NWWA/EPA Series
Methods for Determining
the Mechanical Integrity of
Class II Injection Wells
David M. Nielsen
Linda Aller
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EPA-600/2-84-121
July, 1984
METHODS FOR DETERMINING THE MECHANICAL
INTEGRITY OF CLASS II INJECTION WELLS
David M. Nielsen
and
Linda Aller
National Water Well Association
Worthington, Ohio 43085
Cooperative Agreement CR-809353
Project Officer
Jerry Thornhill
Ground Water Research Branch
Robert S. Kerr Environmental Research Laboratory
Ada, Oklahoma 74820
This study was conducted
in cooperation with
East Central University
Environmental Research Institute
Ada, Oklahoma 74820
ROBERT S. KERR ENVIRONMENTAL RESEARCH LABORATORY
OFFICE OF RESEARCH AND DEVELOPMENT
U.S. ENVIRONMENTAL PROTECTION AGENCY
ADA, OKLAHOMA 74820
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DISCLAIMER
Although the research described in this report has been funded wholly
or in part by the United States Environmental Protection Agency through
cooperative agreement CR-809353 to East Central University Environmental
Research Institute. it has not been subjected to the agency's peer and
policy review and therefore does not necessarily reflect the views of the
agency and no official endorsement should be inferred. nor does mention of
trade names or commercial products constitute endorsement or recommendation
for use.
i i
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FOREWORD
The Environmental Protection Agency was established to coordinate
administration of the major Federal programs designed to protect the
quality of our environment.
An important part of the Agency's effort involves the search for
information about environmental problems, management techniques and new
technologies through which optimum use of the Nation's land and water
resources can be assured and the threat pollution poses to the welfare of
the American people can be minimized.
EPA's Office of Research and Development conducts this search through
a nationwide network of research facilities.
As one of these facilities, the Robert S. Kerr Environmental Research
Laboratory is the Agency's center of expertise for investigation of the
soil and subsurface environment. Personnel at the laboratory are
responsible for management of research programs to: (a; determine the
fate, transport and transformation rates of pollutants in the soil, the
unsaturated zone and the saturated zones of the subsurface environment; (b)
define the processes to be used in characterizing the soil and subsurface
environment as a receptor of pollutants; (c) develop techniques for
predicting the effect of pollutants on ground water, soil and indigenous
organisms; and (d) define and demonstrate the app1icabi ,ity and limitations
of using natural processes, indigenous to the soil and subsurface
environment, for the protection of this resource.
This report contributes to that knowledge which is essential in order
for EPA to establish and enforce pollution control standards which are
reasonable, cost effective and provide adequate environmental protection
for the American public.
C1 inton W. Hall
Di rector
Robert S. Kerr Environmental
Research Laboratory
i i i
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PREFACE
Methods for Determining the Mechanical Integrity of Class II Injection
Wells has been developed under the guidance of East Central Environmental
Research Institute, in conjunction with the U.S. Environmental Protection
Agency, for use by all of those involved in efforts to determine the
mechanical integrity of injection wells. Techniques described are those
which are currently in use and methods which may be of future significance.
For those concerned with protecting ground water, this document may be
helpful as a ready summary of ways to help ensure that injection wells do
not have a leak in the casing, tubing or packer and that no significant
fluid movement behind the casing exists. Finally. this manual partially
fulfills a mandate contained in the Safe Drinking Water Act (P.L. 93-523)
reauiring the Administrator of the Environmental Protection Agency to
1I...carry out a study of methods of underground injection which do not
result in the degradation of underground drinking water sources.1I
iv
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ABS TRAC T
The Underground Injection Control program regulations,
administered by the U.S. Environmental Protection Agency, require
injection well operators to test the mechanical integrity of injection
wells, including those wells that inject fluids 1) brought to the
surface during oil and gas production, 2) for enhanced recovery of oil
and gas and 3) for storage of ~drocarbons in the subsurface (Class II
wells). Testing is required to satisfy the regulatory requirement
that there is no significant leak in the casing, tubing or packer, and
that there is no significant fluid movement through vertical channels
adjacent to the injection well.
There are a number of methods available to injection well
operators for mechanical integrity testing. These include monitoring
of annulus pressure, pressure testing, temperature logging, noise
logging, pipe analysis surveys, electromagnetic thickness surveys,
caliper logging, borehole television, borehole televiewer, flowmeter
surveys, radioactive tracer surveys and cement bond logging. Only
temperature logging, noise logging and radioactive tracer surveys can
be utilized to provide relatively definitive information regarding the
presence or absence of fluid movement behind casing; cement bond logs
provide information from which fluid movement may be inferred. With
the exception of cement bond logging, all of the testing methods can
be used to locate leaks in casing.
This document describes each of the methods that can be used in
mechanical integrity testing in detail, including the principles.
equipment, procedures, interpretation, cost, advantages and
disadvantages and examples of each technique. Other methods which may
also have application in mechanical integrity testing, but which
require additional field testing to establish their effectiveness, are
also described. Many of the described mechanical integrity tests are
not adaptable to the testing of hydrocarbon storage well systems.
During the last few years, rapid development of specialized testing
procedures has changed the state of the art considerably. Therefore,
a discussion of storage well testing methods is not included in this
document.
This report was submitted in partial fulfillment of Contract No.
CR-809353 by the National Water Well Association under the sponsorship
of the Robert S. Kerr Environmental Research Laboratory, Ada, Oklahoma
and in cooperation with East Central University Environmental Research
Institute, Ada, Oklahoma. This report covers a period from December,
1981, to December, 1983, and work was completed as of December, 1983.
v
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vi
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CONTENTS
Disc 1 a; mer. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. ; ;
F 0 rewa rd . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . i ; i
P ref ac e . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. ; v
Abstract. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. v
Figures. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . viii
Tab 1 es . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. x; v
Acknowledgements. . . . . . . . . . . . . . . . . . . . . . . . . . . xvi
1. Introduction. . . . . . . . . . . . . . . . . . . . . . . . . .
2 . Co nc 1 us ion s . . . . . . . . . . . . . . . . . . . . . . . . . . .
3. Recommendations. . . . . . . . . . . . . . . . . . . . . . . . .
4. Basic Injection Well Design. . . . . . . . . . . . . . . . . . .
5. Monitoring of Annulus Pressure. . . . . . . . . . . . . . . . .
6. Pressure Testing. . . . . . . . . . . . . . . . . . . . . . . .
7. Well Logging - A General Discussion. . . . . . . . . . . . . . .
8. Temperature Logging. . . . . . . . . . . . . . . . . . . . . . .
9. Noise Logging. . . . . . . . . . . . . . . . . . . . . . . . . .
10. Pi pe An a 1 ys is Su rvey ............ . . . . . . . . . .
11. Electromagnetic Thickness Survey. . . . . . . . . . . . . . . .
12. Caliper Logging. . . . . . . . . . . . . . . . . . . . . . . . .
13. Borehole Television. . . . . . . . . . . . . . . . . . . . . . .
14. Borehole Televiewer. . . . . . . . . . . . . . . . . . . . . . .
15. Flowmeter Su rveys . . . . . . . . . . . . . . . . . . . . . . . .
16. Radioactive Tracer Surveys. . . . . . . . . . . . . . . . . . .
17. Cement Bond Logging. . . . . . . . . . . . . . . . . . . . . . .
18. Other Mechanical Integrity Testing Methods. . . . . . . . . . .
References
Appe nd ices
A. Tables used 'to estimate the volume of fluid lost from
a well (in gallons) for a given annulus pressure change. . . . .
B. Graphs which depict the response of annulus pressure to
injected fluid temperature for various well configurations
. . . . .
. . . .
.......
. . . .
......
. . . .
vii
1
7
13
15
26
36
54
64
86
103
124
138
151
161
173
190
200
224
242
250
255
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FIGURES
Number
1 Means by which injection wells may demonstrate a lack of
mec h ani c a 1 i n te g r i ty ........... . . . . . . . . . . . .
2 Common methods of class II injection well completion
.......
3 Basic design elements of a typical class II injection well
. . . .
4 Types of i nj ec t ion we 11 configurations (new wells). . . . . . . . . 38
5 Types of injection well configurations (ex i s t i ng well s ) . . . . . . 39
6 Dual packer system used for staged pressure tests. . . . . . . . . 42
7 Tool utilized for testing specific intervals of well casing or
tub; ng for 1 eaks ...... . . . . . . . . . . . . . . . . . . .
8 Completed state form for rep 'ting of the pressure test on the
annulus between the injection tubing and long string. . . . . . .
9 Graphic depiction of a pressure test
...............
10 State well inspection report for a pressure test on a salt water
di sposal we' 1 . . . . . . . . . . . . . . . . . . . . . . . . . . .
11
Graphic depiction of a pressure test showing no bleed off.
. . . .
12 Truck-mounted logging equipment set up at a well
. . . . .
. . . .
13 Block diagram of geophysical well-logging equipment
........
14 Diagram of a
lubricator. . . . . . . . . . . . . .
........
15 Temperatures in and around a cased and cemented well bore
.....
16 Schematic of RDT logging tool
.........
..........
17 Gradient temperature logs run at various times after well is
shut; n . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
viii
Page
5
16
18
43
48
49
51
52
55
57
58
67
69
71
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FIGURES (Continued)
Number
18 Gradient temperature log used for locating gas entry channel
a round pi pe . . . . . . . . . . . . . . . . . . . . . . . .
. . . .
19 Examples of gradient tempterature logs showing the natural
geothermal gradient and anomalies caused by flow through a
channel behind the well casing. . . . . . . . . . . . . . . . . .
20 A gradient temperature log used to locate a small gas leak
; n tub; ng . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
21
Temperature logs used in locating a gas channel behind casing
22 Temperature logs used in locating a casing leak
......
. . . .
23 RDT scans and temperature log in a well, showing channel to
potential gas zone before squeeze and no channel after squeeze. . .
24 Typical noise logging tool
. . . . . .
..............
25 Block diagram of noise logging system. . .
......
. . . . . .
26 Distinctive noise log frequency distributions.
27 Typical noise log display. . .
..........
..................
28 Combination nOise/temperature survey system.
. . . . . . .
. . . .
29 Noise log sections from a 2-zone, 2 tubing string completion
. . . 100
30 Diagram of magnetic field being induced into the casing
body wa 11 . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . 105
31 Diagram of the response of the pipe analysis log to a casing
de fee t .... . . . . . . . . . . . . . . . . . . . . . . .
. . . 106
. . . 108
32 Principle of operation of magnetic flux leakage test
33 Principle of operation of eddy current test. . . .
. . . .
. . . .
. . . . 109
34 The pipe analysis survey tool
35 Diagram of pad overlap
.......
. . . . . . .
. . . . . 111
. . . . 112
. . . .
. . . . . .
........
36 Diagram of pad configuration
......
...........
ix
Page
73
75
80
81
82
83
89
90
93
98
99
. . 113
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FIGURES (Continued)
Number
37 Example of four-channel output from one type of PAS log.
38 Oscilloscope traces of a laboratory PAS log. . .
. . . . .
.....
. . . .
39 Example of a PAS log from a gas storage well
...........
40 PAS tool response in a 7-inch test well with known defects
41 Diagram of principles of an ETS Survey
. . . .
..............
42 Diagram of modified ETS array.
.........
.........
43 ETS downhole tool and diagram of an ETS logging system.
......
44 Casing inspection log of a portion of a well in the San Juan
Basin of New Mexico (750-850 feet) ................
45 Casing inspection log of a portion of a well in the San Juan
Basin of New Mexico (1850-2000 feet) ...............
46 Field application of 2616" coil spacing ETT-A sonde in
concentric string of 7" x 9 3/8" casing. . . . . . . . . . . . . .
47 Indications of a casing rip in pipe wall away from any collars
48 High resolution tubing caliper tool
................
49 High resolution casing caliper tool.
........
.......
50 Standard casing and casing anomalies recorded by a caliper
10g91ng tool. . . . . . . . . . . . . . . . . . . . . . . . . . .
51 Example of a tubing profile caliper.
........
.......
52 Example of a casing profile caliper.
53 Downhole picture of cracked casing
...............
.....
......
.....
54 Downhole picture of casing damaged during a fishing job
......
55 Downhole picture of damaged casing and resulting sidetrack
56 Downhole picture of damaged casing and resulting sidetrack
at different depth. . . . . . . . . . . . . . . . . . . .
. . . .
. . . .
x
Page
115
117
120
121
126
128
129
133
133
135
136
141
142
145
147
149
156
156
157
157
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FIGURES (Continued)
Number
57 Downhole picture of separated casing
. . . . . . . .
. . . . . . .
58 Downhole picture of separated tubing inside screen
........
59 Block diagram of a borehole televiewer logging system. .
. . . . .
60 Assembled borehole televiewer logging tool
............
61
Borehole televiewer casing inspection logs of a casing blowout. . .
62 Borehole televiewer casing inspection logs of perforations
63 Diagram showing parts of a flowmeter
. . . .
........
.......
64 Diagram showing packer flowmeter in a well
............
65 Two different spinner configurations in continuous flowmeters . . .
66 Fullbore flowmeter
..........
. . . . .
.........
67 Packer flowmeter log in an injection well with an open hole
completion. . . . . . . . . . . . . . . . . . . . . . . .
. . . .
68 Log using a continuous flowmeter in stationary and
continuous mode of operation. . . . . . . . . . .
. . . .
. . . .
69 Diagram showing principles of interpretation for flowmeters
. . . .
70 The effect of logging speed on flowmeter data. . .
. . . .
. . . .
71
Heat pulse flowmeter detection system. . . .
. . . .
.......
72 Results of a flowmeter survey showing a leak in the casing
between perforations. . . . . . . . . . . . . . . . . . . . . . .
73 Radioactive tracer tool
...........
.......
. . . .
74 Three possible configurations of a radioactive tracer tool
. . . .
75 Radioactive tracer log showing movement of radioactive material
below perforated zones. . . . . . . . . . . . . . . . . . . . . .
76 Technique using radioactive tracer tool and logs used to locate
leak in the casing. . . . . . . . . . . . . . . . . . . . . . . .
77 Basic cement bond log theory
.....
......
........
xi
Page
158
158
163
165
170
171
174
176
177
178
180
181
182
183
185
187
192
193
197
198
201
-------
FIGURES (Continued)
Number
78 Typical transit times for various media inspection by the
cement bond tool. . . . . . . . . . . . . . . . . . . . . . . . .
79 Typical cement bond log
.................
. . . .
80 Principle of operation of the variable density log.
.......
81 Diagram of equipment used for recording CBL-VDL combination
82 Diagram showing response of fixed and floating gating systems. . .
83 Diagram of the cement evaluation tool
84 CBL/VDL log showing uncemented casing
. . . .
.....
.....
..........
. . . .
85 CBL/VDL log showing good casing-cement and cement-formation
bo n d . . . . . . . . . . . . . . . . . . .
............
86 CBL/VDL log showing good casing-cement bond but poor cement-
formation bond at level A ... . . . . . . . . . . . . . . . . .
87 CBL/VDL logs showing reponse of microannu1us runs with and
without pressure in the casing. . . . . . . . . . . . . . . . . .
88 Effect of fixed gate and floating gate on the same log. . . . . .
89 CBL log showing effect of proper and improper tool centering. . .
90 Elimination of a channel by cement squeezing. . .
........
91 Comparison of an old gamma log with a more recent gamma log and
electric log run in the same well. . . . . . . . . . . . . . . .
92 Dual-detector flow sonde and hypothetical channel water flow. . .
93 Log depicting results of a magnetic casing log. . . . . .
. . . .
94 Final design of the magnetic casing logging tool. .
95 Casing damage: tiled polar image.
.......
................
96 Casing damage: polar scanning with sectioning and rotation. . . .
97 Proposed helium return leak-test arrangement. . . . . . .
. . . .
xi i
Page
202
204
205
206
208
210
213
214
216
217
218
219
222
226
227
229
230
232
233
234
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FIGURES (Continued)
Number
I
98 Diagram of transverse electromagnetic diverted flux search
co; 1 sy stern. . . . . . . . . . . . . . . . . . . . . . .
. . . .
99 Diagram of longitudinal EDFSC system used to detect transverse
imperfections. . . . . . . . . . . . . . . . . . . . . . . . . .
B-1
Response of annulus pressure to injected fluid temperature
for 7" tubing x 9 5/8" casing x 12 1/4" borehole. . . . .
B-2 Response of annulus pressure to injected fluid temperature
for 3 112" tubi ng x 7" casi ng x 8 1/2" borehole. . . . .
B-3 Response of annulus pressure to injected fluid temperature
for 4 1/2" tubing x 7" casing x 8 1/2" borehole. . . . .
B-4
Response of annulus pressure to injected fluid temperature
for 4" tubing x 7" casing x 8 1/2" borehole. . . . . . .
B-5 Response of annulus pressure to injected fluid temperature
for 2 3/8" tubing x 5" casing x 6 1/8" borehole. . . . .
Page
236
237
. . . . 255
. . . . 256
. . . . 257
. . . . 258
. . . .
B-6 Response of annulus pressure to injected fluid temperature
for 2 7/8" tubing x 5 1/2" casing x 6 3/4" borehole. . . . . . .
B-7 Response of annulus pressure to injected fluid temperature
for 2 3/8" tubing x 7" casing x 8 1/2" borehole. . . . .
. . . .
B-8 Response of annulus pressure to injected fluid temperature
for 2 3/8" tubing x 5 1/2" casing x 6 3/4" borehole. . . . . . .
B-9 Response of annulus pressure to injected fluid temperature
for 2 7/8" tubing x 7" casing x 8 1/2" borehole. . . . .
xii;
. . . .
259
260
261
262
263
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TABLES
Number
1
Summary of applications of methods which may be used to
determine the mechanical integrity of class II injection wells. . .
Summary of advantages and disadvantages of methods which may be
used to determine the mechanical integrity of class II
; nj ect ; 0 n we 11 s .... . . . . . . . . . . . . . . . . . . . . . .
2
3 Annulus pressure monitoring requirements of selected states
4 Change in annulus pressure/change in injection pressure
relationships. . . . . . . . . . . . . . . . . . . . .
. . . .
......
5 State pressure testing requirements for class II injection
we 11 5 ........ . . . . . . . . . . . . . . . . . .
.....
6 Results of survey of prices charged for well logging services,
"midcontinent" area. . . . . . . . . . . . . . . . . . . . . . . .
7
Industry trade names for basic logging services
......
. . . .
8 Typical depth and logging charges for standard temperature
1 0991 n9 ...... . . . . . . . . . . . . . . . . . . .
.....
9 Typical depth and logging charges for differential
temperature logging. . . . . . . . . . . . . . .
.........
10 Typical charges associated with radial differential temperature
1 099; ng .............. . . . . . . . . . . . . . . . .
11 We11 geometry factors to compensate for recorded noise levels. . . .
12 Typical depth and logging charges for noise logging
........
13 Typical depth and logging charges for pipe analysis surveys
. . . . 119
14 Typical depth and logging charges for electromagnetic thickness
surveys. . . . . . . . . . . . . . . . . . . . . . . . . . . .
15 Typical depth and logging charges for caliper logging
.....
16 Typical charges associated with borehole television surveys
. . . . 154
xiv
Page
8
10
28
31
40
61
62
77
77
78
95
96
. . 132
. . 144
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TABLES (Continued)
17 Typical charges associated with borehole televiewer surveys
Page
. . . . 168
Number
18 Typi cal depth and logging charges for flowmeter surveys . . . . . . 184
19 Typi ca 1 depth and 1 oggi ng charges for radioactive tracer surveys . . 195
20 Summary of characteristics of typical cement bond 1 oggi ng tool s . . 209
21 Typical depth and logging charges for cement bond 1 oggi ng . . . . . 221
A-I Fluid loss in gallons vs. pressure drop in 7" (6.366" 10) x
4.5" annulus (gallons) . . . . . . . . . . . . . . . . . . .
A-2 Fluid loss in gallons vs. pressure drop in 7" (6.366" 10) x
4" annulus (gallons) . . . . . . . . . . . . . . . . . . . .
. . . . 250
. . . . 251
A-3 Fluid loss in gallons vs pressure drop in 7" (6.366" 10) x
3.5" annulus (gallons) . . . . . . . . . . . . . . . . . . .
A-4 Fluid loss in gallons vs. pressure drop in 7" (6.366" 10) x
2 7/8" annulus (gallons) . . . . . . . . . . . . . . . . . .
. . . . 251
. . . . 252
A-5 Fluid 10ss in gallons vs. pressure drop in 7" (6.366" 10) x
2 3/8" annulus (gallons) . . . . . . . . . . . . . . . . . . . .
A-6 Fluid loss in gallons vs. pressure drop in 5 1/2" (4.892" 10) x
2 7/8" annulus (gallons) . . . . . . . . . . . . . . . . . . . .
. . 252
. . 253
A-7 Fluid loss in gallons vs. pressure drop in 5 1/2" (4.892" 10) x
2 3/8" an nu 1 u s (ga 11 on s) . . . . . . . . . . . . . . . . . . . .
. . 253
A-8 Fluid loss in gallons vs. pressure drop in 5" (4.408" 10) x
2 3/8" ann u 1 us (g a 11 0 n s) . . . . . . . . . . . . . . . . . .
. . . . 254
A-9 Fluid loss in ~a110ns vs. pressure drop in 7 5/8" (6.95" 10)
casing x 2 3/81 tubing annulus (gallons) . . . . . . . . . . . . . . 254
xv
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ACKNOWLEDGEMENTS
This document reflects the state of the art available today on methods
for determining the mechanical integrity of Class II injection wells. It
is the product of many e~~eriences, some published and some unpublished.
Its successful completion, however, is due to the time and effort which an
unusually able advisory review panel was willing to devote to this
activity. To the following named persons, grateful acknowledgement of
their contributions is made:
Ray Al red
Research Services Division
Conoco Inc.
Richard Benson
Technos, I nc.
Bill G. Cantrell
Oil Operator
Timothy Dowd, Executive Director
Interstate Oil Compact Commission
W. Scott Keys
U.S. Geological Surey
1. A. Mi nton
Oklahoma Corporation Commission
Joe G. Moore
University of Texas at Dallas
Jerry Mull ican
Texas Railroad Commission
Robert Phillips
Shell Oil Company
Larry Sowell
Gearhart Industries
John S. Talbot
Baffin Associates
xvi
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SECTION 1
INTRODUCTION
OBJECTIVES AND SCOPE
Methods for Determining the Mechanical Integrity of Class II
Injection Wells has been prepared as an aid to state and federal
authorities involved in administering the regulations pertaining to
the mechanical integrity of Class II injection wells under the
Underground Injection Control Program (UIC). This report is also
designed to assist industry representatives, injection well operators,
engineers and others with the task of ensuring the mechanical
integrity of those injection wells. While this report is intended to
apply specifically to Class II wells, the technology described herein
may also be applicable to other classes of injection wells.
This report is intended to be informative rather than
prescriptive in nature. The basic objective is to provide a concise
description of methods or technologies which are currently being used
or which may have applicability in determining the mechanical
integrity of injection wells.
In developing Methods for Determining the Mechanical Integrity of
Class II Injection Wells, past, present and potentlally aval1able
methods for determining the mechanical integrity of injection wells
were researched. A review of the available literature revealed that a
significant amount of information has been written about the testing
of wells for downhole problems such as leaks in the casing or flow
behind the casing. However, most of the work described in the
literature has involved the testing and inspection of producing oil
and gas wells rather than injection wells. Fortunately, most of this
technology is also applicable to injection wells.
To better determine the state-of-the-art, government officials in
oil and gas producing states were surveyed regarding regulations,
requirements, methods and procedures used to determine mechanical
integrity of injection wells. Efforts to document the applicability
of many types of services provided by well logging companies were also
conducted.
1
-------
Mecha~~~~u~ni~rr~~ ~~v~~~~~e~f ~~j:~~~~~Sw~~~sD:;~~~~~~~y
passage 0 u 1C aw tea e r1n 1ng Water Act) and the
subsequent enactment of federal regulations found in 40 CFR Parts 122,
123, 124 and 146 (the UIC Program). The Safe Drinking Water Act of
1974 requires the U.S. Environmental Protection Agency to develop
minimum requirements to assist in the establishment of effective state
programs to protect underground sources of drinking W!ter from
contamination resulting from the subsurface emplacement of fluids
through well injection. Additionally, the Act states that these
requirements not impede the re-injection of brine or other fluids
resulting from oil and natural gas production or the injection of
fluids used in secondary or tertiary recovery unless drinking water
sources would be endangered (Federal Register, June 24, 1980).
40 CFR Parts 122, 123, 124 and 146, (the UIC Program) were
enacted under the authority of PL 93-523. 40 CFR Part 122 defines the
regulatory framework of EPA-administered permit programs; 40 CFR Part
123 describes the elements of an approved state program and criteria
for EPA approval of that program; 40 CFR Part 124 describes the
procedures the agency will use for issuing permits under covered
programs; and 40 CFR Part 126 sets forth technical criteria and
standards for the UIC (Federal Register, June 24. 1980; Federal
Register, February 3, 1982). A discussion of some of the pertinent
sections of 40 CFR Part 146 are described below.
Underground injection is defined as the subsurface emplacement of
fluids through a well (146.03). For purposes of the UIC program,
injection wells were classified into five categories based on the
nature of the fluid which would be injected. In general, Class I
wells include industrial and municipal disposal wells and hazardous
W!ste disposal wells not covered in Class IV; Class II wells include
wells which inject fluids 1) brought to the surface during oil and gas
production, 2) for enhanced recovery of oil and gas, or 3) for storage
of hydrocarbons which are liquid at standard temperature and pressure;
Class III wells inject for the purpose of extraction of minerals or
energy; Class IV wells inc~e disposal wells used by hazardous and
radioactive waste generators and disposal site operators; Class V
includes injection wells not covered by the four other classes
(146.05).
Inherent in the permit process for each of these classes of wells
is the determination of the mechanical integrity of the injection
well. An injection well is determined to have mechanical integrity
when it meets both of the following criteria: 1) there is no
significant leak in the casing, tubing or packer; and 2) there is no
significant fluid movement into an underground source of drinking
water through vertical channels adjacent to the injection well
(146.08). The absence of a significant leak can be evaluated using
2
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either monitoring of annulus pressure, pressure testing with liquid or
gas or, in specified instances, monitoring records that show no
significant change in the relationship between injection pressure and
injection flow rate. The absence of significant fluid movement can be
evaluated by using the results of a temperature or noise log, or, for
Class II wells, by presenting well records that demonstrate the
presence of adequate cement to prevent migration (146.08). A
definition of the term IIsignificantli WlS not included in the
regulations. A qualitative definition provided by Webster (Gura1nik,
1976) states that IIsignificantli means lIof or pertaining to an observed
departure from a hypothesis too large to be reasonably attributed to
chancell. While the intent of the regulations is thus clarified,
question as to a quantitative value for each test has been raised.
While this question is a valid concern, it is not the purpose of this
report to provide an interpretation of the federal regulations.
Additional regulations which are specifically applicable to Class II
wells (CFR 40, Part 146.08 and Part 146 Subpart C) are further
detailed.
The permitting authority in each state with a UIC program in
force or the appropriate regional EPA administrator is charged with
authorizing the construction of a proposed injection well and
overseeing the continued operation of existing injection wells. Prior
to granting approval for the operation of the injection well, the
permitting authority must evaluate the mechanical integrity of the
injection well. To assist the permitting authority, the permit
applicant must submit (along with other specified information) a
demonstration of mechanical integrity of the injection well which is
in accordance wi th the methods described in the preceedi ng pa ragraph
(146.24). However, the rules do allow the applicant to petition for
acceptance of additional methods for determining the mechanical
integrity of the injection well. The EPA Administrator has the
authority to evaluate additional methods and grant approval for their
use (146.08).
Once a permit granting approval for operation has been issued,
operating, monitoring and reporting requirements must be followed by
the operator of the injection well (146.23). Of particular importance
are the requirements that: 1) observation of the flow rate, injection
pressure and cumulative volume be conducted at specified time
intervals, 2) a demonstration of the mechanical integrity be provided
at least once every five years during the life of the injection well,
and 3) the results of all monitoring be maintained until the next
permit review as determined under 40 CFR 122.42 (e) (146.23). These
provisions help to guarantee that the mechanical integrity of the well
is present initially and also maintained throughout the life of the
injection well. This helps to ensure that injection will not result
in the migration of fluids into an underground source of drinking
Wlter so as to create a significant risk to the health of the persons
using the source of drinking Wlter.
3
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PROBLEM ASSESSED
Ground ~ter and surface ~ter contamination instances from 0;1
field brine disposal practices, especially surface discharges and
unlined pits, are well documented in the literature (Fryberger, 1972;
Oklahoma Water Resources Board, 1975; Pettyjohn, 1971; Payne, 1966).
As a result, present disposal operations are typically limited either
to underground injection or to discharge into lined lagoons. It is
estimated that there are approximately 140,000 Class II wells in use
across the United States.
With the increasing emphasis on brine injection operations, the
UIC regulations were adopted, in part, to help reduce the potential
for the contamination of underground sources of drinking ~ter by
Class II injection wells (Federal Register, 1980). In general, two
types of injection wells are utilized in oil and gas production
operations: 1) brine disposal wells in which the fluid is injected
into a receiving formation for the purpose of retention; and 2)
enhanced recovery wells in which the fluid is injected into a
producing formation for the purpose of increasing the production of
oil and gas. Both types of wells are virtually identical in design,
construction materials and completion, and can be completed as new
wells or converted from existing production wells.
Injection wells can be operated without endangering ground ~ter
provided they are properly constructed and maintained in such a ~y as
to ensure their mechanical integrity. Salt~ter injected under
pressure or by gravity into wells may escape through leaks in the well
casing caused by a mechanical failure within the well . or through
migration of brine forced up between the well's outer casing and the
wellbore because of a faulty cementing job (Figure 1). Determination
of the mechanical integrity of an injection well is extremely
important. since it provides a measure of the protection of fresh
~ter aquifers from contamination.
ORGANIZATION
This document contains 18 sections and 2 supporting appendices.
The development of the sections and appendices are user-oriented.
Section 4 provides a basic introduction to the design of injection
wells. Sections 5 and 6 address methods of determining the mechanical
integrity of injection wells which do not require the services of a
professional well logging company or specialized contractor. Section
7 provides an introduction to well logging and to services performed
by well logging companies. Sections 8 - 17 address different logging
techniques which may help determine mechanical integrity of injection
wells. Section 18 describes other methods which may also have
application. An attempt has been made to summarize applicable
techniques and technologies throughout the report. Each section
contains a reference section for additional information.
4
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Casing
Casing
- Formation
Leak Through Hole In Casing
Fluid
Movement
Through
Vertical
Channel
In Annulus
Figure 1. Means by which injection wells may demonstrate a lack of mechanical integrity.
- Cement
Cement
Injection Zone -
--
-'--
--
5
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REFE.'ENCES
Federal Register, vol. 45, no. 123, June 24, 1980, pp. 42472 - 42512.
Federal Register, vol. 47, no. 23, February 3, 1982, pp. 4992 - 5001.
Fryberger, J.S., 1972, Rehabil :ation of a brine-polluted aquifer;
U.S. Environmental Protection Agency publication #EPA-R2-72-014, 61
pp.
Guralnik, David B., ed., 1976, Webster's new world dictionary; Collins
and World Publishing Company, Inc., 1692 pp.
Oklahoma Water Resources Board, 1975, Salt water detection in the
Cimarron Terrace, Oklahoma; U.S. Environmental Protection Agency
publication #EPA-660/3-74-033, 166 pp.
Payne, Roy B., 1966, Salt water pollution problems in Texas; Journal
of Petroleum Technology, vol. 18, no. 11, pp. 1401-1407.
Pettyjohn, Wayne A., 1971, Water pollution by oil-field brines and
related industrial wastes in Ohio; The Journal of Science, vol. 71,
no. 5, pp. 257-269.
6
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SECTION 2
CONCLUSIONS
Leaking injection wells may result in the migration of fluids
into an underground source of drinking water so as to create a
significant risk to the persons using that source of drinking water.
However, injection wells can be operated without endangering ground
water provided they are properly constructed and maintained in such a
way as to ensure their mechanical integrity.
All Class II injection wells must demonstrate that there is no
significant leak in the casing, tubing or packer and that there is not
significant fluid movement through channels adjacent to the injection
well to ensure mechanical integrity. To date, the UIC program
requires that the absence of a significant leak in the casing, tubing
or packer be evaluated using either monitoring of annulus pressure,
pressure testing with liquid or gas or, in specified instances,
monitoring records that show no significant change in the relationship
between injection pressure and injection flow rate. The absence of
significant fluid movement can be evaluated by using the results of a
temperature or noise log, or, for Class II wells, by presenting well
records that demonstrate the presence of adequate cement to prevent
migration.
In addition to these methods, there are a number of other methods
which are not currently approved for use which may also be used to
determine the mechanical integrity of injection wells. Pipe Analysis
Surveys, Electromagnetic Thickness Surveys, Caliper Logging, Flowmeter
Surveys, Radioactive Tracer Surveys and Cement Bond Logs which are
available from professional well logging companies are capable of
detecting leaks in the casing, tubing or packer and/or fluid movement
behind casing. Borehole Television and Borehole Televiewer surveys,
which are performed by specialized contractors, may also be used to
detect leaks. Table 1 provides a detailed listing of the detection
capabilities, well diameter constraints and pressure/temperature
limitations of each of these techniques as well as the techniques
approved for use in the UIC program.
Nearly all of the testing methods currently available are
available only through professional well logging companies which
specialize in these and other injection well and production well
services. Many of these companies have district or regional offices
7
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TABLE 1. SUMMARY OF APPLICATIONS OF METHODS WHICH MAY BE USED TO
DETERMINE THE MECHANICAL INTEGRITY OF CLASS II INJECTION WELLS
Detection Capability Well Diameter For Use PressurelTemperature
Leaks in Casing, Fluid Movement Constraints in Casing Limitations of
Tubing or Packer Behind Casing Minimum Maximum or Tubing Technique
Monitoring Annulus Pressure X N/A N/A N/A
Pressure Testing X N/A N/A both N/A
Temperature Logging
(Gradient) X X 1 'h" 8'12' both 20,000 psi/400° F
(Differential) X X 1 'I,' 8'h" both 20,000 psi/400° F
(Radial Differential) X X 23,." 13'Ys" both 20,000 psi/400° F
Noise Logging X X 1 'I,' no limit both 15,000 to 22,000 psi/350° F
Pipe Analysis Survey X 4'h" 9%" casing 1 0,000 psi/250° F
CD
Electromagnetic Thickness Survey X 4'h" 9%" casing 20,000 psi/350° F
Mechanical Caliper Logging X 2" 133fs" both 1 0,000 psi/300° F
Borehole Television X 3" 36" casing 5,000 psi/175° F
Borehole Televiewer X 2'Ys" 8V,' casing 15,000 psi/175° F
Flowmeter Surveys X 2" 10" both varies widely according to
tool design
Radioactive Tracer Surveys X X 1 'h" no limit both 15,000 psi/300° F +
Cement Bond Logging 2" no limit casing 20,000 psi/400° F
. inferred only
.. annulus between casing and tubing
N/A not applicable
+ depends on choice of gamma ray detector
-------
across the country, thus most services are readily available in most
areas. In addition, many of the methods described in detail in this
document have been utilized, in one form or another, by the petroleum
industry for a number of years. Therefore, these methods have been
tested not only under laboratory conditions, but also under field
conditions, and the interpretation of results is fairly well
established.
Since many different tests may be applicable for determining the
mechanical integrity of Class II injection wells, the advantages and
disadvantages of each method must be understood to facilitate a
rational decision regarding which method or methods can be applied in
each individual situation. Few of the methods which can be employed
to test the mechanical integrity of injection wells can be used alone
to provide definitive information on both the presence and the
location of leaks in the casing, tubing, or packer, and fluid movement
behind the casing. In general, it will take two or more testing
techniques, run either independently or in conjunction, to ensure that
no significant leaks exist in the casing and that no fluid movement is
occurring in the cement ~heath behind the casing. Table 2 provides a
detailed summary of the advantages and disadvantages of all methods
which may be used to determine the mechanical integrity of Class II
injection wells. When used in conjunction with Table 1 which lists
the applications and limitations of all the methods, the best method
or combination of methods may be chosen.
9
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TABLE 2. SUMMARY OF ADVANTAGES AND DISADVANTAGES OF METHODS THAT MAY
BE USED TO DETERMINE THE MECHANICAL INTEGRITY OF
CLASS" INJECTION WELLS
Method
Monitoring Annulus Pressure
Advantages
Provides "real time" measurement
Well does not have to be taken out of service
No specialized equipment needed
Very inexpensive
Provides either continuous or frequent, regular
measurement
Disadvantages
Injected fluid temperature and pressure changes
complicate interpretation
Provides no information on leak location
Limited to use in wells completed with tubing and packer
Pressure Testing
Most tests of short duration
Minimum of specialized equipment needed
Some disruption of service
Non-staged tests provide no information on leak location
Relatively inexpensive for most wells
Results straightforward and easy to interpret
..
o
Staged tests provide information on leak location
Temperature Logging
Can detect and locate both leaks in casing, tubing or
packer and fluid movement in channels behind casing
Gradient and differential logs available from most
logging companies
Application of excessive pressures could damage well
Requires professional service, equipment and
interpretation
Requires removal of well from service for extended
period (24 to 48 hours or more)
Use limited in large-diameter wells
Radial differential log available from only one logging
company
Noise Logging
Can detect and locate both leaks in casing, tubing or
packer and fluid movement behind casing
Possible to distinguish between single and dual
phase flow
Possible to estimate rate and volume of flow from
a source
Available from most major logging companies
Requires professional service, equipment and
interpretation
May require removal of well from service for extended
period
Injection operations must be stopped during logging
May not be useful for detecting flow behind casing
when pressure differentials too low
-------
TABLE 2 (continued)
Pipe Analysis Survey
Developed specifically to evaluate downhole casing
damage
Can distinguish between internal and external casing
damage
Can detect and locate small defects (1/8-inch diameter)
in casing
Offered only by a select few well logging companies
If tubing removal necessary, requires removal of well
from service for extended period
Electromagnetic Thickness
Survey
...
...
Offers only method of detecting defects on the outer
string of double casing string
Cannot detect small casing defects (less than 1-inch
diameter)
If tubing removal necessary, requires removal of well
from service for extended period
Difficult to distinguish true cause of log anomalies
Requires availability of baseline log against which
comparison is made to subsequent logs
Mechanical Caliper Logging
Offered only by a select few well logging companies
High resolution caliper provides very accurate record of
condition of casing interior
Log can be run in short amount of time
Log can be run in either tubing or casing
May not detect small-diameter (1/2-inch) defects
Difficult to locate vertical splits or cracks in casing
High resolution caliper offered only by a select few well
logging companies
Borehole Television
Provides for direct visual inspection of downhole
conditions
Video tape recording provides for ease of replay and
comparison with other logs
Well fluid must be free of suspended material
If tubing present, must be removed
Operation requires removal of well from service for
extended period
Service not offered by commercial well logging
companies; specialized contractor necessary
Cannot be run in high temperature/pressure
environments
-------
TABLE 2 (continued)
Borehole Televiewer
Provides easily recognizable image of casing interior
Provides either photographic or videotape record
Limited interpretation necessary
Can operate in less favorable environments than
borehole television
If tubing present, must be removed
Operation requires removal of well from service for
extended period
Technique relatively slow
Service not offered by commercial well logging
companies; specialized contractor necessary
Flowmeter Surveys
Log can be run in either tubing or casing
Possible to estimate volume of flow from leak
Flow rates must be high enough for flowmeter to
function
Log run during injection; little disruption of service
Available from most major logging companies
...
N
Injection rate must be held constant for proper
interpretation
Requires professional service, equipment and
interpretation
Radioactive Tracer Surveys
Log can be run in either tubing or casing
Log run during injection; little disruption of service
Available from most major logging companies
Requires use of radioactive tracer
Requires professional service, equipment and
interpretation
Cement Bond Logging
Infers presence of channels behind casing
Available from most major logging companies
If tubing present, must be removed
Cannot be used to find leaks or determine fluid
movement
Many factors affect log validity
Requires professional service. equipment and
interpretation
Interpretation complicated and not standardized within
industry
-------
SECTION 3
RECOMMENDATIONS
There are many methods which may be applicable for determining
the mechanical integrity of Class II injection wells. Because of the
many variations in injection well completions, it is not possible to
make recommendations regarding mechanical integrity testing methods
which apply to all such wells. Since each well is unique, testing
procedures should be carefully selected and tailored to the individual
well. The following list of criteria should be used to help establish
a systematic approach to choosing the appropriate testing methods:
1)
Determine the type of completion of the well;
2) In wells completed with tubing and packer, determine the type
of packer to evaluate the maximum amount of pressure which can be
applied to the annulus between the tubing and casing;
3) Determine the inside diameter of the casing or tubing to
assess tool diameter limitations;
4) Determine the depth of the well to evaluate
pressure/temperature limitations of methods;
5) Determine the wall thickness of casing or tubing since
selected methods rely on the measurement of thickness to determine the
soundness of the pipe;
6) Attempt to determine the interval(s) of injection to
facilitate the application or interpretation of tests;
7) Evaluate the availability of professional companies to
perform the service, if appl icable;
8) Evaluate the cost of the method with respect to the type of
results desired.
Because some of the testing methods detailed in the "Other
Mechanical Integrity Testing Methods" Section of this report have not
been specifically used or properly evaluated for use in testing the
mechanical integrity of Class II injection wells, further study is
needed in the following areas:
13
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1) Gamma ray logging has traditionally been used in injection
wells for purposes other than leak detection, however further study
into the applicability for leak detection is needed;
2) Helium leak testing has been used to test for leaks in other
applications, but has not been applied specifically to injection
wells. This method should be laboratory and field tested to determine
its applicability to injection wells;
3) Volumetric scanning has been used for fracture evaluation in
open boreholes, but further evaluation for use in cased hole
applications is necessary; and
4) Continuous oxygen activation logging has been field tested
for application of determining leaks in injection wells but the
results are inconclusive. Further testing is need~d to assess the
applicability of this technique.
14
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SECTION 4
BASIC INJECTION WELL DESIGN
INTRODUCTION
It is presumed that most readers of this document have a basic
knowledge of injection well design. However, for the purpose of
standardizing the terms used in subsequent chapters, it is appropriate
to review the basic design of the types of wells (Class II) that this
document deals with. This chapter is not intended to be a detailed
discussion of injection well design, as numerous examples of this
appear in the literature.
The common objective for Class II injection wells, both brine
disposal and enhanced recovery wells, is to furnish a path~y for the
subsurface emp1 acement of f1 ui d wi thout endangeri ng fresh-water
aquifers. Because of this common objective, the design and
construction details and the operational practices employed in both
types of well s are very similar.
Injection wells can be classified into three general types based
on the method of completion (American Petroleum Institute, 1978):
1) cased-hole completions, in which the well is cased and cemented
through the injection zone then opened through perforations (Figure
2A); 2) open-hole completions, in which the well is cased and cemented
to the top of the injection zone and the well advanced into the
formation intended for injection (Figure 2B); and 3) liner
comp1 eti ons, in which the well is ca sed and cemented to a shallower
formation, drilled deeper, and a liner set through the injection zone,
cemented, and opened through perforations (Figure 2C).
Many variations in these three methods of completion are found,
particularly in wells which were originally completed as production
wells and then converted to injection wells. Construction details in
these wells are dependent on practices in use at the time of
completion and on local conditions. One variation which is common in
some parts of the country is the tubing1ess or "slim-hole" completion,
in which the tubing is cemented in a small borehole to serve as both
the long string and the tubing string. These and other so-called
Iinon-standard" completions pose the most difficult problems to
regulators because the wells do not conform to UIC standards.
15
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Fresh
Water
Aquifers
Injection
Zone
A
Cased Hole-Perforated
Surface Casing, set
below fresh water,
cement Circulated to
surface
- Top 01 Cement --+
....... Complellon Ihru
perforations
,...~
Long casing string
set thru injectIOn
zone
B
Open Hole
Long casing string
set on top of
inJection zone
Completion In open
/hole
Surface PIpe, set
below fresh water.
..- cement Circulated to
surface
Li ner set th ru
Injection zone
C
Liner-Perforated
Figure 2. Common methods 0' class II injection well completion (After American Petroleum
Institute, 1978).
16
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For the purposes of this document, it is assumed that most
so-called "standard" operational Class II injection wells are composed
of several basic design elements. These elements, as illustrated in
Figure 3, include: casing, cement, injection tubing, packer, and the
we 11 head.
CASING
The primary functions of casing are to prevent the borehole from
caving, to confine the injected fluid to the well bore and the
intended injection zone (to prevent contamination of fresh-water
aquifers), and to provide a method of pressure control. Design of a
casing program depends primarily on well depth, character of the rock
sequence, fluid pressures, type of well completion, the corrosiveness
of the fluids that will contact the casing and the water quality of
the aquifers through which the casing is installed.
Three different IIstri ngsll or types of casi ng may be used in
injection wells: a surface string, an intermediate string, and a long
string (or injection string). The number of casing strings and their
setting points are generally governed by geologic condi .ions. There
are normally at le~st two casing strings as illustrated in Figure 3;
the surface strin, and the long string. An intermediate string of
casing may be useo in deeper completions, but is not always necessary.
A liner may also be used in deeper completions, for reasons of
economics.
In most recently completed injection wells, surface casing is
installed through the deepest fresh-water aquifer and is seated into a
confining layer beneath the aquifer. Cement is then circulated back
to the surface in the annulus between the casing and the borehole. The
surface casing then protects fresh-water aquifers from foreign fluids
during the drilling operation, continues to offer this protection
during the life of the well, and will be left in place with cement
both inside the casing and between casing and borehole upon
abandonment of the well. Older existing production wells which have
been converted to injection wells may not have the surface string
cemented to the surface.
Within the surface string is installed the long casing string, or
the injection string, which is the permanent connection between the
surface and the injection zone. The diameter of the casing used in
the long string is selected based on the following considerations
(Warner and Lehr, 1977):
1. Tubing diameter. The inside diameter of the casing must be
great enough to accommodate the packer and tubing (coupling diameter).
17
-------
Annulus Pressure Gauge
Injection Pressure Gauge
~ Injected Liquid
. ,.
.' .
....
\ ~ ....
~ ...
".".
.
.
::.:
Potable Water
: ..
"..
,
..
. .'
.'
'.
'.'
'. .
.' .
"
. .
----
Non-Potable Water
Undifferentiated Rocks
! !
I \ :;{i:
~ ) :~::..
\ ~ ':.':.
.0' ,
-.".
.".-
.,
'.
"...:
. .
....:
',.
; ,:
Confining Bed
Injection Zone
Annular Access
Surface Casing
Cement
---
Injection Tubing
Long String Casing
Annular Fluid
Cement
Packer
Perforations
Figure 3. Basic design elements of a typical class II injection well.
18
Wellhead
-------
2. Cost of drilling and casing. Since the cost of drilling and
casing increases with hole diameter, the size should be minimized.
3. Workovers. Since remedial work is frequently necessary in
injection wells, the casing size must accommodate workover equipment.
During their lifetimes, many injection wells require some form of
maintenance (liworkoverli in the terminology of the petroleum industry).
Workovers are commonly attempted for the following purposes:
a.
Well repa i r
1) Replace damaged tubing and/or packers
2) Repair damaged or corroded casing
3) Perform remedial well cementing
4) Install additional liners or casing
b.
Maintenance of injection capacity
1) Reperforating
2 ) Ac i d i z i n g
3) Fracturi ng
4) Mechanical or
hydraulic cleaning of the wellbore
c.
Recompleting or deepening to a new injection interval
4. Common practice. The experience of others in the geologic
area of interest and in similar operating situations should guide the
final choice.
The decision on the size of the casing used in the long string
fixes the minimum size of the hole and of all other casing strings.
The hole diameter is nearly ahays at least two inches greater than
the casing coupling outside diameter to allow at least a one-inch
sheath of cement around the casing (American Petroleum Institute,
1978).
Depending on the type of completion, the long string is installed
either to the top of the injection zone (open-hole completion),
through the injection zone (cased-hole completion) or to some point
above the injection zone (liner completion). It is designed with
adequa te tensi on, burst and collapse strength to wi thstand formati on
pressures, injection pressures, and cementing. Because of these
constraints, the long string is nearly always steel casing.
A long string, properly designed, set, and cemented, allows no
movement of injected fluids up the annulus. During the operation life
of the well, specific attention should be directed to the protection
of the injection string from abuse and corrosive fluids because this
casing is the permanent avenue of access from the surface to the
injection zone.
19
-------
A liner may be utilized where economics or site conditions
dictate. Like the long casing stringr the liner is the means of
accessing the injection zone. Thusr the liner is designed for burst,
collapse and tension just as the long string, and is cemented to
impede movement of injected fluids up the annu1usr though achieving a
competent completion is more difficult to obtain with a liner than
with the long string (American Petroleum Instituter 1978).
CE~IENTING
Cementing of injection wells entails mixing a slurry of cement
and Wlter and pumping it down, usually through casing, into the open
hole below the casing. The cement is then forced upward, under
pressure. into the annulus between the casing and the borehole or
between the casing and previously installed larger casing. Although
cement is normally emplaced through the casing, other methods of
emplacement are available for special situations.
The principal functions of cementing are to forestall travel of
injected fluids into fonnations other than the injection zone, to
restrict fluid movement between formations and to bond and support the
casing. Cement also aids in protecting the casing from external
corrosion and in isolating high pressure or lost circulation zones.
Another type of cementing procedure, squeeze cementingr is used to
correct defective primary cementing jobs. In squeeze cementingr
cement is selectively placed to fill intervals not completely cemented
during primary cementing. Squeeze cementing can also be used for
other purposes~ such as selective plugging of an injection interval
wi thout abandonment of the enti re well.
I n the i nstalla ti on of surface casi ng r cement shou1 d ah.ays be
circulated back to the surface, thus ensuring that the aquifers
through which the surface casing is installed are protected. In
installing the long string, circulation of cement back to the surface
is desirable. but in deep completions. is not a1WlYS economically
feasible or mechanically possible. In some cases. regulatory
authori ti es may allow a well to be constructed wi th only the bottom of
the long string cemented to a specified level above the injection
zone. In other cases. cementing the upper portion of casing by
circulating through a multiple-stage cementing tool installed in the
casing below the base of fresh ftBter, may be required. In deep wells,
multiple-stage cementing of the long string casing is usually
necessary to reduce the risk of lost circulation and to allow for
better cement bonding between the casing and the formations.
A successful primary cementing job is considered to be as
important as any aspect of injection well construction. Even the
best-designed well can be rendered inadequate if the casing is not
adequately bonded to the formations above the injection zone. A poor
cement job can allow vertical migration of injected fluids in channels
20
-------
between injection casing and the borehole.
aquifers could be endangered. but perhaps a
external corrosion of the longstring casing
the well.
In some cases, fresh water
greater danger is from
that can lead to loss of
In new injection well completions. the primary cement job shoul d
always be checked. Commonly used methods of checking cement include
temperature surveys. cement bond logs, and noise logs. Temperature
surveys and radioactive tracer surveys are used for locating the top
of cement behind casing. Cement bond logs are used to indicate the
quality of the bond between the cement and the casing and the bond
between the cement and the formation. Noise logs and radioactive
tracer surveys can be used to determine the presence of channels in
the cement. These and other logs are discussed further in subsequent
chapters.
In open-hole completions, after the injection string is set at
the top of the injection zone and cemented. the cement at the bottom
of the well is drilled out and the well is completed. In cased-hole
completions, access to the injection zone is usually obtained after
the well has been cased and cemented, through perforations in the
casing string. The casing may be perforated by anyone of several
means, but is usually perforated by shaped-charge jets.
INJECTION TUBING
Most recently installed wells injecting potentially corrosive
fluids have been constructed with injection tubing inside the long
casing string, and with a packer set between the tubing and the casing
near the bottom of the well. The tubing is the controlling element of
injection well construction because it conveys the fluid to the
injection zone.
Tubing size is based on the volume of fluid to be injected. but
there is no fixed rel a ti on between the two. For a speci fi ed fl ui d
volume. an increased tubing size requires less energy to force the
fluid through the tubing. but increases tubing cost. The optimum
tubing size is that which minimizes the cost of operation and still
meets the engineering requirements of the system. Tubing grade and
weight are selected in a manner similar to that for selecting casing
grade and weight. However. because of the relatively small diameter
of tubing. more pressure is required to inject fluids at high rates
through tubing than through casing. Thus. selection of proper tubing
grade and weight must reflect this consideration.
Tubing for injection wells is available in various types and
grades of steel and other material s. The material used for tubing in
Class II wells is generally steel. but when the injected fluid,
usually saltwater, is corrosive. the steel tubing is protected from
internal corrosion by plastic coating. Unlined steel tubing may be
21
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util i zed in the well if the i nj ected fl ui d ha s been trea ted wi th a
corrosion inhibitor or is not corrosive.
Protection from corrosion can also be obtained by substituting
non-corroding materials, such as fiberglass, for the standard steel
normally used. However, because fiberglass is not as strong as
standard steel, it is only useful in wells where high injection
pressures are not anticipated and in those installations where well
depths are compatible with the tensile properties of the material.
PACKERS
Packers are designed to seal off, or "pack off" certain sections
in an injection well. They may be used to protect casing from
injection and formation pressure and fluids, to isolate given
injection lones, and as a subsurface safety control. Packers can also
be used to isolate specific zones within a well to allow for multiple
completions in the same well bore.
Most packers used in injection wells are of three basic types -
those in which the tubing is positioned in tension (tension-set),
those in which the tubing is held in compression (compression-set),
and universal packers. These packers are all seated by movement of
the tubing. This may be accomplished by use of the tubing weight as
in the case of a compression-set packer; this type of packer may be
retrieved by simply lifting up on the tubing. Tension-set packers are
set by a pulling tension on the tubing; they are released by slacking
off on the tubing. Tension-set packers are set even tighter by
pressure from below and therefore work well in some injection wells.
Compression-type packers are generally less expensive than
tension-type packers because they are less complex mechanically.
Universal packers are generally preferable if the fluid being injected
is \l6rm to hot. With some of these packers, a long seal assembly can
be used, all owi ng the lower end of the tubi ng to move freely in
response to thermal expansion without destroying the integrity of the
seal. If the fluid being injected is relatively cool, then thermal
expansion is not a consideration and the tubing can be set in
compression if high pressures are not anticipated.
Other types of packers which may find use in injection wells
include rotational-set packers and hydraulic packers. Rotational-set
packers are set using a left-hand rotation to extend the slips; this
procedure is reversed to release the packer. The primary advantage of
rotational packers in injection wells is that the tubing may be set in
a neutral-wei ght si tua tion. thus elimi nati ng the possibil i ty of
unseating the packer due to tubing elongation (as when using a
tension-set packer) or separating due to contraction (as when using a
compression-set packer.) The main disadvantage of rotational-set
packers is that solids tend to settle out on top of the packer which
prevents any rotational action; thus, on attempting to release the
packer, the tubi ng may unscrew (Wa rner and Lehr, 1977).
22
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The hydraulic-set packer employs fluid pressure to wedge the
slips; once set, this type of packer is usually held by a mechanical
lock. Retrieval is by either rotation or tension. Hydraulic-set
packers are used particularly where tubing movement is limited. This
type of packer also allows the tubing to be in a neutral-weight state.
A speci a1 type of hydrau1 ic packer is the inf1 atab 1 e or II ball oon"
packer which can be used in either open holes or cased wells. The
packer element is set by applying fluid pressure. Primary usage
occurs in we~ls with partially collapsed casing. Inflatable packers
will not withstand high pressure differentials, and are relatively
expensive, thus they are not widely used in injection wells.
In some situations, it is possible to complete a well using
tubing without using a packer. This technique, referred to as the
hydraulic seal technique, is one in which a hydraulic barrier rather
than a mechanical one is used to prevent the migration of injected or
formation fluid up the casing-tubing annulus. This type of seal can
be used only in cases in which the hydrostatic pressure of the
formation is sufficient to raise the formation fluid to some level up
inside the well. The seal is made by pumping fresh water or a light
oil, such as kerosene or diesel oil, into the annulus and displacing
the formation water downward to a point near the bottom of the well.
The annulus is then closed off at the surface and a valve and pressure
gauge installed at the wellhead to monitor the annulus pressure.
Because the oil is for all practical purposes incompressible, any
variations in injection pressure are reflected in the annulus
pressure. If any changes in the annulus pressure are noted while
injection pressure remains constant, or if the differential pressure
is found to decrease or increase, this is an indication of a leak in
either the casing or the tubing.
ANNULAR CORROSION PROTECTION
The annular space between the tubing and the casing should always
be filled with a corrosion-inhibiting fluid to protect both the tubing
and casing from the effects of corrosion. Fresh water treated with a
chemical inhibitor is widely used for this purpose, but other fluids,
including light oils, may also be used. Regulatory authorities may
require that a positive differential pressure be maintained on the
annulus fluid so that well malfunctions may be detected.
WELLHEAD
The final components of the injection well are the wellhead and
appurtenant structures, which are all standard oil-field equipment.
The wellhead is the main link between the surface fluid distribution
system and the downhole equipment, and generally consists of a surface
casing flange, casing hanger and spool and tubing flange. Where
metering is required, as in most larger operations, or where other
equipment (i.e. va1ving, pressure taps, etc.) is desired, the wellhead
may be more complex. Pressure gauges are generally installed on the
23
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injection tubing and on the tubing-casing annulus (if one exists) at
the wellhead. Continuous recording devices may be installed to record
injection tubing pressures and injection flow rates and volumes. An
automatic alarm or shut-down system may be installed to signal the
failure of any important component of the injection system, or to shut
off the system should a failure occur.
CONSIDERATIONS IN MECHANICAL INTEGRITY TESTING
Before any type of mechanical integrity testing can be performed
on an injection well, the following details of well completion must be
known about the well:
1) The type of completion must be determined. Testing procedures
which may work well in, for example, a well without tubing and packer,
may not work at all in a well completed with tubing and packer.
2) The depth of the well should be known, as some testing methods
have limitations with regard to the depth at which they perform well.
3) The interval (or intervals in the case of multiple
completions) into which injection is taking place, should be
identified so that testing can avoid it (or them) or so that it (or
they) can be accounted for in the interpretation of test results.
4) The inside diameter of the casing and the tubing is also
critical, as some methods require the use of downhole tools, the
diameter of which may preclude their use in some wells.
5) Casing and tubing wall thickness should also be determined
before any mechanical integrity testing is done, as some methods of
testing rely on measuring that thickness as a means of determining the
soundness of the pipe.
6) In wells completed with tubing and packer, the type of packer
used in the well must be known, primarily for pressure testing. The
type of packer will determine the maximum amount of pressure which can
be applied to the annulus between the tubing and casing.
Many variances in methods of completion of injection wells are
encountered, particularly in older existing wells where factors at the
time the wells were completed influenced construction practices.
Also, wells with extensive downhole repairs may have unusual
mechanical configurations. In view of the great variety of types of
completions of injection wells, and the complications involved in
mechanical integrity determinations, it is critical to realize that it
is not possible to make general statements about mechanical integrity
testing of injection wells. Each well is unique with respect to its
individual characteristics, and testing procedures should be carefully
selected and tailored to the well to ensure that testing can be
performed in the most efficient, cost-effective manner.
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REFERENCES
American Petroleum Institute, 1978, Subsurface salt water injection
and disposal (second edition); American Petroleum Institute,
Vocational Training Series Book #3, 67 pp.
Warner, D.L. and J.H. Lehr, 1977, An introduction to the technology of
subsurface wastewater injection; U.S. Environmental Protection
Agency publication #EPA-600/2-77-240, 345 pp.
25
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SECTION 5
MONITORING OF ANNULUS PRESSURE
SYNOPSIS
Many injection well operators utilizing wells completed with
tubing and packer routinely measure and keep a record of the pressure
on the corrosion-inhibiting fluid in the annulus between the casing
and the tubing. The practice of monitoring annulus pressure is
employee to detect any changes in pressure which may indicate leakage
through the injection tubing, the casing or the tubing-casing packer.
Because annulus pressure is normally monitored on either a
continuous or frequent, regular basis, this method provides for
determination of a mechanical integrity problem relatively soon after
it occurs. Other testing methods, which are normally employed only
periodically (federal and some state regulations require mechanical
integrity testing only once every five years), may only detect a leak
years after it has occurred. The cost of annulus pressure monitoring
is very low, and equipment requirements are minimal. Monitoring of
annulus pressure can be conducted without removing the well from
service.
A potential problem in utilizing annulus pressure monitoring as a
means of determining injection well mechanical integrity is that
interpretation of test results may be complicated by changes in
injection pressure and injected fluid temperature.
PRINCIPLES
The principle of annulus pressure monitoring is very simple. The
annular space in an injection well which is closed at the bottom with
a packer and at the top with a wellhead functions as an enclosed
vessel. If the fluid in an enclosed vessel is maintained at a fixed
volume and temperature the fluid pressure should remain constant if
there is no leak. Pressure changes within the vessel can be caused by
indirect outside influences (i.e. outside pressure or temperature
acting on the vessel and thus the fluid inside) or by direct
communication between the inside of the vessel and the outside
environment. Thus, the vessel (or annulus) will experience pressure
changes whenever the outside influences are great enough or whenever
an avenue of direct communication (a leak) exists.
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EQUIPMENT
The only equipment necessary to conduct annulus pressure
monitoring is a standard wellhead pres ure gauge which is normally
installed upon completion of a tubing and packer well. If no
operable, accurate pressure gauge is present on the annulus, an
appropriate fitting should be provided so that a gauge can be
temporarlly installed to take pressure readings. This equipment is
inexpensive and readily available.
PROCEDURES
Two conditions commonly exist in injection wells: 1) where the
casing-tubing annulus is not pressurized at the surface and the
initial pressure is atmospheric except for some pressure resulting
from the expansion of the injection tubing (Warner, 1975) and 2) where
positive pressure of a predetermined amount is maintained on the
casing-tubing annulus. Dim3tteo (personal communication, 1983)
suggests that pressure on the annulus be maintained at 10 psi above
atmospheric pressure; this is to ensure that a positive pressure will
always be exerted on the pressure gauge regardless of changes in the
annulus pressure during injection. Owens (1975) suggests that a
pressure greater than that of the injection pressure be maintained on
the annulus. With the latter arrangement, any leakage in the tubing
creates leakage into the injected fluid stream and thus a detectable
drop in annulus pressure. This procedure may be limited to use in
relatively new wells where the injection string is designed to
withstand such pressure. In older wells or in wells converted from
producing wells where casing is not designed to withstand such
pressures, this procedure is not advisable.
Monitoring of annulus pressure can be conducted either
continuously or on a periodic basis. Continuous monitoring is
accomplished by utilizing a recording device which plots annulus
pressure versus time. The monitoring device is usually checked by the
operator on a regular basis (i.e. daily. weekly or monthly). Some
continuous monitoring systems are connected to an alarm or shut-down
device so that when the annulus pressure drops below or exceeds a
predetermined amount, an alarm warns of failure and the injection
operation shuts down until the cause of failure is located.
Periodic monitoring is accomplished by the operator noting the
pressure displayed on the wellhead pressure gauges on a regular basis.
Common industry practice is to monitor annulus pressure on either a
weekly basis or a daily basis; in some cases, daily monitoring may be
required. Table 3 illustrates annulus pressure monitoring
requirements of eleven states which have set these requirements.
Requirements range from daily monitoring/weekly reporting to quarterly
monitoring/annual reporting.
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TABLE 3. ANNULUS PRESSURE MONITORING REQUIREMENTS OF SELECTED STATES
State
Frequency of
Monitoring Required
Frequency of
Reporting Required
Alabama
Colorado
Florida
Louisiana
Michigan
Nebraska
New Mexico
Ohio
Oklahoma
Texas
Wyoming
Weekly
Weekly
Daily
Daily
Quarterly
Weekly
Monthly
Monthly
Monthly
Monthly
Daily
Bimonthly
Monthly
Weekly
Monthly
Annually
Monthly
Annually
Quarterly
Annually
Annually
Monthly
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Annulus pressure is generally recorded on a standard form so that
readings taken at different times may be compared in a similar format.
Injection pressure and temperature of the injected fluid should also
be recorded to provide a better basis for interpretation of the
annulus pressure monitoring data.
INTERPRETATION
Interpretation of annulus pressure monitoring results, under
conditions where there are no changes in either injection pressure or
injected fluid temperature, is relatively straightforward. In an
operating injection well in which there is no surface pressure
maintained on the casing-tubing annulus, a leak in the tubing or
packer will cause pressure in the annulus to increase if there is
fluid entry from the tubing or the injection formation. The pressure
will decrease if the hydrostatic pressure on the annulus fluid is
greater than the injection pressure or the pressure in the injection
formation. A leak in the casing may manifest itself as either an
increase or decrease in the annulus pressure, depending on whether the
pressure outside the casing is greater than or less than hydrostatic
pressure on the annulus.
In a well in which some pressure is maintained on the annulus
fluid, the response of annulus pressure will depend on the amount of
pressure applied at the surface and on the pressure differential
between annulus pressure and the pressure at the source of the leak.
If annulus pressure is greater than injection pressure, and a leak
occurs in the tubing or packer, a pressure drop in the annulus will
occur. Likewise, if annulus pressure is greater than formation
pressures and a leak occurs in the casing, annulus pressure will drop.
The reverse is true for tubing or packer leaks if injection pressure
exceeds annulus pressure, and for casing leaks if formation pressure
exceeds annulus pressure.
In wells in which a pressure drop is noted on the casing-tubing
annulus, it is possible to relate the pressure decrease to volume of
fluid lost. Langlinais (1981) provides tables which can be used to
estimate the volume of fluid lost from a well for a given annulus
pressure change (Appendix A). As an examp,le, he suggests that a well
with a 7 5/811 diameter casing and a 2 3/8' diameter tubing, with a
packer at 3000 feet, would experience a loss of 1.929 gallons of
annulus fluid with a 100 psi pressure drop in the annulus. The flow
rate depends on the time period over which the pressure drop is noted.
Thus, if the 100 psi pressure drop had occurred for a 15 minute
period, the fluid loss rate from the well would be 185 gallons per
day. This would apply to a leak in either the casing, the tubing or
the packer.
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In practice, several variables may complicate the interpretation
of annulus pressure monitoring results. The two major phenomena that
affect monitoring of annulus pressure are the responses of the annulus
to injection pressure changes and to injected fluid temperature
changes.
An injection well with a closed annulus will experience annulus
pressure changes whenever injection pressures are changed because the
mechanical dimensions of the tubing change with injection pressure;
thus, the volume of the annulus and hence the annulus fluid pressure
at the surface will vary. Langlinais (1981) determined that annulus
pressure responses are sensitive to the fOllowing variables:
1) changes in injection pressure; 2) the well geometry (relative sizes
of tubing and casing); and 3) the permeability of the injection zone
multiplied by the thickness of the injection zone (in darcy-feet). He
was able to establish a relationship in annulus pressure change to
injection pressure change for a given well geometry and injection zone
permeability x thickness (Table 4). Using this table, if a 400 psi
injection pressure change were to occur in a well completed with
5 1/2" casing and 2 7/8" tubing in a relatively highly permeable
formation (50 darcy-feet), a change of about 12 psi in annulus
pressure could be expected (400 psi/34). As the table demonstrates,
the annulus pressure change is rather small relative to an applied
injection pressure change for a well with a large annulus. On the
other hand, in wells with a small annulus, the annulus pressure change
is of more consequence, but is still small compared to
temperature-induced changes.
In many larger injection operations, the temperature of the
injected fluid is kept relatively constant, thus in these systems
seasonal temperature variations may be the only temperature changes
noted. However, in some injection operations, the injected fluid
temperature may change significantly on a more irregular basis.
Temperature changes may be due to 1) varying storage time at the
surface for fluid; 2) variations in temperature at the oil-water
separation facility; or 3) the need to transport the salt water from
the point of collection to the injection well. Changes in the
temperature of the injected fluid will cause the annulus fluid to
undergo a volume change due to thermal expansion or contraction, and
will also cause a volume change in the annulus, due to thermal
expansion or contraction of the tubing and casing. The latter change
is due to the differences in the coefficients of thermal expansion of
the annulus fluid (i.e. water) and the casing and tubing (i.e. steel).
With injected fluid temperature changes, the annulus thus undergoes
several changes, the net result of which is measured as an annulus
fluid pressure change at the surface.
Langlinais (1981) has identified the variables involved in
annulus pressure change due to injected fluid temperature change as:
1) depth of the well; 2) injected fluid temperature; 3) mechanical
configuration of the well (size of the annulus); 4) geothermal
30
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TABLE 4. CHANGE IN ANNULUS PRESSURE/CHANGE IN INJECTION PRESSURE
RELATIONSHIPS (LANGLINAIS, 1981).
~p injection
~p annulus
Geometry
(casing x tubing) 50 darcy ft 5 darcy ft
9%" x 7" :1:6.2 :1:5.9
7" x 4%" :1:13 :1:11
7" x 3%" :1:38 :1:29
7" x 27/8" :1: 120 :1:90
5%" x 2%" :1:34 :1:26
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gradient; and 5) heat exchange coefficients. In addition, because of
the effect of thermal expansion of the tubing and casing, a calculated
volume change in annulus fluid will not result in a pressure change as
though the annulus were a fixed volume.
Graphs presented in Appendix B (Langlinais, 1981) depict the
response of annulus pressure to injected fluid temperature. In these
graphs, annulus pressures (on the vertical axis) correspond directly
to annulus volume changes due to temperature changes. Positive
pressure indicate expansion of annulus fluid and negative pressures
indicate contraction of annulus fluid. Each graph represents several
depths for a given well geometry. The surface temperature is assumed
to be a constant 69°F and the geothermal gradient 1.3°F/100 ft. These
graphs can be used to determine the expected annulus pressure changes
for injected fluid temperature changes, but cannot give annulus
pressure at a particular injection temperature, since other variables
(i.e. level of annulus fluid in the well) are not considered.
As an example, suppose fluid at a temperature of 85°F is being
injected into a 400 foot deep injection well with 4 1/2" tubirj and 7"
casing. If the injected fluid temperature were to increase to 95°F, an
annulus pressure increase of about 300 psi is expected. The graphs
take into account the fact that injected fluid heats the annulus fluid
only to the depth at which injected fluid temperature is equal to the
temperature outside the well bore, and below that depth the injected
fluid cools the annulus fluid. A 1000 foot well with the same
injection fluid temperature change, then, would experience an annular
pressure increase of nearly 400 psi.
In creating these relationships, Langlinais (1981) assumed that
the well was allowed to achieve steady-state equilibrium conditions.
However, because injected fluid temperatures may vary somewhat on a
daily basis, and may not allow the well to reach steady-state
conditions at any temperature, these relationships may not always hold
true. Langlinais (1981) recommends that in predicting the response of
a well to injected fluid temperature changes, a value of 65% of peak
change be used. As an example, if injection temperature in a 3000
foot deep well with a 5 1/2" diameter casing ~nd 2 3/8" diameter
tubing reaches a maximum temperature of 95°F ,nd a minimum temperature
of 85°F on a daily basis, there is a 10°F temperature change over each
day; the average temperature of injected fluid is 90°F. Taking 65% of
the 10°F temperature change, or 6.5°F, and spreading that 6.5°F range
on either side of the 90°F average, values of approximately 93.2°F and
86.7°F are obtained. Thus, for this well, a daily annulus pressure
variation of approximately 260 psi could be expected.
It is important to note from this discussion that even slight
injection temperature changes result in a noticeable annulus pressure
change. Temperature changes as small as 2°F may result in as much as
32
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a 100 psi pressure change. Therefore, th~ interpretation of annulus
pressure monitoring results must take injected fluid temperature into
account. This may necessitate the monitoring of injected fluid
temperature to ensure that pressure changes noted at the surface are
due solely to changes in temperature in injected fluid and not to
possible casing, tubing or packer leaks.
COST
The cost for monitoring annulus pressure is minimal, since the
equipment needed to perform the monitorirq (i.e. pressure gauges) is
relatively inexpensive and is either alr~Jcy installed on the
wellhead, or can be readily installed (with the proper fittings) on a
temporary basis. Time and manpower requirements for both continuous
monitoring and periodic monitoring are minimal, and consist simply of
the time and manpower required to take periodic pressure measurements
or to monitor the continuous recording device.
No accurate figures regarding the cost of implementing an annulus
pressure monitoring program were available at the time of writing of
this report, although in comparison with other mechanical integrity
testing methods, costs are very low.
ADVANTAGES AND DISADVANTAGES
The primary advantage to monitoring of annulus pressure is that
because the technique provi des a "real-time" measurement of well
integrity, the well does not have to be taken out of service for
monitoring to be performed. This is a significant advantage to
operators because it minimizes "down time" for the well. This adds to
the cost advantage of this method, which is already significantbecause
manpower requirements are low, little if any specialized equipment is
needed to perform the test, and the test can be conducted in a very
short period of time. Another advantage of annulus pressure
monitoring is that it provides for early determination of a mechanical
integrity problem, because the well is normally monitored on a regular
and frequent (i.e. daily, weekly or monthly) basis. Compared to other
mechanical integrity testing methods, which may be used only once
every year or once every five years, annulus pressure monitoring
provides a more timely indication of well failure.
There are several potential drawbacks to using annulus pressure
monitoring as a means of determining mechanical integrity of an
injection well. One disadvantage of this technique is that several
variables may complicate the interpretation of monitoring results. As
previously discussed, variations in injection pressures and injected
fluid temperatures can cause significant changes in annulus pressures.
If these are not accounted for during the period of monitoring,
erroneous monitoring data may result, which may lead to faulty
conclusions regarding the mechanical integrity of the well.
33
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Another disadvantage is that it is possible that monitoring of
annulus pressure would not detect the presence of a leak in the
tubing, packer, or casing if the fluid pressure on the outside of the
annulus is in equilibrium with the pressure imposed on the annulus.
It is possible to vary annulus pressure periodically so that the
presence of leaks at equilibrium with anyone pressure become app~rent
thus eliminating this problem for wells in which pressure is
maintained on the annulus.
Annulus pressure monitoring is a method limited to use in wells
completed with tubing and packer; thus it cannot be used in ~any
operating injection wells. Also, because of the n~ture of the method,
it cannot be used to detect the presence of fluid migration behind
casing.
EXAMPLES
No examples of annulus pressure monitoring were available at the
time of writing of this report.
34
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REFERENCES
Langlinais, Julius, 1981, Waste disposal well integrity testing and
formation pressure build-up study; Final Report submitted to
Louisiana Department of Natural Resources, September, 1981, 56
pp.
Owens, Sam R., 1975, Corrosion in disposal wells; Paper presented at
the National Association of Corrosion Engineers, South Central
Meeting, October 1974, Houston, Texas, 3 pp.
Warner, Don L., 1975, Monitoring disposal well systems; u.S.
Environmental Protection Agency publication #EPA-680/4-75-008, 99 pp.
35
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SECTION 6
PRESSURE TESTING
SYNOPSIS
Pressure testing is one of the standard industry procedures
utilized to detect the presence of leaks in the casing, tubing, or
packer of an injection well. In fact, it is required in many
oil-producing states as the means of testing the integrity of casing
in new production and injection wells at the time that the casing is
cemented into the borehole. Pressure testing may also be required on
wells newly converted from production to injection and on wells in
which major workovers have been performed.
The type of pressure test performed on an injection well is
dependent on the construction details of the well, though certain
general testing procedures apply to all wells. Pressure is applied to
the liquid-filled, shut-in casing or casing-tubing annulus by one of
several means, usually either a drilling rig mud pump or service
pumping equipment. Liquid pressure is generally used, as gas pressure
may not generate useful test results. The amount of pressure used in
the test, and the period of time the pressure is held on the well
depend on the requirements of individual state regulatory agencies.
Maintenance of the shut-in pressure during the test provides evidence
of the mechanical integrity of the well. If a significant pressure
die-off is noted during the period of the test, the casing or one of
the other well components (tubing or packer) is considered to be
leaking.
PRINCIPLES
The principle of a pressure test is simple and straightforward.
Liquid pressure applied to a fixed volume enclosed vessel, such as an
injection well closed at the bottom and the top, should remain
constant if there are no leaks in the well. Because a volume of
liquid requires only a relatively small volume change to yield a
detectable pressure change, any leak in the vessel being pressurized
should make itself evident as a pressure drop (if liquid pressure
outside the vessel is less) or pressure increase (if liquid pressure
outside the vessel is greater). Thus, it is possible to use pressure
changes, as monitored during a short-term test conducted at the
surface, to determine the presence of leaks in the casing of an
injection well, provided the test is properly conducted.
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EQUIPMENT
Provided that the well to be tested is equipped with suitable
wellhead pressure gauges, the only equipment necessary to conduct a
pressure test is a device to generate fluid pressure. Generally, a
drilling rig mud pump or service pumping equipment, which can supply
the desired pressures, are used for pressuring well casing. As these
are the two most common oil-field practices for applying pressure to
wells for various purposes, this equipment is generally available
through either drillers or well servicing contractors.
If the well to be tested is not equipped with a suitable
wellhead, the well must first be outfitted with that equipment. The
wellhead should have pressure gauge connections, so that the pressure
applied to the casing or casing-tubing annulus can be monitored during
the period of the test, and a recording device to record any pressure
fluctuations.
PROCEDURES
The procedures for pressure testing an injection well differ
depending on whether the well to be tested is a new well or an
existing well, and further differ in existing wells depending on the
construction details of the well. The following injection well
configurations are described in this document:
- New wells (Figure 4)
- Existing wells without tubing and packer (Figure 5A)
- Existing wells with tubing and packer (Figure 5B and 5C)
- Existing wells with tubing and without packer (not illustrated)
Certain general procedures, which follow, apply to pressure
testing for any of the above well configurations.
The pressure is applied by the chosen method, either to the
shut-in casing or to the casing-tubing annulus, and monitored for a
period of time. The pressure used for testing, the period of time the
pressure is monitored and the amount of pressure variation
("bleed-off") allowed are all dependent on the requirements of the
individual state UIC program. Table 5 illustrates the pressure
testing requirements for fifteen states which have these requirements.
A common requirement of many states is that the wen be pressuri zed to
300 psi or the maximum allowable injection pressure, whichever is
greater, and the pressure monitored for 30 minutes. The amount of
pressure bleed-off allowed is left to the discretion of the individual
state regulatory agencies, and ranges from no bleed-off allowed to ten
percent bleed-off allowed.
Pressure tests are nearly always conducted on the entire length
of casing or tubing in the well. However, it may be possible to
37
-------
+
A
New well to be completed as an
open-hole well. Completion will
be accomplished by drilling
through injection lone.
Applied Pressu re
Surface Casing
Cement
Long String Casing
Cement
Injection Zone
."
,".l'
.
- :.,.
- '::~:
~
,i~:
-
.".
".'
."
.'.:~
.,
,-
:;~"':':..::";:. ~.;~~; .~:~.
B
New well to be completed as a
cased-hole well. Completion
will be accomplished by
perforating casing adjacent to
injection lone.
Figure 4. Types of injection well configurations (new wells).
38
-------
Applied Pressure
Applied Pressure
Applied Pressure
A
Well with casing, without
tubing and packer, fitted with
temporary packer for pressure
test
B
Well with casing, tubing and
packer
Cement
Packer
C
Well with casing, tubing,
packer and seating nipple
Figure 5. Types of injection well configurations (existing wells).
39
-------
TABLE 5. STATE PRESSURE TESTING REQUIREMENTS FOR CLASS II INJECTION WELLS
State
Alabama
Arkansas
Colorado
Florida
Kansas
Kentucky
Louisiana
Michigan
Mississippi
Nebraska
North Dakota
Ohio
Oklahoma
Texas
Pressure Required (psi)
0.2 x depth to injection interval, not to
exceed 1,500 psi
300-750 (sliding scale)
300 or minimum injection pressure,
whichever greater
0.2 x depth to injection interval
100 or maximum authorized injection
pressure, whichever greater
100 or maximum allowable injection
pressure
300 or maximum allowable injection
pressure, whichever greater
Minimum of 133 percent of expected
operating pressure
500
125 percent of maximum authorized
injection pressure or 300 psi, whichever
greater
1,000
300 or maximum allowable injection
pressure, whichever greater
Length of Test
(minutes)
30
Allowable
Bleed-Off
( percent)
10
30
30
10
5
30
30
10
N/A
N/A
N/A
30
N/A
N/A
30
N/A
10
N/A
15** 0
15 5
15 10
30 10
20 5
15 10
500 or maximum authorized injection
pressure, whichever less; at least 200 psi
West Virginia 2,000
Wyoming 1,000 psi or maximum injection pressure,
whichever greater
"left to discretion of state inspector
Hrequire longer test if any pressure loss is noted.
N/A=not available
40
-------
utilize a dual packer system (Figure 6) or a retrievable bridge plug
or temporary packer to isolate specific intervals in a well for staged
pressure testing. Pressure may then be exerted on the chosen interval
via tubing between the dual packers, or an increasingly shorter length
of casing or tubing above the retrievable bridge plug or temporary
packer. This procedure may be repeated as necessary in any interval
in the well, or the packers may be reset to any separation to test any
length of casing greater than 3 feet. This procedure provides a means
of not only detecting but also locating a leak. However, it is more
time-consumi ng than Inorma1" pressure testi ng.
Rome and LaRussa (1978) describe a tool which can be used for
testing specific intervals of tubing or well casing for leaks. The
tool (Figure 7) consists of longitudinally spaced packers which can be
expanded to isolate a portion of the tubing or casing string for
subjecting the isolated portion to a pressure test. Liquid pressure
is applied to the isolated portion of the tubing or casing through
flow controllers which include a liquid diffuser that prevents direct
impingement of the testing liquid onto the inside coating of the
tubing, thereby preserving the integrity of the coating. The spaced
packers are expanded by piston and cylinder assemblies arranged so
that the tool does not move or change in length in order to compress
the packers when in operation. A swab structure on the bottom end of
the tool prevents the testing liquid from running down the tubing or
casing as the tool is moved from one position to another.
Normally, liquid is used to pressurize injection wells.
Langlinais (1981) suggests that the practice of using gas to
pressurize injection wells should be avoided because the loss of fluid
from the well may not be detectable as a pressure decrease. This is
primarily because of the difference in compressibility between gas and
liquid. A given volume of gas requires a relatively large volume
change to yield a detectable pressure change, whereas the same volume
of liquid will yield a detectable pressure change with a relatively
small volume change.
The following example, given in Langlinais (1981) emphasizes the
difference in pressurizing with gas and with fluid:
If the volume of gas used to pressurize the column of fluid in
the casing is approximately one barrel at a pressure of 500 psi, then
in a well utilizing 7 5/8 inch diameter casing with 3000 feet of 2 3/8
inch diameter tubing, a one gallon leak results in a pressure loss of
approximately 12 psi. If the same pressure were applied with water,
then a 50 psi pressure loss results. On the other hand, if the
original gas volume used to pressurize the column of fluid in the
casing had been two barrels, then the pressure loss would only have
been half as much, or 6 psi.
In this example, if the observation time were 30 minutes, the
leak in the well would amount to about 48 gallons per day, or 17,500
41
-------
Applied Pressure
Casing
Cement
Tubing
Packer
Cement
Inert Fluid
Packer
Plug
Injection Zone
Figure 6. Dual packer system used for staged pressure tests.
42
-------
Casing or Tubing
Tool Head
Top Rubber Sealer
Flow Controller
Diffuser
Coupling
'f
Flow Controller
Diffuser
Bottom Rubber Sealer
Tool Foot
Swab Structure
Figure 7. Tool utilized for testing specific intervals of well casing or tubing for leaks
(After Rome and LaRussa, 1978).
43
-------
gallons per year (assuming constant operation). This could certainly
be a "significant leak," as defined by the UIC program criteria.
Thus, it is clear that if gas is used to pressurize the well, a leak
of this size may not be detected or may be accepted if even a five
percent pressure die-off is permitted by testing criteria.
The pressure testing procedures which follow are those which are
specific to each of the four well configurations previously described.
New Wells
Following the completion of a new injection well (Figure 4), the
well casing is generally tested as a matter of course to assure the
operator and to satisfy regulatory concerns that no leaks exist in the
casing. This test is usually performed after the casing has been
installed and cemented in place, but prior to perforating (if a
cased-hole completion) or drilling out the casing shoe (if an
open-hole completion) so that the casing is entirely sealed at the
bottom. The casing is then shut in at the top with a wellhead seal or
blowout preventer and the casing is filled with fluid. The well
should be allowed to remain idle for several hours so that the
temperatures of the fluid inside the casing and the formation fluids
at depth can equilibrate; pressure can then be applied to the well.
Ignoring this step may cause problems in the interpretation of the
data obtained from the test. This test is a test of the entire length
of casing.
Existing Wells Without Tubing and Packer
A pressure test of the casing of a well without tubing and packer
(Figure 5A) requires the installation of a temporary packer or
retrievable bridge plug above the injection zone prior to testing.
Once the temporary bottom seal is effected, the well can be tested in
the same manner as a new well, the only difference being that the
length of casing below the temporary seal is not tested. Care should
be taken to choose the correct type of packer to ensure that the
packer is able to withstand the pressure applied to the column of
fluid above it. Otherwise, the packer may leak, resulting in
misinterpretation of the test results.
Existing Wells With Tubing and Packer
The standard procedure to test the mechanical integrity of wells
with tubing and packer (Figure 58) is to first apply pressure to the
fluid-filled annulus between the tubing and the casing and monitor the
pressure. To conclusively test the well, the hydrostatic pressure in
the annulus at any depth must exceed both the formation pressure and
the hydrostatic pressure in the tubing. This will allow for a
determination of the mechanical integrity of the casing, tubing and
packer as a unit. However, this test does not permit the operator to
determine which of these three well components may have a leak, if one
44
-------
should be present. A leak in anyone of these components would
manifest itself as a pressure loss at the surface.
This type of test should be conducted with the tubing shut in
(i.e. injection should be ceased for the period of the test). Prior
to conducting a pressure test on a well with tubing and packer, the
type of packer in the well should be known since this will determine
the amount of pressure which can be applied to the annulus. If the
packer in the well is a compression-set packer, in which the weight of
the tubing is placed on the packer to effect a seal, then additional
annulus pressure will tend to increase the integrity of the seal. On
the other hand, if the packer is of the tension-set type, in which
tension is needed to effect a seal, additional annulus pressure may
cause the packer to unseat. The possibility of unseating the packer
will be determined by the original tubing tension at the time the well
was completed (Langlinais, 1981). If the packer is set high above the
perforations, the packer should be lowered so that a test of the
entire length of casing and tubing above the perforations is possible.
Moving of a packer which has remained in place for a long period of
time nearly alwdls necessitates removing the packer and replacing the
sealing elements, which may be a time-consuming operation.
Other variables which should be known prior to conducting a
pressure test on a well include casing yield strength, wall thickness,
and type of casing connection. All of these will have some bearing on
the amount of pressure which can be applied to a particular well
without causing failure of one of the well components.
If the injection well must maintain some flow and cannot be shut
in, a dynamic test, or one which is conducted while the well is
injecting, must be performed. The most dependable method to conduct a
dynamic test is to continuously monitor the tubing injection pressure,
the injected fluid temperature and the tubing-casing annulus pressure
simultaneously. Short-term variations in injection pressure and
injected fluid temperature, though uncommon, may complicate the test
results and make it more difficult to recognize leaks in the casing,
tubing or packer in this type of test. A discussion of the
implications of injection pressure and temperature influences on
annulus pressure is given in Section 5 "Monitoring of Annulus
Pressure. II
In wells with tubing and packer completions in which the tubing
is fitted with a seating nipple at the base of the tubing, (Figure 5C)
it is possible to pressure test the tubing independently. In wells
with tubing and packer completions in which the tubing is not fitted
with a seating nipple, it is still possible to independently
pressure-test the tubing by installing a retrievable tubing plug. A
downhole shutoff valve, which opens and closes by tubing rotation,
could also be utilized to shut in the tubing. The presence of either
the seating nipple, the tubing plug or the shutoff valve thus allows
the independent determination of tubing mechanical integrity. The
45
-------
test is performed by shutting in and pressurizing the fluid-filled
tubing and monitoring for pressure loss.
Existing Wells With Tubing and Without Packer
A pressure test of the casing of a well with tubing but without a
packer can only be accomplished after the tubing has been pulled and a
temporary packer or retrievable bridge plug has been set above the
injection zone. After this is done, the procedure for testing the
casing is essentially the same as for a well without tubing and
packer.
A pressure test of the tubing in this type of well can be
accomplished if the tubing is fitted with a seating nipple or can be
fitted with a tubing plug at the bottom. The tubing can then be
sealed at the well head and pressure applied on the tubing. The
tubing could be inspected at the surface for defects after it has been
pulled from the well, but this may not be effective in finding small
leaks or leaks at tubing joints.
Interpretation
Interpreting the results of a pressure test is a relatively
straightforward task. Generally, a surface recording device will have
been used to record pressure test results; the results are displayed
on either a strip chart or a disc chart. Maintenance of constant
pressure as applied either to the casing or to the casing-tubing
annulus results in a straight-line chart recording over the period of
the test. Any change in pressure, either an increase or a decrease,
will result in a deviation from the straight-line recording.
If after the prescribed period of time the pressure applied to
the well does not change, it can be concluded that the well does not
have a leak. If there is a slight pressure decrease, it may be due to
air dissolving in the fluid in the well, or to the failure of
temperature in the well bore to stabilize with formation temperatures
before the test is performed (Langlinais, 1981). The pressure test
should be repeated if this situation is encountered. If, after the
well is pressurized a second time, there is a continued and
significant pressure die-off during the period of the test, it is
likely that a leak in the well exists. If a leak in the well is
detected, the rate at which the fluid is being lost and thus the size
of the leak can be estimated using methods outlined by Langlinais
(1981). It may not be possible, without further testing, to determine
the location of the leak or to determine which component of the well
(casing, tubing or packer) is leaking.
There may also be pressure increases immediately following
pressurization of the well. These are usually due to thermal
expansion of the fluid in the well, which should stabilize after a
short period of time. Another cause of increased wellhead pressure
46
-------
may be leakage into the well from high-pressure zones in the
subsurface that were not adequately isolated from the well bore by the
packer.
COST
Cost for a pressure test will vary a great deal depending on the
construction details of the well, the distance of the well from the
service contractor, and a number of other variables. Costs for
pressure testing an operating well, including pump and packer rental,
time allotted to testing, a round trip to and from the well for the
service contractor, and time required to pull tubing, set and remove
the retrievable packer and reset the tubing are estimated to be in the
range of $2000 to $10,000 (Dimatteo, personal communication, 1983).
ADVANTAGES AND DISADVANTAGES
In compa ri son to other mechanica 1 i ntegri ty tests, pressure tests
are relatively inexpensive and easy to perform in both new and
existing injection wells. They generally produce results which are
simple and stra i ghtfor\tit rd wi th regard to i nterpretati on, if they are
conducted properly. For these reasons, pressure testing is perhaps
the most widely utilized means of determining mechanical integrity.
In many cases, pressure testing of a well takes less than one
day's time. In some cases, however, pressure testing may take up to
several days.. during which the well will be out of service.
Pressure testing of an injection well which serves as a
salt-\titter disposal well, particularly where the well of concern is
the only disposal well for a producing field, presents the problem of
what to do with the salt \titter produced during the period of the test.
The salt \tit ter must ei ther be stored on si te, haul ed off-site, or the
production shut in. Some disruption of production is inevitable if
the injection well is out of service long enough to overload the
alternative disposal methods.
If excessive pressures are applied to the well r the pressure test
itself may cause the well to develop a leak in either the casing or
the tubing, aggravating already deteriorating well conditions (i.e.
corrosion).
EXAMPLES
Figures 8 and 9 illustrate the results of a pressure test run on
a salt \titter injection well in Meigs County, Ohio. Figure 8 is the
completed state form for reporting of the pressure test on the annulus
between the injection tubing and the long string; Figure 9 graphically
displays the test. Initially a corrosion inhibitor and fresh \titter
\titS run down the annul us, then the 1 i nes were tested and the annul us
pressure tested. During the initial test, the pressure did not stay
47
-------
CONSTRUCTION AND TESTING REPORT
SAL'lWATER mm:'I'ICN WELLS,IFMWaD REDJ\1ERY PJnJEX:TS
ano DEPARIMENI' OF NAIDRAL RE:.9:XJR:ES
DIVISICN OF OIL l\ND GAS
CDll.M!US, cm:o 43224
IFcmn 251:4-21-83
1. CWO NAMES, AOORESS l\ND 'l'ELEPHCNE NlMBER: b. &WIW OR ERP NlMBER: 1
Liberty Oil and Gas 7. CXXJN1'¥: Me i gs
8. CIVIL ~: Oli ve
( ) 9. SEX:TICN: 1m:
2. ~I NUMBER: 34 1 052'" 2 32"14 10. FRACI'ICN: 35 Ql'R. 'lWP.:
J. DATE PERoUT ISSUED:
4. LFASE NAME: "B" 11. TRACI'/ALIDIMENI':
5. TYPE OF REPORT:
SAL'lWATER mm:'I'ICN WELL (SWIW) X8 ornER SPB:IFY
ENHANCED REXXJ\IERY PFO.ID:T (ERP)
12. CASrnG l\ND 'IDBrnG REXX>RD: Please indicate which is used (oerrent: or IIIJd)
SIZE FEET Usn> IN NCUm' OF CEMENl' FEET LEPI'
DRII.LJN; OR KID IN WELL
8 5/8 251 . to surface (cmt) All
4 1/2 2083' 1,0 sx rmt J\ll-plllp hilck
2 3/8 3Pprox. 1:;00' Set on a packer 1 '"100' Ini
exMIDn'S: Took tHO ioints nf ~"hina out to oet ""rJ,pr ~n ~p~ f.O f~ 1 J50~
13. Cl:MENI' '!Up OF LCNGSTRING: 1,177 ft. Lorged 2-2-82
14. TYPE lIND SETTrnG DEPTH PAO
-------
LEASE M B Hall
This line merely
shows the length
of time the pressure
test was run
J?
~
~
~
.,:.:>
~~
~O
~
~
z
c
~
CP
m
::D
VJ
.j:>.
.j:>.
()
o
~
~
<:
~
VVOf:
Figure 9. Graphic depiction of a pressure test.
49
-------
within the 5 percent allowable pressure bleed-off. The tubing was
pulled up to tighten the packer and the pressure test repeated.
Again, the test failed, the tubing was pulled up once more and the
annulus retested. This time the pressure remained within the 5
percent limit and the well met the integrity test (Dailey, personal
communication, 1983).
Figures 10 and 11 illustrate a pressure test on a saltwater
disposal well in Santa Rosa County, Florida. Figure 10, the state
well inspection report, indicates that in this well, in which
tubing-casing communication was occurring, the tubing and packer were
replaced. The well was sUbsequently pressure tested at 1200 psi for
30 minutes. Figure 11 graphically displays the test, which shows that
there was no bleed off.
50
-------
STATE OF FLORIDA
WElL INSPECTION REPORT
Rig
Well Type
plant
66
SWD
Santa Rosa
Operator Exxon Corp.
BCS/BCNP
Sec~ T ~R 29W
Phone
Permit No 502
Well Name & No
Fleld/ Area
Well Location
Contractor --
API No.
SWDS No.7 Well No. ]
.Jay field
+11 mile south of the Santa Jay
WellTech
Well Status - -"dj0
County
OF
TO 16,373 -
Plugback T.D. 10,000
Note II a violation eXists. the inspecting agent IS to designate the Rule violated (16C-27 05, Casing. lor example) and describe
the Infraction. If no violation eXists write "No violation"
Spud
Replacement of tubing and packer and testing of the annulus.
----
___There was tubing-casing communication in this well. Attached is a Cobb-pressur~--
ch,grt for the I ,:lOO-psi, iO-mi nnte test of the annular space between ~ replacement
2 7/8 inch injection tubing and the 8 5/8 inch casing. There was no bleeding-off
~_.fr.QnL.t.his test, which I witnessed. ------- ---_.-
-----~----
---- ----
------
- -~-- - - - --
------ - -----
--------
----~--------~--- - ----
--- - --- -----
-- - ~-- --------
--- ---------
---- -~------- ----.
- __N..Q....viola_tj.Q.n~----- ----- --~------- -- ---
----- ------ ---
I certlly that I Inspected the above well and premises on the ~tlL--- - day 01 March--____- 198..:L, and that
said well was not In violation 01 any rule or regulation governing the Conservation 01 Oil and Gas In Florida, except as noted
above
Signed
Time:
5 hours
This inspection IS made under authority 01 F S Chapter 377.21 entitled "JUriSdiction 01 Board"
Instruction to the Operator or Producer:
If any violation 01 rule(s) IS noted on this InspectIOn report. you are required to report to the Administrator 01 011 and Gas.
903 West Tennessee Street, Tallahassee. Florida 32304. (904/488-4191). within 5 days describing what action has been
taken to correct such violation, or to show cause why the rule cited In this report should not apply to the alleged violation.
00 NOT FAIL to reply to the Administrator 01 Oil and Gas within the period noted. Failure to reply may subject you to a
penalty lor each day that such violation noted continues beyond live (5) days Irom the date of this Inspection report
(CHAPTER 377 37. Flonda Statutes. Conservation of Oil and Gas Resources)
NOTE Original report to be filed with the Administrator of Oil & Gas
Yellow copy to be served on operator's field representative or mailed to the operator 01 record
Pink copy to be retained by Inspecting Agent
Figure 10. State well inspection report for a pressure test on a salt water disposal well.
51
-------
50
~
~ i(,
'(,\
."
~
o
~
m
z
(11 (;)
o -
Z
m
m
~
z
(;)
()
9
09
Figure 11. Graphic depiction of a pressure test showing no bleed 0".
52
-------
REFERENCES
Langlinais, J., 1981, Waste disposal well integrity testing and
formation pressure build-up study; Final Report submitted to
Louisiana Department of Natural Resources, September 1981, 56 pp.
Rome, D.J., Sr. and S.P. LaRussa, 1978, Tubing testing tool; U.S.
Patent #4,083,230, April 11, 1978, 9 pp.
53
-------
SECTION 7
WELL LOGGING:
A GENERAL DISCUSSION
INTRODUCTION
The mechanical integrity of injection wells may also be tested
using well logging techniques offered by professional well logging
companies. A well log is defined as, lIa record containing one or more
curves related to some property in the wellbore or some property in
the formations surrounding the wellbore" (Ransom, 1975). Borehole
measurements are obtained by lowering one or more tools into the well
and measuring either the characteristics of the formations intersected
by the well or the structural components of the well. In the case of
an injection well, a log may be run to determine any or all of the
following:
1)
2)
the presence or absence of casing leaks;
the quality of the cement bond to the casing;
3) whether or not channeling of fluid occurs outside the well;
4)
the rate and direction of fluid movement into or out of the
well at any desired point;
5) casing condition (both internally and externally); and
6)
tubing integrity.
Although each log is designed to monitor specific parameters and
requires specialized interpretation, the basic logging equipment, need
for interpretation and method of determining the cost of each log are
similar for most logs. This chapter provides a discussion of those
common parameters which pertain to the logs which have applicability
for determining the mechanical integrity of injection wells.
LOGGING EQUIPMENT
Even though there is a wide variety of instruments used for well
logging, all logging equipment has the same essential elements. The
primary components of a logging system include a downhole sensor an
electric cable attached to the tool, a powered winch for hoisting the
tool, a calibrated sheave for measuring the length of cable in the
hole, a weight indicator, a prime power unit, surface control circuits
and a recording system (Guyod and Shane, 1969) (Figure 12). The
54
-------
WEIGHT INDICATOR
...
181
o
/I:
Go
CABLE
WINCH
CIRCUITS
Figure 12. Truck-mounted logging equipment set up at a well (Guyod and Shane, 1969).
55
-------
downhole sensor is housed in a Wltertight probe which receives power
from the surface and transmits signals to the surface via the logging
cable. The probes may either be held in the center of the well by
centralizers or allowed to hang freely in the well depending on the
requirements of the measurements being made. As the probe is moved up
or down the hole, the sensor emits a signal in response to lithology,
fluid or borehole parameters (Keys and MacCary, 1971). Logging
measurements (with the notable exception of temperature logs) are
normally made by lowering the probe to the bottom of the hole and
recording data as the probe is raised to the surface. Logging speed
depends on the type of measurement performed, but typically ranges
from one half to two feet per second (Guyod and Shane, 1969). Some
logs, particularly temperature logs, may have to be made at a lower
speed.
The signal transmitted by the cable is processed at the surface
by electronic equipment. Control panels permit the regulation of (1)
logging speed and direction, (2) power to surface and downhole
electronics, (3) a signal conditioning, and (4) recorder response
(Keys and McCary, 1971) (Figure 13). The logging signals are recorded
on chart paper, photographic film and/or magnetic tape as a function
of the position of the probe in the hole (Labo, 1978). Logs at
various vertical scales are produced by changing the gear ratio in the
recorder. The recorder may be driven as a function of time for some
1 og s .
In addition to the actual logging system, other equipment is
needed to sa fely log an i njecti on well. When an i njecti on well is
under pressure, pressure control equipment is usually necessary at the
si tee Logs can be run wi th or wi thout well head pressure control, wi th
or without a full lubricator and with or without a rig depending on
the situation and expected pressures (Rust and Feather, 1977). The
most typical configuration for a pressurized well is shown in Figure
14. A lubricator is an assembly of wireline pressure control
equipment which consists of a blowout preventor, riser, flow tube and
stuffing box (Ransom, 1975). The lubricator can be used without a
blowout preventor which is usually not necessary in injection wells.
A lubricator permits the tools to be introduced into the well without
the loss of pressure control, but the use of a ri g or some form of
supporting mast at the site is necessary (Rust and Feather, 1977).
LOG ANALYSIS
A log is a continuous record of apparent values over pre-selected
intervals of the well. In order for these values to be quantified or
qualified, a log analysis must be performed. The correct recording
and interpretation of well log data are extremely important steps in
ensuring useful results. An experienced, professional log analyst
must be employed to do log interpretation.
56
-------
RECORDER ORlvE ---
[1]
RECORDER
~ t
~ '"
III",
~ ~
DEPTH
INDICATOR
---,
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
I
_.J
>
~ -
-oil
'" Z
" ...
0:
o
UU
...
00:
" oil
Z ...
- >
>- -
'" 0:
Figure 13. Block diagram of geophysical well logging equipment (Keys and MacCary, 1971).
LOGGING
SPEED AND
DIRECTION
DOWNHOLE
POWER
(NOT UNIVERSAL I
SIGNAL CONDITIONING
ZERO POSITIONING
SENSITIVITY
TIME CONSTANT
ETC
I I I
L______~ ----~---
LOGGING CONTROLS
57
-------
Cable
\
Hydraulic
Packing
Gland
Control Fluid
In/ectlon
Seal
Salety
Check Valve
Riser
~PIPe
Blowout
p"",,", \
Tool
-Trap
I,"
!
Lubricator
Figure 14. Diagram of a lubricator (Ransom, 1975).
58
-------
Professional log analysis is available at extra cost from the
logging companies which perform the logging service and also from
professional well logging consultants. In order to properly ~nalyze a
log, the log analyst must be intimately familiar with the principles
of each log and have a knowledge of the geologic environment and
construction of the well for which the log was obtained. Often more
than one type of log is run in a well to enhance the interpretation.
Combinations of logs are commonly better-suited to defining down-hole
conditions than individual logs. According to Keys and MacCary
(1971), the amount of information available from a log is a function
of the available background information, the number of different types
of logs run, the number of wells logged in a geologic environment and
the experience of the log analyst.
When analyzing a log, a log analyst may need to apply correction
techniques. Service company interpretation books detailing the many
corrections which may be necessary for each individual type of log are
widely available. Their availability should not preclude obtaining
the services of a professional log analyst to perform the
interpretation. Even the most accurately run log is not useful until
a proper analysis and interpretation of the readings have been
performed.
COST
The prices of well logging services are dependant on the general
pricing policy of the company, the type of log, the location of the
well and the need for specialized equipment at the site. The basic
pricing structure for logging services is relatively standard
throughout the industry. The costs associated with most logging
services can be divided into two categories: 1) general costs and 2)
log-specific costs.
General costs of well logging are usually listed in the front
section of each company's price schedule. The general section
includes basic fees to transport equipment to the site, charges for
manpower to operate the equipment, rental fees of specialized
equipment and fees for special conditions encountered either in the
well or at the site. The following list details typical items for
which logging companies charge fees. Sometimes companies combine fees
for items; therefore it is necessary to read each company's pricing
schedule to obtain more exact cost for logging a well.
1) Service charge - a standard fee charged for initiating the
logging service (Depth charge is not included). Normally this fee is
charged for each trip to the well.
2) Mileage - a per-mile fee is charged when the well site is
over a designated amount of miles from the well logging company
service center.
59
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3) Crew and equipment - fees are normally computed on a per-hour
or per-diem basis for all the time that a crew is on the site whether
or not a service is being performed. Different fee schedules may
apply to different situations. Some companies allot a certain amount
of "free time" before charges are initiated.
4) Specialized crew - when logs require the presence of a
specialized engineer to either perform or supervise operations, an
additional fee is charged. Rates may be computed on a per hour or
per-diem basis and normally include travel and lodging costs.
5) Incomplete operations - charges associated with inability to
run the log due to well conditions or changes of orders. Normally the
service fee plus other specified minimum charges will be assessed.
6) Equipment protection charge - a fee charged for the
protection against loss of the logging tool downhole. If this charge
is not paid, the customer is normally liable for the cost of all lost
tools. Furthermore, the logging company is not liable for damage to
the well.
7) Pressure control equipment - fees may be charged for the
installation and use of blowout prevention devices.
8) Equipment rental - mast rental fees are the most common
additional fee because either a mast or a rig is usually needed at the
site. Costs are usually assessed on a daily rate.
9) High temperature/pressure -
environments which exceed the normal
established by the logging company.
a per- foot charge.
10) Corrosive fluids - fees charged by the company for corrosive
conditions encountered in the well (usually hydrogen sulfide). The
fees are usually established on a per-foot basis.
fees charged for well
temperature and pressure limits
The fees are usually assessed as
11) Interpretation - fee for log interpretation which is nearly
always a separate charge.
Specific costs for these general pricing policy items vary among
logging companies. In order to provide a general idea of the costs
associated with these items, prices of six major well logging
companies were compared. These six companies represent approximately
85 percent of the well logging services performed in the United
States. To help ensure continuity among pricing schedules, the
"midcontinent" price catalog for each company was consulted. Costs in
other regions may vary significantly. Table 6 contains a typical fee
schedule for general price items.
In addition to the previously described general costs
log-specific charges are also assessed. Log-specific cost~ are
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usually based on a two-item fee schedule, one charge for depth and a
second charge for operation. Depth charges are assessed on a per-foot
basis with an established minimum charge. This charge is normally
assessed based on the deepest reading. Operation charges are also
calculated on a per-foot basis with an established minimum charge.
These costs are usually based on the actual number of feet in the
section logged.
TABLE 6. RESULTS OF SURVEY OF PRICES
CHARGED FOR WELL LOGGING SERVICES,
"MIDCONTINENT" AREA*
Item
Range of Prices
(1982 Dollars)
$475 - $1065 per job
$2.00 - $2.40 per mile
$75 - $150 per day
$275 - $310 per day
**
Service charge
Mileage
Crew and equipment
Specialized crew
Incomplete operations
Equipment protection charge
Pressure control equipment
Equipment rental
High temperature/pressure
Corrosive fluids
Interpretation
Depth & operation charges
$35 - $70 per job
$150 - $300 per day
$290 - $1500 per day
**
**
**
***
*This table was developed as a guide. Prices quoted in this table are
subject to change and are based on interpretation of pricing catalog
information.
**Due to pricing differences between companies, comparison cannot be
made.
***See each specific section for additional costs.
In order to compare costs for specific types of logs between
companies, it is necessary to be familiar with applicable trade names
for each log. Table 7 provides a listing of seven basic logs which
are described in subsequent sections of this report and lists
associated trade names for seven major logging companies. Specific
cost comparisons for each of these logs is contained within the
chapter on each log. The prices are based on those companies which
offer the particular logging service.
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TABLE 7. INDUSTRY TRADE NAMES FOR BASIC LOGGING SERVICES
Industry Trade Name Gearhart-Owens Int Schlumberger Dresser Atlas Welex Birdwell NL McCullough D,.-Log
BasIc Log
Temperature Differential High Resolution Differential PrecIsion Differential Differential! Absolute Temperature Log
Temperature Log Temperature (HAT) Temperature Temperature Temperature (TLD) Temperature Log Differential
(DTL) Temperature Log Log Temperature (TL) Temperature Log
Temperature Log (TL)
Radial Differential
Temperature Log
(RDT)
NOise Borehole Audio Audio Log Sonan Log N/A N/A NOise Log Borehole Sound
Tracer Survey Survey
(BATS)
Electromagnetic N/A Electromagnetic Electromagnetic N/A N/A Casing Inspection N/A
Casing Inspection Thickness Log Casing Inspection Log
(ETT)
Vertllog
Pipe AnalystS Log
(PAL) Magnelog
en
N Caliper Casing Inspection Caliper Log (CAL) Caliper Log Caliper Caliper Logging Electronic Caliper Casing Profile Caliper
Caliper Log (CtCL) (CA3, CA6, CAL, Log
CSG)
Caliper, FoRxo
Tubing Profile Caliper
Contact Caliper Log MIcro-Contact Caliper
(EMC)
Flowmeter Spinner Fluid Velocity Continuous Continuous Fluid Travel Log Spinner Log Spinner Log Spinner Log
Survey (SFVS) Flowmeter (CFM) Flowmeter
Packer Flowmeter Spinner Survey
(PFM)
Radioactive Tracer Radioactive Tracer Radioactive Tracer Tracer Log Radioactive Tracer N/A Nuclear Tracer Log Tracer Survey
Log (RTL) Log (RTL) Log
Nuclear Flolog
Cement Bond Log Cement Bond Log Cement Bond Log Acoustic Cement Acoustic Cement Cement Bond Log Bond CemenVSonic Cement Bond Log
(CBL) (CBL) Bond Log (ACBL) Bond Log/MIcro (VSD) Seismogram Log
Seismogram (MSG)
Cement Bond Variable
Denslfy (CBL-VDL)
From available InformatIOn at the time of Writing Subject to change.
N A =: not available
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REFERENCES
Guyod, Hubert and Lemay E. Shane, 1969, Geophysical well logging;
Hubert Guyod, Houston, Texas, 256 pp.
Keys, W. Scott and l.M. MacCary, 1971, Application of borehole
geophysics to water-resources investigations, book 2, chapter E1;
United States Geological Survey, 126 pp.
labo, J., 1978, A practical introduction to borehole geophysics; Paper
presented at the 48th Annual Meeting of the Society of
Exploration Geophysicists, San Francisco, California, 44 pp.
Ransom, R.C., 1975, Glossary of terms and expressions used in well
logging; Society of Professional Well log Analysts, Houston.
Texas, 74 pp.
Rust, D3vid and G.l. Feather, 1977, Mechanical understanding ~ssentia1
for cased-hole wire-line operations; The Oil and Gas Journal, vol. 75,
no. 14, pp. 86-91.
63
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SECTION 8
TEMPERATURE LOGGING
SYNOPSIS
Temperature logs are one of the oldest methods utilized for
investigating downhole conditions. In fact, Peacock (1965) suggests
that the first physical measurement made in a well, other than depth,
was the determination of bottom hole temperature. Early temperature
logs were applied only to well conditions known to produce appreciable
temperature disturbances, such as cement hydration (Basham and Macune,
1952). However, the heat sensing devices used in temperature probes
have been improved radically over the years, and now temperature logs
can be used in situations where even minute temperature anomalies must
be located.
Three different types of temperature logs are currently available
for use in injection wells. A conventional (absolute or gradient)
temperature log is a record of the temperature of the f~uid
surrounding a heat sensor, recorded as a function of depth in a well.
The temperature recorded mayor may not reflect the temperature of the
fluid in the formations surrounding the well. Under static
conditions, with no flow in the well or adjacent to the well, the
geothermal gradient is measured (Keys and Brown, 1978).
A method of increasing the sensitivity of the data recorded on a
conventional temperature log is to supplement these data with a
differential temperature log. A differential temperature log is a
record of the rate of change of the gradient curve that can be
recorded within a wide sensitivity range. This log contains no new
information -- it is simply the same data from the gradient curve
presented in a different form. The differential temperature log is
valuable in that it enables the graphic display of relatively minute
temperature changes that may not appear significant on the gradient
log; the differential log is highly responsive to the slightest
changes in well temperature. Fluid temperatures in the well may be
measured with only one sensor, and the rate of change of temperature
is obtained electronically or the difference between the two sensors
may be measured.
A radial differential temperature (RDT) log measures the
variations in temperature in the plane of the casing radius at two
points on the inside of the casing wall or between the casing wall and
the center of the casing (Cooke, 1978). The RDT log was developed
specifically for the purpose of locating areas of channeling behind
64
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casing, and is also used to orient perforating guns to penetrate
through casing and into channels in the casing - borehole annulus
(Cooke and Meyer, 1979).
Temperature logging can be used in a number of ways to evaluate
changes that have taken place in and adjacent to a well. The fact
that this measurement is dependent on an almost continually changing
characteristic makes it different from most other logging
measurements. Temperature in a well changes with the geothermal
gradient, or the natural increase in the earth's temperature with
depth, and may be modified by fluid movement within the well and
behind the casing. For this reason, the temperature log is useful in
mechanical integrity testing of injection wells.
Temperature surveys have been used to evaluate the following
downhole conditions in both production wells and injection wells:
determining the geothermal gradient,
- locating cement tops by detecting the heat of hydration of
curing cement,
locating points of fluid production in open and cased holes,
locating tubing and casing leaks, particularly when the
leaking fluid is gas,
detecting channel flow behind casing under some conditi~ns
of injection,
- determining injection points and developing an injection
profile,
determining the location of chemical activity during and after
acidizing, and
locating lost circulation zones.
PRINCIPLES
The basis of temperature logging is the fact that the temperature
of the earth, and therefore the static temperature in a well,
gradually increases with depth. The rate of this change varies due to
a number of factors, such as near-surface seasonal changes,
circulating ground water and variations in the intrinsic permeability
and thermal conductivity of the rocks penetrated by the well.
Excluding extremes, geothermal gradients in the United States
generally fall within the range of 1.0°F to 1.3°F per 100 feet of
depth (Johns, 1966). When the fluid in a we11bore is static, and has
been for a long period of time, the temperature in the well is
generally regarded as representative of the natural geothermal
temperature. Thus, measurement of this temperature reveals the
65
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geothermal gradient, provided that there is no vertical flow behind
the casing in the casing-borehole annulus. The geothermal gradient is
a smooth, linear temperature change.
The reason that variations in the geothermal gradient are
observed is that whenever two media at different temperatures are in
contact, heat from the higher temperature medium flows to the medium
of lower temperature. Given enough time, the plane of contact between
the two media will reach the same temperature, or thermal equilibrium.
The media may be any combination of solids, liquids or gases. The
rate of temperature change that occurs is dependent on the volumes of
materials involved, the difference in temperature between the media,
the thermal conductivity characteristics of the media, the length of
time the heat transfer has been taking place and the presence and rate
of fluid movement that may be taking place.
In mechanical integrity testing of an injection well, the last
factor is the most important. Any type of fluid movement (liquid, gas
or a combination), either outside or inside a well will produce a
temperature anomaly. Deviations in the normal geothermal gradient
will be created by vertical movement of gases or liquids behind the
casing or through leaks in the casing. The temperature of the fluid
flowing in a vertical channel outside the casing will normally differ
from the geothermal temperature at a given depth in the well. (001in9
of gas on expansion, if gas flow is occurring, or because of f1c of
liquid from a different depth in the well where the geothermal
temperature is different will cause the temperature anomalies in 0
well (Cooke, 1978). If fluid is migrating downward, it is creating an
abnormally cool disturbance relative to the natural geothermal
gradient. If an upward movement is occurring, then the thermal
conditions are reversed and a warm disturbance relative to the natural
geothermal gradient is created.
Figure 15 illustrates the hole geometry and the points at which
temperatures are measured by the RDT tool and a cc~ventional
temperature tool. The radial differential temoerature is the
difference between TW1 and TW2' measured at a single depth as
temperature sensors contact and rotate around the inside of the casing
wall. A conventional temperature log measures Tf, the temperature of
the fluid inside the well at different depths as it is lowered in the
wel1bore. In the case where a channel exists in the cement behind the
casing, fluid traveling through the channel heats or cools the casing
on that side, causing te~perature at TW1 to be higher or lower than
that at TW2 (Cooke. 197~ I.
EQUIPMENT
Essential to obtaining valid temperature data is a detection
system that is sufficiently sensitive to small temperature changes and
stable to the degree that accurate readings can be faithfully
recorded. The downhole temperature logging tool used for producing
66
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Figure 15. Temperatures in and around a cased and cemented well bore (Cooke, 1979).
67
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both the gradient log and the differential temperature log employs a
heat sensing element to detect temperature changes in the we11bore.
The heat sensing element is usually either a thermistor, which
converts temperature changes into resistance changes, or a
semiconductor element, which converts temperature changes into
frequency pulses. Thermistor-type sensors may have an accuracy,
repeatability and sensitivity of approximately 0.02°C (Keys and Brown,
1978). The signals produced by the heat sensing element are conveyed
to the surface via mu1ticonductor logging cable. Once at the surface,
the signals are transformed by electronic surface equipment into
voltages proportional to well temperature. The voltages generated are
used to produce the log. The log is usually recorded in analog form,
however, it is possible to make digital records as well (Keys and
Brown, 1978).
The surface equipment used to record the differential temperature
log also includes an electronic memory circuit. In the surface unit,
the impulse from the downhole tool is fed after a preselected time
into a comparison circuit, which is also impressed with the impulse
generated at that time. The difference in temperature detected at the
two time intervals is recorded as the differential temperature. The
gradient temperature log is recorded on a separate circuit.
Typical downhole tools range from 7 to 8 1/2 feet long and 1 1/2
to 1 11/16 inches in diameter, for use in wells of 1 11/16 to 1 25/32
inches minimum diameter. Available tools are constructed to withstand
downhole temperatures of from 325°F to 400°F and pressures of 15,000
to 20,000 psi. The tool employs centralizers to keep it centered in
the borehole.
Components of the ROT downhole logging tool are shown in Figure
16. The temperature sensors, which are similar to those used in a
conventional temperature tool, are located on arms 180° apart, that
are extended and retracted by an electric motor. The contact diameter
of the extended arms is adjusted so they exert slight pressure to
maintain contact between the temperature sensors and the casing wall
(Cooke, 1978). A motor near the top of the tool rotates the tool at a
speed of one revolution every 2 1/2 minutes (Cooke and Meyer, 1979).
The outside diameter of the tool is 1 11/16 inches; the length of the
tool, a collar locator and two centralizers is 12 feet. The tool can
be run through tubing on a conventional logging cable and used in any
size casing from 2 3/8 inches to 9 5/8 inches; a tool has been
modified for use in 13 3/8 inch casing. An anchor spring at the top
of the tool prevents the entire tool from turning as the sensor arms
rotate (Cooke, 1978). The difference in temperature between the two
sensors can be measured with high sensitivity -- in the range of
0.005°F (Cooke and Meyer, 1979).
68
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.
I -.
I .
--..
ANCHOR
SPRING
ROTATION
MOTOR
ELECTRONICS
ROT
SENSOR
CONVENTIONAL
TEMP. SENSOR
..
CENTRALIZER
CONNECTOR FOR
PERFORATION GUN
Figure 16. Schematic of RDT logging tool (Cooke, 1978).
69
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PROCEDURES
For the purposes of mechanical integrity testing, the primary
objective for running a temperature log in an injection well is to
determine whether there are any leaks in the casing or tubing or
whether there is flow occurring through channels in the casing -
borehole annulus. This is customarily accomplished by stopping
injection and shutting the well in for a period of time to allow the
well to stabilize and reach near-normal temperature prior to logging.
If a well is logged too soon after being shut in, the casing and
tubing will not have dissipated their heat and little or no character
will be found on the temperature log (Kading and Hutchins, 1969)
(Figure 17). Timing of the temperature log with respect to when it is
run after the well has been shut in is very important, because the log
can be run too soon or too late to detect minute temperature anomalies
caused by mechanical integrity problems. The amount of time required
for the well to be shut in depends on a number of factors, including
well construction and injection operation details. Usually 24 to 48
hours are needed for the well to stabilize, but large diameter
boreholes will require longer stabilization periods than small
diameter wells (Kading and Hutchins, 1969). Ideally, the borehole
temperature in a shut-in well reflects the distribution of temperature
in the formations adjacent to the well.
Because of the critical nature of the timing of the logging
operation, a sequence of temperature profiles is usually recorded as
the borehole temperature returns to the natural geothermal temperature
(Witterho1t and Tixier, 1972). Portions of the temperature profile
that deviate from the smooth geothermal curve (anomalies) provide the
information for locating injected fluid -- its points of exit from the
casing, whether known perforations or unexpected casing leaks, and/or
its flow in channels behind the casing.
In wells completed with tubing and packer, it may be necessary to
remove the tubing in order to properly detect or locate leaks in the
casing or fluid movement in channels behind the casing. Temperature
anomalies may not be adequately transmitted through the tubing-casing
annulus, thus it may be difficult to recognize well problems if the
log is run through the tubing.
The downhole temperature tool is always calibrated prior to being
run in the well. In recording the conventional temperature log,
logging is accomplished going downhole to avoid temperature
disturbances caused by the motion of the tool in the well.
Temperatures within the well are detected by the downhole tool and a
signal representing these temperatures is transmitted to the surface,
where it is recorded versus depth. Logging speed varies from about 10
to 40 feet per minute depending upon well conditions and probe
response. Continuous logs, made at logging speeds of 25 feet per
70
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TEMPERATURE GRADIENTS 1° PER INCH SENSITIVITY
HOURS AFTER INJECTION
246
INJECTING
PERFS
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GEOTHERMAL
GRADIENT
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85°
WW.S. TD. 3903
86° 87° 88° 89° 90°
Figure 17. Gradient temperature logs run at various times after well is shut in
(Kading and Hutchins, 1970).
71
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minute have been compared with point-by-point measurements, and
discrepancies of no more than O.03°C were found (Keys and Brown,
1978).
Kading and Hutchins (1969) describe a procedure for locating gas
channeling behind casing utilizing a gradient temperature log.. When
attempting to locate gas entry, the most successful procedure 1S to
flow the well for a period of twelve hours or more before starting the
surveys. The first survey should then be recorded under a stable flow
condition. Gas entry into a wellbore is determined by a cooling at
the gas entry point or by a temperature increase just below the gas
entry point. Note that a gas source may not be evident on the flowing
run if gas is channeling from above the point of entry into the
wellbore. The gas flowing up the casing and past the temperature
instrument will mask the anomaly at the point of entry.
The next step is to shut in the well and immediately run a survey
over the area of interest. Static or near static conditions will
remove the masking effect of the flowing gas and also allow the small
temperature changes caused by channeling gas to be detectable adjacent
to their point of occurrence. Transient temperature anomalies may be
recorded; therefore, more than one static survey should always be run.
These spurious temperature changes will usually move uphole and be
recorded at varying depths, so temperature changes at constant depths
indicate true gas movement. Figure 18 is a gas entry log with stable
flow and static runs which shows a gas entry behind the casing
channeling around the casing shoe.
The temperature survey can only be used in a qualitative sense
for gas entry because of the factors which cause this temperature
change. A large volume of gas moving through an unrestricted area
with little temperature drop, will log a small temperature change
compared to a small volume of gas having a large pressure drop. The
high pressure drop low volume entry with its large temperature change
will mask adjacent significant gas entries. This is one of the
reasons that shut-in surveys sometimes must be run after flowing
surveys (Kading and Hutchins, 1969).
The differential temperature log is recorded simultaneously with
the gradient log from the same downhole tool. It is a continuous
measurement, and at a particular point on the log gives the difference
in the temperature at one depth and a preselected depth upho1e. The
subsurface temperature data transmitted to the surface are fed into a
memory storage and differential computer. The computer stores and
continuously compares temperature measurements between two subsurface
points. The two points, or spacings, are selected at the surface
based on the logging speed. Proper selection of the variable spacing
is dependent on the desired resolution of the slope changes.
Differential temperature measurements, at the selected spacings chosen
to be the most suitable to individual well conditions, are obtained to
provide maximum benefits from the log. Differential temperature logs
may also be run using two sensors.
72
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I
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\ STABLE FLOW TEMP. LOG
3000 -
I \ SHUT IN TEMP. LOG
.4
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Figure 18. Gradient temperature log used for locating gas entry channel around pipe
(Kading and Hutchins, 1970).
73
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The procedure for running a radial differential temperature log
differs significantly from that for either a conventional or
differential temperature log. The ROT log is typically utilized after
a downhole problem (especially a channel behind the casing) is already
suspected. The ROT tool is lowered to depths in a well where a
channel is suspected, the arms containing temperature sensors are
extended and the motor is engaged, allowing the tool to make one or
more revolutions. The temperature sensors contact the casing so that
the thermal properties and movement of fluid in the well have a lesser
effect on the measurements (Cooke and Meyer, 1979). The log is made,
the sensor arms are retracted and the tool is moved to another depth,
where the procedure is repeated. As many measurements can be made as
needed at different depths in order to delineate a channel (Cooke,
1978).
Rotation of the ROT tool produces a signal that is used to mark
the edge of the chart paper. The marks are omitted in one interval of
each revolution so that the end of the revolution can be easily
located on the chart. The curve is normally reproduced by the
recorder on each revolution (Cooke, 1978).
Cooke (1978) and Cooke and Meyer (1979) indicate that greater
differences in temperature between fluid flowing in a channel behind
the casing and the geothermal temperature at a given depth can be
obtained by injecting fluid at the surface into open perforations to
cool the channel. This technique is particularly useful if the
temperature of the channel relative to the geothermal temperature is
not known and has been successful in locating channels both above and
below perforations. The temperature of fluid entering perforations
can be monitored during injection by using a conventional temperature
tool. The ROT tool can then be run in the well and used to detect the
channel. With this technique, temperature differences as great as 3°F
have been measured on opposite sides of well casing (Cooke and Meyer,
1979). Temperature differences from flow of subsurface fluids between
zones are much smaller -- often in the range of 0.005°F to 0.05°F
(Cooke, 1978).
INTERPRETATION
Because of the large number of mechanical configurations of
tubing, casing, packers and injection conditions in injection wells,
there is an almost unlimited variety of responses that could be
obtained with a temperature survey. However, it is possible to
generalize the types of deflections a temperature log will display in
response to fluid leaks and movement in channels behind casing.
Figure 19 shows common log responses to the natural geothermal
gradient, and two conditions of fluid flowing behind casings.
On a temperature log, deflections from the geothermal gradient
may be due to reasons other than casing leaks or fluid movement behind
74
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FLUID FLUID
~ \
EXIT
ENTRY \ \
TO THE
CHANNEL \ \
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en
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FLUID FLUID
EXIT ENTRY
FROM THE
CHANNEL
EXAMPLE A
NATURAL GEOTHERMAL
GRADIENT AS MEASURED
IN A STABLE WELL
TEMPERATURE
EXAMPLE B EXAMPLE C
TEMPERATURE ANOMALY TEMPERATURE ANOMALY
SUPERIMPOSED ON GEO- SUPERIMPOSED ON GEO-
THERMAL GRADIENT THERMAL GRADIENT
INDICATIVE OF DOWNWARD INDICATIVE OF UPWARD FLOW
FLOW THROUGH A CHANNEL THROUGH A CHANNEL BEHIND
BEHIND THE WELL CASING THE WELL CASING
Figure 19. Examples 0' gradient temperature logs showing the natural geothermal gradient
and anomalies caused by 'Iow through a channel behind the well casing.
75
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casing. Local variations in thermal conductivity or intrinsic
permeability of rocks penetrated by the well and the presence of zones
of ground-water circulation could significantly alter ~he expe~ted.
gradient. Practically, a temperature survey at a part1cular t1me 1S
compared with similar data from a different time period. By noting
the difference in the two sets of data, conclusions are drawn to
explain the reason for these differences. Since it is unlikely that
all of the possible variables encountered in a well will be known
quantitatively, it is difficult to arrive at precise conclusions from
temperature surveys. Supplementary data, including information on
local geology and any other available well logs, should always be
considered when available.
Sharp definition of temperature interfaces with a gradient log is
improbable unless the difference in temperatures is extreme; slight
changes go unnoticed unless recording sensitivity is high. In all
applications of the gradient log, there are occasions when the
recorded temperature anomalies are too small to be interpreted with
certainty. The differential temperature log, because of its ability
to detect and amplify minute anomalies, is effective in these
situations (Peacock, 1965). The anomalies on both the gradient and
differential temperature log are often quite confusing, and sometimes
do not represent the downhole situation. This is particularly true
when the cross-sectional area of, for example, a channel behind the
casing compared to the volume of the well is very small (Pennebaker
and Woody, 1977).
The differential temperature log graphically indicates changes in
temperature gradient. The log plots the rate of change in temperature
as well as the magnitude of the difference. Increases in temperature
are plotted to the right of an axis line on the log, while decreases
are plotted to the left. Anomalies show up as distinctly large
deviations (either increases or decreases) from the normal gradient.
One of the biggest pitfalls in interpreting any temperature log
is the tendency to select the wrong scale for recording the log.
Depth and temperature scales selected are commonly so large that
subtle temperature changes are often lost or confused with normal
variations in temperature caused by, for example, different rates of
cooling or heating in shale or sand intervals (Pennebaker and Woody,
1977).
As Basham and Macune (1952) point out, the chief value of
differential temperature measurement lies in the fact that a
difference between two factors can be measured with a scale of values
best suited to that difference; a scale that might be cumbersome or
impractical if applied to the factors themselves. When it is known
that all factors will be nearly equal in value, and therefore the
differences consistently small, it is possible to select a scale that
will permit very accurate measurement of the differences.
76
-------
As with other logs, another type of log should be compared to the
gradient log or differential temperature log so that proper
correlations can be made with perforated zones, packer settings and
casing collars. This is particularly true in injection wells that
have a dual completion. During a shut-in period, fluid from one zone
may migrate into the well and travel via the casing to another zone of
lower hydrostatic pressure. When this occurs, the borehole is
artificially heated or cooled and interpretation is hampered. Without
another log for correlation purposes, the interpretations from either
a gradient log or a differential temperature log could be misleading.
COST
The cost of performing a temperature log is dependent upon the
many general pricing variables as outlined in Section 7. The range of
specific depth and logging charges as determined by a survey of six
major well logging companies in the midcontinent area of the United
States are listed in Tables 8 and 9. Refer to Table 7 for a listing
of companies surveyed which perform this service.
TABLE 8. TYPICAL DEPTH AND LOGGING CHARGES FOR STANDARD
TEMPERATURE LOGGING
Depth Charge Low High
per foot $0.20 $0.29
minimum $400 $580
Logging Charge Low High
per foot $0.20 $0.29
minimum $400 $580
TABLE 9. TYPICAL DEPTH AND LOGGING CHARGES FOR DIFFERENTIAL
TEMPERATURE LOGGING
Depth Charge Low High
per foot $0.22 $0.33
minimum $450 $990
Logging Charge Low High
per foot $0.21 $0.33
minimum $400 $950
Refer to Table 7 for a listing of companies surveyed which perform
this service.
77
-------
At the time of writing this report. only one firm offered the
Radial Differential Temperature log. Their costs are explained in
Table 10.
TABLE 10. TYPICAL CHARGES ASSOCIATED WITH RADIAL DIFFERENTIAL
TEMPERATURE LOGGING
Depth Charge per foot
Each Station Reading
Temperature Log - Operation Charge
Tool Used to Read Temp.
Each Jet Charge Used
Royalty Charge:
Per Well (Land Operation), 6,000' or less
Per Well (Land Operation), greater than 6.000'
$ .30
$50.00
$ .18
No Charge
$45.00
Min. $ 600.00
Min. $ 400.00
Min. $ 360.00
Min. $ 540.00
$148.20
$296.40
ADVANTAGES AND DISADVANTAGES
Perhaps the primary advantage of temperature logging is that a
properly run and interpreted temperature log can indicate not only
tubing and/or casing leaks, but also channeling in the cement sheath
behind the casing of an injection well. Differential temperature logs
are very useful in this regard; the differential temperature can be
known with much greater accuracy than the absolute temperature. RDT
logs are specifically run for the purpose of locating channeling
behind casing. The ROT log may define not only the interval of
channeling behind casing, but also the orientation of the channel
(Cooke. 1979). This would facilitate later remedial action.
Additionally, the technology of temperature logging has seen a
number of significant advances over the years; the equipment now
utilized is able to detect very small changes in temperature.
Temperature log interpretation has also become more sophisticated with
the advent of digitized logs and computer matching techniques.
However. in spite of all of the literature on field examples and the
advances in equipment and simplified interpretation procedures,
temperature logging continues to be an art rather than an exact
science (Witterholt and Tixier. 1972). Utilizing a temperature log as
the sole means for making important decisions regarding a well is not
advisable; other logs must commonly be used to assist in the
interpretation of downhole situations.
A significant disadvantage of utilizing temperature logs in
mechanical integrity testing relates to the fact that the well must be
taken out of service for anywhere from 24 to 48 hours or more to allow
the well to reach thermal stability. The injection tubing and packer
may also have to be removed during the logging process and then
78
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replaced. This may significantly affect the schedule of operation of
production wells relying on the injection well to dispose of salt
wa ter.
Large diameter wells may not benefit as much from a temperature
log as smaller diameter wells due to thermal attenuation that occurs
between temperature anomalies and the logging probe which is normally
centered in the well. The radial differential temperature log partly
eliminates the problem because the temperature sensors actually come
in contact with the casing. However, the RDT tool is limited to use
in casings 13 3/8 inches in diameter or smaller.
EXAMPLES
A conventional use of gradient temperature surveys is shown by
Figure 20. This illustrates leaks in two gas wells equipped with
tubing and packer. Both wells had been produced at moderate rates for
some time, then shut-in. Gas expanding through the leaks reduced the
temperature several degrees as shown. The leaks were approximately
located in reconnaissance surveys, then pinpointed by stops made at
25- to 50-foot intervals, as the figure indicates. In subsequent
tubing repair work, the leaks were found to be very close to the
points ind;cated (Pierce, et. a1., 1966).
In Figure 21, the gradient temperature log (left-hand side) shows
gas moving from the top of a channel behind the casing at 23201 and
migrating downward to the top of the perforations at 2380'. In both
cases, there is a deflection to the left at the problem, indicating
that the flow through the channel is cooling the casing relative to
the natural geothermal temperature. A squeeze cement operation above
the perforations successfully sealed the channel (Peacock, 1965/.
Detection of a casing leak, shown in Figure 22, was accomplished
by making all logging runs with the well shut in. The first log run,
the gradient temperature log (left) indicated a leak at 34201. Two
differential temperature logs run at different sensitivity settings
confirmed the leak at same depth (Peacock, 1965).
The well depicted on the log in Figure 23 (from Cooke and Meyer,
1979) originally fed in a small amount of gas and 0.5 barrels per hour
(bb1/hr) of water when the fluid level was swabbed to just above the
perforations. The well was then acidized with 1000 gal of acid (400
gal mud acid with pref1ush and after flush of hydrochloric acid),
after which it flowed 100% salt water at a rate of 12 bb1/hr.
At this point, the RDT log was used to detect a channel above the
perforations by injection of water into the well. Figure 23 shows the
location of the RDT tool when water pumping began. The we11bore was
originally full of water. The temperature log showed that cooling
appeared to exist above the perforations. As can be seen in the RDT
79
-------
TEMPERATURE of
60 100 140 180
o
1000
TUBING LEAK.
-2100-2125 FT.
2000
~
~ 300
~
y. WElL 1..1\
..
]: ,
~ 4000 "
,
~
0 "
,
5000 APPROX FORMATlONJ',
TE MPER A TURE "
6000 '
'i:
'\":
7000
Figure 20. A gradient temperature log used to locate a small gas leak in tubing
(Pierce et at, 1967).
80
-------
40
76° 77° 7f )7r 80° 81° 82°
60 " 'I
TEMPERATURE LPG
80 10 PER INCH
DIFFERENTIAL TEMPERATURE L
2200
20
.
40
60
I 80
r----= COLLAR
2300 LOG
20 TOP OF CHANNEL-
40
60 ~
.
80 12
:
2400
20
40
60
~
80 PERF I "
I "'"'-- '" .>
2500 .-
. I 1 5
20
OG
Figure 21. Temperature logs used in locating a gas channel behind casing (Peacock, 1965).
81
-------
85° \ 86° 870 880 890 900 910 920 930 940 I
-, II DIFFERENTIAL TEMPERATURE LOG
2900 I \ ~ \ I
TEMPERA TURE LOG r ""'"
I- 1 C PER INCH
\ \
3000
3100
3200
I
3300
I
3400 /
I ( - ~ ~
--- t--- - CASING LEAK
--
\ " 1<
3500
1\ "' \
1\
3600 \ i\ r\
\ \ \
3700 \
) \
3800 \ 1
Figure 22. Temperature logs used in locating a casing leak (Peacock,196S).
82
-------
SP
DEPTH
J ~~'
6300'
6350'
6400'
6450'
6500'
:~I'1"
..::t j'::-.
TEMPERATURE
LOG
~
2 3 4 5
REVOLUTIONS
6413' - STOP PUMPING
~~iORE~
1 2 3 4 5
REVOLUTIONS
BEFOREl
saz
6413' - START PUMPING
6408'- START PUMPING
1
~
\
\
\
\ dT = 1° F
~
\
'. AFTER I
\ saz
~
~
I
2 3 4
REVOLUTIONS
5
Figure 23. RDT scans and temperature log in a well, showing channel to potential gas zone
before squeeze and no channel after squeeze (Cooke and Meyer, 1979).
83
-------
plots on the right side of the figure, no signal was observed above
the perforations before water was pumped into the well. Very soon
after water injection began, the ROT signal appeared. This signal
repeated for a period of 30 minutes, each time with the peak at the
same angle of rotation, as water was pumped into the well at a rate of
0.5 BPM. Water injection was then stopped. The next ROT curve shows
that the amplitude of the signal increased slightly as the water
pumping ceased. The well was perforated in the direction of the lower
temperature.
This well was later squeeze cemented, but the zone produced
negligible amounts of gas. The ROT log was then rerun in the well,
using the same procedure to determine if a channel existed. As shown
on the figure, no signal was observed after the squeeze job,
indicating that the channel had been repaired, but the perforated zone
was not productive.
84
-------
REFERENCES
Basham, R.B. and C.W. Macune, 1952, The delta-log, a differential
temperature surveying method; Petroleum Transactions, AIME, vol. 195,
6 pp.
Cooke, Claude E., Jr., and Andre J. Meyer, 1979, Application of radial
differential temperature (RDT) logging to detect and treat flow behind
casing; Paper presented at the SPWLA Twentieth Annual Logging
Symposium, June 3-6. 1979, 10 pp.
Cooke, Claude E., 1979, Radial differential temperature (RDT) logging
- a new tool for detecting and treating flow behind casing; Journal of
Petroleum Technology, vol. 31, no. 6, pp. 676-682.
Johns, S. Earl Jr., 1966, Tracing fluid movements with a new
temperature technique; Gearhart-Owen Industries, Inc., Bulletin No.
EJ-416, Fort Worth, Texas, 23 pp.
Kading, Horace and John S. Hutchins, 1970, Temperature surveys: the
art of interpretation; Drilling and Production Practice, American
Petroleum Institute, Washington, D.C., pp. 1-20.
Keys, W.S. and R.F- Brown, 1978, The use of temperature logs to
trace the movement of injected water; Ground Water, vol. 16, no. 1,
pp. 32-48.
Peacock, D.R., 1965, Temperature logging; Transactions of the SPWLA
Sixth Annual Logging Symposium, vol. 1, pp. 1-18.
Pennebaker, E.S., Jr. and R.T. Woody, 1977, The temperature-sound
log and borehole channel scans for problem wells; Paper presented
at the 52nd Annual Fall Meeting of SPE-AIME, paper number 6782, 11
pp.
Pierce, Aaron E., J.B. Colby and Beldon A. Peters, 1967, Diagnostic
use of thermal anomalies in wells; Drilling and Production Practice,
American Petroleum Institute, New York, New York, pp. 186-190.
Witterho1t, E.J. and M.P. Tixier, 1972, Temperature logging in
injection wells; Paper presented at the 47th Annual Fall Meeting of
SPE-AIME, paper number 4022, San Antonio, Texas, October 8-11,
1972, 11 pp.
85
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SECTION 9
NOISE LOGGING
SYNOPSIS
Noise logging was first used in 1955 to detect leaks in casing
strings of producing oil and gas wells. Enright (1955) described a
procedure for utilizing a downhole microphone to locate noise peaks
associated with the point of origin of a leak in the casing. Since
that time, several other authors have described the use of
noise-logging techniques to search for fluid movement within channels
in the cement in the casing-borehole annulus. Robinson (1976a)
describes five applications in which the noise logging technique has
proven useful:
1) existing production (or injection) wells with cemented casing
having channels or communication behind the casing;
2) new wells with cemented casing in which channels develop
before perforating;
3) wells that develop underground crossf10w or IIb10woutsll;
4) wells losing injected gas or fluid; and
5 )
determining relative flow rates from perforated zones.
The noise log is a trace of the noise intensity in the well
versus depth. The noise logging tool, which detects the acoustic
(sound) energy generated by the turbulent flow of fluids moving
through restrictions, can be utilized in virtually any downhole
condition, whether the well is filled with liquid or gas. The sound
energy created by fluid movements can be detected through the cement,
the casing, the annulus fluids, and the tubing. Sound energy between
200 Hz and 6000 Hz is picked up by the noise logging tool and
converted to an electrical signal that is amplified and transmitted to
the surface to an electronic recording device. The surface equipment
further amplifies the signal and splits it into several frequencies. A
determination of the type of flow occurring at a noise source can be
made from an analysis of the sound frequency spectrum. Volume of flow
can be calculated from the sound amplitude.
86
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PRINCIPLES
Any composition of fluid (liquid or gas) flowing through
restrictions (either leaks in a well casing, or in channels behind the
casing of a well) generates a complex group of distinctive audible
sound frequencies between 200 Hz and 6000 Hz. Turbulence generated by
fluid moving from points of low hydraulic head to points of higher
hydraulic head creates a sound field within the well casing. The
intensity of this sound field is greater than the ambient (background)
noise level in the wellbore. The sound energy which is generated by
fluids in motion is transmitted through the various well components
(cement, casing, annulus fluid, and tubing) and can be detected with a
noise logging tool. When the sound energy from the moving fluids is
detected by the tool, the mechanical vibrations are transformed to
electrical signals having an alternating frequency wave form. The
noise log signal wave form produced by the moving fluid is a composite
of many frequencies, each of which has an intensity that varies with
time. Selection of the proper time constant gives quantitative
average values of the wave-form amplitude. This amplitude, as plotted
on the noise log, is expressed in AC millivolts (mv) (NL McCullough
Inc., no date).
The noise log records two kinds of information about downhole
noise: an amplitude profile and a frequency structure. The amplitude
profile indicates the presence or absence of fluid movement and allows
for the location of the noise source. The frequency structure
provides a means of determining whether the flow occurring is
single-phase or dual-phase flow and also yields information about
pressure differentials (Pennebaker and Woody, 1977).
The amount of noise generated by fluid movement in a well at any
point along its path is proportional to the volume of flow and to the
pressure differential acting on the flow at this point. In the case
of a leak in the casing, the greatest pressure differential occurs at
the source of the flow (i.e. a hole in the casing). In the case of
flow in a channel behind the casing, pressure differentials may occur
at the source of the flow (i.e. a high pressure zone), at restrictions
along the flow path (i.e. in a channel in the cement sheath), and at
the sink of the flow. These places where flow occurs across a
pressure differential are displayed as amplitude peaks on the noise
log (NL McCullough, no date).
EQUIPMENT
The noise logging sonde contains a transducer which can be as
small as 1 inch in outside diameter, thus enabling the device to be
used in casing or tubing as small as 1 1/2 inches inside diameter.
The tool is small enough that it can even be lowered down the annulus
between the tubing and the casing, provided the annulus is at least
two inches wide and that the tubing is centered within the casing.
87
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Several different tools are described in the literature and used
in practice in the oil industry. McKinley et a1. (1973) describe a
tool 3 feet long which consists of a piezoelectric crystal detector in
its lowermost section and an amplifier in its uppermost section. This
tool, which is encased in stainless steel, is able to withstand
corrosion as well as maximum operating pressures up to 14,000 psi and
temperatures up to 325°F (transistorized amplifier model) or 500°F
(vacuum-tube amplifier model).
Robinson (1976b) describes a longer tool (6 feet in length) in
which the bottom third consists of an oil-filled, pressure-compensated
piezoelectric detector (Figure 24), and the middle third of the sonde
is an amplifier. Amplifier gain ranges from 200 to 2000 so that
both low flow rates (as low as 100 cubic feet per day of gas) as well
as high flow rates (up to several million cubic feet per day) can be
detected without having to manually adjust the gain. The upper two
feet of the tool is a magnetic collar locator which is used to
correlate the noise log depth with the log of any other tool that has
a similar device. The maximum operating pressure and temperature of
this tool are 22,000 psi and 350°F respectively.
Britt (1976) describes another noise logging tool 1 11/16" in
outside diameter, 48" long, with a 15,000 psi pressure and 350°F
temperature rating. As with the other tools, the downhole device is
simply a very sensitive microphone with a downhole amplifier. The
microphone is designed to respond to sound which originates in any
direction around the well and therefore has no directional properties.
The tool is not equipped with centralizers.
Each tool described above is sensitive enough to detect
significant noise from within a tubing or casing at a distance of 200
feet above or below the source. Even when close to the source,
distinct noise level changes can be detected in as little as six
inches, the length of a typical sensing element (Pennebaker and Woody,
1977).
The noise logging sonde is run downhole on a single conductor
cable, which transmits the signal generated and amplified by the sonde
to the surface. There it is received by an electronic recording unit
in which the noise signal output from the sonde is further amplified
(Figure 25). As the signal is received, it may also be heard by the
operator through a speaker or high-fidelity headphones.
Within the surface recording unit the noise signal is, after
amplification, divided into four separate frequencies. Four separate
band pass filters eliminate different parts of the noise spectrum
resulting in the recording of noise levels above four separate'
frequencies: 200 Hz; 600 Hz; 1000 Hz; and 2000 Hz. After the four
frequency levels are displayed, the AC voltage from each of the four
noise amplitudes enters an analog to digital converter and four
digital voltmeters register the four peak-to-peak voltage values.
88
-------
Casing Collar
Locator
Electronics
Detector
Pressure
Equalizer
Figure 24. Typical noise logging tool (Robinson, 1976b).
89
-------
Downhole
Power
Supply
-f""
<
<
-------
These four voltage values are recorded at each depth on a data sheet.
After all data are recorded, the four noise levels are pJotted versus
depth on semi10g graph paper, thus producing a noise log with four
separate curves. Observing the amplitude which is not filtered out by
each filter indicates the spectrum of the noise generated by a noise
source. These amplitudes are measured at each logging interval.
PROCEDURES
The standard method of producing the noise log is to lower the
tool down the hole in a non-recording mode and raise it gradually,
recording on the trip back up the well. Because the sonde is
sensitive to any noise that can be heard in a well, the noise that is
generated by the movement of both the tool and the wire1ine downhole
must be eliminated, or it may mask out the noise produced by fluid
movement. Thus, the noise log is usually made with the logging sonde
in a stationary position, and the survey is perfonmed on a
station-by-station basis. Also, the well must be completely shut in
to ensure that all surface leaks through wellhead connections (i.e.
valves and fittings) are eliminated, since any noise generated at the
wellhead may be transmitted downhole.
With regard to selecting the intervals of logging stations used
in the noise survey, generally recording stops are made every 200 feet
to establish a background level and to listen for sound from any
potential noise sources. Pennebaker and Woody (1977) and Robinson
(1976a) suggest that intervals of 500 to 1000 feet may be adequate to
establish background conditions in some situations.
If a noise should be detected, progressively smaller intervals
are used to pinpoint the source of the noise. Intervals of 25 to 50
feet may be used upon first recognition of a noise source; 5 to 15
foot intervals are usually adequate to close in on a source; and 1 to
2 foot intervals are generally used to pinpoint the problem area.
Closely spaced readings may also be appropriate at all casing seats
and through any other changes in well construction details (Pennebaker
and Woody, 1977).
At each downhole station, the noise logging sonde is stopped
until the stabilized noise levels above the four standard frequencies
are recorded and plotted on the log. This operation may require up to
three minutes for each stop (McKinley et a1., 1973). Britt (1976)
maintains that the typical time for extraneous noise to die out in a
well is 40 to 60 seconds -- this can be detenmined by listening to the
well sounds with the headphones. Time required to read and tabulate
the various frequency cuts ranges from about 30 seconds (Britt, 1976)
to only about 15-20 seconds per stop (Pennebaker and Woody, 1977).
This method of log operation is unlike that used for other logs, which
result in a continuous record of the measured parameter versus depth.
91
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Unless a noise source is detected, even with the discontinuous
nature of the noise logging operation, it is possible to achieve
almost the same average speed as with IInorma111 continuous logging and
still collect high-precision data. Average logging speeds of from 25
to 35 feet per minute are reported for detailed logging runs in which
stations 20 feet apart are used (Britt, 1976). However, because the
tool must be stopped and the recording/plotting operation performed at
smaller intervals to pinpoint a noise source, this procedure can
become very tim~ consuming.
INTERPRETAT:ON
The noise log allows for a simple form of frequency analysis by
recording four sepa~ate noise amplitude curves. Within the surface
electronic equipment, a series of band pass filters, which eliminate
all audio frequencies below selected frequencies and pass all
frequencies above those selected, separates the frequency spectrum of
the sound for analysis of the individual amp1it~des contained in each
of four bands: 200 Hz; 600 Hz; 1000 Hz; and 2000 Hz. An analysis of
the relative energy levels in the four frequency bands can be
perfonned to determi ne whether the f1 ui d movement is si ng1e-phase or
dual-phase flow and to determine the location of the flow source with
respect to the individual well components.
Single-phase flow (either all liquid or all gas) is characterized
by higher frequency sound. Thus, single-phase flow can be recognized
by the close spacing of the 200, 600, and 1000 Hz curves, and the
separation of the 2000 Hz curve on the noise log. At a single-phase
flow noise peak, the four curves may nearly converge (Figure 26A).
Dual-phase flow (a combination of liquid and gas) is
characterized by lower frequency sound. Thus, dual-phase flow is
indicated by the separation of the 200 Hz curve from the others
(Figure 26B) (Pennebaker and Woody, 1977). The degree of separation
of the 200 Hz curve from the other three curves will vary depending
upon the low-frequency noise associated with the two-phase flow
(Robinson, 1976a).
At a noise peak, the frequency distribution of the noise will
provide a clue to the pressure differential there. The greater the
pressure differential, the higher the noise frequency will be and the
less the separation will be between the four frequency curves. For
example, at a noise peak where the pressure differential is so high
that nearly all the noise is above 2000 Hz, the four frequency curves
on the noise log will converge to almost the same value (Nl
McCullough, no date).
It is possible to detect flow behind the casing by an examination
of the 2000 Hz curve, because as differential pressure in
constrictions in channel behind the casing increases, the 2000 Hz
92
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(l) 08
"0
::J
A
g, 06
'"
E
~ 04
Single phase
10
TYPical log response
50 70 90 110
Sound Intensity db
TYPIC"1 log response
50
70
90
130
110
130
;;;
a;
a: 02
(l) 08
"0
::J
B
g, 06
'"
E
~ 04
o
200
1.000 2.000
Frequency hz
5.000 10.000
Sound intensity db
Figure 26. Distinctive noise log frequency distributions (Pennebaker and Woody, 1977).
;;;
a;
a: 02
500
Two phase
10
o
200
500
1.000
2.000
5.000 10.000
Frequency. hz
93
-------
noise level increases. Any significant deviation of the 1000 Hz curve
from the background levels reveals a problem with a leak in the casing
(Robinson, 1976a).
It is possible to estimate the rate and volume of flow from the
amplitude of each of the individual frequency curves. A more accurate
determination of rate and volume of flow can be made with the use of
an empirical formula. The reader is referred to McKinley et al.
(1973) and Britt (1976) for methods to accurately determine leak rates
and volume of flow.
Several factors associated with the actual well completion and
subsequent production or injection operations will influence
interpretation and should be known to the operator at the time the
survey is conducted. The construction details of the well generally
do not affect either the operation of the sonde or the interpretation
of the noise log. However, the transmission of sound energy through
the well and the wellbore is to some degree affected by the various
well components, including the cement, the casing, the annulus fluid
and the tubing. For example~ when the logging sonde is run in a
tubing string, the amplitude or strength of the noise signal generated
by a leak in the casing or by fluid movement behind the casing is
somewhat subdued because of the "buffering" effect of the fluid in the
casing-tubing annulus. Alternately, if there is a leak into the
string containing the sonde, a different problem results. McKinley et
al. (1973) have compiled a set of factors for various well completion
types by which recorded noise levels may be multiplied to compensate
for differences in well construction (Table 11).
Because the noise signal recorded on the log is interpreted
relative to background noise levels, compensating for differences in
well construction is generally not a problem to a skilled log analyst.
Problems in the interpretation of the noise log may arise because of
the scales used for depth and amplitude. If these scales are not
properly selected, subtle changes in noise may go unrecognized.
Pennebaker and Woody (1977) suggest that it may be very difficult to
make an accurate diagnosis of downhole problems from a log displayed
on a 5 inch = 100 foot scale.
COST
The cost of conducting a noise logging survey is dependant upon
the many general pricing variables outlined in Section 7. The range
of specific depth and logging charges as determined by a survey of six
major well logging companies in the midcontinent area of the United
States are listed in Table 12.
94
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TABLE 11. WEll GEOMETRY FACTORS TO COMPENSATE FOR RECORDED NOISE
lEVELS (McKINLEY ET AL., 1973)
Type of Well
Tubingless Completion
Tubingless Completion
Tubing String in Casing
Fluid Content
Liquid in String
Gas in String
Liquid in Tubing
Liquid in Annulus
Gas in Tubing
Liquid in Annulus
or Vice Versa
Gas in Tubing and Annulus
Liquid in String
Gas in String
Factor
1.0
1-2
2
Tubing String in Casing
2-4
Tubing String in Casing
Leak into Same String as Detector
Leak into Same String as Detector
5-10
0.06
0.20
95
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TABLE 12. TYPICAL DEPTH AND LOGGING CHARGES FOR NOISE LOGGING
Depth Charge Low High
per foot $0.26 $0.29
minimum $540.00 $700.00
Logging Charge L~ High
per foot $0.26 $0.29
minimum $520.00 $580.00
Refer to Table 7 for a list of companies surveyed which perform this
service.
ADVANTAGES AND DISADVANTAGES
The noise survey offers several advantages over other methods of
determining mechanical integrity of injection wells. The primary
advantage is that it can be utilized to detect both leaks in the
casing and channeling in the cement sheath behind the casing. In
addition, through the unique interpretation methods used with this
survey, it is possible to distinguish whether an anomaly detected by
the survey is caused by single-phase or dual-phase flow. Also, under
some conditions, it is possible to estimate both the rate and volume
of flow from a source that is detected by the noise logging sonde.
The sonde itself offers an advantage in that it can not only be used
in casing, but it is small enough to be used in tubing as small as
1 1/2 inches inside diameter.
Several disadvantages of the noise survey are apparent. The main
drawback of the noise logging technique is the logging speed which can
be achieved if noise sources are detected. Because the operation of
the tool demands that the survey be conducted on a station-by-station
basis, pinpointing noise sources can be a very time-consuming task.
Also, while interpretation appears to be very straightforward, it is
easy to misinterpret the data obtained with a noise survey,
particularly if the interpreter is not experienced. Other logs (i.e.
a temperature log) may have to be run in conjunction with the noise
survey to more narrowly define any anomalies recognized by the noise
logging sonde. In addition, as Arnold and Paap (1979) point out,
since the noise amplitude generated by turbulence from high-energy
expansion of fluids is a direct function of energy dissipated in the
expansion process, the noise logging technique may not be useful in
detecting water channeling when pressure differentials are too small
to generate detectable noise amplitudes.
96
-------
EXAMPLES
Figure 27 illustrates a typical noise log of a well in which
fluid movement in a channel behind the casing is detected. As the
figure shows, fluid enters the channel at a point opposite a
permeable formation, moves upward, and exits the channel at another
permeable formation. This example illustrates several important
facts. First, noise levels are greater than the background level over
the entire length of the channeled section where fluid is moving.
Second, the top and bottom peaks indicate the points of fluid entry
and exit. However, the direction of fluid movement must be inferred
without additional information. Third, the middle noise peak on the
log, the result of a constriction in the channel in the cement,
appears the same as the other noise peaks. This could lead to a
different interpretation of the log. These problems could be solved
if additional information about the noise source was available.
The noise log has been used in combination with other logs to
enhance the utility of each log. For example, when used with a
temperature log, a noise log may have greater meaning with regard to
determination of the type of anomaly in the well causing the
disturbance. Both temperature and sound profiles reinforce one
another and enhance interpretation.
Pennebaker and Woody (1977) have described a technique using
condensed and expanded depth scale presentations of both sound and
temperature data which has proved helpful in diagnosing well problems,
particularly those producing subtle changes in sound and temperature.
The system developed to implement this technique is depicted in Figure
28. As an example of how this system can be used, if flow is detected
behind the casing with the noise log, the temperature log may indicate
the direction in which fluid is moving through channels in the cement
sheath. By comparison, where each log is run independently in a well,
interpretation of both of the logs is more difficult and may well show
very different situations downhole.
Another example, this of a producing well with channels or
communication behind cemented casing, is offered by Robinson (1976b).
Figure 29 shows two log sections from a two zone, two tubing string
completion in Louisiana. Tests indicated that both zones produced
2800 mcf of gas, 42 barrels of oil and 1000 barrels of water per day.
The water seemed to be extraneous to both zones and began nearly
simultaneously. One conclusion was that communication existed between
the two zones. BHP tests were inconclusive. A tubing leak and
communication behind casing was suspected, but not proven. A spinner
flowmeter survey was ruled out because of the possible behind- pipe
communication. The decision was made to run a noise log to determine
behind-pipe communication, tubing or casing leaks and a possible
packer leak. The 10ggin9 tool was in the long string for the three
runs shown in Figure 29A and 29B.
97
-------
..
..,
Casing
~.::
;.p
;;~.
Cement
-
o. .
~:.;:
Less :..'.<;
Permeable -;:..;"
Formation >~~
.).\
Channel
Construction
> .
Channel
" .~
Physical Condition 01 Well
Figure 27. Typical noise log display.
98
NOise
Detection
Station
.J::
a.
~
o
~
Peak
NOise Level
(Millivolts)
Noise Log Display
-------
Temperature/sound tool
CCllo
recorder
To differential
temperature
module
Frequency to
temperature
converSion
High-pass filters
and averagmg amplifiers
Ampl
Sound
Temp.
Neg voltage
To sound recorder, spectrum analyzer.
speaker and earphones
Figure 28. Combination noise/temperature survey system (Pennebaker and Woody, 1977).
99
-------
....
8
TYPE 1
9-3-75
TERREBONNE
PARISH, LA
RUN 1
BOTH STRINGS OF
2'," TBG-SHUT IN
RUN2
TOOL IN LONG STRING
SHORT STRING FLOWING
2
5
TBG PACKER
@ 10,500
20
10
7"CSG
2'," TBG
200 HZ
Blast JOint
PEAK-PEAK MILLIVOLTS NOISE LEVEL
50
100
A. Run 1 and Run 2
9.400
X
NIPPLE
I
DUAL
PACKER
9,500
9.600
9.700
9,800
>--
u.
I
>--
Cl.
UJ
o
TYPE 1
9-3-75
TERREBONNE
PARISH, LA.
2
5
10
20
50
100
200
PEAK-PEAK MILLIVOLTS NOISE LEVEL
B. Run 3
Figure 29. Noise log sections from a 2-zone, 2 tubing string completion (Robinson, 1976b).
9.800 t;:
I
9,900 Ii:
UJ
o
10,000
10,100
10,200
10,300
500 1,000
-------
Both strings were shut in to log Run 1. This run did not show
any flow of significance; however, it does furnish a base or reference
log. Run 2 is a log over the same interval as Run 1 with the long
string shut in and the short string producing water, oil and 1500 mcf
of gas per day. Comparing Run 2 with Run 1, the increased separation
between the four curves, especially the 200 HZ, indicates two phase
flow through the entire interval. The peaks on all four curves
opposite the perforations are an indication the zone is producing.
The shift of all four curves at 96161 indicate there is two-phase flow
inside the 7" casing past the foot of the long-string blast joint.
This shift is due to a difference in the cross section area caused by
the 3" 0.0. blast joint compared to the 2 3/8" 0.0. tubing. There
weren't any indications of a hole through this interval and the
conclusion was that the packer was probably leaking.
Figure 29B is Run 3 from the same well as Figure 29A. The short
string was shut in and the log was run in the long string while it was
producing. There are at least two indications of problems on the log:
1) the relative amplitude of the peaks opposite the perforations
which are supposed to produce into the short string and
2 )
a significant shift on all four curves beginning at 9750'.
The high noise level at the perforations for the short string
indicate a hole in the blast joint. All four curves shifting at 9750'
indicates behind casing flow or a hole in the casing or tubing. The
SP and E log indicate a water sand at that depth and, regardless of
whether the problem is, a hole or behind pipe flow, the water source
is at 9750'.
To review the interpretation, there was a hole in the long string
blast joint, behind pipe communication from 9750' to the short string
perforations and a probable packer leak at 10,5001.
101
-------
REFERENCES
Arnold, D.M. and H.J. Papp, 1979, Quantitative monitoring of water
flow behind and in wellbore casing; Journal of Petroleum
Technology, vol. 31, no. 1, pp. 121-132.
Britt, E.L., 1976, Theory and applications of the borehole audio
tracer survey; SPWLA Seventeenth Annual Logging Symposium
Transactions, 35 pp.
Enright, R.J., 1955, Sleuth for down hole leaks; Oil and Gas Journal,
vol. 53, no. 43, pp. 78-79.
McKinley, R.M., F.M. Bower and R.C. Rumble, 1973, The structure and
interpretation of noise from flow behind cemented casing; J(Jrnal of
Petroleum Technology, vol. 25, no. 3, pp. 329-338.
NL McCullough, Inc., no date, Logging manual: noise logging; N.L.
McCullough, Houston, Texas, pp. 43-55.
Pennebaker, E.S., Jr. and R.T. Woody, 1977, Scanner, orienter help
solve casing leaks; Oil and Gas Journal, vol. 75, no. 49, pp.
75-80.
Robinson, W.S., 1976a, Field results from the noise-logging technique;
Journal of Petroleum Technology, vol. 28, no. 11, pp. 1370-1375.
Robinson, W.S., 1976b, Recent applications of the noise log; SPWLA
Seventeenth Annual Logging Symposium Transactions, 25 pp.
102
-------
SECTION 10
PIPE ANALYSIS SURVEY
SYNOPSIS
The Pipe Analysis Survey
downhole corrosion damage, is
other types of casing damage.
produced by the PAS tool, the
(Bradshaw, 1976):
(PAS), which was developed to detect
also able to provide information on
Through interpretations of the log
fOllowing conditions may be evaluated
- the approximate range of nominal casing body wall penetration;
- whether the damage is on the inside casing wall (internal) or
the outside casing wall (external); and
whether the casing damage is isolated or circumferential.
The PAS functions as a "microscopic" casing inspector. It is
primarily used to detect the presence of small casing defects, such as
corrosion pitting. Tests indicate that casing anomalies as small as
1/8" in diameter for inner wall defects and 3/8" in diameter for outer
wall defects with as little as 20% nominal body wall penetration can
be detected and recorded with the PAS (Smolen, 1976). Although small
defects are easily observable on the PAS log, large-scale conditions,
such as casing splits, are often impossible to discern. The PAS tool
can inspect casing from 4 1/2" to 9 5/8" diameter. Because the tool
is centralized in the casing and has multiple and independent
measuring devices, the PAS inspection covers the full circumference of
the casing. The PAS is capable of inspecting only the inner string of
multiple casing strings.
The PAS tool detects casing defects such as holes, gouges or
cracks, by measuring fluctuations in an induced magnetic field with
coils mounted in small pads. The PAS is able to discriminate between
defects on the inside and outside of the casing wall by means of a
high-frequency eddy current test, which detects flaws on only the
inner surface, and a magnetic flux leakage test, which inspects the
full casing thickness. An evaluation of the various nondestructive
mechanical integrity testing techniques indicates that a combination
of high-frequency eddy current and magnetic flux leakage tests
provides an optimum approach for in-place inspection of well casings
to detect small, isolated defects or corroded areas and to determine
whether they are located on the internal or external casing wall.
103
-------
PRINCIPLES
Magnetic f1 ux leakage testing re1 ies on the detection of.
perturbations in an induced magnetic field caused by defects 1n the
casing of a well. Implementation of this technique requires a source
of magnetic flux and sets of pick-up coils that ri~e the inner surface
of the casing on an array of pads. If DC current 1S sent through a
coil of wire (the electromagnet within the PAS tool), a magnetic field
is generated along the axis of the coil (Figure 30). The magnitude of
the magnetic field is primarily determined by the product of. the
current through the coil in amperes and the number of turns 1n the
co i 1 .
A magnetic field consists of an inf'nite number of lines of force
called magnetic lines of flux. These have two basic properties which
the PAS system uses:
- the magnetic lines of flux travel through casing more readily
than through ai r or f1 ui ds; and
- one line of magnetic flux cannot cross another line of magnetic
f1 ux.
Energy. in the form of magnetic flux, is introduced into the pipe
wall. The pipe itself acts as a conducting medium and conveys the
magnetic lines of force. If the casing body wall is consistent, and
no anomalies are present, the li~es of magnetic flux are
uninterrupted. Any anomaly in the casing will cause a leakage of flux
from the casing wall; the lines of flux alter ~heir path and create a
"fringing" or bridging pattern over and around the anomaly since, at
the defect, there is less iron in the pipe to conduct the magnetic
flux (Figure 31). The amount of fringing or bridging is directly
proportional to the geometry and the percentage of penetration of the
anomaly.
Tre fringing flux, which extends into the hole, is detected by
pick-up coils or transducers, mounted on the PAS tool, which provide a
full 3600 coverage of the circumference of the casing. As these
sensors pass through an area of flux leakage, an electrical signal is
produced. The magnitude of this signal is determined by the pick-up
coil size, the rate at which the coil passes through the area of
leakage, and the amount of leakage through which the coil passes.
Because the size of the pick-up coils is constant and the rate at
which the coils pass through an area of leakage (logging speed) is
relatively constant, the magnitude of the vOltage generated in the
transducer is proportional to the percentage penetration of the
anomaly relative to the nominal casing body wall.
The magnetic flux path, which is distorted in the vicinity of a
defect, has a small component normal to the casing wall both above and
below the defect. As the flux leakage coils pass over the defect as
104
-------
'il. Coil
II
I'"
I "
I ~ I
"I Casing
II . I
I 'I
III
I I:
I Induced Field
'I
Flux Lines
Figure 30. Diagram of magnetic field being induced into the casing body wall
(Bradshaw, 1976).
105
-------
~
- -- ~z ~ -
-=-=... -;.-: -_.- _:_~~~-................~---=-.~_..- ,- -.
--~--=..~-- -- - -. --
- ~---~ --.
- - - -
A =-
A Visualization of Magnetic Lines of Flux Flowing Around a Pit in Casing Inner Wall
.{~ I::::::::::::::::::::::::::::~
~
-
- .
-
B
The Signal Produced as a Pad Approaches the Pit
-
C
The Signal Produced as the Pad Passes Over the Pit
-
1'.'''''''''::-)
',',',','0°.'.'.'.'.'.'.".".'
"",""","','
- -
o
The Signal Produced as the Pad Leaves the Pit
Figure 31. Diagram of the response of the pipe analysis log to a casing defect
(After Bradshaw, 1976).
106
-------
shown in Figure 32, this component grows from zero to a maximum and
then back to zero, thereby inducing a current in each of the flux
leakage coils. Since the coils are1t different points in the field,
the current induced in each is different. The differences in the
induced currents in the upper and lower flux leakage coils is a
measure of the rate of change of the flux vector into the well bore
and hence of the magnitude of the defect.
The amount of flux leakage detected by a transducer is
the location of the anomaly with respect to the transducer.
to the instrument, this means that an internal anomaly will
signal of greater magnitude than an external anomaly of the
penetration.
The overall system for defining internal and external defects
uses a technique known as eddy current sensing. By varying the
amplitude and polarity of current flowing through a coil, a
corresponding variance in the amplitude and polarity of the magnetic
field produced by the coil will occur. If an electrical conductor is
placed in this varying magnetic field, small varying currents known as
eddy currents will be set up in the electrical conductor due to the
relative movement of the magnetic field with respect to the electrical
conductor.
rel ated to
Relative
generate a
same
As Figure 33 illustrates, a high-frequency current in the eddy
current coil generates a magnetic field, Be, which induces a
circulating current; ii, in the casing. This induced current
generates a countervailing field Bi in the casing wall. The
resulting field intensity is detected by the flux leakage coils and
separated from the flux leakage signal by a frequency filter. Flaws
in the casing surface impede the formation of circulating currents and
hence have a substantial effect on the distribution of the induced
field, Bi. Changes in the difference in the induced currents in the
sensing coils, il-i2, are a measure of surface quality. The
effect of good and bad casing on this test is shown in Figure 33.
The amplitude of current passing through the eddy current coil is
affected by the distance of the coil from the conductor, the
electrical conductivity of the conductor, the permeability of the
conductor, the magnetic reluctance of the metal, the current
frequency, and the amount of conductor present. A change in any of
these factors will produce a corresponding change in coil current
amplitude. For the eddy current test, a transmitter coil is mounted
above the pick-up coils in each pad on the instrument. Frequency for
the eddy current test is chosen so that the depth of investigation is
only about 1 rom into the inner casing wall; as a result, this test is
insensitive to outer surface casing defects. Thus, simultaneous
defect signals from both the eddy current and the magnetic flux
leakage tests indicate that the defect is on the inner surface of the
casing. On the other hand, an indication from the magnetic flux test
with no indication from the eddy current test indicates the defect to
be on the outer surface of the casing (see Figure 38).
107
-------
FLUX LEAKAGE TEST
PAD
1. UPPER
I COIL
FLUX
LEAK
LOWER
COIL
VECTOR
COMPONENTS
OF FLUX
! PATH
L PAD MOVING
DOWN
FLUX
COMPONENT
NORMAL TO CSG.
WALL
RESPONSE
SHOWN
ON LOG
iL -iu
RESPONSE
TO DEFECT
Figure 32. Principle of operation of magnetic flux leakage test (Smolen, 1976).
108
-------
EDDY CURRENT TEST
CSG.
WALL
EDDY
CURRENT
COIL
PRIMARY
i2 FIELD
SENSING COILS
OUTPUT BALANCED;
i, - i2 - CaNST.
GOOD CASING WALL
INDUCED
FIELD
i
I
i,
SENSING COIL OUTPUT
NOT BALANCED;
i, - i2 - CaNST.
DAMAGED WALL
Figure 33. Principle of operation of eddy current test (Smolen, 1976).
109
~
-------
EQUIPMENT
The basic downhole PAS tool consists of a sonde, an upper and
lower cartridge (each an electronics package) and two centralizers
(Figure 34). The sonde is comprised of an electromagnet and two. .
arrays of pads consisting of six pads each. The electromagnet w1th1n
the sonde is a coil of wire wound on a core passing through the center
of the sonde. Regulated DC current is sent to this coil from the
surface instrumentation via a wireline. The magnitude of the magnetic
field generated by the coil is made great enough to sat~rate the. body
wall of the casing with lines of magnetic flux. Magnet1c pole p1eces
are mounted above and below the pad arrays. The pole pieces are
changed for various sizes of casing to be inspected so that there is
approximately a 1/411 gap between the pole piece and the casing.
The sensing width of each pad is two inches. The pads are
arranged as shown in Figure 35 in upper and lower arrays of six pads
each to assure total casing coverage (Smolen, 1976). In most casing
sizes, there is a degree of double coverage due to overlapping of the
pad paths. Hence, some portion of the casing may be examined by a pad
in each of the upper and lower arrays while other portions of the
casing may be only examined once. The pads are spring loaded and
adjust for casing sizes from 4 1/211 to 9 5/811 outside diameter.
The pads each contain a pair of coils on their inner surface to
detect flux leakage. These are referred to as the upper and lower
flux leakage coils and are situated within the pad as shown in Figure
36. Centrally located on the inside of the pad is a third coil used
for the eddy current test. The pad is oriented in the well bore with
the flux leakage coils one above the other. These transducers are
located in such a manner that the area of casing affecting the eddy
current transducer is also the area containing a potential anomaly
which would affect the flux leakage transducer. Each transducer is
connected to one of the cartridges on the tool.
The two cartridges relate directly to the two principles used by
the system -- one supports the magnetic flux leakage test and one
supports eddy current testing. One of the cartridges thus processes
the signal received from the flux leakage transducer, relating to the
severity of casing damage, and the other cartridge is dedicated to
discriminating between internal and external anomalies. The cartridge
supporting the flux leakage test is divided into two sections
corresponding to the two arrays of pads on the instrument. Each array
of pads has a readout channel at the surface for flux leakage
detection. The top ring of pads produces one channel and the bottom
ring of pads the second channel.
An uphole signal processing panel is connected to the downhole
tool via a conducting wireline. The uphole panel provides power for
the downhole cartridges, DC power for the electromagnet, and uphole
signal processing circuitry.
110
-------
Upper
Cartridge
Centralizer
Pad
Arrays
Centralizer
Lower
Cartridge
Figure 34. The pipe analysis survey tool (Cuthbert and Johnson, 1974).
111
-------
PAD GAP"" .5 x 1.0. - 2
SINGLE INSPECTION
Figure 35. Diagram of pad overlap (Smolen, 1976).
112
UPPER
ARRAY
-------
UPPER FLUX LEAKAGE COIL
EDDY CURRENT COIL
LOWER FLUX LEAKAGE COIL
a EDDY CURRENT CDIL
I FLUX LEAKAGE COILS
~=El
Figure 36. Diagram of pad configuration (Smolen, 1976).
113
-------
The downhole tool will operate in temperatures and pressures up
to 250°F and 10.000 psi respectively.
PROCEDURES
Prior to logging each well. the system is calibrated by inducing
a magnetic signal of a known level into.e~ch transduc~r. Each
transducer is connected to its own amp11f1er located 1n the
instrument. With the instrument connected to the wireline. each
amplifier is adjusted so that the magnetic signal induced.i~ !ts
respective transducer produces the same number of chart d1v1s10ns on
the readout system. This calibration procedure is necessary to ensure
that each of the transducers will react as identically as possible to
the same anomaly.
The PAS downhole tool is lowered down the well on a wireline to
the desired depth of investigation. The pads are then extended via a
spring-loaded mechanism until they contact the well casing. DC
current is supplied to the electromagnet contained within the sonde.
The tool is then pulled up the well on the wireline. centered in the
well with centralizing devices on either end of the tool.
The magnetic field generated by the electromagnet causes magnetic
flux lines to permeate the casing in a direction parallel to the well
bore. Anomalies in the casing distort the flux path. causing some
flux lines to bridge around the defect. Defects are detected by
sensors located in each of twelve pads in two pad arrays. Electrical
signals generated by casing defects are then amplified and sent uphole
to receiving equipment at the surface. where the data generated by the
downhole tool is recorded and later interpreted.
Any scale buildup on the inside of the casing may be a potential
problem to the operation of the PAS tool in the well. While this does
not directly affect the measurements made by the tool. scale deposits
may adversely affect the ability of the tool to be pulled back uphole.
since pads which contact the inside of the casing are used in making
measurements.
INTERPRETATION
PAS data consist of four channels of information on one type of
log. and two channels of information on another type of log.
Int~rpre~atio~ of the PAS log. then. con~ists of reading and
dec1pher1ng e1ther the four channels of 1nformation on the one type of
log or the two channels contained on the other type of log.
The first two channels of the first type of PAS log (Figure 37)
are called flux leakage channels -- they correspond to the two rings
of pads on the downhole tool. These two channels relate to the
overall condition of the casing with respect to pitting. Since the
flux leakage test is sensitive to the gradient of the component of
magnetic flux lines normal to and into the well bore. it is in reality
114
-------
.....
.....
U'I
Discriminator
Average
FL-1
FL-2
l 7" OD 261. J-55 L
.. ,101'''", . ...""~,' Jt.-, ",..'" "'*'....." ...""... ..,..
tin .J"i" -11~""P ~
.. ,
'; . ~ -'-
.~ .
~ ;. .:~):, r ~ ,of ~
) ;
, .
u
........~-
~ ~ ;; { :
.t r' f ~ .~. ~ q)-.. -.¥- .~, } ..:
-- . ~ .. ~.. 1.. 1
f: .~;.t j': Fef,.
~ ~
. ,
1 !
.1 ! ' .~.
j I < ;
-.". '; '1, ,t.~. ..,
! ...1 t.1 L
+.innf.. f
~ i ~ { ~
,
~ ~ >
l :. u ;
! :.-
t r!
t ;
t '
t ' .
. .
i :
-r
Figure 37. Example of four-channel output from one type of PAS log (Bradshaw, 1976).
-------
sensitive to the abruptness of the defect's occurrence, as seen when
the tool moves uphole. A gradually occurring defect will not be
detected unless some surface roughness or pitting is present. The
signal which appears on each of the first.two cha~nels is the maximum
of the signals generated by each of the S1X pads 1n an array.
The thi rd channel is referred to as the "di scrimi nator" channel.
Any change in current amplitude is sensed by the eddy current coils
which in turn send a signal to the discriminator channel. If the
signal on the discriminator channel has a corresponding si~nal on the
first or second channel, that signal is interpreted as an 1nternal
anomaly. If there is no corresponding signal on the first or second
channel, the signal on the discriminator channel is ignored.
The fourth recording on the ?AS log, the "average" channel,
relates the effect of the cross-sectional area of the casing, thus
allowing for interpretation of thf results from the first two
channels. It has been found from :ield tests that a circumferential
anomaly will produce a higher indication than an isolated anomaly of
the same body wall penetration. Tc help differentiate anomalies, all
transducers in the top ring of shoe$ are connected to a circuit which
produces the average channel readJu. The averaging circuit takes a
portion of the si gnal produced by ech transducer in the top ri ng of
shoes and adds all of the portions .ogether. The output of the
averaging circuit is proportional tc the number of top ring
transducers that produced a signal at the same time. A casing collar,
for example, produces an equal signai on all transducers, and thus
appears as a 3600 anomaly.
If the intensity of the indication produced by the average
channel is divided by the number of transducers located in the top
ring of shoes, the contribution of each transducer to the total
intensity of the indication can be determined. Experimentation has
shown that an anomaly which produces a signal on the average channel
equal to the contribution of 2 1/2 transducers should be interpreted
as circumferential in nature (Bradshaw, 1976).
The average channel also serves as a guide to help evaluate the
proper operation of the instrument. Any signal which is recorded on
the first channel must have a corresponding signal on the average
channel. Because of the difference in the method of signal
processing, a signal recorded on the average channel does not imply
that the signal should have been recorded on the first channel.
The oscilloscope traces on Figure 38 illustrate the information
contained on the second type of PAS log. The signals shown are from a
sonde as it was pulled through a pipe with various known defects in
the laboratory (Cuthbert and Johnson, 1974). The upper trace is the
flux leakage test signal and the lower trace is the eddy current test
signal. The first five defects, A through E, are on the internal
wall; they are drilled holes ranging from 3/8 in. diameter with 25
116
-------
MAG.-FLUX
TEST
. (TOTAL WALL)
PERCENT
DEFECT LOCATION DIAM. WALL
(in.) PENETRATION
A INTERNAL 3/8 25
B INTERNAL 3/8 50
C INTERNAL 1/2 25
o INTERNAL 1/2 50
E INTERNAL 3/4 25
F EXTERNAL 3/8 25
G EXTERNAL 3/8 50
H EXTERNAL 1/2 25
J EXTERNAL 1/2 50
K EXTERNAL 3/4 25
L EXTERNAL 3/4 50
Figure 38. Oscilloscope traces of a laboratory PAS log (Cuthbert and Johnson, 1974).
117
-------
percent wall penetration to 3/4 in. diameter with 25 percent wall
penetration. Since both the magnetic flux le~ka~e test and the eddy
current test show anomalies, the defects are lndlcated to be on the
internal wall surface. The next six defects, F through L, are on the
outside wall and range from a 3/8 in. diameter pit with 25 percent
wall penetration to a 3/4 in. diameter pit with 50 percent wall
penetration. In this instance, anomalies are indicated by the
magnetic flux leakage test, but not by the eddy current test,
indicating that the defects are confined to the outer surface.
On a variety of the second type of PAS log, which consists of two
channels of information plus a composite curve, the first two channels
correspond to the two arrays of pads on the tool (Figure 39). One
channel corresponds to the signal produced by the lower array of pads,
and one corresponds to the upper array of pads. On this log, each
array produces two curves, one which relates to the condition of the
inner surface of the casing and to the eddy current test, and one
which relates to total wall thickness and thus to the flux leakage
test. The traces in the left-hand track are referred to as "enhanced
curves. II Each of the two enhanced traces is derived from the
corresponding maximum signal from any of the twelve pads in the upper
and lower arrays. There is a provision to make large deflections more
visible on the enhanced curves by holding the recording device at the
maximum deflection for a short period of time after the maximum is
reached. If a second defect were to occur during the hold period, it
will not appear on the enhanced curves. Thus, vertical resolution is
lost on the enhanced curves, but major defects can be made more
apparent.
External metallic hardware which is in contact with the casing
(i.e. scratchers or casing centralizers) will also produce a change in
magnetic flux in the hole, which will be detected by the PAS tool.
Thus, information concerning the placement of exterior hardware is
essential for correct log interpretation.
COST
The cost of conducting a pipe analysis survey is dependant upon
the many general pricing variables as outlined in Section 7. The
range of specific depth and logging charges as determined by a survey
of six major well logging companies in the midcontinent area of the
United States are listed in Table 13. Refer to Table 7 for a listing
of companies surveyed which perform this service.
ADVANTAGES AND DISADVANTAGES
The PAS offers several advantages in mechanical integrity testing
in that it was developed specifically to evaluate downhole casing
damage. It is able to distinguish between internal and external
casing damage and can determine whether the casing damage is isolated
or circumferential. Even relatively small defects in casing (l/8"
diameter for inner wall defects; 3/8" diameter for outer wall defects)
118
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TABLE 13. TYPICAL DEPTH AND LOGGING CHARGES FOR PIPE ANALYSIS SURVEYS
Depth Charge Low High
per foot $0.29 $0.30
minimum $580.00 $600.00
Logging Charge Low High
per foot $0.28 $0.29
minimum $560.00 $580.00
can be detected by PAS. The combination of high-frequency eddy
current and magnetic flux leakage tests in one tool appears to offer
the best available approach for detecting casing defects.
Several disadvantages in the use of the PAS for mechanical
integrity testing are also apparent. The primary disadvantage is that
the PAS is offered by only a few well servicing contractors.
Additionally, interpretation of the log produced by the PAS must be
done by a highly skilled log analyst.
Because of the size of the tool used, the PAS can only be
utilized inside casing, and thus cannot be used to inspect tubing.
The tubing must be removed from the well before the PAS can be run,
necessitating a lengthy shut-down time for the well and possibly
replacement of the packer. In addition, while the PAS can detect
external casing defects, it cannot provide information on fluid
migration in the cement sheath behind the casing.
EXAMPLES
Figure 39 is an example of a PAS log from a gas-storage well
where the inner wall of the pipe is corroded. Interpretation of the
data from the pipe analysis log indicates that the casing is free of
defects below 70 ft. With the exception of one serious defect near 30
ft, the log indicates that the corrosion is light to moderate on the
internal surface of the pipe. This string of pipe was subsequently
pulled. Surface inspection confirmed that the casing below 70 ft is
free of corrosion. Above 70 ft there is heavy scale build-up on the
inner surface, with light to moderate pitting. The large indication
on both the magnetic-flux-leakage and eddy-current tests is from a
large pit, greater than 1-in diameter, with 20- to 30-percent wall
penetration.
In another example from Cuthbert and Johnson (1974), Figure 40
shows the PAS tool response in 7-in casing in a laboratory test well
with known defects. The bottom joint of casing from 20 ft down has
119
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PIPE ANALYSIS LOG
ENHANCED CURVES LOWER ARRAY UPPER ARRAY
INNER TOTAL INNER TOTAL
INNER TOTAL SURFACE\ WALL SURFACE" #' WALL
SURFACE, II WALL DEPTH /
0
0
0
CC 0
t ~ ;;;...
CC
L r-
~ -'
~ - f
-= ....--
~
CC
~
1 ~ J-
.. ~ -
cc
cc 0
0
0
cc
cc
cc 0
...
0
0
Figure 39. Example of a PAS log from a gas storage well (Cuthbert and Johnson, 1974).
120
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LOWER ARRAY
UPPER ARRAY
10
- INNER --1 ~ TOTAL INNER. TOTAL
SURFACE WALL SURFACE 1 ~ WALL
~"J ,~, I r~~ ~~'
I I ..
. NEW PIPE S
~ '
,. -,
{ ,
S ~
~ .~-
CC""'" i --I os,.;
.'" I~ SEVERE J
'I c: "-I -'
~ - OUTER-WALL 1
.. I~ P-
I CORROSION
I-'- i
1!!1!:--- ~
-- .-- .""~ -..!
..... - - = -:.."" 0-...:
CC", .... -1
,
{IF~ r ~ ~ ~
I MODERATE
\
OUTER-WALL i. IoL
:S:: "'" CORROSION '. ..
20% PENETRATION I C~~
~ >- ~, I ' I I I
CC - =--= ~~ ~z--. I t-~"r~t: ~
il , ~
LIGHT
I .Ii; I OUTER-WALL i ~
. '"
CORROSION -~.' ~
, I 10% PENETRATION ' ..
I I I I I I .-..;
20
Figure 40. PAS tool response in a 7-inch test well with known defects
(Cuthbert and Johnson, 1974).
121
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light external corrosion--approximate1y la-percent wall penetration.
The joint from 15 ft to 20 ft has moderate external corrosion with
approximately 20-percent wall penetration. The joint between 10 and
15 ft is corroded externally. The corrosion is so severe that there
were several small holes, 1/4-in to 1/2-in in diameter, completely
through the pipe. Except for the holes, which are detected by the
eddy-current test, the inner surface is quite clean. The flux-leakage
test, however, produces a dramatic log indicating the severity of the
external corrosion.
122
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REFERENCES
Bradshaw, James M., 1976, New casing log defines internal/external
corrosion; World Oil, vol. 183, no. 4, pp. 53-55.
Cuthbert, J.F. and W.M. Johnson Jr., 1974, New casing inspection log;
Paper presented at 49th Annual Meeting of SPE, October, 1974, Houston,
Texas, 12 pp.
Smolen, James J., 1976, PAT provisory interpretation guidelines;
Schlumberger Well Services, Interpretation Development, Houston,
Texas, 9 pp.
123
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SECTION 11
ELECTROMAGNETIC THICKNESS SURVEY
SYNOPSIS
The Electromagnetic Thickness Survey (ETS) re~ponds t~ gener~l
casing deterioration. including large-scale corrOSl0n, caslng.spl~ts
and mechanical wear, by measuring the phase shift of a m~gnetlc fleld
induced by the tool. The ETS measures average casing thlckness over a
length of about two feet.
Stroud and Fuller (1961) list the applications of the ETS in
production wells:
- to detect the progress of corrosion and determine the
effectiveness of cathodic protection programs,
- to log casing where a re-drill is proposed to determine if the
casing has adequate strength to support such an operation,
- to log casing to evaluate its salvage value, and
- to locate a leak and determine the general condition of
adjacent casing to plan remedial action.
The log generated by the ETS tool is sensitive to variations in
magnetic permeability and electrical conductivity of the casing.
Because of this, it is most effectively used to monitor changes in
casing condition over a period of time as an indicator of progressing
casing damage. This requires a base log as a reference.
The ETS does have a somewhat limited resolution in that the
smallest hole size it can detect is approximately one inch in
diameter. It is used primarily to observe large-scale casing
problems, such as splits or parting or large holes in the casing
It cannot discriminate between inner and outer wall defects.
wall.
The ETS tool utilizes the only measurement capable of detecting
corrosion or other defects in the outer string of a double string of
casing. It is capable of serving as an early warning device in double
casing strings by indicating major alterations in the outer string.
124
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PRINCIPLES
The ETS responds to the amount of metal surrounding the downhole
tool by measuring the effect of eddy currents on a magnetic field.
The downhole instrument used in the PAS consists of two radial coils--
an exciter coil and a pick-up coil. An alternating current sent from
the surface equipment to the exciter coil generates a magnetic field
which sets up eddy currents in the casing wall. These eddy currents
cause the magnetic field to be attenuated and shifted in phase, and
the resulting magnetic field is detected by the pick-up coil. The
phase of the signal induced in the pick-up coil lags the exciter coil
current by an amount proportional to the average thickness of the
casing (Figure 41). The signal detected by the pick-up coil is
amplified and transmitted to the surface.
At the surface, in the upho1e instrumentation, the signal from
the downhole tool is separated from the exciter voltage and amplified.
At this point, the signal is a true reproduction of the bottom hole
signal from the pick-up coil. The phase of this signal is compared
with the phase of the exciter voltage signal and the resulting phase
shift is recorded.
The theory of eddy currents indicates that phase shift is
determined by four factors: casing wall thickness, frequency,
magnetic permeability, and resistivity of the metal. The basic
phase-shift equation:
cI>= 211"0 j2-
p x lOJ
where cI>= phase shift (radians), 0 = casing thickness (meters), F =
freauency (Hz), ~ = Magnetic permeabil i ty (Henrys/meter), and p =
casing resistivity (ohms-meters); demonstrates that the phase shift is
directly proportional to casing wall thickness.
The factors of magnetic permeability and metal resistivity vary
considerably for casing from well to well and even from joint to joint
within a well. Stresses placed upon casing installed in wells also
seem to affect the magnetic permeability of the metal. This problem
is minimized by running a base log early in the life of the well, for
comparison with subsequent logs run in that well.
A modified ETS log was developed by one well servicing company to
eliminate the dependence of the ETS on magnetic permeability and metal
resistivity (Smith, 1980). The tool used in this survey measures
magnetic permeability and computes true average wall thickness. It
can, therefore, distinguish magnetic permeability variations from
thickness variations. This is especially useful in older wells, where
magnetic permeability can vary by as much as a factor of five (Smith,
1980 ) .
125
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~
N
G)
Group A-Flux lines completely inside casing wall
Group B-Flux lines in casing wall
Group C-Flux lines pass thru wall
Flux lines sensed by receiving coil
Transmitter Coil
[Phase shift
resulting from
flux passing
thru points X
Figure 41. Diagram 01 principles 01 an ETS Survey (Smolen, 1976).
X-Points at which transmitted field picked up by receiver
coil pass thru casing-Leo these are the pOints where
casing thickness data is taken. Points approximately
three feet apart.
-------
The modified ETS utilizes a multiple-frequency measurement scheme
to determine average casing wall thickness, with six separate coils
operated in pairs at three different frequencies (Figure 42).
A low-frequency magnetic flux induces eddy currents in the casing
wall, much as the other surveys do. These currents cause a phase
shift and amplitude attenuation in the flux flowing from the
transmitter coil to the receiver coil. The resulting receiver coil
voltage phase shift is a function of the casing thickness and magnetic
permeability of the casing.
A mid-frequency measurement is used so that none of the
transmitter-to-receiver flux penetrates through the casing wall. The
receiver coil voltage at this frequency is dependent on the magnetic
permeability and inside diameter of the casing.
A third, high-frequency measurement is made so that the
transmitter-to-receiver flux penetrates only the inner skin of the
casing wall. The high-frequency receiver voltage is thus a function
of inside diameter only, allowing this measurement to serve as an
electronic caliper.
EQUIPMENT
The original ETS downhole tool, illustrated in Figure 43,
consists of two radial coils -- an exciter coil and a pick-up coil.
Centralizing springs are located at the top and bottom of the tool to
minimize wear on the two coil housings. The tool is designed to
withstand downhole temperatures and pressures of 350°F and 20,000 psi
respectively. Tools are available for use in wells from 4 1/2 to 9
5/8 inches outside diameter.
In the surface instrumentation, the phase angle transmitted
upho1e via the wire1ine is measured by a solid-state phase detector.
A linear output voltage, which is proportional to the phase angle, is
produced to drive a strip-chart recorder.
The equipment utilized in the modified ETS differs in that the
downhole tool consists of a sonde with six radial coils -- three
transmitter-receiver pairs which utilize three separate frequencies --
an electronics cartridge to process the data and a telemetry cartridge
to transmit the data upho1e. The device is centered in the hole with
three centralizing devices. Sondes are available for use in casing
from 5 1/2 to 9 5/8 inches outside diameter; the limiting diameter of
the tool string is the sensor. The maximum temperature and pressure
rating of the downhole equipment is 350°F and 20,000 psi.
In the upho1e signal processing equipment, a differential display
is used to present data transmitted from the downhole tool. The
nominal inside diameter for the casing being inspected is first set
into the instrument memory. Deviations from the nominal level are
then recorded on film and displayed on the log.
127
-------
ETT-C SONDE COIL ARRAY
HIGH
FREQUENCY
F (10)
LOW FREQUENCY
F (t. 1")
MIDDLE FREQUENCY
F (I" 10)
10 = INSIDE DIAMETER
t = CASING WALL THICKNESS
I" =CASING RELATIVE PERMEABILITY
ETT -C PROCESSING
a) LOW FREQUENCY SHIFT: F (t. 1")
b) MIDDLE FREQUENCY MEASURE: F (I" 10)
c) HIGH FREQUENCY MEASURE: F (10)
. PROCESSING b) and c) YIELDS I"
. PROCESSING a) and I" YIELDS t
=WALL THICKNESS
I" = RELATIVE PERMEABILITY
10 =CASING INSIDE DIAMETER
Figure 42. Diagram of modified ETS array (Smith, 1980).
128
-------
PRODUCTION POWER !.WIT
ETT PLUG -IN UNIT
NONOCABLE HEAD
- CENTRALIZER
- ETT CARTRIDGE
Pickup
Coil
Exciter
Coil
COIL
ETT SONDE
COIL
- CENTRALIZER
B
A
Figure 43. ETS downhole tool and diagram of an ETS logging system
(A-Stroud and Fuller, 1962, B-Cotton et aI., 1983).
129
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PROCEDURES
The ETS is run much the same as the PAS in tha~ the downho1~ tool
is lowered down the well on a wire1ine, AC current 1S then supp11ed to
the tool's sonde so that a magnetic field may be generated, and the
tool is then pulled up the well. Normal logging ~rocedure would call
for an in-hole run at a speed of about 150 feet/m1nu~e. T~e ETS may
be run as a base log either before or after perforat1ng, Slnce the
we11bore fluid has no effect on the log. The tool works equally well
in gas, air, water, or oil.
Prior to running the tool in the well, the tool is calibrated by
recording an "air reading" with the tool suspended above the wellhead.
This is the recorder response to zero casing wall thickness. As the
tool is lowered into the well and the casing wall thickness is
recorded, the recorder pen on the uphole logging instrumentation moves
from left to right on the strip chart.
The coils on the logging sonde must be adjusted so that the flux
lines generated by the exciter coil just reach the pick-up coil. and
not so far away that the signal received is too weak to be detected.
This has required an exciter coil to pick-up coil spacin? of two to
three times the casing diameter. Thus, for 7" and 9 5/8' casing,
spacings of 17.6" and 21.6" respectively would be necessary (Cotton et
a 1 ., 1981).
Experience indicates that the ETS is of great value in
determining the extent and rate of casing damage if periodic surveys
are made at regular time intervals, beginning with a base log recorded
at the time of completion of the well. With a base log for
comparison, corrosion and other casing damage can be detected when as
little as three to five percent of the original casing thickness has
been affected. With this method of early detection, it is possible to
take remedial action before serious problems develop in a well. This
also allows for more accurate methods of interpretation, since
anomalies due to casing mill tolerances will be detected by the survey
and recorded on the base log.
INTERPRETATION
The ETS can be a valuable tool in isolating corroded or otherwise
damaged intervals of well casing. However, several points must be
kept in mind when interpreting ETS logs.
Because phase shift is dependent on the magnetic and electrical
properties of the casing, it is difficult to positively distinguish
whether,a log,anomaly is due to lo~s of metal from the casing or to a
change 1n cas1ng properties. Runn1ng ETS logs on a time-lapse basis
assumes that the magnetic and electrical properties of the casing are
constant with respect to time as the casing performs its function in
the well. Reductions in the phase shift over time, then, reflect a
130
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loss of metal. However, many wells have never had a baseline log run.
This poses a major obstacle in the evaluation of information from any
ETS log run on those wells.
The ETS measures the changes in metal mass by responding to phase
shifts in an induced magnetic field between two coils. It indicates
only possible total metal loss and therefore cannot differentiate
between interior and exterior casing damage.
It is difficult to place an accurate quantitative scale on the
log because of mill tolerances inherent to the casing manufacturing
process. Zero metal thickness is determined from an air reading,
allowing for calibration of the instrument. If casing sizes and
wei ghts are known prior to runni ng the ETS, an II average" reference
joint can be established by the log analyst. By using this reference
level as the value for nominal wall thickness, an approximate linear
scale can be applied to the log. The log displayed is linear with
respect to average wall thickness for uniform sections of casing
longer than the length of investigation, which is approximately the
distance measured between the exciter coil and the pick-up coil.
Magnetic permeability and electrical resistivity of the well
casing also affect the ETS log. Differential stresses placed on
casings can alter magnetic permeability with time and can thus affect
log response. Generally an increase in casing magnetic permeability
increases the response of the log and an increase in casing electrical
resistivity decreases log response.
With the mbdified ETS, it is possible to determine true wall
thickness, because this survey does not depend on casing magnetic
permeability or metal resistivity. Because the mid-frequency
measurement of this log is a function of both magnetic permeability
and inside diameter, processing the mid-frequency and high-frequency
data together yields a measurement of magnetic permeability. This
permeability value processed with the low-frequency phase-shift data
enables the interpreter to compute true wall thickness. Thus, the
multiple-coil, multiple-frequency approach enables measurement of
differential inside diameter, magnetic permeability and casing
thickness. This not only eliminates dependence on magnetic
permeability but also adds a sensitive inside diameter ~easurement to
the ETS.
COST
The cost of conducting an electromagnetic thickness survey is
dependant upon the many general pricing variables as outlined in
Section 7. The range of specific depth and logging charges as
determined by a survey of six major well logging companies in the
midcontinent area of the United States are listed in Table 14. Refer
to Table 7 for a listing of companies surveyed which perform this
service.
131
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TABLE 14. TYPICAL DEPTH AND LOGGING CHARGES FOR ELECTROMAGNETIC
THICKNESS SURVEYS
Depth Charge Low High
per foot $0.29 $0.30
minimum $580.00 $600.00
Logging Charge Low High
per foot $0.29 $0.30
minimum $580.00 $600.00
ADVANTAGES AND DISADVANTAGES
The ETS offers several advantages in mechanical integrity
testing. The primary advantage is that it offers the only method of
detecting corrosion or other defects on the outer string of a double
(concentric) string of casing. This could have great benefits in
wells which must utilize multiple casing strings, for there are no
other surveys available which can accomplish this.
There are several disadvantages to using the ETS in mechanical
integrity testing. Because of the limited resolution of the tool, the
smallest defect it can detect is approximately one inch in diameter.
Also, it cannot discriminate between inner wall and outer wall
defects. The PAS must be used in conjunction with the ETS to resolve
these two problems.
One of the other major disadvantages of the standard ETS is that
it is dependent on the magnetic and electrical properties of the
casing being surveyed. Therefore, it is difficult to positively
distinguish whether a log anomaly is due to a loss of metal from the
casing or to a change in casing properties. The availability of a
baseline log, run immediately after the installation of the well,
would alleviate this problem. However, many older wells have never
had a baseline log run, so evaluation of information from any ETS log
run in these wells is difficult. A modified ETS is available to
eliminate this problem, however it is offered by only one well
servicing contractor.
ETS logs cannot be run in tubing due to the large outside
diameter of the tools used to produce the log. Tubing must be removed
from the well prior to conducting this type of survey.
EXAMPLES
Figure 44 is a portion of the ETS log run in a well in the San
Juan Basin, New Mexico. A possible pit or hole is indicated at 735
132
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CASING WALL THICKNESS (INCHES)
.146 .209 .272 .335
700
800
I 1 I II J
REFERENCE
~ JOINT
.... _ !t EFLECTIO
/'
\ -
.....
....
'"
~ ,.,..
.cP
N
750
85-
Figure 44. Casing inspection log of a portion of a well in the San Juan Basin of New Mexico
(750-850 feet) (Edwards and Stroud, 1963).
CASING WALL THICKNESS (INCHES)
.152 .212 .272 .332
1850
..
~
- REFERENCE
JOINT
DEFLECTION
~ ~
=1--
=F-
.. ~
h
1900
1950
2000
Figure 45. Casing inspection log of a portion of a well in the San Juan Basin of New Mexico
(1,850-2,000 feet) (Edwards and Stroud, 1963).
133
-------
feet and probable extensive corrosion is evident from 820 to 850 feet.
A possible hole or pit can also be seen at 847 feet. As a result of
the evident extent of corrosion in this well, a new string of casing
was run and the well recomp1eted (Edwards and Stroud, 1963).
Figure 45, the log of a well in the same township as that
illustrated in Figure 44, indicates extensive corrosion in the
interval from 1100 to 2100 feet. A maximum metal loss of 42 percent
indicated in the interval from 1855 to 1862 feet. The character of
the log indicates extensive small pits or mottled type corrosion
throughout the logged interval (Edwards and Stroud, 1963).
Figure 46 illustrates the capability of the ETS log to detect
problems in concentric casing strings. This is an extreme case where
a 9 5/8" casing has parted completely and dropped down the hole behind
a string of 7" casing. The section of log between 4140 feet and 4170
feet is the phase shift corresponding to a single string of casing and
is identical to that found below 4250 feet (single string of 7"
casing). A high-resolution caliper survey run in the 7" casing
indicated the casing tube in good condition.
Figure 47 is an example of a rip in the casing wall of a well,
noted on both a pipe analysis log and an electromagnetic thickness
log. The pipe analysis log shows the beginning and end of the rip,
reacting at a point of change in the amount of metal which causes a
change in the flow pattern of the induced magnetic flux. In the
interval between the top and bottom of the rip, the damage is
consistent and the flux does not change appreciably. The
electromagnetic thickness log reacts to the total damaged area because
of the different physical principle involved in the measurement. The
two tools in combination clearly locate and define the anomaly,
whereas either one used alone could not do the job (Cuthbert and
Johnson, 1974).
134
-------
9%"CSG
I~I
PHASE SHIFT
--'-~
DEPTH 0°
4000'
400°
I
4200'
4100'
4300'
(A) ELECTROMAGNETIC THICKNESS GAUGE
(ETT-A) w/21.6" COIL SPACING
Figure 46. Field application of 26'6" coil spacing ETT -A sonde in concentric string of
7" x 9%" casing (Cotton et at, 1983).
135
-------
CASING n---
RIPPED II
1789' -1792~_-
------
---
-- "\800 -
---
PIPE ANALYSIS LOG
UPPER PAD ARRAY
TOTAL
DEFECTS
o
ELECTROMAGNETIC
THICKNESS LOG
PHASE SHIFT
180
Figure 47. Indications of a casing rip in pipe wall away from any collars
(Cuthbert and Johnson, 1974).
136
360
-------
REFERENCES
Cotton, W.J. Jr., I.S. Iliyan and G.A. Brown, 1983, Test results of a
corrosion logging technique using electronic thickness and pipe
analysis logging tools; Journal of Petroleum Technology, vol. 35, no.
4, pp. 801-808.
Cuthbert, J.F. and W.M. Johnson, Jr., 1974, New casing inspection
log; Paper presented at 49th Annual Meeting of SPE, October, 1974,
Houston, Texas, 12 pp.
Edwards, J.M. and S.G. Stroud, 1963, Casing Inspection Results in the
Rocky Mountain Area; Paper presented at Spring Meeting, Rocky Mountain
District, Division of Production, American Petroleum Institute,
Casper, Wyoming, April, 1963, 7 pp.
Smith, Glenn S., 1980, The ETT-C, an improved corrosion inspection
tool; Paper presented at 1980 AGA Operating Section Transmission
Conference, Salt Lake City, Utah, May. 1980, 8 pp.
Smolen, James J., 1976, PAT provisory interpretation guidelines;
Schlumberger Well .Services, Interpretation Development, Houston,
Texas, 9 pp.
Stroud, Stanley G. and Charles A. Fuller, 1962, New electromagnetic
inspection device permits improved casing corrosion evaluation;
Journal of Petroleum Technology. vol. 14, no.3, pp. 257-260.
137
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SECTION 12
CALI PER LOGGING
SYN, -SI:
Caliper loqging was intro1uced as a commercial w~ll ~ervice for
logg~ng o~en hoies in 338 (Hi!chle, 1968). The app11catlon of
caliper logging to cas d holes, where it is useful as a tool for
detennining the iechanica1 integrity of injection well or p~oduction
well casing or tubi~g, is somew~ It more recent. However, 11ttle
effort has been mad;:- to update t '-c 1 i terature regardi ng the more
modern applications ~f ~aliper lvgging. Several significant
refinements of the tc=hnique have resulted in caliper logging being
one of the most accurate means of locating defects in casing or
tubing.
When used in a cased hole, the caliper log is a continuous
profile of the casing or tubing's inside diameter with depth.
Cased-hole calipers can be used for several purposes, including:
1) locating breaks in parted casing or tubing;
2) locating distortions in casing due to partial collapse;
3) locating areas of internal corrosion;
4) locating leaks or holes in the pipe; and
5) locating paraffin deposits or mineral scaling present on the
inside of casing.
Calipers used in cased holes are of three general types -
mechanical, electronic, and acoustic. Mechanical calipers use
finger-like anns or feelers to contact and measure the inside surface
of casing or tubing, producing a continuous profile of the inside
diameter with depth. Two different varieties of mechanical calipers
are available - those with six or fewer anns (low-resolution calipers
generally used in open-hole applications) and those with from 20 to 64
anns (high-resolution calipers). Calipers with six or fewer anns can
generally be used in cased holes only to detennine the shape of the
casing in cross section, to detect major distortions in the diameter
of the casing. This is usef~l in mechanical integrity testing, as the
presence of a distorted casing may indicate casing damage in the fonn
138
-------
of splits or breaks. Calipers with from 20 to 64 arms can be used in
cased holes to detect minor casing anomalies, such as pitting and
small holes, and thus are better suited to mechanical integrity
testing of injection wells. These calipers can be used in tubing with
1 1/2" to 4" inside diameter or in casing with 4 1/2" to 13 3/8"
inside diameter. Tools available from well servicing contractors can
be used in wells with pressures and temperatures to 10,000 psi and
350°F respectively. Logging speeds of 90 to 100 feet per minute are
possible with the high-resolution mechanical caliper.
Electronic calipers use an electronic principle to measure the
inside diameter of casing. This type of caliper was introduced in
1966 specifically to complement the electromagnetic casing inspection
log (Edwards and Stroud, 1966). It is described in more detail in
Sections 10 and 11, which describe two different types of
electromagnetic casing inspection surveys.
The acoustic caliper log is produced by the travel-time dependent
rather than the amplitude-dependent output of the borehole televiewer
(Keys, 1981). The travel time of an acoustic pulse generated by the
downhole tool and reflected off of the casing wall is recorded,
prodiving an extremely high resolution log of hole diameter. This
method is discussed in greater detail in Section 14.
Because both electronic and acoustic calipers are discussed in
other sections of this report, only mechanical caliper logging will be
discussed here.
PRINCIPLES
The principle of a mechanical caliper log is very simple. This
log employs a tool with feeler arms which extend from the body of the
tool to contact the interior wall of whatever pipe the tool is being
run in (either tubing or casing). The feeler arms act as small
calipers, each measuring the inside diameter of the pipe at the point
at which it contacts the pipe1s inner surface. As the tool is run in
the well and the full length of pipe is surveyed, each feeler arm
produces a signal which is recorded at the surface. Taken in
combination, the measurements made simultaneously by all of the feeler
arms produce a representation of the full inside circumference of the
pipe. Compared against the expected inside diameter of the pipe as
installed in the well (to an accuracy specified by the American
Petroleum Institute for oilfield tubular goods), the log can show
areas where defects occur in the pipe. The recorded log indicates
either the actual amount or a percentage of remaining wall thickness
at every point along the tubing or casing.
EQUIPMENT
The construction details of mechanical caliper tools differ
depending upon the manufacturer or the well service contractor.
It is
139
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possible, however, to generalize some of the basics of equipment
design.
The mechanical caliper tool consists of a central shaft fitted
with from two to six hinged arms (low resolution type) or from 20 to
64 arms (high resolution type). In the form~r to~l, the c~ntral shaft
is enclosed by a rubber, oil-filled chamber 1n Wh1ch.the h1~ged arms
are connected to a potentiometer that measures chang1ng res1stance.
The arms fold against springs into the side of the shaft when fully
retracted, and rest against the inside of the casing when fully
extended.
In the high-resolution-type caliper the feelers, which are either
spring loaded or motor-driven, retract into the body of the shaft when
the tool is not in use, and extend to contact the inside of tubing or
the casing when the tool is in use.
Low-resolution calipers for use in cased holes are available in
sizes from 1 1/211 outside diameter to 4" outside diameter to measure
casing from 4" diameter to 60" diameter. Two-arm, three-arm,
four-arm, and six-arm calipers are available.
High-resolution calipers for use in tubing are available in
sizes from 1 112" outside diameter to 3 1/32" outside diameter to
measure tubi ng from 2" di ameter to 4" di ameter (Fi gure 48).
High-resolution calipers for use in casing are available in sizes from
3 5/8" outside diameter to 11 5/16" outside diameter to log 4 1/2"
diameter to 13 3/811 diameter casing (Figure 49). The number of feeler
arms on these tools increases with the diameter of the tool, from 20
to 30 feelers on the tubing caliper to 40 to 64 feelers on the casing
caliper. The width of the feeler arms is generally less than
one-tenth of an inch and the feeler tips are less than one-half inch
apart at the outside when extended. The feeler arm section is
generally in the middle of the tool. These tools are all rated
consistently at 10,000 psi and from 300°F to 350°F depending on the
manufacturer.
Most low-resolution calipers do not employ centralizers. They
are allowed to freely orient themselves and pass through all types of
casing deformities. On the other hand, high-resolution tools do
utilize centralizers to maintain the caliper tool in positive axial
alignment in the casing or tubing to ensure the accuracy of the
measurement. The centralizers are located above and below the section
of the tool containing the feeler arms.
An amplifier is located between the feeler arms and the upper
centralizer in the high-resolution tool. The amplifier boosts the
electrical signal generated by the movement of the feeler arms in
response to changes in inside diameter of the tubing or casing.
140
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,.
,
!
!
Sizes 0' l\Jbing Profile Calipers
~
0.0. of Number of Tool
Tubing Feelers Diameter
2" 20 1112'~
2'/'6" 20 1%"
2%" 26 1%"
21fe" 32 23/'6"
3%" 44 2'1/'6"
4" 44 3%2"
Figure 48. High resolution tubing caliper tool (Dialog, Inc. product literature).
141
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Size of Casing Profile Callpe~
0.0. of Number of Tool
Casing Feelers Diameter
4%"-6" 40 3%"
6%"-7%" 64 53fa'~
85fe" -9" ;- 64 7%"
9%" !,.r. 64 7%"
10314 " 64 8%"
113/4 " 64 99/16~'
133fa" 64 11%6"
Figunt 49..Hlgh NIOIution C88lng caliper tool (DIalog, Inc. product-inenduN).
142
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PROCEDURE
To produce a log with the low-resolution caliper tool, the tool
is lowered to the bottom of the well with the arms retracted (with the
exception of the bowspring-type caliper). When the tool reaches the
bottom of the well, the arms are released so that they contact the
wall of the well casing and the tool is pulled up the hole. As the
pressure from the arms on the central chamber changes with the varying
diameter of the casing, the potential drop across the potentiometer is
measured and recorded at the surface.
To produce a log with the high-resolution caliper tool, the tool
is lowered down the tubing or casing on a standard wire1ine with its
arms retracted. When the tool reaches the bottom of the survey depth
desired, the feeler arms and centa1izers are released by either a
spring-loaded or motor-driven mechanism and the tool is raised up
inside the well. As the tool is brought up the well, the caliper
feelers continuously contact the casing or tubing wall, measuring the
minimum and maximum diameter of the internal wall of the casing or
tubing. The arms are free to move independently to conform to the
condition of the casing wall, extending in places where the casing has
a large diameter (i.e. where corrosion has pitted the casing or where
holes in the casing exist), and retracting in places where the casing
has a smaller diameter (i.e. where scale has been deposited or where
the casing has partially collapsed). The large number of arms on the
high-resolution caliper ensures the detection of even very small
irregularities in the casing or tubing wall.
This tool .produces a log which is a record of variations in
casing or tubing diameter with depth. The tool can be closed and
reopened from the surface allowing for any number of log repeats.
This procedure allows repositioning of the tool for the detection of
casing defects that are even smaller than the distance between the
feeler ann tips.
The inside diameter of the tubing or casing in which the caliper
is run is determined by the feeler arm that extends the furthest from
the axis of the caliper tool. The movements of the individual arms of
the tool are converted to electrical signals. The feeler which
penetrates the greatest depth into any irregularity in the wall of the
tubing or casing generates the most intense electrical signal. The
signal is amplified within the tool. transmitted to the surface via
the wireline, and recorded on standard surface equipment.
The instruments used in the caliper log, both the downhole tool
and surface recording equipment, are calibrated before and after each
logging run. It is possible to obtain a fast, accurate record of
casing or tubing diameter with the high-resolution caliper. Logging
speeds of 90 to 100 feet per minute are reported (Dia-Log, Inc.,
product literature).
143
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INTERPRETATION
Interpretation of the tubing caliper 10g.is som~what differ~nt .
from that of the casing caliper log. The tub1ng ca11per log, Wh1Ch 1S
available from only one well service company, is a record of wall
penetration of tubing defects in percent (Dia-Log, Inc., product
literature). Nominal inside diameter thus equals zero percent wall
penetration, and nominal outside diameter is 100% wall pene~ration.
The tubing is graded on the log in 5% increments of the nom1na1 wall
thickness to show the maximum penetration or wall loss recorded. This
measurement is a function of American Petroleum Institute
specifications for new tubing, which allow the nominal outside
diameter to vary by + 0.031 inch and the nominal wall thickness to
vary by -12.5%. -
The casing caliper log (Dia-Log, Inc., product literature)
indicates remaining wall thickness in fractions of an inch. The
accuracy of the remaining wall thickness on this log is a function of
the American Petroleum Institute specifications for new casing, which
allow the nominal outside diameter to vary by ! 0.75%.
Another caliper log (Gearhart-Owens, Inc., product literature) is
a record of both minimum detected internal diameter, at a scale of
0.1" per chart division on the strip chart, and maximum detected
internal diameter, at a scale of 0.05" per chart division. The
minimum wall recording shows actual wall loss, while the maximum wall
recording is represented as remaining wall thickness, including any
buildup attributed to scale or other restrictions on the pipe's inside
surface (Figure 50).
COST
The cost of conducting a caliper survey is dependant upon the
many.g~neral pricing va~iab1es as outlined in Section 7. The range of
sp~c1f1C depth ~nd 10ggln~ ch~rges as.determined by a survey of six
maJor well 10gglng compan1es 1n the m1dcontinent area of the United
States are listed in Table 15. Refer to Table 7 for a listing of
companies which perform this service.
TABLE 15. TYPICAL DEPTH AND LOGGING CHARGES FOR CALIPER LOGGING
Depth Charge
per foot
minimum
Low
$0.23
$500.00
High
$0.33
$660.00
Logging Charge
per foot
minimum
$0.30
$580.00
$0.33
$660.00
144
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PIPE CROSS SECTION
\:.MINIMUM WALL MAXIMUM W~7LL
E (S,WS wall loss) (Includes bUildup)
COMPLET ~ '\.
@ ~~::~:::N ~
m ALL AROUND' -f~: -
~ ;l
E9 d' ;1.E.
~~~~~S~ON, I~.g; SI
AROUND t
@~~~OR - JIi .p. 'n ",: ::::1f
@ . j.
RESTRICTION ~ ~~ MU t.: i ! j
i:
- ,:: i"!
@ ~:~~'CTOON ,," , , t;
@ ~ !
HOLE, OR /'" i III "q
~~I~~~R i I ! ! n j
i
@~ ~,~~~.:',~R'- ...;.,., ........ "." Tn
SMALL, OUT' f
OF ROUND i : :: f tm
~ ::',
.
~
ill
X ::E
mROUND P
SMOOTH
LEG PIPE T OL
. i SIM
.....~!, "
~2i t
~~i -+
-=== =f
-
IPE,
BORE
OUTER WALL OF PIPE-I
Figure 50. Standard casing and casing anomalies recorded by a caliper logging tool
(Gearhart-Owens, Inc. product literature).
145
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ADVANTAGES AND DISADVANTAGES
The primary advantage of high-res~lut~on m~chanica~ ca1ip~r
logging in mechanical integrity determ1nat10n~ 1~ that 1t pr?v1des a
very accurate record of the condition of the 1ns1de of a st~1ng of
tubing or casing. High-resolution caliper logs can be run 1n.both
tubing and casing, at relatively high logging speeds. Mechan1cal.
calipers have several weaknesses. Perhaps the greatest weakness 1S
the inability of the tool to reveal the presence of small-diameter,
dri11-ho1e-like pits or holes in the casing or tubin~ (NL McCullough,
Inc., product literature). Such holes may escape be1ng located even
by high-resolution calipers, because the feeler a~s ar~ locat~d
approximately one-half inch apart. Unless the ca11per 1S reor1ented
and a repeat run made in the well, holes just smaller than one-half
inch in diameter may go unrecognized as the tool is raised up the
hole.
In addition, it is difficult to locate some vertical splits or
hairline cracks in casing because of the method in which the caliper
tool is operated. At least one well service company offers a tool to
detect splits in tubing or casing as an accessory to the caliper. The
split detector, which functions like a magnetic casing collar locator,
is designed specifically to detect and log vertical cracks or splits
in tubing or casing (Dia-Log, Inc., product literature). In practice,
the split detector is used to log going down the well, while the
caliper log is made going back up the well. This allows for a
complete inspection of both the wall thickness and casing splits in
one run of the tool string in the well.
In wells with tubing and packer completions, it is possible to
log the tubing independently of the casing. However, if it is desired
to log the casing in addition to the tubing, the tubing must be pulled
before the casing can be logged. This can be a lengthy process, and
it generally necessitates the installation of a new packer. The
high-resolution mechanical caliper is only available from a limited
number of well servicing companies.
EXAMPLES
Figure 51 i~lustrates a ~ubing profil~ caliper tool and the log
produced by runn1ng the tool 1n a well hav1ng a variety of mechanical
defects, including moderate corrosion pitting, holes and severe
corrosion pitting, and rod scores on the inside of the tubing. Tubing
joints are recognizable by their distinctive signal (roughly
corresponding to nominal outside tubing diameter). Baseline on the
log is nom~nal inside diameter; defe~ts on the inside of the tubing
are recogn1zed by departures from th1s baseline. Corrosion pitting
and holes are indicated by deflections to the left, while scale
b~i1dup or partial collapse would be indicated by deflections to the
r1ght. The results of a log pro~uced by a companion tool, the split
defector, are also included on F1gure 51. Log deflections due to two
vertical splits are shown.
146
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;;:;;;11
Ii
~
"0
u
~
"3
u
,. -T
E.mc
",.,.C
_M
M ...
Q
:~
Figure 51. Example of a tubing profile caliper (Dialog, Inc. product literature).
147
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Figure 52 illustrates a casing profile caliper tool and the log
produced by running the tool in another well, showing log response to
a variety of downhole conditions. A casing weight change, illustrated
by a shift in the baseline on the log, is indicated at 250 feet. At
1400 feet, a hole and severe corrosion pitting is indicated by an
intense concentration of log deflections. Drill pipe wear at 2600
feet; split, parted and damaged casing at 3300 feet, 4400 feet and
7000 feet respectively, and perforations at 9600 feet also produce
recognizeable log deflections.
148
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Figure 52. Example of a casing profile caliper (Dialog, Inc. product literature).
149
-------
REFERENCES
Dia-Log, Inc., product literature, Houston, Texas.
Edwards, J.M. and S.G. Stroud, 1966, New electronic casing caliper
log introduced for corrosion detection; Journal of Petroleum
Technology, vol. 18, no. 8, pp. 933-938.
Gearhart-Owens Inc., product literature, Houston, Texas.
Hi1chie, D.W., 1968, Caliper logging - theory and practice; The Log
Analyst, vol. 9, no. 1, pp. 3-12.
Keys, W.S., 1981, Borehole geophysics in geothermal exploration;
Developments in Geophysical Exploration Methods, A.A. Fitch,
editor; Applied Science Publishers, Ltd., Essex, Eng1~nd, pp.
239-268.
NL McCullough, Inc., product literature, Houston, Texas.
150
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SECTION 13
BOREHOLE TELEVISION
SYNOPSIS
The borehole television (TV) survey provides a continuous
photographic log of the inside surface of well casing. The borehole
TV survey reports on the condition of the casing as viewed from the
inside; the condition of the outside casing surface and the condition
of the cement behind the casing cannot be determined from this log.
When logging with a borehole TV system, a miniature television
camera is lowered into the well. A light source illuminates the
inside of the casing and the resulting television picture is
transmitted back up to the surface for recording and viewing. As the
camera is lowered into the well, a continuous photographic log is
obtained. The camera may be slowed or stopped at any depth and the
focal length changed on the lens to magnify a particular problem for
close examination.
PRINCIPLES
The principle behind the borehole TV survey is similar to that of
a closed circuit TV system. An object reflects light rays back toward
the camera and the reflected rays of light enter a lens. As the rays
of light pass through the lens, they are focused onto a light
sensitive plate called a charge-coupled device (or CCO). An iris
located in the lens adjusts the amount of light that strikes the CCO.
The CCO chip onto which the light rays are focused is scanned by
a microscopic network of horizontal and vertical lines. The scan
determines the color as well as the light intensity that strikes the
area and sends a corresponding signal to an amplifier for transmission
to the surface (Cheshire, 1982).
EQUIPMENT
The borehole TV logging tool consists of a miniature closed
circuit TV camera, a light source and related electronic circuitry.
Cameras can transmit either black and white or color pictures back to
the surface. The size of the camera ranges from 2 3/4 inches to 4 7/8
inches in diameter, and from 18 inches to 24 inches in length
(exclusive of the light source). Centralizers are standard equipment
on all camera housings, allowing the cameras to be run in 3-inch to
151
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36- inch tubing )r casing. Standard lenses and.lighting ar~ used for
a maximum hole ciameter of approximately 9 3/4 1nches. Opt10nal
lenses and highf~ intensity lighting are needed for larger holes.
The lighting source is perhaps the most import~nt ~iece of
equipment in borehole TV logging. Without proper 11ght~ng.(and clear
water in the well}, it is impossibl~ to photogr~phllthe 1ns1de ~urface
of the well casing. Improper light1ng result~ 1n bounce back ?r
reflection of the light source caused by turb1d water or reflect10n
off the well casing surface, thus IIblindingll the camera due to
excessive light. Most color cameras are balanced acco~di~g to the
expected or recommended lighting requir~ents. The ma~or1ty of color
lighting systems consist of a tungsten 11ght.source wh1le most black
and white cameras utilize a quartz-halogen 11ght source. There are a
few exotic lighting sources available, but their use is limited at
this time.
Light sources can either be located in an annular ring around the
camera lens or hung several inches below the camera lens. Both
light-source locations offer advantages and disadvantages, the
discussion of which is beyond the scope of this report.
Camera housings are usually made of stainless steel and can be
constructed to exceed 25,000 psi. However, the operational depth of
the cameras is limited by several factors, primarily the lighting
source. Standard lighting sources frequently implode (or are crushed)
at excessive depths. In addition, the power requirements for the
light source limit the operation of the cameras to approximately 8,000
feet due to the fact that the electrical resistance of the cable is
too great below this depth. The cable resistance also limits the
depth the signal from the camera can be transmitted back to the
surface. Thus. for all practical purposes, camera operation is
limited to depths of 8.000 feet and most systems will not operate to
this depth (Davis and Fleniken, 1980).
Borehole temperature also limits the camera depth. A temperature
of approximately 175°F is generally the maximum operating temperature
(Mullins, 1966). Ice packs and thermal bottles can extend that limit,
but only for a short period of time (1-2 hours).
Surface support equipment is elaborate. The signal from the
camera is sent to the surface via a 12, 16 or 32- conductor cable not
fou~d on a s~andard logging truck. At the surface, the signal is
Spl1t; one slgnal goes to a Video Cassette Recorder (VCR) the other
to a TV monito~. The VCR is generally a standard. high-q~ality video
recorder on Wh1Ch the camera signal is recorded so that a permanent
record of the log exists and can be played back at a later date.
When the camera is in operation, the conductor cable passes over
a measuring sheave. The sheave sends a depth indicator signal to the
VCR and the monitor. In surveying deep wells. a sophisticated
152
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measuring sheave that will correct for the stretch potential of the
cable may be used. Depth readings are overlayed and recorded
simultaneously with the camera signal. Other data such as the date or
job number can also be recorded by overlaying the data on the signal.
An audio track is usually available for audio dubbing either during
or after the logging operation.
The TV monitor is a standard TV screen. It is used
the quality of the log as well as the survey itself. On
equipped, the tool can be slowed, stopped, re-focused or
view an area of particular interest.
to monitor
systems so
adjusted to
PROCEDURES
To run a borehole TV survey, injection into the well must be
stopped and the injection tubing removed from the well. The well then
must be thoroughly flushed with a clear fluid. This step is very
important, because the quality of the log hinges on the quality of the
flushing job. The well is then shut-in for an hour or two to allow
the fluid to stabilize and particulate matter to settle (Davis and
Fleniken, 1980).
If flushing the well fails to clear the turbidity from the water,
the well fluid may be treated with a flocculent additive. One gallon
of feric floc and one gallon of hot lime for each 1,000 gallons of
water contained in the well has been successfully used to flocculate
and clear wells. The solution is mixed at the surface and injected
into the well. The well then must stand for 12 to 24 hours to allow
for settlement of the floc (Jensen and Ray, 1965).
Once the fluid in the well is of an acceptable clarity, the
camera is lowered into the well on a wireline to the starting point of
the survey. The system is checked and the depth indicator is
synchronized. As the log begins, the camera is lowered down into the
well. Logging speed varies throughout the survey because the camera
can be stopped or slowed at any point so that a more detailed view of
the casing can be gained. Logging speeds generally range from 0-25
feet per minute, but little is seen at the higher speed. The
resulting VCR tape can also be slowed while being played back at a
later date.
If the well has a layer of oil floating on top of the water
standing in the well, the camera lens is usually coated with a
detergent paste. As the camera passes through the floating oil, the
detergent prevents the oil from fouling the lens. The detergent
coating washes off as the camera is run up and down in the water below
the oil layer (Jensen and Ray, 1965).
153
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INTERPRETATION
The ;nterpretat;on of all photog~ap~;c logs ;s d~ff;cult to the
untra;ned v;ewer. The low angle of vlewlng and the wlde-angle lenses
that are typ;cally used requ;re a per;od of or;entat;on (Huber,
1982 ).
After the survey ;s run, the log ;s presented on a TV mon;tor
screen and can be slowed or stopped by controll;ng the VCR playback
un;t. Because the depth of the camera ;s always shown on the screen
along w;th the ;mage, depths to problem areas are known. Cas;ng
collar locat;ons are eas;ly seen ;n most wells and are used for
correlat;ng depth and locat;on of problems.
Turb;d or murky water w;ll ;nh;b;t accurate ;nterpretat;on as
w;ll scale on the ;ns;de of the cas;ng. Turb;d water w;ll reflect
1; ght rays back to the camera and cause the camera to be "bl; nded" by
excess reflected l;ght. The ;ns;de surface of the cas;ng can also
cause camera bl;nd;ng by reflect;ng l;ght rays from an ;mproperly
pos;t;oned l;ght source (Dav;s and Flen;ken, 1980).
COST
Dav;s and Flen;ken (1980) have est;mated that costs for borehole
TV logg;ng are ;n the same order of magn;tude as other types of
geophys;cal lO9g;ng. Table 16 conta;ns a pr;ce l;st show;ng the
average cost ;n the Un;ted States ;n 1980 dollars.
TABLE 16. TYPICAL CHARGES ASSOCIATED WITH BOREHOLE TELEVISION SURVEYS
Equ;pment Charge
8 hour m;n;mum
Overt;me
$750.00
250.00/hr.
Depth Charge
o - 1000 ft.
1000 - 2000 ft.
2000 - 3000 ft.
Below 3000 ft.
M;n;mum
$0. 301ft.
0.40/ft.
0.60/ft.
V;deo Tapes
1 12 II 2 hr.
3/4" 60 m;n.
$75.00
100.00
Standby
W;th crews and equ;pment
W; thout crews
$250.00/hr.
50.00/hr.
Mn eage
Porta 1 to portal
0.80/m; .
154
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As Davis and Fleniken (1980) note, other charges for the rig and
auxiliary equipment and filtration equipment, pumps and trucking to
process the water in the well to an acceptable clarity, are also
associated with television loggin9. These costs may be four to five
times the costs of the logging equipment. Davis and Fleniken (1980)
estimate that, with proper equipment scheduling and preplanning, a
4000 foot well can be logged for about $6000.
ADVANTAGES AND DISADVANTAGES
There are several distinct advantages in using a borehole TV
survey. The most obvious advantage is the fact that a first-hand view
of the problem is obtained from the log. Visual inspection
facilitates the understanding of the problem and subsequent remedial
work. Also, because the log is recorded on a video tape, it can be
played back at a later date or compared with another TV surveyor
other logs made at an earlier date. Photographs of any problem areas
can be taken from the TV monitor by a polaroid camera or a 35 mm
camera for detailed study or documentation.
The biggest disadvantage of borehole TV logging is that the
injection tubing must be removed from the well so that direct visual
contact with the inside surface of the casing is obtained.
Another problem with the use of borehole TV and other
photographic methods is that the fluid in the well must be kept
relatively clear. A five-inch casing holds approximately one gallon
of fluid per foot of casing. Proper flushing techniques may require 2
to 3 times the well.s volume of good quality fluid (usually water) to
be circulated in or injected into the well prior to logging.
Another disadvantage to photographic logging is the temperature
restriction imposed by either the film or the equipment. Also, the
borehole TV survey must be run by a specialized contractor and the
equipment is not readily available for logging injection wells in all
areas of the country. This may preclude the use of borehole TV
logging in some areas.
All photographic methods only report on the condition of the
inside surface of the casing and a leak may not be obvious in corroded
casing. No method of determining channeling or fluid migration behind
the casing is available.
EXAMPLES
Figures 53 through 58 (from Davis and Fleniken, 1980) illustrate
various downhole problems in wells. Figures 53 through 56 are a
series of photographs of the borehole TV monitor from the logging of a
single well, showing a progression of well casing damage; Figures 57
and 58 are from logs of two other wells. As these figures illustrate,
it is possible to visually recognize a wide variety of problems, from
155
-------
Figure 53. Downhole picture of cracked casing (Davis and Fleniken, 1980).
Figure 54. Downhole picture of casing damaged during a fishing job
(Davis and Fleniken, 1980)
156
-------
Figure 55. Downhole picture of damaged casing and resulting sidetrack
(Davis and Fleniken, 1980).
Figure 56. Downhole picture of damaged casing and resulting sidetrack at different depth
(Davis and Fleniken, 1980).
157
-------
Figure 57. Downhole picture of separated casing (Davis and Fleniken, 1980).
"
Figure 58. Downhole picture of separated tubing inside screen (Davis and Fleniken, 1980).
158
-------
split, cracked or otherwise damaged casing to separated casing or
tubing. On each photograph of the borehole TV monitor appears the
depth that the downhole camera occupies in the well.
159
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REFERENCES
Cheshire, Davis, 1982, The video manual; Van Nostrand Reinhold Co.,
pp. 16-23.
Davis, Ken E. and John A. F1eniken, 1980, Visual logging for
inspection and troubleshooting; Paper presented at 55th Annual Fall
Technical Conference SPE AIME, paper number 9338, September 1980,
10 pp.
Huber, W.F., 1982, The use of television in monitoring applications,
Proceedings of the Second National Symposium on Aquifer Restoration
and Ground-Water Monitoring, National Water Well Association,
Worthington, Ohio, pp. 285-286.
Jensen, Owen F. and William Ray, 1965, Photographic evaluation of
water wells; Log Analysts, vol. 5, no. 4, 12 pp.
Mullins, J.E., 1966, New tool takes photos in oil and mud-filled
well; Wor1 d Oil, vol. 164, no. 6, 4 pp.
160
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SECTION 14
BOREHOLE TELEVIEWER
SYNOPSIS
The acoustic or borehole televiewer (BHTV) was developed and
patented in 1966 (Zemanek, et a1., 1969) and has been modified to suit
several specific purposes since then. The initial purpose for which
BHTV was developed was the inspection of open boreholes to locate
fractured zones in potential hydrocarbon reservoirs. The BHTV has
since been successfully used to solve a variety of problems related to
both open hole and cased hole inspection, including:
- inspection of open boreholes for vuggy porosity or fractures,
- providing a micro-caliper of borehole and casing anomalies,
- determining the dip of fractures or bedding planes,
- detecting thin, laminated shale and sand sequences, and
- inspecting casing and tubing for splits, perforations,
deterioration, or collapse.
The BHTV utilizes high-frequency acoustic energy to scan and
provide an image of the inside surface of either an open borehole or a
cased well. The image is a representation of the borehole or casing
wall as if it were split vertically and laid out flat. With the BHTV,
borehole irregularities or casing defects are located simply because
they are visible on the log; log interpretation in the usual sense is
not performed, but experience is needed for correct interpretation.
Changes in image intensity, as displayed on an oscilloscope at the
surface, indicate irregularities. In an open hole, the orientation
of these irregularities can be determined; in cased holes, the
orientation is not known but the features can still be recorded and
studied.
Casing can be inspected with BHTV in considerably greater detail
than is presently possible using most other logging tools. The BHTV
is able to resolve features as small as 1/32-inch in boreholes filled
with water, oil, or drilling mud. In conjunction with present-day
computer-enhanced signal processing, BHTV provides a very useful tool
in inspecting casing or tubing for the purpose of determining the
mechanical integrity of an injection well.
161
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PRINCIPLES
The BHTV employs high-frequency acoustic ene~gy to pr?be the.
inner surface of the casing in a well. A sma11-d1ameter p1~zoe1ectr1c
transducer in the down-hole 10ggin9 tool (Figure 59) transm1ts bursts
of acoustic energy as it is rotated within the tool at three.
revolutions per second. The dominant frequency of the e~erg~ 1S about
1.3 megahertz (Wiley, 1980; Keys, 1980). The energy, Wh1~h 1S .
transmitted at a rate of 1200 to 1600 pulses per second, 1S conf1ned
to a very narrow beam which is directed toward the casing wall. A
portion of the energy is reflected by the wall back toward the
transducer which also serves as a receiver. The transducer converts
the reflected acoustic energy pulses into electrical signals, which
are utilized in producing the BHTV log. The combination of transducer
rotation with the continuous vertical movement of the logging tool as
it is pulled up the borehole results in a continuous log of the
borehole being surveyed (Zemanek, et a1., 1970).
The amount of energy reflected by the casing wall is a function
of the physical properties of the wall surface. As Zemanek et a1.
(1969) observed, a smooth surface will reflect energy better than a
rough surface, a hard surface better than a soft surface, and a
surface perpendicular to the transducer (at the time it
transmits/receives the acoustic energy) better than one that is at
some other angle. In general, any irregularities on the casing wall
surface will reduce the amplitude of the reflected signal.
The signals representing both the amplitude and the travel time
of the reflected acoustic energy are transmitted to the surface via
the logging cable; the amplitude signal is displayed on an
oscilloscope. The BHTV obtains !pprOximate1y 485 data points per
transducer rotation, and 1.75x10 data points per foot of borehole
surveyed at a logging speed of five feet per minute (Wiley, 1980).
Each rotation of the transducer is dis1ayed as a horizontal sweep on
the oscilloscope. The individual sweeps, which begin on the left hand
side of the oscilloscope face, are triggered by a magnetic pickup
(cased hole applications on1y--in an open hole, sweeps are triggered
by a flux-gate magnetometer, which senses magnetic north and thus
provides a means of determining log orientation). Each time a
magnetic signal occurs, the electronic beam within the oscilloscope is
returned quickly to the left side of the screen and sweeps across to
the right side. Depth information is provided by a reading from the
logging cable measuring sheave (Wiley, 1980). The result of the
combination of all this information is an image of the casing wall
that makes it appear as though the casing were split vertically and
laid out flat. Because the entire 3600 of the casing wall are
scanned, the image produced on the oscilloscope is a true reproduction
of the casing wall (Zemanek, et a1., 1969). The actual BHTV log is
made by taking a series of photographs of the image on the
oscilloscope face.
162
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....
aI
Co)
Piezoelectric
Transducer
Retrace
Camera
-r-I rI~,:e'ol
- - - Generator
---
-~~
-- ,
- ,
~
Figure 59. Block diagram of a borehole televiewer logging system (Zemanek et aI., 1969).
-------
In addition to displaying and recordi~g sig~al amplitude, the
BHTV records signal travel time. T~avel t1me.(t1me bet~een . .
transmitting and receiving pulses) 1S a funct10~ of.ca~lng d1am!ter,
uniform travel time throughout a section of c~sln~ 1~d1cates un1f~rm
casing diameter, while variations in travel ~lme 1nd1cat~ aberrat10ns
in casing diameter. The preciseness with Wh1Ch travel t1me can be
measured by the BHTV allows the creation of an ext~em~ly accura~e
acoustic caliper log, which compliments t~e acoust1~ 1mage and 1S very
helpful in interpreting the nature of cas1ng anomal1es (Schaller, et
al.,1972).
EQUIPMENT
The original BHTV downhole tool, as described by Zemanek et al.
(1969) is depicted in Figure 60. It consists of 1/2-inch diameter
ceramic piezoelectric transducer, a flux-gate magnetometer, and a
motor that rotates the transducer and magnetometer within the tool
about the vertical axis. The magnetometer, which produces a pulse
indicating the orientation of the tool each time it rotates past
magnetic north. is not utilized in cased-hole applications because the
casing severely attenuates the earth's magnetic field. A magnetic
pickup replaces the magnetometer in cased-hole applications. (Wiley.
1980 ) .
The tool described by Zemanek et al. (1969) is 3 3/8 inches in
diameter and 11 feet long, and includes four bow-spring centralizers
at the top and bottom to keep the tool centered in the casing. The
tool is suited for use in wells as small as 5.5 inches in diameter.
Continuous operation of this tool is possible at temperatures up to
300°F; maximum operating pressure is 15,000 psi. The temperature
limit is imposed primarily by the electronic components of the
downhole tool. A modified model of this tool, developed by the U.S.
Geological Survey for use in geothermal wells, has been successfully
operated at temperatures of 500°F (Keys, 1980).
Glenn et a1. (1971) describe a slim version of the BHTV tool
which is only 1 3/4 inches in diameter. This tool has been used
through 2-inch tubing and even through standard 1 25/32-inch seating
nipples to log open hole and casing below tubing as small as 3" in
diamet~r. The slim BHTV is longer, at 15 feet in length, but is
essent1a11y the same tool as the larger model and performance is
similar, though resolution suffers somewhat a~ a result of
miniaturization (Glenn et a1., 1971).
Both tools described above operate on multiconductor (4 or 7
conductor) logging cable. The cable supplies power to the downhole
tool and also conducts the signal generated by the tool to surface
equi~ment. where i~ is processed and recorded. The surface equipment
cons1~ts of ~n osc1110scope on which the image produced by the
scan~lng act10n of the downhole tool is displayed, a camera or
cont1nuous chart recorder to record the image displayed on the
164
-------
Figure 60. Assembled borehole televiewer logging tool (Zemanek et aI., 1969).
165
-------
oscilloscope and the necessary electronic circuitry to control th~
tool from the surface. The record may also be recorded on magnet1c
tape for later playback and image enhancement.
PROCEDURES
The BHTV log is made as the tool is p~l~ed up the well; the.
result is a continuous record of well cond1t10ns. Because the tool 1S
moved vertically simultaneously with the rotation of the transducer
within the tool, a continuous log of the casing wall is produced.
Logging speed is normally from 5 to 6 feet per minute at the expanded
scale necessary to resolve casing leaks.
For the BHTV to be run in an injection well, the well must first
be taken out of service to accommodate the logging equipment. In an
injection well utilizing a tubing and packer completion, the tubing
must be removed to allow the BHTV to probe the casing wall. For the
BHTV to operate efficiently, it is necessary to have some type of
liquid present in the well. Because the BHTV is an acoustic device,
it performs equally well in clear water, salt-saturated brine, crude
oil, or drilling mud, though with the latter the quality of the log
obtained is diminished somewhat (Zemanek et al., 1970).
When the BHTV is used to survey casing, the first pass is usually
made at a reconnaissance gain setting. At this gain, casing collars
and joints will be visible on the log. If any anomalies other than
those due to casing collars and joints are observed, the casing is
resurveyed at different gains to optimize the identification of the
anomaly.
INTERPRETATION
As the various conditions of the inside of the casing are
surveyed, they are imaged on the oscilloscope and on photographic
film, which becomes the permanent log of the well. Whenever a smooth,
hard surface normal to the transducer is scanned, the reflected
signals will be of a uniform amplitude that, in turn, will produce
uniform intensity traces on the oscilloscope; the image will thus
consist of only bright traces. However, when an irregular portion of
the casing, such as a casing collar or joint, a split, a perforation,
or an area of deterioration or collapse is surveyed, the amplitude of
the reflected signal decreases, causing the intensity of the
oscilloscope traces to decrease. The result is a dark trace of low
reflectivity on both the oscilloscope and on the photographic image.
This visual comparison of casing wall image intensity at various
points within the well is the only interpretation necessary with the
BHTV.
A typical photographic image size is 2 1/2 inches (vertical scale
of the log. which corresponds to well depth) by 2 inches (horizontal
166
-------
scale of th~ log, which corresponds to the azimuth of the casing
wall). A~ lnterva~ of 10 feet or less is represented on the vertical
sca~e, whl1e the clrcumference of the casing is represented on the
horlzonta1 scale (W.S. Keys, personal communication, 1983).
Even though the quality of the photographic image is normally
very good, the data presented are obviously quite compressed. Thus,
in order to enhance the ability of the BHTV to resolve small features,
improved methods of handling and displaying the data have been
developed. Keys (1980) reports that the u.s. Geological Survey has
developed a system for recording the BHTV signal on magnetic tape.
Playback of the data recorded in this manner provides the opportunity
to improve the quality of the BHTV log. Jage1er (1980) describes a
method for taping field data in analog form to allow reprocessing to
enhance image quality. This technique allows replaying of the data at
any gain or televiewer setting. Digitizing of the analog data to
assist in further enhancment of image quality is also possible using
this technique. Pasternack and Goodwill (1983) describe the methods
for and applications of digital BHTV logging.
Resolution of the BHTV log is a function of the characteristics
of the oscilloscope, the photographic film, the logging speed, the
type of the fluid in the well, and the various electronic parameters.
The characteristics of the oscilloscope and photographic film are
fixed, for all practical purposes. Log resolution is greater with
slower logging speed, and is better in water or other homogeneous
fluids than in heavy drilling mud or in a liquid with entrained gas.
In a 6" casing filled with water, features as small as 1/32-inch wide
can be recognized (Zemamek et al., 1970) The adjustment of the
various electronic parameters, especially the gain setting of the
receiving amplifier, is perhaps the most critical factor in image
resolution with the BHTV; this is done at the discretion of the
operating engineer. In general, lower gain will emphasize the smaller
irregularities in the casing being surveyed. Higher gain settings
tend ~ "burn out" the smaller defects and thus put the emphasis on
the larger anomalies (Schaller, et al., 1972). If adjustments are
improperly done, the resolution may not be adequate ~ recognize small
casing defects. The technique described by Jaegeler (1980) above
eliminates operator control of instrument settings, and thus allows
for optimal resolution.
COST
At the time of writing of this report, only one service
contractor offered BHTV as a commercial logging service. Fees charged
for the BHTV service, in 1982 dollars, are found in Table 17.
Additional costs which may be incurred as a result of contracting
for a BHTV survey include the cost of renting a logging truck,
operator travel expenses, parts equipment shipping, and living
expenses. It is estimated that the cost for logging a 4000-foot
167
-------
injection well would be in the range of $4500 to $~OOO, t~ou~h t~e
great number of variables involved could cause a w1de var~at10n 1n the
range of costs for this service (J. West, person~l commu~lcation,
1983). This cost is competitive with other 10gg1ng serV1ces.
TABLE 17. TYPICAL CHARGES ASSOCIATED WITH BOREHOLE TELEVIEWER SURVEYS
In-transit time
First operator at $50.00/hr.
Second operator at $30.00/hr.
Stand by time
First operator at $55.00/hr.
Second operator at $30.00/hr.
Logging, Maintenance or Service time
First operator at $62.00/hr.
Second operator at $37.50/hr.
ADVANTAGES AND DISADVANTAGES
The BHTV offers several distinct advantages over other cased-hole
logging methods used in the location of casing defects. The primary
advantage is that the BHTV provides a true representation of the
casing in the form of an image that can be easily recognized as that
of the casing's inner wall. Little if any true log interpretation
must be performed because the BHTV log is a straightforward visual log
of downhole conditions. However, experience with this type of log is
necessary for correct interpretation. The log can be a simple
photographic record or a videotape record which can be replayed at any
time. While the borehole television (Section 13) offers much the same
service (providing a visual image rather than an acoustic image), the
BHTV offers advantages over these optical devices. It is able to
operate in less favorable environments (higher temperatures and
pressures; wells filled with nearly any homogeneous liquid) and it is
available in smaller diameter tool sizes to fit down smaller wells. In
addition, the casing wall does not have to be clean for a BHTV survey
to be run. Other advantages include the potential availability of new
techniques that allow for analog taping of BHTV data and subsequent
digitization, leading to enhancement of the BHTV data and improved
imaging.
As with other logging techniques, the BHTV survey requires that
the well be taken out of service and the injection tubing pulled in
order for the survey to be performed. This may result in significant
down time for the well.
168
-------
While the BHTV survey is competitive on a cost basis with other
cased hole logging techniques, it is at present only offered through
one specialized service company. This greatly limits the availability
of the service to injection well operators. A related problem is that
while the BHTV survey has been utilized extensively in open hole
applications (particularly research-oriented work involving evaluation
of fractures), it has seen limited application in cas~ holes.
EXAMPLES
Figure 61, from Zemanek et a1., (1969) illustrates the use of
BHTV for locating and determining the exact size of a hole in casing
that has burst. The first log, on the right, was run at a
reconnaissance gain setting such that even small irregularities were
located. The second log from the right was a log rerun at a higher
gain to locate major defects. The third log from the right was a
re-run to preserve a one-to-one relationship between the vertical and
horizontal scales. Thus, the exact shape of the defect is as depicted
on this log. This is confirmed by a photograph of the casing shown on
the extreme left.
Figure 62, also from Zemanek et a1., (1969) is a BHTV 109 run in
a perforated section of casing. The vertical scale of the log on the
left is compressed with respect to the horizontal scale (casing
circumference). This is the normal depth scale for logging, however
at this scale the perforations appear distorted. The depth scale on
the log on the right has a one-to-one relationship with the horizontal
scale. The perforations take on their normal circular appearance.
169
-------
....
......
o
o
--
, -
~,
-... - ~.
1 '
.' ,
.
2'
. ,
"
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,- -
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3'
l.&-
, "
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~ -- ----
--- - ---
....-
4'
"-
-----
-----
--a..
-.---------
-- -.- ----
- -- - - - -
--
~- - - - -
---
- - -
5'
X16
X 16
X 1
Figure 61. Borehole televiewer casing inspection logs of a casing blowout (Zemanek et aI., 1969).
-------
2605
2608
-
-
-
.:.
.
..
-
-
-
...
'-
-
~
~
..
.
--
p.
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2608
2611
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~K
261411-:
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~----=-"'..
:--.~
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Figure 62. Borehole televiewer casing inspection logs of perforations (Zemanek et at, 1969).
171
-------
REFERENCES
Glenn, E.E., W.F. Baldwin, V.R. Slover, M.U. Strubhar and J. Zemanek,
1971, New borehole televiewer can be run through tubing; World Oil,
vol. 172, no. 1, 3 pp.
Jage1er, A.H., 1980, New well logging tools improve formation
evaluation; World Oil, vol. 190, no. 4, 8 pp.
Keys, W.S., 1980, The application of the acoustic televiewer to the
characterization of hydraulic fractures in geothermal wells;
Proceedings of the Geothermal Reservoir Well Stimulation Symposium,
San Francisco, California, pp. 176-202.
Pasternack, E.S. and W.R. Goodwill, 1983, Applications of digital
borehole televiewer logging; SPWLA Twenty-fourth Annual Logging
Symposium, June, 1983, 12 pp.
Schaller, Herman E., Robert Kilpatrick and Robert Stratton, 1972, The
acoustiviewer - a new method for inspection of down-hole tubular
goods; Paper presented at 47th Annual Fall Meeting of the SPE-AIME,
paper number 4000, October 8-11, 1972, San Antonio, Texas, 8 pp.
Wiley, Ralph, 1980, Borehole televiewer-revisited; SPWLA Twenty-first
Annual Logging Symposium, July, 1980, 16 pp.
Zemanek, J., R.L. Caldwell, E.E. Glenn, Jr., S.V. Holcomb, L.J. Norton
and A.J.D. Straus, 1969, The borehole televiewer - a new logging
concept for fracture location and other types of borehole inspection;
Journal of Petroleum Technology, vol. 21, no. 6, pp. 762-774.
Zemanek, J., E.E. Glenn, L.J. Norton, and R.L. Caldwell) 1970
Formation evaluation by inspection with the borehole te1eview~r;
Geophysics, vol. 35, no. 2, pp. 254-269.
172
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SECTION 15
FLOWMETER SURVEYS
SYNOPSIS
A flowmeter survey is made by using a downhole tool which
measures the rate of flow of borehole fluids. In injection wells,
f10wmeters may be used to help determine the location of leaks in the
casing, tubing, packer or plug. The survey is conducted during
injection of fluids by using small diameter tools which can be used in
tubing as small as two inches. Three different types of f10wmeters --
packer, continuous and fu11bore -- are available for differing flow
rates and fluid conditions.
PRINCIPLES
A flowmeter is a downhole logging device which is used to measure
the rate of flow of borehole fluids (Ransom, 1975). A flowmeter
survey measures the rate of fluid flow at any desired point in the
well and helps determine the direction (up or down) of fluid movement.
In injection wells, flowmeter surveys may be used to help locate leaks
in the casing, tubing, plugs or packers. Flowmeter surveys only
indicate the amount of fluid which is leaving the borehole at
specified intervals and cannot be used to determine fluid flow behind
the casing or within the formation (Warner and Lehr, 1977).
Flowmeter surveys may be run in the tubing, casing or in an open
hole with a variety of different types of flowmeter tools. Regardless
of the differences in tool types, f10wmeters or spinners operate on
basically the same principle. The downhole part of the tool contains
an impeller inside a protective housing which is rotated by the motion
of borehole fluid past the blades (Ransom, 1975) (Figure 63). As the
spinner rotates, electrical pulses are sent up the cable to be
recorded at the surface. The number of pulses is directly
proportional to the average velocity of fluid passing through the tool
(Syms et a1., 1982). With the proper hole size information, the
velocity can be converted to barrels per day or recorded as a
percentage of the total fiow (Bird and Bullard, 1961).
When injection rates are held constant, the velocity of the fluid
is proportional to the diameter of the casing, tubing or borehole.
When the cross sectional area either is known (such as for casing or
tubing) or can be determined with a caliper 109 (for open boreholes),
points and rate of fluid exit can be determined.
173
-------
-
CAllE CONOUCTOR
- --
- - UIiNET
~ PIC~UP COil
/ SPINNER
1
IEll CASI Nii
~
Figure 63. Diagram showing parts of a flowmeter (Schlumberger Services Catalog, 1978).
174
-------
EQUIPMENT
There are three basic types of flowmeters: packer, continuous
and fullbore. For best results, all flowmeters should be centered in
the well by bowsprings or similar devices. A packer flowmeter is a
flowmeter which uses an inflatable packer to restrict flow around the
tool and channel all fluid flow in the well by the impeller in the
flowmeter (Figure 64). Because they channelize the flow, packer
flowmeters are suitable for low flow rates. Packer flowmeters are
available in a range of sizes which will fit into tubing as small as 2
inches in diameter, with packers that will seal a hole as large as 9
5/8 inches in diameter. Because of problems with maintaining the
packer seal, this device is not as commonly used as other types.
Continuous flowmeters are the most commonly used flowmeter
device. Figure 65 shows two different spinner configurations common
in continuous flowmeters. Continuous flowmeters range in diameter
from 1 5/8 inches to 5 inches and are typically rated to withstand
pressures up to 15,000 psi temperatures to 350°F. Continuous
flowmeters are generally better suited for higher flow rates than
packer flowmeters. The measurable flow rate depends in part on the
diameter of the tool and the size of the well. For example, some
continuous flowmeters are designed to detect flows as small as 30
barrels per day (bpd) in a 7-inch well, while others function more
reliably with minimum flow rates of 300-400 bpd in 4 1/2 inch wells.
Results from continuous flowmeters may also be influenced by the
presence of gas or liquids other than water (such as oil) in the well.
Continuous flowmeters are best suited to applications where flow is
entirely in the liquid phase.
Fullbore flowmeters are the most sophisticated flowmeter devices.
The tool can be collapsed to 1 11/16 inches in diameter and is
suitable for well diameters from 3 1/2 to 9 5/8 inches inside
diameter. They are designed to overcome some of the limitations of
continuous flowmeters. Fullbore flowmeters collapse to a diameter of
1 11/16 inches for entry into small diameter tubing, but expand once
they are positioned in the hole (Figure 66). This expansion
capability increases the accuracy of the log by enabling the blades of
tool to occupy a significant portion of the well diameter. Fullbore
flowmeters can be effectively used in holes ranging from 3 1/2 to 9
5/8 inches inside diameter and in a wide range of flow rates and
multiphase flow. Use for flow rates as low as 50 bpd in 3 1/2 inch
pipe and 200 bpd in 5 1/2 inch pipe are common.
PROCEDURES
A flowmeter survey can be run in either the tubing or the casing
of an injection well. A survey is run by lowering the tool into the
well and beginning injection operations at a controlled rate. The tool
is usually calibrated by measuring the flow at a point above a
suspected leak or the known injection zone. A packer flowmeter survey
175
-------
It
t
I
I~
Packer Flowmeter
Figure 64. Diagram showing packer flowmeter in a well (Ransom, 1975).
176
-------
.
A
B
Figure 65. Two different spinner configurations in continuous flowmeters (A-Gearhart
Industries, Inc. product literature, B-Cmelik, 1979).
177
-------
TOOL CLOSED
IN RUN-IN POSITION
TOOL PARTIALLY
CLOSED
TOOL OPEN
IN LOG POSITION
Figure 66. Fullbore flowmeter (Schlumberger Well Services product literature).
178
-------
is run by positioning the tool at the depth of interest. A packer is
inflated to fill the annulus between the tool and the casing or
tubing. The fluid is thus forced to flow through a constricted region
which contains the spinner. The profile is determined by taking
readings at fixed points within the well. Figure 67 shows an electric
log, well diagram, flowmeter log and injection profile for an
injection well with an open hole completion. The flowmeter log
details the depths at which readings were taken and displays the flow
in barrels per day as a function of depth. The injectivity profile is
another display of information obtained from a flowmeter which shows
the receptivity of the formation (in barrels per day per foot)
(bpd/ft) to injected fluids. In this example, the electric log and
injectivity profile correlate to show the expected flow into the
formation.
A continuous flowmeter survey is run by moving the tool at a
constant rate past the zone of interest to obtain a continuous
profile. The tool can also be held stationary to record measurements
at specified intervals. The well is often logged both up and down the
well to obtain more accurate information by log correlation. Figure
68 shows a log obtained using a continuous flowmeter to obtain
readings with the tool held stationary and with the tool operating
both up and down the well. The log is displayed in revolutions of the
spinner per second. Fullbore flowmeters are run using the same
procedures except that the spinner must be expanded during the logging
operation.
INTERPRETATION
Interpretation of flowmeter surveys must be performed based on
the type of flowmeter used and the tool-specific interpretation. In
general, however, interpretation of a survey is accomplished by
applying the basic principles illustrated in Figure 69. Figure 69
shows an idealized flowmeter survey with two points of fluid exit from
the well (P1 and P2). The fluid is exiting at mass flow rates
M1 and M2. Above P1, the indicated flow would be proportional
to M1 + M2 (Schlumberger, no date). Thus, by knowing the volume
of fluid which should be leaving the well at a specified interval,
differences in measured flow from expected flow rates can be used to
help find leaks in the tubing or casing.
Errors in interpretation can be caused by fluctuating injection
rates, fluctuation of cable speed in continuous surveys and channeling
of flow around packer flowmeters (Morris and Cocanower, 1966). These
sources of error may be minimized by monitoring equipment and operator
performance prior to and throughout the entire logging procedure and
by performing the logging operation both up and down the well. It
should be noted that although logging speed must be held constant
during a flowmeter pass, the speed may be changed between passes. The
resulting log simply shows a displacement (Figure 70).
179
-------
Electric Log
- 16" normal
- 64" normal
.
.
.
,
,
Well Diagram
I
5'12" Casing
Set at
2035'
TO
2116'
t
Injectivity Profile
(BPD/FT)
o 5 10 15 202530 35
Figure 67. Packer flowmeter log in an injection well with an open hole completion
(Bird and Bullard. 1961).
a;
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. Packer Settings
180
-------
DEPTHS
CONTINUOUS FLOW SURVEY
rev./~c.
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--
--
---f--
--
- ..:-==
_n
Figure 68. Log using a continuous flowmeter in stationary and continuous mode
of operation (Cmelik, 1979).
181
-------
. ,,'
. . 0
.. "
tI.
. .,
"
" " " "
.. . I) C>
" "
" "
. I>
0 ~ 0
"
&>
0 " tJ C
" .. "
" I . r
. e "
" €) 0 "
o
o "
. 0 0"
" " 0
. " It>
0 0 0
.. 0 P" "
o
". a
.. .0"
o " 0
D .
D
() " 0 0
. "
" " c
. t' "
D
. 0
"
" " "
{) 0
"
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b "
" I D ~
P1 0 .
o
~:: 0 0
"
0 "
o
.. 0 00':
P2 ,,-
(0 . ,," 0
o. "
CONTINUOUS FLOWMETER
M1
---
M2
-- -- --
~
Increased Flow
Figure 69. Diagram showing principles of interpretation for flowmeters
(Schlumberger, no date).
182
.J::.
-
a.
Q)
o
-------
~
CABLE
SPEEDS
140~ft/min
~
WELL
SKETCH
60
~
100
--
--
--
C
ZONE 2
j'
- --
B
ZONE 1
J'-
A
a
2
4 6
SPINNER RESPONSE rps
8
Figure 70. The effect of logging speed on flowmeter data (courtesy Schlumberger)
(Dewan, 1982).
183
-------
Interpretation of flowmeter data is often enhanced by combining
the results with the results of other logs. This may be accomplished
by using a combination tool which houses more than one sensing device
or by actually performing additional individual logs. An example of a
heat pulse flowmeter detection system is shown in Figure 71. This
device is much more sensitive to low velocity flow than impellers, but
cannot be used at high temperatures.
Knowledge of the completion practices in the well and of the type
and characteristics of the injection formations may facilitate data
interpretation. This may be particularly helpful in older wells where
no data on initial flow conditions were ever recorded (Godbey, 1962).
COST
The cost of conducting a flowmeter survey is dependant upon the
many general pricing variables outlined in Section 7. The range of
specific depth and logging charges as determined by a survey of six
major well logging companies in the midcontinent area of the United
States are listed in Table 18.
TABLE 18. TYPICAL DEPTH AND LOGGING CHARGES FOR FLOWMETER SURVEYS
Depth Charge
per foot
minimum
Low
$0.19
$350.00
High
$0.33
$990.00
Logging Charge
per foot
minimum
Low
$0.19
$350.00
High
$0.33
$950.00
Refer to Table 7 for a listing of companies surveyed which perform
this service.
ADVANTAGES/DISADVANTAGES
Flowmeter surveys can provide a relatively accurate determination
of the location of leaks in the casing, tubing, packer or plug. Care
must be exercised to ensure that injection rates are constant
throughout the logging process. The single largest limitation of the
method is that flow rates must be high enough to permit the device to
function adequately. This flow rate is dependant on the tool design
and diameter of the borehole.
184
-------
680
MILLIMETERS
r-
100
MILLIMETERS
~
LOGGING CABLE
CABLE HEAD
ELECTRONICS
SECTION
HEATER GRID
SECTION B-B
THERMISTOR,
HEAT-PULSE
SENSORS
I
+
20
MILLIMETERS
rl
B
IT
B
20
MILLIMETERS
t
I
THERMAL
INTEGRA TOR
WIRE
THERMAL THERMISTOR,
'tlTEGRATOR0 HEAT-PULSE
WIRE SENSORS
FLOW-SENSOR TUBE
185
Figure 71. Heat pulse flowmeter detection system (Hess, 1982).
FLOW-SENSOR TUBE
-------
EXAMPLES
Figure 72 shows the results of a flowmeter survey displayed as an
injectivity profile, compared with a core analysis and microlog of the
well. A leak in the casing between the perforations was found using
the flowmeter. The fl ow rate was too hi gh to be accounted for by the
leak alone, so fracturing in the upper section was also suspected
(Godbey, 1962).
186
-------
Microlog Flowmeter Core Analysis
Flow, BWPD Permeability, millidarcies
70 10 30 50 70 90 110 10 30 50 70 90
80
90
"",..- -.
" .
5,200 ..
10
20
30
40 B Perforations
Figure 72. Results of a flowmeter survey showing a leak in the casing between perforations
(Godbey, 1962).
187
-------
REFERENCES
Bird, James M. and H.M. Bullard, 1961, Use of subsurface flowmeter and
fluid density analyzer for studying fluid flow in producing and
injection wells; Paper presented at the Petroleum Engineering
Conference, University of Illinois, Urbana, Illinois, May 4-5,
1961, 4 pp.
Cme1ik, H., 1979, A controlled environment for measurements in
mu1tiphase vertical flow; Transactions of the SPWLA Twentieth
Annual Logging Symposium, June 3-6, 1979, Tulsa, Oklahoma, 10 pp.
Dewan, John T., 1982, Open hole and cased hole log interpretation;
Presented for the U.S. EPA, Region VI, Dallas, Texas, October
18-21, 1982, 350 pp.
Gearhart Industries Inc., product literature, Fort Worth, Texas.
Godbey, John K., 1962, New f10wm~ter gives water-injection profiles;
The Oil and Gas Journal, vol. 60, no. 11, pp. 92-95.
Hess, Alfred E., 1982, A heat pulse flowmeter for measuring low
velocities in boreholes; U.S. Geological Survey Open File Report
82-699, 40 pp.
Morris, Billy P. and R.D. Cocanower, 1°~6, Factors to be considered in
the interpretations of injectivity proii1es; Paper presented at the
SPWLA Seventh Annual Logging Symposium, May 8-11, 1966, 21 pp.
Ransom, R.C., 1975, Glossary of terms and expressions used in well
logging; Society of Professional Well Log Analysts, Houston,
Texas, 74 pp.
Sch1umberger Services Catalog, 1978, Sch1umberger Ltd., Houston,
Texas.
Sch1umberger Well Services product literature, Houston, Texas.
Sch1umberger, no date, Interpretation of the temperature log and
continuous flowmeter; Houston, Texas, 27 pp.
Syms, Margot C., Peter H. Syms and Paul F. Bix1ey, 1982,
Interpretation of fiow measurements in geothermal wells without
caliper data; The Log Analyst, vol. 23, no. 2, pp. 34-45.
188
-------
Warner, Don L. and Jay H. Lehr, 1977, An introduction to the
technology of subsurface wastewater injection; U.S. Environmental
Protection Agency publication EPA#600/2-77-240, December, 1977,
344 pp.
189
-------
SECTION 16
RADIOACTIVE TRACER SURVEYS
SYNOPSIS
Radioactive tracer surveys or logs are used to study the movement
of radioactive tracers in the immediate vicinity of the borehole
(Ransom, 1975). They may be used in injection wells to help determine
the presence of tubing, casing or packer leaks or to detect channeling
behind the casing (Warner and Lehr, 1977). The radioactive tracer
survey is conducted during injection operations by loading the
radioactive tracer into the tool, lowering the downhole tool to a
desired depth and ejecting a small amount of radioactive tracer. The
tracer movement is detected by a gamma ray detector(s) which may be
mounted in the tool in a variety of configurations. The tool may be
held stationary or moved to follow the tracer movement. More than one
run may be made; interpretation is accomplished by comparison of logs
obtained both before and after radioactive tracer ejection.
PRINCIPLES
A radioactive tracer survey is conducted by ejecting a small
quantity of short lived radioactive material, dissolved in an
appropriate medium, into the fluids flowing in the tubing or casing.
The transport and distribution of the radioactive tracer is monitored
by gamma ray detectors (Lichtenberger, 1981). By comparing logs
obtained during the survey to logs run before the tracer was injected,
leaks in the casing, tubing or packer and channeling behind the casing
can be detected.
Radioactive tracer surveys utilize the principle that unstable
isotopes of elements emit radioactivity while decaying to reach a
more stable state. In the process of decay, the isotopes emit alpha
and beta particles and gamma rays. The alpha and beta particles are
absorbed relatively quickly by the ;urrounding material and are
therefore not measured in tracer surveys. The gamma rays, however,
travel for a short distance through rock, cement and steel and can be
detected by a sensor in the logging tool.
A variety of compounds can be used in radioactive tracer surveys.
The primary concerns in selection of the proper radioisotope are the
well conditions and the characteristics of the r~dioisotope. First,
the radioisotope must be completely soluble in t~e injection fluid
(Kelldorf, 1969). Second, tne tracer should have an appropriate half
190
-------
life, long enough to be detected in the vicinity of the well, but not
long enough to reach any area of ground water use. A half life is the
length of time required for any given number of atoms to lose half
their measurable radioactivity.
In Class II injection wells, the most common radioactive tracer
is Iodine-131. Iodine-131 is typically available as water-dissolved
radioiodine which has been stabilized to prevent oxidation in air,
water or acid. The tracer is miscible in water and insoluble in oil.
Iodine-131 has a half life of 8.1 days and is classified as a medium
energy emitter (Johnson and Morris, 1964). Iridium-192 may also be
used as a tracer in injection wells. However, because it has a 74 day
half life, it is less commonly used.
The gamma rays emitted by the tracer are measured by a gamma ray
detector. The two most common detectors in use are the scintillation
crystal and the Geiger-Mueller tube (Lichtenberger, 1981). A
scintillation detector usually contains a crystal of sodium iodide
which is optically coupled with a light-sensitive amplifier tube or
photomultiplier (Johnson and Morris, 1964). Gamma rays strike the
crystal and produce small light flashes that are sensed and amplified
by the photomultiplier (Dresser Atlas, 1976). This type of detector
is 85 percent efficient in the detection of small amounts of
radiation. However, the detector is not suitable for use at
temperatures greater than 150°F unless some temperature protective
housing is provided for the crystal (Kelldorf, 1969). Typically, this
temperature restriction should not be a constraint in Class II
injection wells (W.S. Keys, personal communication, 1983).
Where temperature is a concern, Geiger-Mueller tubes may be used.
Their use has been largely discontinued except in small-diameter tools
used in slim-hole completions where temperature protection is not
possible (Dresser Atlas, 1976). Geiger-Mueller tubes can be used at
temperatures up to 300°F, however efficiencies are limited to less
than 10 percent (Kelldorf, 1969).
EQUIPMENT
The radioactive tracer logging tool basically consists of a
tracer ejector and one or more gamma ray detectors. Figure 73 shows a
tool with one detector; Figure 74 shows typical tracer tool
configurations for tools with two detectors. The ejector may either
employ a solenoid plunger, be well-pressure operated or operate by
positive piston displacement (Johnson and Morris, 1964). All types of
ejectors are activated at the surface.
The radioactive logging tool ranges in outside diameter from
1 1/2 inches to 3 3/8 inches depending on the design. The length of
the tool varies by manufacturer and tool configuration, but ranges
from 10 to 30 feet. Some tools can be used in downhole environments
up to 300°F and at maximum pressures of 15,000 psi.
191
-------
UNIVERSAL {
ATTACHMENT
HEAD
RIA
TRACER
SECTION
DETECTOR
SECTION
TO SURFACE CONTROLS
LOGGING CABLE
SURFACE CONTROLLED
ELECTRIC MOTOR
AND PUMP
FILLER PLUG
EJECTOR PORT
ACME THREAD
TOOL JOINT WITH
o RING SEAL
SCINTILLATION
DETECTOR
CRYSTAL
(Continuous Surface
Recording Gamma
Ray Signal)
Figure 73. Radioactive tracer tool (Ford, 1962).
192
-------
~
6
~
+-- CCl
~CCl
o ~ EJECTOR
n GAMMA
U +-- DETECTOR
n ~ GAMMA
U DETECTOR
n ~ GAMMA
U DETECTOR
n ~GAMMA
U DETECTOR
o ~ EJECTOR
EJECTOR
n <,.-GAMMA
II DETECTOR
GAMMA
DETECTOR
g
Q
g
Figure 74. Three possible configurations of a radioactive tracer tool (courtesy
Schlumberger) (Dewan, 1982).
193
-------
PROCEDURES
Radioactive tracer surveys are performed on injection wells
during injection operations. The survey is run by loading the ejec :or
tool at the surface with the radioactive tracer through a filler plug.
The tool is lowered into the well through an assembly which permits a
minimum of alteration of the injection pressure. A natural gamma
background log is run before ejection of the radioactive tracer to
provide information on background conditions and correlation with
previously run logs (Ford, 1962).
The tool is then positioned and a small amount of radioactive
tracer is released. The tracer tool can either be held stationary or
moved to trace the path of the radioactivity; the method of operation
depends on the tool design and the purpose of the survey. In a
two-detector tool, the tracer is injected into the well and the tool
is typically held stationary. The time for the radioactivity to pass
frr~ one detector to another is recorded. If the slug moves too
slowly, a leak may be indicated. In a single detector tool, the tool
is typically moved to follow the radioactive tracer. By moving the
tool, it may be possible to better locate channeling behind the casing
or leaks in the tubing or casing. In either method, checks may be
made at various depths to verify the presence or absence of leaks
and/or channeling by changing the depth of ejection or direction of
movement of the tool.
Because radioactive tracer surveys utilize radioactive materials,
completion of a radioactive tracer survey must be performed by
personnel which hold a current and valid Nuclear Regulatory Commission
license or a state license. This ensures that proper procedures will
be followed in the handling of the radioactive material. In addition,
the Department of Transportation regulates the transport and handling
of radioactive materials used in well logging operations. These
licenses and regulations are not of general concern to the person
requesting a log because the logging company is responsible for
complying with the regulations and procedures.
INTERPRETATION
Interpretation of radioactive tracer surveys must be performed
based on the type of tool used and the method of running the log. The
following general situations and statements can be used to help
interpret data obtained from a radioactive tracer survey. In general,
a radioactive tracer log is evaluated by comparing the 10g(s) obtained
after injection of the radioactive tracer with the 10g(s) obtained
prior to radioactive tracer injection. The differences between these
logs provide the basis for analysis. In addition, some basic
statements about detection and f10wrates may also be used to evaluate
the logs. For example, if a tool configuration of an ejector between
two detectors is used, a leaking packer in an injection well may be
found by ejecting a radioactive tracer at the tubing shoe and
194
-------
observing the readings at each detector. Increased radioactivity at
the higher detector will show movement of fluid in the tubing-casing
annulus (Dewan, 1982). Using the same tool configuration, channeling
of fluid behind the pipe at a casing leak can be found by ejecting the
radioactive tracer above the leak. After moving the ejector below the
leak, the radioactive tracer will not be present at the upper detector
(Dewan, 1982).
A similar interpretation may be made by knowing the location of
the injection zone and recording whether or not the radioactive tracer
moves past this zone. This indicates either a leak or channeling
(Edwards and Holter, 1956).
COST
The cost of conducting a radioactive tracer survey is dependent
upon the many general pricing variables as outlined in Section 7. The
range of specific depth and logging charges as determined by a survey
of six major well logging companies in the midcontinent area of the
United States are listed in Table 19.
TABLE 19. TYPICAL DEPTH AND LOGGING CHARGES FOR RADIOACTIVE TRACER
SURVEYS
Depth Charge L~ High
per foot $0.27 $0.33
minimum $540 $990
Logging Charge Low High
per foot $0.28 $0.33
minimum $550 $950
Refer to Table 7 for a listing of companies surveyed which perform
this service.
ADVANTAGES/DISADVANTAGES
Radioactive tracer surveys provide an effective means for
locating and evaluating leaks in casing, tubing and packer and
channeling behind the casing. The primary advantage is that the
survey is run during injection operations and can therefore provide a
clear picture of what is taking place in the well under actual
operating conditions. This also means that there is no need to
interrupt the injection process to perform this service. The
disadvantages to this method of checking mechanical integrity is in
the choice of the correct radioactive isotope to ensure that no
195
-------
radioactivity reaches an area of ground-water use. Additionally, the
correct strength of radioactivity must be made because the effective
penetration of gamma rays is reduced by travel through a medium such
as steel casing.
EXAMPLES
The following examples serve to illustrate the interpretation of
logs to locate channeling behind the casing and a leak in the casing.
Figure 75 shows the comparison of the logs run prior to and after the
ejection of the radioactive tracer. The presence of radioactive
tracer below the perforations indicates that fluid is being channeled
behind the casing.
Figure 76 shows the technique used to locate a leak in the casing.
Figure 76a shows the top detector of the tool located in the tubing
and the bottom detector just below the tubing at the top of the
perforations. When the radioactive tracer was ejected, radioactivity
reached the top detector, but not the bottom detector. This suggests
that no injected water was exiting through the perforations because
the tracer would have to pass the bottom detector to reach the
perforations. Figure 76b shows the survey being run with both
detectors inside the tubing. The radioactive tracer passed both
detectors, but still was not entering the perforations. Therefore,
the water is interpreted as traveling up the hole inside the casing.
Figure 76C shows movement of the fluid up the well when a radioactive
tracer was injected at 2400 feet. In Figure 76D, the tracer was
followed up the hole until 2020 feet where the movement became
stationary. This indicated that the injected water exited through a
leak in the casing at this point (Welex, 1968).
196
-------
RADIOACTIVE TRACER LOG
....
0>
a
o
o
...~ RADIOACTIVE TRACER LOG
,....,,---'
,
.,'
..:: :-,
-,':)
,"
...
~
....
9>
....
o
o
,----
---------------------
- =:::.
,-
C------
----_:::::> RADIOACTIVE MATERIAL
--:- BELOW PERFS.
"
c::_--------
«'::": ---- ----- - ----- -- -------::-----:=:::===~
--Z
I
I
,
m PERFORATIONS
Figure 75. Radioactive tracer log showing movement of radioactive material below
perforated zones (courtesy Schlumberger) (Dewan, 1982).
197
-------
Top Detector
INJECTION RATE
2BPM
2180
2190
2200
Bottom
Detector
~
1 MIN
Figure A
2210 LOGGING
2220 t
~ TIME
DRIVE
2000
Figure B
2050
LOGGING TOOL STATIONARY
2150
Figure C Figure D
Figure 76. Technique using radioactive trace.r tool and logs used to locate leak in the casing
(Welex, 1968).
198
-------
REFERENCES
Dewan, John T., 1982, Open hole and cased hole log interpretation;
Presented for the u.S. EPA, Region VI, Dallas, Texas, October
18-21, 1982, 350 pp.
Dresser Atlas, 1976, Gamma Ray-Neutron Log; Dresser Industries, Inc.,
Publication No. 3101-R/3-76, Houston, Texas, 20 pp.
Edwards, J.M. and E.L. Holter, 1956, How to use radioactive isotopes
for water-input profiles; The Oil and Gas Journal, v. 54, no. 30,
pp. 69-70.
Ford, Walter 0., Jr., 1962, How new injectivity profiling method
works; World Oil, v. 145, no. 2, pp. 43-47.
Johnson, Wallace and Billy P. Morris, 1964, Review of tracer surveys;
Paper presented at the Spring Meeting, Southwestern District,
Division of Production, American Petroleum Institute, paper number
906-9-E, Midland, Texas, March 18-20, 25 pp.
Ke11dorf, W.F.N., 1969, Radioactive tracer surveying - a comprehensive
report; Society of Petroleum Engineers of AIME, paper number
SPE-2413, 10 pp.
Lichtenberger, Gunter J., 1981, A primer on radioactive tracer
injection profiling; Proceedings of the 28th Annual Southwestern
Petroleum Short Course, Lubbock, Texas, April 23-24, 1981, pp.
251-265.
Ransom, R.C., 1975, Glossary of terms and expressions used in well
logging; Society of Professional Well Log Analysts, Houston,
Texas, 74 pp.
Warner, Don L. and Jay H. Lehr, 1977, An introduction to the
technology of subsurface wastewater injection; u.S. Environmental
Protection Agency publication #EPA 600/2-77-240, December, 1977, 344
pp.
We1ex, 1968, Utility of the fluid travel log; We1ex, Technical
Bulletin #Cl-2003, Houston, Texas, 6 pp.
199
-------
SECTION 17
CEMENT BOND LOGGING
SYNOPSIS
The cement bond log is made using a downhole tool which emanates
and records pulsed sound energy. In injection wells. cement bond logs
can be used to determine the quality of the cement bond to the casing
and to infer the presence of channels in the cement behind the casing.
The log cannot be used to determine fluid movement in channels behind
the casing. The cement bond log is run by centering the tool within
the casing. This necessitates the removal of tubing from wells which
are completed with tubing. The logging tool is suitable for use in
casing as small as 2 inches in diameter and some tools can withstand
maximum temperatures and pressures of 400°F and 20,000 psi. The
cement bond log is a continuous log which can be recorded in a CBL
(cement bond log) or combination CBL/VDL (variable density log)
format. Interpretation of the cement bond log is enhanced when the
combination is used. However, interpretation of logs made using
different tools is difficult because there is no standardization
within the industry. Even when proper interpretation techniques are
employed, a great number of variables may influence the output and
must be taken into consideration.
PRINCIPLES
Cement bond logs can be used to detect and locate areas behind
the casing that have been inadequately cemented. Incomplete bonding
of the cement to the casing or to the formation may provide avenues
for the passage of fluids through the casing-borehole annulus.
Although small channels and the presence or absence of fluid movement
cannot be determined, cement bond logs can indicate that the potential
for fluid movement exists.
A cement bond log utilizes a logging tool in a borehole which
emits and records acoustic signals. The signal, produced by a
transmitter within the tool, travels 1) through the fluid in the
borehole to the casing, cement and formation. 2) along the casing and
formation and 3) back through the fluid to the receiver (Figure 77).
Because sounds travel at different velocities through different
mediums, the sound waves from these different pathways will arrive at
different times. The most common order of arrival is 1) the casing
pathway. 2) the formation pathway and 3) the borehole fluid pathway
(Gearhart, 1982). Figure 78 shows common pathways and illustrates
typical travel times through each of the mediums.
200
-------
rh.:Jr /"r" ~
t{j ~ i:r~ r1
~)-~
~ ~ ~
~ V'
u
k' .y,
~r~
W~
~~
"\ '>..J ~
~~\.
~'-'
111 --I >'
~\-,~
.lHh.J ""1
~ --00 X
~ y"
u:? 1a: J )I
~ J ~~ ~
11 ~~}{ ~
(1 'r LXrr'.... >:1"
~
.v-
-,..,r
I
~~~...
"'
",""NY
~X("1
~ .....
, ,
'I~i'
.A.
~ ~
1 .J?L \...) ,
TRANSM ITTER
... .L \ ~,' '
~ :Q ,9 ~
T
.11',.:\(
STEEL PI PE (f, l).J'rl
(Casing)H ..,-.
'llhJ( 1:J.-17.
'Y {}. W1 'f H :1:
Ii >1 ...... >-'
9' , :<- J; ~ 'f'"
~ J >
, ,H n""" ~
, .- ~ ~ r
.1r~~~? t1~ 7 ~Q1 y \?~
M i: lei;' r< >f,
).). to( ;f,l, .v
l'~ W!':):>,- V;;
'., r ~ ~ '" ~ 0
:1 ):.~~'"" '<9
or .,~~ ~ --r"''--
,\JIc."3L lrt J. ' 1..1 \ \""'1
;f'tt~ ~ n ~~,.;
~~) 0 ry Kt. &~
1,«: ~ ~ t-\~'~
{f. ~ :n:x~
!I, IX .... vD..... -- , .f. ...
r,..;
'~ .,. 1.?1
D. 'J.r'
...
():..J.
Figure 77. Basic cement bond log theory (Gearhart Industries, Inc., 1982).
..
.q
rJ V< .,..
'r /{rY k'
~ ':)~ 1Ar'(,'- ..
'1"1'- ~ p~ .,:
,... I""', ('r
-1' t;:o'>< ~ :.- I'~
~ RECEIVER
~ :r'1 .9'
~ ..Y ,..:~'
~ .'
.n"
N, .:p.
\ ;- ~~ 9,
~~ ~H~
--~
R
I~~u~~~ .
201
-------
-
- 5' RECEIVER
- 5' RECEIVER
~1 ~
~ -
~ - GULF COAST
- ~FORMATION
- - 75 microsec/ft
- --
CASING
FLUID
200 microsec/ft
~I- - CEMENT
"'- 100 microsec/ft
CASING
57 microsec/ft
Figure 78. Typical transit times for various media inspection by the cement bond tool
(Schlumberger, no date).
202
-------
A cement bond log is made by recording the amplitude of the
signal and the transit time necessary for that signal to reach the
receiver through the casing pathway. According to Gearhart (1982),
the amplitude of the signal recorded at the receiver is a function of:
1) the magnitude of the original sound pulse,
2) the internal diameter of the casing,
3)
4)
the type of fluid in the well,
5)
6)
the thickness of the casing wall,
the amount of cement bonded to the casing, and
the compressive strength of the cement bonded to the casing.
Figure 79 shows a typical cement bond log. The log is analyzed to
evaluate the quality of the cement bond to the casing. In general,
the amplitude of the signal received from casing which has no cement
bonded to it is large. Conversely, when the cement and casing are
bonded together, the signal is attenuated by the casing and therefore
the signal at the receiver is very small (McGhee and Vacca, 1980).
Often a second recorder will be used to measure all the energy in the
wave train which arrives at the receiver. The primary purpose of this
second recording method, called a variable density log (VOL), is to
record the signal from the formation pathway (McGhee and Vacca, 1980).
This output is then used to support the interpretation of the casing
curve and to more clearly identify micro-separations in the cement
(McGhee and Vacca, 1980).
The VOL is displayed as a series of alternating light and dark
bands which represent the different pathways of the sound waves.
Typically the casing arrivals will appear as regular bands and the
formation arrivals as irregular bands (Figure 80). Because the two
outputs (CBL and VOL) compliment each other, the two outputs usually
appear as one log rather than as separate logs.
Although the cement bond log is simple in theory, the validity of
the cement bond log and its interpretation is a source of controversy
(Fert1 et a1., 1974). The American Petroleum Institute has recognized
this problem and has formed a committee to offer suggestions on
standardization of equipment and interpretation.
EQUIPMENT
The typical cement bond logging tool consists of a sonic
transmitter and either one or two receivers located at specified
distances from the transmitter (Figure 81). The transmitter-receiver
spacings range from 3 to 7 feet, but 3 and 5 foot spacings are common
(McGhee and Vacca, 1980). The shorter spacing is desired in the
traditional cement bond log format (CBL) because it more clearly shows
203
-------
TOTAL TRANSIT TIME
400 MICROSECONDS 200 0
2000
1
1
t
I
MILLIVOLTS
! .
2500
AMPLITUDE
50
PIPE SIGNAL
CASING COLLAR
Figure 79. Typical cement bond log (Schlumberger, 1976).
. I
3000
204
100
-------
AMPLITUDE
mV
CASING ARR.
FORMATION ARRIVALS
MUD ARRIVALS
TRANSMITTER
I
I I I I
I I I I
I I I I
I I I I
I I I I
I I I I
I I I I
I I I I
I I I I
I I I I
I I I
t J.I SEC
Figure 80. Principle of operation of the variable density log (Schlumberger, 1976).
205
-------
CATHODE RAY UNIT
.3' CBl - 5' VlD logic
--
STANDARD OPTICAL CAMERA
3' CBl Signal
5' VDl Signal
., -
'.' -
. -
:.::~':~' : ~ = - - -
\~) ~=~~:;-
. - - -
','""- - - -
...', - - --
'." - - -
. - ---
,'. - - -
,,'. - - --
TRANSMITTER
~::;\ -~ = ~ ~ -=~-
?\~ --=- = == =~
5' RECEIVER
./: - --
.:t :~~~~
3' RECEIVER
- - -
Figure 81. Diagram of equipment used for recording CBL-VDL combination
(Brown et al., 1970).
206
-------
the attenuation rate of casing arrival. The longer spacing is
normally used for a variable density log output (VDL) which more
clearly depicts formation arrivals in well bonded intervals (Fert1
a1., 1974).
et
The cement bond logging tool ranges in outside diameter from
1 1/8 inches to 3 5/8 inches depending on the design. The length of
the tool varies by manufacturer and tool configuration, but ranges
from 10 to 22 feet. Some tools can be used in downhole environments
up to 400°F and at maximum pressures of 20,000 psi.
In cement bond logging, the transmitter emits a series of pulses
at a fixed frequency which normally ranges from 15 to 30 kHz depending
on tool design. The pulse rate also varies with tool design but
ranges from 10 to 60 pu1ses/sec and may be able to be varied at the
site (Fert1 et a1., 1974). After travel through the appropriate
combination of borehole fluid, casing and formation, the acoustic
signal is picked up by the receiver{s). The measurements at the
receivers are made during a specified interval called a gate. The
gate has specific beginning and ending time boundaries which are
referred to as the gate width (Ransom, 1975). Cement bond logging
tools have two different gating systems: fixed and floating. In a
fixed gate CBL, the gate width and the time the gate opens after the
transmitter sends out a signal are fixed by the operator. The
amplitude of whatever signal is present is recorded while the gate is
open (Fert1 et a1"o 1974). In contrast, with a floating gate, the
gate remains open until an amplitude high enough to trigger the tool
causes it to close. This response is recorded as transit time. The
amplitude to which the gate responds is called a bias setting and must
be set high enough to avoid interference from sources such as cable
noise (Fert1 et a1., 1974). Figure 82 shows a diagram of the response
of the two gating systems. Because the gating system used has a
direct effect on the interpretation of the log, this is an important
feature of tool design. Table 20 shows a summary of characteristics
of typical cement bond logging tools and their design characteristics.
Froelich et a1. (1982) describe the next generation of cement
evaluation tools (CET) which are being designed and marketed to
overcome some of the design and interpretation difficulties with
cement bond logging tools. The CET tool is 3 3/8 inches in diameter
and made for use in 4 1/2 to 5 1/2 inch casing; a 4 inch diameter tool
is available for use in 5 1/2 to 9 5/8 inch casing. Eight transducers
are helically arranged at 45° to one another on the tool to receive
signals generated by a high frequency transducer with frequencies
ranging from 300 kHz to 600 kHz (Figure 83). The transducers measure
the decay of the ultrasonic echoes. The resultant log is a
three-track output which is easy to interpret and which provides a
display of cement distribution around the caslng.
207
-------
Amplitude
E,
~t
DETECTION LEVEL
I
I
I
I
I
I
Time
------------------
FLOATING GATE
TRIGGERED BY At
I
FIXED GATE
SET BY OPERATOR
Figure 82. Diagram showing response of fixed and floating gating systems
(Schlumberger, 1976).
208
-------
TABLE 20. SUMMARY OF CHARACTERISTICS OF TYPICAL CEMENT BOND LOGGING TOOLS (FERTL ET AL., 1974)
Tool Tr Transmitter Pulse Gate
Logging 00 Spacing Frequency Rate Width
Company (in) Type 01 Gate (ft) (KH) (pulse/see) (see)
A 3-3/8 Floating time,
fixed or floating amplitude 3 20 20 25-100
3-5/8 Fixed amplitude, 20 20 25
floating time 3,5
1-11/16 Fixed amplitude 3 30 20 15-20
N Floating time 5
C)
CD B 3-5/8 Floating time, 20 15 50
fixed amplitude 3,4,5,7
3-5/8 Fixed 3 20 60 50
3-5/8 Fixed 3, 4, 5 20 60 50
2-1/8 Fixed 3, 5 20 60 50
1-11/16 Fixed 4 20 60 50
3-3/8 Fixed 3,4,5 20 60 50
C 2-5/8 Fixed 4 20 20 200
1-1/8 Fixed 30
0 1-3/4 Fixed 4 15 10 200
-------
!D
~
~
OD4"
CENTRALIZER
BULK HEAD
FIXED TRANSDUCER
MOVABLE TRANSDUCER
ADJUSTING SCREW
TRANSDUCER
CENTRALIZER
OD 3"1.'
COMPENSATION
Figure 83. Diagram 0' the cement evaluation tool (Froelich et al., 1982).
210
N
a,
-------
PROCEDURE
Cement bond logs are performed on injection wells which have a
cemented casing. In wells which have tubing, the tubing must be
removed before the log can be run. The log may run 1) by
repressurizing to injection pressures, 2) at higher or lower pressures
or 3) without pressure. It may be necessary to perform the log more
than once or at different pressures to avoid false interpretation due
to micro-separations which decrease the amplitude of the casing
signal, resulting in casing signals that are too large (McGhee and
Vacca, 1980). According to McGhee and Vacca (1980), microseparations
or a microannulus may be caused by a number of factors including:
- lowering the casing fluid level,
- pressure testing casing,
holding surface pressure on casing during cement set, and
- circulating tool casing fluid immediately before logging.
By maintaining the correct fluid pressure inside the casing, anomalous
results can be avoided. This may necessitate the installation of a
pressure control assembly before the log is run. The presence of gas
in the casing fluid will also cause unpredictable increases in transit
time; therefore the casing fluid must be free of gas to obtain a
meaningful log (McGhee and Vacca, 1980).
A cement bond log is made by lowering a centralized tool to the
depth of interest. A minimum of three centralizers is recommended to
avoid interpretation problems due to excentering (Fertl et al., 1974).
The well is logged at a speed of approximately 0.5 feet per second
over the zone of interest. Maximum logging speeds should not exeed 1
foot per second (Fert1 et al., 1974). A continuous log is made as the
tool emits pulses of signal and the acoustic signal is received by the
recorder(s). The signal is processed at the surface on logging film
and recorded in the CBl or CBl/VDl format (Muir and Rollman, 1970).
Care should be taken to ensure that the gain setting for the
gating system is chosen properly. Too low gain settings result in
reduced amplitude recording and improper interpretation (Fertl et a1.,
1974).
INTERPRETATION
Correct interpretation of cement bond logs is dependent on the
specifications of each tool. Cement bond logs run in the same well
with different tools will produce different logs. Therefore it is
extremely important that a professional log analyst perform the
interpretation based on the tool as well as knowledge of conditions
within the well.
211
-------
Cement bond logs are interpreted by observing the trace of the
cement bond log or the CBl/VOl combination. Typical log responses for
the four most common situations have been described in detail by Brown
et ale (1970) and are discussed below.
Uncemented Casing
Uncemented casing permits most of the acoustic wave to trav~l
through the casing with a minimum of signal attenuation. Formatl0n
signals are weak or non-existent. The CBl and VOL characteristics
are:
- large casing arrivals,
- very weak or no formation arrivals,
- clear chevron patterns at the collars,
- slight increase in travel time and a decrease of CBl amplitude
at the collars, and
- no change in arrival time versus depth.
Figure 84 illustrates a typical CBl and VOL output for uncemented
casing. The chevron displacement shows the location of casing collars
and the straightness of the VOL output indicates proper centering of
the tool.
Good Casing Bond and Good Formation Bond
When both the casing and the formation are bonded to the cement,
the acoustic energy is transmitted efficiently to the formation. This
results in little signal travel through the casing. Characteristics
of such a situation would be:
- weak casing arrivals, and
- strong formation arrivals if formation attenuation is not high.
Figure 85 illustrates a typical CBl and VOL response for good casing
and formation bonding. The CBl shows low amplitude readings and the
VOL confirms this indication by showing weak casing arrivals and
strong formation signals. Formation signals are identified on the VOL
as wiggly lines which are caused by the variation of formation transit
time with depth.
Good Casing Bond but Poor Formation Bond
When a casing-cement bond is present, but a good cement-formation
bond is not present, the casing signal will be attenuated by the
cement but little energy will be transmitted to the formation. The
characteristics of this situation would include:
212
-------
TOTAL TRAVEL TIME
Depth
CEMENT BOND LOG
Amplitude
..
VARIABLE DENSITY LOG
Time
..
.
CBL T-R SPACING (3')
rnrn
VOL T-R SPACING (5')
CBL FIRST CASING ARRIVAL AMPLITUDE
~
a>
8
TOTAL TRAVEL TIME
Figure 84. CBL/VDL log showing uncemented casing (Brown et al., 1970).
213
-------
GAMMA RAY LOG CEMENT BOND LOG VARIABLE DENSITY LOG
API UNits Depth Amplitude Time
~ .. ..
.fYLif1n III
I' MUD ARRIVA LS
I: ~f
.....
~ ;~itt
...
~ FORMATION COMPRESSIONAL WAVE ARR~~ I
>r1.1'~:
;l'~J~ ~
, ':~~
GAMMA RAY I-- - .~f{'
II ~
~ ~ .~
'" CBL FIRST CASING I-- ~ 1
ARRIVAL AMPLITUDE ~ ~ ',' r~:
I
I
I . ,
.. .
I '--- ----1
FORM~TJON RAYLEIGii]~~Hm~
~)f~'
I t,
~.. ~l' I
100 microsec~k JA'~i
Figure 85. CBL/VDL log showing good casing-cement and cement-formation bond
(Brown et ai., 1970).
214
-------
- weak casing arrivals, and
- weak or no formation arrivals.
Figure 86 shows good casing-cement bonding with poor cement formation
bonding. The CBl amplitude is low, however the VOL does not show a
clear formation arrival. Thus, poor cement-formation bonding is
suspected.
Microannulus or Channeling
In situations where a small annulus gap forms between a casing
and cement but the casing is well cemented, a microannulus exists.
This microannulus may not affect the ability of the cement to prevent
fluid migration, but will affect the results of a cement bond log.
The results for both a microannulus and channeling (which permits
fluid migration) are characterized by:
- moderate casing arrivals, and
- moderate formation arrivals.
Because the signal response is the same, the difference between a
microannulus and channeling is most commonly distinguished by
performing another log with the casing pressurized. If channeling
exists, pressurizing the casing produces little or no change in the
CBl or VOL. Figure 87 illustrates the CBl/VOl response for a
microannulus before and after casing pressurization. When the casing
is pressurized, the casing arrivals are weakened and the formation
arrivals are strengthened. Another way to differentiate between a
microannulus and channeling is to observe the length of casing over
which the condition occurs. Typically, the microannulus will be
evident over a longer section while channeling occurs for a shorter
distance (Brown et al., 1970).
The results portrayed on a cement bond log may also be influenced
by such factors as the type of gating system in the tool, excentering
of the tool, cycle skipping and transit time stretch. The two
different types of gating systems are detailed in the equipment
section. Figure 88 shows the effect of each system on a CBl log run
in the same well. By observing the amplitude trace, the importance of
understanding the gating system can be appreciated. Excentering of
the tool may also produce erroneous cement bond logs. Figure 89
illustrates the effect of performing the logging operation with the
tool both properly and improperly centered.
Cycle skipping and transit time stretch are two normal responses
which may occur during logging operations. Transit time stretching is
a function of the wavelength of the transmitter and is caused by
variations in the casing signal energy at the receiver. This
phenomenon can be identified on the log for proper interpretation.
215
-------
TOTAL TRAVEL TIME CEMENT BOND LOG VARIABLE DENSITY LOG
Depth Amplitude Time
.. ~
.. .....-
I I ~ ... 100 microm conds.
..-:
...
CBL FIRST CASING
ARRIVAL AMPLITUDE
~
.
... A I~
.... I\..
TOTAL TF AVE TM 1_1000'
1-"'"
l"'"
I.
t:::I
r'I' ...~ ~
r-I-ot
lilt
1,,000 t'"
Figure 86. CBL/VDL log showing good casing-cement bond but poor cement-formation bond
at level A (Brown et aI., 1970).
216
-------
CEMENT BOND LOG
Amplitude
VARIABLE DENSITY LOG
Time
CEMENT BOND LOG VARIBLE DENSITY LOG
Amplitud~ Time
" " , II
I I I 1
250 Dsi PRESSURE
I I I I I
... ~ - tro~g~r~O~MIATION ARRIVALS
"
J'
....
11
.J
c.. ,..
~
I""!o
1.0-
,
~
AMPLITUDE ....
~
~
- II'"'
-- -
.....
-
Figure 87. CBLlVDL logs showing response 0' microannulus runs with and without pressure
in the casing (Brown et aI., 1970).
217
-------
TRANSIT TIME
microseconds
400
AMPLITUDE
millivolts
50
TRANSIT TIME
microseconds
400 200
AMPLITUDE
millivolts
~
z
w
~
w
(j
50
FLOATING GATE
218
Figure 88. Effect of fixed gate and floating gate on the same log (Schlumberger, 1976).
~
z
w
~
w
(j
FIXED GATE
-------
400
I
TRANSIT TIME, lLSec
200
I
7700
o
I
AMPLITUDE, mv
50
100
7800
Figure 89. eBl log showing effect 0' proper and improper tool centering (Fertl et at, 1974).
219
-------
Cycle skipping occurs when the casing signal becomes less than the
transit time circuit can measure. This phenomenon can also be
identified on the logs for proper interpretation.
Another way to interpret CBL is to apply what is termed a bond
index, where
Bond
Index
Attenuation rate in zone of interest db/ft)
= Attenuation rate in well cemented internal (db/ft)
(Sch1umberger, no date)
The bond index gives an indication of the percentage of the casing
circumference which is bonded. A bond index of 1.0 represents the
ideal bond and an index less than 1.0 indicates an incomplete bond.
Field experience has shown that the minimum value of bond index for a
hydraulic seal is 0.8 (Sch1umberger, no date). However, values less
than 0.8 may also be adequate in certain situations (Brown et a1.,
1970).
The bond index is determined by taking the lowest amplitude
reading (in millivolts) on the CBL and assuming that this represents a
100 percent cement bond. By consulting a chart for the specific tool,
and by knowing the amplitude and casing diameter, the attenuation rate
in decibels can be read. This number is entered as the denominator in
the equation (Gearhart, 1982). By multiplying the denominator by an
assumed desired bond index of 0.8 and returning to the chart, it is
possible to determine the values in millivolts which would constitute
a poor bond. Any readings greater than this would be interpreted as
having a good bond; any numbers less as having a poor bond (Gearhart,
1982). According to Brown et a1., (1970) the advantage of applying a
bond index is that it depends on ratios and not absolute measurements
for evaluation. This minimizes the chance of interpretation errors
due to unknown environmental parameters and conditions.
COST
The cost of producing a cement bond log is dependent upon the
many general pricing variables outlined in Section 7. The range of
specific depth and logging charges as determined by a survey of six
major well logging companies in the midcontinent area of the United
States are listed in Table 21. Refer to Table 7 for a listing of
companies which perform this service.
ADVANTAGES/DISADVANTAGES
The cement bond log may be used in injection wells to infer the
presence of channels in the cement adjacent to the casing. When
properly interpreted, the cement bond log indicates the potential for
220
-------
TABLE 21. TYPICAL DEPTH AND LOGGING CHARGES FOR CEMENT BOND LOGGING
Depth Charge Low High
per foot $0.21 $0.35
minimum $300 $700
Logging Charge Low High
per foot $0.20 $0.35
minimum $250 $700
fluid movement and may point out areas that need to be investigated
using other logging techniques.
There are many disadvantages to using a cement bond log. First,
the log cannot be used to find leaks or determine actual fluid
movement behind the casing. Second, when injection wells are
completed with tubing, the tubing must be removed before the log can
be run. However, the greatest disadvantages are the wide range of
parameters which can affect the readings and interpretation of cement
.bond logs. Cycle skipping, transit time stretching, excentering,
design of gating systems, spacing of tool transmitter-receivers, the
presence of a microannu1us, the type of borehole fluid as well as the
conditions during cementing and pressures of operation are some of the
variables which must be taken into consideration during interpretation
since they may cause a channel to be missed. Because logging tools
are not standardized, the log must be interpreted for that particular
tool and logs run by one company should not be interpreted by another.
EXAMPLES
Figure 90 is an example of a channel in the cement which was
located and solved through the use of a CBl/VDl bond log. The CBl on
the far right shows a high amplitude signal which is indicative of a
poor casing-cement bond. In the interval from 8950 to below 9050, the
VDl confirms the results of the CBl display through the presence of
straight bands delineating casing signals on the far left. After the
problem was identified, the casing was perforated and a cement squeeze
job performed. The CBl/VDl log after the squeeze indicates that the
problem has been solved as evidenced by the lower amplitude on the CBl
and the elimination of the straight bands on the VDl.
Additional examples have been included as part of the
interpretation section.
221
-------
BEFORE SQUEEZE
AFTER SQUEEZE
PIPE AMPLITUDE
(XI
<0
U1
o
.I
.
~
...-
... -'"
---..
\
I
I
"-"- after
I
.
I
I
I
,
I
I
I
I
,
I
I
<0
o
o
o
I
,
I
I
<0
o
U1
o
Figure 90. Elimination 0' a channel by cement squeezing (Walker, 1968).
222
-------
REFERENCES
Brown, H.D., V.E. Grijalva and L.L. Raymer, 1970, New developments in
sonic wave train display and analysis in cased holes; Paper presented
at SPWLA Eleventh Annual Logging Symposium, May 3-6, 1970, 24 pp.
Fert1, Walter H., P.E. Pilkington and James B. Scott, 1974, A look at
cement bond logs; Journal of Petroleum Technology, vol. 26, pp.
607-617.
Froelich, Benoit, A. Dumont, Dennis Pittman and Bruno Seeman, 1982,
Cement evaluation tool: a new approach to cement evaluation;
Journal of Petroleum Technology. vol. 34, no. 8, pp. 1835-1841.
Gearhart Industries, Inc., 1982, Basic cement bond log evaluation;
Gearhart Industries, Inc., Fort Worth Texas, 36 pp.
McGhee, B.F. and H.L. Vacca, 1980, Guidelines for improved monitoring
of cementing operations; Paper presented at the SPWLA Twenty-First
Annual Logging Symposium, July 8-11, 1980, 21 pp.
Muir, D.M. and E.E. Rollman, 1970, New look at bond logging; Petroleum
Engineer, vol. 42, no. 2, pp. 72-78.
Ransom, R.C., 1975, Glossary of terms and expressions used in well
logging; Society of Professional Well Log Analysts, Houston,
Texas, 74 pp.
Sch1umberger, no date, Cement logging: completion services;
Sch1umberger, Inc., Houston, Texas, 53 pp.
SCh1umberger, 1976, The essentials of cement evaluation; Sch1umberger,
Inc., Houston, Texas, 11 pp.
Walker, Terry, 1968, A full-wave display of acoustic signal in cased
holes; Journal of Petroleum Technology, vol. 20, no. 8, pp.
811-824.
223
-------
SECTION 18
OTHER MECHANICAL INTEGRITY TESTING METHODS
INTRODUCTION
In addition to the methods described in previous chapters, there
are several other methods which could potentially be useful in testing
the mechanical integrity of an injection well. This chapter briefly
summarizes these methods, which are either so highly specialized or so
new that limited or no field data are available to assist in
evaluating their usefulness. Some of these methods are variations of
existing logging methods and others are applications of methods from
other fields. With additional laboratory and field testing, some of
the methods described in this chapter could prove very useful in
mechanical integrity testing.
NATURAL GAMMA LOGGING
Natural gamma logging measures the natural gamma radiation of
formations adjacent to the we11bore, and is one of only a few
techniques which can be utilized to log through casing. Changes in
the intensity of natural gamma radiation are commonly associated with
lithologic changes. Shale or clay. for example, emit more natural
radiation than a clean quartz sand. This phenomenon is due to the
presence of higher concentrations of potassium, thorium or uranium
isotopes in clay-rich deposits. As these isotopes decay, they emit
gamma radiation that can be detected by a natural gamma logging tool.
Campbell (1951) noted the occurrence of increased natural
radioactivity in zones of perforations in producing oil wells. He
attributed this phenomenon to the presence of a "radioactive crust"
that forms from the buildup of mineral scale resulting from the
reaction of salt water with iron oxides in metal well casings.
Natural gamma logs have been successfully used to locate such zones in
producing wells in which appreciable quantities of salt water are
produced along with petroleum.
Killion (1966) suggests that similar naturally radioactive
deposits can result from prolonged fluid migration in channels in the
cement behind well casing, and further suggests that these deposits
can be logged using gamma logging techniques. By correlating a
recently run natural gamma log with a previously run gamma log and
electric log, Killion was able to detect what he interpreted to be
zones of fluid migration outside the casing of a producing oil well.
224
-------
Figure 91 shows an anomaly which appeared in a producing well over the
course of six years, as the well produced increasing amounts of water.
The well was taken out of service and a new gamma log run and then
compared to previously run gamma and electric logs. In the interval
from about 7775 feet to 7850 feet, a radioactive anomaly was noted.
This was determined to have been caused by a radioactive crust formed
as salt water from a salt water sand at 7760 to 7775 feet channeled
through the well bore into the production zone at 7852 to 7858 feet.
In this case, the well was rehabilitated and brought back to
water-free production (Killion, 1966). Keys (personal communication,
1983) notes that for this method to be successful, any comparison of
gamma counts must be done either using the same probe or normalizing
the response of a different probe.
While this logging technique has not been reported as having been
used in injection well applications, clearly the same principles apply
and the technique could be useful in wells for which a baseline gamma
log is available. However, because no work has been done in this area
since the initial work of Killion, additional field testing of this
method would be desirable.
CONTINUOUS OXYGEN ACTIVATION LOGGING
Wichmann et a1. (1967) reported on a method for determining the
presence of fluid flow behind casing that utilized the principle of
oxygen activation. This technique involves the "tagging" of any fluid
containing oxygen (016) by making it radioactive; in effect, this
amounts to using oxygen as a tracer. When an 010 atom is irradiated
with neutron radiation from a downhole source, the atom transmutes
into a radioactive nitrogen (N16) atom. The N16 atom decays with
a half-life of 7.13 seconds, emitting a beta particle and high-energy
gamma radiation that can be detected by a gamma ray detector.
This principle was utilized by Paap and Arnold (1977) and Paap et
a1. (1977) in the development of a water flow monitoring system that
measures the direction, linear flow velocity, volumetric flow rate and
radial position of water flowing vertically behind casing. The system
utilizes a neutron radiation source which pulses neutron radiation
outward in all directions (Figure 92). A pair of longitudinally
spaced gamma ray detectors is used to detect the movement of
irradiated 016 behind the casing in a manner similar to that used in
radioactive tracer techniques (Section 16). The flow parameters of
interest are computed from the energy and intensity response of the
detectors. Oxygen activation differs from other tracer techniques in
the sense that the tracer, N16, is "manufactured" in the water
(Arnold and Paap, 1979). This essentially eliminates several of the
disadvantages of using radioactive tracers (i.e. handling of
radioactive materials). and allows for a more quantitative description
of flow parameters than is possible with conventional tracers (Arnold
and Paap, 1979).
225
-------
GAMMA RAY
ELECTRICAL LOG
Figure 91. Comparison of an old gamma log with a more recent gamma log and electric log
run in the same well (Killion, 1966).
226
-------
D
Detector 2
Detector 1
D ~
o
u::
"-
OJ
iij
3:
Shield
o
Source
Figure 92. Dual-detector flow sonde and hypothetical channel water flow
(Arnold and Paap, 1979).
227
-------
Field testing of this technique has proven promising, but it is
not yet, at the time of printing of this report, widely available
through well service companies.
MAGNETIC CASING LOGGING
Patterson et al. (1971) describe a system developed for logging
tension-type casing failures in steam injection wells. The system was
developed after it was noted that during borehole television surveys
of these wells, distortion of the picture on the television monitor
would occur when the downhole camera passed by tension failures in the
casing. The actual theory behind the operation of the device is
complicated, but in simple terms depends upon the fact that a well
casing acts like a very long magnet, with the bottom of the casing
acting as one pole and the top of the casing acting as the other pole.
When a tension failure occurs and the casing is separated, the
once-long single magnet is broken into two smaller pieces. The
magnetic lines of flux produced by the casing separation set up an
external magnetic field across the separation; this anomaly can be
detected by a tool which operates in a manner similar to that of a
casing collar locator. The tool utilizes a search coil which, when
passed through a magnetic field, generates a voltage that is sent to
the surface via a shielded wireline. An example of the resulting log,
which plots the magnitude of the voltage created when the tool passes
through a magnetic field with respect to depth, is shown in Figure 93.
Several magnetic casing logging tools were tested by Patterson et
al. (1971) under field conditions in steam injection wells. The final
design of the tool which was developed for field use is shown in
Figure 94. This tool was designed to fit through standard 2 3/8-inch
injection tubing, and thus could be used in a well without removing
the tubing. However, the tool can only detect areas of the casing
which have pulled apart (or nearly so) and casing collars; it does not
detect minor casing flaws or vertical splits. Thus, its applications
in mechanical integrity testing appear to be limited.
VOLUMETRIC SCANNING
Broding (1981) describes a process of measuring the physical
response of rock formations or well casing in a borehole by scanning
with high-frequency acoustic energy in the lateral, vertical and
azimuthal directions. The method of operation of the volumetric
scanning (VS) survey is similar to that of the borehole televiewer
(Section 14), in which an acoustic transducer is rotated in a well at
three revolutions per second and pulsed at 485 times per revolution.
The VS differs from BHTV in that it pulses acoustic energy at 512
times per revolution and it utilizes three scans: a rotational scan
and a depth scan like the BHTV, and an outward scan which provides a
third dimension. The acoustic signal is reflected off the casing wall
back to the transducer, where it is received; the resulting signal,
228
-------
1 1 I
. !
! I
I
I I
~ DEPTH -
I MARKER
-500-
I I I
I
\: I I
TENSION FAILURE
I
I I i I I
I - 550 -
, .... ~ ---~ ! I
--
\- --- --- h-
I
~...,...-
I~ - - 600
- t--- C7
'
I i
I I /
! I ! I V
i /
I ~ I ~! V
/
I /- 650
/
V
/
,/
/'
V
... '/
, - 700 -
I I
I I I
CASING COLLARS
(TYPICAL)
OTHER TENSION
FAILURES
Figure 93. Log depicting results of a magnetic casing log (Patterson et al., 1971).
229
-------
N
Co)
o
TOP
SUB
214 a-RING (2) PLACES
CONTACT NON-MAGNETIC
SPRING TOP SPACER &
INSULATOR
NON-MAGNETIC
COIL BOTTOM SPACER
214 a-RING (2) PLACES
SINKER BAR ~
ANCHOR I
Figure 94. Final design of the magnetic casing logging tool (Patterson et a!., 1971).
-------
which consists of both signal amplitude and travel time, is recorded
on magnetic tape at the surface. The recorded image of casing
reflectance has the general appearance of a true three-dimensional
image of the well casing. The image can be tilted at different angles
(Figure 95) or rotated (Figure 96) to assist in the interpretation of
the casing image. This results in the capability of essentially
holding the casing in the viewers' hand and viewing it from all
directions (Broding, 1981).
While Broding has successfully applied the VS to casing
inspection with success, the use of this technique is limited by lack
of additional field applications and inavai1abi1ity of equipment.
HELIUM LEAK TEST
Dewan (1983) describes a method of leak testing that utilizes
helium, an inert, non-toxic, relatively inexpensive gas that readily
diffuses through microscopic leaks because of its small molecular
size. The testing procedure consists of pressurizing an enclosure to
be tested (i .e. and injection well casing or tubing) with a mixture of
he1 ium and air to above atmospheric pressure and then "sniffing" the
outer surface of the enclosure with a probe capable of sensing very
low concentrations of helium (i.e. 1 part per million) in air. While
this testing method is utilized in other applications, it has not been
applied to mechanical integrity testing of injection wells.
A method for testing injection wells utilizing this technique has
been proposed by Dewan (1983):
After the well is taken out of service, a mixture of 90 percent
nitrogen (or air) and 10 percent helium would be injected into the
tubing at about 1000 psi pressure in a quantity sufficient to fill the
well to a point just below the packer. About 50 cubic feet of gas
mixture would be required for a 2000-foot well with 2-inch tubing, and
about 12 hours would be required for the helium to displace the water
in the tubing into a formation normally taking 50 barrels per day. As
the helium/water interface progresses downward, any tubing leak
encountered would allow helium to enter the casing-tubing annulus.
The helium would diffuse upward and collect at the top of the annulus,
where it could be detected with a gas detector probe. Once the
helium/water interface reaches a level below the packer, any leak
through the packer in the casing-tubing annulus or in the cement in
the casing-borehole annulus would likewise allow helium to enter the
annulus, diffuse upward, and be detected. Figure 97 shows the helium
leak test arrangement proposed by Dewan for so-called "non-standard"
injection wells (i.e. those in which casing does not extend to total
depth) .
Because water will dissolve helium, it will hinder the diffusion
of helium to the surface. Dewan (1983) notes that the solubility of
231
-------
1010'
998'
30°
Figure 95. Casing damage: tiled polar image (Brading, 1981).
15°
232
-------
Figure 96. Casing damage: polar scanning with sectioning and rotation (Broding, 1981).
233
-------
Valve (Closed)
- -
- - - -
~ ---
- --
Water Injection Line
Valve (Open)
90% Air or Nitrogen plus -
10% Helium (at -1,000 psi)
rr:
Pressure gauge
Helium Probe
Plastic Shroud
Tubing
0- Water
0-
0-
0
-
0-
0
,- I I
I I
-I 10_1
0-
Helium Leak in
Packer and Cement
Figure 97. Proposed helium return leak-test arrangement (Dewan, 1983).
234
-------
helium in water, at atmospheric pressure and 86°F, is 0.84 cubic feet
of helium per 100 cubic feet of water, and that the solubility
increases in direct proportion to the pressure. He estimates that the
rate at which excess helium would progress upward through a column of
water is about 2000 feet per hour. The optimum situation is that in
which there is no water or other fluid in the annulus, only air, but
this is uncommon in injection well operations.
While helium leak testing is among the most sensitive leak
detection systems known and it is employed in many other applications,
its usefulness in mechanical integrity testing of injection wells is
not proven. Both laboratory and field testing would be necessary to
establish this as a viable technique for testing injection well
i ntegri ty.
ON-SURFACE TUBING INSPECTION
Prior to running some of the logs discussed in this report, it is
required that the injection tubing be removed from the well. While
the tubing is at the surface, it can be inspected by anyone of
several methods.
One device, described by Haul dren (1977) inspects tubing for
stress cracks and f1 aws as it is pull ed from the well. Thi s device
utilizes a series of ultrasonic search units that each send acoustic
energy through the tubing. Receiving transducers are stabilized and
kept at the proper detection angles by a series of tension wheels.
The transducers detect discontinuities both transverse and parallel to
the longitudinal axis of the tubing. Wall thickness of the tubing is
also detennined.
Another type of testing method, described by Tompkins (1972)
provides an overall detennination of the quality of the tubing. It
uses a gamma radiation detector positioned inside the tubing and a
gamma radiation source, which pulses gamma rays as the tubing is
rotated and pulled through the detector, on the outside of the tubing.
Flaws and weak areas in the tubing are determined by comparing the
amount of radiation detected at the probe against a standard for a
given wall thickness.
Suman and Ellis (1977) describe a method refered to as the
electromagnetic diverted flux search coil testing system. The
principle behind this system is relatively complex, but is similar to
that described for the electromagnetic casing inspection methods
outlined in Sections 10 and 11. A magnetic flux field is induced into
the wall of the tubing. The field flows in one direction through the
tubing and diverts around any imperfections (Figure 98). Search
coils, as shown in Figure 99 detect these diversions in the induced
magnetic field and record the magnitude and pattern of the diversion
(Suman and Ellis, 1977).
235
-------
Longitudinal Imperfection with Flux Leakage,
I
Search Coil Transducer
I
c:
o
<0
'0
II:
Magnetic Source
Pipe
Figure 98. Diagram of transverse electromagnetic diverted flux search coil system
(Suman and Ellis, 1977).
236
-------
Electric Coil
-;:: ~ - --
1,,/-------
\ It I
\ \
\. ..
longitudinal Magnetic Field
Search Coil Transducer
\
~-
\
. ~~
: 'l
Transverse Imperfection
Figure 99. Diagram of longitudinal EDFSC system used to detect transverse imperfections
(Suman and Ellis, 1977).
237
-------
Variations in metallurgical properties of tubing can be detected
using electronic metal comparitors, which electronically compare
induced electromagnetic eddy currents in the tubing with the response
of a known grade of material used as a standard. Variations in the
balance between the standard and the injection tubing indicate a
change in the metallurgical properties of the tubing. This method
only provides a qualitative measure of differences in tubing
properties and does not define the extent or magnitude of any problem
present (Suman and Ellis, 1977).
PHOTOGRAPHIC LOGGING
Photographic logging was originally developed to locate and
evaluate fractures in the uncased portion of wells (Dempsey and
Hickey, 1958). With refinements in the techniques and equipment,
photographic logging has been used for detailed casing inspection.
Photographic logging produces a "snapshot" photographic image
using a light source, a borehole camera, and light-sensitive film.
The image is actual documentation of the condition of the casing
rather than derived information. A simple visual examination of the
problem provides valuable information often lacking when conventional
logging techniques are used.
Borehole cameras have become nearly obsolete with the advent of
newer technology, such as the borehole television (Section 13) or the
borehole televiewer (Section 14), but they may still be useful for
specialized applications in injection wells.
There are several types of borehole cameras available for use in
inspecting the inside surface of the well casing. They are, from the
simplest to the most complex:
1) monocular - single-shot camera,
2) monocular - multi-shot camera,
3) stereoscopic - single-shot camera, and
4) stereoscopic - multi-shot camera.
The actual design of borehole cameras varies greatly from
manufacturer to manufacturer but the basic principle of their
operation is the same. The camera operates by means of a shutter that
exposes photographic film to a properly illuminated image. An image
reflects light rays toward a camera and the reflected light rays enter
the camera lens. As the reflected light rays move through the lens
they are focused onto the film plane. An iris, located within the'
lens, reduces the amount of light that strikes the film plane
commensurate with the speed of the shutter opening and closing and the
speed of the film.
238
-------
In an injection well, lighting is generally provided by a
syncronized electronic flash mounted just below or just above the
camera lens. The field of vision (or focal length) and focus are
adjusted manually at the surface for optimum picture quality and
clarity based on the well design and its condition.
Film size varies, depending upon the type of camera (single-shot
or multi-shot) and the physical size of the camera. Film disks (1
inch diameter) are generally used in single-shot cameras while Bmm,
10mm, 16mm or 35mm film magazines are used in multi-shot cameras. The
film magazines are advanced through the film plane by means of an
electronic motor drive. Film magazines range in length from a few
dozen shots to up to 600 shots per magazine.
The camera system can be activated either by means of an internal
timer system or electronically through a connecting cable. For
single-shot cameras, the camera must be retrieved from the well and
reloaded at the surface after each shot. Multi-shot cameras
automatically advance the film and cock the shutter after each
photograph.
Camera sizes range from 1.25 inches OD to 3 inches OD. The
length of the camera varies from 1 foot to several feet. Cameras are
manufactured of corrosion-resistant material, such as stainless steel;
most are pressure-rated to 15,000 psi.
Stereoscopic cameras vary only slightly from monocular cameras.
In the case of stereoscopic cameras, two photographs are
simultaneously taken of the same image, from two slightly different
viewing angles. The resulting photographs, when viewed together
through a special viewer are seen as a three-dimensional image.
There are several disadvantages to using the borehole cameras in
an injection well. The fluid in the well must be clear for the camera
to produce a useful image. In addition, the survey cannot be
conducted in high-temperature environments, as high temperatures
deteriorate the film quality; the maximum operating temperature for
most cameras is approximately 200°F. Also, the results of the log are
dependent upon retrieval of the camera and proper film development.
Photographic logging cannot provide information about the condition of
the outside surface of the casing or the condition of the cement
behind the casino It can, however, provide evidence of casing damage
and internal corrosion, and it is possible to recognize a leak.
239
-------
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240
-------
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241
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242
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3,683,187, August 8, 1972.
Walker, Terry, 1968, A full-wave display of acoustic signal in cased
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Warner, Don L., 1975, Monitoring disposal well systems; U.S.
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248
-------
Warner, D.L. and J.H. Lehr, 1977, An introduction to the technology of
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Witterholt, E.J. and M.P- Tixier, 1972, Temperature logging in
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11 pp.
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249
-------
APPENDIX A
TABLES USED TO ESTIMATE THE VOLUME OF LIQUID
LOST FROM A WELL (IN GALLONS) FOR A GIVEN
ANNULUS PRESSURE CHANGE
(LANGLINAIS, 1981)
TABLE A-1. FLUID LOSS IN GALLONS VS. PRESSURE DROP IN 7" (6.366" ID) x
4.5" ANNULUS (GALLONS) (LANGLINAIS, 1981)
"Ci5
E;
Q)
...
:J
!II
!II
Q)
D::
c
Q)
C)
c
CtI
.c
()
10
25
50
100
200
300
400
1,000
.039
.098
.196
.391
.782
1.173
1.563
Depth (Feet)
2,000 3,000
.078 .116
.193 .288
.388 .577
.773 1.150
1.547 2.301
2.320 3.451
3.092 4.599
4,000
.154
.381
.765
1.524
3.048
4.572
6.094
5,000
.192
474
.952
1.898
3.795
5.693
7.587
250
-------
TABLE A-2. FLUID LOSS IN GALLONS VS. PRESSURE DROP IN 7" (6.366" ID) x
4" ANNULUS (GALLONS) (LANGLINAIS, 1981)
'iij
S
Q)
...
:J
UI
UI
Q)
...
a..
10
25
50
100
200
300
400
1,000
.044
.109
.219
.437
.874
1.312
1.749
Depth (Feet)
2,000 3,000
.086 .128
.216 .320
.432 .643
.863 1.283
1.728 2.568
2.593 3.853
3.456 5.136
4,000
.169
.424
.851
1.699
3.401
5.103
6.802
5,000
.211
.528
1.059
2.115
4.233
6.351
8.466
E
Q)
OJ
c:
<\I
s::.
()
TABLE A-3. FLUID LOSS IN GALLONS VS. PRESSURE DROP IN 7" (6.366"ID) x
3.5" ANNULUS (GALLONS) (LANGLINAIS, 1981)
'iij
a.
Q)
...
:J
UI
UI
Q)
...
a..
c:
10
25
50
100
200
300
400
1,000
.048
.118
.236
.470
.940
1.410
1.879
Depth (Feet)
2,000 3,000
.094 .140
.232 .345
.466 .692
.929 1.379
1.856 2.757
2.785 4.136
3.711 5.512
4,000
.185
.457
.916
1.826
3.649
5.4 75
7.296
5,000
.230
.568
1.139
2.272
4.540
6.812
9.077
Q)
OJ
c:
<\I
s::.
()
251
-------
TABLE A-4. FLUID LOSS IN GALLONS VS. PRESSURE DROP IN 7" (6.366"ID) x
27/." ANNULUS (GALLONS) (LANGLINAIS, 1981)
.Iii
~ 10
~ 25
:;)
~ 50
Q)
It 100
c
-; 200
0)
~ 300
~
o 400
1,000
.051
.128
.257
.512
1.025
1.537
2.048
Depth (Feet)
2,000 3,000
.101 .150
.253 .375
.507 .752
1.011 1.501
2.022 3.002
3.033 4.502
4.043 6.001
4,000
.199
.497
.996
1.986
3.972
5.957
7.941
5,000
.247
.618
1.238
2.470
4.940
7.411
9.878
TABLE A-5. FLUID LOSS IN GALLONS VS. PRESSURE DROP IN 7" (6.366"ID) x
23/." ANNULUS (GALLONS) (LANGLINAIS, 1981)
.~ 10
~ 25
:;)
~ 50
Q)
It 1 00
c
Q) 200
g> 300
<0
<3 400
1,000
.055
.136
.271
.540
1.080
1.621
2.160
Depth (Feet)
2,000 3,000
. 1 08 . 160
.268 .397
.534 .792
1.066 1.583
2.131 3.163
3.198 4.746
4.261 6.324
4,000
.211
.525
1.048
2.094
4.185
6.278
8.366
5,000
.263
.653
1.304
2.604
5.205
7.808
10.406
252
-------
TABLE A-6. FLUID LOSS IN GALLONS VS. PRESSURE DROP IN 5112" (4.892" ID) x
2W' ANNULUS (GALLONS) (LANGLINAIS, 1981)
"(jj
a.
CD
...
::J
'"
'"
CD
...
a..
c:
10
25
50
100
200
300
400
1,000
.026
.064
.127
.255
.509
.764
1.019
Depth (Feet)
2,000 3,000
.050 .075
.125 .186
.251 .373
.503 .746
1.005 1.493
1.509 2.240
2.011 2.986
4,000
.099
.247
494
.988
1.976
2.964
3.952
5,000
.123
.307
.614
1.229
2.458
3.688
4.917
CD
C>
c:
10
~
()
TABLE A-7. FLUID LOSS IN GALLONS VS. PRESSURE DROP IN 5112" (4.892" ID) x
2%" ANNULUS (GALLONS) (LANGLINAIS, 1981)
"(jj
a.
CD
...
::J
'"
'"
CD
Il:
c:
10
25
50
100
200
300
400
1,000
.029
.071
.142
.283
.565
.848
1.130
Depth (Feet)
2,000 3,000
.057 .085
.140 .208
.279 .414
.558 .828
1.115 1 .655
1.673 2.483
2.230 3.310
4,000
.112
.275
.548
1.096
2.189
3.285
4.379
5,000
.140
.343
.682
1.363
2.723
4.086
5.446
CD
C>
c:
10
~
()
253
-------
TABLE A-8. FLUID LOSS IN GALLONS VS. PRESSURE DROP IN 5" (4.408" ID) x
23/," ANNULUS (GALLONS) (LANGLINAIS, 1981)
"~ 10
~ 25
::J
::: 50
Q)
Q: 1 00
c
Q) 200
~ 300
-------
1000
900
800
700
600
500
400
300
200
100
in
a. 0
w
~
w -100
Q:
'"
~
:; -200
c
c
..
-300
-400
-500
-600
-700
-800
-900
-1.000
-1.'00
-'.200
-1.300
-'400
APPENDIX B
GRAPHS WHICH DEPICT THE RESPONSE OF ANNULUS PRESSURE TO
INJECTED FLUID TEMPERATURE FOR VARIOUS WELL CONFIGURATIONS
(LANGLINAIS, 1981)
1.000'
3.000'
5.000'
40
50
65
95 100 105 1'0 115 120
70
75
80
85
90
55
60
45
Injected Waste Surface Temperature (" F)
Figure B-1. Response of annulus pressure to injected fluid temperature for 7" tubing x
95/8" casing x 12114" borehole (Langlinais, 1981).
255
-------
1.000
900
800
700
600
500
400
300
200
100
iii
~ 0
Q)
5
'"
'"
Q) -100
0:
'"
2
::J -200
c
c
«
-300
-400
-500
-600
-700
-800
-900
-1.000
-1.100
-1.200
-1.300
-1.400
2.000'
4,000'
6,000'
40
50
45
55
60
65
70
75
80
85
110
115
100
105
120
90
95
Injected Waste Surface Temperature (0 F)
Figure 8-2. Response of annulus pressure to injected fluid temperature for 3112" tubing x
7" casing x 8W' borehole (Langlinais, 1981).
256
-------
1000.
900
800
700
600
500
400
300
200
100
in
e:. 0
~
:0
-------
1.000
900
600
700
600
500
400
300
200
100
in
~ 0
QJ
:;
-------
1.000 1,000'
900
800
700
600 3,000'
500
400
300
200
100
in
~ 0
5,000'
:;
-100
Q:
.2
:0 -200
c:
c:
-------
1.000
900
800
700 2,000'
600
500
400
300 4.000'
200
100
v;
~ 0
[1'
ii:
-------
1.000
1,000'
900
800
700
3,000'
600
500
400
300
200
100
iii
~ 0 5,000'
~
:J
'" -100
a:
:J
:; -200
c:
c:
«
-300
-400
-500
-600
-700
-800
-900
-1.000
-1.100
-1.200
-1.300
-1.400
40 45 50 55 60 65 70 75 80 85 90 95 100 105 110
Injected Waste Surface Temperature (0 F)
Figure B-7. Response of annulus pressure to injected fluid temperature for 'PIe" tubing x
7" casing x 8112" borehole (Langlinais, 1981).
261
-------
1000
900
800
700
600
500
400
300
200
100
;;;
c::. 0
"'
'5
V>
V>
"' -100
Q:
V>
~
:0 -200
c:
c:
<::
-300
-400
-500
-600
-700
-800
-900
-1.000
-1.100
-1.200
-1.300
-1400
2,000'
4.000'
6.000'
40
50
95
100
105
65
45
55
60
70
80
75
85
90
Injected Waste Surface Temperature (0 F)
Figure 8-8. Response of annulus pressure to injected fluid temperature for 'PI," tubing x
5112" casing x 63/4" borehole (Langlinais, 1981).
262
-------
1.000
1,000'
900
800
700
600 3,000'
500
400
300
200
100
in
~ 0
OJ 5,000'
:;
'"
'"
OJ -100
0:
'"
~
:; -200
c
c
«
-300
-400
-500
-600
-700
-800
-900
-1,000
-1.100
-1,200
-1.300
-1.400
40 45 50 55 60 65 70 75 80 85 90 95 100 105
InJected Waste Surface Temperature (0 F)
Figure 8-9. Response of annulus pressure to injected fluid temperature for 2W' tubing x
7" casing x 8112" borehole (Langlinais, 1981).
263
------- |