!
l^Of
Lower Floridian limesfone^
Shale:
18 20ft.
gure 8.4. Schematic diagram of Class I injection
WP 1 1 chnw i nn non 1 nrrv ( Ra f 1
-------
1965 to accommodate the disposal of greater amounts of
wastes. Injection rates have risen from 600 gallons per
minute (gpm) (37.8 lps) in 1963 to 2,100 gpm (132.3 lps) in
1971. Over the years, injection pressures have dropped
while increasingly greater amounts of wastes have been
pumped into the deep aquifer indicating probable dissolution
of the injection zone.
A second example of an industrial waste-disposal
well is one used for disposal of spent pickling liquors at a
steel plant near Gary, Indiana (Bayazeed and Donaldson,
1973; Hartman, 1966; Smith, 1969). This facility disposes
of 151 gpm (9.5 lps) of waste effluent composed of a mixture
of iron salts, residual acid, and water. The waste is a
highly corrosive, toxic liquid which requires neutraliza-
tion, producing a large quantity of salt.
Construction details of the Gary, Indiana, well are
shown in Figure 8.5. A 16 inch (40.6 cm) construction
casing was used to stabilize the hole during drilling and
subsequent operations. Potable water occurs at the site
only in the surficial glacial drift which extends to a
depth of 175 feet (53.3 m). This aquifer was isolated by
setting a 13-3/8 inch (33.9 cm) surface casing into a 17-1/2
inch (44.4 cm) diameter hole drilled to a depth of 128 feet
(39 m) below the fresh-water aquifer. The borehole was
continued below the surface casing using a 12-1/4 inch (31
cm) diameter bit into the upper portion of the Eau Claire
Formation to a depth of 2,703 feet (823.9 m). The hole
was cased with a 9-5/8 inch (24.4 cm) casing and cemented
back to the surface. The borehole was extended through the
Eau Claire Formation using a 8-1/4 inch (20.9 cm) diameter
bit to a depth of 3,257 feet (992.7 m). Penetrating just
inside of the Mt. Simon Formation, the borehole was cased
and cemented back to the the surface using a 7 inch (17.8
cm), J-55, 23 pound (34.2 kg/m) casing. The well was
completed with a 6-7/8 inch (17.5 cm), open hole drilled to
the basement granite, exposing 1,611 feet (491 m) of Mt.
Simon Formation sandstone for injection.
Throughout the drilling program, drill cuttings and
cores were taken at intervals. These samples, along with
geophysical logs, were analyzed to determine the character-
istics of the geologic strata penetrated by the well.
The core samples were examined for a variety of formation
235
-------
13 3/8 in. OD surface
casing, 303 ft.
9 5/8 in. OD casing,
2,703 ft.
7in OD casing,
3 infi ft
3 1/2 in. fibercast tubing,
3.408 ft.
"Waste pickle liquor
Treated water
16 in. surface casing
Cement
T.iKin/i 4 I. . ~ ^ A
i uuiii^ uuvtiivi 9 iiuicu
Casing guide and float
shoes
Open hole
Fiaure 8.5.
Schematic diagram of ("las 53 I in lection
well at Oarv, Indiana (Raya;'eed and
i ? n a .1 i i <>n , 1 / i >
-------
characteristics, including permeability, porosity, and
solubility.
Compatability tests were run using a sample of the
waste pickle liquor. It was found that the formation
in the injection zone contained bentonitic or montmoril-
lonitic clay minerals that reacted immediately with the
waste fluid, resulting in a decrease in formation permea-
bility. The loss of permeability was not judged great
enough to significantly hinder the waste-injection oper-
ation. Tests also indicated that dissolution of the sand-
stone cements would occur with time and possibly result
in an increase in formation permeability.
After completion of drilling and sampling, the hole
was cleaned of drilling fluid and a temporary injection
tubing was set in a retrievable packer. Injectivity test-
ing was performed using filtered, processed water treated
with a biocide. After the well-performance tests were
completed, the temporary tubing and packer were removed.
A 3-1/2 inch (8.9 cm), Fibercast tubing was then set on
a fluted tubing anchor. The anchor allows flow of fluid
through the annulus between the tubing and casing so that
a hydraulic seal can be maintained. Water was pumped
through the annulus at a sufficient pressure to prevent
the injection fluid from entering the annulus.
After two years of operation, the injection facility
was found to be working as designed. The waste fluid
is filtered prior to injection, and the water injected
through the annulus is treated with a biocide to prevent
bacterial growth on the exposed surface of the injection
zone. No reduction in permeability beyond that observed
during the initial injectivity testing has been noted.
Also, no increases in permeability have been detected.
8.2 MUNICIPAL DISPOSAL WELLS
Municipal-waste disposal wells are not nearly as
numerous as industrial-waste disposal wells. The basic
location, design, and operation issues are, however, ap-
plicable to both types of wells.
237
-------
8.2.1
Description of the Practice
Increasingly stringent controls on discharges of
sewage effluents into surface-water bodies have forced
municipalities to look for more effective means of waste
treatment and disposal. In many areas of the country
including Florida, Hawaii, Louisiana and Texas, municipali-
ties have turned to the use of injection wells for the
disposal of sewage effluents. Currently the largest and
most sophisticated wells are used in Southern Florida where
the favorable hydrogeology makes the use of wells for
subsurface injection of wastes appropriate (Garcia-Bengochea
and Vernon, 1970; Kaufman, 1973).
South Florida is underlain by a series of ground-
water bearing strata of cavernous limestones and dolomites
separated by thick and impervious layers of marls and
dense limestones. Ground water in the deeper strata,
generally at depths greater than 1,500 feet (457 m), is
highly mineralized. At a depth of approximately 3,000 feet
(914 m), a particularly permeable bed of highly fractured
cavernous dolomite exists. This zone is called the Boulder
Zone because oil-well drillers have reported fractured
dolomite fragments (boulders) falling into boreholes during
drilling. Water quality is poor at this depth, and the
zone has an extremely high permeability and the capacity
to receive large amounts of waste under low injection
pressures. Consequently, a number of injection-wells
have been constructed in the area in the past decade.
8.2.2 Well Design
A municipal waste-disposal facility was constructed
in West Palm Beach, Florida, in the mid-1970s (Amy, 1980).
Development of this facility was motivated by a request
to consider alternate means of waste disposal other than
ocean outfall from EPA to the City of West Palm Beach.
The presence and character of the Boulder Zone had not
been verified in the West Palm Beach area. Consequently, a
program to explore th
-------
occurred at a depth of 3,150 feet (960.1 m) . The zone was
highly transmissive and pumping tests indicated that bottom-
hole driving pressures of 6 to 12 psi (4.1 x 104 to 8.2 x
104 N/m2) would result in injection rates of 7,000 to
10,000 gpm (441 to 630 lps).
The use of injection wells for the disposal of the
waste-water effluent of the city was determined practical,
and the city embarked on a program to construct a well
system. A two-phase construction program was used. The
initial phase called for a treatment capacity of 20 million
gallons per day (mgd) (7.56 x 104 m^/d) and for injection
into three 24 inch (61.0 cm) diameter wells. Each well was
designed for an average disposal rate of 11 mgd (4.16 x
104 m^/d) and a peak injection rate of 22 mgd (8.3 x
104 m^/d). Two wells were to operate simultaneously,
with the remaining well acting as a stand-by. The second
phase called for expanding the plant to 44 mgd (1.66 x 10^
m^/d) with the addition of two similar wells.
A diagram of a typical disposal well installed at this
site is shown in Figure 8.6. Four strings of casings were
used, the first set to a depth of about 100 feet (30.5 m) to
provide protection from washout and collapse during drilling
and subsequent operations. A 48 inch (1.2 m) diameter
surface casing was set to approximately 400 feet (121.9 m)
to seal off the fresh-water aquifer and a 36 inch (0.9) m
diameter intermediate casing was set to a depth of approxi-
mately 1 ,000 feet (305 m) . The inner or injection casing
was set into the lower portion of the confining layer
to a depth of approximately 3,000 feet (915 m) . A 24 inch
(61.0 cm) seamless or electric-resistance welded pipe with a
wall thickness of 0.375 inches (.9 cm) was used for the
inner casing. The bottom-hole completion was of an open-
hole configuration.
All casings were completely cemented in place to
provide additional protection for longer life. Because of
the thin walled casing and its large diameter, cementing had
to be performed with caution to prevent collapse. The
cementing was done in stages and the casings were pressur-
ized to prevent collapse. Cement was pumped through the
drill pipe from the lower portion of each casing to fill the
annulus from the bottom up. Upper portions of the casing
were cemented through a tremie pipe set in the annulus.
239
-------
125 ft. bottom of 54 in. casing
125 ft. bottom of 62 in. open hole
-Conductor casing
54in. O.D. 0.375 in. wall
Surface casing
42 in. O.D. 0.375 in. wall
950ft bottom of 42 in casing
953 ft. bottom of 52 in. open hole
1896 ft. bottom of 34 in. casing
1970 ft. bottom of 40 1/2 in. open hole
2820 ft. bottom of 24 in. casing
2829 ft. bottom of 32 In. open hole
¦Cement
-Intermediate casing
34 in. O.D. 0.500in. wall
Inner casing
24in. O.D. 0.500in. wall
3480 ft. bottom of 22 in. open hole
Figure 8.6.
Schematic diagram of Class I injection
well at west Palm Beach, Florida
(Amy, 1980)
-------
The Florida Department of Environmental Regulation
required monitoring of the salt-water bearing zone above
the top of the confining strata with either separate moni-
toring wells or annulus monitoring tubes. Annulus moni-
toring was selected as the least costly alternative. A zone
between 2,000 and 2,300 feet (609.6 and 701.0 m) was desig-
nated for monitoring because it was sufficiently permeable
to produce salt water. In each well, a 2 inch (4.9 cm)
steel pipe was set inside the annulus between the 24 inch
(61.0 cm) casing and the wall of the borehole to serve as a
monitoring tube. Identification of the appropriate depth
settings was accomplished using geophysical logs and drill-
ing records. The monitor tubes and cement sheaths were
directionally perforated with explosive charges to assure
communication with the formation. In some instances it was
necessary to stimulate the monitoring zone using an in-
hibited, 15 percent solution of hydrochloric acid.
An extensive suite of geophysical logs was run in each
well during construction, including induction and lateral,
gamma ray, caliper, variable density, temperature, neutron,
sonic, and denisty logs. After completion, cement-bond logs
and pressure tests were run within casings, and the wells
were surveyed using downhole television equipment. Video
tapes were made and preserved for future reference. Di-
rectional surveys were performed during drilling to insure a
straight hole.
The injection facility started operation in December
1977, disposing of an average of 10 mgd (3.78 x 10^ m^/d)
of sewage, with peak injection rates of 10,000 gpm (630
lps). Prior to injection, the static water level in
the wells was about 15 feet (4.6 m) below land surface.
After injecting for some period of time, a bubble of fresh
water accumulated in the injection formation around the
wells, resulting in a shut-in pressure at the well head of
28 to 30 psig. These pressures, generated by the density
differential between saline formation water and the injected
fresh-water effluent, represent a major component of the
total head required for injection. The remainder of the
head is needed to overcome friction loss occurring during
fluid flow down the casing and into the injection formation.
Pressure records taken from one well during the initial
phase of operation indicated a shut-in pressure of 30 psig
(2.07 x 105 N/m2 ) and an injection pressure of 43 psig
(3.0 x 105 N/m2) with an injection rate of 1 0 , 500 gpm
(662 lps).
241
-------
By 1980, this facility was disposing of 20 to 22 mgd
(7.56 x 10^ to 8.3 x 10^ m/^d) of sewage effluent. Peak
injection rates were as much as 25 ,000 gpm (1 ,577 lps)
with three wells in operation, and injection pressures were
between 40 and 50 psig (2.76 x 105 and 3.4 x 105 N/m2).
An extensive program of monitoring has been conducted, with
samples taken continuously from each annular monitor tube
using a small centrifugal pump. The conductivity of this
fluid has been recorded on strip charts, and periodic
chemical analyses have been made for chlorides, total
Kjeldahl nitrogen, sulfates, pH, total organic carbon,
hydrogen sulfide, fecal coliform, and total coliform. No
change in character of the monitor zone fluids has been
observed.
^ 4 'J
-------
REFERENCES
Amy, V. P., 1980. Disposal wells really can work. Water
and Wastes Engineering, 17(7): 20-23.
Batz, M. E., 1 964 . Deep well disposal of nylon waste
water. Chemical Engineering Progress, 60(10):85-88.
Bayazeed, A. F., and E. C. Donaldson, 1973. Subsurface
disposal of pickle liquor. Bureau of Mines, Report No.
7804.
Dean, B. T., 1965. Design and operation of a deep well
disposal system. Water Pollution Control Federation
Journal, 37(2):245-254.
Donaldson, E. C., 1964. Subsurface disposal of industrial
wastes in the United States. Bureau of Mines, Infor-
mation Circular 8212.
Donaldson, E. C., 1972. Injection wells and operations
today, _in Underground waste management and environ-
mental implications. American Association of Petroleum
Geologists Memoir 18, Tulsa, Oklahoma.
Garcia-Bengochea, J. I., and R. 0. Vernon, 1 970 . Deep
well disposal of wastewaters in saline aquifers of
south Florida. Water Resources Research, 6(5):1464-
1470.
Hartman, C. D., 1966. Deep well disposal at Midwest Steel.
Iron and Steel Engineering, December, pg 118-121.
Hower, W. F., R. M. Lasater, and R. G. Mihram, 1 972.
Compatibility of injection fluids with reservoir
components, iji Underground waste management and envi-
ronmental implications. American Association of
Petroleum Geologists Memoir 18, Tulsa, Oklahoma.
Ives, R. E., and G. E. Eddy, 1968. Subsurface disposal of
industrial wastes. Interstate Oil Compact Commission,
Oklahoma City, Oklahoma.
Kaufman, M. I., 1973. Subsurface waste water injection.
Journal Irrigation Drainage Division, American Society
Civil Engineers Procedures, 99 (IRI).
243
-------
Louis Reeder and Associates,
of deep-well injection
Environmental Protection
2013.
1975. Review and assessment
of hazardous waste. U. S.
Agency Contract No. 68-03-
Sadow, R. D., 1972. Pretreatment of industrial waste
waters for subsurface injection, _in Underground waste
management and environmental implication, American
Association of Petroleum Geologists, Memoir 18.
Tulsa, Oklahoma.
Smith, R. D., 1969. Burying your pickle liquor waste
disposal problem. Civil Engineering, 39( 1 1 ):37 — 38.
van Everdingen, R. 0., and R. A. Freeze, 1971. Subsurface
disposal of waste in Canada. Department of the Envi-
ronment, Technical Bulletin No. 49, Ottawa, Canada.
U. S. Environmental Protection Agency, 1974. Compilation
of industrial and municipal injection wells in the
United States. U. S. Environmental Protection Agency,
EPA-520/9-74-020.
Warner, D. L., 1968. Subsurface disposal of liquid in-
dustrial wastes by deep-well injection, _in Subsurface
disposal in geologic basins - a study of reservoir
strata, J. E. Galley, Ed. American Association of
Petroleum Geologists, Inc., Memoir 18. Tulsa, Oklahoma.
Warner, D. L. , 1972. Survey of industrial waste injection
wells. u. S. Geological Survey Contract No. 14-08-0001-
12280.
Warner, D. L., and J. H. Lehr, 1977. An introduction
to the technology of subsurface wastewater injection.
U. S. Environmental Protection Agency, EPA-600/2-77-
240.
-------
9. CLASS II INJECTION WELLS
Class II injection wells are used for the disposal of
salt water, for enhanced oil recovery, and for subsurface
storage of liquid hydrocarbons. In a basic sense, they are
designed, constructed, and operated similarly to Class I
wells, but with major distinctions involving the use of
special construction materials and special techniques to
reduce failure. During enhanced oil recovery, for example,
the high temperatures generated by in-situ combustion can
cause the development of strong tensile and compressive
forces and can warrant the use of high strength casing.
The following discussion highlights the characteristics,
design, and construction methods used to complete different
types of Class II injection wells. The different types of
Class II injection wells to be included under the UIC pro-
gram are associated with several oil field operations as
shown in Table 9.1.
9.1 SALT-WATER DISPOSAL
9.1.1 Description of the Practice
In oil and gas production, salt water is frequently
produced which must be disposed of. The most common
method of salt-water disposal is subsurface injection which
may be integrated with an enhanced oil recovery strategy.
The chemical composition of oil-field salt water (brine)
differs considerably from one geologic formation to another.
The major constituents of brine are sodium and calcium
chloride, but may also include magnesium, bicarbonate, and
sulfate ions. Concentrations of anions and cations in the
salt water can range from less than 100 to more than 100,000
ppm as shown in Table 9.2 (Donaldson, 1979).
Salt water can be disposed of through a well specific-
ally drilled for disposal, through a converted oil or gas
production well, or through a dry hole. When necessary, the
brine is treated prior to injection to control corrosion and
prevent plugging of the formation. An overview of such
pretreatment is discussed in Chapter 6. Injection is
accomplished either by gravity flow or by pumping the salt
water through a cased and cemented well. Generally, the
245
-------
TABLE 9.1
CLASS II INJECTION WELLS
Salt water dispoal
Enhanced oil recovery
Water Flooding
Thermal processes
-Steam flooding
-In-situ combustion
Chemical processes
-Polymer flooding
-Caustic flooding
-Surfactant flooding
Miscible displacement processes
-Miscible hydrocarbon displacement
-Carbon dioxide injection
-Inert gas injection
-Other gases such as hydrogen sulfide
Liquid hydrocarbon storage
-------
TABLE 9.2
ANALYSIS OF NATURAL BRINES SHOWING
MAJOR CONSTITUENTS (ppm)
(Donaldson, 1970)
Type of Brine Formation Location Na Ca Mg CI HCO3 SO4
Sodium chloride
Big Injun
PA
52,200
1,730
3,910
121,000
70
320
Sodium carbonate
Ellis
MT
3,140
90
80
2,890
4,040
820
Sodium sulfate
Coalinga
CA
3,290
390
340
2,520
360
7,260
Calcium chloride
Arbuckle
KS
4,230
6,900
8,430
60,100
42
1,190
Calcium carbonate
Embar
WY
140
140
30
10
210
190
Calcium sulfate
Madison
WY
580
870
180
1,070
1,080
1,940
Magnesium chloride
Lodegepole
Manitoba
44,900
3,260
67,340
94,900
2,140
4,800
Magnesium carbonate
Unita
CO
450
428
542
90
1,185
1,038
Magnesium sulfate
—
NM
100
1,000
25,000
9,000
0
60,000
-------
best formations for injection are pressure-depleted aquifers
or depleted oil-producing zones (API, 1978).
9.1.2 Well Design
Commonly, Class II injection wells are completed
as open hole, perforated casing, or perforated liner.
In unconsolidated formations, a screened and gravel packing
completion may be used.
Major problems encountered during salt-water disposal
involve the formation of precipitates and the deposition of
scale on the formation, reducing the permeability of the
injection zone and inhibiting injection. The use of a
pretreatment system can control this problem.
Other problems result from well design and construc-
tion, especially corrosion of materials when converting a
former production well into an injection well. Corrosion in
salt-water disposal wells can occur both internally and
externally. Internal corrosion is primarily a result of
oxygen in the injection fluid contacting the casing or
tubing. External corrosion is caused by oxygen or by
sulfate-reducing bacteria in the environment surrounding the
well. If the salt water also contains carbonates and/or
hydrogen sulfide, the rate of corrosion can be greatly
accelerated.
Internal corrosion in salt-water disposal wells can
be controlled by removing the oxygen from the brine or
by adding corrosion inhibitors such as bactericides to
eliminate sulfate-reducing bacteria. Oxygen removal is
i s accompii shed by a treatment sy s tem; however, if such
systems are too costly, use of materials such as plastics or
cements to coat the casing to eliminate contact with the
oxygen-bearing brine could be considered (API, 1973).
However, pinholes can develop in the coatings and can permit
corrosion to occur. Stainless steel alloys also have a
greater resistance to oxygen corrosion than other carbon-
steel materials and are frequently more useful than coating.
A more successful method of controlling corrosion is to
utilize a tuning string, preferably of fio e r g1 ass-epoxy
resin, run through the center of the well casing to trans-
port injection fluids from the wellhead to the inject ion
zone. For this type of well completion even greater pro-
-------
tection against corrosion is afforded by isolating the
annulus between the tubing and injection casing. This is
accomplished by setting a packer at the bottom of the
borehole between the tubing and the casing to seal off
the annulus from the injection zone. The annulus then can
be filled with an aqueous solution containing a corrosion
inhibitor. Placing the annulus under observation (either
pressure or fluid flow) also enables monitoring for leakage
(Donaldson, 1979).
Conversion of an oil or gas production well to a
salt-water disposal well is common in oil-field operations.
Often it is less expensive to convert a depleted well or
a dry hole than to drill a new well. In addition, the
mechanical condition of an existing well, including casing,
cementing, and choice of the injection zone, may be ideally
suited for salt-water injection. In other instances, the
well may be in poor condition (inadequately cased or ce-
mented) to function safely as a disposal well (Bachman,
1980). This may be particularly true in the conversion of a
dry hole (i.e. a well drilled and not completed for pro-
duction) to a disposal well (API, 1978).
Conversion of an oil or gas production well to a salt-
water disposal well must include a thorough examination of
the structure of the existing well and the receptivity of
the injection zone. Existing records of the methods of
completion of the production well and the nature of the
geologic environment may not be adequate to assess the
suitability for conversion. Mechanical integrity tests and
geophysical logging methods have been established to pro-
vide information concerning the structure of the well and to
determine what, if any, remedial construction is necessary.
Often the existing well may not have been fully cased
or cemented to the surface to provide adequate protection of
underground sources of drinking water required during
salt-water injection. Squeeze cementing techniques are
used in these instances to selectively cement certain zones
between the borehole and the casing. Several different
types of specialty cements have been developed to facilitate
successful squeeze cementing including pozzolan, thixo-
tropic, and expanding cements.
249
-------
9.2 ENHANCED OIL RECOVERY
9.2.1 Description of the Practice
Enhanced oil recovery encompasses a broad spectrum
of technologies designed to increase the yield of crude
oil from existing reservoirs. The technologies vary from
conventional secondary recovery techniques, such as water
flooding, to more sophisticated tertiary recovery methods
such as polymer or surfactant flooding. However, all of
the enhanced oil recovery methods do have a singular common
feature; that is, the utilization of a well to provide a
means of injecting a liquid or a gas into the formation to
produce a drive mechanism to increase oil production. The
four principle enhanced oil recovery methods are flooding,
thermal processes, chemical processes, and miscible dis-
placement processes.
Enhanced oil recovery methods differ widely in the
total quantity of oil produced by each and also in the
stage of technological development of each. In addition to
water flooding, steam flooding is one of the most widely
used methods in the United States [140,000 to 160,000
barrels per day (2.22 x 10 to 2.54 x 10 m per day)]
(Dafter, 1980). In California, tne number of steam injec-
tion wells has risen from 140 in 1966 to 1,630 in 1975 (van
Poolen, 1980). Conversely, chemical processes are limited
and account for less than one percent of the enhanced oil
recovered in the United States (van Poolen, 1980).
Water Flooding
Water-flooding operations utilize the injection of
water to restore reservoir pressure or to maintain pressure
to increase oil recovery. The source of water for injection
is the brine produced with the oil, brackish water from
other sources, or fresh water. Injection wells for water
flooding are usually installed in a grid pattern, witn lour
injection wells surrounding a production well. Durino
operation, water is pumped into the in]i?ction wells ana a;;
it moves toward the product ion well, it force:; tne oi I
aheaa. Produced water is separatee t rorr. tne oil ana re-
2 50
-------
cycled for injection. Water flooding will continue until
the process is no longer economical.
Thermal Processes
Thermal-recovery methods are used primarily to reduce
the viscosity of the oil in place. By adding heat, oil
trapped by capillarity in the reservoir is thinned or
vaporized and becomes mobile. The oil can then be dis-
placed by injected liquids or gases (van Poolen, 1980).
The three types of thermal recovery operations are cyclic-
steam stimulation, steam flooding (including hot water
flooding), and in-situ combustion (fire flooding). Within
the UIC regulatory framework, cyclic steam injection
is considered a production-well stimulation method and is
not covered in this discussion.
Steam flooding is similar to water flooding except that
steam is injected rather than water. Steam is injected into
a number of wells arranged in patterns compatible with
adjacent production wells. Near the injection wells, the
steam forms a saturated zone with a temperature nearly equal
to that of the injected steam. As the zone expands toward
the producing wells, the temperature drops in response to a
pressure decrease; consequently, a series of zones develops
as shown in Figure 9.1. In the steam zone, oil is displaced
by steam distillation and gas. In the hot water zone,
thermal expansion of the oil, reduction in viscosity,
reduction in residual saturation, and changes in relative
permeabi1ity result in oil recovery. In addition, the
heat transferred to the reservoir rock can heat cold water
subsequently injected into the system and provide an addi-
tional recovery mechanism (hot water flood) (van Poolen,
1980; Dafter, 1980).
In-situ combustion or fire flooding involves injecting
air into the reservoir and then igniting the oil to gen-
erate heat. There are two fundamentally different processes
of in-situ combustion, forward combustion (dry combustion)
and reverse combustion (as shown in Figures 9.2 and 9.3,
respectively). In forward combustion, air is injected
and the burning front moves toward the producing well.
Typically, temperatures generated at the burning front
range from 600°F to 1200°F (315°C to 630°C), causing the
lighter fractions of oil ahead of the flame front to vap-
orize, leaving the heavy, residual coke and carbon deposit
251
-------
STEAM
Hot water zone
Steam zone
| | Oil and water zone
OIL AND WATER
4
Fiqure 9.1. Schematic cliaqram of trie steam Hood
_ ( r> fi. ~ 1 fl Q H ]
orocess ('jci i... l.ci f ± J -
-------
CROSS SECTION OF FORMATION
INJECTION WELL PRODUCTION WELL
Figure 9.2. Schematic diagram of the forward in-situ combustion process
(van Poolen, 1980)
-------
as a fuel. As combustion proceeds toward the producing well,
the heated oil is recovered.
Reverse combustion was developed to improve recovery of
extremely viscous, heavy crude oil. Like forward combus-
tion, the process is begun by injecting air into the reser-
voir. After burning out a short distance from the inject-
tion well, it is switched to a production well and air
injection is continued through an adjacent well causing the
flame front to move in an opposite direction to the air flow
(Figure 9.3) (Dafter, 1980; van Poolen, 1980).
Chemical Processes
Chemical processes to achieve enhanced oil recovery
include some of the most complex and least proved recovery
methods. Essentially, chemical enhanced recovery methods
are water-flood operations with chemicals added to the
injection water to increase the efficiency of oil recovery.
Chemical processes consist of three main techniques known
as surfactant/polymer or micellar/polymer injection, poly-
mer flooding, and caustic or alkaline flooding. Although
commercial applications of these techniques have been
undertaken, most of the projects have been directed toward
research.
Surfactant/polymer injection involves the injection
of surfactants (soap-like chemicals) in combination with
polymers. The surfactant lowers the interfacial tension
between the oil and the water in the reservoir and thereby
mobilizes oil trapped by capillary forces. The purpose
of the polymer is to buffer the integrity of the surfactant
slug and to provide more effective piston-like displacement
of the oil (Gogarty, 1978; van Poolen, 1980). The sur-
factant/polymer displacement process is shown schematically
in Figure 9.4.
Polymer flooding is essentially an improved water-
flood technique. Polymers added to injection water are
used to increase viscosity, to improve sweep efficiency,
and to reduce the total volume of water required to reach
ultimate residual oil saturation. The two types of poly-
mers used are polysaccharides and polyacry1 amides. Unlike
ordinary water which has a tendency to channel through
the most permeable parts of the reservoir and bypass large
-------
Injection well
Production well
Figure 9.3. Schematic diagram of the reverse in-situ combustion process
(van Poolen, 1980)
-------
INJECTION FLUIDS
Drive water zone
Water/polymer zone
[ | Surfactant slug zone
~ Oil and water zone
OIL AND WATER
Figure 9.4.
Schematic diagram of the surfactant-
polymer displacement nrocess (Dafter,
1980)
-------
volumes of oil, the polymer-thickened water is less prone
to channeling and is consequently a more efficient pushing
agent (Dafter, 1980; van Poolen, 1980).
Caustic or alkaline flooding is a technique which
alters the pH of flood water by the addition of chemicals
such as sodium hydroxide, sodium silicate, or sodium car-
bonate. Existing water floods can be easily converted
to caustic floods by the addition of 1 to 5 percent sodium
hydroxide. Typically the pH of the flood water is main-
tained between 12 and 13. Although the recovery mechanisms
are not well understood, potential lowering of inter-
facial tension, wettability changes, emulsification and
entrapment, emulsification and entrainment, and solubil-
ization the rigid films of the oil-water interface are
achieved. All of these processes are thought to relate to
the formation of surfactants in the reservoir which arise
from the alkaline chemicals neutralizing the acids in the
oil in the injection water (Dafter, 1980; van Poolen, 1980).
Miscible Displacement Processes
Miscible displacement processes employ miscible hydro-
carbons, carbon dioxide, and inert gas as solvents to
dissolve oil, to reduce interfacial tension and capillary
forces and to permit increased recovery. Miscible dis-
placement processes were developed in the late 1940s and
early 1950s for oil fields containing light crude. Cur-
rently, the number of projects involving inert gas injection
has grown, while hydrocarbon miscible projects are de-
creasing due to limited supply and high cost. Carbon
dioxide miscible flooding may potentially recover 40 percent
of the total projected enhanced oil reserves in the United
States (van Poolen, 1980). Figure 9.5 shows the process
of carbon-dioxide injection.
During the injection of miscible fluids including
hydrocarbons (e.g., naphtha, kerosene, or alcohol), carbon
dioxide, or inert gas (nitrogen), oil is dissolved with
the solvent to form a single substance; hence, capillary
forces are overcome because there is no interface between
the oil and solvent. Recovery is completed by following
solvent injection with water and/or gas to drive the dis-
solved substance toward the production well. Pressures in
the reservoirs can range from 1 ,500 psi (1.03 x 10^ N/m^)
257
-------
Injected CO2 and water zone
Ppl CO2 - crude oil miscible zone
J Oil and water zone
Figure 9.5. Schematic diagram of the carbon dioxide
-------
for carbon dioxide displacement to more than 4,000 psi
(2.76 x 107 N/m^) for hydrocarbon displacement. As with
the other enhanced recovery methods, these processes
include injection wells that convey the solvent to the
reservoir and that dispose of produced brines (Dafter,
1980).
9.2.2 Well Design
Injection wells used in different enhanced oil-recovery
operations are designed to consider such factors as types of
injection fluids, temperatures, and likelihood of corrosion.
Wells used for steam flooding and in-situ combustion
air injection must be designed to withstand high temper-
atures. Both types are subjected to ambient temperatures
during construction that are substantially lower than those
encountered during operation. Excessive temperatures
generated by steam injection and fire flooding range from
400 ° F to 700°F (204°C to 371°C) and from 750°F to 2000°F
(398°C to 1092°C), respectively (Allen and Roberts, 1978).
Such temperatures exert a number of stresses on the well
which may include compression or expansion causing pull-out
or buckling of the casing, cracking of cement, strength
retrogression of cement, and corrosion rate increases. In
addition, to achieve the most efficient operation, heat loss
through the borehole is undesirable.
To withstand the stresses exerted by high temperatures
during operation, casing and cementing programs can be
selected that provide protection against well failure.
Heavier grade casing such as K-55, N-80, or P-105, plus
specially threaded buttress connections can withstand
compressive and tensile strengths exerted during heating
and cooling (Allen and Roberts, 1978). Data on the range of
temperature various grades of casing can tolerate are
presented in Table 9.3.
Use of good cementing procedures is also important
to insure well integrity (Farouq, 1979). In general,
cement should be circulated to the surface, with specially
designed slurries placed in zones where high temperatures
are being generated. The cement slurry may include an inert
filler, such as silica flour, to arrest strength retro-
gression. Where loss of heat through the borehole is
undesirable, perlites or vermiculite can be added to provide
259
-------
TABLE 9.3
ALLOWABLE TEMPERATURE CHANGE AT SHOE
(Farouq, 1979)
Casing
Willhite*
Gates
*
Grade
CP)
(°
C)
(°
F)
(°
C)
H-40
170 - 200
77
- 93
170
- 230
77
- 110
J-55
240 - 275
116
- 135
250
- 310
121
- 154
N-80
350 - 400
177
- 204
370
- 480
188
-249
S-95
410 - 475
210
- 246
-
-
P-110
—
—
520
- 630
271
- 332
* Various experimenters
-------
a more efficient thermal insulating barrier between the
casing and the formation (Halliburton Services, 1981).
Injection wells used for steam and air thermal recovery
processes are used for disposing of water produced during
operation. These are generally designed as salt-water
disposal wells. Schematic diagrams of both a steam injec-
tion and a fire flood injection well are shown in Figures
9.6 and 9.7, respectively.
In chemical enhanced-recovery processes, injection
wells are used for directing the flood water as well as for
disposal of produced water. Surface equipment for this
process is designed to blend and to inject the chemically-
treated water. In flooding, corrosion of well equipment and
casing may be more pronounced from the presence of sodium
hydroxide or other alkaline chemicals. A detailed dis-
cussion of alkaline corrosion has been provided in Chapter
6.
Caustic-flooding injection wells are designed to
minimize corrosion by selecting appropriate construction
materials. Particular grades of casing, such as C-75 and
epoxy-resin fiberglass reinforced pipe, have exhibited a
higher resistance to corrosion than common steel. Coatings
or liners of cement or plastic materials can also reduce
susceptability to corrosion. Further protection can be
attained by using a corrosion-resistant cement such as
a non-aqueous epoxy-resin based cement. Epoxy-resin cements
are highly resistant to caustic and mineral acids, solvents,
and other corrosive materials (Western, Co., 1981).
Miscible-displacement injection wells generally are
designed like other standard injection wells. Corrosion,
however, can also be a major problem to carbon-dioxide
injection wells. Stainless steels and other special metal
alloys, plastics, and/or coatings may be required to reduce
the rate of corrosion and to increase casing longevity. In
addition, the organic solvents used for hydrocarbon dis-
placement injection are corrosive to plastic materials,
which prevent their use in organic-solvent injection
wells.
261
-------
Ground surface
Figure 9.6. Diagram of steam injection well used in
the Cat Canyon Field, Ca11fornia
2 f> 2
-------
Figure 9.7. Diagram of fire-flood injection well
used in the Lynch Canyon, California
263
-------
9.3 LIQUID HYDROCARBON STORAGE
9.3.1 Description of the Practice
For some time, petroleum products have been stored
underground in large caverns in soluble rock formations
created by solution processes. Generally, stored petroleum
products have included natural gas liquids such as ethane,
propane, and butane. The Federal government's Strategic
Petroleum Reserve Program targets crude oil for extensive
underground storage [up to a billion barrels (1.6 x 10-
m3)] (Medley, 1978).
Storage caverns can be developed in rock formations
like shale, limestone or granite, but salt deposits are most
commonly used. The caverns may be mined specifically for
storage or may exist as a result of commercial brine pro-
duction. Typically, the caverns are from 100 to 150 feet
(30.5 to 45.7 m) in width and extend vertically around the
injection well for several hundred feet (several hundred
meters) (m). In addition to the use of injection wells for
storing hydrocarbons, wells may be used to dispose of the
brines produced during cavern formation and to fill the
cavern with product. Injection and withdrawal of hydrocar-
bons and brine can be conducted separately or simultaneously
(Gas Processors Association, 1975; Geraghty & Miller, Inc.,
1977).
For a hydrocarbon storage operation to work success-
fully, caverns must be completely sealed and impervious
to prevent injection fluid loss. Completing high quality
wells through cap rock overlying the salt dome is often a
complex undertaking, Protection of the roof of the cBveirn
and the pipe can be provided by floating a light hydrocarbon
blanket above the leaching zone.
9.3.2 Well Design
To provide maximum protection against vertical escape
of injected hydrocarbons into fresh-water bearing forma-
tions, injection wells are usually fully cased and cemented
with several different sizes of casing. As shown in
Figure 9.8, the casing and cement program of a hydrocarbon
4
-------
Figure 9.8. Diagram of hydrocarbon-storage injection
well
-------
storage well is more extensive than those associated with
either salt-water disposal or enhanced oil recovery.
The well generally consists of an inner string of casing
set within the salt body and cemented to the land surface,
surrounded by as many as four or five other strings of
casing set above and on top of the cap rock which are
also cemented to the surface. Prior to use the casings and
the caverns are pressure-tested and periodically there-
after. Injection and withdrawal can be conducted simul-
taneously through the tubing and annulus to control the
brine that is displaced as the hydrocarbons are injected
(Geraghty & Miller Inc., 1977).
^ t * )
-------
REFERENCES
Allen, T. 0., and A. P. Roberts, 1978. Production oper-
tions, Volumes 1 and 2. Oil and Gas Consultants,
Inc., Tulsa, Oklahoma.
American Petroleum Institue (API), 1978. Subsurface salt
water injection and disposal. Dallas, Texas.
American Petroleum Institute (API), 1980. Primer of oil and
gas production. Dallas, Texas.
Bachman, A. L., 1980. Proceedings of the workshop on
subsurface disposal of geopressured fluids. Louisiana
State University, Baton Rouge, Louisiana.
Dafter, R. , 1980 . Scraping the barrel: the worldwide
potential for enchanced oil recovery. Financial
Time's Business Information, Ltd., London, England.
Donaldson, E. C., 1979. Subsurface disposal of oilfield
brines and petrochemical wastes. Department of Energy,
Report No. DOE/EV 0046, Volume 1, Bart1esvi1le,
Oklahoma.
Farouq, S. M. , and R. F. Meldau, 1979. Current steamflood
technology. Journal of Petroleum Technology, October,
pg. 1332-1342.
Gas Processors Association, 1975. Tentative method for the
underground storage of natural gas liquids. Tulsa,
Oklahoma.
Geraghty & Miller, Inc., 1977. Preliminary evaluation of
well injection practices. U. S. Environmental Protec-
tion Agency, Contract No. 68-01-5071, Washington, D.C.
Gogarty, W. B., 1978. Micellar/polymer flooding—an over-
view. Journal of Petroleum Technology, August, pg.
1089-1101.
Halliburton Services, 1981. Cementing compositions for
thermal recovery wells. Duncan, Oklahoma.
267
-------
K. van Poolen, and Associates, 1 980 .
of enhanced oil recovery. PennWell
Oklahoma.
Fundamentals
Books, Tulsa,
Medley, A. H., 1978. Crude oil storage in salt domes,
in Proceeding of the API 1978 Pipeline Conference,
Houston, Texas.
Western Company, 1981. Stimulation and cementing services
product bulletins. Ft. Worth, Texas.
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10. SELECTED CLASS III AND CLASS V INJECTION WELLS
Class III and Class V Injection wells discussed in this
chapter are utilized in the production of energy or the
extraction of minerals. Industrial processes, injection
practices, and conditions applicable to the use of these
wells are widely variable and involve both commercial
operations and technologies that are still being researched
and developed. Additionally many utilize the injection of
non-hazardous materials such as water or oxygen. The tech-
nologies described in this section are restricted to Frasch
sulfur, solution mining with fresh-water solvents, solution
mining with chemical solvents, in-situ combustion of fossil
fuels, and geothermal energy development.
10.1 FRASCH SULFUR INJECTION WELLS
10.1.1 Description of the Practice
The Frasch sulfur-mining process is used commercially
along the Gulf Coast of Texas and Louisiana, and in western
Texas. The process, developed by Herman Frasch at the turn
of the century, accounts for about two-thirds of the United
States' sulfur production. The Frasch process is used
primarily to recover sulfur from deposits in the limestone/
gypsum portions of the caprock of salt domes. The sulfur is
obtained by injecting hot water to melt it, allowing it to
be pumped to the surface.
10.1.2 Well Design
The Frasch process utilizes a single-well system
to simultaneously inject hot water and air and to recover
the sulfur (Figure 10.1). A borehole is drilled to the
top of the caprock overlying the sulfur deposit. Casing is
seated in the top of the caprock, and the borehole is
extended to the bottom of the sulfur deposit. Casing is
installed in the borehole and the lower end is perforated
with small diameter holes in two separate zones. A packer
is used to seal the casing between the two zones of perfora-
tion. A smaller diameter pipe is placed through the
269
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Figure 10.1. Schematic diagram of" a Frasch sulfur
well
2 7 U
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packer to channel the melted sulfur to the surface inside of
which is another pipe for the injection of compressed air.
The mining process is initiated by pumping super-
heated water [325°F (163°C)] down the well assembly where
it flows out both perforated zones into the sulfur-bearing
deposit (Figure 10.1). When the temperature of the
sulfur reaches or exceeds 246°F (119°C), the liquid sulfur
flows by gravity into the bottom of the well. Pumping water
down the inner casing is discontinued at this point, and
the liquid sulfur is forced into and partially up the
inner casing by the pressure from the hot water. Compressed
air is injected then to aerate the sulfur so that it will
rise to the surface.
Construction characteristics of Frasch production
wells differ with operators, individual projects, and
geological conditions. For example, the surface casing and
tne outer injection casing are in some instances fully
cemented and in others cemented only at the shoe. In gen-
eral, casings are cemented only as needed, mainly where
there are high formation pressures or pressure losses
within the production zone (Geraghty & Miller, 1980).
As the sulfur matrix is mined, the caprock may weaken
enough to collapse under the weight of the overburden, which
in turn may collapse. Depending on the depth and degree of
compaction, the settlement may be propagated to the land
surface as subsidence and cause sheared casings and ultimate
loss of the well. Operators generally separate their wells
into groups to limit their exposure to a sudden formation
movement (Donner and Wornat, 1973; Shearon and Pollard,
1950).
The injection of super-heated water results in signif-
icant casing expansion and contraction. The well-casing
program, therefore, must be compatible with such high-temp-
erature operation. The tubing and packer installation also
must be compatible with any temperature cycles likely to
occur to prevent tubing elongation or contraction which
could unseat the packers.
Although liquid sulfur is not corrosive to well equip-
ment, the combination of water and air injected in the lift
process is highly corrosive to steel. In addition, the
formation water produced with the sulfur can be corrosive to
steel, especially at elevated temperatures. Cement-lined
271
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pipe or special alloys are used in some operations to avoid
premature loss of wells (Donner and Wornat, 1973).
10.2 FRESH-WATER SOLUTION-MINING WELLS
10.2.1 Description of the Practice
Solution mining by injection of fresh-water solvents
is used in producing minerals such as sodium chloride,
potassium chloride (potash, sylvite), sodium carbonate
(trona), and phosphate. The techniques may be extended to
other water-soluble minerals in future applications.
Sodium chloride (salt) is mined using a single-well or
a multiple-well system and is practiced from depths ranging
from several hundred feet (100 m) to about 10,000 feet
(312.5 m) in both domed and bedded salt deposits.
Potash is produced using either single-well or mul-
tiple-well solution-mining systems and has been tested
in New Mexico, Europe, and Canada (Davis and Shock, 1970;
Husband, 1973). Potash is selectively extracted from
beds associated with other soluble materials such as sodium
chloride. The potash is mined by injecting a sodium-
chloride brine that selectively dissolves potash and leaves
sodium salts behind. Mining efficiency can be increased by
heating the brine to increase potash solubility.
Phosphate deposits are less suitable to classical
solution-mining techniques than are sodium and potassium
salts. In fact, the in-situ production of phosphate min-
erals involves the physical break-up of the mineral deposits
by a water jet and pumping the slurry to the surface. This
experimental technique, known as borehole slurry mining, is
being tested in the phosphate deposits of Florida under a
research program by the Bureau of Mines (Anonymous 1980).
Phosphate resources occur throughout the coastal
plain regions of the southeastern United States. Two
regions in particular have been identified by the Bureau
of Mines as potential areas tor in-situ d e ve 1 oprcent.
These include the deposits of central Florida and those of
eastern North Carolina (Kasper, et al., 1979).
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10.2.2 Well Design
Single-well solution-mining techniques utilize the
same borehole for both injection and production. Because
the areal extent of the solution process is quite limited,
this method is best suited for very thick-bedded formations
or dome-like deposits (Davis and Shock, 1970; Geraghty
& Miller, Inc., 1980). Multiple-well solution-mining
systems utilize one or more wells for production and a
separate set of wells for injection of the fresh-water
solvent.
Single-Well Systems
There are four basic single-well systems for solution
mining, top annular-injection, bottom injection, trump,
and bottom annular-injection (Figure 10.2). Which system is
utilized depends on geology and mining strategy. The top
annular-injection method is the type commonly used for
salt-solution mining (Jacoby, 1973).
Well construction for all methods is similar. A
conductor or surface casing is installed through the un-
consolidated overburden into bedrock using either the
cable-tool or the rotary-drilling method. After the casing
is in place, it is cemented to the surface and allowed
to set. Drilling is then continued into the top of the
salt formation where an intermediate casing string is
set and cemented back to the surface. Drilling is con-
tinued to the bottom of the salt deposit or to a specific
design depth. The borehole is then equipped with one
or more free-hanging strings of tubing extending from
the surface to a point near the bottom of the borehole
(Jacoby, 1973). Typical casing sizes are presented for a
bottom-hole injection system in Figure 10.3.
After completion, water or brine is injected through
the annulus or down the central tubing. The product is then
recovered up an annulus or up the central tubing.
Single-well mining of salt deposits presents various
unique considerations including control of cavern geom-
etry, corrosion, and cement incompabilities. Without
proper control of solution-cavern geometry the structure
273
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mining (Jacobv f 1973)
274
-------
Water in
275
-------
can collapse, damaging the casing and possibly propagating
subsidence to the surface.
Logging operations are useful in determining cavern
orientation (Hicks, 1974; Caldwell and Strobala, 1966). The
existence of any insoluble zones can be detected which could
collapse and cause casing damage. Logging techniques can
help define the geometry of the cavern roof, an aid to avoid
roof collapse and shearing the casing.
The injection of high salinity brines makes the
control of electrochemical corrosion in solution-mining
wells important. Cathodic protection methods have been
suggested for use (Titterington, 1963). (See Chapter 6 for
more information. )
Drilling and cementing operations in salt mining
require special fluids or additives to avoid formation
incompatibility (Davis and Shock, 1970; Baker and Smith,
1974; Laswell, 1976). The use of water-based drilling fluids
with low ionic content can lead to expansion of associated
clay and to dissolution of salt materials.
Cement additives are necessary to attain proper cement
bond with sufficient strength qualities. Sodium chloride
is a commonly used additive when slurries are expected to
contact fresh-water sensitive shale, and clay, as well as
salt formations. The addition of salt can also improve
early strength development and allow turbulent flow patterns
at lower velocities that are important in setting a homogen-
eous cement sheath. In addition to sodium chloride,
other cement additives and circulation practices are devel-
oped specifically for salt applications. Oil-well service
companies have extensive experience in this area and are
best qualified to prescribe the proper grouting program for
each specific case.
Multiple-Well_Svsterns
The multiple-well method is commonly used in sol Lit ion
mining of thin-bedded deposits of sodium chloride and
potash. One or more pairs of injection and recovery wells
interconnected by hydraulic fracturing techniques are
commonly used (Shock, 1966; Henderson, 1974; Manker 1966;
Davis and Shock, 1970).
-------
Injection wells are generally constructed with one
or more strings of cemented casing. Wells used for frac-
turing or for high-pressure fluid injection have tradi-
tionally been completed with a tubing and packer or with a
tubingless arrangement. Operations using fluid to fracture
the formation require a casing with sufficiently high
burst strength to withstand the pressures. Fracturing may
be accomplished in open hole or through a perforated inter-
val in the casing. In either case, the casing string is
exposed to the pressure and corrosiveness of the brine.
In operations where tubing and packer are used, the
fracture is initiated in an open hole. By using the tubing
and packer method, a thin-walled casing can be installed
since it is not subjected to initial injection pressure.
Also, the cement behind the casing is not exposed to frac-
ture pressures which presents less opportunity of migration
in a poor cement job.
Experience has shown that failures of hydraulic frac-
turing operations can occur as a result of inadequate
cementing practices, structural weakness of the media
leading toward fractures propagating in wrong directions
(i.e. outside the salt zone), existence of downward vertical
fractures allowing fluid to escape into heavily fractured or
permeable formations, and improper placement of the frac-
turing well in relationships to the production well (Hender-
son, 1963). Special siting, logging, and well-construction
procedures are employed to avoid these problems. A protec-
tive blanket of oil can be floated over the leached zone to
limit the vertical migration of the solute. Washouts can
occur if this protective blanket rises past the cemented
string in wells completed without tubing and packer.
Slurry Mining
Slurry or borehole mining refers to the process in
which a deposit of insoluble but relatively soft mineral
is reached by a borehole and is broken down by the injection
of a high-velocity stream of water. The resultant slurry of
ore and water is pumped to the surface for processing as
shown in Figure 10.4. Borehole mining is an experimental
technique which has been tested on coal, uranium (Savanick,
1979), and phosphate deposits.
277
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Recovered slurry
High pressure supply to jet
/ / /
Figure 10.4. Schematic diagram of the hydraulic
borehole slurry mining (Kasper, et
al., 1979)
2 7 B
-------
A hole of sufficient diameter to accomodate the hy-
draulic jetting tool gives access to the ore. Typically,
an 18 to 24-inch (44 to 59 cm) diameter hole is drilled to
approximately six feet (1.8 m) below the mineral-bearing
strata. A casing is installed above the ore body to prevent
caving of the overburden. The section of the hole within
the ore body is not cased. The cutting-jet assembly is
positioned in the hole at the end of a rigid service column
containing the necessary conduits for pressurized water and
for transport of the slurry to the surface. The lower
section of the cutting jet assembly contains the slurry pump
which is installed in the hole below the ore body. After
the mining unit is positioned in the borehole and the
above-ground equipment is installed, the high-pressure
water, slurry, and hydraulic connections are made.
Normally, the underground mining operation is begun
with the jet set at the lowest position. The jet rotates
and cuts material through an arc of 200 to 300 degrees
leaving a segment of unmined material to support the over-
lying strata. The material is removed to a radius of
up to 76 feet (23 m), depending on the properties of the ore
and the pressure, nozzle, shape, and diameter of the jet
system. After the material is removed, the jet is raised to
reach the next level of ore. The slurry is pumped to the
surface where it is decanted for processing. The decanted
water is recycled and used for slurrying new ore. Treatment
requirements for this water are minimal since low concen-
trations of suspended solids do not interfere with the
jetting operation.
The duration of mining in a borehole is a function
of the ore characteristics and the capacity of the jetting
apparatus. Kasper, et al. (1979) projected that a borehole
46 to 77 feet (14 to 23 m) in diameter could be completely
mined in 8 to 24 hours, assuming an ore zone 30 feet (9 m)
thick.
10.3 CHEMICAL-SOLVENT SOLUTION-MINING WELLS
10.3.1. Description of the Practice
Uranium and copper are the two principal metals
mined by the use of chemical solutions injected through
279
-------
wells. Uranium is being extracted on a commercial scale in
several states; however, copper leaching has been largely
experimental except for a few small commercial systems
which are not in operation at present because of market
conditions and depletion of the ore deposits. Other metals
that may eventually prove suitable for mining by in-situ
leaching are gold, silver, aluminum, and nickel/cobalt.
Uranium
In—situ solution mining is a practical and economic
method of extracting uranium from low grade ores. The
process involves the injection of an acidic- or an alkaline-
leach solution (lixiviant) into the uranium-bearing forma-
tion. A complex salt solution, formed by the lixiviant and
the dissolved uranium, transports the uranium from the host
rock. Production wells remove the uranium-bearing solution
from the subsurface for recovery of the uranium at a surface
facility* Bon ©fits of in~situ mining include a. smaller"
capital cost for deep or small scattered deposits, low labor
costs, improved worker safety, short preparation time,
and fewer environmental impacts (e.g., disturbance of the
land surface or disruption of surface runoff) (Larson, 1978;
Huff, et al., 1980). However, careful monitoring is
essential to prevent the toxic lixiviants from polluting
potable water-bearing zones.
Leachable uranium deposits are found in sandstone
formations associated with mountain-front, near-shore
marine, and deltaic environments, as well as intermontane
basins (Galloway, et al., 1979). Uranium mineralization
occurs as elongated, narrow lenses often less than a few
hundred yards (few hundred meters) in length (Thompson, et
al., 1978). The uranium ore is found in "roll-type" depos-
its along the margins of a reducing ground-water environ-
ment. The dominant uranium minerals associated with the
roll-type deposits are uraninite and coffinite, a uranium
silicate. The ore bodies are generally found at depths
ranging from tens of feet (a few meters) to several thousand
feet (hundreds of meters) below land surface.
-------
Copper
In-situ copper leaching techniques are different
in many aspects from the methods used in solution mining of
uranium, primarily a result of the competency of the
rocks in which copper occurs. The copper-bearing rocks of
low permeability generally require fracturing by explosives
before effective leaching operations can be started.
More than 80 percent of the copper production of
the world comes from porphyry copper deposits (Kasper, et
al., 1979) which occur as hydrothermal veins and replacement
deposits in the western United States. Porphyry copper
deposits are found along the mountainous Cordilleran Belt
from Alaska to Central America. These deposits are also
an important source of associated metals such as molybdenum,
gold, and silver.
The techniques chosen for recovering copper depend
largely on the type of geologic setting of the ore body.
Depths of wells may range from tens of feet (a few meters)
to thousands of feet (hundreds of meters). In many places
lixiviants are applied to dumps by sprinkler systems rather
than by injection wells, and other wells are used to recover
the pregnant solutions.
Three general types of in-situ copper leaching mining
environments are described by Wadsworth (1977). Type
I deposits occur above the water table with ore bodies
having one or more sides exposed. This type of deposit is
leached by pumping solvent into boreholes, by surface
spraying, or by surface flooding. The pregnant solution is
extracted by a pump in a product well.
Type II deposits are located below the water table
but are generally less than 1,000 feet (305 m) deep. These
deposits may require extensive fracturing, and the copper
rubble may be leached by injection of lixiviants such as
iron solutions, oxygen, and sulfuric acid. The copper-
enriched solutions are recovered through wells. A major
difficulty with Type II deposits is predicting flow patterns
after fracturing for complete removal of the copper solu-
tions and prevention of excursions of toxic leachate into
underground-sources of drinking water.
281
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Type III deposits occur below the water table but are
too deep for conventional mining operations. Following
fracturing by conventional explosives, hydrofracturing, or
chemical dissolution, lixiviants are injected under high
pressure into the rubble and the pregnant solutions are
extracted by recovery wells.
10.3.2 Well Design
Well drilling for in-situ uranium leaching is generally
performed by rotary drilling methods, except in areas
of competent rock where percussion drilling may be employed.
Bentonite muds, guar gum, polyanionic cellulose polymers,
air, and foam drilling fluids have been used in drilling
in-situ wells (Tweeton and Connor, 1978; Larson, 1978).
Upon completion of the drilling, natural gamma, resistivity,
and caliper logs can be run to determine a suitable depth
for installation of a screen or open hole for injection.
Casing selection is based upon the depth of the well,
casing strength, and corrosion resistance. At shallow
depths, PVC casing is generally used, although fiberglass-
reinforced pipe, carbon steel, or stainless steel can
be used because of their greater strength (Huff, et al.,
1980; Larson, 1978; Tweeton and Connor, 1978). Corrosion-
resistant tubing and packers are used with carbon steel
casing or where carbon steel is used in combination with
fiberglass or stainless steel casing, to prevent casing
deterioration from the leaching solution. Casing diameters
of uranium leaching wells generally range from 2 to 7 inches
(5.1 to 17.8 cm).
1 I' \7 3 1 1x7 T1 11 T~\ A A V" Q D \ V" 4" 1 ¦> »•> /-J x—n m i r« i i r« /N ^ y
¦«. j v- «-«. j. a j f x V h- r\ w l. i_> cul Lianij v-ciucii l j. o uaSu i.v^L
cementing in-situ wells, but if an acid solution with a
pH of less than 2 is to be used as the lixiviant, epoxy
cement can be used (Huff, 1980). The well is checked for
leaks and the cement is allowed to harden, after which
the cement plug at the base of the casing is drilled out.
Depending on the type of bottom-hole completion, the bore-
hole below the casing may be under reamed and cleaned, a
liner may be installed, or a screen may be pi aced be1ow
the cement.
Well design takes into account the d i a m e t. e r o f the
pumps installed and the screen openings needed to prevent
2P2
-------
sand invasion of the borehole. Injection well designs
also consider the corrosiveness of leaching solutions on the
well screens. Virtually every type of well completion
has been used with uranium leaching operations. Figure
10.5 illustrates the various techniques used.
Pilot-test operations are generally conducted before
production-scale leaching operations begin. The pilot
leacning operations are commonly run for a four to five
month period to determine recovery and operating parameters
(e.g. injection rate and pressure). Various injection/
recovery well configurations are used to achieve the best
hydraulic and economic returns.
Depending on ore body shape and size, the patterns of
wells may be a five-spot (four injection wells surrounding a
recovery, or production well), seven-spot, or thirteen-spot
configuration (Figure 10.6). Irregular patterns of wells
may be needed in places for localized variations in the
shape of the ore body. The leach pattern is selected to
maximize recovery but does not affect aquifer quality if all
injected fluid is recovered.
Copper
There are no representative designs of wells that are
used for copper-leaching operations. Some wells consist
of 150 to 200 foot (45.7 to 61 m) holes cased with 2 inch
(5.1 cm) PVC pipe. Others may be several thousand feet
(hundreds of meters) deep with stainless steel casing
(Apian, et al., 1974), and others may not be cased. The
copper is leached with either sulfuric acid or ammonia
solutions. Advantages of each lixiviant solution are
described in the literature (Kasper, et al., 1979; Apian, et
al. , 1974; Schuffman and Rowden, 1973).
Figure 10.7 shows assemblies of injection and re-
covery wells for mining copper. Figure 10.7A shows mining
of native copper. Following the fracturing of the ore body,
a production well is drilled to the base of the fractured
zone for collection of the copper-bearing solution. Figures
10.7B and 10.7C present potential configurations of wells
for leaching copper in an abandoned mine or in fractured
rocks.
283
-------
Fiqure 10.5.
Examples of; m-situ
wells (Larsen, 19 78
uranium leachinq
2 84
-------
A. DIRECT LINE DRIVE
B. STAGGERED LINE DRIVE
Y
t i
-o-
i
— o —
— o —
o-
I
I
. O
o-
I
¦ o —
0 ¦
1
-o
I
I
o-
I
-o
I I
O-
d
• i—
— o — —o
-~ X
C. 5" SPOT
Figure 10.6.
• Production well
o Injection well
Y
/ _
o o o o
• I • I • I • I
o O o
0 0«- "
1 • I • Td 4---> •
^o^o-4-„-0-o
• I • I • I • I
o-0-o-°-o-0-o-0
0 o o o
• I • ! • I • I
<3 c> a o
1 • I • I • I •
o o o o
D. 7-SPOT
Well patterns for in-situ leach mining
of uranium (Thompson, et al., 1978)
285
-------
A.
C.
igure 10.7. Well programs for in-situ l-"*ach mining
o f c o p p e r (K a spe r, 19 7 9)
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10.4 IN-SITU COMBUSTION OF FOSSIL FUELS
Three principal fossil-energy resources, oil shale,
coal, and tar sand, are under experimental consideration for
in-situ combustion. The physical and geological character-
istics of these resources and their unique development
requirements present specific demands on injection-well
design and construction.
10.4.1 Description of the Practice
Oil Shale
Research and development activities in the field of
in-situ combustion of oil shale have focused on two princi-
pal techniques, in-situ retorting and modified in-situ
retorting. A generalized in-situ retorting process is
illustrated in Figure 10.8. The process consists of several
steps (DOE, 1977; U. S. Office of Technology Assessment,
1980; Baughman, 1976; Burwell, et al., 1973; Lekas, 1979).
The first step is to drill down and fracture the retort zone
to form rubble. The retort is ignited, producing hydro-
carbons which are then recovered and separated from undesir-
able byproducts.
Modified in-situ retorting of oil shale generally
involves mining a small part of the zone to be retorted and
then fracturing the remaining shale to create a highly
permeable zone (DOE, 1977; Baughman, 1976; U. S. Office of
Technology Assessment, 1980; Occidental Petroleum, 19 79;
Ashland Oil, 1976). Retorting the column is then initiated
by igniting the shale and combustion is sustained by in-
jecting air and gas into the zone. A conceptual drawing of
the modified in-situ retorting process is shown in Figure
10.9.
In-situ combustion of coal consists of two principal
steps, a preparation process (in which permeability is
induced) and actual gasification. Permeable pathways
or links in the coal seam between the injection and the
production wells can be created by reverse combustion,
hydrofracturing, directional drilling, or other techniques.
287
-------
ure 10.8. Schematic diagram of in-situ retorting of oil shale (Jee, et
al., 1977)
-------
CO
kO
RETORTED BLOCK
BLOCK BEING RETORTED
BLOCK UNDER DEVELOPMENT
Figure 10.9. Schematic diagram of the modified in-situ retoring process for
oil shale (DOE, 1977)
-------
The general concept which is illustrated in Figure 10.10
is referred to as the linked-vertical well method.
The steeply-dipping bed concept (Figure 10.11) is
designed to gasify beds of coal that have a steep angle
of dip from the land surface. Obvious advantages of this
method are the placement of injection wells below the
seam where they are unaffected by subsidence, and drilling
the output boreholes down the easily-penetrated coal seam.
Increased production is achieved from a number of modules
operating side-by-side that are linked by drilling or
by combustion along the bottom of the gasification zone
(Wieber and Sikri, 1977).
The packed-bed process uses fracturing techniques
for increasing permeability in coal seams. Explosives are
used in this process so that flow can occur through a
uniformly packed bed. This results in the exposure of the
coal to the gases over a large surface area for long con-
tact periods. The packed-bed process uses steam/oxygen
injection at the top of the fractured bed with flow down
the bed and toward the lower periphery as shown in Figure
10.12 (Wieber and Sikri, 1977).
In-situ combustion of coal involves two principal
types of injection wells, combustion-zone injection and
produced-water disposal. The injection wells entering
the combustion zones are widely variable in design. They
are used for various purposes, including initial combustion
zone preparation activities (e.g., hydrofracturing) and air
and steam injection during processing. Produced water-
disposal wells are necessary to return waters from artific-
ial drawdown operations, whicn are usually required in the
combustion process.
10.4.2 Well Design.
Oil Shale
In the modified in-situ process
from shale, access wells are drilled
mined retort. These wells may be several nunared teet to
over one thousand feet (hundreds o f m e t ors) deep. In
initial experiments both eased and op«n-hole wells have
for recovery of oil
into the top of the
-------
Figure 10.10. Conceptual diagram of in-situ combustion of coal (DOE, 19 80)
-------
No. I air inlet
Strata cracking
and subsiding
No. I air inlet used
for first phase of
gasification
Ash and clinker
in burn out area
Gas offlet (in different
vertical plane than air
inlets)
No. 2 air inlet for
second phase of
gasification
Coal seam
Reaction zone
Strata subsiding into
burn out area
Original end of gasification borehole
Fi aure 10.11. Conceptual diagram of coal gasification in steeply dipping
beds (Wieber and Sikiri, 1977)
-------
Pipeline gas
Oxygen plant
Gas
purification
plant
to
kO
UJ
Coal and shale
Water plant
Reaction zone
Figure 10.12.
Conceptual diagram of packed bed coal gasification
and Sikri, 1977)
(Wieber
-------
been used with varying success; further study in well design
and construction is being made during the technology re-
search and development process. Retort conditions do not
expose the wells to high pressures although high tempera-
tures are encountered. Specific design requirements will be
available as more experimental retorts are developed.
Well design is different in true in-situ retorting.
The wells are actually drilled into the shale or the retort
zone. The wells are cased to the top of the shale bed
and are cemented to the surface. The specific design of the
wells depends on the depth of the resource and the selected
fracturing techniques (Jee, et al., 1977); however, addi-
tional research and development activities will determine
the final design characteristics. The longevity of the
access wells in a high-temperature environment should be
determined as part of this process.
Subsidence of retorts could impact the integrity
of injection wells. The production of large volumes of
shale from continuous beds could lead to caving or compac-
tion and ultimately, subsidence. Short-term subsidence
could cause disruption of the injection wells in the retort
zone. Long-term subsidence propagated to the surface could
lead to further disruption of injection wells and other
wells in the area (Rothman, 1975).
Coal
In-situ coal conversion wells are completed in high-
temperature combustion zones and are exposed to subsidence.
These wells are subjected to temperatures of up to 2735°F
(1500"C) for several hours. During ignition, the base of
the injection well will undergo an initial thermal cycle
reaching as high as 1112 F (600 C). Conibusjliun ul cudi in
the vicinity of any commonly used casing material (carbon
steel) will cause its rapid deterioration, by sulfidation,
oxidation, and melting. High temperatures also cause
problems wi tn surface valves and wellheads. Struct ur a 1
failure can result from thermal expansion of the casing.
Dur ing the receding portion of the therma 1 cycle, e o n -
traction forces can exceed trie u 1 t i m a t -¦? s t r e n g t h of t h e
casing and cause rupture. In addition, overburden drying
gsnsiTcilly cdus^s the n ti bond to shrinK &nd pcirt,
ating leakage paths to upper level aquifers and eventually
-------
to the surface (Hill, et al. , 1978 and 1980). High tem-
perature cements and special casing materials are under
experimentation.
The potential failure modes noted have been partially
addressed in the design of the well shown schematically in
Figure 10.13. The highlights of this design include:
an improved high-temperature resistant cement for casing
emplacement; a casing liner installed through the length of
the well and suspended from the wellhead flange with the
lower end unsupported allowing free vertical movement; the
annulus formed between liner and casing provides an insula-
ting barrier between process gases and the casing; the lower
section of the liner assists in protecting the well from
exposure to high temperatures; and the liner serves as
insurance against casing failure by enhancing the reli-
ability of the well to serve as a conduit with the coal
seam reaction zone (Hill, et al., 1979).
10.5 GEOTHERMAL ENERGY DEVELOPMENT
10.5.1 Description of the Practice
The four principal geothermal resource areas being
commercially developed or researched are hydrothermal
(hot-water), geopressured, hot dry rock, and dry steam.
Exploration of these diverse resources involves innovative
technologies and presents different demands on injection-
well design and construction (Glorioso, 1980).
Nearly all commercial electric power generated from
geothermal sources is from the Geysers field in northern
California and is of the vapor-dominated or dry-steam
variety. The only other large scale geothermal electrical
power produced in the United States is a hydrothermal/
geothermal demonstration. Plants are under development
throughout the United States, but are not yet producing
electrical power commercially.
Known and potential hydrothermal resources of the
nation are indicated in Figure 10.14. Most of the high-
temperature prospects are located in the western states and
have the most potential for electrical-power generation.
However, lower grade [less than 194°F (90°C)] geothermal
295
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iO 3/4 in. casing liner
3 in. injection liner
Coal seam
9 5/8 in. sump liner
Wellhead assembly
20in. borehole
HTR cement
^ 13 3/8 in. J55 casing
Drilled hole reamed
to 12 in.
Figure 10.13. Schematic diagram of an in-situ coal
conversion well (Hill, ot. al., 1979)
19 6
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N>
V£>
—]
Potential low to moderaK
temperature targets
Figure 10.14. Known and potential hydrothermal resources (DOE, 19 80)
-------
resources may be useful in direct-heat applications, the
most rapidly developing area of geothermal energy.
Geopressured geothermal resources are found in sedi-
mentary basins in which abnormally high temperatures 248°F
to 347°F (120°C 175°C) and pressures [9,000 to 15,000 psi
(6.2 x 10' to 1.0 x 10^ N/m^)] are found (Figure 10.15).
Fluids from these zones also contain large amounts of
methane that may be economically recoverable. Current
research and development plans are considering a combined
program of methane, hydromechanical, and hydrothermal
energy recovery. However, the development potential is not
proved and the commercial potential is uncertain (Wallace,
et al., 1978; U. S. Department of Energy, 1981; Dorfman and
Deller, 1976; House, 1975).
The hot dry rock geothermal resource consists of
the heat stored in rocks that contain insufficient water
to transport heat to the land surface. The concept is
illustrated in Figure 10.16, and involves drilling into
the hot rock zone, developing permeability through frac-
turing, and circulating a heat-transfer fluid, usually fresh
water, through a heat-exchanger in a closed loop configura-
tion. This process is currently in the research and devel-
opment stage. The resource base for hot dry rock systems is
potentially large.
Injection wells related to geothermal energy develop-
ment are used for various purposes and, consequently,
have differing design characteristics. In hydrothermal
reservoirs, produced waters are commonly reinjected into the
original reservoir to maintain pressure and to limit forma-
tion compaction. These pressure maintenance wells are
similar in purpose to those used in secondary oil recovery.
Depending on geothermal or reservoir engineering require-
ments, produced fluids may be disposed of in other strata.
Waste—disposa1 wells may also be used in disposal of conden-
sate from geothermal power plants. Geopressured resource
development also requires the disposal of large quantities
of fluid, usually in an overlying formation. Pressure
maintenance wells also have been considered in geopressured
aquifer development. Development of hot dry-rock systems
requires welIs to inject the heat-exchange fluid into the
thermal area.
-------
to
V£>
Figure 10.15. Geopressured basins in the United States (Wallace, et al., 1978)
-------
Figure 10.16. Conceptual diagram of a dry rock geo-
thermal onsircjy irccovcrv (AFC f 197^)
Ju U
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10.5.2 Well Design
Well design elements are closely related to the geo-
thermal practice and the nature of the fluids. The chemical
make-up of geothermal and geopressured fluids is likely to
contribute to corrosion and scaling of well casings. In
fact, disposal wells may be more prone to corrosion than
production wells since the fluids pick up oxygen from
exposure to air in the power plant. Research is being
performed to develop corrosion-resistant metals for geo-
thermal energy development (Eliezer, et al., 1979; Deffer-
ding, 1980).
Geothermal and geopressured brines contain up to
325,000 ppm of total dissolved solids, including carbonates
and sulfates of calcium, strontium, and barium. Erosion
of tubing and casing can occur if these dissolved solids
precipitate or if sand is present in the injection fluid
(Bachman and Smith, 1979). Hydrogen sulfide is also present
in many geothermal fluids at levels above concentrations
regarded safe to structural stability (<2-5 ppm) which can
be a potential problem in geothermal-disposal well construc-
tion, and should be reflected in material selection.
High-strength materials are also more susceptible to sulfide
cracking than less hardened steels (Defferding, 1980; Reed,
1975) .
Material selection for use in geothermal disposal
systems should also include consideration of the severe
corrosiveness of brines to carbon-steel casing, and par-
ticularly to stress-corrosion cracking. Stress-corrosion
cracking is the failure by cracking of a material that is
under constant tensile stress. Crack propagation and
failure may occur after only a few minutes or after months
or years (Defferding, 1980).
Injection rates, pressures, temperatures and pretreat-
ment must be optimized to maintain corrosion control,
injectivity, and well competency. Factors beneficial
in corrosion inhibition could adversely affect scaling which
to some extent, mitigates corrosion by providing a protec-
tive barrier (Reed, 1975).
Drilling and casing methods must be specially adapted
to hot geothermal or geopressured areas. In geopressured
applications, blowout prevention equipment must be properly
301
-------
installed as large pressure surges or kicks can occur if
a geopressured zone is penetrated. Drilling equipment
must include a cooling tower for drilling fluid as high
temperature zones will result in fluid degradation and in
lack of cooling properties when contacting formation walls.
In geothermal drilling and casing, most problems
arise from high temperatures, lost circulation zones, and
contamination of the cement. In general, cement should be
installed to the surface on all casing strings. Uncemented
casing can fail from thermal expansion and buckling when
unsupported, or contract and pull apart when cooled (Shryock
and Smith, no date). To mitigate expansion and contraction
problems, casing should be selected that has a modulus of
elasticity (or expansion potential) matched to the expected
temperature of the fluid.
Cementing procedures and materials are critical in
geothermal well design and construction. Some cementing
materials may exhibit a satisfactory compressive strength
when first set, but will begin to lose this strength when
continually exposed to high temperatures. As this occurs,
cement permeability will decrease until the cement column
can no longer prevent communication. This phenomena
requires the use of specialty cements or additives, such
as silica flours (Shryock and Smith, n.d.).
Well completion methods must also allow for widely
varied and high temperatures. Tubing expansion and con-
traction must be considered to prevent ballooning or helical
buckling. Packers that depend on tubing weight or tension
for setting strength can be unseated during expansion and
contraction; an expansion receptacle is critical to prevent
losing the seal. Additionally, special thermal-seal packers
are designed for high temperature operation in corrosive
conditions.
Figures 10.17 illustrates several designs of geothermal
wells that can be used either for production or injection.
The figures indicate the use of both liners and open hole
configurations. Also, both tubing and packer and through
casing injection may be employed.
-------
Conductor Casing
20m.- 26 in. hole
Surface Casing
13 3/8 in.-17 1/2 in. hole
8uttress thread
K-55 - 61 ppf
2,000-2,500 ft-
Producfion Liner
9 5/8 in.- 12 |/4in. hole
Buttress Thread
36*40 ppt
5,000- 5,800 ft.
Open Hole
8 3/4 in
BHST 450-525° F
7,000-10,000 ft.
Expanding well head
Surfoce
API class G cement
3% calcium chloride
API class G
40% silica flour
2% calcium chloride
Intermediate
class & cement
35% silica flour
cubic ft. perlite
3% bentonite
Friction reducer
Liner - Lead Slurry
API class G cement
40% silica flour
( cubic ft. perlite
3% bentonite
Friction reducer
Retorder
Tail In Slurry
"API class G cement
40% silica flour
Friction reducer
Retarder
Conductor Casing
55-66 ft .
20in.-30ia hole or
!8ia in 22 in hole
Surface Casing
290 - 300 ft -
l6in.-22 in. hole or
13 3/8in."l71/2 in. hole
Intermediate Cosing
1200-1700 ft —
Production casing
4700-6000 ft.
5 1/2 in.-9 7/8 in. hole
7 7/8 in.-10 5/8 in. hole
APt class A or G cement
Sometimes 30% silica flour
rAPl class A or G cement
-< 30% silica flour
l-Lost circulation material
CAPI class A or G cement
) 30~4O% silica flour
0.3% retarder
1,0.75% friction reducer
Two stages
API class G or E cement
40% silica flour
Retarder as needed
Perlite if needed
Same material used on both
stages
BHST - 500 to 700* F
Conquctor Casinj
I00*300ft.
2l ii .- 26 in. hole
H-4c -94 ppf
Surface Casing
3000 " 3200 ft.
13 3/8 in.-17 1/2 in. hole
K-55 " 61 ppf.
Buttress thread
Intermediate Cosing
6000-6500 ft.-
9 5 '8in.-!2 1/4 in. hole
N-80- 43.5 ppf
Hydril SEU
Production Liner (Mech. Hanger)
7 in. set in 8 1/2 in. hole
Hydril SEU
9780 ft.
BHST - 600-650°F
Expanding well head
h
'API class G cement
40% silica flour
.Cement friction reducer
JriLC cement
:m , / 40% silica flour
\ \ Cement friction reducer
r l^Fluid loss agent-retorder
1st Stoge-
APt class G cement
40% silica flour
Filler additive
Friction reducer
Bentonite
Fluid loss agent
I
s- 2nd Stage -
j API class G cement
I I cubic ft perlite
-/ Bentonite
\ Friction reducer
Fluid loss agent
^ Retarder
Liner
API class G cement
40% silica flour
Filler additive
Friction reducer
Bentonite
Fluid loss agent
igure 10.17.
Design of geothermal energy wells (Shyrock and
Smith, n.d.)
303
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