FINAL REPORT
MECHANICAL INTEGRITY TESTING
OF
INJECTION WELLS
Contract No. 68-01-5971
Submitted to
Dr. Jentai Yang
Office of Drinking Water
Mr. Thomas F. Sullivan
Contract Operations
Prepared for
U. S. ENVIRONMENTAL PROTECTION AGENCY
OFFICE OF DRINKING WATER
By
Geraghty & Miller, Inc,
April 30, 1980
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FINAL REPORT
MECHANICAL INTEGRITY TESTING
OF
INJECTION WELLS
Contract No. 68-01-5971
Submitted to
Dr. Jentai Yang
Office of Drinking Water
Mr. Thomas F. Sullivan
Contract Operations
Prepared for
U. S. ENVIRONMENTAL PROTECTION AGENCY
OFFICE OF DRINKING WATER
By
Geraghty & Miller, Inc.
April 30, 1980
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TABLE OF CONTENTS
Page
ACKNOWLEDGMENTS iii
EXECUTIVE SUMMARY . . iv
INTRODUCTION 1
METHODOLOGY . 2
COMPANIES AND ORGANIZATIONS CONTACTED 3
LEAKS ' 4
Pressure Testing 4
Other Surveys 8
ADEQUACY OF WELL RECORDS 9
COSTS FOR PRESSURE TESTS 10
RESULTS OF LOGGING 14
Sonic Log 16
Neutron Log . . 18
Density Log 20
Temperature Log 22
Cement Bond Log 24
VDL Log 27
Noise Logging 32
Tracer Log 36
COSTS 37
ELEMENTS OF STATE UIC PROGRAMS RELATED TO WELL INTEGRITY. 41
Regulatory Approach 42
Pre-permitting Engineering Report 48
Logs and Surveys 49
Monitoring of Well Integrity 49
Periodic Well Testing Programs 51
SELECTED REFERENCES 55
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FIGURES
Page
FIGURE 1:
FIGURE 2:
FIGURE 3:
FIGURE 4:
Temperature Log Signatures
Liquid Flow
Variable Density Log Display . . ,
Typical Bond Log and VDL Displays
Typical Noise Log Display . . . ,
25
29
30
33
TABLES
TABLE 1:
TABLE 2;
Summary of Various Logs and their
Applicability to Detecting Fluid
Movement Behind Casing .
Well Integrity Elements of State
UIC Requirements
38/39
43
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ACKNOWLEDGMENTS
This report was prepared under the direction
of Mr. Vincent P. Amy, Senior Scientist, Geraghty
and Miller, Inc., for the Office of Drinking Water.
The EPA Task Manager was Mr. Paul M. Beam. Mr. Amy
was assisted by Mr. Oliver C. Lewis, Drilling
Specialist, and Nola Gillies, Regulatory Analyst,
of Geraghty and Miller, Inc.
111
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EXECUTIVE SUMMARY
The various logging techniques used in determining mech-
anical integrity are widely employed and were developed for
this purpose. They were designed to enable man to detect
evidence rather than observe conditions which cannot be seen
first hand. In effect, they are an indirect measurement and
are indicators of a condition. They measure something elec-
tronically: temperature, sound velocity, noise levels, etc.
Thus, the data interpretation is subjective and dependent on
the skills and experience of the operator, in contrast to a
pressure test which is a more direct, readily observable
indicator of a condition.
Experience shows that the presence of a condition is often
discovered by weight of evidence. In many cases, the results
of a single survey produce unclear and somewhat confusing
results, and additional, different surveys clarify and confirm
the results of the first. In any case, a program for determining
mechanical integrity should be kept flexible to provide the
greatest benefit. Also, the logs described in this report are
regarded as the best for the purpose. However, flexibility must
be provided to permit the use of other surveys to permit collec-
tion of evidence offering the clearest indication that a problem
exists. For example, a tracer survey could be used to determine
iv
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the adequacy of the cement at the bottom of the casting by
detecting fluid movement at that point. Abnormally high
radioactivity would be detected above the casing shoe. This
could only occur when the cement seal at the casing shoe is
poor, permitting fluid to leak upward.
Similarly, surveys such as noise, temperature, and
tracer logs could be substituted for pressure testing.. Economics
would play an important role. While the pressure tests yield
more positive results, it may be more economical for the opera-
tor to substitute the appropriate log or logs. The evidence
will be less direct, but the burden of proof should be on the
operator to demonstrate conclusively that his well possesses
the required integrity.
Cost of pressure tests and wire-line surveys range widely
depending on various factors such as depth of well, distance from
service center, presence or absence of tubing and packer, type
of survey, time factors, and general site conditions. For
example, under certain conditions, pressure tests could range
from about $400 to more than $7,000. Likewise, some types of
wire-line surveys for common injection well depths (2,000-
6,000 feet) may range from $1,500 to $2,800.
Continuous monitoring of annulus pressure and regular
checks of injection pressure are now the common means of mon-
itoring well integrity during operations that are required by
requlations in the 12 states surveyed. Of these states, Cali-
fornia, Illinois, New York, Michigan, and Oklahoma require
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periodic well integrity testing. The majority of the 12
states require the submission of data on casing, cementing,
tubing, and packers as part of the pre-permitting report to
assure that integrity is designed into an injection well.
There appears to be little distinction among classes of wells
in the regulations of these states.
VI
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INTRODUCTION
Section 146.08 of the proposed State Underground Injec-
tion Control Program (40 CFR Part 146, Federal Register,
Volume 44, No. 78, April 20, 1978) concerns the mechanical
integrity of injection wells. According to the proposed
rules, an injection well has mechanical integrity if: (1)
there is no significant leak in the casing, tubing, or packer;
and (2) there is no significant fluid movement in,to an under-
ground source of drinking water through vertical channels
adjacent to the injection well bore. The rule also states
that some combination of a number of tests shall be used to
evaluate the absence of significant leaks. A list of these
tests is contained in Section 146.08. The section also des-
cribes means by which the absence of fluid movement may be
demonstrated. These are: (1) well records demonstrating the
presence of adequate cement to prevent such migration; or (2)
the results of a cement bond log, sonic log, temperature log,
density log, or dual neutron log.
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On October 16, 1979, Geraghty & Miller, Inc., received
approval from the U. S. Environmental Protection Agency to
commence work on Contract 68-01-5971, Work Assignment #1,
dealing with identifying and evaluating methods used by in-
dustry and regulatory agencies to determine the two aspects
of mechanical integrity. In particular, the tests described
in' Section 146.08 were to be evaluated, along with others
that could be employed.
The costs for performing the various surveys and tests
referred to in this report are expressed in 1977 dollars.
These were computed by converting the costs in 1979 dollars
using the Consumer Price Index (CPI). These are based on
a December 1979 CPI of 229.9 and a December 1977 CPI of 186.1.
Thus, the conversion was accomplished by dividing 1979 costs
by 1.235 (229.9-7186.1) to yield the estimated cost in 1977
dollars.
METHODOLOGY
To accomplish the objectives of Work Order #1, experienced
Geraghty & Miller personnel contacted and interviewed repre-
sentative of a number of service companies in the oil industry,
drilling contractors, and regulatory agencies. Information
was obtained on methods of costs for preparing and performing
the various tests used to determine mechanical integrity.
Senior personnel of companies recognized as experts in the
field were contacted or interviewed as part of the data
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collection process. Technical manuals, service catalogs,
and pricing schedules were obtained from the major companies
who perform the various surveys used in determining mechni-
cal integrity. Various state regulatory agencies also were
contacted and pertinent information collected. In addition,
the firm's library and files on the subject were researched
and utilized.
COMPANIES AND ORGANIZATIONS CONTACTED
Information used in preparing Task Order #1 was obtained
from the following companies .and organizations:
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Schlumberger Well Services
We lex
The Western Company
The East Texas Brine Disposal Company
Dowell Division of Dow Chemical Company
NL McCullough
Birdwell Division
Dresser Atlas
GO Wireline Services, Division of Gearhart Owens
Industries
Progress Drilling and Marine
Kansas Department of Health, Division of Environment
California Division of Oil and Gas
Oklahoma Oil and Gas Division
Ohio EPA, Legal Services Department
Texas Department of Water Resources, Geological
Services
Texas Department of Water Resources, Underground
Injection Unit
Nuclear Regulatory Commission
Ohio River Valley Sanitation Commission
Illinois EPA
Pennsylvania Bureau of Water Quality Management
Pensylvania DER, Division of Oil and Gas
New York Department of Pure Waters, Industrial
Programs Division
New York Department of Environmental Control
Louisiana Department of Conservation
LEAKS
Pressure Testing
According to Section 146.08, an injection well has mechan-
ical integrity if there is no significant leak in the casing,
tubing, or packer. "Significant" is not defined. Both industry
and regulatory agencies utilize and/or require pressure testing
of the various components such as casing, tubes, and packers as
a means of determining the presence of leaks. One accepted
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means of defining a significant leak, which is used as a guide-
line by industry, deals with pressure testing. Typically, a
test pressure equivalent to 125 percent of the design operating
pressure is applied. The test is judged to be successful, and
no significant leaks are deemed to be present, if any pressure
loss or bleed off stabilizes at a point equal to or greater
than the design operating pressure and does not fall below that
value. Normally, pressure tests are performed for periods of
time ranging in duration from five to thirty minutes. If the
pressure falls below the design value, the test is judged to
be a failure; a significant leak exists and remedial measures
are taken to fix it. The State of California requires that a
loss in pressure must not exceed ten percent of the test pres-
sure (for casing tests) during thirty minutes and that correc-
tive measures must be taken until a satisfactory test is ob-
tained. A set of test specifications is set forth by the
state. A set of test specifications is set forth by the state.
California also requires that tubing, plugs, and packers hold
pressure; otherwise a leak is presumed to exist.
Consideration of the various tests and procedures descri-
bed in Section 146.08(b)(1) reveals that their principal purpose
is the location of leaks rather than their detection. Aside
from the various pressure tests (Items 2, 5, and 8), the remain-
ing surveys are primarily tools for locating leaks once it is
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known that they exist. Also, interpretation of the data from
many of these tests is somewhat subjective, whereas pressure
tests produce results that are simple and easy to interpret.
Pressure testing is also economical (comparatively speaking)
and relatively easy to perform in both old and new injection
wells. For these reasons, pressure testing of the casing,
tubing, and packer is considered the principal, most reliable
means of determining mechanical integrity (leaks). The reliance
on pressure testing by industry and its requirement by the
various regulatory agencies attests to this fact.
Pressure testing is usually performed on casing, tubing,
and packers. This would apply to Class I, II, and III wells.
Many of these wells, regardless of classification, have similar
construction characteristics. Performance of a pressure test
is controlled by construction details rather than classification
by use. The following descriptions of pressure testing are
presented in this manner.
The inner casing, or long string, in a new well is usually
pressure tested after it has been cemented and before the casing
shoe is drilled out. At that time, cement is present at the
bottom of the casing so that it is sealed. Usually the pipe is
filled with fluid and pressure is applied using the rig mud
pump, a positive displacement pump with suitable capacity, or
pumping equipment operated by the cementing company. A seal at
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the top can be effected by using blow-out preventers. In the
event a blow-out preventer is not on the well, it is a compara-
tively simple matter to seal the well head. Rig mud pumps
usually can be utilized to supply pressures up to 1,000 psi;
for greater pressures, cement pumping equipment is generally
used.
When the inner casing of an old well without tubing or
packer is tested, the bottom must be sealed with a retrievable
plug (bridge plugs or packers are used) prior to testing. The
same sources for pressure noted above can be utilized. For old
wells with tubing but no packer, the outside casing is tested
after the tubing has been pulled and a retrievable plug set.
If successful, the tubing is reinstalled; otherwise, remedial
measures are taken. Tubing is normally tested after reinstal-
lation. Usually, the tubing is installed with a seating nipple
at the bottom. A ball made of rubber-covered aluminum, steel,
or plastic is dropped into the seating nipple to seal the
bottom. It also is sealed at the top and a pressure test is
performed. The ball is then "reversed out" and the well is
ready for service.
New and old wells with tubing and packer are tested by
pressurizing. The fluid-filled annulus is pressure-tested to
determine the integrity of the casing; the tubing is tested
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in the well using a ball and seating nipple. A satisfactory
test on the annulus also indicates the integrity of the packer.
A reverse type of test is used in some instances, espec-
ially in mining applications, to determine casing integrity of
a new or used well. In this test, fluid is removed from the
casing. Sometimes, if the well is not too deep, the inside of
the casing is completely evacuated to the bottom. This must be
done with care in order to prevent casing collapse. For deep
wells, the evacuation is staged, using a bridge plug and packer.
The space between the plug and packer is evacuated and then
observed to determine whether or not fluid enters. This test
is called a dry test and will work only in those portions of
the casing opposite formations that are saturated with fluids
and are somewhat permeable.
When the pressure that the outside casing will be subjec-
ted to is low and a low hydrostatic head exists on the outside
of the casing, it can be tested by filling it with fluid. If
there is a lowering of the fluid level, a leak exists. This
test can be performed on both new and old wells.
Other Surveys
Television:
The down-the-hole television camera is classified as one
of those tools which can be used as an aid in determining the
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location of a leak. However, the equipment is not readily
available and few companies provide this service.
Monitoring of Annulus Pressure:
Annulus pressure can be monitored in wells with'tubing
and tubing and packers, along with injection pressures and
rates. If a pressure change occurs, a leak is indicated.
Continuous or frequent monitoring of annulus pressure is prob-
ably the best tool for determining mechanical integrity, pro-
viding a well's construction permits it to be done.
Radioactive Tracers, and Temperature Logs:
Surveys of this type normally are not undertaken to test
well integrity. Their most usual application is for locating
a leak after it has been discovered. In certain situations they
may be used to estimate well integrity. For example, integrity
may be estimated this way if the well has a casing but no
tubing, and cannot, therefore, be pressure tested.
ADEQUACY OF WELL RECORDS
Existing well records have limited use in determining the
adequacy of the cement sheath outside of a well casing. These
records usually contain information on the types, sizes,
weights, and lengths of casing, and the types, quantities, and
weights of cement pumped, along with additives used. By
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themselves, they do not indicate if the cement was successfully
emplaced and an effective seal was obtained. Only some means
of determining whether or not leakage is occurring can establish
this. If excellent data on annular volumes are available
(caliper and temperature logs and accurate volumetric cement
measurements), a rough estimate of whether or not an adequate
cement seal exists may be possible. This determination can be
made as follows. A temperature log is used to pick the cement
top. The amount (footage) of actual cement fill-up is calcula-
ted based on this information. If this footage exceeds the
theoretical fill-up which should have occurred, the possibility
of channelling of the cement exists and there would be a
potential for fluid movement through the channel. In this case,
other surveys would be called for such as a cement bond log, or
temperature and noise logs. In effect, well records offer clues
to, but not necessarily definitive indications of, the adequacy
of cementing.
COSTS FOR PRESSURE TESTS
Costs for pressure testing are directly related to a well's
construction details. For a new well or an existing one equip-
ped with tubing and packer, the test is simple and the cost is
not expensive. In a new well, the pressure test is performed
on the inner or long string of casing after it has been
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completely cemented in place, the cement has set up, and before
the cement at the bottom of the casing has been drilled out.
The well head can be sealed in with the blow-out preventer.
Depending on the pressure required, the rig mud pumps can be
used or the pump on the cementing equipment can be used. For
pressure testing the casing with the rig, the estimated cost
is approximately $400.00. If a cement pumper is required, the
cost is estimated to be $800.00 to $1,200.00, depending on
the amount of time the equipment is on location.
A similar cost would be incurred in performing a pressure
test on an existing well equipped with a tubing and packer.
Usually this could be done by operating personnel, using their
own or rental pumping equipment. As an example, a positive
displacement pump with a suitable capacity could be used. This
would account for the lower cost of $400.00. If a pumper is
needed, the cost could be in the range of $800.00 to $1,200.00.
Greater costs will be required to perform pressure tests
on the casing in wells with no tubing or packer or only tubing.
In the case of a well with tubing, a rig will have to be used
to pull the tubing and reset it. For a well with no tubing or
packer, it is assumed a rig will be used to set and pull a
retrievable plug. In most cases, a workover rig rather than a
standard rig is employed. This equipment is designed specifi-
cally for work of this type; it is lighter, more mobile, and
less expensive than a conventional drilling rig.
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Determination of the cost of performing pressure tests
in the above situations is complicated by the fact that there
is no such thing as a typical well. Casing depths and dia-
meters vary, as do the depths of the tubing settings. The
condition of the well is a controlling factor in how long it
takes to do a particular task. Companies doing this kind of
work charge strictly on a time and material basis for the use
of rig and crew. Similarly, companies who furnish the plugging
>
devices and related equipment charge according to complicated
schedules. Time, distance to the well, standby charges,
working depths, and the size of the tools to be used are com-
ponents of the total charge. In the event the equipment must
be used in a "hostile environment" (abnormal pressure, high
temperatures, and a corrosive fluid) additional charges are
billed. Consequently, because of the numerous variables that
would have to be considered, it is impossible to arrive at
the precise cost for pressure testing.
Some idea may be obtained by setting up some arbitrary
examples using assumptions based on a range of well depths,
distance to the well, and time required to pull tubing, set
and remove a retrievable plug, and reset the tubing. For these
examples, it is assumed it is a 300-mile round trip to the well,
the well depth ranges from 2,000 to 6,000 feet (80 percent of
injection wells are included in this depth range), rig time is
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figured at $125 per hour, and mileage charges are $1.50 per
mile. Also, it is assumed that there are minimal delays; in
this case, 8 hours of rig time due to unanticipated conditions
(site work to make the well more accessible, problems in
removing well-head equipment prior to entry, etc.). Costs due
to lost production time, use of alternative waste disposal
facilities, in-house administration and engineering associated
with any testing are not included. The same set of conditions
was used to develop costs for performing a test on a well with
no tubing, but for which a rig was required. In this case,
no rig time is needed for pulling and resetting tubing.
Costs for performing pressure tests for wells with tubing
and packer and without, based on the above assumptions, are
listed in the following table,, (Estimates are rounded to the
nearest $100.) converted to 1977 dollars.
Working Depth Estimated Costs
(feet) Tubing & Packer Without
2,000 $ 4,600 $ 4,000
3,000 $ 5,300 $ 4,300
4,000 $ 6,000 $ 4,600
5,000 $ 6,600 $ 5,000
6,000 $ 7,300 $ 5,300
It should be noted that these costs are based on no unusual
or unanticipated conditions which would cause delay and add to
the cost.
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RESULTS OF LOGGING
Section 146.08(c)(2) lists five wire-line geophysical logs
which could be used to demonstrate the absence of significant
fluid movement into an underground source of drinking water
through vertical channels adjacent to the injection well bore.
(It is understood that the vertical channels referred to are
those which may exist in the cementing annulus outside of a cas-
ing as a result of an inadequate cement job.) These logs are
cement bond, sonic, temperature, density, and neutron logs. Some
of them may not be effective or useful for determining the absence
of fluid movement, while others not on the list can be used for
this purpose. Each log on the list, as well as others which can
be used, is discussed below. The reasons for a particular log's
unsuitability for detecting fluid movement are given, as well as
a discussion of those logs which are used for that purpose.
Sonic, density, and neutron logs are not suited for detec-
ting fluid movement; the cement bond log indicates the poten-
tial for fluid movement; and the temperature log and a survey
known as a noise log can be used to detect fluid movement.
Radioactive tracers could be used, but this presumes that a
leak exists in or around the casing so that the tracer can be
introduced and its movement tracked.
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The typical record of each one of these tests is a log or
graph of the parameter being measured versus depth. The record
is a continuous one (except for most noise logs) and is either
made directly on a paper strip chart or recorded on film. In
both cases, the log is easily duplicated. Blueprints (ozalids)
are the most common form of reproduction. Two depth scales
are usually used: 5 inches equal 100 feet, and 2 inches equal
100 feet. Pertinent information on the well (depth log, casings,
dates, etc.) is contained in a heading form which is filled out
for each log.
Apparatus used in logging consists of the logging tool
itself, multi-conductor armored cable, and the electronic equip-
ment for measuring and recording the various parameters. The
equipment is usually mounted in a vehicle designed specifically
for the purpose.
A number of companies can perform these surveys as well as
a wide variety of other geophysical logging techniques. The
principal companies are Schlumberger Well Services, Welex, GO
Wireline Services, Birdwell, NL McCullough, and Dresser Atlas.
These organizations maintain offices throughout the United
States and overseas so that services can be offered with little
or no difficulty. The principal locations are in or close to
the major oil-producing areas. A number of other, smaller
companies scattered throughout the United States specialize in
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providing logging or performing the surveys as part of the
services they offer.
Sonic Log
The conventional sonic log measures the time required for
an acoustic signal to travel from a transmitter to a receiver
spaced a known distance apart. Other, special applications of
acoustic signals are used in cement bond logging. These are
treated separately and are not included in this discussion.
The logging tool, or sonde, contains both transmitters
and receivers (more than one of each is used to compensate for
bore-hole effects). The sonde is usually centered within the
bore hole by centralizing straps on the tool. While the tool
is being raised or lowered in the hole, a signal is generated,
is transmitted through the bore-hole fluid and the formation,
and is refracted back through the fluid and detected by the
receiver. The first arrival of the signal is detected, ampli-
fied, and presented on the strip chart or film. The time of
travel for the signal, expressed in microseconds per foot
(^sees/ft), is the conventional method of presentation.
The conventional sonic log is a tool used to determine
porosity. The time required for the signal to travel through
a rock formation is a function of density and porosity; dense,
non-porous rock will transmit sound much more rapidly than less
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dense, porous rocks. Given the same lithology or rock type,
the rock with the greater porosity will have the slowest
travel or transit time.
If the rock type is known, it is possible to compute its
porosity from a sonic log. Information on the transit time
for various rock types is readily available from the various
texts and literature describing sonic logging, and it is a
comparatively easy task to compute the porosity based on the
following relationship.
Atn - At
log - ma
At. - At
f ma
where 0 = porosity
At, = transit time from log, in jusec/ft
log
At = transit time of matrix material, in usec/ft
ma
At = fluid travel time, in jusec/ft
The sonic log reacts to primary or intergranular porosity, but
does not usually respond to secondary porosity, such as that
occurring from vugs and fractures in the rock. The former is
usually more evenly distributed throughout the rock and will
influence travel time. The latter is erratically distributed,
usually constitutes a small percentage of the rock volume, and,
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therefore, permits sound energy to pass around it so that it is
not detected and does not show on the log. This characteristic
is utilized to determine a secondary porosity index by compar-
ing logs which measure total porosity with porosities calcul-
ated from the sonic log.
The sonic log cannot be used to determine whether there is
fluid movement behind casing, nor can it be used to locate
zones where voids or channeling in the cement may be present.
The steel casing is much more dense than the cement and the
formation. Therefore, the sonic log will record only the tran-
sit time of the steel, which is 57 ^isecs/ft and significantly
faster than that of rock and cement. The presence of the steel
will mask out the arrivals of sound energy from rock and/or
cement, thus making it impossible to investigate the nature of
the cement.
Neutron Log
The neutron log is another tool used for the measurement
of porosity. It employs a radioactive source in the logging
tool as well as detectors, counters, and the circuitry to con-
vert the signals and display them as porosity values on the log.
Because it employs a source which emits neutrons, it is used in
cased holes where information on porosity is desired, as well
as in open bore-holes.
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During the logging process, the radioactive source in the
tool emits neutrons. Some of these are captured by the
nuclei of hydrogen atoms. The capturing nuclei become ex-
cited and emit high-energy gamma rays. These are detected
and counted by the logging tool. Pore space, either primary
or secondary, saturated with water contains hydrogen atoms.
The higher the porosity, the greater the number of hydrogen
atoms available to capture neutrons emitted by the logging
tool. Thus, measurement of the emitted high-energy gamma rays
associated with the capture of the neutrons becomes an indirect
measurement of porosity.
The neutron log is a widely-used tool employed by indus-
try to evaluate porosity in both cased and uncased holes. When
used in conjunction with other geophysical logs, it is possible
to identify selected minerals, determine limestone-dolomite
content, identify hydrocarbons, and assess secondary porosity.
Because of the principle on which the neutron log is based,
it cannot be used to determine the presence or absence of sig-
nificant leaks in injection wells. The logging tool cannot
discriminate between hydrogen atoms contained in free water
associated with porosity and those associated with or bound
in the molecular structure of minerals, cement, or compounds
used in cementing. When cement hardens or sets up, water
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becomes bound up in the structure of the various compounds
that are formed. Also, additives used in cementing contain
water in their molecular structure. For example, bentonite
(gel), which is widely used as a filler, is a hydrous mont-
morillonite (a type of clay); and gypsum, which is used for a
variety of purposes, is a hydrous calcium sulfate. A neutron
log made in a cased cemented hole would show a high porosity
because of the presence of the "bound" water in the cement and
additives, yet the cement could have completely filled the
annulus and bonded both to pipe and formation, achieving an
adequate seal.
The neutron log is a contact tool; that is, the sonde or
instrument is in physical contact with the formation or well
casing when the survey is being made. This is done to minimize
or eliminate the influence of drilling mud or other fluids in
the bore hole. Consequently, the tool investigates only a
portion of the circumference of the well casing.
Density Log
The density log, a tool employing a radioactive source,
can be used in both cased and open holes. It is primarily a
tool for measuring porosity. It operates by measuring the
electron density of a material, which is related to its actual
density.
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Density log data are presented as the bulk density of the
material in gm/cc (grams per cubic centimeter) . If the type of
rock is known, its true density can be determined quite easily.
The difference between the bulk and true densities serves as
the basis for determination of the porosity according to the
following formula, which also requires a knowledge of the den-
sity of the interstitial fluids:
e -ft
0
Where
0 = porosity
p = matrix density
^ -*
ft = formation bulk density
ft. = formation fluid density
A density log is performed with the tool offcentered in
the hole and in contact with the formation or well casing.
This is done because the bore-hole fluids will interfere with
the log and their influence must be either compensated for or
eliminated. The tool investigates to a relatively shallow
depth and has been used to locate cement tops, or identify the
presence of cement behind casing due to the difference in den-
sity between cement and fluid. However, the results of the log
are at best only indicative of the presence of cement and are
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by no means capable of providing detailed information on the
adequacy of the cement. The tool only investigates a small
portion of the circumference of the pipe which is in contact
with the tool. Therefore, the density log cannot be relied
upon to provide the information necessary to determine the
presence or absence of fluid movement.
Temperature Log
The temperature log is one of the tools used by industry
for locating casing leaks and up- or down-hole fluid movement
behind pipe. This wire-line tool can be used in holes or
casing and tubing with diameters as small as two inches. All
of the geophysical logging companies offer temperature logs as
part of their service. Temperature logs are made with elec-
trical resistance thermometers (a device where resistance
changes with changes in temperature). Resistance variations in
the thermometer are transmitted electrically to the surface
and are displayed on the strip log in the same manner as other
geophysical logs.
Temperatures are usually recorded in degrees Fahrenheit.
The equipment is reportedly capable of detecting changes of
0.5 F in a range between 0 F and 350 F. Two types of tempera-
ture logs are available. The first is simply the measurement
and display of the temperature with respect to depth, utilizing
22
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a single temperature measuring device. The second measures
the differential temperature between two units spaced a
measured distance apart, and is used to determine changes in
the temperature gradient. Temperature logs can be performed
in both operating and shut-in wells whether they are under
pressure or not. If they are under pressure, the tool and
wire-line are installed in the well and the log run through a
device known as a stripper head or lubricator.
The temperature of the earth increases with respect to
depth, except for the first hundred feet or so which are
influenced by partial fluid saturation and seasonal variations
in temperature. Below this depth, the temperature gradually
increases; the rate of increase is approximately linear and is
known as the geothermal gradient. Variations in the gradient
occur from place to place, but average about 1°F per 100 feet
of depth.
In the event of a casing leak or fluid movement behind
the casing, the normal geothermal gradient will be disturbed.
This will be reflected as a change in the temperature which
distorts the normal, characteristically smooth, curve of the
temperature shown on the log. The degree of change is related
to the quantities of fluid flow and the temperature difference,
All gradations of this can exist and it is difficult to deter-
mine limits below which fluid movement cannot be detected.
23
-------
Temperature logs will display characteristic signatures
for fluid leaks and movement. Idealized curves are shown on
Figure 1. Of particular importance is the signature for the
upward movement of fluid. The leak or point where movement
begins is at the base or lower portion of the curve where it
joins the normal curve of the geothermal gradient. It should
be noted that in the case of fluid upflow, the curve is dis-
torted in the direction of increasing temperature, whereas the
opposite is true where fluid is moving in a downward direction.
Temperature logging is widely used by industry to locate
leaks arid fluid movement behind casing. It is relatively
accurate and is a readily available service offered by all of
the logging companies.
Cement Eiond Log
Cement bond logs were developed specifically to determine
the condition of cement behind casing. By themselves, they do
not indicate if fluid movement is occurring; they do indicate
if the potential for fluid movement exists (i.e. the absence of
cement or the presence of channeled cement). The bond log is
a form of sonic log that utilizes sound energy in a slightly
different manner. The conventional sonic or acoustic log men-
tioned previously is based on the measurement of the transit
time for sound energy and its relationship to the density and
24
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Geraghty & Miller, Inc.
Q.
OJ
Q •
in
JO
o;
s_
o
Down Flow
Up Flow
Increasing
Temperature
FIGURE 1
TEMPERATURE LOG SIGNATURES
LIQUID FLOW
25
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porosity of the rock. The cement bond log (CBL) relies on the
use of amplitude of the first arrival of the signal as an
indicator of bonding. Also, a survey known as the Variable
Density Log (VDL) is used in conjunction with the CBL in deter-
mining the condition of cement behind casing. The VDL log is
the trade name used by Schlumberger Well Services; it is also
known as the microseismogram (Welex), the 3D Velocity log
(Birdwell Division), and the Acoustic Signature log (Dresser
Atlas). All the companies refer to the bond log as the cement
bond log.
The principles of bond and VDL logs offered by the various
companies are essentially the same. The logging sonde is
usually equipped with a transmitter and two receivers. The
receivers are set at different spacings; one is utilized for
the CBL, the other is used for the VDL. The tool is central-
ized within the bore hole and is run on a wire line; a contin-
uous record is made. The transmitter emits a signal with a
ringing frequency of 20 - 25 kHz (kilohertz) that is radiated
in all directions. The receiver, which is usually set three
feet from the transmitter, detects and measures the amplitude
of the first arrival of the sound energy. In effect, this log-
ging method depends on the difference between the energy loss
of a sound pulse travelling through casing that is standing
free (no bond) in the hole and the energy loss of a pulse
26
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travelling through casing that is firmly bonded to a hard
material of a low sonic velocity, such as cement. The sound
pulse will travel through free casing with very little atten-
uation, whereas when the cement is firmly bonded to the casing
the sonic pulse loses energy continuously to the cement sheath
and a large signal attenuation results.
By logging the signal amplitude, it is possible to locate
points in the cemented section where the bond is not adequate
and a potential for fluid movement may exist. Laboratory
experiments have shown that the signal attentuation in cemented
pipe is proportional to the percentage of the casing circum-
ference that is bonded with cement. Investigations by Schlum-
berger Well Services indicate that a decrease in attentuation
to less than 70 to 80 percent of the maximum value may indicate
cementing problems.
VDL Log
The VDL log, when used in conjunction with the CBL, can
provide additional information on the quality of the cementing.
Basically, the VDL log (microseismogram, 3D velocity, acoustic
signature) is a photographically reproduced display of the
arrival of the sonic signal. A special recording oscilloscope
is used for the purpose. The tool is set up so that a contin-
uous record of the wave train is made as the logging tool is
27
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raised or lowered in the bore hole. A VDL display is shown on
Figure 2. The normal sinusoidal trace of the wave train is
shown on Figure 2a. The VDL display of the wave train is shown
on Figure 2b. The VDL display is derived photographically.
The troughs of the signal produce high light intensities and re-
sult, in .dark zones on the film. Signal peaks produce low
light intensities and result in light zones on the film. The
photographic record of a VDL log appears as a series of alter-
nating light and dark bands (Figure 2). If the rock properties
were the same, the VDL display on the log would appear as a
series of alternating light and dark panels or broad straight
lines covering the interval of the logged section. The "free
pipe" signal shown on Figure 3 demonstrates this. A VDL log
made in an open bore hole can be used to determine porosity
and locate fractures. Detailed interpretation of the wave
train makes it possible to determine various rock properties
for engineering purposes.
When used in a cased hole in conjunction with a bond log,
the VDL log is an aid to interpreting the condition of the
cement. A typical presentation of bond and VDL logs is given
on Figure 3. The logs shown on the figure were taken in a bore
hole in which known portions were cemented and uncemented (the
uncemented portion was gravel packed). The uncemented part
28
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Geraghty & Miller, Inc.
TRANSIT TIME IN MICROSECONDS (jj Sec)
200 1000 2000 3000 4000 6000
a.
b.
IIIIIIIIIIIIIIIIIIII I
FIGURE 2
VARIABLE DENSITY LOG DISPLAY
a0 Sound Wave Display
b, VDL Display
29
-------
U)
O
DEPTH (Feet)
CO
o
a.
t—
o
>
3';
CO
o
en
a
r~
o
Njo Cement—;
Free Pipe Signal.
Pipe Signal .
I ' •
Formation Signal
3
X3 CO
0.
O)
o
-5
fD
CU
BBHt»»^"- •_Dlte..j3.t. . ,a*
o
n
CTQ
•^?
o
-------
shown on the log (below 2058 feet) is shown by a high ampli-
tude signal on the bond log (no signal loss to the formation),
whereas the cemented portion of the casing (above 2058 feet)
is indicated by the lov; amplitude of the signal.
The VDL display below 2058 feet shows a characteristic,
strong, free pipe signal which gives the appearance of the
undistorted alternating light and dark bands. No signal
strength is being lost to the formation, which accounts for
the rather sharp display on the VDL display.
The cemented portion of the casing is characterized by (1)
the low amplitude signal; (2) the weak, almost indistinguish-
able pipe signal; and (3) the wavy, irregular formation signal.
The low amplitude of the signal is due to the loss of acoustic
energy to the formation and indicates that the cement is bonded
to the pipe. The amplitude of the pipe signal also is low
because of the loss of strength to the formation. The presence
of the irregular, wavy formation signals on the VDL display
indicates that cement is bonded to the formation.
The combined use of both the cement bond log and the VDL
log makes it possible to obtain some idea as to whether or not
cement is bonded to the pipe and to the formation. However,
it should be pointed out that this only indicates the presence
or absence of an adequate bond, but does not detect fluid
31
-------
migration behind the casing; it only indicates whether such a
potential exists. Other tests, such as temperature or noise
logging, would be required to establish this.
Noise Logging
Within the past 20 years or so, the oil industry has
developed the noise log as another tool which can be used to
detect and locate fluid movement behind casing, cross-flow
between zones, and relative flow rates from perforated inter-
vals. The noise log can be of significant help in locating
"leaks" that would be associated with fluid movement behind
casing due to channeled cement. Research has shown that the
frequency of sound generated by this type of leak is-distinc-
tive and can be utilized effectively to detect fluid movement.
A noise logging tool detects sound energy created by the
turbulent flow of fluids (single phase) or water-and-gas (two-
phase) moving through channels, perforations, and leaks. The
sound generated ranges in frequency from 200 to 6000 Hz.
Single and two-phase flows generate typical frequencies and, by
examining the frequency of the noise, it is possible to estimate
whether it is gas or liquid that is in motion. The logging
tool or sonde is basically a sophisticated microphone. Sound
energy from a noise source is detected through cement, casing,
and bore hole fluids (or gas, in the event the bore hole is
32
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Geraghty & Miller, Inc.
Fluid
'Departure
Channel
Constriction
Channel
Fluid
Entry
Noise Level -
Mil 1ivolts
FIGURE 4
TYPICAL NOISE LOG DISPLAY
33
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empty). The resultant electrical signal is transmitted via
cable to surface electronic equipment where it is recorded.
The noise signal has an alternating frequency wave form
composed of a number of frequencies. The intensity of the
signal is an indication of the presence (or absence) of fluid
movement, leaks, etc. The noise log measures (and records)
the amplitude of the signal, which is expressed in AC milli-
volts, and is sensitive to any flow that can be "heard."
Noises associated with movement of the tool and wire-line in
the bore hole will mask out noise produced by leaks, movement,
etc. Consequently, a noise log is usually made with the tool
in a stationary position. The noise log is a survey taken on
a STATION by STATION basis, in contrast to other logs which
provide a continuous record with respect to depth of the para-
meter being measured.
Recently, noise logging tools have become available
which can make a continuous record. By eliminating the fre-
quency response generated by tool movement, the log can be
made without stopping the sonde at a station, recording the
noise level of the signal, and moving on to the next point.
Figure 4 illustrates the results of a typical noise log.
In this example, fluid is entering a channel at a point oppo-
site a permeable bed, moving upward, departing the channel,
and entering another permeable bed. The noise log reveals a
34
-------
number of important facts. First, noise levels are greater
than background values over the entire length of the chan-
neled section where fluid is moving, giving an indication of
the entire section which has been affected. Second, the top
and bottom peaks indicate the points of entry and departure.
These two peaks indicate only points of entry and departure;
they do not indicate direction of flow. The flow could have
been shown in the opposite direction and the log would have
looked essentially the same. However, flow direction could be
determined using a temperature log in conjunction with the
noise log. Third, the middle noise peak on the log is shown
as being the result of a constriction in the cement channel.
It could have been shown as another point of entry or depar-
ture and the result would have been the same. Any of these
causes will produce a noise that will be detected.
The noise log is another tool which can be used indivi-
dually or in conjunction with other logs to aid in detecting
fluid movement behind casing. It also can be applied success-
fully in locating leaks. It is a wire line service offered by
a number of the commercial logging companies such as Schlum-
berger Well Services, McCullough, and Dresser Atlas.
35
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Tracer Log
A radioactive tracer log can be used to locate fluid
movement behind casing (assuming that a leak exists in the
casing) or at the bottom of the casing to establish the integ-
rity of the cement seal at that point. Basically, the survey
is quite simple. A fluid containing a radioactive substance
with a very short half life is injected into the well. As it
moves downward it will leave the casing where leaks exist
(assuming the material outside of the casing will permit fluid
movement).
After the fluid is injected, a gamma-ray tool is lowered
in the hole. At the point of the leak, where radioactive fluid
has accumulated, a zone of comparatively intense radioactivity
will exist; it will be detected by the tool and shown on the
log as an anomaly. The log presentation is in essentially the
same format as other logs.
In the case of fluid movement behind the casing at a
leak or at the shoe, the zone of radioactivity will move as
the fluid migrates and will be shown at different positions in
successive surveys. In the case of upward movement at the
shoe, radioactivity will be shown at points above the shoe
where the only way this can occur would be for the fluid to
migrate upward behind the casing.
36
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A summary of the various logs and their applicability to
determining fluid movement is given on Table 1.
COSTS
The costs for performing the various wire-line surveys
used in determining mechanical integrity will, of course,
depend on a number of factors. The commercial logging com-
panies have a rather complex method of calculating charges
which is based on: (1) the distance from the company office
to the well, (2) standby charges, (3) an operations charge or
depth charge, and (4) the type of survey. A minimum charge
also is applied for depth and type of survey. Most companies
allow the customer some "free standby" time before charges
for this item will apply. Also, there will be differences in
the charge for performing a specific survey within the same
company, dependent on the geographic area. As noted previously,
each of the major logging companies has subdivided the country
into areas. The breakdown of service areas is remarkably
similar between the various companies. Costs for a given survey
will vary depending on the area and will vary between companies.
The difference could be as much as $1,000.00, depending on the
depth and type of survey.
Thus, the development of costs for a typical survey is
complex and depends not only on the well (depth to be logged)
37
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TABLE 1
SUMMARY OF VARIOUS LOGS AND THEIR APPLICABILITY TO
DETECTING FLUID MOVEMENT BEHIND CASING
Type of Log
Sonic
Cement Bond
VDL
Parameter
Measured
U)
oo
Temperature
Density
Neutron
Travel time of
generated sonic
signal
Amplitude of
sonic signal
Time of travel
and behavior of
the signal wave
train
Temperature of
cement, forma-
tion, and fluid
Electron
density
Emitted gamma
ray
Area of
Investigation
360°
Centralized
Tool
360°
Centralized
Tool
360°
Centralized
Tool
360
1)
Presentation
(2)
Partial
(contact tool)
Partial
(contact tool)
Record of travel
time of sound in
psecs/ft
Record of signal
amplitude in
millivolts
Photographic
record of wave
train, transit
time in usec/ft
Record of temp-
erature in °F,
also record of
temperature
gradient
Bulk density of
formation in
grams/cc
Porosity in
percent
Applic-
ability^
No
Indicates
Potential
Indicates
Potential
Yes
No
No
Principal Use
Porosity
Condition of
cement behind
casing
Condition of
cement, rock
properties,
fracturing,
porosity
Leak detection,
fluid movement,
cement top
Porosity tool
Porosity tool
-------
TABLE 1 - Continued
Type of Log
Noise
Tracer
Parameter
Measured
Sound generated
by fluid or gas
movement
Radioactivity
Area of (1)
Investigation Presentation
Applic-
ability^ ;
360
360
Amplitude of the Yes
noise signal -
amplitude of more
than 1 frequency
can be examined
Radioactive Yes
highs
Principal Use
Leak detection
Leak location,
detection
NOTES:
(1) Refers to whether or not the tool investigates all or a portion of the circumference of the
bore hole or casing
(2) All surveys are presented as a continuous record of the value of the parameter being-
measured versus depth
(3) Refers to whether or not the survey can be used in determining fluid movement
-------
and the type of survey, but on the same factors noted for
pressure testing as well.
To develop estimated costs for the various surveys,
assumptions similar to those used in costing out pressure
testing were used. Depths ranged from 2,000 to 6,000 feet;
the well was a 300-mile trip from the service company office,
and no standby time was required. Also, none of the logging
company's special equipment or services were needed. The
logs were performed over the entire cased portion of the bore
hole and no provisions for dealing with a hostile environment
were necessary. The estimated costs, rounded to the nearest
$100.00, for temperature, cement bond-VDL, and noise logs
are shown on the following table. These are average values
converted to 1977 dollars.
Logged Depth
Temperature
Cement Bond-
VDL
Noise
2000
3000
4000
5000
6000
$1,600
1,900
2,200
2,400
2,700
$1,500
1,800
2,100
2,400
2,800
$1,500
1,800
2,100
2,400
2,800
These figures are average values and could vary as much as
$500.00 depending on the survey, company, and geographic loca-
tion.
40
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ELEMENTS OF STATE UIC PROGRAMS
RELATED TO WELL INTEGRITY
This portion of the report summarizes the results of a
review of the underground injection control practices of 12
states. The objective of this part of the assignment was to:
1. Determine the range of requirements applicable to
assuring the mechanical integrity of wells designated
Classes I and II by the proposed Federal Underground
Injection Control Regulations.
2. Ascertain the compatability of the state require-
ments with the process and performance standards for
well integrity and abandonment expressed in the
proposed EPA regulations.
The states of interest are: California, Illinois,
Kansas, Louisiana, New Mexico, New York, Michigan,
Oklahoma, Ohio, Pennsylvania, Texas, and Wyoming.
Geraghty & Miller's regulatory files and library were
analyzed and updated through contacts with state agency rep-
resentatives and assessment of data from regulatory and
41
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technical reports. It was also necessary to undertake a
limited review of the supporting legislation in each state
to determine the philosophy of the agency with respect to
control of underground injection.
Table 2 shows that the principal sources of information
concerning well integrity assurance are related to: (a) the
regulatory emphasis or objectives of the permit; (b) the pre-
permitting engineering report submitted by the applicant; (c)
the actual permit application requirement for logs and surveys
of well construction and operation; (d) on-going operational
monitoring; and (e) record keeping and reporting.
Regulatory Approach
Examination of the regulatory approach of the state
agency was necessary to determine the overall minimum standard
for regulation of underground injection.
For instance, New York, Oklahoma, and Pennsylvania each
follow the case-by-case permitting procedure, but each agency
has special considerations, rules, or policies which influence
this individual assessment and address well integrity either
directly or by inference.
The New York Department of Environmental Conservation uses
construction procedures required for Class II wells as minimum
standards, as does California, Texas, Oklahoma, Ohio, Michigan,
42
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TABLE 2
WELL INTEGRITY ELEMENTS OF STATE UIC REQUIREMENTS
CA
IL
KS LA NM
NY
Regulatory Approach
Case-by-Case
Compliance With Performance Stan-
dards (Environmental)
Compliance With Process Stan-
dards (Technical)
Judgement of Contents of
Engineering Report
Pre-Permitting Report
Area of Review (in Miles)
Contingency Plans
Technical Report on Disposal Zone
Well Construction Drawings
Casing Specs
Cementing Specs
Tubing Installation
Packer Installation
Permit Application
Logs and Surveys
1. Driller's Log
2 . Cement Bond Log
3. Porosity Survey
4 . Resistivity
5. Faulting Potential Survey
6 . Gamma-Ray Neutron
7. Casing Log
8. Bottom Hole Pressure Test
Monitoring of Well Integrity
Continuous Annulus Monitoring
Injection Pressure
Periodic Well Integrity
Testing "Program"
Monitor Wells
Record Keeping
Site Inspection
Monitoring Data
Reporting
1. Weekly
2 . Monthly
3 . Quarterly
4 . Annually
X
X
X
X
X
X
X
X
X
X
X
X11
X
X
once
then
ann.
X
X6)
X
2
X
X
X
X
X
X
X
x8)
X •
X
X
X
X
X
X
X
X
/We*
X
X
X
X
X
X
X3)
X
X
X
X
23)
X
X
X
X
X3)
X
X
X
/We*
X
21)
X8,9)
X
X
X
X
X
X
X
X
X
X
X
X
/MO*
X
43
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TABLE 2 - Continued
WELL INTEGRITY ELEMENTS OF STATE UIC REQUIREMENTS
MI OK OH
PA
TX
WY
Regulatory Approach
Case-by-Case
Compliance With Performance Stan-
dards (Environmental)
Compliance With Process Stan-
dards (Technical)
Judgement of Contents of
Engineering Report
Pre-Permitting Report
Area of Review (in Miles)
Contingency Plans
Technical Report on Disposal Zone
Well Construction Drawings
Casing Specs
Cementing Specs
Tubing Installation
Packer Installation
Permit Application
Logs and Surveys
1. Driller's Log
2 . Cement Bond Log
3. Porosity Survey
4. Resistivity
5 . Faulting Potential Survey
6 . Gamma-Ray Neutron
7. Casing Log
8. Bottom Hole Pressure Test
Monitoring of Well Integrity
Continuous Annulus Monitoring
Injection Pressure
Periodic Well Integrity
Testing "Program"
Monitor Wells
Record Keeping
Site Inspection
Monitoring Data
Reporting
1 . Weekly
2 . Monthly
3. Quarterly
4 . Annually
X
X
X
21)
X
X
X
X
X
X
X
X5)
X
X
X
X10)
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
/Da*
/We*
X
X
X
X
X
X3)
X
X
X
/MO*
X
X9)
X
X
X
2.5
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
44
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TABLE 2 - Continued
WELL INTEGRITY ELEMENTS OF STATE UIC REQUIREMENTS
NOTES
1. Oklahoma requires extensive testing of wells within one
mile radius of each injection well. This area is designated
as the "Potentially Affected Zone." State requires integrity
test program for inspection wells every five years.
2. Texas offers most comprehensive guidance through extensive
permit requirements.
3. Prescribes log requirements on case-by-case basis.
4. Michigan requires applicant to make "exhaustive search" to
locate "penetrations" in "expected area of influence."
5. Michigan will accept results of continuous monitoring of
the well in lieu of integrity testing quarterly.
6. Uses Class II regs for salt-water disposal as minimum
standards for permitting all well injection.
7. Agency "may" request data on nearby wells and other facilities
in the area of review.
8. Policy is to use Class II well construction procedures as
minimum standards. Division of oil and gas must approve spec-
ifications and engineering plans for all injection wells.
9. Applicant required to demonstrate that no alternative disposal
method is available.
10. Well owner must submit estimate of the "life-time expect-
ancy" of the injection well (Rule 5.10).
11. Agency has the option of requiring periodic well integrity
tests including temperature testing, radioactive tracer and/or
spinner test. Testing is done by specially equipped mobile unit.
12. Agency may follow oil and gas regs requiring "periodic"
temperature, radioactive tracer, and/or spinner tests.
*/We (Weekly)
*/Da (Daily)
*/Mo (Monthly)
45
-------
and Kansas. However, both New York and Pennsylvania discourage
the use of injection wells for industrial and municipal use.
In New York, "the injection of liquid wastes by deep wells is
considered a last resort after all other methods have been
evaluated." This practice is regarded as "a method for gaining
long-term storage rather than treatment." In New York, the
applicant must demonstrate that injection is the optimal
approach, and has the least effect to the total environment.
Pennsylvania also views underground injection as a "last
resort." Case-by-case evaluation for Class I wells in Oklahoma
involves judgment of the applicant's projection of the "life-
time expectancy" of the well.
The case-by-case review usually involves one of two dif-
ferent regulatory approaches. One approach stresses com-
pliance with established environmental standards and requires
all parts of the facility to operate so that this standard is
maintained. This approach always relies heavily upon long-
term monitoring and stops short of imposing detailed technical
construction and testing regulations. Although guidance is pro-
vided, the technical process standards are not written as regu-
lations, but rather inferred by the contents of the permit
application. The other approach uses specific technical
requirements or testing procedures to meet the established
standard for environmental protection, and is usually more
46
-------
rigorous with respect to prevention of problems. Monitoring
is required as a secondary checking mechanism of operational
integrity.
For instance, the Kansas Department of Health uses the
regulations for oil and gas salt-water disposal wells as the
minimum standard for permitting all well injection. Agency
rules simply say that underground injection must protect
"usable water," defined as all water containing not more than
5,000 ppm chlorides. The technical details of how to construct
a well that will meet this standard are not provided as regu-
lations by the agency. Hence, when the applicant submits the
required engineering report, the reviewer must consider prin-
cipally whether the proposed well has or will have sufficient
integrity to protect "usable water" regardless of the techni-
ques used for construction, testing, or maintenance. Technical
guidance offered and testing procedures imposed allow for site-
specific judgment.
Conversely, Michigan regulations emphasize the initial
determination of the site containment potential and well con-
struction to assure integrity of the total operation, but
reinforce this reliance through rigorous pre-permitting inves-
tigations, prescribing specific testing procedures to be
completed periodically. Oklahoma's Rules and Regulations for
47
-------
Industrial Waste Management also prescribe specific well
integrity tests as a condition of permitting. These tests
are comparable to those required by Sec. 146.08 of the pro-
posed regulations.
Pre-permitting Engineering Report
The technical data collection requirements related to
well integrity are to be found to one degree or another as
data submission items in the applicant's site evaluation,
well construction, and operational engineering report, which
each of the states uses to initiate the permitting process.
.Procedural guidance and permit forms used by the Texas Depart-
ment of Water Resources stipulate the variety of tests needed.
However, the agency reported that monitoring is considered to
be the most important indicator of problems. It was pointed
out that "other tests are redundant." The degree to which
pre-construction data is relied upon by the states is indi-
cated by the fact that, of the states reviewed, only Califor-
nia, New York, Michigan, and Oklahoma formally require sub-
sequent periodic well integrity testing (Table 2).
It also should be noted that the contents of the pre-
permitting report for Class I wells in Illinois, Michigan, and
Oklahoma are particularly rigorous, requiring considerable
preliminary fiscal investment by the potential operator with
48
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no guarantee that the results will not lead to a request for
additional investigation.
Logs and Surveys
The logs and surveys required for the actual permit
application indicate that Illinois, Oklahoma, and Texas re-
quirements are the most consistent with respect to start-up
testing programs which test the validity of the initial permit
application data (Table 2). The other states prescribe logging
and surveying activities on a case-by-case basis without ap-
parent regulatory reference to the pre-permitting tests.
Monitoring of Well Integrity
Oklahoma and Texas rules are noteworthy because of the
degree to which fairly rigorous log and survey requirements
are supported by equally explicit monitoring requirements. As
previously mentioned, most of the other states, including
California, Ohio, Illinois, Michigan, and New York, place
heavy reliance on post-operational monitoring to confirm the
integrity of the well.
Continuous annulus monitoring and regular checks of
injection pressure are the two most common requirements for
checking day-to-day operational integrity of the well. However,
some states, notably Texas, Kansas, and California, stipulate
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additional testing on a case-by-case basis in conjunction with
the issuance of the operational permit. In California, the
State Water Resources Control Board retains the option of
requiring periodic well integrity tests including temperature
testing, radioactive tracer and/or spinner testing. The tests
are run by a specially equipped mobile unit.
In Texas, the applicant for an injection well must:
"Describe provisions for continuing activities necessary for
proper well operation and qualifications of personnel who will
operate and supervise the injection well and related facili-
ties." The agency policy is to rely on well monitoring to
indicate problems. Other tests, although they are sometimes
requested, are regarded as "redundant" in the context of the
total permitting process for injection wells. It should be
noted that Texas and Oklahoma regulations for well design,
construction, and operation are probably the most comprehen-
sive of those reviewed. They prescribe casing, construction
materials, pressure gradients, emergency facilities, qualifi-
cations of operators, and also offer considerable regulatory
guidance to permit applicants.
In Kansas, the frequency of checking disposal operations
is dictated by .the Division of Environment's "knowledge of the
potential for problems in the region." The state requires a
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spinner survey if problems with the well are "suspected."
Radioactive tracers are used "occasionally" and the instal-
lation of an annulus pressure gauge is "preferred but not
mandatory." The state philosophy is to "use rules and policy
requirements based upon laws rather than uniform regulations."
Periodic Well Testing Programs
Oklahoma and Michigan prescribe periodic testing of
operating wells in a fashion similar to the proposed EPA
regulations (Sec. 146.24(3)). The Oklahoma regulation
(5.6.10.1) requires that
"At least once during each five (5") years, the operator
shall conduct such tests, such as cement bond logs or
tracer surveys, as are necessary to insure the con-
tinued integrity of the cementing..."
The operator also is advised that:
"Formation pressure decay tests as specified shall be
conducted annually and the results submitted to the
Department.
5.6.11.1 Such formation pressure decay tests shall
be conducted by pressurizing the well to
its maximum normal injection pressure for
a length of time sufficient to establish
stable conditions, then closing off the
well and monitoring the decay in well head
pressure. The test may be terminated when
the well head pressure changes no more
than three (3) p.s.i. in one (1) hour, or
at the end of the twenty-four (24) hours,
whichever comes first."
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Michigan's Rule 67 covers "Periodic testing of storage
and disposal wells." This quarterly testing specifies the
use of the variable-rate input method, the pressure fall-off
test, "or any other performance test specified." The rule
stipulates that:
"Sufficient data shall be collected during each calen-
dar year to facilitate analysis of static and injec-
tion formation pressures, storage zone limits or
boundaries, changes in formation characteristics, and
other information commonly derivable from such
tests."
However, the agency advises the operator that continuous
monitoring data may be an acceptable substitute for "some"
periodic testing.
New York State Department of Environmental Conservation
policy with respect to deep well injection declares that:
"It is incumbent upon the applicant to obtain a com-
petent geologist and a professional engineer for the
necessary studies, design and preparation of reports
and plans. This should include, but not be limited
to the environmental, economical and technical
implications."
The well testing program required by the Illinois Divis-
ion of Land/Noise Pollution Control also goes beyond contin-
uous monitoring (Table 2). The specific tests to be run are
52
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determined on an individual basis for each well and are per-
formed six months after initial operation and then either
annually or every two years.
Existing state regulatory practices and policies are
designed to assure the integrity of wells used to inject
municipal or industrial wastes into the subsurface.
Controls are based upon practices established by the
oil and gas industry for Class II wells. These oil and gas
waste disposal regulations are minimum standards for other
injection wells.
The states incorporate a number of elements of the prg-
posed Federal regulations into their practices. However, no
state program is organized in a categorical fashion similar
to the proposed EPA standards. The state emphasis is on
assessing the likelihood that the well will be secure rather
than upon prevention of problems sometime in the future.
The lack of uniformity for data requirements directed at
well integrity for Class I wells exists because of the spe-
cial nature of the practice. Injection of industrial and
municipal wastes is sufficiently limited nationally to allow
state agencies to issue permits on a case-by-case basis. The
tendency to regard underground injection as a "last resort"
53
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management practice is sufficiently prevalent to encourage
this approach. For instance, the New York Department of
Health "Statement of Policy" declares that "the injection of
liquid wastes by deep wells is considered a last resort after
all other methods have been evaluated." The same policy
exists in Pennsylvania.
The potential operator, not the regulatory agency, is
principally responsible for proposing technical design,
operation, and monitoring details. Permit forms ask ques-
tions and rarely dictate specific standards other than those
related to the quality of water to be protected. Judgment
concerning the applicant's data submission with respect to
well integrity is the basis for the permitting agency's
selection of testing procedures as a condition of permitting.
Philosophically, the principal difference between the
Federal approach to well integrity assurance and related
testing and the state practices relates to the reluctance of
state agencies to standardize technology. Instead, perfor-
mance standards are emphasized.
Re-permitting of Class I injection wells every five years
is not the practice of any of the states whose regulations
were reviewed in this assessment. However, Oklahoma does
require the operator to undertake a formal program of well
integrity testing every five years.
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SELECTED REFERENCES
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Arthur D. Little, Inc., for the Office of Drinking Water,
U. S. Environmental Protection Agency, Washington, D. C.
BROWN, H. D.: Grijalva, V. E.; and Ramer, L. L.. 1970.
New Developments in Sonic Wave Train Display and Analysis
in Cased holes. Society of Professional Well Log Analysts,
Eleventh Annual Logging Symposium. May 3-6, 1970
CALIFORNIA ADMINISTRATIVE CODE, Title 14, Sections 1744.4 and
1724.4. Natural Resources, IBID Sections 1723,1724.6, and 1748.
CALIFORNIA STATE WATER RESOURCES CONTROL BOARD. 1976.
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ENGLAND, R. E. Well Log Interpretation, Volume I. Birdwell
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FERTL, W. H.; Pilkington, P. E. ; and Scott, J. B., 1974.
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3, Page 38, (1979) .
55
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SELECTED REFERENCES - Continued
ILLINOIS EPA, Division of Land/Noise Pollution Control.
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Vegas, Nevada
KREIBLER, W. L., Underground Disposal of Liquid Waste
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LYNCH, E J. 1962. Formation Evaluation. Harper and Row.
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MICHIGAN DEPARTMENT OF NATURAL RESOURCES GEOLOGICAL SURVEY
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Geological Survey Division. IBID. Selected Rules Pertain-
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MOODY, G. B., Editor. 1961. Petroleum Exploration Handbook.
McGraw-Hill Book Company, Inc., New York
MYUNG, J. I., and Sturdevant, W. M. 1970. Introduction to
the Three-Dimensional Velocity Log. Birdwell Division,
Seismograph Service Corporation, Tulsa, Oklahoma
MYUNG, J. I., and Baltosser, R. W. Fracture Evaluation by the
Borehole Logging Method. Birdwell Division, Seismograph
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NEW YORK STATE, Rules and Regulations for Mineral Resources,
Parts 550-558. Dec 1975
NEW YORK STATE BUREAU OF MINES. Notice of Intention to Plug
or Abandon.
OHIO EPA, Outline of Requirements for Establishing and Operating
a Facility for Underground Waste Injection
56
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SELECTED REFERENCES - Continued
OHIO OIL AND GAS LAW. Ohio Revised Code, Chapter 1509, with
Rules and Regulations
OHIO RIVER VALLEY AND SANITATION COMMISSION, Underground
Injection of Waste Water in the Ohio Valley Region. Policy
on the Underground Injection of Waste Water 1979
OKLAHOMA CORPORATION COMMISSION, Rules and regulations of the
Oklahoma Corporation Commission, Oil and Gas Conservation
Division 1976
PENNSYLVANIA Industrial Waste Regulations as Amended through
May 6, 1978
ROBINSON, W. S. 1976. Field Results From the Noise Logging
Technique. Jornal of Petroleum Technology, November 1976
SCHLUMBERGER WELL SERVICES. 1973. Production Log Interpretation.
Schlumberger Well Services, Houston, Texas
SCHLUMBERGER WELL SERVICES. 1975. Cased Hole Applications.
Schlumberger Well Services, Houston, Texas
SCHLUMBERGER WELL SERVICES. 1978. Service Catalog. Schlumberger
Well Services, Houston, Texas
SCHLUMBERGER WELL SERVICE. 1979. Schlumberger's Audio Log.
Schlumberger Well Services, Houston, Texas
SEISMOGRAPH SERVICE CORPORATION. 1960. Basic Velocity
Logging Manual, Birdwell Technical Bulletin No. 4. Birdwell
Division, Seismograph Service Corporation, Tulsa, Oklahoma
SEISMOGRAPH SERVICE CORPORATION. 1976. Logging Capabilities
and Services, Birdwell Division, Seismograph Service Corporation,
Tulsa, Oklahoma
SMITH, D. K. 1976. Cementing, Monograph Volume Number 4,
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STATE OF ILLINOIS. An Act in Relation to Oil, Gas, Coal and
other Surface and Underground Resources.
57
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SELECTED REFERENCES - Continued
STATE OF ILLINOIS. Department of Mines and Minerals. Rules
and Regulations
STATE OF KANSAS Statutes Pertaining to the Control of
Pollution Resulting From the Exploration or Production
of Oil and Gas.
STATE OF KANSAS, Permit Application for Sub-Surface Disposal
of Waste Water, State of Kansas, State Department of Health,
Division of Environmental Health. IBID. Application for
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Methods.
STATE OF MICHIGAN Act 249, Public Acts of 1929 as Amended by
Public Act 117
STATE OF NEW MEXICO Energy and Minerals Department, Oil
Conservation Division, Rules and Regulation 1978
STATE OF NEW YORK, Article 23 of the Oil and Gas Mining Law
STATE OF NEW YORK, Department of Health. Deep Well Injection
State of Policy 1969
STATE OF LOUISIANA. Office of Conservation. 1977. State-
wide Order Number 29-N. IBID. Order Number 29-B. Approval
Procedure for Salt-Water Disposal Wells.
STATE OF OHIO Department of Natural Resources, Division of Oil
and Gas, Application for Permit to Drill, Reopen, Convert,
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STATE OF OKLAHOMA. Rules and Regulations for Industrial
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TEXAS DEPARTMENT OF WATER RESOURCES. Instructions for Filing
an Application for a Permit to Disposal of Waste by Well.
TEXAS DEPARTMENT OF WATER RESOURCES, Underground Injection Unit.
Instructions and Procedural Information for Filing an
Application for Permit to Disposal of Waste by Well Injection.
TEXAS DEPARTMENT OF WATER RESOURCES. Subsurface Waste Disposal
in Texas. Texas Department of Water Resources Publication
72-05.
58
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SELECTED REFERENCES - Continued
TEXAS "WATER QUALITY BOA"RD- /Summar-y Data ff>r -Industrial and
Municipal Injection Wells
TEXAS WATER QUALITY BOARD. 1976. Rules of Practice and
Procedure
TOFFLEMORE, T. J., and Brezner, G. P., Deep Well Injection
of Waste Water, Journal of Water Pollution Control Federation,
(July 1971).
U. S. ENVIRONMENTAL PROTECTION AGENCY. 1977. The Report
to Congress, Waste Disposal Practices and Their Effects on
Ground Water, U. S. Environmental Portection Agency, Office
of Water Supply, Office of Solid Waste Management Programs,
Washington, D. C.
WALKER, T. 1967. Utility of the Micro-sismogram Bond Log.
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WARNER, D. L., and Lehr, J. H. 1977. An introduction to
the Technology of Subsurface Wastewater Injection, Environ-
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1977, U. S. Environmental Protection Agency, Ada, Oklahoma
WATT, H. B., et al. 1974. Log Review I. Dresser Atlas
Division of Dresser Industries, Inc., Houston, Texas
WELEX SERVICES. 1974. Services Catalog, Welex Services,
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WELEX SERVICES. Temperature Log Interpretation, Welex Services,
Houston, Texas
WELEX SERVICES. Frac-Finder/Micro-Seismogram Log, Basic
Acoustics, Welex Services, Houston, Texas
WICHMANN, P. A. 1975. Log Interpretation Fundamentals.
Dresser Atlas Division of Dresser Industries, Inc., Houston,
Texas
WYLLIE, M. R. J. 1963. The Fundamentals of Well Log Inter-
pretation. Academic Press, New York
WYOMING OIL AND GAS CONSERVATION COMMISSION. 1979. Rules and
Regulation of the Wyoming Oil and Gas Conservation Commission
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