FINAL REPORT
DEVELOPMENT OF PROCEDURES
FOR SUBCLASSIFICATION OF
CLASS III INJECTION WELLS
Contract No. 68-01-5971
Submitted to
Dr. Jentai Yang
Office of Drinking Water
Mr. Thomas F. Sullivan
Contract Operations
Prepared for
ENVIRONMENTAL PROTECTION AGENCY
OFFICE OF DRINKING WATER
By
Geraghty & Miller, Inc.
April 30, 1980
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FINAL REPORT
DEVELOPMENT OF PROCEDURES
FOR SUBCLASSIFICATION OF
CLASS III INJECTION WELLS
Contract No. 68-01-5971
Submitted to
Dr. Jentai Yang
Office of Drinking Water
Mr. Thomas F. Sullivan
Contract Operations
Prepared for
ENVIRONMENTAL PROTECTION AGENCY
OFFICE OF DRINKING WATER
By
Geraghty & Miller, Inc.
April 30, 1980
-------
CONTENTS
Page
ACKNOWLEDGMENTS iii
EXECUTIVE SUMMARY iv
INTRODUCTION 1
CLASS III INJECTION WELL PRACTICES 3
ALTERNATIVES FOR SUBCLASSIFYING 10
SUBCLASSIFICATION ON BASIS OF ENVIRONMENTAL THREAT 17
Avenues of Contamination 18
Quality of Injected Fluids 19
Existing Regulatory Control 20
Relative Environmental Threats 21
APPLICATION OF CRITERIA AND STANDARDS, BY PRACTICE 23
APPENDICES
A. Description of Injection Well Practices A-l
B. Summary of Existing State and Federal
Regulations Governing Class III Wells B-l
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LIST OF FIGURES
Figure Page
1. Principal Locations of Class III Injection
Well Sites 5
LIST OF TABLES
Table Page
1. Estimated and Projected Number of Class III
Special Process Injection Wells and Sites 4
2. Comparison of Physical Characteristics of Class
III Wells 8
3. Comparative Evaluation of Potential for
Contamination of a UDWS by Injection Wells in
Classes I, II, and III 24
4. Minimal Required Technical Criteria and
Standards for Ground-Water Protection 26
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ACKNOWLEDGMENTS
This report was prepared under the direction
of Mr. Nathaniel M. Perlmutter, Senior Scientist,
Geraghty and Miller, Inc., for the Office of
Drinking Water. The EPA Task Manager was Mr. Russ
Wright. Mr. Perlmutter was assisted by Mr. James J.
Geraghty, President, Mr. Wolfgang V. Swarzenski,
Senior Scientist, and Mr. Cleason P. Smith, Hydro-
geologist, of Geraghty and Miller, Inc.
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EXECUTIVE SUMMARY
Class III injection wells are special process wells
associated with the recovery of minerals, petroleum, gases,
and heat (geothermal energy). The wells can be grouped, for
descriptive purposes, into five major subclasses: (1) sulfur
mining by the Frasch process, (2) solution mining of salt
(including potash), (3) in-situ leaching of uranium and copper,
(4) in-situ combustion, and (5) production of geothermal
energy.
This report has been prepared to assist EPA in developing
the criteria and standards to be applied to subclasses of wells
within the Class III designation. In the course of the work
assignment, EPA requested the Contractor to address possible
alternatives for subclassification and to pay special attention
to the relative threats to ground water posed by the different
practices.
It is estimated that there were about 7,800 Class III in-
jection wells in use in 1979, at about 140 sites; most of these
are in the States west of the Mississippi River. About 6,000
of the wells, used for in-situ leaching of uranium, are in the
Texas Gulf Coast uranium belt. The total number of all types
of Class III injection wells may reach about 25,500 by 1985.
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There is a wide range in physical characteristics of the
injected fluids, formation fluids, hydrogeologic settings, well
construction, and other features of Class III wells. Injected
fluids include water, steam, and chemical solutions to dissolve
ores, and air or gases to sustain combustion of coal, oil shale,
lignite, and tar sand. Depending on the geologic setting, the
depths of injection wells may be from less than 100 ft in the
case of shallow copper ore deposits to as much as 10,000 ft in
the solution mining of salt. Injection zones generally are
within the zone of saturation and contain water ranging in
quality from fresh to saline. The permeability of the rocks in
the injection zones is increased in some practices by hydro-
fracturing and the use of explosives. Although ground water
within, above, and below the injection zones may be of useable
chemical quality, in some places, the economic value of the re-
covered mineral and energy resources may exceed the value of
nearby poor quality ground-water resources.
In principle, there are many alternative ways for reclassi-
fying Class III injection wells. In the course of the present
study, the Contractor has made a preliminary evaluation of some
of these alternatives, as listed below;
1. Place all or selected Class III wells in a separate
category, pending further evaluation by states in next five
years.
2. Allow states to regulate Class III wells under state
rules on a case-by-case basis.
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3. Require submission and review of ground-water assess-
ment reports and outlines of mining plans in lieu of rigid
regulations•
4. Set up new experimental technology class.
5. Provide area permits or certificates of acceptance for
entire ore body to be mined.
6. Place all Class III wells that inject non-toxic sub-
stances into a separate category.
7. "Grandfather" in existing and abandoned wells of
record acceptable to state agencies.
8. Designate special impacted mining areas to be either
exempted from UIC regulations or where selective requirements
would be waived or liberalized.
9. Classify wells on the basis of relative environmental
threat.
Perhaps the most logical way to subclassify the Class III
wells, would be in terms of the relative threats to the ground-
water environment posed by the different practices. In a
fundamental sense, the threat to the environment posed by any
injection well, regardless of its class, is determined by the
potential for leakage of injected fluid into a UDWS.
Another way to appraise relative environmental threats
would be in terms of the chemical composition of the injected
fluid itself. As mentioned previously, the injection of fresh
water, air, or gas represents far less of a threat than in-
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jection of fluids containing toxic substances. Still a third
measure of environmental threat might be the degree to which
the practice is already being monitored by regulatory authori-
ties .
The overall threat to the ground-water environment that
might be posed by a particular type of injection well in Class
III depends to a large degree on the site-specific hydrogeo-
logic situation. One very important consideration with regard
to all of the wells in the Class III category is that the
practices involve withdrawal from the injection zone through
production wells of essentially the same volume of fluid that
is injected through the injection wells. If it is accepted
that the Class III method of operation almost guarantees that
all injected material will ultimately be pumped back out of
the ground, it could then be argued that the potential threat of
contamination from all of these wells is essentially low. More-
over, coupled with the generally non-toxic character of most of
the injected fluids, there would be a basis for deciding that
most of the practices in Class III category represent a very
low threat to ground water in comparison with wells in some of
the other classes. An exception is the case of in-situ leaching
of uranium and copper, although in the uranium practice, there
are tight regulatory requirements for monitoring and aquifer
restoration, which are further safeguards against threats of
uncontrolled ground-water contamination.
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An effort has been made, utilizing information previously
compiled by EPA and the best professional judgment of the Con-
tractor and others, to estimate whether the environmental
threats are low, medium, or high. For the most part, the likeli-
hood of escape of contaminants through the various potential
avenues of contamination is low, with only a few of the entries
being shown as moderate to high.
For each of the six individual practices, suggested minimal
criteria and standards have been suggested. The rationale for
this selection is that the strictest controls should be applied
only if any one of the relative potentials for contamination is
"high". It is, of course, recognized that some requirements may
be modified for non-technical reasons such as administrative
coordination, economic considerations, or others.
Although some minor differences in required standards
exist from practice to practice, one alternative would be to
subclassify the Class III wells under the following general
groupings:
(1) Frasch sulfur
(2) Salt solution
(3) In-situ leaching of uranium
(4) In-situ leaching of copper and other metals
(5) In-situ combustion (coal, lignite, oil shale, and
tar sand)
(6) Geothermal
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A second alternative, possibly more feasible from a regu-
latory viewpoint, would be to provide a single set of require-
ments for all Class III wells but allow for flexibility in
their implementation, depending on the well type and conditions.
This would permit application of the regulations to all Class
III wells.
At the present time, most State agencies attempting to
regulate Class III injection wells (with the exception of geo-
thermal wells) do so through a case-by-case assessment of mining,
drilling; or discharge permit applications. To provide a basis
for this assessment, applicants are usually required to include
technical plans and pertinent geological and hydrological in-
formation with the permit application form; this information is
reviewed and plans are evaluated for their adequacy in meeting
various environmental performance standards that have been es-
tablished in that State. It should be noted, however, that
permitting of Class III operations in some States seems to be a
superficial procedure; consequently, a significant number of
Class III wells may be installed and operated under minimal re-
gulatory control by State agencies.
Several States which have Class III injection wells do not
have regulations designed specifically for a particular mining
practice, but do have general permitting procedures that are
applicable to any Class III operation (with the exception of
geothermal wells). These States include Wyoming, Colorado, Utah,
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New Mexico, and Oklahoma. Wyoming, Colorado, and Utah have more
comprehensive information requirements for permit application
forms than do New Mexico or Oklahoma. Other States have specific
regulations for certain Class III practices such as in-situ leach-
ing (Texas and New Mexico),in-situ combustion (Texas), salt solu-
tion (Kansas, Michigan, and Ohio), and geothermal (California,
Oregon, New Mexico, Idaho, Arizona, and Utah). Federal regu-
lations cover geothermal activities on Federal lands.
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DEVELOPMENT OF PROCEDURES FOR
SUBCLASSIFICATION OF
CLASS III INJECTION WELLS
INTRODUCTION
Development of standards and criteria for special
process injection wells (referred to as Class III Wells in
the proposed April 1979 UIC regulations) have been a con-
troversial problem since the preparation of the first draft
of the proposed Underground Injection Control (UIC) regula-
tions in 1976. These injection-well practices have a number
of similar elements, such as injection and recovery of
fluids and production of either energy-related or mineral-
bearing fluids of great economic value. They also have a
number of basic differences with regard to chemical character
of injected fluids and the quality of the native water in
the injection zones.
Previous attempts (197 6-1979) to develop standards
applicable uniformly to all of the injection well practices
have met with complaints that across-the-board application
of regulations would be impractical, that a number of require-
ments are unnecessary and costly, and that some types of
mining operations might have to be shut down. Moreover,
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some mining practices, such as in-situ combustion of fossil
fuels, have not yet been applied commercially and are only
in an experimental or research stage.
The present report has been prepared to assist EPA in
developing the criteria and standards to be applied to sub-
classes of wells within the Class III designation. In the
course of the work assignment, EPA requested the Contractor
to address possible alternatives for subclassification and
to pay special attention to the relative threats to ground
water posed by the different practices. The report contains
discussions of these aspects and also contains, in Appendices
A and B, background information on the practices themselves
and on pertinent State and Federal regulatory controls.
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CLASS III INJECTION WELL PRACTICES
Class III injection wells are special process wells
associated with the recovery of minerals, petroleum, gases,
and heat (geothermal energy). The Class III injection wells
can be grouped, for descriptive purposes, into five major
subclasses: (1) sulfur mining by the Frasch process, (2)
solution mining of salt (including potash), (3) in-situ
leaching of uranium and copper, (4) in-situ combustion, and
(5) production of geothermal energy. A description of each
practice is given in Appendix A.
It is estimated that there are about 7,800 Class III
injection wells in use in 1979, at about 140 sites (Table
1); most of these are in States west of the Mississippi
River (Figure 1). Some of the symbols on the map (Figure 1)
represent more than one site. The number of injection wells
per site may range from 2 or 3 to more than 100, depending
on the type and location of the mining practice. About
6,000 of the wells, used for in-situ leaching of uranium,
are in the Texas Gulf Coast uranium belt (Figure 1). The
total number of all types of Class III injection wells may
reach about 25,500 by 1985.
Commercial production of uranium by in-situ mining
methods is presently limited to Texas and Wyoming, although
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Table 1
ESTIMATED AND PROJECTED NUMBER OF CLASS III SPECIAL PROCESS
INJECTION WELLS AND SITES
Sites Wells
(Projected)
1979/1980 1979/1980 1985
Sulfur Mining (Frasch Process) 8-10 500 a/ 500 - 600
Solution Mining of Salt 80 1,000 b/ 1,100
In-situ Leaching
Uranium 35 6,300 18,000
Copper and other metals c/ 2-3 10-20 30-50
In-situ. Combustion c/
Coal
Lignite
Oil shale
Tar sand
30
300
Geothermal Energy
140+
25 d/
7,785+
50
25,500+
a/ Replace 300-500 wells per year.
b/ Replace about 100 wells per year. May include some converted
oil and gas wells.
c/ Pilot and experimental studies only.
d/ Mostly in California and Oregon.
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EXPLANATION
WELL SYMBOLS
A Fraicfl Sulfur
O Soil Solution
k> Situ Corwbutlion
Q Coal
B Oti Shoi*
Q Tar Sandt
100 200
In Situ L*oclnnQ
o Urortium Sit*
Y//A Uranium Belt
A Coppw
^ Ceofhermol
Figure 1. Principal Locations of Class III Injection Well Sites.
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pilot projects are in operation in several other States. In
some of these areas, commercial production may be achieved
in the near future and possibly some 18,000 active uranium
injection wells will have been installed by 1985.
About 500 injection wells, at 8 to 10 sites in Texas
and Louisiana, are used in the production of sulfur by the
Frasch process, and about 1,000 wells are used in the solu-
tion mining of salt at about 80 sites in 14 States. The
bulk of the salt is mined by solution in coastal salt domes
in Texas and Louisiana and in stratified deposits, mostly in
west Texas, New York, Michigan, Ohio, and Kansas. In addi-
tion, minor production is reported from seven other States.
Production of sulfur and salt is related to the general
level of economic development and, assuming no major changes
in recovery techniques, only a modest increase in the total
number of such injection wells is anticipated by 1985.
In-situ copper leaching operations are relatively
short-lived and it is difficult to estimate the number of
active operations or injection wells at any particular time.
Only a few operations exist at present, largely in an experi-
mental stage, but it is assumed that this practice will
expand commercially in the future.
The third group of injection wells in Class III com-
prises wells installed for the in-situ combustion of coal,
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lignite, oil shale, and tar sands. Up to the present time,
only a small number of such injection wells have been in-
stalled experimentally to enhance formation permeability and
to sustain combustion in the various processes under study.
Air, oxygen, propane, steam, or water are the principal
fluids being injected. It can be expected that some com-
mercial production, particularly from coal, lignite, and oil
shale, will be achieved by 1985.
Injection wells associated with the development of
geothermal energy, mostly at a few sites in California and
Oregon and possibly in several other nearby States, are used
to return produced brines or to dispose of condensates from
power generating stations. In addition, injection wells may
be used for the fracturing of deep, hot, dry rock areas and
the injection of water, from which geothermal energy can be
produced. Geothermal energy is used commercially to generate
electricity and domestically to heat homes, greenhouses, and
schools. A moderate increase in the number of geothermal
injection wells can be expected by 1985.
Table 2 shows the wide range in physical characteris-
tics of the injected fluids, formation fluids, hydrogeologic
settings, well construction, and other features of Class III
wells. Injected fluids include water, steam, and chemical
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PAGE NOT
AVAILABLE
DIGITALLY
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solutions to dissolve ores, and air or gases to sustain
combustion of coal, oil shale, lignite, and tar sand.
Depending on the geologic setting, the depths of injection
wells may be from less than 100 ft in the case of shallow
copper ore deposits to as much as 10,000 ft in the solution
raining of salt. Injection zones generally are within the
zone of saturation and contain water ranging in quality from
fresh to saline. The permeability of the rocks in the
injection zones is increased in some practices by hydro-
fracturing and the use of explosives. Although ground water
within, above, and below the injection zones may be of
useable chemical quality in some places, the economic value
of the recovered mineral and energy resources may exceed the
value of nearby poor quality ground-water resources.
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ALTERNATIVES FOR SUBCLASSIFYING
In principle, there are many alternative ways for
reclassifying Class III injection wells. For example, some
of the practices that have a number of features in common,
like the mining of sulfur by the Frasch process and the solu-
tion of salt in dome deposits, might be treated similarly.
Or, some practices might be grouped according to the chemical
quality of the injected fluids, some of which are relatively
pure water or gas that probably pose little or no threat to
the ground-water environment. In still other cases, sub-
classification might be based on whether or not injection
takes place directly into a UDWS (Underground Drinking Water
Source). Still another possibility would be to separate out
special process wells that are designed for the production
of energy. In the course of the present work assignment,
the Contractor has made a preliminary evaluation of some of
these alternatives, as listed below:
Place All or Selected Class III Wells in a
Separate Category, Pending Further Evaluation by
States in Next Five Years
Because the Class III wells present special problems in
terms of historical practices, economic dislocations that
might result from too restrictive regulations, and the fact
that some of the technologies are in a developing or experi-
mental stage, it could be argued that more time should be
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given for the development of the most suitable criteria and
standards for controlling the different practices. In
essence, this option would allow EPA to defer the develop-
ment of specific regulations until more data and experience
could be obtained by the States, especially with regard to
site-specific threats to ground-water resources.
Allow States to Regulate Class III Wells
Under State Rules on a Case-by-Case Basis
This approach is the one most commonly followed (see
Appendix B), in which the State regulatory authority assesses
all of the specific site conditions in order to develop the
needed level of control. Because the hydrogeologic frame-
work may differ radically from site to site, the approach
gives better recognition to the fact that threats to the
ground-water environment may be markedly different. In some
instances, little or no control might be required simply
because field evidence shows that the practice is not detri-
mental to the environment.
Require Submission and Review of
Ground-Water Assessment Reports and Outlines
of Mining Plans in Lieu of Rigid Regulations
This approach would be in conformance with the widely
accepted procedure for requiring an environmental impact
statement or assessment for entire mining operations. In
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this regard, it must be kept in mind that mining is a very
disruptive practice to the environment and that the injection-
well operation may represent only a small part of this dis-
ruption. In the Frasch sulfur process, for example, the
dissolution of the sulfur may cause collapse and subsidence
of overlying geologic formations, with the net result that
the original flow system of the aquifers is disrupted and
monitor wells or other wells may be damaged or broken as the
overburden materials catastrophically collapse or subside.
The logic here would be that the environmental impact assess-
ment should address all of these problems in advance, and if
the impacts were found to be acceptable to the State, then the
injection practice similarly would be allowed, with minimum
regulatory control.
Set Up New Experimental Technology Class
The in-situ copper leaching and in-situ combustion
practices are essentially still in an experimental stage,
with few or no commercial operations at present. The operators
of these experimental practices maintain that they have no
clear idea of what kinds of injection wells ultimately will
be needed, and that it seems unreasonable to set up long-term
regulatory programs for wells whose designs may have to be
modified radically as time goes on. Also, some aspects of
the injection techniques are proprietary and the operators
feel that any requirements for premature divulging how the
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wells are designed and used could be detrimental to their
economic interests. The rationale would simply be to put
experimental types of operations into a separate category
until they enter a commercial stage of operation and more
is learned about the type and degree of required regulatory
controls.
Provide Area Permits or Certificates of Acceptance
for Entire Ore Body to be Mined
Where a practice involves the use of a number of more or
less standardized injection wells, each designed to be a
duplicate of the other, logic might indicate that a single
area permit be issued for an entire such operation. As
presently worded, the UIC regulations call for extensive
public hearing procedures and permit submissions for indi-
vidual wells, which would be severely disruptive to injection-
well practices where the need exists to continuously install
new wells and abandon others. In some cases, literally
hundreds of similar injection wells are in operation or are
being replaced at any given time in a well defined area.
Place All Class III Wells that Inject
Non-Toxic Substances into A Separate Category
In some of the Class III practices, the injected fluid
is essentially non-toxic, and in a few instances is simply
fresh water or steam. From this viewpoint, it could be
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argued that EPA is not required to regulate the injection of
fluids that pose little or no threat to the ground-water
environment. However, even in those cases, the fluid in-
jected into the earth may mobilize minerals from the geologic
formations that might be considered harmful to the ground-
water environment. As a counterbalancing protective element,
however, some of these practices also involve the pumping
out or recovery of these mineralized fluids, so that the end
result may be only a very limited localized contamination of
ground water, if any, and may pose little or no overall
threat to the integrity of the regional ground-water system.
"Grandfather" In Existing and Abandoned Wells
of Record Acceptable to State Agencies
Owing to the sheer number of existing Class III injec-
tion wells that have been installed over the years in con-
formance with widely varying historical mining procedures,
EPA might wish to consider the alternative of putting all
existing wells under permit or certificate of acceptance
and applying more specific regulations only to new wells to
be installed in the different mining practices. This option
probably would require EPA to stipulate that the existing
wells can be grandfathered in only where there is no evidence
demonstrating that they are causing harmful ground-water
contamination. In this regard, it should be kept in mind
that many of the Class III practices are already under
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fairly restrictive State regulatory controls (see Appendix
B), and that the States presumably have some knowledge of
the potential threat that they may pose to the local ground-
water environment.
Designate Special Impacted Mining Areas
to be Either Exempted from UIC Regulations or Where
Selective Requirements Would be Waived or Liberalized
As noted above, some Class III practices are fundamen-
tally mining operations, not unlike any other type of mining
operation. Moreover, some of the practices take place in
areas that are already heavily impacted by surface or
underground mining or by the production of oil and gas from
hundreds of wells. The logic here would be to simply recog-
nize the largely unavoidable disruptive nature of all such
practices and to designate mining areas as being outside the
purview of EPA's injection-well regulatory controls. This
approach would be most workable in places where it can be
demonstrated that there is little or no usable ground water
in the vicinity of the injection-well activities or where
public water-supply wells are too far away to be subject to
any meaningful threat from the injection-well operations.
Classify Wells on the Basis of
Relative Environmental Threat
Still another way, and perhaps the most logical way to
subclassify the Class III wells, would be in terms of the
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relative threats to the ground-water environment posed by
the different practices. From this viewpoint, differences
in the operations themselves would be of less significance,
and the only real consideration would be whether or not a
particular type of well injects contaminants, how those
contaminants could escape into the ground-water environment,
whether the practice itself tends to prevent such excursions,
how closely the injection process is monitored and controlled
by operators and/or regulatory agencies, and finally, whether
an assessment of the combination of hydrogeologic environ-
ments and chemical composition of the injected fluids could
provide a mechanism by which to measure impacts. The next
section of this report addresses the environmental threat
alternative in greater detail.
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SUBCLASSIFICATION ON THE BASIS OF
ENVIRONMENTAL THREAT
In a fundamental sense, the threat to the environment
posed by any injection well, regardless of its class, is
determined by the potential for leakage of injected fluid
into a UDWS. The leakage could occur through openings
connecting the injection zone with a UDWS or through actual
leaks in well casings opposite a UDWS. In some instances,
the potential for increased leakage could be caused by the
mining process itself, as for example where solution of a
particular ore body causes overlying confining beds to
collapse or be breached by fractures that allow harmful
migration of fluids.
Another way to appraise relative environmental threats
would be in terms of the chemical composition of the injected
fluid itself. As mentioned previously, the injection of
fresh water, air, or gas represents far less of a threat
than injection of fluids containing toxic substances. Still
a third measure of environmental threat might be the degree
to which the practice is already being monitored by regula-
tory authorities. With regard to this latter concept, for
example, the existing close scrutiny already given to in-
situ uranium leaching practices by the Nuclear Regulatory
Commission and various State agencies may itself constitute
a reasonable level of protection. Each of the foregoing
factors is discussed in some detail below.
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Avenues of Contamination
The ways in which an injected fluid can escape from an
injection well, regardless of its class, are essentially the
same. For example, the well may discharge 100 percent of
its contents directly into a UDWS, which is always the case
for wells in Classes IV and V and for some wells in Class
III. Or, a well may be designed to discharge into a non-
potable injection zone overlain by and hydraulically separ-
ated from a UDWS, which is the situation for essentially all
wells in Classes I and II and some wells in Class III. In
the case of Class III wells discharging directly into a
UDWS, some controlled contamination of fresh ground water
can take place except where the injected fluid is completely
harmless.
For wells designed to inject into deep non-potable
ground water, the potential exists for escape of the injected
fluid through: (1) leaks in the casing of the well at
depths opposite a UDWS, and (2) upward escape of injected
fluid into a UDWS through leaky confining beds, natural or
artificial fractures, the annulus of the well itself, or
nearby improperly abandoned wells that penetrate the injec-
tion zone. A much more remote possibility is that the
injected fluid could travel laterally into an adjacent part
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of the injection zone containing potable water. Presumably,
the regulating authority would not allow such a well to be
placed in operation or continue to operate if the latter
possibility existed.
Quality of Injected Fluids
The fluids injected into Class III wells (see Table 2)
range in composition from essentially fresh water to alkaline
and acidic solutions. In addition, salty water is injected
into some wells and others receive air, propane, gas, or
steam. The precise chemical composition of the different
fluids is not always known, partly because in some cases it
is proprietary information which the operator prefers not to
reveal. Also, under any one particular category of wells
(such as Frasch wells), different types of injected fluids
may be used at different locations within the same well
field, at different times.
Lacking detailed chemical analyses of the injected
fluids, it is not possible to compare their relative environ-
mental threats except in a general way. Injection of essen-
tially fresh water and/or air, for example, could be thought
of as no threat to the environment. Other types of injected
fluid might pose a moderate threat, although in all of the
practices nearby production wells recover the injected
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fluids as rapidly as they are emplaced. In those kinds of
practices, the body of injected fluid is fairly well con-
trolled, with little or no likelihood of vertical movement
upward through confining beds into an overlying UDWS.
Existing Regulatory Control
Some of the practices (uranium wells, for example) are
closely monitored because of the special nature of the
mining operation (see Appendix B). Federal and State agen-
cies are fully aware of the need to keep close control on
in-situ leaching of uranium, and it is probably safe to
state that the existing procedures for monitoring uranium-
well practices are at least equal to or even more restrictive
than the standards that EPA has been considering for these
wells up until now.
An additional level of monitoring and control is pro-
vided by the operators themselves, largely because it is in
their economic interest not to allow any loss of injected
fluids. In wells into which steam is injected, for example,
the operator incurs a very high energy cost in bringing the
temperature of the steam up to the required level, and he is
deeply concerned over the possibility that any of this fluid
might somehow escape in an uncontrolled manner. With this
in mind, many of those operators keep records on volumes of
-20-
-------
fluid injected versus volumes of fluid recovered, the
amounts of constituents that must be placed in the fluids to
achieve a desired mining result, and changes in pressures
that might be observed and interpreted as indicators of
leaks or other types of losses. Thus, it can be argued that
the self-monitoring that the operator believes to be an
essential part of the mining practice is itself a form of
assurance that little or no contamination could go undetected.
Relative Environmental Threats
The overall threat to the ground-water environment that
might be posed by a particular type of injection well in
Class III depends to a large degree on the site-specific
hydrogeologic situation. It would be difficult, for example,
to generalize on a nationwide basis the factors that govern
the presence of natural fractures or faults that could serve
as conduits for upward escape of fluids into an UDWS.
Similarly, the precise method of construction of individual
wells may differ, even within a single well field, so that
some wells may pose more of a contamination threat than
others. In addition, the volumes of fluids being injected
would have to be taken into account and compared with their
relative toxicity and potential for escaping into a UDWS.
Finally, the relative threat is also related to the way in
-21-
-------
which a particular UDWS is being used, the locations of
nearby wells that might be affected, and the likelihood that
the aquifer could be put into more productive use sometime
in the future.
One very important consideration with regard to all of
the wells in the Class III category is that the practices
involve withdrawal from the injection zone through pro-
duction wells of essentially the same volume of fluid that
is injected through the injection wells. By contrast, wells
in other classes in the UIC regulations continuously inject
fluids that create an ever-expanding and growing volume of
injected materials. If it is accepted that the Class III
method of operation almost guarantees that all injected
material will ultimately be pumped back out of the ground,
it could then be argued that the potential threat of con-
tamination from all of these wells is essentially low.
Moreover, coupled with the generally non-toxic character of
most of the injected fluids, there would be a basis for
deciding that most of the practices in Class III category
represent a very low threat to ground water in comparison
with wells in some of the other classes. An exception is
the case of in-situ leaching of uranium and copper, although
-22-
-------
in the uranium practice, there are tight regulatory require-
ments for monitoring and aquifer restoration, which are
further safeguards against threats of uncontrolled ground-
water contamination.
Because it is not possible to define all of the foregoing
factors for all of the practices, an effort has been made in
this report, utilizing information previously compiled by
EPA and the best professional judgment of the Contractor and
others, to estimate whether the environmental threats are
low, medium, or high. Table 3 makes such comparisons for
each of the well practices. The table shows that, for the
most part, the likelihood of escape of contaminants through
the various potential avenues of contamination is low, with
only a few of the entries being shown as moderate to high.
APPLICATION OF CRITERIA AND STANDARDS, BY PRACTICE
Based on the material presented previously in this
report, and especially on the rankings of potential threats
shown in Table 3, a re-assessment has been made of the
different technical criteria and standards originally stipu-
lated in the 197 9 version of the UIC regulations for Class
III injection wells. In general, giving due recognition to
the relatively low threat of ground-water contamination
posed by these wells, it is felt that a number of the
original criteria and standards can be deleted. However,
-23-
-------
Table 3. COMPARATIVE EVALUATION OF POTENTIAL FOR CONTAMINATION OF
A UDWS BY INJECTION WELLS IN CLASSES I, II, AND III
Well Class Number
I
II
III (Special Process Wells)
-—__and Type
(Hunlcipal
In Situ Leachinq
In Situ Combustion
Environmental"""" .
Factors
and
Industrial
Hells)
(Oil and
Related
Hells)
Frasch
Sulfur
Salt
Solution
Uranium
Copper And
Other
Minerals
Oil Shale
Coal
Liqoite
Tar
Sand
Geo-
therma)
a/
1. Dimensions of in-
jected water body
Continuous-
ly expandim
Expanding
Stable
Stable
Stable
Stable
Stable
Stable
Stable
Stable
Stable
to Ex-
panding
2. Pressure buildup in
injection xone b/
High
High
Low to
Moderate
Low to
Moderate
Low
Low
Low
Low
Low
Low
Moderate
to High
). Quality of injected
fluid _c/
Poor
Poor
Good to
Poor
Good to
Poor
Poor
Poor
Good
Good
Good
Good
Poor to
Moderate
1. Integrity of
well _d/
High
Low to
Medium
Medium
to High
Medium
to High
High
Medium
to High
Medium
to High
Medium
to High
Medium
to High
Medium
to Hlgf
Medium
to High
>. Quality of water in
Injection zone
Poor
Poor
Poor
Poor
Good
to Poor
Good
to Poor
Good
to Poor
Good
to Poor
Good
to Poor
Good
to Pooi
Poor
Relative Potential For Contamination^
Potential For Upward
or Lateral Miqration
(Based on items 1
and 2 above)
High
High
Low to
Moderate
Low
Low to
Moder-
ate
Low
Low
Low
Low
Low
Low to
Moder-
ate
Potential for Leak
Opposite a UDWS
(Based on item 4
above)
Low,
Moderate
Low to
Moderate
Low £o
Moderate
Low
Low
Low to
Moderate
Low to
Moderate
Low to
Moderate
Low to
Moder-
ate
Low
Potential for Deqra-
dat ion of a UDWS
(Based on item ]
above)
High
High
Low to
Moderate
Low to
Moderate
Moderate
to High
Moderate
Low
Low
Low
Low
Moder-
ate
(Based on items ]
and 5 above)
Low
Low
Low
Low
Moderate
to High
e/
Moderate
to High
e/
Low
Low
Low
Low
Low
*/ Relatea to also of area of review.
abandoned°wells,°' ar8a ™*iew and local Potentlal upward migration through natural or artificial fractures and
c/ Relatea to relative toxicity.
—/ Tttl,e8 lnto ®ccount potential corroaivity, Ufa of well, type of casing, cement program, and possibility of subsidence,
low where mitigated by an aquifer reatoration program.
-------
some of the original criteria and standards will have to be
applied in order to provide an acceptable level of protection
of the ground-water environment.
Table 4 lists, for each of the individual practices,
suggested minimal criteria and standards that could be required.
The rationale for this selection is that the strictest controls
should be applied only if any one of the relative potentials
for contamination in the table is listed as "high." It is, of
course, recognized that EPA may wish to modify some requirements,
for non-technical reasons such as administrative coordination,
economic considerations, or others.
Although some minor differences in required standards
exist from practice to practice, one alternative would be to
subclassify the Class III wells under the following general
groupings:
(1) Frasch sulfur
(2) Salt solution
(3) In-situ leaching of uranium
(4) In-situ leaching of copper and other metals
(5) In-situ combustion (coal, lignite, oil shale, and
tar sand)
(6) Geothermal
-25-
-------
Table 4. MINIMAL REQUIRED TECHNICAL CRITERIA AND STANDARDS
FOR GROUND WATER PROTECTION a/
CRITERIA AND STANDARDS
FRASCH
SALT
URANIUM
COPPER
COAL
LIGNITE
OIL
SHALE
TAR
SAND
GEO-
THERMAL
146.32 Construction Requirements
fa) Casinq
X
X
X
b/
X
X
X
X
X
Cement or other sealing mechanism
X
X
X
is/
X
X
X
X
X
(b) Corrosive Resistant
Material AoDlicable
(c) Logs
(1) Drillers
(2) Geoohvsical
(3) Tests
(d) Information on Injection
Formation
X
X
X
X
X
X
(e) Monitor Wells
X
X
X
X
X
X
146.33 Abandonment of Wells
(Class III)
X
X
X
X
X
X
X
X
X
146.34 Operating, Monitoring, and
Reporting Requirement
(a) Operating
(1) Control of Injection
Pressure to Prevent Harmful
Migration
X
X
X
X
X
X
X
X •
X
(2) No Aiuiular Injection
Between Outermost
Casing and Well Bore
X
X
X
X
X
X
X
X
X
(b) Monitoring
(1) Test Injection Flow
(2) Monitor
Injection
Flow Rate and Volume/ and outflow
X
X
X
X
X
X
X
X
X
(3) Mechanical Integrity
(every 5 years)
(4) Honitor
Water Levels and Water
Quality in Monitor and or existing
Wells
X
X
(5) Monitor
Water-supply Wells
X
X
X
X
X
X
X
X
X
(6) Maintenance of Results
for 5 years
(c) Reporting Requirement
(1) Report to
Director on Monitoring
(2) Results of Mechanical
Integrity Test
(3) Written Notice to
Director within 30
Days of any Compli-
ance Schedule Date
(4) Immediate Reports to
the Director of viola-
tion of Permit or
Malfunction
-26-
-------
Table 4. - Continued
CRITERIA AND STANDARDS
FRASCH
2
V)
URANIUM
COPPER
i
o
o
LIGNITE
OIL
SHALE
TAR
SAND
6 u
U X
IS H
146.35 Information to be Considered
by Director Prior to Issuance
of a Permit :
(a) Application for Permit
X
X
X
X
X
X
X
X
X
(b) Map (Area of Review) Showing
Location of All Wells and
Other Physical Information
(c) Maps and Cross Section (Area
of Review) Delineating Under-
ground Source of Drinking
Water
X
X
X
X
X
X
X
X
X
(d) Geologic Maps (Local)
X
X
X
X
X
X
X
X
X
(el Geoloaic Kaos (Reaional)
(f) Well Data in Area of
Review
(q) ODeratinq Data
X
X
X
X
X
X
X
X
X
(h) Formation Testing Program
(i) Stimulation Program
(i) Injection Procedure
X
X
X
X
X
X
X
X
X
(k) Engineering Drawings
X
X
X
X
X
X
X
X
X
(1) Plans for Monitoring
X
X
X
X
X
X
X
X
X
(m) Change in Pressure, Fluid
Displacement, and Direc-
tion of Movement
(n) Contingency Plan for Well
Failure
X
X
X
X
X
X
X
X
X
(o) Well Data
X
X
X
X
X
X
X
X
X
(p) Proposed Corrective Action
X
X
X
X
X
X
X
X
X
(q) Bondinq
(r) Mechanical Integrity
a/ All requirements to be based on area permit concept,
where feasible.
b/ Optional, based on site-specific conditions in relation
to need for aquifer protection.
-27-
-------
A second alternative, possibly more feasible from a
regulatory viewpoint, would be to provide a single set of
requirements for all Class III wells but allow for flexi-
bility in their implementation, depending on the well type
and conditions. This would permit application of the
regulations to all Class III wells.
-28-
-------
APPENDIX A
DESCRIPTION OF INJECTION PRACTICES
-------
APPENDIX A
Contents
Paae
Sulfur Mining (Frasch Process) A-l
Salt Solution
In-Situ Leaching A-ll
Uranium A-ll
Copper A-18
In-Situ Combustion A-21
Coal A-21
Oil Shale A-26
Tar Sands A-28
Geotherraal Energy A-30
-------
LIST OF FIGURES
Figure Page
A-l Frasch Sulfur Mining Operations and Idealized
Section of a Salt Dome A-2
A-2 Construction Diagram of a Frasch Sulfur Well in
Louisiana A-4
A-3 Solution Mining of Salt Domes and Bedded Deposits A-7
A-4 Construction Diagram of a Salt Solution-Mining
Well Showing Multiple Casings and Cement A-9
A-5 Cross Section and Plan View of In-Situ Uranium A-12
Leaching Operations
A-6 Cross Section of an Injection-Recovery In-Situ
Uranium Leaching Well Using a Retrievable Screen A-13
A-7 Cross Section of an Injection-Recovery In-Situ
Uranium Leaching Well Using a Screen or Slotted A-14
Casing
A-8 Cross Section of an Injection-Recovery In-Situ
Uranium Leaching Well Using Hydraulic Jet A-15
Perforations
A-9 Construction Diagram of Deep In-Situ Uranium
Leaching Injection and Recovery Wells A-17
A-10 Diagram of an In-Situ Copper Leaching Operation
in a Fault Zone A-20
A-11 Schematic Diagrams Showing the Linked Vertical
Well Underground Coal Gasification Process A-22
A-12 Construction Diagrams of In-Situ Combustion
Injection and Recovery Wells A-23
A-13 Cross Sections Showing Modifications of In-Situ
Coal Combustion Processes A-25
A-14 Known Geothermal Areas in California and Southern
Oregon A-31
A-15 Construction Diagram of Geothermal Steam-Producing
Wells in the Geysers Area, Northern California A-33
-------
Figure
A-16 Construction Diagram of a Geothermal Hot Brine-
Producing Well, Southern California
A-17 Geologic Section and Construction Diagram of a
Typical Domestic Geothermal Hot-Water Well With
a U-Tube Heat Exchanger, Klamath Falls, Oregon
A-18 Diagrams of Domestic Geothermal Heat Exchange
Systems and Wells, Klamath Falls, Oregon
-------
DESCRIPTION OF INJECTION WELL PRACTICES
Sulfur Mining (Frasch Process)
Sulfur contained in the lower part of the limestone cap
rock that overlies salt domes (Figure A-l) or in bedded salt
strata is mined by the Frasch process in the Gulf Coast area
of Texas and Louisiana and in west Texas. In the Frasch
process, injection of fluids and recovery of sulfur take
place in the same well. Superheated fresh to brackish water
(about 325°F), treated so as to minimize corrosion and
encrustation, is injected into the sulfur-bearing strata to
increase the temperature and melt the sulfur. The sulfur
accumulates near the bottom of the well and enters the
casing through perforations. High pressures from steam
injection causes the sulfur to rise in a small-diameter
inner casing, from which it is pumped to the surface by air
lift. In some operations, the spent injection water, cooled
and mixed with the native water in the cap rock, is removed
by relief wells located a short distance from the producing
well. This water is highly mineralized and may be disposed
of by reinjection elsewhere or by discharge to brackish,
tidal water after treatment.
In typical Frasch sulfur wells in Texas, an outer cas-
ing (8- or 10-inch-diameter) is set into the top of the cap
-A-l-
-------
I
>
I
to
I
•'ir, urc A-L. Frasch Sulfur /lining Operations and Idealized Section of a Salt Dome.
-------
rock, and the overlying water-bearing formations, containing
fresh to salty water, are permitted to collapse around the
uncemented casing. The depths of injection zones range from
about 400 to 2,100 ft (feet). Six-inch casing, with two
perforated zones near the bottom, is set inside the outer
casing to the base of the sulfur-bearing cap rock. The
upper perforations, for steam injection, are separated from
the lower perforations and from a 3-inch production casing
by means of a packer. Figure A-2 shows the design struc-
ture of a sulfur well with cemented casing that is used in
parts of Louisiana.
Frasch sulfur wells generally have a short service
life, commonly ranging from a few weeks to a few months, and
timely replacement of wells is essential. Hence, casings
are cemented only as needed, in case of high formation
pressures, or to counteract pressure losses within the
production zone. Land surface subsidence due to the com-
paction of the porous cap rock is common in areas of dimin-
ishing production. Owing to the decrease in permeability of
the sulfur depleted zone in areas of subsidence, heat and
water losses are reportedly reduced while the productivity
of adjacent sulfur wells is enhanced.
Beds of unconsolidated or semi-consolidated sand, silt,
clay, and gravel, as much as several hundred feet or more
thick, overlie some of the sulfur mining areas along the
-A-3-
-------
=
-------
interbedded with consolidated shale, sandstone, and lime-
stone. Water at intermediate and deep zones in these
formations is generally saline, but ground water at shallow
depths may be potable. In some of the mining areas of the
northeastern United States, consolidated rocks are overlain
by stratified glacial deposits, which also constitute a
source of potable ground water. Salt mining operations
commonly occur in areas including or near oil and gas well
fields.
-A-10-
-------
In-Situ Leaching
Uranium
Uranium deposits suitable for mining by in-situ leach-
ing are found in sand and sandstone, interbedded with clay
and silt (Figure A-5A). The uranium-bearing deposits must
be below the water table and in well confined strata. At
present (1979), commercial production is mainly limited to
operations in Texas and to a small extent in Wyoming.
Uranium is extracted during in-situ mining by applica-
tion of dilute alkaline or acid solutions (lixiviants), in
combination with a chemical oxidant. The oxidant is used to
oxidize uranium from the usual tetravalent state to the more
soluble hexavalent state. The uranium is then taken into
solution by the solvent. Hydrogen peroxide is a typical
oxidant. Ammonium bicarbonate is a typical alkaline- and
sulfuric acid is a typical acid-leaching agent.
In uranium-mining operations, oxidants and lixiviants
are injected at depths of about 300 to 2,000 ft (Table 2).
Various patterns are used in the spacing of injection and
production wells, including the 5-spot, 7-spot (Figure A-
5B), and line-drive system. The well consists of a single
wall cemented casing and well screen (Figures A-6, A-7, and
A-8); PVC is the preferred casing material, but steel and
—A-ll-
-------
INJECTION
WELL
"ECOVERT WELL
INJECTION WELL
GROUND LEVEL
(A)
SANOSTONE aQuiFE
SrLl^?i0n °f-a typi<=al uranium ro11 ^ont deposit and
tne solution mining unit • •
(B)
"A" WELL FIELD
~O pro*, location*
* 32 *«) location*
<3 r«Mrt w*h
• (8 common ro "B*)
<9 common to *Ca)
*
T$
*C# WELL FIEUJ
<2 p^od. Jocofioft*
40inj locotiom
Ocommofl ro "A*)
C 3 common to *0*)
• UOfelTO* WfU. ITIST 0H.Y)
* TRCHO VGLL (TEST 0*LY)
HOTZ-. DISTANCES TO monitor wells arc from
6D6C 0f TEST WELL FIELD
<2 prod. Jocofton*
40 irq locoriom
(5 common to "O ^yj
(3 common to *C*)
FRONT
I
200
J I
Well field locations for the initial mining unit and pilot-scale test
x' igu.t.e A-5. Cross Section and Plan View of
^¦"Situ Uranium Leaching Operations.
-A-12-
-------
Casing
iif =wCSV~^=!f- i
v (VA .—.'• •• /i •_". \L-
( =r \U== \*\ •S\>^^^^5,///=l«lS»-^>e^a
'•: /.^tCement -=->-/.xr,. .v
_ V/V.- "•-
Figure A-6. Cross Section of. an Injection-Recovery In-Situ
Uranium Leaching Well Using a Retrievable
Screen.
-A-13-
-------
Figure A-7. Cross Section of an Injection-Recovery In-Situ
Uranium Leaching Well Using a Screen or Slotted
Casing.
-A—14-
-------
Shale or mudstone
Figure A-8.
Cross Section of an Injection-Recovery In-Situ
Uranium Leaching Well Using Hydraulic Jet
Perforations.
-A-15-
-------
fiberglass may be used in deep wells (Figure A-9). Ore-
bearing zones are commonly only a few tens of ft thick, and
as mining progresses, the function of injection and produc-
tion wells (Figure A-5A) may be reversed. It is common
practice to pump recovery wells at rates slightly in excess
of injection rates, so as to maintain a cone of depression
in the potentiometric surface and, thereby, minimize the
potential for an uncontrolled excursion of contaminated
fluids from the injection site.
The uranium-bearing fluids from the recovery wells are
processed into uranium oxide by ion exchange. Lixiviants
can be reused after regeneration, whereas other waste pro-
ducts are generally placed in evaporation ponds or are
disposed of in deep waste injection wells.
The uranium-bearing sands in south Texas are part of
the Gulf Coast Aquifer of Tertiary to Pleistocene age; it
contains ground water that is fresh to slightly brackish to
depths of about 3,000 ft. In Wyoming and several other
States, relatively shallow uranium deposits in sandstone or
sand can be mined by in-situ leaching. The deposits are
generally in shallow fresh-water aquifers, but deeper deposits
may be in brackish-water zones.
-A-16-
-------
INJECTION WELL
60' /
2
/
/
y
/
s
1/
/
/
?
LEACHATE INJECTION
02 INJECTION
7K7
;<^NEAT CEMENT TO SURFACE
8 5/8" STEEL CASING SHOE
5 1/2" STEEL CASING,
^(SURFACE TO 1850*)
HOWCO LITE & NEAT
dJiJIii^'CEMENT TO SURFACE
5 1/2" F/G CASING
(1850' • 2080')
PACKER
2" F/G TUBING
X 5/8" F/G 02 LINE
PERFORATIONS
P.B.T.D.
51/2" F/G CASING SHOE
T.D.
1955'
Figure A-9. Construction Diagram of Deep In-
Recovery Wells.
PRODUCTION WELL
PRODUCTION
NEAT CEMENT TO SURFACE
8 5/8" STEEL CASING SHOE
1
\
5 1/2" STEEL CASING,
-PLASTIC COATED ON I.D.
(SURFACE TO 1850')
REDA PUMP 5 HP.
28 GPM AT 300 FT HEAD
HOWCO LITE & NEAT
CEMENT TO SURFACE
5 1/2" F/G CASING
(1850' • 2080')
PERFORATIONS
P.B.T.D.
5 1/2" F/G CASING SHOE
T.D.
Uranium Leaching Injection and
-------
Copper
In-situ leaching of copper is practiced in ore bodies
in igneous rocks, or in worked-out mines where the ore is
not of sufficient grade to be extracted by conventional open
pit or underground mining methods. Usually, a dilute sul-
furic acid solution is injected into the ore deposit through
wells. However, in some places, water may be used as a
leaching agent because sulfuric acid may be naturally pre-
sent in the rocks as a result of the oxidation of pyrite in
the ore body. In either case, copper is leached and recovered
from the subsurface as copper sulfate. The copper is most
commonly removed from the copper sulfate by placing the
acidic solution in contact with shredded iron.
Initially, leaching techniques were focused on mining
of residual copper in abandoned mines and caved workings,
and then was developed, particularly in the southwest, to
include the mining of entire ore bodies where more conven-
tional mining and metallurgical practices could not be
applied economically. Leaching of copper after hydraulic
fracturing and blasting of the ore body to increase its
permeability has been tried on a pilot scale in recent
years. Although much of the work to date is experimental
and solution mining of copper is not widely used at present,
it is likely to become a growing practice in the future.
-A-lg-
-------
No single construction method is used for boreholes
that inject copper-leaching solutions. Where leaching
solutions are introduced into previously mined, caved, or
blasted ore bodies, injection wells commonly are shallow,
uncased boreholes through which the fluids are injected by
gravity flow. Other relatively shallow injection wells are
cased with PVC pipe. In places where injection wells may be
used to hydraulically fracture the ore body, wells may be
several thousand ft deep and may be constructed with cemented
steel casing. Figure A-10 shows a cross section through one
type of hydrogeologic setting of an in-situ copper leaching
operation in a fault zone.
Probably most copper deposits in the United States are
in or above fresh ground-water zones. Water within a copper
deposit may contain elevated amounts of other dissolved
metals, compared with the ground water in the same aquifer
outside of the ore deposits. The potential for ground-water
contamination is from the injected leaching solution and the
ions mobilized by it, which may include other heavy metals
in addition to copper. The ore body and adjacent bedrock
may be broken by faults and other fractures.
-A-19-
-------
Pump
Leaching
Solution
Land
Surface yy / y ^
Injection
Well
Collection
Gallery
Barren
Solution
Product Recovery
Figure A-10. Diagram of an In-Situ Copper Leaching Operatioi
in a Fault Zone.
-A-2 0-
-------
In-Situ Combustion
Coal
In the in-situ combustion process, which is entirely an
experimental practice at present, injection wells are used
for the fracturing of coal seams and the injection of gas
and/or air to sustain combustion. Modifications of the
process have been adapted to the mining of thin seams and
coals of different ranks. Experiments involving a small
number of wells have been carried out in several coal fields.
The underground combustion of coal is accomplished in
two steps, a preparation process known as reverse-combustion
linking and the actual gasification process (Figure A-ll);
some dewatering may be necessary in places. Two wells are
drilled to the coal seam; one is used as an ignition well
and the other is used as an injection well (see Figure A-
12 for construction details), supplying oxygen to sustain
the fire. The fire proceeds toward the oxygen source,
creating a highly permeable pathway due to carbonization and
the removal of volatile matter. Upon completion of the
linking, the system is ready for gasification. High volumes
of air are injected at low pressures, and the fire burns
back toward the ignition well, expanding until it encom-
passes the full thickness of the coal seam. All gases
produced during both the linking and gasification periods
-A-21-
-------
well 1
well 2
virgin coal
high pressure
ainnjection gas^ production
• dry seam
ignition system
implanted
ignite and supply
air
gas high pressure
production air injection
^ *
• switch injection
• fire seeks air source
• highly permeable
pathway results
(reverse com-
bustion)
production from either well
At 14'
• permeable pathws.,
complete
• equivalent borehoit
high volume gas
air injection production
N r
• coal consumption
begins
• forward gasificatioi
continues
• cavity grows
high volume gas
air injection production
N f
• cavity expands to
production well
• process may now
be relayed
Figure A-11. Schematic Diagrams Showing the Linked Vertical
Well Underground Coal Gasification Process.
-A-22-
-------
Figure A-12. Construction Diagrams of In-SitU Combustion Injection a»;d Recovery
Wells. 2
-------
are removed at the ignition well. Figure A-13 shows some
additional modifications of the in-situ combustion process
involving hydrofracted reaction zones and dipping beds.
Additional data on the characteristics of the practice are
given in Table 2.
Underground coal combustion is believed to be environ-
mentally preferable to conventional mining techniques;
moreover, it permits the mining of coal seams which lie too
deep to be economically mined by other known methods. How-
ever, some coal seams are part of useable aquifers, and the
combustion process might produce detrimental effects.
Subsidence may be expected which could cause the shearing of
wells and also provide conduits for the escape of gas.
Water could drain into the combustion cavern, extinguishing
the burn, and the ground water could become contaminated.
Gas leaks could be dangerous because of carbon monoxide
generation. In-situ combustion of oil shale, lignite, and
tar sand are similar in operation, construction practices,
and environmental problems to those described for in-situ
combustion of coal.
-A-24-
-------
LINKED VERTICAL WELLS PROCESS
LINKED VERTICAL WELLS
PROCESS OAS
IN _
PRODUCT OAS
_ OUT
DIRECTION OF
MAXIMUM NATURAL PERMEABILITY
ICOUNTERCURRENT FLOW
CONDITION SHOWNI
AIR COMPRESSOR BLDG.
TO POWER PLANT
.LOU PRESSURE .
-ii...- —
IPROOUCTION'.
;HIGH PRESSURE,
-H-
JUJUNJECnON WELL ( WELL . AIR INJECTION WELL .
*\
's*
FORWARD
GASIFICATION
REVERSE
combustion
LINKING
PACKED BED PROCESS
PIPELINE OAS
OAS
PURIFICATION
PLANT
OXYGEN PLANT
WATER PLANT
COAL AND SHALE
REACTION ZONE
STEEPLY DIPPING BED CONCEPT
STRATA CRACKING
AND SUBSIDING
NO 1 AIR INLET USED
FOR FIRST PHASE OF
GASIFICATION
ASH AND CLINKER IN
BURNT OUT AREA
GAS OFFLET
UN DIFFERENT
VERTICAL PLAN
ORIGINAL END OF
GASIFICATION BORE HOLE
NO 2 AIR INLET
FOR SECOND
PHASE OF
GASIFICATION
EACTION ZONE
STRATA SUBSIDING
INTO BURN OUT AREA
Figure A-13. Cross Sections Showing Modifications of In-Situ Coal Combustion Processes.
-------
Oil Shale
In-situ oil or gas production from oil shale is another
essentially experimental practice. Unlike above-ground
processing in which the oil shale must be mined, crushed,
and heated, the in-situ process involves removing the oils
and gases from the oil shales through underground combustion,
and artificially increasing the permeability and surface
area of the rocks to increase the flow of process fluids.
Recovery of oil shale by in-situ combustion requires
the drilling of injection and recovery wells into relatively
impermeable confined oil-shale deposits. Hydraulic frac-
turing, electro-linking, explosive fracturing, or reverse
combustion are then used to create directional permeability
in which a self-sustaining combustion zone will spread
through the oil shale, producing gas and oil. Air is injected
along with propane or other combustible gas to ignite the
system. In a modified in-situ combustion process, part of
the oil shale is removed by underground mining and some is
rubblized to form a retort and to improve the efficiency of
the combustion process. Each retort is ignited and burned
individually to produce oil and gas.
Injection wells are not only used for injecting water
and gels in the rock-fracturing process, but also are used
-A-26-
-------
to inject detonants (pelletized or liquid nitroglycerine).
An electric ignition system is emplaced in the injection
well at depths opposite the open hole through the oil-shale
zone to be pyrolized. Recovery wells are spaced around the
injection well/ and are pumped to recover the produced oil
and gas. Table 2 lists additional characteristics of the
practice.
The oil shales of the Green River Formation/ the prin-
cipal source rock for in-situ combustion experiments, are in
Wyoming, Utah, and Colorado and are interbedded with evap-
orites. Thus, in much of their extent the ground water is
highly mineralized and does not meet stringent water-quality
standards. In the Piceance Creek Basin of northwestern
Colorado, however, the upper part of the shale beds contain
relatively fresh water. Heavy-metals content is a problem
in some parts of the aquifer system.
Ground water must be removed from the oil shales by
dewatering prior to combustion, but owing to the value of
the water resources, plans are generally developed for
reinjecting the water. Spent gels and solvents used in
fracturing must also be removed and are commonly disposed of
by injection into saline aquifers.
-A-27-
-------
Tar Sands
Tar sands are a type of petroleum deposit from which
the lighter fractions of crude oil have escaped, leaving a
residual tar, or asphalt composed principally of a mixture
of thick, viscous to semi-solid hydrocarbons essentially
free of oxygenated compounds. In-situ recovery of oil
and/or gas from tar sands is still essentially in an experi-
mental stage. Table 2 lists principal characteristics of
the practice.
One field experiment in the tar sands involved the
drilling of a row of three production wells flanked by two
rows of three injection wells each. The production and
injection wells were completed with a 10-ft open-hole
section in the production zone selected for pyrolysis. Air
and small quantities of propane were injected into the tar-
sand deposit at a rate of about 16,000 scf/hr (standard
cubic feet per hour) at 200 to 400 psig (pounds per square
inch). The production wells were constructed with two
strings of tubing; one to transmit cooling water to the
bottom of the production well, the other to convey hot,
vaporized oil and other gases, including steam, to the
surface.
Ignition of the tar sands was originated by use of a
600-watt calrod heater set in a pack of charcoal briquets
-A-28-
-------
about 10 ft long, filling the open-hole part of the wells
from the base to the top of the tar sands, which was gener-
ally at a depth of about 100 ft. Five gallons of diesel
fuel were poured to soak the charcoal to enhance ignition.
As combustion progressed in this experiment, some injection
wells were converted to production wells. In the reverse
combustion process of oil recovery from tar sands, the
combustion front travels in a direction opposite to the
direction of air flow. This carries hot gases and oil mists
toward recovery wells through that part of the tar sand that
was previously heated or burned.
-A-2 9-
-------
Geothermal Energy
Geothermal energy in the form of heat and hot water is
extracted from underground zones of high temperature associ-
ated with relatively shallow magma chambers, radioactivity,
and volcanism. Faults and other fractures are common in the
rocks. Surface manifestations of geothermal sources include
hot springs, geysers, and steam vents. However, these are
not always present, and some zones of potential geothermal
energy have been found through studies of temperature gra-
dients in deep exploratory wells. The geothermal heat
sources give rise to hydrothermal convection systems that
produce water at temperatures ranging from slightly above
ambient to hot. The water may be suitable for space heat-
ing, where the temperature ranges from 90°C to 150°C, and
may be used in the generation of electricity, where the
temperature exceeds 150°C.
The principal use of injection wells associated with
geothermal facilities is to dispose of brines brought to the
surface and to dispose of steam condensates from generating
plants. The only field in the United States presently pro-
ducing electricity and utilizing injection wells continuously
is the Geysers field in northern California (Figure A-14).
Here, nine injection wells return small amounts of condensate
back to the producing formation by gravity flow. The wells
-A-30-
-------
Figure A-14. Known Geothermal Areas in California and
Southern Oregon.
-A-31-
-------
have multiple casings and cement seals, and injection of the
water and steam condensates is accomplished by gravity flow
through the innermost string back into the producing forma-
tions. Figures A-15 and A-16 are construction diagrams for
geothermal recovery wells in northern and southern Cali-
fornia; the injection wells reportedly have similar con-
struction features. The rocks at the Geyser site are part
of the Franciscan series of metamorphic rocks which contain
fresh to saline ground water.
The use of geothermal injection wells in other areas,
including the Imperial Valley in southern California, is
largely experimental. The water is hot and corrosive, and
little or no potable ground water overlies the geothermal
zone. In addition to disposal of condensates and spent
brines, injection wells may serve to inject waters into deep
dry hot rock areas to develop geothermal energy. Although
the development of geothermal power generation requires high
temperature water, there are many areas of anomalously high
geothermal gradients, with temperatures ranging up to 150°C,
which can and are being developed for space heating, par-
ticularly in southern Oregon. Many of the low temperature
geothermal wells in Oregon are used for domestic, non-
commercial heating purposes and largely fresh water is
circulated through heat exchangers in wells that are operated
-A-32-
-------
Variable total depth depending on depth of
producing zone
Figure A-15. Construction Diagram of Geothermal Steam-
Producing Wells ir. the Geysers Area,
Northern California -A-33-
-------
(Note: Drawing not to
scale.)
/
Land
Surface
Conductor Pipe (20 in.
110 ft. (depth to bott'
of conductor pipe)
Surface Casing Bore Hole
(17-1/2 in.)
Surface Casing (13-3/8 i
900 ft. (hanging positio
of liner)
1,050 ft. (depth to bott
of surface casing)
Liner Bore Hole (10-5/8
(is drilled after the p
hole if potential produ
ing zone is indicated)
Blank Liner (8-5/8 in.)
Slotted Liner (8-5/8 in.
(is positioned adjacent
producing zone)
2,600 to 6,000 ft.
(depth range for bottom of pilot
hole)
Producing Zone
2,000 ft. £ (depth varies depe!
ing on the location of the
producing zone)
Remnant Pilot Hole (7-7/8 in.)
(is probably plugged before
well production, ?)
Figure A-16. Construction Diagram of a Geothermal Hot
arine-Producing Well, Southern California.
-A-34-
-------
as closed systems (Figures A-17 and A-18); these systems
have little or no potential for contamination. In this
respect, these low-temperature closed geothermal wells
appear to be much less a potential threat to fresh ground-
water resources than are the deep corrosive hot water geo-
thermal wells such as those in southern California.
-A—35-
-------
TO HEATING a
DOMESTIC USE
I * .
¦1A ~ ~\ \ 11 \ -iij
a U-Tube Heat Exchanger, Klamath Falls, 0 g
-------
SIMPLE U-TU86 HEAT EXCHANGER
Radiator
8. CONVENTIONAL COIL HEAT EXCHANGER
Figure A-18. Diagrams of Domestic Geothermal Heat Exchange
Systems and Wells, Klamath Falls, Oregon.
-A-37-
-------
APPENDIX B
SUMMARY OF EXISTING STATE AND FEDERAL
REGULATIONS GOVERNING CLASSIII WELLS
-------
APPENDIX B
Contents
Page
General Background B-l
Generalized Regulatory Controls B-2
Specific Regulatory Controls for Selected Practices B-4
In-Situ Uranium Leaching B-4
In-Situ Coal Combustion B-5
Solution Salt Mining B-5
Frasch Sulfur Mining B-7
Geothermal Wells B-8
-------
APPENDIX B
LIST OF TABLES
Table
B-l Regulatory Information for
Operations
B-2 Regulatory Information for
Leaching
B-3 Regulatory Information for
B-4 Regulatory Information for
B-5 Regulatory Information for
Page
General In-Situ Mining
B-ll
In-Situ Uranium
B-16
In-Situ Coal Gasification B-21
Solution Salt Mining B-26
Geothermal Wells B-32
NOTE: In Tables B-l through B-4, "X" indicates that regu-
lations or permit application forms list specific
stipulations for the given parameter, and "/" indi-
cates that stipulations regarding the parameter are
more vague.
In Table B-5 for Geothermal Wells, under "Regulatory
Approach," indicates that the parameter is less
stressed in the overall regulatory procedure.
For all tables, under "Regulatory Approach," numbers
listed for the Regulating or Permitting Agency(s)
are referenced on a separate page at the end of each
table.
-------
SUMMARY OF EXISTING STATE AND FEDERAL REGULATIONS
GOVERNING CLASS III WELLS
General Background
At the present time, most State agencies attempting to
regulate Class III injection wells (with the exception of
geothermal wells) do so through a case-by-case assessment of
mining, drilling or discharge permit applications. To pro-
vide a basis for this assessment, applicants are usually
required to include technical plans and pertinent geological
and hydrological information with the permit application
form; this information is reviewed and plans are evaluated
for their adequacy in meeting various environmental perfor-
mance standards that have been established in that State.
It should be noted, however, that permitting of Class III
operations in some States seems to be a superficial proce-
dure; consequently, a significant number of Class III wells
may be installed and operated under minimal regulatory
control by State agencies.
The following sections present a general summary both
of generalized and specific State and Federal regulations
that currently control Class III injection wells. For con-
venience, specific controls for each practice are discussed
separately, and are summarized in Tables B-l through B-5.
—B—1—
-------
The work in this section was originally included in Work
Order 8 but was placed for convenience in Work Order 2,
covering Class III injection wells.
Generalized Regulatory Controls
Several States which have Class III injection wells do
not have regulations designed specifically for a particular
mining practice, but do have general permitting procedures
that are applicable to any Class III operation (with the
exception of geothermal wells). These States include
Wyoming, Colorado, Utah, New Mexico, and Oklahoma. Wyoming,
Colorado, and Utah have more comprehensive information
requirements for permit application forms than do New Mexico
or Oklahoma. Other States have specific regulations for
certain Class III practices such as in-situ uranium leaching
(Texas and New Mexico), in-situ combustion (Texas), salt
solution (Kansas, Michigan^and Ohio), and geothermal (Cali-
fornia, Oregon, New Mexico, Idaho, Arizona^ and Utah). Fed-
eral regulations apply to geothermal activity on Federal lands.
In Wyoming, the Department of Environmental Quality,
Land Quality Division, requires all in-situ mining operators
to obtain either an In-Situ Mining Permit or a Research and
Development Testing License". In addition to these permits,
mining operations must comply with applicable parts of the
Land Quality Division's Rules and Regulations and the Water
Quality Division's Rules and Regulations.
-B-2-
-------
In Colorado, in-situ mining practices are permitted and
regulated through the Department of Health, Division of
Administration, and are required to comply with Rules for
Subsurface Disposal Systems and the Colorado Water Quality
Control Act. In Utah, in-situ mining operations are regu-
lated by the Code of Wa3te Disposal Regulations which are
issued by the Utah Department of Health; additional require-
ments for mining wells are contained in the Oil and Gas
Conservation Act, which is enforced by the Department of
Natural Resources. New Mexico requires in-situ mining
operations to comply with the Water Quality Control Commis-
sion Regulations', the Commission does not have a formal
permitting procedure but does require that persons intend-
ing to discharge contaminants must submit a Discharge Plan
for approval by the Director. In Oklahoma, the Water
Resources Board requires prospective mine operators to
submit an Application for a Waste Disposal Permit and also
requires operations to comply with Oklahoma's Water Quality
Standards and the Oklahoma Water Resources Board's Rules3
Regulations and Modes of Procedure. For additional regula-
tory information regarding general in-situ mining practices
in these States, see Table B-l.
—B-3-
-------
Specific Regulatory Controls For Selected Practices
In-Situ Uranium Leaching
In-situ leaching of uranium is regulated through a
case-by-case assessment of information submitted with
permit application forms in all States where this type of
mining is taking place. In Texas, the Department of
Water Resources receives and processes applications for
both Large Acreage Permits and Production Area Authoriza-
tions-, these applications must be given final approval by
the Texas Water Commission before well construction may
begin. New Mexico requires that uranium leaching opera-
tions obtain a Radioactive Materials License, which is
issued by the Radiation Protection Section of the Environ-
mental Improvement Division; in addition to this, leaching
operations are required to comply with the Regulations of
the New Mexico Water Quality Control Commission. Non-
agreement States often adopt Regulatory Guides that are
established by the NRC (U.S. Nuclear Regulatory Commis-
sion) ; the two main guides that are used are Standard Format
and Content of License Applications for Uranium Mills and
Preparation of Environmental Reports for Uranium Mills. In
addition to NRC guidelines, States may also require opera-
tions to comply with other requirements such as water-quality
control regulations and waste-discharge controls. For
-B-4-
-------
additional regulatory information regarding in-situ uranium
leaching, see Table B-2.
In-Situ Coal Combustion
Texas is the only State which has specific regulatory
procedures for in-situ coal combustion operations. In
this State, operators are required to obtain an In-Situ
Coal Gasification Operation Permit and are also required
to comply with relevant parts of the Rules of the Surface
Mining and Reclamation Division and the Texas Surface
Mining and Reclamation Act. Regulating and permitting is
mainly controlled by the Texas Railroad Commission, Surface
Mining and Reclamation Division. For additional regulatory
information regarding in-situ coal combustion, see Table
B-3.
Solution Salt Mining
The scope of existing State regulations for solution
salt mining activities ranges from established technical
requirements to virtually no regulatory control. In Kansas,
the Department of Health, Division of Environmental Health,
has promulgated specific technical standards for the con-
struction, operation, and abandonment of salt solution
wells; those standards are contained in the Kansas Corpora-
tion Commission's Rules and Regulations . Solution mining
-B-5-
-------
operators are also required to obtain a Permit for Produc-
tion of Brine from Subsurface Formations by Hydraulic
Methods. In Michigan, the Department of Natural Resources,
Geological Survey Division, controls both regulation and
permitting of solution mining operations. There are some
general technical standards, but for the most part regula-
tory control is accomplished through permitting require-
ments; prospective mine operators must submit both an
Application for a Mineral Well Permit and an Application
for a Permit to Drill, Deepen} Rework or Convert Mineral
Wells. Both technical requirements and permitting require-
ments are contained in. the Selected Rules Pertaining to
Brine Production Wells. Solution salt mining in Ohio is
mainly regulated by permit through the Ohio Department of
Natural Resources, Division of Oil and Gas, and the Ohio
Environmental Protection Agency. The DNR processes and
approves Applications for Permits to drill, Reopen3 Con-
vert, Deepen, Plug Back, or Plug and Abandon a Well', the
EPA processes and approves Applications for a Permit to
Drill and Test a Well for Industrial Wastewater Injection.
In Louisiana, the Department of Conservation, Minerals
Division, requires mining operators to obtain a Permit to
Drill for Minerals and also requires that operators comply
with applicable parts of the State-Wide Order (Number 29-B)
Governing the Drilling for and Producing of Oil and Gas in
_B -fi-
-------
the State of Louisiana. It should be noted, however, that
information requirements for permit application forms are
minimal and that few parts of State-Wide Order 29-B seem
applicable to solution salt mining operations. In West
Virginia, the Department of Mines, Oil and Gas Division,
requires that solution mining operators obtain an Oil and
Gas Well Permit; information requirements for the permit
application are minimal. After drilling has been completed,
operators must submit a Well Record to the Division. In
both Texas and Alabama there seems to be few specified
procedures for either regulating or permitting solution salt
raining. In Texas, wells penetrating the base of fresh
ground water may be subject to plugging and abandonment
requirements established by the Texas Railroad Commission.
For additional regulatory information regarding solution
salt mining, see Table B-4.
Frasch Sulfur Mining
Texas and Louisiana are the only two States where
Frasch sulfur mining is being done. In Texas, there is no
specified procedure for either regulating or permitting
Frasch operations. Sulfur wells that penetrate the fresh
ground-water base (<3,000 mg/1 TDS) may be subject to plugging
-------
and abandonment requirements established by the Texas Rail-
road Commission. In Louisiana, the Department of Conserva-
tion, Minerals Division, requires Frasch operations to
obtain a Permit to Drill for Minerals and also requires that
operators comply with applicable parts of the State-Wide
Order (Number 29-B) Governing the Drilling for and Producing
of Oil and Gas in the State of Louisiana. However, infor-
mation requirements for permit application forms are minimal
and few parts of State-Wide Order 29-B may be applicable to
Frasch sulfur mining. Because regulating and permitting
procedures for Frasch sulfur mining are essentially iden-
tical to the procedures governing solution salt mining, see
Table B-4 (under Louisiana and Texas) for additional regu-
latory information regarding Frasch operations.
Geothermal Wells
Regulations governing geothermal operations are sig-
nificantly different from regulations governing other Class
III practices in that practically all States having geo-
thermal resource potential have, in addition to environ-
mental performance standards, an established set of technical
requirements for drilling, operating, and abandoning geo-
thermal wells. Basically, these requirements are designed
-B—8-
-------
to implement the protection and conservation of geothermal
resources and to prevent environmental degradation. Permits
are also required for different phases of an operation such
as drilling, deepening, converting to injection, etc., but
the procedures and techniques specified in permit applica-
tion forms must comply with established technical standards
and thus are probably not allowed the same degree of tech-
nical flexibility that exists for other Class III operations.
Geothermal operations on Federal lands are mainly
regulated by the Geothermal Steam Act of 1970 and Regula-
tions on the Leasing of Geothermal Resources; these regula-
tions were, issued by the U.S. Geological Survey, Department
of Interior. For additional regulatory information
regarding geothermal wells, see Table B-5.
—B—9—
-------
Appendix Tables B-l through B-5
-B-10-
-------
Table B-l. REGULATORY INFORMATION FOR GENERAL IN-SITU MINING OPERATIONS
New
Mt:ilatory Approach
l*c(|t)lating or Permitting Agency (a)
Wyoming
1
Colorado
2
Utah
3
Mexico
4
Oklahoma
5
Date of Regulation or Permitting Enactment
1978
1976j 1975
1978}
1965] 1955
1977
1976» 1979
Case-by-Case (Regulation by Permit)
><
X
X
X
X
Compliance With Performance Standards (Environmental)
X
X
X
X
X
Compliance With Established Technical Standards
Assessment of Contents of Engineering Report
X
X
X
X
X
1) Independent Engineer Required
may be
required
I'erinit Application Contents
Background Information;
Area of Review (in Miles)
3
2
X
1
llydrologic Assessment of Permit Area
*
X
X
Geologic Assessment of Permit Area
X
X
X
X
Character of Mastes
X
X
X
X
X
Description of Injected Fluids
X
X
X
X
X
Wo 11 Construction Specifications
X
X
X
X
Casing Specifications
X
X
*
V
Cementing Plans
v/
X
y
J
Mr »n i I nf i nn PI
x:
X'
¦j
)<
-------
Table B-l (Continued)
New
'resting Plans
Wyoming
X
Colorado
X
Utah
Mexico
*
Oklahoma
Plugging and Abandonment Plans
X
X
><
Reclamation or Restoration Plans
X
X
X
Environmental Impact Statement
X
X
~
Contingency Plans
X
X
i.
Maintenance Plans
X
X
Subsidence Control Plans
X
.tional Information:
Drillers Logs
X
><
*
Core Analyses
X
z
Resistivity Surveys
7
rt
*
Casing Logs
7
Other Logs or Surveys
X
*
s/
Bottom Mole Pressure Test
X
Mechanical Integrity Test
><
X
Ground Water Analyses
X
X
X
X
(¦
-------
Table B-l (Continued)
Well Monitoring Requirements
Infection Volumes
Wyoming
X
Colorado
X
Utah
X
New
Mexico
X
Oklahoma
X
Injection Pressure
*
X
*
fluid Injected to Fluid Withdrawn Ratios
><
Periodic Well Integrity Testing Program
X
Monitor Wells Required
X
*
X
Continuous Annulus Pressure Monitoring
i«iin
-------
Table B-l (Continued)
Restoration or Reclamation
Wyoming
A
Colorado
Utah
X
New
Mexico
Oklahoma
Reporting Schedule
Weekly
Monthly
X
Quarterly
Annually
X
*
Plugging and Abandonment
Notification Required
*
*
Permit Required
Plugging Required
X
K
X
Nature of Plug
cement
Records or Reporting Required
X
Own^r Responsible
X
Restoration or Reclamation Required
X
X
X
-------
Regulatory Information for General In-sltu Mining
1. In-situ mining operations in Wyoming are required to comply with applicable parts of the "Rules and
Regulations" (July, 1978) issued by the Wyoming Department of Environemtnal Quality, Land Quality
Division; applications for both "In-situ Mining Permits" and "Researah and Development Testing
Licences" are filed through and approved by the Administrator of this Division. Mining operations
are also required to comply with the "Water Quality Rules and Regulations" established by the Wyoming
Department of Environmental Quality, Water Quality Division.
2. Class III mining operations are permitted through the Division of Administration, Colorado Department
of Health, and abide by the same regulating and permitting procedures that are required of sub-
surface Disposal Operations^ permit approval requires that mining operations comply with both "Rules
For Subsurface Disposal Systems" (July, 1976), and the "Colorado Water Quality Control Act" (July, 1965).
3. Class III mining operations are partially governed by the Utah State Department of Health under the
"Code of Waste Disposal Regulations", Parts I, II, and III (October, 1978; October, 1978; and May,
I 1965, respectively); additional requirements for mining wells are contained in the "Oil and Gas
® Conservation Act " (March, 1955), which is enforced by the Utah Department of Natural Resources,
-* Division of Oil and Gas, and Mining — mining permit applications are filed and approved thorugh
i this division.
4. Class III mining operations are governed by the New Mexico Water Quality Control Commission and are
required to comply with the "Water Quality Control Commission Regulations" (June, 1977); the Commis-
sion does not have a formal permitting procedure but does require that persons intending to discharge
contaminants that may enter ground water or surface water must submit a "Discharge Plan" for approval
by the Director.
5. The Oklahoma Water Resources Board would regulate and permit solution mining activities similarly to
waste disposal facilities. Prospective operators are required to submit an "Application for a
Waste Disposal Permit" and are also required to comply with "Oklahoma's Water Quality Standards"
(1976) and the "Oklahoma Water Resources Board — Rules, Regulations and Modes of Procedure"
(revised, 1979). Note; Sources indicate that there may presently be no Class III operations in
Oklahoma.
-------
Table B-2. REGULATORY INFORMATION FOR IN-SITU URANIUM LEACHING
Regulatory Approach
Herniating or Permitting Agency(s)
Texas
1
New
Mexico
2
USNRC
3
Date of Regulation or Permitting Enactment
1978
1971; 1977
1977j 1978
Caae-by-Case (Regulation by Permit)
><
X
X
Compliance With Performance Standards (Environmental)
*
X
X
Compliance With Established Technical Standards
Assessment of Contents of Engineering Report
X
X
X
1) Independent Engineer Required
Radioactive Materials License Required
/
X
X
Permit Application Contents
background Information:
Area of Review (in Miles)
2
1
X
llydrologic Assessment of Permit Area
X
X
X
Geologic Assessment of Permit Area
X
*
X
Character of Wastes
X
X
X
Description of Injected Fluids
*
X
X
Well Construction Specifications
X
X
Casing Specifications
*
V
Cementing Plans
X
7
-------
'Table B-2 (Continued)
Testing Plans
Texas
~
new
Mexico
X
USNRC
Plugging and Abandonment Plans
X
V
Reclamation or Restoration Plans
X
><
X
Environmental Impact Statement
X
X
Contingency Plans
X
X
X
Maintenance Plans
X
X
v/
Subsidence Control Plans
itional Information:
Drillers Logs
X
n/
Core Analyses
yj
Resistivity Surveys
Casing Logs
Othor Logs or Surveys
Uottoin Hole Pressure Test
Mechanical Integrity Test
Ground Water Analyses
X
X
X
-------
Table B-2 (Continued)
Well Monitoring Requirements
Injection Volumes
Texas
Mexico
X
USNRC
Injection Pressure
X
X
Fluid Injected to Fluid Withdrawn Ratios
X
Periodic Well Integrity Testing Program
Monitor Wells Required
X
X
X
Continuous Annulus Pressure Monitoring
Monitoring After Cessation of Operations
X
X
y
Record Keeping and Reporting
Well llistorv Records
X
/
Well Completion Records
X
~
Production Records
X
X
Iniection Records
X
Site Inspections
X
Monitorinq Data
X
X
X
Well Tnteqritv Testinq Data
Remedial Action
X
X
Nol.J fication of Intent to Abandon
X
I'lixiqinq and Abandonment
X
-------
Table B-2 (Continued)
New
Restoration or Reclamation
Texas
*
Mexico
X
USNRC
*
Reporting Schedule
Weekly
Monthly
X
Quarterly
Annually
Plugging and Abandonment
Notification Required
X
Horuiit Required
1'lugging Required
Nature of Plug
Records or Reporting Required
X
~
X
Owner Responsible
Restoration or Reclamation Required
><
X
X
-------
Regulatory Information for In-aitu Uranium Leaching Operations
1. The Texas Department of Water Resources regulates iri-situ uranium leaching operations through a
case-by-case assessment of permit applications, applications must be filed for both a "Large
Acerage Permit" and a "Production Area Authorization" (reflects organization as of March, 1978)j
these applications must be given final approval by the Texas Hater Commission before construction
may begin.
2. The New Mexico Radiation Protection Section of the Environmental Improvement Division reviews
permit applications and approves "Radioactive Materials Licences" (1971); the New Mexico Water
Quality Control Commission requires that leaching operations abide by the "Water Quality Control
Commission Regulations" (June, 1977) (the Commission does not have a formal permitting procedure
but does require that persons intending to discharge contaminants must submit a "Discharge Plan"
to the Director for approval.)
0 3. The U.S. Nuclear Regulatory Commission has developed Regulatory Guides for "Standard Format and
^ Content of Licence Applications for Uranium Mills" (November, 1977) and "Preparation of Environ-
ed mental Reports for Uranium Mills" (September, 1978). Although those guides were actually
1 developed for uranium mills, they are often applied to in-situ uranium leaching operations in
Non-agreement States) these operations are usually required to attain a "NRC Source Materials
Licence" before mining may begin.
-------
Table B-3. REGULATORY INFORMATION FOR IN-SITU COAL COMBUSTION
Regulatory Approach
Itegulating or Permitting Agency (a)
Taxas
1
Hate of Regulation or Permitting Enactment
1977
Ctisii-by-Case (Regulation by Permit)
X
Compliance With Performance Standards (Environmental)
X
Compliance With Established Technical Standards
Assessment of Contents of Engineering Report
X
1) Independent Engineer Required
Permit Application Contents
background Information:
Area of Review (in Miles)
1
llydrologic Assessment of Permit Area
*
Geologic Assessment of Permit Area
A
Character of Wastes
X
Description of Injected Fluids
X
Well Construction Specifications
X
Caning Specifications
X
Cementing Plans
<
v/
-------
Table B-3 (Continued)
Testing Plans
Texas
Plugging and Abandonment Plans
Reclamation or Restoration Plans
X
Environmental Impact Statement
><
Contingency Plans
><
Maintenance Plans
X
Subsidence Control Plans
X
tional Information:
Drillers Logs
X
Core Analyses
X
Resistivity Surveys
~
Casing Logs
Other Logs or Surveys
Bottom Hole Pressure Test
Mechanical Integrity Test
Ground Water Analyses
X
-------
Table B-3 (Continued)
Well Monitoring Requirements
Injection Volumes
Texas
X
1
1
Injection Pressure
fluid Injected to Fluid Withdrawn Ratios
Periodic Well Integrity Testing Program
Monitor Wells Required
X
Continuous Annulus Pressure Monitoring
Monitoring After Cessation of Operations
Record Keeping and Reporting
Well History Records
Well Completion Records
Production Records
luicction Records
y
Si to Inspections
Monitoring Data
*
Well Tnteciritv Testinq Data
Remedial Action
Notification of Intent to Abandon
PI u«i
-------
Table B-3 (Continued)
Restoration or Reclamation
Texas
lie porting Schedule
Weekly
Monthly
Quarterly
Annually
Plugging and Abandonment
Notification Required
Permit Required
Plugging Required
X
Nature of Plug
Records or Reporting Required
Owner Responsible
Restoration or Reclamation Required
X
-------
Regulatory Information for In-sltu Coal Combustion Operations
!• Applications for "In-Situ Coal Gasification Operation Permits" (October, 1977), are submitted
and approved by the Director of the Surface Mining and Reclamation Division, Texas Rail Road
Commission. All operations are required to comply with the rules and regulations presented
in "Rules of the Surface Mining and Reclamation Division" and "Texas Surface Mining and Re-
clamation Act."
I
w
i
to
(_n
I
-------
Table B-4. REGULATORV INFORMATION FOR SOLUTION SALT MINING
hu(|iilatory Apiicoach
Regulating or Permitting Agenoy(s)
Kansas
1
Michigan
2
Alabama
3
Ohio
4
Texas
5
Louisiana
6
West
Virginia
7
DaU of Regulation or Permitting Enactment
1979
1972
1978
1963, 1967
OjiiU-by-Caae (Regulation by Permit)
A
*
*
~
Compliance With Performance Standards (Environmental)
X
X.
X
Compliance Hith Established Technical Standards
X
7
Assessment of Contents of Engineering Report
X
X
X
1) Independent Engineer Required
Permit Application Contents
background Information!
Area of Review (in Miles)
X
2
llydroloylc Assessment of Permit Area
y
X
Otologic Assessment of Penult Area
X
X
character of Wastes
X
X
X
Inscription of Injected Fluids
X
X
Hull Construction Specifications
X
X
X
Casing Specifications
A
X
X
Cemunting Plans
*
X
X
Monitoring Plans
-------
Table B-4 (Continued)
West
Tusting Plans
Kanaaa
Michigan
X
Alabama
Ohio
X
Texas
Louisiana
Virginia
Plugging and Abandonioent Plana
X
Keclduiation or Restoration Plana
/
fclnviroiintcntal Impact Statement
Contingency Pl<*ns
X
Maintenance Plana
Subsidence Control Plana
~
)<
Kecording and Reporting Plana
X
tional Information!
DrilUru Logs
X
*
v/
X
Core Analyses
X
Hcaiativity Surveys
X
Casing Logs
v/
X
Other Logs or Surveys
/
Bottom llole Pressure Test
a
X
Mechanical Integrity Test
X
Giound Hater Analyses
X
X
-------
Table B-4 (Continued)
Technical Requirements For
Well Construction and Operation
General Drilling Requirements
Kansas
Michigan
X
Alabama
Ohio
Texaa
Louisiana
West
Virginia
Hull Spacing-location Requirements
X
Casing Mqulreiwnts (General)
X
X
Surface Casing Requirement!!
X
Production Casing Requirements
*
Cementing Requirements (General)
X
X
Cementing of Surface Casing
X
Cementing of Production Casing
X
Minimum Salt Roof Thickness
X
Hiixinuin Horizontal Diameter of Solution Cavity
X
Initial Testing for Mechanical Integrity
~
X
periodic Testinq for Mechanical Inqeqritv (years)
2
Mechanical Integrity Testing After Temporary
Abandonment
X
W:rio
-------
Table B-4 (Continued)
Mast
Well Monitoring Requirements
Infection Volumes
Kansas
X
Michigan
X
Alabama
Ohio
X
Texas
Louisiana
Virginia
Injection Pressure
X
X
X
Fluid Injected Co fluid Withdrawn Ratios
X
X
Periodic Well Integrity Testing Program
X
Monitor Hells Required
X
Continuous Annulus Pressure Monitoring
|
Monitoring After Cessation of Operations
|
Subsidence Monitoring
X
X
Record Keeping and Reporting
Wo 11 llistorv Records
X
X
Info 11 Completion Records
X
X
X
Product ion Records
X
X
In taction Records
X
X
|
Situ Inspections
v/
Honitorii^a Data
X
J
HliII tiiL«i>iri Cv Tustln'i Data
X
X
J
lunikiilidl Action
X
X
Notification of Intent to Abandon
X
I'l ti
-------
Table B-4 (Continued)
Restoration or Reclamation
Kansas
Michigan
v/
Alabama
Ohio
Texas
Louisiana
Virginia
Subsidence or Surface Elevation Changes
><
X
Ruportinq Schedule
Weekly
Hon Lilly
Quarterly
Annually
X
X
Plugging and Abandonment
Notification Required
X
I'ertuit Required
IMmjying Required
N.ituiu of Plug
cement
Huooids or Re|>orting Required
X
X
CMnor Responsible
KuuLoratlon or Reclamation Required
X
-------
Regulatory Information for Solution Salt Mining
1. In Kansas solution salt mining operations are both permitted and regulated through the Kansas State
Department of Health, Division of Environmental Health. Kansas does have "technical standards" for
construction, operation, and abandonment of salt solution wells; these regulations are contained in
the "Kansas Corporation Commission's Rules and Regulations" (effective May, 1979). Mining permits
are required; there is a specific application form titled "Application for Production of Brine From
Sub-surface Formations By Hydraulic Methods."
2. The Michigan Department of Natural Resources, Geological Survey Division, controls both permitting
and regulation of solution salt mining operations. Regulations, presented in "Selected Rules Per-
taining to Brine Production Wells" (effective July, 1972), do specify some general technical
standards but for the most part require operators to include specific technical information in
permit application forms; these include; "Application For a Mineral Well Permit" and "Application
For a Permit to Drill, Deepen, Rework or Convert Mineral Wells". Additional regulation of solu-
tion salt mining is imposed through "Act number 315 of the Public Acts of 1969"j this Act is
designed to provide control for drilling, operating and abandoning mineral wells.
3. According to the Alabama Geological Survey, there is presently no specific format for either regulating
or permitting solution mining activities.
4. Solution mining in Ohio is mainly regulated by "Permit" through both the Ohio Department of Natural
Resources, Division of Oil and Gas, and the Ohio Environmental Protection Agency. The Division of
Oil and Gas processes and approves "Applications for Permits to Drill, Reopen, Convert, Deepen, Plug
Back, or Plug and Abandon a Well" (Required by Chapter 1509 of the Ohio Revised Code; July, 1978).
The EPA processes and approves "Applications for a Permit to Drill and Test a Well for Industrial
Wastewater Injection."
5. According to the Texas Department of Water Resources, Texas presently has no specified procedure
for either regulating or permitting solution salt mining (and Frasch Sulfur mining). If wells
penetrate the ground water base (less than ^000 TDS) they may be subject to plugging and abandon-
ment requirements established by the Texas Rail Road Commission.
6. The State of Louisiana, Department of Conservation, Minerals Division, has promulgated the "State-Wide
Order (Number 29-B) Governing the Drilling For and Producing of Oil and Gas in the State of Louisiana"
(effective July, 1943; revised October, 1967); this same Order is "supposedly" applied to both solution
salt mining and Frasch sulfur mining operations. Mine operators are required to obtain a "Permit to
Drill for Minerals", which is issued by the Department of Conservation. Note: information require-
ments on the "Application for Permit to Drill (or Renew) for Minerals" are minimal.
7. The West Virginia Department of Mines, Oil and Gas Division, requires that solution salt mining opera-
tions obtain an "Oil and Gas Well Permit"; information requirements for the permit application are
minimal. After drilling has been completed, operators must submit a "Well Record" to the Division.
»
W
I
u>
I—'
I
-------
Table B-5. REGULATORY INFORMATION FOR Gi
Kugulatory Approach
Rnqulatimj or Permitting Agency(s)
iOTHERMAL
California
1
WELLS
Idaho
2
New
Mexico
3
Oregon
4
Arizona
5
Utah
6
Nevada
7
Federal
Lands
a
OaLe of Regulation or Perialttlng enactment
1978) 1971
197a
1974
1979
1972
197B
1969j 1975
1976
Couiiillance With Performance Standards (Enviro.)
V
v/
V
/
/
V
~
Coni|iliancu With Established Technical Standards
x
X
X
X
X
X
X
Case-by-Case (Regulation by Permit)
v/
y
V
v/
V
X
~
Drilling Requirements
General Requirements
X
X
X
X
X
Ikjsignat ion o£ Agent
X
X
X
X
bond Requirement
*
X
X
X
X
X
Drilling Penult Or Approval
X
X
X
X
X
X
X
X
M.il'tt and Geoloqical Assessment of Area
X
X
X
¦tuviuw of Existing Wells in Area
X
X
ivriuit or Approval To Dee|>en, Redrill,
I'lug. or Alter Caslnq
X
X
X
X
X
X
X
Permit Or Approval I'D Drill Observation Hells
X
n/
/
X
^uppleutentarv Drillinq Approval
X
X
X
X
X
X
milling Requirements in Unstable Terrain
X
7
funutt To Convert To Injection
X
X
V
-/ •
X
IWuiiL Peu Required
X
X
X
X
X
Sign On Wells
X
X
X
X
X
X
Well Location Map
X
X
X
X
X
X
X
-------
Table B-S (Continued)
New Federal
Well Spacing and Location Requirements
General Requirements
California
Idaho
X
Mexico
Oregon
X
Arizona
X
Utah
X
Nevada
Lands
X
For txploration Wells
i
:>
X
X
For Development Wells
X
X
For Induction Wells
X
X
For Disposal Wells
<
w
e*
M
ft
X
For I
-------
Table B-5 (Continued)
Cgaiiui and Ceaontln^ Requirements
General Requirements
California
Idaho
X
New
Mexico
Oregon
Arizona
Utah
Nevada
K
Federal
Lands
Conductor Pipe
J
Surface Casing
J
length of Surface Casing
Couuiating Point For fiurfaca Casing
:L
Mud Haturn Temperature Monitoring
X
U0&>£ Bofora Drilling Shot*
Intermediate Casing
Production Caalng
Casing and Cement Vesta
Defective Caalng or Cementing edlal Action)
LluctrAc or Radioactive logs
Cementing Kequirements (General)
Completion and Production
Nullification of Hell Completion
X
X
I'roUuct ion Koports
X
Kt|uH*ment Maintenance
Cmcoaion Surveillance (aurface equipment)
X
Mechanical Integrity Testing (periodic)
v/
7
X
-------
Table B-5 (Continued)
Right of Entry Stipulation
California
*
Idaho
New
Mexico
Oregon
Arizona
X
Utah
Nevada
Federal
Lands
Hecorda and Report Requirements
Drilling Log and Care Records
X
X
X
X
X
X
X
X
Well History Records
X
X
X
X
X
X
X
Production Record*
X
X
X
X
X
X
X
Well Inspection Records
X
*
¦J
X
Report on Cosing and Cementing Job Teat
><
X
X
X
y
*
Report ont Plugging and Abandonment
X
X
X
X
X
X
X
Report of Remedial Work
/
X
X
X
V
X
Report of Change of Ownership
X
X
X
X
X
y
Injection Records
X
X
X
X
X
infection and Disposal Well Requirements
I'ermit to Drill New Well or Convert Existing Well
X
*
X
*
X
Haps And Geologic Assessment of Injection Zone
X
X
X
rt
V
Review of Existing Wells in Area
X
X
Detailed Sketch of Proposed Injection Well
Con^Lruct ion
*
X
*
-------
Table B-5 (Continued)
injection Raporta
California
X
Idaho
*
New
Mexico
X
Oregon
Arizona
X
Utah
*
Nevada
Federal
Lands
Mechanical Integrity Testing
X
X
X
X
X
Surveillance and Monitoring
X
X
X
X
Mugging and Abandonment Requirements
X
X
X
X
Remedial Action
X
*
X
X
Monitoring injection Pressures
X
X
Abandonment Requirements
Nuticu of Intention to Abandon
X
X
*
X
X
X
X
General Requirements
X
X
X
X
X
X
X
slugging Requirements
X
X
X
X
X
X
X
Temporary Abandonment
X
y
X
Abandonment of Exploratory Wella
X
X
X
Abandonment of Cased Hells
X
Abandonment of Deserted Wells
X
Abandonment of Injection Hells
X
X
X
1. lability (person (s)) Responsible For
IJ1 uqg ing
X
X
-------
Regulatory Information for Geothermal Wella
1. The California Department of Conservation# Division of Oil and Gas, imposes "State-Wide Geothermal
Regulations** (revised, August, 1979); the Division of Oil and Gas also has published "California
Laws for Conservation of Geothermal Resources" (approved September, 1965), and "Drilling and Operat-
ing Geothermal Wells in California" (published, 1976).
2. The Idaho Department of Water Resources issues "Drilling for Geothermal Resources, Rules and
Regulations and Minimum Well Construction Standards" (June, 1978), and "Well Construction Standards,
Rules,and Regulations" (June, 1976).
3. The New Mexico Energy and Minerals Department, Oil Conservation Division, imposes "Rules and Regul-
ations for Geothermal Resources" (October, 1974).
4. The Oregon Department of Geology and Mineral Industries imposes "Laws and Administrative Rules
Relating to Geothermal Exploration and Development in Oregon" (revised, 1979).
W 5. The Oil and Gas Conservation Commission of the State of Arizona has promulgated "Rules and Regulations
I Regarding Geothermal Resources" (June, 1972).
OJ
¦sj
I 6. in Utah, the Division of water Rights has issued "Rules and Regulations for Wells Used for the
Discovery and Production of Geothermal Energy" (adopted March, 1978).
7. in Nevada, the Department of Conservation and Natural Resources, Division of Water Resources, imposes
"Rules and Regulations for Drilling Wells and Other Related Material" (reprinted, 1969)j the Dep-
artment of Human Resources, Environmental Protection Service, has a general permitting procedure for
prospective geothermal operationsj the Nevada Revised Statutes contain an abbreviated version of
"Regulations for Development., Control, and Conservation of Geothermal Resources" (added in 1975).
8.
The United States Geological Survey, U.S. Department of Interior, has promulgated the "Geothermal
Steam Act of 1970 and Regulations on the Leasing of Geothermal Resources" (October, 1976).
------- |