&EPA
United States
Environmental Protection
Agency
Industrial Environmental Research EPA-600.'7-78-101
Laboratory June 1978
Cincinnati OH 45268
Research and Dewetoprnent
Pollution Control
Guidance for
Geothermal
Energy
Development
Interagency
Energy-Environment
Research
and Development
Program Report
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RESEARCH REPORTING SERIES
Research reports of the Office of Research and Development, U.S. Environmental
Protection Agency, have been grouped into nine series. These nine broad cate-
gories were established to facilitate further development and application of en-
vironmental technology. Elimination of traditional grouping was consciously
planned to foster technology transfer and a maximum interface in related fields.
The nine series are:
1. Environmental Health Effects Research
2. Environmental Protection Technology
3. Ecological Research
4. Environmental Monitoring
5. Socioeconomic Environmental Studies
6. Scientific and Technical Assessment Reports (STAR)
7. Interagency Energy-Environment Research and Development
8. "Special" Reports
9. Miscellaneous Reports
This report has been assigned to the INTERAGENCY ENERGY-ENVIRONMENT
RESEARCH AND DEVELOPMENT series. Reports in this series result from the
effort funded under the 17-agency Federal Energy/Environment Research and
Development Program. These studies relate to EPA's mission to protect the public
health and welfare from adverse effects of pollutants associated with energy sys-
tems. The goal of the Program is to assure the rapid development of domestic
energy supplies in an environmentally-compatible manner by providing the nec-
essary environmental data and control technology. Investigations include analy-
ses of the transport of energy-related pollutants and their health and ecological
effects; assessments of, and development of, control technologies for energy
systems; and integrated assessments of a wide range of energy-related environ-
mental issues.
This document is available to the public through the National Technical Informa-
tion Service, Springfield, Virginia 22161.
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EPA-600/7-78-101
June 1978
POLLUTION CONTROL GUIDANCE
FOR
GEOTHERMAL ENERGY DEVELOPMENT
by
Robert P. Hartley
Industrial Environmental Research Laboratory
Cincinnati, Ohio 45268
INDUSTRIAL ENVIRONMENTAL RESEARCH LABORATORY
OFFICE OF RESEARCH AND DEVELOPMENT
U. S. ENVIRONMENTAL PROTECTION AGENCY
CINCINNATI, OHIO 45268
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DISCLAIMER
This report has been reviewed by the Industrial Environmental Research
Laboratory, U. S. Environmental Protection Agency, and approved for publica-
tion. Mention of trade names or commercial products does not constitute
endorsement or recommendation for use.
ii
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FOREWORD
When energy and material resources are extracted, processed, converted,
and used, the related pollutional impacts on our environment and even on our
health often require that new and increasingly more efficient pollution
control methods be used. The Industrial Environmental Research Laboratory -
Cincinnati (lERL-Ci) assists in developing and demonstrating new and improved
methodologies that will meet these needs both efficiently and economically.
This report provides preliminary pollution control guidance to be used
by developers and regulators of geothermal energy. The report and similar
ensuing reports are intended to develop the technical basis for eventual
regulations.
Further information on the subjects of this report can be obtained from
the Power Technology and Conservation Branch, Industrial Environmental
Research Laboratory, Cincinnati, Ohio 45268.
David G. Stephan
Director
Industrial Environmental Research Laboratory
Cincinnati
iii
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PREFACE
This document originated as a result of the Environmental Protection
Agency (EPA) concern as a member of the Interagency Geothermal Coordinating
Council, that the development of geothermal energy as an alternative energy
source not be constrained by uncertainties about environmental standards.
It is the intent of EPA to ensure that technology-specific environmental
goals are developed and maintained during the course of geothermal technology
development in order that undue development delays be avoided and that a
mature geothermal industry, compatible with national environmental goals,
can be established.
The EPA envisions this document as the first of a series leading
toward the establishment of regulatory standards for the geothermal industry.
The series is expected to serve several purposes. First and foremost, it
will serve to communicate EPA regulatory policies to geothermal developers
on a comprehensive basis. Second, the series will update the state of
knowledge with respect to known geothermal pollutants and their potential
effects. Third, the series will describe state-of-the-art control techno-
logies as they evolve and will describe the remaining needs where techno-
logies are not sufficient. Finally, it will suggest ranges of discharge and
emission limits within which the geothermal industry should strive to operate.
Ideally, as more information becomes available, each document in the series
will offer more definitive limits and more demonstrated confidence in avail-
able control technologies. The series would culminate in a document provid-
ing the basis for legally defensible regulations,
This document, as the first of the series, presents general information
relevant to geothermal pollution problems and their control as they are
viewed today. It should be kept in mind that the present data base is
meager and that attempts to precisely define problems and their control
would be incomplete. The purpose here is to present a first approximation
to EPA's regulatory expectations and thereby to generate, through their pub-
lication, the necessary concern, proper perspective, and a logical and
predictable approach to geothermal pollution control.
This document was prepared by the EPA, with guidance, input and review
from its Geothermal Working Group, chaired by Dr. Gregory J. D'Alessio,
Office of Energy, Minerals and Industry. The following EPA offices were
represented:
- Office of Energy, Minerals and Industry
- Office of Water Supply
Office of Planning and Management
iv
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Office of Water Planning and Standards
- Office of Air Quality Planning and Standards
- Office of Radiation Programs
Office of Noise Control Programs
- Office of Solid Waste Programs
The principal author of this document was Robert P. Hartley, Office of
Energy, Minerals and Industry, Industrial Environmental Research Laboratory-
Cincinnati. Several offices of the Department of Interior, Department of
Energy, and other agencies have reviewed the document, and revisions, where
appropriate have been incorporated.
Readers are urged to make known to the Environmental Protection Agency
their views as to the content of this document. Comments should be addressed
to:
U. S. Environmental Protection Agency
Office of Energy, Minerals and Industry
401 M Street, SW
Washington, D.C. 20460
v
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ABSTRACT
This report summarizes the EPA regulatory approach toward geothermal
energy development. The state of knowledge is described with respect to the
constituents of geothermal effluents and emissions, including water, air,
solid wastes, and noise. Pollutant effects are discussed. Pollution control
technologies that may be applicable are described along with preliminary cost
estimates for their application. Finally discharge and emission limitations
are suggested that may serve as interim guidance for pollution control during
early geothermal development.
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CONTENTS
FOREWORD ill
PREFACE iv
ABSTRACT vi
FIGURES x
TABLES xii
I. SUMMARY AND CONCLUSIONS 1
Perspective 1
EPA Regulatory Approach 2
Precommercialization Regulations 2
Surface Water Protection 2
Ground Water Protection 2
Air Quality Protection 3
Noise Protection 3
Radiation Protection 3
Geothermal Pollutants and Sources 3
Environmental Concerns from Known Pollutants 5
Water Pollutants 5
Air Pollutants 5
Noise 6
Land-Disposed Wastes 6
Radiation 7
Pollution Control Technology 7
Air Pollution Control 7
Water Pollution Control 8
Land-Disposed Waste Control 10
Noise Control 10
II. RECOMMENDATIONS 11
Suggested Pollutant Limitations 11
Air Emissions 11
Water Discharges H
Land-Disposed Wastes 12
Noise 12
Monitoring 12
Control Technology and Regulatory Development Needs ... 12
III. INTRODUCTION 13
Objectives 13
Background 13
Standards Problem 13
Perspective 13
vii
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EPA Geothermal Pollution Control Regulatory Approach . . 15
Air Pollution 16
Water Pollution 16
Land-Disposed Wastes • • 17
Noise 17
Radiation 18
IV. GEOTHERMAL POLLUTANTS AND PROCESS SOURCES 19
Wellfield Exploration, Development and Construction
Activities 19
Fluid Distribution and Energy Conversion System
Operations 20
Pollutants Derived from Geothermal Fluid 23
Noise Derived from Geothermal Operations 27
V. ENVIRONMENTAL EFFECTS OF KNOWN POLLUTANTS 30
General 30
Water Pollutants 30
Human Use 32
Aquatic Life 32
Agricultural Use 35
Industrial Water Supply 35
Air Pollutants 37
Effects on Humans 37
Effects on Plants and Crops 39
Noise Pollution 40
Land-Disposed Wastes 40
Radiation 40
VI. POLLUTION CONTROL TECHNOLOGY 41
Air Pollution 41
Stretford Process 41
Iron Catalyst Process 44
EIC Process 48
Dow Oxygenation Process 53
Other H£S Removal Processes . 58
Water Pollution 63
Wastewater Treatment Technologies 63
Wastewater Disposal Technologies 83
Solid Waste Disposal 103
Noise Control 104
VII. SUGGESTED POLLUTANT DISCHARGE LIMITS 106
General 106
Air Pollutant Limitations 106
Hydrogen Sulfide 106
Other Noncondensible Gases 107
Water Pollutant Limitations 107
Electric Power Generation 108
viii
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Non-Electric Uses 109
Sanitary Wastes and Construction Wastes 109
Land-Disposed Waste Limitations 110
Noise Limitations 110
VIII. FUTURE DEVELOPMENT OF EFFLUENT AND EMISSION STANDARDS ... Ill
IX. EFFLUENT AND EMISSION MONITORING 114
Air and Water Point Source Monitoring 114
Ambient Air Monitoring 115
Ambient Water Monitoring 116
Ground Water Monitoring 117
Land-Disposed Wastes 118
Noise Monitoring 118
Baseline Air and Water Monitoring 119
REFERENCES CITED 120
APPENDIX - Summary of Laws Requiring or Related to
Geothermal Pollution Control 126
ix
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FIGURES
Number Page
1 Simplified diagram of open cycle geothermal electric
power generation system • 21
2 Simplified diagram of closed loop geothermal electric
power generation system 22
3 Simplified diagram of non-electric use of geothermal
energy 22
4 Ranges of chemical constituent concentrations in
geothermal fluids 24
5 Noncondensible gases in geothermal fluids 25
6 Cumulative frequency distribution from radon-222 in
geothermal waters 26
7 Flow diagram of a Stretford Process 42
8 Stretford annual cost (mill/kwh) vs. power generation ... 44
9 Iron catalyst hydrogen sulfide removal process 45
10 Iron catalyst annual cost (mill/kwh) vs. power generation . 47
11 EIC H£S removal process with regeneration by raosting ... 48
12 EIC l^S removal process with regeneration by leaching ... 49
13 EIC annual cost (mill/kwh) vs. power generation 53
14 Dow oxygenation I^S removal process with in-line mixers . . 54
15 Dow oxygenation B^S removal process with cocurrent packed
tower 54
16 Dow oxygenation in-line system annual cost (mill/kwh) vs.
power generation 57
17 Dow oxygenation packed system annual cost (mill/kwh) vs.
power generation 58
18 Solid sorption H^S removal process 59
19 Claus sulfur recovery process 60
20 Cut-away view of a granular mixed media filter ...... 65
21 Cost estimates for sedimentation 67
22 Cost estimates for chemical precipitation with single
stage lime addition 68
23 Cost estimates for chemical treatment for 2-stage lime
addition * . . . 68
24 Cost estimates for chemical precipitation with alum
addition 69
25 Cost estimates for chemical precipitation with ferric
chloride addition 69
26 Cost estimates for filtration 70
27 Schematic presentation of reverse osmosis '. . . . 71
28 Cost estimate for reverse osmosis system 72
29 Electrodialysis cell 72
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Number Page
30 Cost estimates for electrodialysis system 73
31 Mixed-bed ion exchange process 75
32 Cost estimates for ion exchange system 75
33 Principle of multiple stage flash evaporation 76
34 Multiple effect evaporation 77
35 Principle of compression still 77
36 Total costs for evaporation 78
37 Application of treatment technologies for achieving three
effluent quality levels from high level waste 84
38 Application of treatment technologies for achieving three
effluent quality levels from mid level waste 85
39 Application of treatment technologies for achieving three
effluent levels from low level waste 86
40 Typical injection well set-up 88
41 Hole size cost comparison for wells (capital cost only) . 93
42 Annualized capital cost for injection of geothermal
wastewaters 96
43 Total annual cost of evaporation ponds versus pond surface
area 100
44 Annualized investment cost of spill containment ponds
(10-foot depth) 103
45 Typical multi-chamber silencer 105
46 Twin-cylinder centrifugal expansion muffler for large
volume fluid wasting 105
xx
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TABLES
Number Page
1 Sound Levels from Various Sources at the Geysers 28
2 Pollutants Limited by Water Quality Standards in States
with Geothermal Potential 31
3 Effects on Humans of Oral Ingestion of Compounds .... 33
4 Aquatic Life Criteria for Constituents in Geothermal
Fluid 34
5 Agricultural Use Criteria for Constituents in Geothermal
Fluids 36
6 Total Dissolved Solids Concentrations in Surface Waters
That Have Been Used as Sources for Industrial Water
Supplies 37
7 Effects on Humans of Inhalation of Gases or Vapors ... 38
8 Hydrogen Sulfide Effects on Humans 39
9 Efficiencies of Control Technologies for Treatment of
Specific Constituents in Wastewaters 80
10 Assumed Geothermal Waste Brine and Surface Water
Discharge Concentrations 81
11 Geothermal Waste Brine Flow Rates and Concentration
Levels for Various Uses 81
12 Removal Efficiencies Required for Treating Various
Levels of Raw Geothermal Fluids 82
13 Assigned Efficiencies of Various Treatment Systems
for Removing Gross Constituents 82
14 Capital Costs for Injection Systems at Four Well
Capacities 95
15 Operating Energy Costs for Injection Pumps 97
16 Cost of Ocean Disposal of Geothermal Wastewaters .... 98
17 Estimated Water Surface Area Required for Disposal
of Geothermal Plant Wastewaters 99
18 Estimated Maximum Hydraulic Loading of Wastewater
Effluent for Various Soil Conditions 101
19 Annual Cost of Disposal of Geothermal Wastewater
by Land Spreading 102
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I. SUMMARY AND CONCLUSIONS
PERSPECTIVE
The total geothermal resource in the United States is immense, but its
exploitation is technologically and economically limited to geologically
anomalous areas where high temperatures are very near the surface. Geothermal
energy will contribute a relatively small fraction of the nation's total
energy requirement in the foreseeable future. However, locally and perhaps
regionally, its contribution may be very important, particularly in the
western and southwestern United States before the turn of the century.
The magnitude of pollution problems resulting from geothermal exploita-
tion is directly related to the scope of development. Discharges from
geothermal activities are not foreseen as threats to the national health
and welfare, but may well be locally significant.
A major part of the current development effort is directed toward
electric power generation from high-temperature, liquid-dominated geothermal
systems. Less effort is directed toward development of direct heating
uses, even though those uses are more energy-efficient. With increasing
knowledge of the exploitable potential, the emphasis may shift.
Only one commercially operating geothermal power field exists in the
United States, the 11-unit 502 MWe station at The Geysers, California. It
is probably atypical of future plants because it utilizes dry steam, a
relatively rare type of resource. The steam is nearly pure, but hydrogen
sulfide emissions have caused much local concern with the odor problem and
resulted in delays to plant expansions. At the other end of the spectrum,
much effort is being directed to development of California's large Imperial
Valley geothermal resources which are characterized by high salinity liquids,
with the highest thus far encountered in the Niland field. The great bulk
of the exploitable geothermal resources probably lies somewhere between The
Geysers and the Imperial Valley resources in pollution potential.
In favor of the continued expansion at The Geysers and the intense
development in the Imperial Valley is the probability that successful
demonstration of control of their present and potential pollution problems
will contribute greatly to successful environmental control at all other
future sites.
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EPA REGULATORY APPROACH
The Federal EPA regulatory approach for the geothermal industry will
be directed toward the following goals by the time the geothermal industry
reaches a stage of significant commercialization.
Precommercialization Regulation
Prior to the establishment of formal regulations, during the geothermal
development phase, geothermal discharges will be controlled through the
issuance of permits, as prescribed by Federal law, on a case-by-case basis,
the conditions of which will be determined by existing ambient standards,
known or expected effects, state-of-the-art control technology, and environ-
mental impact review. Periodic guidance will be issued by EPA with respect
to these factors, beginning with this document.
Surface Water Protection
Technology-based Effluent Guidelines, including National Standards of
Performance, will be established under Sections 301, 304, 306 and 307 of
the Federal Water Pollution Control Act Amendments of 1972. Consideration
will be given, as required by the Act, to the elimination of all pollu-
tants, where technologically achievable.
Water Quality Standards, applicable to receiving waters, will be
revised, where necessary, under Section 303 of the Federal Water Pollution
Control Act Amendments of 1972. Revisions may include additional pollutants.
It is possible that some additions may result from pollutants having been
found in geothermal wastes in environmentally harmful concentrations.
Ground Water Protection
Current regulations under Part C of the Safe Drinking Water Act are
not applicable to subsurface disposal of spent geothermal fluid. If and
when applicable regulations are promulgated, they are likely to include
injection system design requirements and pre-operational approval of
designs. Regulations would probably prevent injection of spent fluid
contaminants to designated drinking water aquifers and would probably
require injection to or below the producing reservoir where economically
and technologically feasible. Where not feasible, injection would probably
be limited to saline, nonpotable ground waters; this may be the case in
geopressured resource areas.
Regulations will be established under the Resource Conservation and
Recovery Act that will be applicable to surface brine and/or sludge impound-
ments at geothermal facilities, primarily to prevent infiltration of
contaminants to ground waters. The regulations will also protect surface
waters from contamination by impoundment runoff. The regulations will
include system design requirements and pre-operational design approval.
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Air Quality Protection
New Source Performance Standards (NSPS) will be established under
Section 111 of the Clean Air Act and Section 109 of the Clean Air Act Amend-
ments of 1977, for emissions from geothermal energy conversion facilities.
Emissions of specific gases, such as hydrogen sulfide, will be NSPS-regulated.
NSPS regulations are technology-based; thus the approach will include
support for technology development to minimize environmental effects.
Although the option is available, it does not presently appear likely
that any of the gases emitted from geothermal facilities will be regulated
by the effects-based ambient air quality criteria and ambient standards
under Sections 108 and 109 of the Clean Air Act and Section 106 of the
Clean Air Act Amendments of 1977, or by the hazardous air pollutant provi-
sions of Section 112 of the Clean Air Act and Section 110 of the Amendments
of 1977.
Section 122 of the Clean Air Act Amendment of 1977 provides for the
regulation of emissions of radioactive substances, cadmium and arsenic, all
of which may be found in geothermal fluids. Emissions of these substances
from geothermal facilities are likely to be regulated if they are found to
be in environmentally significant quantities.
Noise Protection
Noise will be regulated by EPA under the Noise Control Act of 1972 if
a product used in geothermal energy development is identified as a major
source. Other sources of noise will be regulated by state and local agencies
with EPA providing guidance as necessary. EPA will exercise its authority,
where necessary, to ensure that federal geothermal facilities meet all
appropriate federal, state and local noise regulations, including standards
imposed by the Occupational Safety and Health Administration (OSHA).
Radiation Protection
Radioactivity in geothermal fluid discharges and emissions will be
regulated, where necessary, like chemical pollutants, by inclusion in
guidelines and standards under the provisions of the Federal Water Pollution
Control Act, the Clean Air Act1, and the Safe Drinking Act, as described
above.
GEOTHERMAL POLLUTANTS AND SOURCES
The principal geothermal pollutants, all of which originate in the
geothermal reservoir, are dissolved chemical constituents, "non-condensible"
gases, and heat. None of the components, except heat and its water medium,
is necessary to the operation of an energy conversion system. All will be
discarded unless mineral recovery is practiced.
Spent geothermal waters will range from low (<1000 ppm) to very high
(>250,000 ppm) salinity and may include many inorganic constituents, such
as metals, in hazardous concentrations. Spent water from most areas is
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expected to be comparable to or lower than sea water in salinity. Generally,
the most contaminated waste water will be discharged from electric power
generation facilities operating from high temperature, saline, liquid-
dominated reservoirs. Discharge volumes may range up ,to 70,000 liters/
megawatt-hour at temperatures of about 50°C (120°F). In-plant sources of
waste water at power generation facilities will be steam-water separators,
residual from flashing water to steam, cooling water and condensate.
Unplanned releases of large volumes of geothermal fluid are possible during
system failures in the plant or in the production well and distribution
network.
The least contaminated waste waters are expected to be from non-
electric applications using lower temperature and less saline geothermal
waters. Discharges can be expected of the total fluid at the end of the
heating system with temperatures of 30°C (85°F) or less. Volumes will
likely be relatively low and the waters may in some cases be further used
as water supplies.
"Non-condensible" gases, those which do not condense at system operating
temperatures, are also expected to be of greater pollution significance in
power generation, with hydrogen sulfide continuing to head the list because
of its offensive odor at low concentrations. Others may come to the fore,
such as ammonia, radon, and mercury. The non-condensible gases will emanate
principally through condenser gas ejection, cooling tower exhaust, power
plant bypassing during plant shutdown, and well venting. Hydrogen sulfide
is currently a problem at The Geysers station, and is likely to be also at
plants operating on steam flashed from hot geothermal water.
Most non-electric uses of geothermal energy are likely to result in
more intimate contact with the user. It is conjectured that this aspect
may prevent a particular non-electric use of geothermal fluids having
significant gas content. In cases where steam may be flashed from the
water, such as in large process heating uses, the problems would be similar
to those from power generation.
Solid wastes, sludges, and/or concentrated brines, may result from
treatment to remove certain geothermal fluid constituents. Spent drilling
muds and well cuttings also constitute solid wastes, as do removed soil and
wasted construction materials; drilling muds may contain hazardous chemicals.
Disturbances of the land surface, necessary in the development of a
geothermal field, can result in the destruction of wildlife habitat.
Sediment runoff from such disturbances can disrupt or destroy fish habitats
in nearby streams.
Noise can be severe, requiring ear protection of nearby workers, from
air drilling operations and venting of steam and water from wellheads and.
distribution systems. Although there are other noise sources, drilling and
venting are over-riding.
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ENVIRONMENTAL CONCERNS FROM GEOTHERMAL POLLUTANTS
Water Pollutants
Water Quality Standards of the fifteen states with known geothermal
potential are not uniform. While six of the states include many of the
chemical pollutants that have been found in geothermal waters, none of the
states include all of them, and six states include none of the specific
chemical constituents.
The environmental effects of many of the constituents characteristic
of geothermal waters have been determined through past research by EPA and
others. This work has formed the basis for Water Quality Standards and
suggested water quality criteria. Most of the effects work has emphasized
the acute and chronic toxicity of various chemical elements and compounds
on aquatic organisms, including fish. Health effects on humans by consump-
tion, through water supplies, have been principally inferred from that
work, but with some reliance upon studies of the results of unintentional
or accidental human ingestion. The paucity of standards for agriculture
indicates little emphasis in that area.
Geothermal waters are not normally sources of organic constituents.
The pollutants of greatest concern are heavy metals. While most geothermal
waters may contain few if any in significant concentrations, all will
contain measurable amounts of several metals. Some geothermal waters,
particularly those with high salinity, contain a few or many metals in
concentrations hazardous to humans, animals, and/or plant life.
Generally, the hazards of metals to all. life forms include chronic and
acute toxicity, interference with reproductive capacity, and interference
with growth rates. Several constituents that have been found in geothermal
fluids may be suspected of having similar effects but have been omitted in
standards and criteria development for one or more uses.
High dissolved solids (salinity) content makes water unacceptable for
human consumption. Regardless of the precise chemical composition, high
and/or prolonged salinity can be toxic to terrestrial plants and aquatic
life not acclimated to it, by interference with normal osmotic conditions.
(
Waste heat in spent geothermal waters, if allowed to enter surface
waters, is potentially dangerous to aquatic life, e.g. excessive temperature
can halt fish reproduction. Sensitivity of most desirable aquatic life
species to temperature change is amplified by the fact that the optimum
growth temperature is usually only a few degrees less than temperatures
destructive to physiological well-being.
Air Pollutants
Most of the non-condensible gases or vapors that have been found in
geothermal fluids are innocuous and are normal components of the atmosphere.
Some, however, are not normally significant atmospheric components. Of
these, hydrogen sulfide is currently of most concern.
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Unlike water pollutants, where effects investigations emphasize aquatic
life, air pollutant studies have emphasized effects of inhalation on humans,
as have resulting standards.
Hydrogen sulfide is unique among geothermal air pollutants in that its
control has been principally forced by its odor rather than health effects.
Although it can have local health effects in the quantities emitted from
geothermal facilities, the difference between offensive odor concentrations
and toxic concentrations to humans is several orders of magnitude.
Increasing hydrogen sulfide concentrations result in varying responses.
At less than 0.1 ppm it has a very offensive odor but otherwise appears to
be innocuous to humans. At about 1 ppm it can cause nausea and headaches.
At 100 ppm to 200 ppm it can cause a loss of the sense of smell, and near
700 ppm death may result quickly due to respiratory paralysis.
Obviously the health effects of hydrogen sulfide are potentially much
greater in the facility occupational environment than in off-site areas.
Occupational Safety and Health Administration regulations list an acceptable,
continuous ceiling concentration, in the workplace of 20 ppm, and lower
concentration limits are being considered.
Regulation of other air emissions from geothermal facilities may be
supportable in the future as more data are accumulated. Those most likely
to be considered, on the basis of their known presence and possible effects,
are ammonia, mercury, arsenic, and radon.
Boron, in the form of boric acid, although principally a concern in
water discharges, may be emitted in cooling tower drift and cause harm
selectively to leaf growth of local vegetation. Citrus crops are parti-
cularly sensitive to boron.
Noise
The effects of noise are functions of intensity and exposure time. In
the immediate vicinity of geothermal operations both can be large. The
effects of noise can be physiological or psychological, or both. They can
range from simple annoyance in an otherwise quiet setting, to stress reactions,
to hearing loss under high intensity conditions. All could occur as a
result of noise from geothermal activities, with annoyance the probable
major problem outside the facility's boundaries. The United States Geolo-
gical Survey has imposed noise restrictions upon geothermal operations on
federal lands. They specify a maximum level of 65 dBA at the lease boundary
or a distance of one-half mile from the source, whichever is greater.
Land-Disposed Wastes
The principal effects of pollution from land-disposed geothermal
fluid-derived solid or brine wastes would be similar to those summarized
above under Water Pollutants, since contamination would result from leachate
runoff and/or percolation to groundwater.
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Radiation
Radionuclides are known carcinogens and no level is accepted as being
non-damaging. The effects upon man are of greatest concern, and may occur
as a result of inhalation or food ingestion. No effects have been shown as
attributable to radionuclides released by geothermal operations; radon gas
specifically may be a potential hazard in some areas.
POLLUTION CONTROL TECHNOLOGY
Very few pollution control technologies applicable to geothermal
energy conversion systems have been demonstrated. Most of the control
technology development and operation of control facilities has been done at
The Geysers geothermal power generation station owned by the Pacific Gas
and Electric Company.
Several pollution control technologies used in other industries appear
to be applicable to the geothermal industry, if they are sufficiently
economical. However, at present, it appears that many of them will not be
economically achievable in situations where they might be technically
feasible. It does not appear at this time that any new control technology
concepts will be devised for the geothermal industry. Instead already
known concepts and their technologies will be adopted.
Air Pollution Control
Two technologies for application to spent geothermal fluid have been
demonstrated at The Geysers power station. Each removes 90% or more of the
hydrogen sulfide reaching the treatment system. One is a regenerable iron
catalyst system applied to the cooling tower exhaust, to which condenser
ejector gases are also directed. This system, which can be used with
direct contact condensers, produces large quantities of sulfur-rich,
but unusable, sludge that must be land-filled. The second technology,
called the Stretford process, is applied to the condenser ejector gases
only, and requires the use of surface condensers. This process also uses
regenerable catalysts, but produces high quality sulfur that may be saleable.
Two "pre-treatment" processes are currently being tested at The Geysers
to remove hydrogen sulfide from the steam before it reaches the turbine.
Both may be successful. One, developed by EIC Corporation, uses regenerable
copper sulfate, and the other, developed by Deuterium Corporation, is
proprietary. Pre-treatment would be desirable in preventing downstream
corrosion and scaling of power plant equipment. Pre-treatment would also
provide treatment when steam must by-pass the plant during shutdown periods
and would eliminate the possibility of leaks from the power generation
process escaping treatment.
Escape of gases during well and pipeline venting is not now controlled
other than by minimization of flow. Collection and treatment schemes need
to be developed for these losses.
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Hydrogen sulfide removal from flashed steam derived from liquid-
dominated resources should not present unique problems. Technologies
employed at The Geysers should be directly applicable. Those using regener-
able catalysts appear to be the most economically feasible. Dow Chemical
USA has shown the technical feasibility of treating geothermal water prior
to flashing by an oxygenation process.
Treatment technologies have not been applied or developed for other
possible air pollutants from geothermal facilities. Additional air pollu-
tants may have to be considered if they are shown to cause significant
environmental problems. Such technologies may include exclusion areas to
allow for dispersion.
The table below summarizes preliminary capital and operating cost
estimates for existing and experimental geothermal t^S control technologies.
SUMMARY OF ESTIMATED ANNUAL AIR
POLLUTION TREATMENT TECHNOLOGY COSTS
mil/kwhmil/kwh
Process @ 10 MWe @ 100 MWe
Stretford 1.9 0.45
Iron Catalyst 1.2 0.4
EIC Process 4 2
Dow Oxygenation 10 8
(in-line system)
Dow Oxygenation 9 7.5
(packed column)
Water Pollution Control
The two principal types of waste water from geothermal operations,
spent geothermal liquid and cooling water, will in most cases require
treatment if they are to be discharged to surface waters. Some low-salinity
waters used in non-electric applications may be clean enough to discharge
to fresh surface waters without treatment, except perhaps for cooling.
Surface pollution treatment technologies, except for cooling, will be
principally aimed at removal and disposal of dissolved solids and their
toxic components. None has yet been demonstrated for geothermal applications
on a large scale. However, several technologies are available, including
evaporation, membrane filtration, and ion exchange. All are costly for
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large-scale application and would probably not be economically feasible for
geothermal operations unless they result in a saleable byproduct.
The following table summarizes preliminary capital and operational
cost estimates for potentially applicable wastewater treatment technologies.
SUMMARY OF ESTIMATED WASTEWATER TREATMENT TECHNOLOGY COSTS
Process
Sedimentation
1-stage lime addition
2-stage lime addition
Alum addition
Ferric chloride addition
Filtration
Ion exchange
Reverse Osmosis
Electrodialysis
Vapor compression evaporation
Multieffect evaporation
Multistage evaporation
$/1000 liters
@ 10 1pm
2.50
4.50
6.00
4.50
6.00
1.10
.30
.30
.60
.90
.90
$71000 liters
@ 100,000 1pm
.01
.02
.01
.06
.07
.06
.09
.12
.30
.20
.50
.50
Wastewater disposal, other than directly to surface waters, may require
less treatment and includes several alternatives such as subsurface injection,
ocean disposal, evaporation ponds, and land spreading.
Injection to the geothermal reservoir with no surface water discharge
appears, in most cases, to be the most practicable and environmentally
acceptable disposal method for spent geothermal brines, cooling water
blowdown, and excess condensates. Injection not only would solve the water
disposal problem, but might minimize reservoir depletion and potential
surface subsidence. Injection of relatively clean excess condensate has
been practiced successfully for several years at The Geysers. Injection of
brines is being tested more or less successfully at several experimental
sites in the Imperial Valley. System corrosion, scaling, and formation
plugging are potential problems, although apparently not insurmountable.
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with higher salinity fluids. Impervious ponds can be provided to contain
unplanned surface losses which might occur with system rupture.
Ocean disposal may be acceptable in some cases where access is available,
and the brine will not significantly contaminate sea water and coastal zones.
However, costs may be prohibitive, particularly where significant transport
distances and/or prior treatment are required.
Evaporation ponds can be very effective, but also very costly, for large
volume disposal because of the land area required. Land spreading may be
inexpensive, but will be limited because of the probability of salt accumula-
tion in soils.
The following table summarizes estimated costs of wastewater disposal by
various methods.
SUMMARY OF ESTIMATED COSTS OF WASTEWATER DISPOSAL
$71000 i ?/ioo(n
Method @ 1000 1pm @ 100,000 1pm
Injection .10 - .15 .02 - .10
Ocean Disposal .52 .33
(200 mi. from plant)
Evaporation Ponds .25 .13
Land Spreading .02 .02
Cooling towers or ponds can be used for excess heat removal from cooling
waters. Closed cycle operation of such facilities may in fact be demanded in
water-short areas, where cooling water must be recycled.
Land-Disposed Waste Control
Land-disposed wastes and surface brine impoundments must be totally and
permanently isolated from ground waters, if hazardous materials are included.
Site selection and landfill methods and impervious liners should be generally
available and adaptable to geothermal wastes. Off-site disposal at control
agency approved sites will often be necessary. It is estimated that disposal
at a site 200 miles distant would cost about $21/metric ton.
Noise Control
Noise can be controlled by a -variety of attenuating devices, all of which
appear amenable to further improvement. Mufflers for escaping air and steam,
the most intense noise sources, range from rock-filled barrels to large
expansion towers. Noise can also be attenuated by distance, barrier walls,
topography, and vegetation.
10
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II. RECOMMENDATIONS
The following recommendations should be considered as initial pollution
control guidance with respect to discharge and emission limits, pollutant
monitoring, and control technology and regulatory development needs.
SUGGESTED POLLUTANT LIMITATIONS
Air Emissions
Hydrogen sulfide is the only air pollutant for which limitations are
suggested at this time. Hydrogen sulfide emissions from initial demonstra-
tion facilities and existing commercial facilities should be limited to an
average of no more than 10% of the loading in the raw fluid. For most
electric power generation facilities it is expected that this will be
equivalent to an average between 0.2 and 0.4 kilograms per megawatt-hour
(MWH) of normal power generation (rated capacity X plant factor). Facili-
ties producing raw loads less than 0.2 kg/MWH probably will not require
treatment.
For non-electric uses where hydrogen sulfide may require control,
limits, comparable to those suggested for power generation, are suggested
to be within the range of 20 to 40 kg H2S per million kg of steam used. The
basis for such emission limitations is an economically achievable treatment
level, rather than environmental effects. However, with the present state
of knowledge, it is expected that the suggested emission levels will have
little if any measurable environmental effect. The basis for this expectation
is The Geysers experience in which the principal known problem caused by
unabated emissions is an odor nuisance; a 90% reduction in emissions should
essentially eliminate this problem.
Emissions of other gases afrd particulate materials from geothermal
operations may be anticipated, although the evidence of need is currently
inadequate to justify their control.
Water Discharges
Where geothermal spent liquids contain pollutants in excess of surface
receiving water standards for the area, a no discharge limitation is suggested,
unless the liquids are treated to meet those standards at the discharge
point. Further, it is suggested that injection to the geothermal reservoir
be practiced, and that it be regulated so that other usable ground water
aquifers are not changed in chemical or physical properties. In cases
where it is not economically feasible to return the spent fluid to the
producing reservoir, such as may be the case with geopressured resources,
11
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injection to other aquifers may be allowed if the injected fluid does not
degrade those aquifers for other existing or potential uses. It is recognized
that spent fluids will in most cases contain higher constituent concentra-
tions than the originally withdrawn fluid. A concentration increase,
caused by injected fluids, should be allowable in the geothermal reservoir
to the extent that it does not interfere with other legitimate uses of the
reservoir waters. In some cases this may require that the state (or EPA
where a state declines primacy) designation of certain geothermal reservoirs
for geothermal use only.
Land-Disposed Wastes
Suggested limitations for geothermal solid wastes containing hazardous
materials (including fluid constituents) are containment and isolation from
possible leaching to ground or surface water, or treatment of leachate to
remove hazardous materials and any materials that, if discharged, would
violate water quality standards.
Noise
Noise limitations should conform, as an initial minimum, to the regu-
lations issued by the U.S. Geological Survey for geothermal operations on
Federal lands; i.e. not to exceed 65 dBA at the lease boundary or one-half
mile from the source, whichever is greater.
MONITORING
All air emissions, water discharges, and noise should be monitored by
the operator on a periodic schedule for all pollutants having a potential
harmful effect. In addition, the operator should carry out ambient moni-
toring at appropriate points at the boundary with other public or private
property for the same pollutants, both before (baseline monitoring) and
during conversion facility operation, to assure that standards are not
violated and harm does not occur, especially where several facilities are
co-located.
CONTROL TECHNOLOGY AND REGULATORY DEVELOPMENT NEEDS
It is recommended that all agencies and private industries concerned
with geothermal research and development cooperate fully, including the
free exchange of information, in developing further the pollution control
and monitoring strategies and technologies described briefly herein.
Detailed technical and economic analyses should be cooperatively pursued
and documented.
It is recommended that increased attention be given to geothermal
fluid characterization, to the determination of pollutant effects on the
environment, and to the development of reliable injection technologies.
The solutions to many of the conversion technology problems should be
evaluated to determine which can simultaneously provide solutions to
environmental problems.
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III. INTRODUCTION
OBJECTIVES
The objective of this document is to provide pollution control guidance
to geothermal energy developers and regulators. Ranges of constituent
limits in air emissions and water discharges are suggested where possible.
The suggested limits may be viewed as serving three purposes: (1) to
provide assistance in developing discharge and emission permit conditions
for specific exploration, development, demonstration, and prototype facili-
ties; (2) to define goals developers can expect and plan for with some
confidence; and (3) to 'take the first step toward development of equitable
and enforceable standards for the geothermal energy conversion industry.
BACKGROUND
Standards Problem
Under the auspices of the U.S. Energy Research and Development Adminis-
tration (ERDA—now the Department of Energy), the Interagency Geothermal
Coordinating Council (IGCC) (formerly Geothermal Advisory Council) was
established to coordinate interagency activities relating to geothermal
energy development. The Institutional Barriers Panel of the Committee
defined several issues in a report dated June 30, 1976.-'- One of the issues
resulted in EPA producing this document. Essentially the report stated
that, in the absence of Federal standards, the States could set varying
standards that would complicate and add cost and uncertainty to geothermal
technology development. Immediate action was recommended to establish,
within one year, interim Federal guidelines for geothermal emissions.
Subsequent discussions resulted in a commitment by the Administrator
of EPA to produce a draft guidance document by July 1, 1977. This document
is the result of the EPA commitment. The Administrator decided that formal
regulatory guidelines could not be produced without the existence of an
established industry.
Although the IGCC inferred that air emission standards are of greatest
concern, this document considers all potential pollution areas—air, water,
solid wastes, radiation, and noise.
Perspective
The total potential geothermal energy resource is immense; however,
its availability for economical exploitation by existing technology is
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small compared to that total. Over most of the earth's surface, temperature
increases rather uniformly and modestly with depth, averaging about 25°C/km.
Exploitation with present technologies can occur only in naturally anomalous
situations that allow heat to move rapidly toward the surface and/or to be
trapped at shallow depths. Anomalous conditions occur typically in areas
of recent crustal disruption where folding, faulting, magmatic intrusions,
and volcanism provide avenues for higher outward heat transport. In the
United States such areas are generally found from the Rocky Mountains
westward. An exception is the geopressured area of the Gulf Coast, which
appears to be a large stable region of simple entrapment of normal outward
heat flow. Search for and characterization of geological anomalies leading
to commercially developable geothermal resources are basic first steps of
geothermal investigation.
Several factors presently limit the exploitability and potential uses
of a geothermal resource. These include temperature, the depth to the
resource, the content of water and its long-term availability, the form of
the water (liquid or vapor) and its pressure, and geographical location.
The most desirable characteristics with respect to these factors are rather
obvious, namely, hot, shallow, high-pressure steam in large volume near an
energy load center. The search for these desirable characteristics has
placed an emphasis on electric power production, although such energy
conversion is much more inefficient than direct heating applications.
Recognition of the inefficiencies may serve to change the emphasis, tempered
by the remoteness of much of the resource from populated areas.
Recent ERDA estimates project a geothermal contribution equivalent to
6,000 MW (megawatts) by 1985 and 39,000 MW by the year 2000, given a success-
ful federal implementation program. For comparison, current electrical
production in the United States is about 400,000 MW.
Most of the geothermal energy production, between now and the year
2000, will probably be from hot water resources. Vapor-dominated resources
are apparently rare, even though the major production at The Geysers in
California, the only present U.S. power generation application, is from
this type. Geopressured resources are not likely to make a major contri-
bution in the period cited by ERDA unless their natural gas content becomes
exploitable.
The total waste water flow resulting from ERDA-projected energy produc-
tion would be in the range of 4 X 109 to 8 X 109 liters/day (1,000-2,000 mgd)
in the year 2000. Flows would be of the same order of magnitude as the
once-through cooling water requirement for equivalent fossil-fualed electric
power generation.
The method chosen for disposal of spent geothermal liquids will not be
determined solely by pollution control reasons, particularly in power
generation. In general, power generation will entail a long-term commit-
ment at one site with sufficient high-temperature resources to maintain
consistent production for at least 30 years. It is likely that in most
places the rate of water withdrawal will significantly exceed natural
replenishment; resource conservation is therefore desirable. The most
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feasible way to accomplish this is by returning the spent liquid to the reser-
voir. It is also possible that subsidence will be induced by high-volume
withdrawal; injection may minimize this possibility. At the same time, in-
jection to the reservoir would also minimize the likelihood of pollution.
Both withdrawal and injection may affect seismicity by increasing or decreas-
ing the risk.
If the emphasis in geothermal development changes more toward direct
heating applications, the choice of disposal methods may also change. A
broader range of temperatures may be utilized. The lower temperature re-
sources, suitable for heating, may not require injection for reservoir main-
tenance; in many places natural recharge may be sufficient. In these cases,
injection might be considered solely as a disposal method to prevent pollution.
If the residual water does not require treatment for surface disposal, it may
serve as a water supply for other uses after heat extraction.
For purposes of establishing a perspective, it can be stated that power
generation is usually sought first because electricity can be transported
easier than heating fluids, from the generally remote geothermal areas, and
that, although vapor-dominated (steam) resources are the most desirable,
liquid-dominated (hot water) resources will prevail because of their greater
abundance. The hottest resources will be developed first if power generation
is the goal. Because of their usually higher salinities, high temperature
liquid resources can potentially cause greater pollution problems, but they
will probably be injected back to the reservoir. At the present time, major
development activity is proceeding in the Imperial Valley, California, which
apparently contains the highest salinity sources in the United States. Other
areas of lesser salinity are in various stages of exploration.
All geothermal sources appear to contain dissolved gases that may prove
to be, overall, the most troublesome pollutants. They must be removed in most
power generation operations because they interfere with steam condensing.
When removed, they must be disposed of, and some will require treatment.
Unlike water, they cannot normally be injected.
In terms of national impact, geothermal energy conversion does not pose a
major environmental threat. Local impacts could in some cases be severe;
however, there is every reason to believe that potential pollution will be
economically controllable in most, if not all, cases.
EPA GEOTHERMAL POLLUTION CONTROL REGULATORY APPROACH
The pollution control regulatory approach being adopted by EPA has been
selected from the options available under EPA-administered laws. The appro-
priate sections of those laws are summarized in the Appendix. Parts of
several other Federal laws, requiring or related to geothermal pollution
control, are also summarized in the Appendix. In addition, the Appendix
discusses briefly the interaction of State and Federal laws.
The regulatory approach selected by EPA is designed to relate to the DOE
development, demonstration, and commercialization schedule. ' The regulatory
objectives are to:
15
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(1) establish point source emission and discharge limitations for
environmentally damaging constituents by the onset (after 1981) of
significant commercialization;
(2) provide guidance, periodically updated up to the time of signifi-
cant independent commercialization (through the development and
demonstration phases), on limitations that can be anticipated prior
to facility construction, through the application of ambient stan-
dards and state-of-the-art control technology;
(3) minimize to the extent possible, by way of the same periodic
guidance, uncertainties in emission and discharge requirements;
(4) develop and evaluate information, which supports guidance and
regulations, throughout the precommercialization stage, in
concert with the industry and other involved governmental
agencies; and
(5) regulate geothermal pollution throughout the precommercialization
period by application of the emission and discharge permit systems,
which may be State-administered, with permit conditions based upon
ambient standards, known or expected effects, state-of-the-art
technology, and environmental impact review. Periodic guidance will
be issued by EPA with respect to these factors, beginning with this
document.
Air Pollution
The EPA will direct effort toward the establishment of New Source Perfor-
mance Standards under Section 111 of the Clean Air Act for those pollutants
that may have significant harmful effects. The most obvious one of those
pollutants at the moment is hydrogen sulfide. That constituent and others are
described more fully in Sections II and III of this document. Controlled
pollutants may include radioactive as well as the more ordinary chemical
constituents.
It should be emphasized, however, that New Source Performance Standards
would be technology-based, rather than effects-based. However the EPA
approach will include support for technology development to minimize environ-
mental effects. The States would still have the option of imposing more
restrictive limitations. EPA would retain the option to set Ambient Air
Quality Standards and Hazardous Air Pollutant Standards, should health and
environmental effects data later prove the need.
Water Pollution
EPA will develop information looking toward the development of Effluent
Guidelines and National Standards of Performance under Sections 304 and 306 of
the Federal Water Pollution Control Act for surface water discharges from
geothermal facilities. These guidelines and standards will eventually provide
firmly based effluent limitations and thus NPDES permit loadings. Consider-
ation will be given, as required by the Act, to the elimination of all
16
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pollutants, where technologically and economically achievable. The effluent
limitations will be available by the onset of full-scale commercialization of
most conversion technologies. This is estimated to be after 1981.
In the interim, the principal base for control will be receiving water
quality standards (40 CFR Part 120) now in existence, which are periodically
revised and upgraded. Revision may include additional constituents, some of
which may be unique to geothermal operations. Water quality standards are
established by the States in concert with EPA. Such standards include chem-
ical, physical, and radioactivity criteria to support designated uses and
frequently result in NPDES permit conditions more restrictive than those based
upon effluent guidelines. The 1983 goal of the Act is to provide water
quality that will support fishing and recreation in and on the water.
The EPA approach to subsurface disposal regulation is of particular
importance to geothermal development, since many, if not most, processes will
probably include injection of spent fluids. When geothermal injection regu-
lations are promulgated by EPA, they will likely require the prior approval of
detailed system plans and designs on a case-by-case basis. Also, drinking
water aquifers are likely to be defined or designated, and degradation of
those aquifers will not be allowed. Most States and the U.S. Geological
Survey (under the Geothermal Steam Act) already have regulations requiring
prior approval of injection system designs.
The EPA will also utilize "Administrator's Decision Statement No. 5,"
which established EPA policy with respect to injection wells. It requires
strict controls and their evaluation where injection is included in any activ-
ity in which EPA has any control. Also, surface water discharge (NPDES) per-
mits are required if waste water treatment, to facilitate injection, results
in surface discharges. On Federal lands, the U. S. Geological Survey may
apply these and its own existing requirements (GRO Order No. 4, Section 9C)
to geothermal reinjection.
Land-Disposed Wastes
Substantial regulatory authority by EPA for the control of land-disposed
wastes has just recently been provided by the Resource Conservation and
Recovery Act of 1976, for which regulations have yet to be established.
However, it is certain that any geothermal activity that uses surface impound-
ments to store, treat, or dispose of potentially hazardous waste, or that
produces solid wastes will be subject to guidelines and regulations, and
operating permits will be required by the States. Most States already have
applicable regulations. Wastes containing toxic, and/or radioactive constit-
uents will be particularly restricted, and detailed records of their history
through ultimate disposal will be required.
Noise
The EPA has the authority to ensure that Federal geothermal activities
meet all applicable Federal, State, and local noise regulations and do not
seriously impact the public health and welfare. EPA recognizes that noise is
a significant concern in geothermal development. EPA's support of U.S.
17
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Geological Survey noise regulations applied to geothermal developers on
Federal lands will depend on whether those regulations are adequately protec-
tive of the public health and welfare. Some States have similar regulations
for State-owned lands. EPA will recommend limits of environmental noise
required to protect health and welfare to the regulatory programs of other
agencies.
Radiation
The "Standards for Protection Against Radiation" (10 CFR 20) that form
the basis for EPA's guidance to the Nuclear Regulatory Commission do not apply
to geothermal energy. This is because 10 CFR 20 is limited to the component
materials and by-products of a nuclear fission reaction, under the Atomic
Energy Act of 1954. EPA does have authority to regulate radiation aspects of
geothermal energy under the Clean Air Act, Federal Water Pollution Control Act
and the Safe Drinking Water Act. The options for such actions are the same
for radiation as for chemical problems in air and water pollution.
EPA acts in an advisory capacity to other Federal agencies in writing
their own internal regulations regarding environmental radiation impacts. EPA
has utilized the numerical limits originally set by the Federal Radiation
Council for individual doses, but these are not considered particularly
restrictive, because radiation exposure can usually be made much lower without
significant economic penalties. In addition to the numerical bounds, EPA
provides qualitative guidance, to ensure that adequate controls are provided.
Because there is no known radiation level at which zero impact exists, quali-
tative guidance has been to require that radiation doses be kept as far as
practicable below the numerical limits. Practicability is judged by a cost/
benefit analysis that addresses the effectiveness of the control technique,
and includes the impact of the anticipated radiation level as a cost.
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IV. GEOTHERMAL POLLUTANTS AND PROCESS SOURCES
The overwhelming preponderance of pollutants from geothermal energy
conversion operations will derive from the geothermal fluid itself. Other
potential pollutants, such as added chemicals, and materials emitted during
exploration, development, and facility construction phases, are expected to
be comparatively minor or transient in nature.
Geothermal fluids and the contained energy are expected to be utilized
in many ways, including electric power production, space heating, industrial
process heating, agricultural drying, and even water supply. By far the
greatest volume of geothermal fluid is expected to be from liquid-dominated
resources used for electric power production. The raw and spent fluids in
power production from liquid-dominated resources are also likely to contain
higher quantities of chemical contaminants and heat.
Regardless of the end uses, the processes and activities preceding these
uses will have many similarities. Pollution sources can generally be sub-
divided into:
• Wellfield exploration, development, and construction activities.
• Fluid distribution and energy conversion system operations.
Each of these categories is discussed further in the following subsec-
tions.
WELLFIELD EXPLORATION, DEVELOPMENT, AND CONSTRUCTION ACTIVITIES
This category of sources can be further subdivided into the following:
• Access clearing and preparation
• Drilling
• Construction of fluid distribution and conversion facilities.
All of these sources are considered, with reasonable management, to be
transient pollution sources and of minimal consequence in the overall geo-
thermal development picture. Many of the pollutants may be significant for
short periods and may not be totally controllable, especially those classed
as fugitive emissions (released without control of flow or direction), such
as road dust. Most pollutants are generally considered more as nuisance-
creating than as hazardous contaminants. The drilling and construction
19
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activities and their associated surface disturbance have been well described
in a preliminary report' prepared by the U. S. Geological Survey.
Access clearing is a part of all geothermal development, from explora-
tion through plant construction. Soil and vegetation are disturbed or
destroyed and replaced by roadways and pipeline clearings. Pollutants are
dust and waterborne silt, vegetation debris, and machinery noise and exhaust.
Drilling site preparation includes the same pollutants.
The drilling process itself has the .potential for more serious environ-
mental contamination from the loss of drilling muds and possible well blow-
outs. Such releases are accidental, but are almost totally preventable with
present-day drilling practices.
Drilling muds may be comprised of various constituents such as bentonite,
barite, and perhaps chrome-lignite or chrome lignosulphonate, and sodium
hydroxide. Proprietary constituents may be included. Drilling mud disposal
is generally subject to strict State solid waste regulations. Well cuttings
may be subject to the same regulations.
Well blowouts can contain any or all constituents of the geothermal
fluid, described later in this chapter.
Equipment operation during drilling can cause very high noise levels,
particularly when compressed air is substituted for drilling mud, generally
during the later stages of drilling.
Construction of fluid distribution and energy conversion facilities is
similar to construction of most other industrial facilities, as are the
associated pollutants. The pollutants derive from debris, runoff erosion,
construction materials, and machinery operation. Soil dust, other airborne
particulates, waterborne suspended solids, and noise are the principal pollut-
ants. Most pollutants are generally considered to be in the non-point source
and fugitive emissions categories.
FLUID DISTRIBUTION AND ENERGY CONVERSION SYSTEM OPERATIONS
The principal pollutants, after the conversion facility is in operation,
will derive from the geothermal fluids as they pass through the facility.
Environment-contaminating discharges can potentially occur at the following
sites within distribution and conversion systems.
• Wellhead (initial and periodic full-flow venting).
• Fluid phase separation (liquid phase wasting).
• Pipeline vents (continuous small stream venting).
• Steam scrubbing (venting of particulates).
• Steam condensation (condensate discharge).
20
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• Condenser gas ejection (venting noncondensible gases).
• Cooling towers (condensate drift).
• Cooling water discharge, with or without recycle.
• Air and/or water waste treatment (sludge and treated water and
air discharges).
• Injection system (all or part of fluids returned to subsurface).
In some proposed systems, one or more of the listed sources will not
exist, while in others all can be significant. The proportion that each of
the sources contributes to the total discharges, and to the discharges to
each medium (air, surface water, land, and subsurface), depends upon many
factors. These factors include the type of conversion systems; the initial
fluid state (temperature, pressure, and composition), cooling water source;
cooling method; and whether waste water injection is practiced.
From an environmental standpoint the production of electrical power is
likely to be the most significant near-term use of geothermal energy. In
turn, the greatest pollution potential will likely be from moderate to high
salinity liquid resources, in which up to 70,000 liters/megawatt-hour would
be discarded as spent liquid. A facility in such a resource area might be as
schematically shown in Figure 1, with potential pollution release points as
depicted. This might be considered environmentally as a worst-case example
where all releases would be directly to the air and surface drainage. Both
ends of such a plant would have continuous discharges, from the wellhead
separator and from the condenser, the latter being cooled by an external
water supply. Condensate and cooling water discharges would constitute by
far the largest pollution source.
EXTERNAL COOLING
WATER
Figure 1.
AIR EMISSIONS
SURFACE WATER DISCHARGES
BOTH AIR AND WATER DISCHARGES
Simplified schematic diagram of open cycle geothermal electric
power generation system operating on flashed steam. All spent
fluids are discharged to surface water and air.
21
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Another facility might be as shown in Figure 2, which is at the other
extreme where the system is closed with potential releases contained and the
excess fluids returned to the producing reservoir. The only significant
waste loss would be heat to the atmosphere.
COOLING
TOWER
Figure 2. Simplified schematic diagram of closed loop geothermal electric
power generation system operating on flashed steam. All spent
fluids are injected.
For systems other than power production, such as space heating, opera-
tions may be much simpler in principle, to the extent of merely passing the
entire fluid flow through heat exchangers and discharging it to surface
drainage or reinjection. Such a system might be as shown schematically in
Figure 3.
HEAT EXCHANGERS E.G. RESIDENCES
WATER
DISCHARGE
Figure 3. Simplified schematic diagram of non-electric use (space heating)
of geothermal energy. Spent fluids either can be injected or
discharged to surface waters.
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There are many possible variations in and between these schemes. For
example, the scheme shown in Figure 3 could be used as part of a power
generation system, in which a recycled secondary fluid, heated in the heat
exchanger, operates a turbine-generator. The schemes of Figures 1 and 2 can
also be made more complex by multi-stage flashing, or simpler by passing the
entire well flow through a turbine.
The principal point is that any discharge to the air, to surface drain-
age, to surface impoundments, or to injection, will be subject to regulatory
control of some degree. Also, the restrictions on those discharges are
likely to be directly related to the number and concentrations of constituents
in the discharged fluids, and to the fluid volume. They will in turn be
directly related to the original character of the geothermal fluid.
If geothermal fluids must be treated for constituent removal, solid
wastes or more concentrated brines containing most of the fluid chemical
constituents will result. These wastes will also be subject to confinement
and other controls to prevent surface and ground water contamination. In
some cases, brine constituents may be extracted for commercial sale and use.
POLLUTANTS DERIVED FROM GEOTHERMAL FLUIDS
The chemical characteristics of geothermal fluids vary greatly between
reservoirs and to a lesser degree even within the same reservoir. The charac-
teristics can also change with time, because of selective withdrawal and
recharge factors.
Figure 4 lists some of the more significant chemical constituents of
geothermal fluids and graphically depicts their ranges. All of the constit-
uents are natural components of geothermal fluids. The information in
Figure 4 has been compiled from an examination of limited data from the
literature and unpublished sources.9,10,11 chemical data are now being
gathered rather extensively so that the listed ranges will likely expand.
Radioactive elements, except for radon gas, which is discussed later, have
not been regarded thus far as significant in geothermal fluids.
Figure 4 is biased considerably by data from the Salton Sea (Imperial
Valley), where very high constituent concentrations are common (see Ref. 9).
In order to add perspective, judgments have been made of ranges within which
the majority of concentration measurements will likely occur when all geo-
thermal fluids are considered together. Generally, spent water from most
areas is expected to be comparable to or lower than sea water in salinity.
In general, low salinity or low total dissolved solids (TDS) are asso-
ciated with relatively low concentrations of all constituents and vice versa.
As a general rule also, higher temperature waters contain higher constituent
concentrations.
Geothermal fluids range rather widely in hydrogen ion concentration,
with pH values generally between 2.0 and 8.5. It appears that most fluids
are above pH 7.0. Fluids of highest salinity generally have the lowest pH
and may be highly corrosive to man-made materials.
23
-------
10,000
100,000
TDS
CHLORIDE
SODIUM
CALCIUM
MAGNESIUM
POTASSIUM
ALUMINUM
IRON
BROMIDE
MANGANESE
STRONTIUM
BORON
ZINC
BARIUM
LITHIUM
CESIUM
FLUORIDE
LEAD
RUBIDIUM
IODINE
COPPER
SULFUR
ARSENIC
MERCURY
CHROMIUM
ANTIMONY
NICKEL
BISMUTH
TIN
SILVER
CADMIUM
BERYLLIUM
SELENIUM
SULFATE
SILICA
AMMONIUM
NITRATE
H2S
Figure 4. Ranges of chemical constituent concentrations in geothermal fluids - mg/1. Narrow
bars show measured ranges. Wide bars show ranges within which the majority of
measurements will probably fall. Where no wide bar is shown, data are insufficient
to make a judgment.(Ref. 9, 10, 11)
-------
Noncondensible gases, those which do not condense at operating tempera-
tures, are environmentally important constituents of geothermal fluids. They
may he free gases or dissolved or entrained in the liquid phase. Hydrogen
sulfide has been the component of greatest concern to this time. Nonconden-
sible gases usually comprise between about 0.3% and 5% of flashed steam from
geothermal fluids.-^
Figure 5 depicts the known ranges of noncondensible constituents as
percentages of total noncondensible gases.H Also shown are their probable
ranges in parts per million of total gases (including steam) in a steam
system. In gas ejector emissions the concentrations can of course be much
higher.
.001
CH4
CO 2
°1
H,S
H2
S02
Ar
NH3
CO
H3B03
He-
As
Hg
— _
INI
.01 PERCENT OF 0.1 NONCONDENSIBLE 1 GASES
io ' '160 ' ' 'iobo
PPM WHEN NONCONDENSIBLES EQUAL 57, OF TOTAL GASES
10 100
.
10,000
1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 I 1 1 | 1 1 ! 1 1 1 1 1 1 1 1 1 1 1
0.1 1 ' 10 100 1000
PPM WHEN NQNCONDENSIBIES EQUAL 0.3% OF TOTAL GASES
Figure 5. Noncondensible gases in geothermal fluids. Base graph shows
individual gases as ranges of percent of total noncondensible
gases. Lower scales convert these values to parts per million
(ppm) of total (noncondensible plus condensible) gases when
noncondensibles equal the specified percentages of total gases.
Radioactive elements are generally found in geothermal fluids in low
concentrations. These include uranium and thorium isotopes, radium, and
radon. Radon, a radioactive gas and one of the products of radium decay, is
the most significant generally recognized radioactive component in geothermal
fluids. A survey by EPA1^ of 136 geothermal manifestations showed a range of
13 to 14,000 pCi/1 (picocuries per liter), with a median of about 510 pCi/1.
Figure 6 depicts the frequency of occurrence of radon concentrations measured
during that survey. The concentrations show considerable variation geograph-
ically, with some regions having much higher concentrations than others.
Chemicals, such as acids, bases, and various flocculants and coagulants,
may be added to geothermal fluids to minimize scaling and corrosion or to
remove certain constituents. Although these chemicals may not in themselves
be of great pollution consequence, consideration must be given to them
(particularly metal compounds), because they may alter the geothermal liquid
25
-------
composition toward being more environmentally detrimental. Most such chemi-
cals will likely be acids and/or bases used for pH adjustment.
PERCENT
10 20 30 40 SO 60 70 80 90
3000 —
2000
1000
500
100
10
J I L
J I L
20 30 40 SO 60 70 80
PERCENT
90
Figure 6.
Cumulative frequency distribution for radon-222 in geothermal
waters. (Constructed from data in Ref. 13)
Waste heat can be of major significance in geothermal electric power
generation because of the relative inefficiencies of low-temperature conver-
sion. Conversion efficiencies are presently less than 20%-*-4>15, so that more
than 80% of the available heat is wasted by way of spent brine, condenser
cooling water, and condensate. If external once-through cooling water is
used, most of the waste heat from cooling will be discharged to surface
waters. If cooling towers are used, with the cooling water recycled, and
blowdown subsurface-injected, most of the waste heat will be dissipated to
the surrounding air. Surface water discharges would be particularly detri-
mental with large volumes released at temperatures as high as 50°C (120°F).
Chemicals and heat are likely to be much less troublesome contaminants '
in discharges from non-electric uses of geothermal fluids.16 One of the
principal reasons is that those uses will probably deal with lower temperature
waters that are inherently less saline. Another is that non-electric systems
probably will demand the use of relatively clean water because they will be
in more intimate contact with the ultimate energy user.
Solid wastes may be produced by particle separators, scale removal, and
as sludge from water treatment and gas scrubbing. Such wastes will include
26
-------
the pollutants of the geothermal fluid itself and any treatment chemicals
used. If mineral recovery is practiced, the residual will also be solid
wastes or bitterns. The constituents of geothermal solid wastes have the
potential for leachate runoff and infiltration to ground water if not properly
handled.
NOISE DERIVED FROM GEOTHERMAL OPERATIONS
In all industrial operations noise is a pollutant that must be accepted
to some degree. In geothermal operations noise may be particularly annoying,
in part because the areas of operation will be generally remote and otherwise
relatively quiet. The most significant potential sources are drilling
(particularly with air) and steam flashing and venting.
Table 1 lists examples of noise measurements at The Geysers power
generating facility.U Noise levels from liquid-dominated sources will
likely be similar. In general, noise level decreases from 3 to 6 dBA with
every doubling of distance.1" The expression dBA means "A-weighted" sound
level measured in decibels above a reference sound pressure of 0.0002 micro-
bars (20 micropascals). "A-weighting" weights the contributions of sounds of
different frequency so that the response of the human ear is simulated.
The sound levels listed in Table 1 can be compared to more well-known
sources, some of which are:18, 19
• quiet wilderness area 20 - 30 dBA
• quiet suburban residence 48 - 52 dBA
• business office 50 - 60 dBA
• noisy urban area 80 - 90 dBA
• adjacent to freeway 90 dBA
• jet airplane at 100 feet 120 - 130 dBA
As the data in Table 1 indicate, the most intense noise levels in geo-
thermal operations result from steam venting. Mufflers of various designs
are in common use, as described in Section VI - Pollution Control Technology.
27
-------
TABLE 1. SOUND LEVELS FROM VARIOUS NOISE SOURCES AT THE
GEYSERS, dBA, re 0.0002 MBAR OR MICROBAR
(Ref. 17)
Source
No.
Noise Source
Sound
Level
dB(A)
Distance
m ft
Comment
2
3
4
5
7
8
10
11
12
13
14
15
Drilling with 114
air
Same as No. 1
Drilling with
air
Same as No. 3
Same as No. 3
Steam well
Same as No. 6 73/75
Steam well
Steam well
Steam well
Steam well
Steam line
Same as No. 13
Testing well
(big well)
Same as No. 14
84
105/110
71/83
92/94
70/75
107
8 25 Steam entry of ^81,720 kg
(180,000 lb)/hr.
No muffler.
Same as No. 1
Steam entry of ^90,800 kg
(200,000 lb)/hr.
With muffler.
Same as No. 3
Same as No. 3
Main valve closed, bleed
line exhausting freely.
Same as No. 6
Main valve closed, bleed
equipped with silencer,
exhausting freely.
27 90 Muffled steam well ex-
hausting through silencer,
exhausting freely.
137 450 Main valve open, unsilenced.
Steam plume about 46 m
(50 yd) high. -
914 3000 Main valve open, unsilenced.
Steam plume about 46 m
(50 yd) high
^74
84
•^65
<50
89/92
73/75
59/62
805
8
76
805
14
55
14
2640
25
250
2640
45
180
45
12
91
8
805
28
40 Directly in front,
300 15/25 degrees off axis.
25 @122,580 kg (270,000 lb)/hr.
With muffler.
2640 Same as No. 14
-------
TABLE 1 (continued)
Source
No.
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
Noise Source
Free venting
well
Same as No. 16
0.6 cm (.25 in.)
bleed on shut-in
well
Same as No. 18
Same as No . 18
Steam line vents
from main line
mufflers of 2
units
Power plant
Same as No. 22
Steam jet gas
ejector
Steam jet gas
ejector
Same as No. 25
Cooling tower
for 2 units
Cooling tower
for 2 units
Same as No. 28
Same as No. 28
Sound
Level
dBA
120
^79
84
^65
<50
64
96
^61
91
88
86
i
81
84
80
72
Outside turbine 72
generator building
Distance
m ft
8
805
8
76
805
244
15
805
1.5
3
6
3
3
12
43
8
25
2640
25
250
2640
800
50
2640
5
10
20
10
10
40
140
25
Comment
@^90,800 kg (200,0001b)/hr
No muffler.
Same as No . 16
No muffler.
Same as No . 18
Same as No . 18
15/25 degrees off axis
454,000 kg (1 million lb)/
hr.
Same as No. 22
Microphone height 1.5 m
(5 ft). Unit load unknown.
Microphone height 1.5 m
(5 ft) . Unit load 41 MW.
Same as No. 25
Microphone height 1.5 m
(5 ft).
Microphone height 1.5 m
(5 ft).
Same as No. 28
Same as No. 28
One unit - 44 MW; second
unit - 54 MW
29
-------
V. ENVIRONMENTAL EFFECTS OF KNOWN POLLUTANTS
GENERAL
Under current laws, discharge permit limitations based upon guidelines
and performance standards are the principal and preferred regulatory methods,
unless such limitations still allow receiving media standards to be violated.
In such cases, the permit limitations will be derived from effects-based
media standards. They also may prevail where effluent guidelines and emis-
sion standards have yet to be developed; such is the case with the geothermal
industry. The current receiving media standards most applicable to the
geothermal industry are those for water quality. Table 2 lists the geother-
mal constituents and those regulated by existing water quality standards for
those States with significant geothermal potential.
As indicated by Table 2, geothermal fluids may contain constituents not
currently controlled by media standards. Since geothermal industry Effluent
Guidelines and New Source Performance Standards have not been developed, and
toxic substance limitations have not been established, it is appropriate to
discuss the environmental effects of geothermal fluid constituents as the
first consideration in the establishment of an appropriate control basis.
Environmental effects are discussed herein only in very general terms.
No attempt is made to detail the literature that may be available on toxicity,
for example. It is recognized that much greater detail for mixtures unique
to geothermal fluids may be justified as geothermal development progresses.
It is also recognized that such detail will require complex analyses, both
theoretical and empirical. Although a considerable number of elemental
chemical analyses are available, the effects of mixtures of these elements
are largely unknown. Often, it is the mixture of compounds that determines
the level of environmental effects. The effects may by synergistic, antago-
nistic, or independent.
WATER POLLUTANTS
The following discussion of environmental effects is divided into areas
of water use, as has been characteristic of water quality standards develop-
ment. The potential water pollutants and their probable concentration ranges
in geothermal waste fluids were shown in Figure 4. Some geothermal reservoirs
may produce waters of sufficient quality for many uses, including human
consumption; however, this is not expected to be generally true.
30
-------
TABLK 2. POLLUTANTS LIMITED V,Y HAITK QUALITY ST.'MJ
IX STATES WITH CB>T!ll-:p:iAL rOTr;,TTAL
Total dissolved solids
Chloride
Sod inn!
Calcium
Magnesium
Potassium
Aluminum
Iron
Bromide
Manganese
Strontium
Boron
Zinc
Barium
Lithium
Cesium
Fluoride
Lead
Rubidium
Iodine
Copper
Sulfur
Arsenic
Mercury
Chromium
Antimony
Nickel
Bismuth
Tin
Silver
Cadmium
Berylium
Selenium
SulEate
Silica
Ammonium
Nitrate (+ nitrite)
PlI (range)
Radioactivity
Total dissolved gas
Toxic materials
Temperature
Dissolved oxygen (min.)
Phosphorus
Conductivity
Alaska |
d
s
d
d
d
s
•\rizona 1
d
d
d
d
d
d
d
d
d~1
d
d
d
s
f
d
d
California |l
II
s
s
s
s
s
s
s
s
d
d
d
d
Colorado ||
l!
s
s
f
d
a
• H
•H
fl]
d
S
S
f
d
s
Idaho j]
H
s
s
s
s
d
s
Louisiana |
1
d
d
d
s
s
s
Montana 1
d
d
d
d
d
d
d
s
d
s
s
d
d
n
TJ
>
OJ
•z.
\ d
s
d
s
s
f
d
s
d
O
CJ
'A
'ff'.
i "j
'/•"
t*
d
d
S
s
s
s
d
s
d
d
c
o
CO
SJ
u
o
~cf-
d
1 cl
d
d
d
d
d
d
d
d
d
d
s
s
s
d
s
d
Ti
fj
~S,
'j
d
d
s
s
s
s
s
s
s
s
s
s
s
d
s
s
s
d
s
;J
^_t
: 0
—
_p
p
p
p
p
p
p
p
p
p
p
p
p
p
s
S
d
s
"j
ij
[
s
s
s
s
d
s
Wyomim; ||
II
S
d
f
d
S i
^
d = criteria for designated waters; s - criteria applied statewide;
p = criteria conform with USPHS Drinking Water Standards, 1976;
f = free from toxic materials.
31
-------
Human Use
Of greatest concern is the protection of public drinking water supplies.
Spent geothermal liquids, in the massive amounts expected to be discharged,
could have very serious effects if allowed to enter drinking water sources.
The effects of injection to ground water supplies could be disastrous, because
such contamination might well be impossible to correct.
Table 3 provides some general toxicological information on compounds
(mainly inorganic) containing each of the significant geothermal fluid con-
stituents. The toxicological information is related to direct undiluted oral
ingestion.20,21 fjo attempt is made to give toxic amounts because they are
highly variable, depending frequently upon associated ions, the health of the
individual, and the time over which the ingestion takes place.
Table 3 also includes the permissible or recommended maximum concen-
o o o o
trations of constituents in public water supplies. ^>^J Comparison of this
list with toxicity levels indicates those constituents in geothermal fluids
that may have pollutional significance, but are not mentioned in drinking
water regulations. These are bromide, lithium, iodide, antimony, and bismuth.
Although no drinking water standards have been established for these constit-
uents, it would be fair to assume that, if such are developed, they will be
something less than 1 mg/1 for each. Sulfides, nickel, and potassium from
geothermal fluids may have potential health effects, but no limits can be
suggested.
Each of the constituents in Table 3, for which an acute and/or chronic
toxicity level of 1 or higher is shown, should be viewed as subject to
discharge control in geothermal operations. Control methods and their
effectiveness are discussed in the next chapter.
Aquatic Life
rt /
The EPA has recently published (1977) "Quality Criteria for Water," in
which many of the constituents found in geothermal fluids are not considered.
Table 4 has been prepared largely from the information contained in that
document, supplemented by others,2^,26 in which much of the emphasis is on
the protection of aquatic life from acute and chronic toxicity. Data in
Table 3 on humans give cause to suspect that the same constituents may
have effects upon aquatic life. Comparison of Table 4 with Table 3 shows then
that there are many geothermal fluid constituents that may have significant
effects upon aquatic life, but have not yet been included in criteria develop-
ment. These constituents include:
• Aluminum • Fluorine
• Bromine • Rubidium
• Strontium • Antimony
• Lithium • Nickel
• Cesium • Bismuth
32
-------
TABLE 3. EFFECTS ON HUMANS OF ORAL INGESTION OF COMPOUNDS
TDS
CI
Na
CA
MS
K
Al
Fe
Br
Mn
Sr
B
Zn
Ba
Li
Cs
F
Pb
Rb
I
Cu
S
As
Hg
Cr
Sb
Ni
Bi
Sn
Ag
Cd
Be
Se
SOi
SiO?
NHi
N03
Acute
Toxicity of
Compounds
0
0
0
0
1
0-2
0
0
2
0
0
2
1
2
2
0
3
3
0
2
2
0-2
3
3
3
3
1
2
0
0
3
0
2
0
0
0-1
2
Chronic
Toxicity of
Compounds
0
0
0
0
0
0
0
0
0
0
0
2
0
1
1
0
3
3
0
2
1
0-2
3
3
3
3
0
1
0
0
3
0
2
0
0
0-1
2
0) O
> 4J rH
•rl (fl 0)
10 -H (U
.Sf S Systemic Effects *g
° ^ Vascular Nervous OT
X
X
X X
XXX
X
X X
X
X XX
X
X XX
X X
X
X X
X
X X
X X
X XX
X XX
X
X
1
X
X
X
X
X X
Muscular
X
X
X
X
Drinking
Water
Standard
(mg/1)
500
250
0.3
0.05
1.0
5.0
1.0**
1.4-2.4
0.05**
1.0
0.05**
0.002**
0.05**
0.05**
0.01**
0.01**
250
0.5 as N
10 as N**
Toxicity Ratings: 0 - usually not harmful or harmful only with overwhelming
dosage; 1 - causes reversible changes which usually disappear after end of
exposure; 2 - causes reversible or irreversible changes not severe enough to
cause death; 3 - may cause permanent injury or death after ingestion of small
quantities.
* Sodium intake must be limited for some cardiac patients, with a generally
accepted limit of 20 mg/1 in drinking water.
** Standards established by 40 CFR 142; all others are DSPHS-recommended (1962)22
33
-------
TABLE 4. AQUATIC LIFE CRITERIA FOR CONSTITUENTS IN GEOTHERMAL
FLUID - FROM "QUALITY CRITERIA FOR WATER" (1977)24
Constituent
Ammonia
(un-ionized)
Arsenic
Barium
Beryllium
Boron
Cadmium
Chromium
Copper
Iron
Lead
Manganese
Mercury
Nitrates
Phosphorus
Selenium
Silver
H2S
Zinc
Total Dissolved
Solids (TDS)
Criteria for
Fresh water
0.02 mg/1
0.11 mg/1 - soft water
1.1 mg/1 - hard water
.004-. 0004 mg/1 - soft water
.012-. 0012 mg/1 - hard water
0.1 mg/1
0.1 96 hr LCsn
1.0 ms/1
0.01 96 hr LCso (sol. lead)
0.0005 mg/1
0.01 96 hr LC-so
0.01 96 hr LC5Q
0.0002 mg/1
0.01 96 hr LCso
Criteria for
Marine water
0.005 mg/1
0.1 96 hr LCso
0.1 mg/1
0.0001 mg/1
0.0001 mg/1 P
0.01 96 hr LC5Q
0.01 96 hr LCso
0.0002 mg/1
Remarks
Toxicity pH dependent
Daphnia impaired by 4.3 mg/1
Toxicity level >50 me/1
Toxicity hardness - dependent
Toxic to minnows at 19,000 mg/1
Toxic at <0.5 mg/1 all tests
Toxicity varies with pH and
oxidation state
Toxicity alkalinity - dependent
Toxicity variable
Salmonids most sensitive fish
Not a problem in fresh water
High bio-accumulation and thus
affects human food
Toxicity to fish >900 mg/1
Eutrophication factor
Toxic at >2.5 mg/1
Toxicity dependent on compound
Toxic at very low levels
Toxicity dependent on tempera-
ture, DO, hardness
Osmotic effects - variable
-------
One of the reasons that the above have not been included is that most
have not normally been considered significant components of waste waters or of
natural waters. This of course is not always true; for example, fluorides are
significant components of natural waters in several areas.
Caution should also be exercised in the use of the data in Table 4, where
no criteria are shown; e.g., arsenic, barium, and boron. These may exist in
geothermal waters in much higher concentrations than regulatory agencies have
had to deal with in other waters.
Criteria cannot be reasonably suggested here for those constituents that
have not been covered in criteria development documents. As noted previously,
such development requires complex analyses.
Waste heat may have particularly significant effects upon aquatic life.
Excess heat, as expressed by artificial temperature rise or temperature fluc-
tuations, can disturb aquatic communities to the extent of complete elimina-
tion and replacement by different species. An excellent summary of tempera-
ture-induced aquatic effects is presented in reference 24. Most water quality
standards limit artificially induced stream temperature rise outside a mixing
zone to 5°F (2.6°C) or less. Generally, the standards also include a maximum
stream temperature tailored to the preferred temperature of native fish
species.
The pH of surface waters has been related to productivity, with the most
productive waters between pH 6.5 and 8.5. Not only may acids and alkalis be
toxic in themselves, but pH increases or decreases may increase the toxicity
of various constituents, e.g. ammonia.
Agricultural Use
Two uses are commonly included in considering pollution effects and water
quality criteria for agriculture. These are livestock watering and irrigation.
Criteria developed in "Quality Criteria for Water"19 are listed in Table 5,
for those constituents that are found in geothermal waters. Again it must be
emphasized that those criteria do not discuss many of the geothermal constit-
uents that may be detrimental t^o agricultural use.
Criteria development for agricultural water uses has obviously not
received the attention that it has for aquatic life and drinking water. This
becomes obvious in a comparison of the numbers of criteria presented in
Tables 4 and 5. Here again, such development would involve complex evalua-
tions. Thus, additional criteria are not suggested herein.
Industrial Water Supply
As a general rule, industrial water supplies are adversely affected by
excessive total dissolved solids concentrations, although there is wide
variability in the quality of water used among various industries (see
Table 6).^5 Geothermal fluids from many reservoirs could potentially contrib-
ute very large quantities of dissolved solids, which could be removed from
industrial water supplies, but the cost in some cases would be prohibitive.
35
-------
TABLE 5. AGRICULTURAL USE CRITERIA FOR CONSTITUENTS IN GEOTHERMAL
FLUIDS FROM "QUALITY CRITERIA FOR WATER" (1977)24
Livestock Crop
Watering Irrigation
Ammonia
Arsenic 0.1 mg/1
Barium
Beryllium .001 to .500 mg/1
Boron 0.75 mg/1
Cadmium
Chromium
Copper
Iron
Lead
Manganese 0.2 mg/1 suggested
for acidiphilic
crops
Mercury
Nitrates
Phosphorus
Selenium
Silver
H2S
Zinc
Total Dis- 5,000-15,000
solved mg/1 suggested
Solid (TDS)
Sodium
Remarks
No criteria suggested.
Toxicity to some crops at 0.5 mg/1; no
livestock criteria suggested.
No criteria suggested.
Crop toxicity acidity dependent; no
livestock criteria suggested.
Toxic to sensitive plants, e.g. citrus
at <1 mg/1; no livestock criteria
suggested.
Reduced crop yields at 1 mg/1; crop
accumulation related to zinc concentra-
tions; no livestock criteria suggested .
No criteria suggested.
Toxicity for plants begins at 0.1 mg/1;
no livestock criteria suggested.
No criteria suggested.
Toxic to plants at <30 mg/1; no criteria
suggested.
Toxicity to plants increases with
decreasing pH; no livestock criteria
suesested.
Bio-accumulation but no criteria
suggested .
No criteria suggested; nutrient for
crops.
No criteria suggested; nutrient for
crops .
No criteria suggested.
No criteria suggested.
No criteria suggested.
Toxic to some crops at 0.4 to 25 mg/1
may cause iron deficiency in plants; no
livestock criteria suggested
Osmotic effects in plants; variable
harm to both plants and animals .
Toxic to certain plants; ratio to
other cations important; no criteria
given.
36
-------
Some Industrial processes (e.g. food and beverages) may require as high or
higher quality than drinking water, in order to maintain consistency of
product quality.
TABLE 6. TOTAL DISSOLVED SOLIDS CONCENTRATIONS OF SURFACE WATERS THAT
HAVE BEEN USED AS SOURCES FOR INDUSTRIAL WATER SUPPLIES25
Industry/Use Maximum Concentration
(mg/1)
Textile
Pulp and Paper
Chemical
Petroleum
Primary Metals
Copper Mining
Boiler Make-up
150
1,080
2,500
3,500
1,500
2,100
35,000
AIR POLLUTANTS
The potential air pollutants and their probable ranges in geothermal
steam and air emissions were shown in Figure 5. Only one of them, sulfur
dioxide, is now subjected to regulation from all stationary sources under the
Federal Clean Air Act. Mercury vapor emissions are regulated by the Hazardous
Air Pollutant section of the Clean Air Act only for mercury ore processing
facilities, mercury cell chlor-alkali plants, and sewage sludge incineration.
Hydrogen sulfide emissions are regulated by some states, but not by Federal
regulations. Some of the noncondensible gases in geothermal fluids are
ordinary, relatively innocuous components of the atmosphere and control is
unnecessary.
i
Effects on Humans
The greatest concern about any of the noncondensible gases is their
effect on human health.
Table 7 shows the general inhalation effects of each of the significant
gases contained in geothermal fluids.20 The listed toxicity effects are
derived from inhalation of high dosages in confined spaces. However, the
relative toxicities and the existence of significant concentrations in geo-
thermal air emissions may indicate which constituents are more likely to
require control.
Carbon dioxide, nitrogen, and helium are relatively harmless, but may
cause asphyxiation in massive doses. Hydrogen sulfide, sulfur dioxide,
37
-------
TABLE 7. EFFECTS ON HUMANS OF INHALATION OF GASES OR VAPORS20
CH4
C09
2
N2
°o
2
H2S
H2
S00
z
Ar
NH3
CO
H3B03
He
As
Hg
^»
±J
0) -H
•U O
3 -H
0 X
"" H
1
0
0
0
3
0
3
1
3
3
2
1
3
2
o >-,
•H 4J
C 'H
0 0
t-J -H
»c ?s
H Respiratory
1 x
0
0
0
3 x
0
2 x
0 x
U X
1 X
2 x
0 x
3 x
3 x
*
01
w
o s-^ /-N * c-
o e MS * B
fX O ft O ft
Systemic Effects ^ £ S >5 ^ ^
t>
Vascular Nervous Muscular f*
x
5000
>1000 >0.03 10
400-500 3 5
x 4000 -50
x
X X
Toxicity Ratings: 0 - usually not harmful or only harmful with overwhelming
doses.
1 - causes reversible changes which usually disappear after
end of exposure; simple asphyxiants.
2 - causes reversible or irreversible changes not severe
enough to cause death.
3 - may cause permanent injury or death after ingestion of
small quantities.
*Fatal dose concentrations in air which cause death with less than one hour
exposure.
**Maximum acceptable concentration - concentration in air which can be withstood
continuously without noticeable harm.
38
-------
ammonia, carbon monoxide, arsenic, and mercury may cause serious harm upon
inhalation of relatively small amounts.
Hydrogen sulfide appears to be universally present in geothermal fluids
in quantities sufficient to be of environmental concern. That concern is
increased by the odor nuisance resulting from very small concentrations of
hydrogen sulfide. Even though in sufficient concentrations it is very toxic,
the odor nuisance at low non-toxic levels creates public antagonism. Its
toxicity effects may be significant in the immediate vicinity of the emission.
The information on hydrogen sulfide in Table 8 is taken from a literature
review by the U. S. Public Health Service.27
TABLE 8. HYDROGEN SULFIDE EFFECTS ON HUMANS
27
ConcentrationsEffects
(ppm)
.0007 - .030 odor threshold
0.33 distinct odor; can cause nausea, headaches
2.7 - 5.3 odor offensive and moderately intense
20 - 33 odor strong but not intolerable
100 can cause loss of sense of smell in few
minutes
210 smell not as pungent, probably due to
olfactory paralysis
667 can cause death quickly due to respiratory
paralysis
750 virtually no odor sensation; death can
occur rapidly, upon very short exposure
Hydrogen sulfide in the facility work environment (e.g. power plant) is
likely to be of greater health significance than in relatively distant areas.
The Occupational Safety and Health Administration regulations (29 CFR 1910.1000)
list an acceptable ceiling concentration, without respiratory protection, of
20 ppm, with a maximum peak of 50 ppm for a 10-minute exposure. The American
Conference of Governmental Industrial Hygienists28 currently recommends a
time-weighted average limit over the work day or week of 10 ppm, with a
short-term (15 minute) exposure limit of 15 ppm. Conformance with these
criteria may obviate human health concerns outside the work environment.
Effects on Plants and Crops
Only hydrogen sulfide, sulfur dioxide and boron (boric acid) in geo-
thermal gases are currently recognized as potentially damaging to crops. Both
39
-------
hydrogen sulfide and sulfur dioxide are converted to acid of sulfates in the
environment, which can be damaging to plants and crops when in high enough
concentrations. Normally, such concentrations will not be reached through
geothermal emissions. Boron may also wash out of the air and damage plants,
particularly citrus crops.
NOISE POLLUTION
Geothermal development may cause noise pollution that is intolerable at
short distances without personal protection, particularly during (1) drilling,
particularly with compressed air, and (2) high volume steam losses, including
atmospheric flashing.
Noise pollution, unlike water and air pollution, is contaminating only
while it is occurring and only in the immediate vicinity of the source. Thus,
its most serious consequences occur near the source and are directly related
to the length of exposure. The effects are functions of intensity and expo-
sure time. In geothermal development both can be large.
The effects upon humans of geothermal development noise can take many
forms and can be physiological or psychological, or both. Effects include
hearing loss, interference with communication, sleep disturbance, and stress
reactions that can have long term health implications.
This document does not attempt to precisely relate noise effects to
noise levels, with respect to humans or other animal life. These relation-
ships have been documented by EPA.^-°»^ Occupational Safety and Health
Administration requirements for the workplace specify that no worker be
subjected to 115 dBA for more than 15 minutes or to 90 dBA for more than eight
hours.
The noise limitations imposed upon geothermal operations on Federal lands
specify a maximum level of 65 dBA at the lease boundary or a distance of one-
half mile from the source, whichever is greater.9
LAND-DISPOSED WASTES
The effects of pollution from land-disposed wastes should be similar to
those described previously under Water Pollution, since contamination would be
derived from leachate runoff and/or percolation to ground water.
RADIATION
Radiation, from radioactive materials, is a known carcinogen. At present
there is no level of exposure below which it is accepted that no biological
damage occurs. Any radiation exposures resulting from geothermal operations
would be caused by a redistribution of naturally occurring radioactive mate-
rials. The environmental effects could be due to external and internal
irradiation. The transfer of radionuclides to man is commonly by ingestion of
food and water and by inhalation.
40
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VI. POLLUTION CONTROL TECHNOLOGY
This section describes pollution control technologies that are or may be
applicable to discharges and emissions from geothermal energy conversion
systems. It also examines the costs of those technologies to the extent that
they can be determined.
As stated earlier, the EPA pollution control regulatory approach to
geothermal energy development is directed primarily toward the eventual estab-
lishment of Effluent Guidelines and New Source Performance Standards. Such
regulations are based upon the best demonstrated economically achievable
control technology in the industrial category to which they are applied.
Most of the technologies described herein either have not been applied to
geothermal operations or have been applied on a very limited scale. Thus, in
general, their applicability and their costs must be considered preliminary
judgments based mainly upon the use of those technologies in other industrial
sectors. Most of the following technology and cost information has been
extracted from a preliminary comprehensive study done for EPA by TRW Inc.
AIR POLLUTION
Technologies to control air pollution from geothermal operations are
directed primarily at incoming steam, condenser vent emissions, and cooling
tower emissions. In all of these, hydrogen sulfide (t^S) is the pollutant
currently of greatest concern. Each of the described technologies removes
hydrogen sulfide.
Stretford Process
Process Description
A simplified flow diagram of the Stretford process is shown in Figure 7.
The process produces elemental sulfur and is applicable to those geothermal
energy conversion processes condensing steam.-*^ It scrubs noncondensible
gases from the condenser ejector with an aqueous solution containing sodium
carbonate, sodium metavanadate, and anthraquinone disulfonic acid (ADA). An
alkaline solution of sodium carbonate and bicarbonate is produced with the
carbon dioxide present in the scrubbed gas stream. The gas stream is scrubbed
countercurrently with the alkaline solution in the absorber, and hydrosulfide
(HS~) is formed:
H2S + Na C03 -»- NaHS + NaHC03
NaHS(aq) -*- Na+ + HS~
41
-------
ABSORBER
CLEAN GAS TO
COOLING TOWER
NONCONDENSIBLE
GAS FROM POWER
PLANT-
REACTION
ZONE
CENTRIFUGATION
AND HEATING
SULFUR TO
STORAGE
Figure 7. Flow Diagram of A Stratford Process
The hydrosulfide is oxidized by 5-valent state vanadate to form elemental
sulfur and 4-valent state vanadate:
HS
V+5
V+4
The above reaction is hindered by pH over 9.5, thus the pH is controlled in
the optimum range of 8.5 to 9.5 by adding sodium hydroxide. Scrubbing solu-
tion is regenerated by blowing air into the oxidizer, and the reduced vana-
date is restored to the 5-valent state through a mechanism involving oxygen
transfer by the ADA:
+ ADA •*• V+5 + reduced ADA
reduced ADA + 0,
ADA + H20
Air blown into the oxidizer brings the suspended elemental sulfur to the
surface. The sulfur froth is removed to the skim tank and is either filtered,
centrifuged, or washed and melted to produce high quality sulfur. The Stret-
ford process is over 99 percent efficient, thus removing essentially all of
the hydrogen sulfide from the condenser off gases. The overall reaction is:
0
2H20
2S
42
-------
A surface condenser rather than a direct contact condenser must be used
with the Stretford process, to eliminate direct contact of the cooling water
with the condensate. Thus, the amount of water (condensate only - not cooling
water) available for hydrogen sulfide to dissolve in is significantly reduced.
However, with a surface condenser approximately 10 to 20 percent of the
hydrogen sulfide remains in solution with the condensate. The hydrogen sul-
fide dissolved in the condensate is stripped out of solution in the cooling
tower and emitted to the atmosphere. Therefore, if a Stretford process is
applied to a geothermal energy conversion system designed with a surface
condenser, 80 to 90 percent of the hydrogen sulfide existing in the turbine
discharge can be removed. The Stretford process will effectively control
hydrogen sulfide emissions without any direct detrimental influence on the
power cycle. However, the conventional geothermal energy conversion system
requires redesigning to include the surface condenser.
Costs
Stretford process cost estimates are based on the process currently being
designed for installation on one unit at the Pacific Gas and Electric Geysers
facility in 1978. Capital costs include the differential investment required
for a surface condenser in lieu of a direct contact condenser. Capital costs
for desired cases, where hydrogen sulfide concentration or steam flow rates
differ from those given for The Geysers base case, can be computed utilizing
the following formulas: ^1
IA = IB (f%0'^ for: 0.5 < SA < 5 metric tons of sulfur per day
SB
IA = IB (f^)0'5 for: 5 < SA < 250 metric tons of sulfur per day
SB
SA = metric tons of sulfur produced per day in the desired case
SB = metric tons of sulfur produced per day by the base case (The
Geysers unit 14) Stretford process.
I = Capital investment for the desired or base (A or B) Stretford
process.
The following assumptions were used to estimate the annual capital and
operating/maintenance costs for a Stretford unit:
32
• Amortization period: 15 years^
31
• Maintenance materials: 2 percent of the installed capital cost
• Maintenance labor: 10 percent downtime, requiring a two man mainte-
nance crew, earning approximately $30 per hour.
• Electrical power usage: 66 operating BHP per metric ton of sulfur
produced per day'-*-
31
• Chemical cost: $35 per metric ton of sulfur produced per day
43
-------
• Sulfur credit: $20 per metric ton
• Construction site: The Geysers
i
Costs, in mills/KWH, for power generation capacities ranging from 12.95
MW to 117.5 MW and a hydrogen sulfide concentration of 220 ppm are presented
in Figure 8. A greater or lesser quantity of steam produced from other geo-
thermal resources may be required to produce the same amount of electrical
energy generated at The Geysers. Since the cost of a Stretford process is a
function of the sulfur mass flow rate, costs will vary from those presented
in Figure 8 for other geothermal applications.
2.0
f 1.0
•^
i
5 °-5
o
0.1
220 ppm H2S
STEAM CONDITIONS:
180°C (355°F)
7.8 aim (114 psia)
TOTAL
- OPERATING &
MAINTENANCE
CAPITAL
10,000 100,000
POWER GENERATION (KWH)
Figure 8. Stretford annual cost vs. power generation
Iron Catalyst Process
Process Description
The iron catalyst (or Ferrifloc) system has been developed by Pacific
Gas and Electric Company and is presently in use for hydrogen sulfide control
at The Geysers geothermal field.33 This system is applicable to geothermal
conversion systems condensing steam and equipped with direct contact conden-
sers. A simplified flow diagram of this process is shown in Figure 9.
44
-------
NONCONDENSIBLE
GASES FROM t_
CONDENSER EJECTOR
COOLING WATER
RETURNED TO COOLING
CYCLE I
SLUDGE -
DISPOSAL
FILTRATION
STEP
SLUDGE
HOLING
TANK
CONDENSATE/COOLING WATER
FROM CONDENSER
COOLING
TOWER
00
BRINE
FERRIC SULFATE
INJECTION
FERRIC SULFATE
STORAGE TANK
Figure 9. Iron catalyst hydrogen sulfide removal process
Ferric sulfate, in solution, is added to the cooling water, thus oxi-
dizing the hydrogen sulfide contained in the aqueous phase. The nonconden-
sible condenser ejector gases are ducted to the cooling tower and hydrogen
sulfide is scrubbed by the falling water containing the ferric sulfate cata-
lyst. Operational experience at The Geysers indicates that practically all of
the hydrogen sulfide dissolved in the cooling water/condensate stream is
stripped out into the air stream as it passes through the cooling tower.
Therefore, any process controlling hydrogen sulfide emissions by treatment of
the cooling water must be applied to the cooling water upstream of the cooling
tower. The addition of ferric sulfate makes ferric ions available to react
with the dissolved hydrogen sulfide, thus forming elemental sulfur, water,
and ferrous ions. The reaction mechanism is given below:
H2S(aq) -»• 2H+ + S~2 '
Fe2(S04)3
2Fe
+3
~2
3S0
-»• 2Fe+2 + SI
2Fe
+2
2Fe+3 + H20
The ferrous ions react with the oxygen encountered in the cooling tower to
regenerate the ferric ions. Thus, the regenerated ferric ions are available
and the hydrogen sulfide reaction repeats continuously to form elemental
sulfur. The elemental sulfur produced by this process is removed from the
cooling water by filtration. The original design for this system included the
use of sand filters; however, significant plugging and maintenance problems
have been encountered at The Geysers facilities. To resolve these difficulties,
45
-------
alternative filtration systems are being investigated. The filtration step
generates large quantities of toxic sludge that may cause disposal problems.
An industrial waste disposal site or appropriate landfill disposal site is
required.
The iron catalyst system results in significant corrosion rate increases
in the condenser, cooling tower, and associated piping. Plugging problems
will be similarly increased in all of the equipment in contact with the
cooling water/condensate. The direct contact condensers presently operating
at The Geysers with an iron catalyst system are clad with stainless steel.
It is anticipated that the accelerated corrosion rate will reduce condenser
life to seven years.34 Insoluble salts carried over into the cooling tower
blowdown may cause plugging problems in the injection well, if the blowdown
is reinjected. The iron catalyst system is the only present control tech-
nology in use to control hydrogen sulfide emissions from both the cooling
tower and condenser ejector. The overall hydrogen sulfide removal efficiency
from the power cycle for the iron catalyst system is 90 to 92 percent.
Costs
The iron catalyst system is currently in operation at the Pacific Gas
and Electric Geysers facility on three units. The installed capital cost of
The Geysers unit 11 iron catalyst system^O Was used as a basis for the cost
estimates presented. It includes a differential investment for sludge
thickeners in lieu of sand filters.35
Capital costs for iron catalyst systems with steam flow rates differing
from those at The Geysers can be calculated with the following formula:
IA = IB (fff)0'6
STA = Steam flow rate of desired iron catalyst system
STB = Steam flow rate of base case (907,000 kg/hr)
I = Capital investment for the desired or base (A or B) iron
catalyst system.
The cost of the iron catalyst system is a function of the cooling water/
condensate flow rate; which is directly proportional to the steam flow rate.
Therefore, the steam flow rate is an acceptable variable in the cost equation.
Capital costs were assumed not to be affected by variations in hydrogen
sulfide concentration. Operation and maintenance costs for electrical power
and chemical usage are assumed to be linearly dependent upon: steam flow
rate (with constant hydrogen sulfide concentration) and hydrogen sulfide
concentration (with constant steam flow rate). Operation and maintenance
costs are difficult to estimate because of the operational problems encountered
at The Geysers.36
The following assumptions were used for the iron catalyst annual capital
and operation/maintenance cost estimates:
46
-------
• Amortization period: 15 years
• Maintenance materials: 1 percent of the installed capital cost
• Maintenance labor: 10 percent down time, requiring a two man crew,
earning approximately $30 per hour
• Electrical power usage: 68 KW per hour35
• Ferric sulfate usage: 0.5 kg ferric sulfate per kg of hydrogen
sulfide, with a loss factor of 20 percent3^
• Ferric sulfate cost: $0.05 per lb35 (0.11/kg)
• Removal efficiency: 90 to 92 percent
• Construction site: The Geysers
Costs, in mills per KWH, for power generation capacities ranging from
12.1 MW to 110 MW and a hydrogen sulfide concentration of 220 ppm are pre-
sented in Figure 10. Costs are based specifically on the operating conditions
for The Geysers unit 11 power plant and should not be applied to geothermal
energy conversion systems in general. At constant flow rates, costs increase
with increasing H2S concentrations.
2.0
1.0
s
5 °-5
o
u
220 ppm H2S
STEAM CONDITIONS:
180°C(355°F)
7.8 atm (114psla)
TOTAL
OPERATING &
MAINTENANCE
0.1
10,000 100,000
POWER GENERATION (KW)
Figure 10. Iron catalyst annual cost vs. power generation
47
-------
EIC Process
Process Description
The EIC process removes hydrogen sulfide from raw geothermal steam by
scrubbing it with an aqueous solution of copper sulfate.37 The hydrogen
sulfide and copper sulfate react in a scrubber, forming a copper sulfide
precipitate. The process is potentially valuable because it can remove
hydrogen sulfide from the plant input steam even while the plant may be shut
down. Another benefit of an upstream scrubbing process is the reduction of
corrosive effects of H2S on the turbine and condensing/cooling cycle equip-
ment. This enables the use of standard materials of construction for the
power plant equipment and piping. The EIC process removes hydrogen sulfide
without significant degradation of steam quality (temperature and pressure).
A simplified flow diagram of the EIC process, with regeneration by roasting,
is shown in Figure 11. Figure 12 shows the process with regeneration by
leaching.
ENERGY
SCRUBBING RECOVERY
HOT
LIQUID/
SOLID
SEPARATION
ROASTING
SOLIDS/GAS
SEPARATION
SCRUBBING/
NEUTRALIZATION
VENT LIME
LIQUID/
SOLID
SEPARATION
COPPER-FREE
SOLUBLES
PURGE
DISSOLUTION
CEMENTATION
AND L/S
SEPARATION
Figure 11. EIC hydrogen sulfide removal process with regeneration
by roasting.
48
-------
SCRUBBING
ENERGY
RECOVERY
LIQUID/
SOLID
SEPARATION
LEACHING
LIQUID/
SOLID
SEPARATION
PROCESS
WASTES
DISPOSAL
CLEANED
STEAM
RAW
STEAM
HOT MAKE-UP
SOLUTION
PURGE
SLURRY
MAKE-UP
SCRUB
SOLUTION
MAKE-UP Cu"-
AIR
MAKE-UP
WATER
COOLED
PURGE
SOLUBLES
PURGE
MAKE-UP
ACID
AIR VENT
SOLIDS
LIQUIDS
SULFUR
I RECYCLE ACID
I
I
LEACHED
SLURRY
REGENERATED
CuSO4 SOLUTION
PRECIPITATE Cu°
COPPER-FREE
SOLUBLES
PURGE
SOLID
WASTES
GYPSUM
NEUTRALIZED
PURGE
LIQUID
WASTES
IRON
LIME
DISSOLUTION
CEMENTATION
AND L/S
SEPARATION
NEUTRALIZATION
LIQUID/ SOLID
SEPARATION
Figure 12. ETC hydrogen sulfide removal process with regeneration
by leaching.
The process consists of three primary operations: scrubbing, liquid/solid
separation, and regeneration. A packed column, sieve tray column, venturi
scrubber, or spray scrubber could be used to provide sufficient contact time
and interfacial area for mass transfer between the hydrogen sulfide and
copper sulfide to occur. An eight- inch diameter single sieve tray column has
been used in field tests at The Geysers. Hydrogen sulfide gas in the geo-
thermal steam is absorbed in an aqueous solution containing dissolved copper
sulfate and suspended copper oxide particles by the following reaction
sequences:
H2S(aq) -> H
+
HS
HS
H
~2
CuS04(aq) -»• Cu
+2
2H
S0
~2
Cu
+2
CuS
Overall reaction: CuS04 + H2S ->• CuS + H2S04
49
-------
H2S(aq) -> H+ + HS"
HS~ -> H+ + S~2
CuO •+ Cu+2 + 0~2
Cu+2 + S~2 -»• CuS
2H+ + 0~2 -»- H20
Overall reaction: CuO + H2S -»- CuS + H20
The two reaction chains given above produce a highly insoluble copper sulfide
precipitate. The reactions given may be a partial list of the actual total
reaction chain mechanism. In addition, some reduction of cupric ions occurs,
resulting in a cuprous sulfide precipitate. The overall reaction for this
mechanism is :
Cu2S04 + H2S -> Cu2S + H2S04
The scrubbed steam passes through a mist eliminator to remove particulate
matter before being expanded in the turbine.
Copper sulfide slurry purged from the scrubber column is pumped to a
centrifuge to concentrate the slurry. The regeneration technique used will
determine the requirements of the liquid/solid separation step. If roasting
is used, a polishing filter may be necessary to remove fines entrained in the
recycle stream. If leaching is used for regeneration, unreacted copper
sulfides and elemental sulfur will be contained in the residues, thus requir-
ing the use of chemical flocculants together with filtration to obtain accept-
able separation and clarification. In order to reduce copper sulfate losses,
washing of the cake may be required. Clear liquid from the liquid/solid
separation process is returned to the scrubber.
Fluid -bed roasting burns the copper sulfide/ cuprous sulfide cake from
the liquid/solid separation step with air to produce recoverable copper
compounds. The roasting regeneration reactions are as follows:
CuS + 2 02 -
CuS + 3/2 02 ->• CuO + S02
S02 + 1/2 02 •> S03
The above reactions are highly exothermic, and self-sustaining after start-,
up. The solid copper sulfate and copper oxide are slurried and reintroduced
into the scrubber for continued hydrogen sulfide removal. The sulfur dioxide
and sulfur trioxide produced in the regeneration step are scrubbed by an
ammoniacal solution. The liquid discharge stream from the sulfur dioxide
scrubber is mixed with cooling tower blowdown and injected.
50
-------
Oxygen pressure leaching is the second alternative for recovering copper
compounds. The co.pper sulf ide/cuprous sulfide cake requires approximately a
two to four hour contact time with pressurized oxygen (100 psia) to obtain
acceptable conversion rates. The copper sulfide is oxidized to copper sulf ate
and elemental sulfur, the ratio being a function of residence time, pH, and
temperature. If desirable, operating conditions can be carefully controlled
to increase elemental sulfur production in the leaching step. The possible
reactions for copper sulf ate regeneration by leaching are:
CuS + 2 0 ->- Cu+2 + SO ~2
Cu2S + 5/2 02 + 2H+ -> 2 Cu+2 + S04~2 + HO
The possible reactions for elemental sulfur formation are:
CuS
Cu2
S
1/2
°2
+ 2H+-
4H+ ->' 2
" Cu+2 + S
Cu+2 + S +
+ H
2H
2
2
0
0
The EIC process was field tested at The Geysers, unit 7 in December 1976.
An eight inch diameter single sieve tray scrubbing column was used. Continuous
scrubbing of 1000 Ib/hr (450 kg/hr of steam, containing 220 ppm hydrogen sul-
fide, was accomplished for 30 hours with efficiencies generally over 97 per-
cent. Entrainment of copper from the scrubbed solution into the steam was
less than measurable (<0.05 ppm). In addition to hydrogen sulfide, approxi-
mately 80 percent removal of ammonia and boric acid was also observed. The
field test scrubber was constructed from Carpenter 20 Cb 3 and showed excel-
lent service under the field test operating conditions. Corrosion tests
with various stainless steels have resulted in corrosion rates of less than 5
mils per year.
Costs
Installed capital cost and operation/maintenance costs are summarized in
the EIC Corporation Annual Status Report37 for a 50 MW geothermal power plant
with steam conditions being those encountered for vent gases at the Niland
geothermal loop experimental facility located in Imperial Valley, California.
Capital costs for EIC units with hydrogen sulfide concentrations differing
from that for the Niland facility were computed by utilizing the following
formula:
IA = 0.85 IB (|f)0-6 + °'15 IB
HA = Hydrogen sulfide concentration of the desired EIC process.
HB = Hydrogen sulfide concentration for the given case (830 ppm) .
I = Capital investment for the desired or given (A or B) EIC process.
Eighty-five percent of the capital investment for the EIC process involves
reactors, tanks, vessels, heat exchangers, filters, pumps, and other asso-
ciated process equipment. The remaining 15 percent of the capital investment
51
-------
is allocated for the scrubbing tower. It is assumed that the capital invest-
ment for equipment associated with the liquid/solid separation and regenera-
tion operations (85 percent of total) vary exponentially with hydrogen sulfide
concentration according to William's sixth-tenth rule. ° The capital invest-
ment for the scrubbing tower (15 percent of total) is assumed to depend upon
steam flow rate and is relatively independent of hydrogen sulfide concentra-
tion.
Assumptions used to estimate the annual capital and operation/maintenance
costs for an EIC unit are:"
• Amortization period: 10 years
• Maintenance materials: 2 percent of the installed capital cost
• Maintenance labor: 4 operators at $18,000 per year
1 maintenance man at $20,000 per year
1 supervisor at $22,000 per year.
• Electrical power usage: 2,200,000 KWH per year
• Water usage: 10,000,000 gallons (37.85 x 106 liters) per year at
$0.50 per 1000 gallons (3785 liters)
• Chemical and process materials:
sulfuric acid - 300 tons (273 metric tons) per year at $33 per ton
($36.30/metric ton)
limestone - 250 tons (227 metric tons) per year at $8 per ton
($8.80/metric ton)
precipitated copper - 37.5 tons (34 metric tons) per year at $1600
per ton ($1760/metric ton)
detinned scrap - 45 tons (41 metric tons) per year at $200 per ton
($220/metric ton)
miscellaneous - $19,000
Costs, in mills per KWH, for power generation capacities ranging between
50 MW and 500 MW and a hydrogen sulfide concentration of 830 ppm are given in
Figure 13. The cost estimates presented for the EIC process were developed
from a specific set of operating conditions and do not necessarily apply to
geothermal resources with different operating conditions. At constant flow
rates, costs increase with increasing HoS concentration.
.52
-------
5.0
o
u
0.5
0.1
"1—i—I I I
i i
1 1 1 1 I I I I
830 ppm hUS
STEAM CONDITIONS:
150°C (300°F)
11.9 atm(160 psig)
TOTAL
OPERATING
& MAINTENANCE
10,000
100,000
POWER GENERATION (KW)
Figure 13. EIC annual cost vs. power generation.
1,000,0.00
Dow Oxygenation Process
Process Description
The Dow oxygenation process removes hydrogen sulfide from geothermal
brine at the wellhead; thus, it is applicable only to liquid-dominated
resources. Removal of hydrogen sulfide at the wellhead would provide a less
corrosive brine in the pipelines of the gathering field and a less corrosive
brine or steam in the power cycle. The Dow process oxidizes the aqueous hy-
drogen sulfide by injecting oxygen directly into the geothermal brine.
Thorough mixing to facilitate contact of the brine and oxygen can be accom-
plished by using in-line mixers or a cocurrent packed tower. Simplified flow
diagrams of these two systems are shown in Figures 14 and 15, respectively.
Figure 14 shows that ten in-line mixers are required for a geothermal well with
a 1000 gallon (3785 liters) per minute flow rate. This design utilizes the
largest available in-line mixer at an acceptable pressure drop.
The oxidation reaction occurs very rapidly, less than one minute for tem-
perature expected for geothermal brines. One proposed reaction chain for the
aqueous oxidation of hydrogen sulfide is as follows:
53
-------
MAGNETIC !
FLOWMETER !
—cr>
FROM
GEOTHERMAL
WELL
FROM02 FC
COMPRESSOR i* ---- '
TEFLON LINED
PIPE ISG
-*•
-j CONTROL
P~| MONITOR
CD=.
£=3^.
-**«-
TO POWER
PLANT
Figure 14
Dow oxygenation hydrogen sulfide removal process with
in-line mixers.
FROM OXYGEN
COMPRESSOR
PACKED
COLUMN
FROM
GEOTHERMAL£
WELL
TO POWER
PLANT
MAGNETIC
FLOWMETER
Figure 15. Dow oxygenation sulfide removal process with cocurrent
packed tower.
5A
-------
H2S(aq) •* H+ + HS
2HS~ + 3 02 -»- 2 S03~2 + 2H+
S03-2 + 1/2 02 -> S04~2
S03~2 + HS~ + 1/2 02 -»- S203~2 + OH~
S203~2 + 1/2 02 -»- S04~2 + S
The second reaction given above has an oxygen/sulfide mole ratio of 3:2
(or 1.5:1). However, Dow's laboratory experiments yielded results indicating
complete sulfide oxidation occurred at oxygen/sulfide mole ratios of 1.25:1 to
1.5:1, depending on temperature and total dissolved salts in the simulated
geothermal brine. Thus, it would appear that other reactions, such as the
following, must occur:
HS~ -y H+ + S~2
S~2 + 1/2 02 + H20 •* S + 2 OH~
S~2 + 02 + H20 -»- H2 S03~2
The oxygen/sulfide mole ratios for these two reactions are 0.5:1 and 1:1,
respectively. The amounts of elemental sulfur, sulfite, and sulfate formed
depend upon the oxygen/sulfide mole ratio, but generally 80 percent or more of
the sulfide is converted to sulfate ion, approximately 10 percent to elemental
sulfur and 10 percent or less to sulfite.
After oxygen is injected into the geothermal brine, and until it reacts
with the sulfide in the brine, the corrosivity of the brine increases. This
condition requires special materials of construction for both mixing/contact
systems. Piping in both systems is teflon-lined between the point of oxygen
injection and the mixers or packed tower. The packed tower requires use of a
corrosion-resistant alloy. The internal components of the mixers are con-
structed of teflon.
The in-line mixer system shown in Figure 14 was designed for a well flow
rate of 1000 gallons (3785 liters) per minute, thus necessitating the use of
ten in-line mixers in parallel, as described previously. In each of the ten
lines, a magnetic flowmeter measures the brine flow rate. The flowmeter is
electrically interlocked with a control valve, to ensure each line has an
equal brine flow rate, and interlocked with a control volve injecting com-
pressed cryogenic oxygen into the brine. The brine-oxygen stream passes
through an in-line mixer to ensure complete reaction. Injection of excess
oxygen into the brine is also controlled by a corrosion rate monitor located
downstream of the mixers. Mild steel piping can be utilized downstream of the
mixers. The brine streams are then combined and the brine sent to the power
plant. The packed tower system shown in Figure 15 does not require the
duplication of equipment and instrumentation necessary for the in-line
system. The geothermal well brine flow rate is measured with a magnetic
flowmeter and oxygen injection is controlled as described for the in-line
55
-------
system. The brine-oxygen stream passes through a packed tower to ensure
complete reaction. The piping downstream of the tower can be mild steel.
The Dow oxygenation process has been tested on a small 3gpm (11.3 £pm)
laboratory pilot-plant scale utilizing the in-line mixer system and shown to
be technically feasible. Initially, catalytic agents were believed necessary
to achieve acceptable reaction rates; however, addition of catalysts had no
measurable effect. Hydrogen sulfide removal efficiencies at 350°F (175°C)
and oxygen/sulfide mole ratio of 1.5:1 generally varied from 90 to 100 percent
over a pH range of 5.2 to 11.3.
Costs
Preliminary capital cost estimates for both the in-line and packed
column systems have been developed by the Dow Chemical Company, based on the
results of the laboratory investigation.39 Capital cost for an in-line sys-
tem was assumed to depend linearly on brine flow rates, because duplication
of equipment is required by the present in-line system design. Capital costs
for a packed column system with differing brine flow rates were computed by
utilizing the following formula:
IA - !B °-85
BA = Brine flow rate of desired Dow process
BE = Brine flow rate of given case (1000 gpm or 3785 Apm)
I = Capital investment for the desired or given (A or B) Dow
process.
The capital cost for a packed column system is, therefore, assumed to be
exponentially dependent upon the geothermal brine flow rate. The exponential
factor was based on that given for a stainless steel packed tower, 36 to 100
inches (90-250 cm) in diameter.38 Capital costs for the in-line and packed
column systems were assumed to be independent of the hydrogen sulfide brine
concentration. Operation and maintenance costs for electrical power usage
and cryogenic oxygen consumption were assumed to be linearly dependent upon
the hydrogen sulfide brine concentration.
The following assumptions were utilized to estimate the annual capital
and operation/maintenance costs for the in-line and packed column Dow oxygena-
tion systems:
• Amortization period: 15 years
• Maintenance materials: 1 percent of the installed capital cost
• Maintenance labor: 10 percent down time, requiring a two-man crew,
earning approximately $30 per hour
• Electrical power usage: 5 horsepower oxygen compressor required for
1000 gpm (3785 fcpm) system35
56
-------
• Cryogenic oxygen usage: Calculated for an oxygen/hydrogen sulfide
mole ratio of 1.25:1.0, with a loss factor
of 20 percent
• Cryogenic oxygen cost: $0.65 per 100 cubic feet (2.83 m3).3->
Because of the relative simplicity of equipment and design for the Dow
process, the annual maintenance material cost was taken as 1 percent of the
installed capital cost.
Costs, in mills per KWH, for power generation capacities varying from
14.9 MW to 347 MW and with a 500 ppm hydrogen sulfide concentration are shown
in Figures 16 and 17. Computations of generation capacities were based on a
double flash energy conversion system with 8 percent overall efficiency
operating with brine conditions given previously. Cost estimates for the Dow
oxygenation in-line and packed column systems have been developed from speci-
fic data and conditions, and thus cannot be applied directly to geothermal
resources in general.
COST (MILL/KWH)
en o
b b
10
—
-
*- t
• ^
4
i I i i i I i I
1 1 1 1 i 1 1 1
500 ppm H2S
BRINE CONDITIONS:
177°C (350°F)
11.2 aim (150 psig)
_ m TOTAL
I ^
OPERATING &
MAINTENANCE
CAPITAL
>A A
• •
i i • ii iii
10,000
100,000
POWER GENERATION (KW)
1,000,000
Figure 16. Dow oxygenation in-line system annual cost
57
-------
10.0
5.0
,
i 1.0
0.5
-I—I—I I I
TOTAL
OPERATING &
MAINTENANCE
^=^T
1 I I
CAPITAL
500 ppm H2S
BRINE CONDITIONS:
177°C (350°F)
11.2 atm (150 psig)
0.1
10,000
_L
1,000,000
100,000
POWER GENERATION (KW)
Figure 17. Dox oxygenation packed system annual cost
Other H2S Removal Processes
Several other processes are available for the treatment of hydrogen sul-
fide emissions. At the present time, they do not appear attractive for geo-
thermal applications because of high costs, low efficiency, proprietary nature
of the process, or questionable process reactions under geothermal conditions.
Solid Sorbent Process
Battelle Pacific Northwest Laboratories has investigated numerous solid
sorbents for the removal of hydrogen sulfide from geothermal steam. Battelle
assumed that the following parameters should be satisfied to establish a tech-
nically and economically viable hydrogen sulfide control process: minimum
degradation of steam regenerable sorbent; reasonably high sorption capacity;
simple regeneration process; quick regeneration; and a stable or useful by-
product of regeneration. Zinc oxide produced the most favorable results among
the numerous metal oxide and organic amine sorbents tested, because of its
good sorbent qualities for removing hydrogen sulfide from simulated geothermal
steam. The zinc oxide-hydrogen sulfide adsorption reaction is given below:
ZnO
ZnS
H20
58
-------
Regeneration is accomplished by reaction with oxygen:
ZnS + 3/2 0 ->• ZnO + S02
ZnS + 2 02 -> Zn SO,
The second regeneration reaction producing zinc sulfate is favored over for-
mation of zinc oxide when zinc sulfide is regenerated at low temperatures
with oxygen or air. Temperatures in excess of 1200°C are necessary to re-
generate zinc oxide directly from zinc sulfide. However, at those tempera-
tures, zinc oxide loses its capacity for adsorbing hydrogen sulfide.
A flow diagram for a sorbent hydrogen sulfide removal process proposed
by Battelle is shown in Figure 18. Geothermal steam is introduced from the
bottom of a fluidized bed gas-solid contact vessel and hydrogen sulfide is
adsorbed by the zinc oxide. The solid sorbent particles suspended in the
steam are removed in a cyclonic separator and, if required, a baghouse. The
steam is then utilized in the energy conversion system. Solid sorbent is
continuously removed from the fluidized bed contactor to the regenerator.
CYCLONE
SEPARATOR
•&-•
BAG
FILTER
CARRIER GAS
VENT
GAS-SOLID
CONTACTOR
GEOTHERMAL
STEAM
TO STEAM TURBINE
POWER GENERATOR
TO SULFUR
RECOVERY
REGENERATOR
CARRIER
GAS
PNEUMATIC AIR OR OXYGEN
PUMP
Figure 18. Solid sorption hydrogen sulfide removal process,
59
-------
Regenerated sorbent is returned pneumatically to the top of the contactor
vessel for reuse. Sulfur dioxide generated in the regeneration process re-
quires treatment in a separate sulfur recovery process. Battelle's labora-
tory investigation has established that a zinc oxide solid sorbent process is
not economically viable for the removal of hydrogen sulfide from geothermal
steam and recommends that no further work on solid sorbents be undertaken.
Glaus Process
The Glaus process is probably the best known process for recovering sul-
fur from gas streams containing hydrogen sulfide and sulfur dioxide. There
are several variations of the process; a specific version of the Glaus pro-
cess flow diagram is shown in Figure 19.
NONCONDEN-
SIBLE GAS
FROM POWER
PLANT
CLEAN GAS TO
COOLING TOWER
cs
AIR
BOILER
FEEDWATER
i— a:
to ut
* >
u- Z
o
at %
II
S§
u
FUEL GAS
REHEATER
Of.
o t^
«/> o
SULFUR TO
STORAGE
Figure 19. Glaus sulfur recovery process,
The process requires a specific concentration ratio between hydrogen
sulfide and sulfur dioxide. This ratio is obtained by combusting part of the
hydrogen sulfide to produce sulfur dioxide, which is mixed with the feed
stream. The hydrogen sulfide and sulfur dioxide are reacted with each other
in a series of converters to produce elemental sulfur, which is condensed out
of the main gas stream. The converters contain an activated bauxite catalyst
which accelerates the following reaction:
2 H2S + S02 •* 3 S + 2H20
60
-------
A tail gas containing residual amounts of hydrogen sulfide and sulfur dioxide
in moderate concentrations is treated by one of the following processes:
recycling into the main process upstream of sulfur separation, sent to another
treatment process, or diluted into a large volume of stack gases.
It is doubtful that the Claus process is suitable for removal of hydrogen
sulfide from condenser ejector gases. The presence of moisture and carbon
dioxide in the feed gas is detrimental to the Claus reaction. Carbon dioxide
causes the following side reactions:
C02 + H2S -*• COS + H20
C02 + H2S -*- CS2 + 2H20
The ejector gases will be saturated and the presence of water tends to reverse
the catalyzed Claus reaction.
Hydrogen Peroxide Process
Hydrogen peroxide has been used to remove hydrogen sulfide from various
wastewater streams. The applicability of H202 to geothermal cooling water/
condensate is somewhat questionable at this time because of the high tempera-
ture environment. Hydrogen peroxide reacts with hydrogen sulfide in an acidic
or neutral aqueous solution to produce elemental sulfur and water:
H202 + H2S -*- S + 2H20
In alkaline solutions (pH >8), the sulfide ion reacts with hydrogen peroxide
to produce sulfate and water:
H2S(aq) -»- H+ + HS~
HS~ -> H+ + S~2
S~2 + 4H202 -> S04~2 + 4H20
The acidic or neutral reaction is catalyzed by a metal ion, such as the
ferrous ion. The rate of the acidic reaction is greatly increased by an in-
crease in temperature. It is interesting to note that four times the hydrogen
peroxide is theoretically required to oxidize hydrogen sulfide in an alkaline
solution than is required to oxidize that in an acidic solution.
The FMC Corporation has conducted laboratory experiments on oxidation of
hydrogen sulfide in samples of cooling water/condensate streams taken from The
Geysers power plant.^ The experiments were conducted with various conditions
of hydrogen sulfide solution concentration, pH, temperature, hydrogen peroxide/
hydrogen sulfide weight ratio, and ferric sulfide catalyst concentration.
The results from the experiments indicate that the hydrogen sulfide oxidation
rate increases as a result of increases in (ranges tested given in parenthe-
sis) : initial hydrogen sulfide concentration (2.3-12.5 ppm), temperature
(40°-51°C), hydrogen peroxide/hydrogen sulfide weight ratio (0.9-3.9 and
400), and ferric sulfide concentration (0-2.0 ppm). An efficiency of 88
61
-------
percent was obtained in less than three minutes, without the use of a cata-
lyst, and using a hydrogen peroxide/hydrogen sulfide weight ratio of 1.9 and
an initial hydrogen sulfide concentration of 12.5 ppm. The results from the
FMC experiments indicate that the use of hydrogen peroxide for oxidation of
hydrogen sulfide in geothermal cooling water/condensate is feasible.
Ozone
The use of ozone to oxidize hydrogen sulfide in aqueous solutions has
not been adequately investigated to evaluate its applicability for control-
ling emissions from geothermal sources. Ozone has previously been used to
oxidize hydrogen sulfide in the gaseous phase. Elemental sulfur and sulfate
are the most likely products of a hydrogen sulfide-ozone aqueous reaction:
3H2S + 03 -> 3S + 3H20
3H2S + 4 03 + 3H2S04
Four times as much ozone is required to produce sulfate as is required to
produce elemental sulfur. Because of the cost of producing ozone, the
economic feasibility of this process may depend on which of the two reactions
dominate.
Burner-Scrubber Process
The burner-scrubber process incinerates the noncondensible condenser
ejector gases and scrubs the combustion products with cooling water. The
hydrogen sulfide contained in the ejector gases is burned to sulfur dioxide.
The combustion gases are ducted to a scrubber where contact is made with
cooling water, thus dissolving the sulfur dioxide. The dissolved sulfur
dioxide reduced the pH of the cooling water, which increases the amount of
hydrogen sulfide being removed with the noncondensible gases from the con-
denser. Thus, more hydrogen sulfide is incinerated, rather than remaining
dissolved and being stripped from the cooling water into the air stream in
the cooling tower. The sulfur dioxide may also oxidize the hydrogen sulfide
dissolved in the cooling water to produce elemental sulfur, providing further
abatement of hydrogen sulfide emissions. The burner-scrubber system has been
field tested on The Geysers 27 MWe unit 4, with approximately 50 percent of
the hydrogen sulfide entering the power plant being removed.30
Catalyst-Scrubber Process
The catalyst-scrubber process is essentially the same as the burner-
scrubber system, except the hydrogen sulfide is selectively oxidized to
sulfur dioxide with a catalyst developed by the Union Oil Company. Since
the hydrogen sulfide is oxidized without combustion, this system is potential-
ly less complex and safer than the burner-scrubber process. The efficiency
of the catalyst-scrubber process is also expected to be approximately 50
percent. This process is projected to be installed on The Geysers 53 MWe
units 5 and 6 sometime in 1978.
62
-------
Deuterium Process
The Deuterium process removes hydrogen sulfide from geothermal steam up-
stream of the power plant. This process is proprietary and a process des-
cription is not currently available. The Deuterium Corporation holds the
patent for heavy water, production of which requires steam containing hydro-
gen sulfide.
WATER POLLUTION
Water pollution control technologies include wastewater treatment and
ensuing wastewater disposal. The following discussion describes both along
with preliminary cost estimates. Depending upon the constituents and the
amounts that must be removed, many of the treatment technologies may be used
individually or in series. The treatment technologies are those applicable
to the removal of suspended and dissolved solids.
Wastewater Treatment Technologies
Sedimentation, Chemical Precipitation, and Filtration
Sedimentation Process Description - Sedimentation is a physical treat-
ment operation that removes settleable solids from wastewaters. It is gener-
ally applied to raw wastewaters and to wastewaters that have been chemically
treated to precipitate constituents. Any one of several configurations of
settling ponds, tanks, and gravity separators may be used for sedimentation.
They may be used (particularly gravity separators) to concurrently remove
floating materials such as oil. Without other treatment, they will not remove
significant amounts of dissolved or emulsified materials.
Sedimentation process efficiency is a function of temperature of the
wastewater, the density and size of suspended particles, the amount and char-
acter of the suspended material, and settling time. Gravity separation can
normally remove 50-65 percent of the suspended solids.^2
Chemical Precipitation Process Description - Chemical precipitation is a
chemical treatment process involving chemical addition, particle aggregation
and particle precipitation. This, treatment process is used to assist the
sedimentation of colloidal and highly dispersed particles in the waste stream
by aggregation and coalescence of small particles into larger more readily
settleable or filterable aggregates. Some dissolved inorganic constituents
may also be precipitated by chemical coagulants.
The function of chemical coagulations and mechanical flocculation of
wastewater is the removal of suspended solids by destabilization of colloids
and removal of soluble inorganic compounds, such as trace metals and phos-
phorus, by chemical precipitation or adsorption on chemical floe. Coagulation
involves the reduction of surface charges of colloidal particles and the
formation of complex hydrous oxides or precipitates. Coagulation is essen-
tially instantaneous in that the only time required is that necessary for
dispersing the chemical coagulants throughout the liquid. Flocculation in-
volves the bonding together of the coagulated particles to form settleable or
63
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filterable solids by agglomeration. Agglomeration is hastened by stirring
the water to increase the collision of coagulated particles. Unlike coagu-
lation, flocculation requires definite time intervals to be accomplished.
The more common chemical coagulants used are filter alum, ferric or
ferrous sulfate, sodium aluminate, and ferric chloride. Among the coagulant
aids used, the more popular ones are lime, soda ash, activated silica, and
bentonite or other clays. Generally, chemical coagulants and coagulant aids
are added to the waste in a separate chamber in which the waste is mixed
rapidly with the chemicals. This system is followed by flocculation chambers
and sedimentation tanks.
In general, coagulation reactions vary significantly with changes in pH;
therefore pH adjustment of the wastewater may be required to achieve optimum
conditions. With proper design of the coagulation/flocculation system and
sedimentation tank, removal efficiencies of 80-90 percent of suspended solids
and 20-40 percent of dissolved solids can be readily attained.
Filtration Process Description - Filtration is a solids-liquids separa-
tion technique to remove particulate matter from wastewater. It may be used
instead of or in addition to sedimentation. In filtration, the wastewater
to be treated is passed through a porous medium. Solids separation is accom-
plished largely by sieving action. The mechanisms involved in the removal of
suspended or colloidal material from wastewater by filtration are complex
and interrelated. The dominant mechanisms depend on the physical and chemical
characteristics of the particulate matter and filtering medium, the rate of
filtration, and the biological-chemical characteristics of the water. The
mechanisms responsible for the removal of particulate matter vary with each
treatment system.
Filtration can be accomplished by the use of: (1) a microstrainer,
(2) distomaceous earth filtration, (3) sand filtration, or (4) mixed-media
filtration. The microstrainer is a screen in the form of a partially sub-
merged rotating drum or cylinder. Water flows continuously by gravity through
the submerged portion from inside the drum to a clear-water storage chamber
outside the drum. Cleaning is carried out by backwashing with sprays of
product water. Removal efficiencies have been reported for the following para-
meters: SS 50-80 percent; BOD 40-70 percent; and turbidity 60-76 percent.42
Diatomaceous earth filtration is a mechanical separation system that
employs a filter aid layer of diatomaceous earth. As filtration proceeds,
deposited solids build up on the precoat, resulting in an increase in pressure
drop. The filter run can be increased by the addition of a filter aid to the
body feed to maintain the porosity of the cake. When the pressure drop be- !
comes too great to continue filtration, the filter is backwashed and a new '
precoat applied. Turbidity and suspended solids removals in excess of 90
percent have been reported.^3
Sand filtration is usually employed following chemical coagulation and
preceding carbon adsorption or ion exchange. The average filter run before
backwashing is related to the solids loading on the filter. Generally, fil-
tration rate is low, and backwashing is frequent because of the rapid build-up
64
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of headless.
very good.
However, removal efficiency for suspended solids is usually
Mixed-media filtration was developed in an attempt to approach ideal
filtration. Three to four types of media are layered into the filter, graded
as to size and density, with coarse low density coal (sp. gr. about 1.0) on
top, smaller regular density coal (sp. gr. about 1.6) and silica sand (sp. gr.
about 2.6) in the middle two layers, and garnet sand or ilmenite (sp. gr. of
4.2 and 4.5, respectively) in the bottom layer. These different media pro-
vide decreasing, coarse to fine, void gradation down through the filter.
Large suspended particles in the wastewater are stopped near the surface with
finer suspended solids being entrapped in bottom layers, thus providing full
bed depth filtration. Effluent suspended solids concentrations less than
1.0 mg/1 are readily achieved.^
A typical granular media filter is shown in Figure 20. The wastewater is
passed through one or several layers of granular material and suspended solids
are removed by physical screening, sedimentation, and interparticle action.
Headless increases until breakthrough or removal capacity is reached, and then
the filter is cleaned by backwashing.
FILTER BASIN
WASH TROUGHS
BACKWASH
GULLET
SINGLE OR
MIXED MEDIA
GRADED GRAVEL
EFFLUENT BACKWASH
HEADER
PERFORATED LATERALS
FILTER FLOOR
Figure 20. Cut-away view of a granular mixed media filter.
65
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Costs of Sedimentation, Chemical Precipitation, and Filtration
The basis for the development of cost curves is derived from the Van
Note, et al. , publication "Guide to the Selection of Cost-Effective Waste-
water Treatment Systems. "^^
The cost curves for these treatment systems basically consist of three
elements: total cost, capital investment, and operation and maintenance
(O&M) costs. Total cost is defined as the sum of capital investment and O&M
costs. Capital investment is the cost of purchasing and installing the
pollution control systems. O&M costs are associated costs for the operation,
repair, and routine maintenance of the pollution control equipment. Since
the capital investment as well as the O&M costs are flow dependent, empirical
equations have been developed for costing these pollution control systems.
The total amortized capital cost (TACC) in cents is given by the following
equation:
TACC = [(BCC) (-) + (LRKULC)]
and the operation and maintenance costs (O&M) are given by:
Fixed operation and maintenance cost in C/1000 gal. is
(0&M)p = (BHM) (MHR) ( * ),
and variable operation and maintenance cost, C/1000 gal. is
(0&M)V= (BMC)
where
BCC = base capital cost
STP = October 1977 cost index for average wastewater treatment plant
LR = land requirement
ULC = land cost
SIF = service and interest factor
Q = wastewater flow (mgd)
CRF = capital recovery factor
BMH = base man-hours
MHR - labor rate
BMC = base materials cost
WPI = wholesale price index
66
-------
Total capital costs and total operation and maintenance costs were computed
in cents per thousand gallons, then converted to cents per thousand liters
and plotted in Figures 21 through 26. The cost for the disposal of sludges
and brine has not been included. Variations of geographic locations, climat-
ic conditions, land values, and composition of waste streams may invalidate
the application of these curves. However, new curves can be developed, based
on the equations and assumptions provided above.
In costing the sedimentation basins, a surface loading rate (overflow
rate) of 800 gallons/day/ft2 (3.26 Ji/day/cm2) was assumed. The required sur-
face area of the basins is based on this loading rate. Depending on the
nature and characteristics of the geothermal fluid, the overflow rate may
not be adequate for complete settling of the suspended material. The cost
curves developed for chemical precipitation by the addition of lime, alum, or
ferric chloride are applicable for geothermal fluids with chemical character-
istics approximating those found in municipal wastewaters. The actual amount
of chemical dosage for geothermal fluids will have to be determined by jar
test of the geothermal fluid. The chemical dosage in this cost analysis
assumes 200 mg/1 lime addition, and 170 mg/1 of ferric chloride and alum addi-
tion. The capital costs for both the sedimentation basin and chemical precip-
itation system include costs for sludge removal devices, piping, pumps, and
equipment for sludge thickening.
100
o
o
in
O
u
10
1.0
0.1
i I i
TOTAL
I I I I 1 1 t III I I I I I
10 100 1000 10,000 100,000
FLOW (1/MIN)
Figure 21. Cost estimates for sedimentation.
67
-------
100.0
10.0
o
o
o
S i.o
0.1
O&AA -
I
1.0
10.0 100.0 1,000 10,000 100,000
FLOW (1/MIN)
1,000,000
Figure 22. Cost estimates for chemical precipitation
with single stage lime addition.
TOO
o
o
o
^ 10
1.0
0.1
I
I
I
O & M
10
100 1000 10,000 100,000
FLOW (1/MIN)
Figure 23. Cost estimates for chemical treatment 2 stage lime addition.
68
-------
o
o
o
100 -
100
1000
FLOW (1/MIN)
10,000
100,000
Figure 24. Cost estimates for chemical precipitation
with alum addition.
10
100
1000
FLOW (1/MIN)
10,000
100,000
Figure 25. Cost estimates for chemical precipitation
with ferric chloride addition.
69
-------
100
o
o
o
^.
2. 10
8
1.0
TOTAL
O&M
10
100
1000
FLOW (1/AMN)
10,000
100,000
Figure 26. Cost estimates for filtration.
The costing curves developed for gravity filtration are based on a fil-
tration rate of 4 gal/min/ft2 (0.016 A/min/cm^). This rate is highly depend-
ent on the nature of the filtering fluid and the characteristics of the
filter media. The capital costs include both the filter and the facilities
for storage of backwash water (all pumps and piping were also included).
Reverse Osmosis
Process Description - In this process, a portion of the wastewater is
forced through a semi-permeable membrane (see Figure 27).^° The membrane
allows passage of water (permeate) while impeding passage of dissolved ions.
The portion of the waste stream not forced through the membrane becomes more
concentrated in dissolved solids than the original waste. This concentrated
solution (retentate) must be disposed of in some manner. If it is not possi-
ble to reclaim the retentate, it must be treated to produce an effluent suit-
able for discharge.
The membrane is the heart of the reverse osmosis process. Most membranes
in current use are cellulose acetate. However, properties of cellulose ace-
tate membranes vary according to the method of manufacture. Therefore, dif-
ferent membranes have different permeabilities for various ions. The feasi-
bility of reverse osmosis as a treatment process is determined by the avail-
ability of a membrane which sufficiently limits passage of the ion to be re-
moved while allowing passage of a reasonable amount of water.
70
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Brine
inlet
permeate
I
Pressure
regulator
ffiPJUKfl Concentrated
'' brine
Treated water
Figure 27. Schematic presentation of reverse osmosis
Given a suitable membrane, the performance of a reverse osmosis unit is
largely determined by the split taken between the permeate and the retentate.
As a larger fraction of the feed is removed as permeate, the concentration of
the retentate increases. The increased concentration difference across the
membrane tends to cause ion migration through the membrane. In general,
reverse osmosis reduces the dissolved solids concentration to approximately
10 percent of that of the feed solution. Passage of individual ions varies
according to the selectivity of the membrane, feed temperature, and pH.
Water flux usually increases with increasing temperature, whereas salt rejec-
tion remains essentially constant over the normal operating temperature range
of 15-30°C. The effect of pH on performance of the reverse osmosis unit is
determined by membrane hydrolysis, which also influences salt rejection.
Since the membrane is an organic ester, the rate of hydrolysis is PH dependent.
Hydrolysis increases at both high and low ends of the PH scale. For thxs
reason a pH of 3 to 7 should be maintained for optimum membrane operation.
Industrial application of the process has shown the following removal effi-
ciencies-42 SS 95-98 percent; BOD 95-99 percent; COD 90-95 percent; NH3 95-
99 percent; and org-N, N03N, P04-P, and TDS 95-99 percent.
For reverse osmosis to be effective, it is essential that all large sus-
pended particles be removed prior to its application. In addition, most mem-
branes have a maximum tolerable temperature beyond which the membrane loses
its effectiveness in retaining the dissolved constituents. Most commercial
membranes have a maximum temperature limitation of 20QOF. Geothermal fluids
may require cooling prior to treatment by reverse osmosis.
Costs - Cost estimates for reverse osmosis were derived from a combina-
tion ^TsTudies prepared by the Fluids Systems Division of UOP, Inc., Los
County Sanitation, and the Orange County Water District Factory 21
incl* .
(M&S Index) .
71
-------
100.0
o
o
o
25- 10.0
1.0
CAPITAL
1,000 10,000 100,000
FLOW (1/MIN)
Figure 28, Cost estimate for reverse osmosis system.
Costs of reverse osmosis depend upon the quality and quantity of waste-
water to be treated. Pretreatment and disposal of residuals have not been
included in the estimates. Membrane life is strongly influenced by the amount
of total dissolved solids. The costs shown are for one stage. More than one
stage may be required to achieve suitable effluent quality.
Electrodialysis
Process Description - This is an electrolytic process causing separation
of ions in the presence of an imposed electrical field. Ions of opposite
charge migrate through membranes toward their respective electrodes and the
brine is separated into water and a concentrated brine.^ The basic princi-
ples of electrodialysis are illustrated in Figure 29.
Wastewater
inlet _
negative pole
or cathode
positive pole
or anode
Concentrated
waste ^—
^Treated
water
Figure 29. Electrodialysis cell
72
-------
The electrodialysis system uses a series of alternately-placed anion and
cation permeable membranes having a series of compartments. The application
of an electrical potential across the system results in the migration of
cations to the cathode and of anions to the anode. This creates a series of
concentrating and diluting compartments.
Electrodialysis as a wastewater treatment process is in the preliminary
development stages. It has been used for the desalination of brackish water.
Electrodialysis has not been used extensively in the treatment of industrial
wastes.
The membranes used in the process are subject to fouling by any sus-
pended solids or oils (or other organics) in the waste. Membrane life in a
system having adequate suspended solids protection must be determined experi-
mentally. Electrodialysis has produced water having a total dissolved solids
content of less then 500 ppm. This process is also found to be effective in
removing 30% to 50% of NH-j-N and PO^-P and approximately 40% of TDS.42
Costs - For electrodialysis systems, the cost estimates were derived
from information gathered in the San Francisco Bay-Delta Water Quality
Control Program Study.^ Data points were extracted directly from the
existing graphical plots. Cost and flow units were converted to the metric
system. These cost data (capital and 0 & M costs) were then updated to the
present 1977 second quarter costs by again using the M & S Index. The plotted
data (shown in Figure 30) were found to correlate relatively well with actual
too.o
o
o
o
10.0
1.0
TOTAL
CAPITAL
O&M
10
] x 10-
1 x
FLOW (1/NVIN)
Figure 30. Cost estimates for electrodialysis system
73
-------
cost data presented by Dryden^O and cost curves illustrated by Faber.->l
Unfortunately the assumptions (amortization periods, interest rates, etc.)
utilized in the original Bay-Delta Study on electrodialysis systems were not
available for inclusion in this report; therefore it is not possible to
assess the accuracy and validity of these data points.
As in reverse osmosis, the cost of electrodialysis will depend primarily
on the quality and quantity of wastewater to be treated. Pretreatment and
residual disposal costs are not included. The costs shown are approximations
for one stage. More than one stage might be required.
Ion Exchange
Process Description - This process involves the exchange of objectionable
ions in the wastewater with non-objectionable ions such as H+ or OH~ in the
resin material. ->2 Most ion exchange materials are synthetic polymers contain-
ing active groups such as HSO^ and NH, to which the exchangeable ions (H+ and
OH") are attached. The exchange reaction for removing sodium chroma te from
surface rinse waters by a combination of cationic and anioni^ exchange resins
can be represented by:
R-H + Na+ -> R~Na+ + H+
(OH-)2 + CrO~"4 -»• RCrO™4 + 2 OH~
i i
where R~ and R represent the cationic and anionic exchange material.
When the resins are operating on H+ and OH~ cycles, treatment with ion
exchange also results in the production of deionized water which can be used
for process water or in other applications requiring a high quality water.
Demineralization by ion exchange is a process for removing inorganic
salts and trace metals from wastewaters. In general, salts are composed of a
positive ion of a base and a negative ion of an acid. These ions are removed
in two stages: the positive ions by the cation exchanger and the negative
ions by the anion exchanger. In the first stage the positive ions of a base
such as calcium (Ca) , sodium (Na) , or magnesium (Mg) are exchanged for hydro-
gen ions (H) in the cation exchange column, thereby converting these positive
anions into their respective acids. In the second stage the negative ions of
the acid such as silicates (8103) , carbonates (003) , chloride (Cl) , or sulf ate
(804) are removed and exchanged for hydroxide ions (OH) in the anion exchange
column. This completes the two step removal of the salt. In mixed-Ked ion
exchangers, as shown in Figure 31, the two steps are combined into one.
!
Once the demineralized ion exchangers are saturated or excessive leakage
occurs they have to be regenerated to allow reuse of the resins . Cation
exchangers are regenerated by strong acids (KUjSO^ or HC1) and anion exchangers
by caustic soda (NaOH) . For continuity of operation during bed regeneration,
two trains of ion exchange columns are needed.
74
-------
Raw water
Drain
Alkali
Treated '—"Raw
water water
SERVICE BACKWASH
Air out
Drain
'Acid ' Air
REGENERATION RESIN MIXING
Figure 31. Mixed-bed ion exchange process.
Ideally, ion exchange columns can reduce a given pollutant concentration
to essentially zero. In practical applications, depending on the type of
resins used, removal efficiencies for total dissolved solids (IDS) have been
reported in the range of 80 to 90 percent.52 Studies using weak electrolyte
ion-exchange resins for the removal of ammonia and phenolics from foul-water
condensates of refineries have shown promise.
Costs - The basis of the cost curves in Figure 32 for ion exchange sys-
tems is from Van Note's publication.^5 Chemical costs for regeneration are
part of the O&M costs. The actual cost for ion exchange systems is depen-
dent on the exchange resin, the characteristics of the waste water, and the
effluent quality required. Pretreatment costs or the cost of disposal of
backwash brine have not been included.
100.0
o
o
' 10.0' -
10
100
1000 10,000
FLOW (1/MIN)
100,000
Figure 32. Cost estimates for ion exchange system.
75
-------
Evaporation - Distillation
Process Description - In evaporation processes components of a liquid
are separated by vaporization and condensation. Single- and multiple-effect
evaporators are frequently used in the chemical industry to extract water
from aqueous solutions.
Evaporators generally use steam as the heat source. Some evaporators
may use several stages (termed "effects") to conserve heat. In multiple-
effect evaporators (Figure 33), steam is introduced into the first effect in
the series, and succeeding effects are operated at lower pressures so that
steam condensed from the preceding stage can be used as the heat source in
the next. Reduced pressure is usually obtained by exhausting the vapor from
the final effect to an aspirator-condenser, such as a jet condenser.
steam in
condensate
brine inlet
product
Figure 33. Multiple-effect evaporation.
The multiple stage flash evaporation scheme places all steam heat ex-
change outside of the evaporation chambers, in a feed preheater. Distillate
is flashed from the brine in each stage at successively lower temperatures
and pressures (Figure 34). A test facility, using this technology on geo^
thermal brines, is being operated by the Bureau of Reclamation, at East Mesa;,
California. Its objective is to produce fresh water for augmenting the Colo-
rado River flow and for irrigation. Vapor condensation occurs on exchanger
surfaces cooled by inlet water, which is warmed progressively through each
stage. Multiple flash evaporators are more economical than multi-effect
units, and are frequently used in desalination applications.
76
-------
VENT
CONDENSATE
TO BOILER
SALT
WATER (20 :C)
DISTILLATE
«- BRINE (30 Cl
Figure 34. Multiple stage flash evaporation.
Vapor recompression techniques can also be used to conserve heat
(Figure 35). The vapor compression method uses mechanical rather than
thermal energy, by compressing overhead vapor and using the compressed vapor
as a heat exchange medium before it is discharged and used to preheat in-
coming feedwater. Compression stills may be economically attractive where
cheap electrical power is available to drive the compressor. The effective-
ness of this method is about the same as that of evaporation ponds, but it is
faster and requires heat input.
STEAM
101°C, 1 atm
SEPARATION
SPACE
MOTOR
'i sA'tZS COMPRESSOR
^L EVAPORATOR
HEAT EXCHANGER
EE SEAWATER
E3 LOW PRESSURE STEAM
M COMPRESSED STEAM
O FRESHWATER
BRINE
0.25 m /hr, 27°C
SEAWATER
1.25 m3/hr, 15°C
"*• FRESHWATER
1.00 m3/hr, 21°C
Figure 35. Compression still
These methods are capable of reducing the volume of brine by 70 to 80
percent. The concentrated salt-brine residue must be properly disposed of by
either ocean dumping, deep well injection, or after total evaporation, by
landfill.
77
-------
Costs - Evaporation systems costs are dominated by energy requirements,
which are directly proportional to the amount of water to be evaporated. The
cost of treatment decreases only slightly with increasing throughput (at a
fixed percentage of feed to be evaporated). The total costs shown in
Figure 36 are a composite of the operating costs and annualized capital costs
using the following assumptions:
Electricity @ 4C/KWH, steam @ $2/million Btu
8400 operating hours/year, over a 20-year project life (8% rate
of return).
Capital and operating costs were obtained from experience in chemical and
paper industry practice^* 54,55 for multi-effect and vapor recompression
evaporators. Most cost data for multistage flash units are available from
desalination installations.56,57
~ 100
o
o
o
5 10
O
u
1.0
MULTISTAGE FLASH
MULTIEFFECT
VAPOR RECOMPRESSION
I
I
I
10
100 1000 10,000
FLOW (1/MIN)
100,000 1,000,000
Figure 36.
Total costs for evaporation. Basis: 50% of
feed evaporated; 40°C feed temperature
The efficiency of multiple stage evaporators (in terms of water produced
per unit quantity of steam) improves with increasing number of stages of
evaporation or flashing, and a total cost advantage is obtained from the use
of ten stages versus three (Figure 36). Even so, the lower cost of vapor
recompression units is clearly evident at power costs of 4C/KWH, and the cost
would be even lower with cheap power available from an associated power
plant.
Variables which strongly affect evaporation costs include the percentage
of feed to be evaporated; the inlet feed temperature; and (in the use of
reduced pressure evaporation) the temperature of cooling water. The cost
data shown in the figures are based on 50 percent evaporation of feed-water,
with an incoming feed temperature of 40°C. There would be considerably more
78
-------
enthalpy (heat content) available in the incoming feed from the flash down of
a geotherraal power operation, and this extra enthalpy can be translated into
increased amounts of evaporation over the base case. If, for example, an
evaporator was designed to evaporate 30 percent of its feed (at 65°C), the
same evaporator could yield about 75% evaporation at a feed temperature of
150°C, and 90% evaporation at 225°C.
The total costs for evaporation (20 to 70c per 1000 liters of feed shown
here are far more than for many competitive methods of wastewater treatment,
and some amount of a high-salinity waste brine stream will always require
disposal. The conclusion is that evaporation is not an economically viable
method for treatment of waste brines.
Other Wastewater Treatment Technologies
In addition to the above-mentioned treatment technologies there are two
processes that have been under investigation by the Office of Saline Waters
(OSW) for desalination of ocean waters. These include direct freezing/gas
hydration and liquid-liquid extraction processes. Direct freezing and the
formation of gas hydrates has potential application for separating salt from
sea water to produce potable water. However, freezing of high temperature
geothermal fluids for the purpose of desalination has technical and economic
constraints. Its application to treatment of geothermal wastewater cannot
be considered a viable alternative at the present time.
Liquid-liquid extraction involves the use of a solvent (such as di-
isopropyl amine-propane or N-butanol) to preferentially extract salt from
saline water and subsequent evaporation and recovery of the solvent. The use
of liquid-liquid extraction for desalting high temperature geothermal fluids
would result in technical problems caused by the instability of solvents at
high temperature. Its potential application to geothermal fluid treatment is
definitely limited and cannot, therefore, be considered viable under current
technology.
Specific Chemical Constituents Abatement Technology
The wastewater control technologies presented in the previous subsection
deal primarily with process effectiveness and applicability in the removal of
gross constituents. A detailed assessment of the removal efficiencies for
specific chemical constituents has not been made. This subsection presents a
survey of control technologies for the removal of specific pollutants from
wastewaters. Table 9 is a summary of this survey. Since most literature
findings are limited in information and specific pollutant removal, efforts
were made to contact knowledgeable persons in the field, such as equipment
vendors, engineering consultants, government regulatory agencies, and academ-
icians, to seek expert opinions on specific applications of pollutant removal
from wastewater.
Application of Wastewater Treatment Technologies
Wastewater treatment requirements depend upon the character of the raw
wastewater compared to the quality to be maintained in the wastewater disposal
79
-------
TABLE 9. REPORTED EFFICIENCIES OF CONTROL TECHNOLOGIES FOR
TREATMENT OF SPECIFIC CONSTITUENTS FROM WASTEWATERS
(% removal)
Chemical Electro- Ion Reverse
Sedimentation Precipitation Filtration dialysis Exchange Osmosis
TS
TDS
Fe
Mn
B
Zn
Ba
F
Pb
Cu
As
Hg
Se
Cr
Ag
Cd
20-40
10
10-30
10-30
10
10-30
10
10
10-30
10-30
10-30
10-30
10-30
10-30
10-30
10-30
40-60
20-40
60-100
65.4-99.4
20-40
90-95
85-99
99
95-97
80-85
80-98
40-60
80-90
60-99
90-99
85-95
70-95
10
70-95
90-98
20-40
60-85
80-98
10
95-98
90-95
75-95
70-80
90-95
60-99
90-99
90-98
30-50
30-40
30-40
30-40
10
30-40
99.9
10
30-40
30-40
30-40
30-40
30-40
30-40
30-40
30-40
80-90
80-90
80-90
80-90
80-90
80-90
99
80-90
80-90
80-90
80-90
80-90
99.7
80-90
85-95
80-90
90-99
85-95
95-98
95-98
60-80
85-95
95-98
88-92
95-98
95-98
85-95
85-95
85-95
85-95
85-95
85-95
area or receiving media. In order to examine the requirements, three sets of
possible raw wastewater constituent characteristics and three sets of possible
discharge requirements have been compiled in Table 10. The values shown are
not intended to be actual, but probably include the ranges to be considered
in geothermal wastewater treatment. Possible ranges of flows for various
uses are shown in Table 11. Based on the information shown in Table 10, the
required removal efficiencies were calculated, as shown in Table 12, for the
various raw levels vs. discharge levels.
In order to simplify the regulatory requirements for achieving the
removal efficiencies for each of the constituents in Table 12, it is assumed
that the removal of total solids (TS) and the soluble metals (SM) with the
most stringent removal efficiency for a given level will concurrently meet
all the necessary requirements for that level. This assumption is considered
valid because the removal of TS to a specified level will also remove a
proportional amount of suspended solids (silica and metal silicates) and
dissolved solids (soluble metals, fluoride, etc.). Concurrently the removal
of SM with the most stringent removal efficiency generally will also remove
SM with less stringent requirements. The only exception is boron, which
cannot be effectively removed by any current control technology.
To achieve the three effluent levels, an average value of efficiency
was assigned to each of the treatment processes (Table 13). As the efficien-
cies of most treatment systems vary with the nature and flow conditions of
the waste and the engineering design of the treatment processes, these arbi-
trarily assigned efficiencies are not to be interpreted as definitive
80
-------
TABLE 10. ASSUMED GEOTHERMAL WASTE BRINE AND SURFACE
WATER DISCHARGE CONCENTRATIONS (mg/1)
Constituent
Total Solids
Iron
Manganese
Boron
Zinc
Barium
Fluoride
Lead
Copper
Arsenic
Mercury
Selenium
Chromium
Silver
Cadmium
Geothermal Waste Brine
Concentration Level
High Mid Low
100,000
1,000
1,000
500
500
500
100
100
50
10
10
0.1
10
1
1
10,000
100
10
10
10
10
1
1
1
1
0.1
0.05
0.1
0.1
0.1
2,000
10
1
1
1
1
0.1
0.1
0.1
0.1
0.01
0.01
0.01
0.01
0.01
Surface Water Discharge
Concentration level
High Mid Low
5,000
5.0
1.0
5.0
10
5.0
1.0
1.0
5.0
0.5
0.01
0.05
0.5
0.5
0.05
1,000
1.0
0.1
2.0
5.0
2.0
0.1
0.1
2.0
0.1
0.005
0.02
0.1
0.1
0.02
500
0.5
0.05
1.0
1.0
1.0
0.05
0.05
1.0
0.05
0.002
0.01
0.05
0.05
0.01
TABLE 11. GEOTHERMAL WASTE BRINE FLOW RATES AND
LEVELS FOR VARIOUS USES
Conversion System
Flow Rate
Liters/Min.
Brine Cone.
Levels
Direct Steam
Power Generation
Flashed Steam,
Binary, Total Flow
Power Generation
Direct Heating
Open fie Closed
Desalination
4,000-30,000
15,000-350,000
10-1,000
1,000-5,000
Mid & Low
High, Mid
& Low
Mid & Low
High & Mid
81
-------
TABLE 12. REMOVAL EFFICIENCIES (%) REQUIRED FOR TREATING
VARIOUS LEVELS OF RAW GEOTHERMAL FLUIDS
Constituent
Total Solids (TS)
Iron (Fe)
Manganese (Mn)
Boron (B)
Zinc (Zn)
Barium (Ba)
Fluoride (F)
Lead (Pb)
Copper (Cu)
Arsenic (As)
Mercury (Hg)
Selenium (Se)
Chromium (Cr)
Silver (Ag)
Cadmium (Cd)
High
1
95
99.5
99.9
99
98
99
99
99
90
95
99.9
50
95
50
95
Discharge Concentration Levels
Level Waste Mid Level Waste Low Level
2 3 123 12
99
99.
99.
99.
99
99.
99.
99.
96
99
99.
80
99
90
98
9
99
6
6
9
9
95
99
99
99
99
99
99
99
99
98
99
99
90
99
95
99
.5
.95
.995
.8
.8
.8
.95
.95
.5
.98
.5
50
95
90
50
0
50
0
0
0
50
90
0
0
0
50
90
99
99
80
50
80
90
90
0
90
95
60
0
0
80
95
99.5
99.5
90
90
90
95
95
0
95
98
80
50
50
90
0
50
0
0
0
0
0
0
0
0
0
0
0
0
0
50
90
90
0
0
0
0
0
0
0
50
0
0
0
0
Waste
3
75
95
95
0
0
0
50
50
0
50
80
0
0
0
0
TABLE 13. ASSIGNED EFFICIENCIES OF VARIOUS TREATMENT
SYSTEMS FOR REMOVING GROSS CONSTITUENTS
Efficiencies
Total Soluble
Solids Metals
Sedimentation
Chemical Precipitation
Filtration
Electrodialysis
Ion Exchange
Reverse Osmosis
Evaporation
30%
50%
85%
40%
85%
90%
99. <
5%
80%
85%
35%
90%
90%
95%
82
-------
efficiencies, but rather as an attempt to demonstrate the number of treatment
systems required for achieving each of the specified effluent levels.
Applications of control technologies for achieving the three effluent
level requirements from three levels of raw geothermal fluid are illustrated
in Figures 37, 38, and 39. These figures depict the treatment systems re-
quired for each of the specified effluent levels. Implicit in these illus-
trations are the following assumptions: (1) pretreatment systems such as
sedimentation, chemical precipitation, and filtration do not remove pollutants
(TS or SM) more than the assigned efficiencies regardless of the number of
identical process units utilized; (2) treatment systems such as reverse
osmosis, ion exchange, or electrodialysis can remove pollutants at greater
than the assigned efficiencies if a combination of unit stages is used, since
the removal efficiencies are cumulative; (3) the sequence of treatment proces-
ses are arranged in a way so that residual pollutants are readily removed to
their assigned efficiencies by succeeding unit processes; reversing the order
of the treatment process sequence will invalidate the assigned efficiencies;
and (4) alternative treatment systems may be developed to produce similar
removal efficiencies.
As an example, Figure 37 presents block diagrams of the various treat-
ment systems necessary for achieving the various effluent quality levels from
a high level waste. For level 1, the required removal efficiencies for both
TS and SM are shown immediately below the level 1 requirement. To achieve a
removal efficiency of 95% TS, it is necessary to have a sedimentation, a
chemical precipitation, a filtration, and a reverse osmosis unit. The per-
centage of TS removed from the system is depicted by the arrow pointing
downward from the specific unit process. The percentage of TS remaining is
shown by the arrow pointing to the right. Thus, 30% of TS is removed by
sedimentation with 70% remaining in the treated waste. Of the 70% TS remain-
ing, an additional 35% is removed by chemical precipitation. Effluent from
the chemical treatment thus contains 35% TS. Filtration then removes another
29-75% TS, and reverse osmosis removes an additional 4.725% TS. At the end
of this sequence of treatment, 99.47% TS removal efficiency is achieved and
only 0.525% TS remains in the treated effluent. A similar procedure can be
followed for SM. These flow diagrams show that the treatment requirements
for SM removal are always higher than or equal to those designed for TS
removal. It appears logical,'therefore, to assume that the effluent water
quality requirements for the three levels should be governed by SM removal
rather than TS removal for that level.
Wastewater Disposal Technologies
Geothermal wastewater requires disposal whether or not it requires prior
treatment. In general, the cleaner the wastewater to be disposed of, the
easier and less expensive the disposal method. For example, effluents that
meet water quality standards can simply be discharged to surface drainage.
On the other hand, it is more expensive and more difficult to dispose of
wastewater that does not meet such standards; it is these disposal methods
with which this discussion is most concerned. It should be borne in mind,
however, that these methods may also be used for reasons other than simply
83
-------
00
4>
HIGH LEVEL WASTE
(A) Level 1 Requireinent
T.S. « 95% removal; S.M. = 99.9% removal
r _, 'l
T.S. Sed
i n r D J5
"• C.P.
30% \ + 35% | +
S.M. Sed
* . r D ly
w.r ,
5% \ + 76% J +
(B) Level 2 Requirement
T.S. » 99% removal; S.M. =
. , . 7f" "*c
T.S. Sed
"- C.P.
30% | + 35% \ *
, . 9!
S.M. S«J
» r r n '-
5% | + 76% i H
% r rilt b'"A r c n ^0 505K
29.75%! + 4.725%! = 99. 475%
% » filt * ^ RO u...o.^ pQ _ 0,0?flS^
16.15%! + 2.565%! 0.2565%! = 99.97%
nn QQ¥
i <; ?i«
a» r-ilt 1 ^ R 0 ..- «. 0 ^75%
29.75%! + 4.725%! = 99.475%
» Filt ^Cj%fc po 0-8^ R ^ U.U.OD/^ p n tn.on?«M
16.15%! + 2.565%! + 0.2565% \ + 0.02565%! = |99.97%
(C) Level 3 Requirement
T.S. - 99.5% removal; S.M. = 99.995% removal
. ~.i-nt . r f*co> «• i"*™/
I S -j6u
UTS, f p ->
30% | + 35% !
9
S.M. Sed
5% |
Legend: T.S.
S.M.
Sed
C.P.
Filt
- R.O.
p ft '
t 76% !
3* . Filt J-<-J«'- p g u.jt^ R Q ^ 0 0525<¥
f 29.75%! + 4.725%! + 0.4725% = 99.95%
at ° n^T i 0 285^ i n n"nrf; i
r Filt » PO r RO °-0tDjV P" r n nn?R«
+ 16.15%| + 2.565% | + 0.2565%i + 0.2565%! = 99.997%
Total solids
Soluble metal with most stringent requirement
Sedimentation
Chemical precipitation
Filtration
Reverse osmosis
Figure 37. Application of treatment technologies for achieving
three effluent quality levels from high level waste.
-------
-LEVEL WASTE
(A) Level 1 Requirement
T.S. = 50% removal; S.M. = 95% removal
T.S.
S.M.
, , ... ,. /LI
Sed
30% | +
-• L or
1 95
Sed
A 1
r" U.P. 1
35% j
h 19/c
*" UP.
5% | + 76% 1 +
evel 2 Requirement
T.S. = 90% removal; S.M. =
T.S.
S.M.
rnrl
30% 1 +
rarl "-
oeu
/o JJ/c
35% | +
% r r r 1 l9*
r- UK |
5% J + 76% | +
evel 3 Requirement
T.S. = 95% removal; S.M. =
T.S.
S.M.
ccd /L
30% 1 +
Srd ^"
» i *
'° J r P •iD/£
35% I +
% _ r D ly%
76% | +
3b%
65% i
*" Filt "• 2.
16.15%! = 97-
99% removal
29.75 ! = 94.
ta r ; i -t- *- • ^DA- ^ r\
fc 1 1 1 1 *» K.
85%
1 5% | |
75% !
„ „,
U. U.i-oj/o
16.15%! + 2.565%! = 99.715%|
99.5%
» Tilt 5'25?b . P
29.75%| + 4.7
» Filt £•!"% p
16.15%! + 2.5
0 pr 0 525%
25%J = 99-475%)
0 »• 0 ''850''
65% ! = 99.715% |
Figure 38. Application of treatment technologies for achieving
three effluent quality levels from mid level waste.
-------
LOW LEVEL WASTE
(A) Level 1 Requirement
T.S. = 0 removal; S.M. = 50% removal
oo
Se
9b% ^ .
d ^ L.P.
5% f + 76% f
(B) Level 2 Requirement
T.S. = 50% removal; S.M. =
Se
d /u* L. r P
30% | + 35% J
Se
d yt>* » C P '
* iy%
81% |
90% removal
_ . •-. IK^
•** Joa
65% |
y* ^ nlt
5% ( + 76% { + 16.15%|
(C) Level 3 Requirement c
T.S. = 75% removal; S.M. = 95% removal
Se
, /UX . r p 3
b% ^ r . u
~ **• hilt
30% | + 35% | + 29.75%J
Se
d yb% - C P '
y% « mt
«• r i i t
5% | + 76% (+ 16.15%J
fr* 9 O K °/
97,1 5% j
— "• 5.^5%
94.75%j
— o pro/
•*• i:.ob^
97.15%j
Figure 39. Application of treatment technologies for achieving
three effluent quality levels from low level waste.
-------
disposal; for example, injection may be practiced for geothermal reservoir
conservation and subsidence prevention.
Subsurface Injection
Methodology - Successful subsurface injection tests have been performed
in a number of geothermal fields in the United States and abroad: for example,
The Geysers, East Mesa, Niland, and Heber fields in California; the Valles
Caldera field in New Mexico; the Matsukawa and Otake fields in Japan; the
Wairakei field in New Zealand; the Ahuachapan field in El Salvador, etc. In
The Geysers field, return of steam condensate to the geothermal reservoir by
injection was started in 1969; about eight billion gallons of condensate have
been injected to date. The current daily rate of injection is about 5 million
gallons. Besides geothermal, many other industries have adopted subsurface
injection of liquid wastes to preventing or control water pollution. The
practice is widespread in oil production fields. There are several reasons
for choosing subsurface injection as a disposal method. Some of these follow:
• Alternatives to injection are isolating the waste from the
surface environment and releasing the waste into surface water
bodies. Surface isolation of large quantities of liquid waste
generated by geothermal operation is difficult. In most cases,
before the liquid waste can be released into surface water bodies,
it will require costly treatment. Treatment will create secondary
wastes, also requiring disposal.
• Failure to replace reservoir fluid may allow ground subsidence.
Subsidence has been observed in the geothermal fields at Cerro
Prieto, Mexico, and Wairakai, New Zealand, where fluid reinjection
has not been practiced.
• If reservoir fluid is not replaced, the reservoir pressure may
decline, unless there is rapid and complete natural recharge.
Evidence of complete natural recharge is rare. Any decline in
reservoir pressure causes a decline in the productivity of the
production wells.
• Injected, cooled geothermal wastewater scavenges heat from the
reservoir rock matrix and may be withdrawn again at the production
wells. Injected steam condensate may be reproduced as steam.
Injection of geothermal waste into the producing formation allows a
higher recovery of heat stored in the reservoir.
• Injection into geothermal reservoirs is an effective means of
preventing not only chemical, but also thermal, pollution of surface
water bodies.
Subsurface injection, if the geothermal fluid is utilized in an open
system, will generally be preceded by settling in ponds or tanks to remove
suspended solids. Sometimes filters may be used for this purpose. The waste-
water might then require chemical or physical deaeration to reduce its
corrosiveness. Finally, it is injected into the geothermal reservoir through
87
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the injection well. Injection may sometimes be accomplished by gravity
alone, without the need for pumping the waste down the well, because of the
higher gravity head of the cooler, denser geothermal waste.
Old production wells may be converted to injection wells. However,
wells may be drilled solely for injection. Unless the geothermal reservoir
rock is very competent (structurally self-supporting), a cased hole with
slotted liner in the injection zone is used. Figure 40 is a schematic dia-
gram of a typical injection well at The Geysers.
BOTTOM 10 IN. COND. 30 FT. (9 m)
BOTTOM 20 IN. 225 FT. (69 m)
TOP SURPENTINE
TOP GREENSTONE
TOP GRAYWACKE
TOP 9 5/8 IN. 1646 FT. (502 m)
BOTTOM 13 3/8 IN. 1884 FT. (574 m)
BOTTOM 9 5/8 IN. 4062 FT. (1244 m)
S = STEAM
TOP 5 IN. LINER, 6703 FT. (2043 m]
- BOTTOM 7 IN.
BOTTOM 5 IN. LINER 8034 FT. (2448 m)
TD 8045 FT.
(2452 m)
Figure 40. Typical injection well set-up
The primary considerations in evaluating injection potential for a
geothermal reservoir are:
• selection of optimum sites;
88
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• cost of drilling and operating the wells compared to other
methods of disposal; and
• operational aspects such as the pressure required to inject at
a certain rate and the decline in injection rate with time.
The injection scheme should be designed to optimize the travel path and
time of flow between injection wells and producing wells, thus preventing
rapid cooling of the production water. At the same time, the water should be
injected sufficiently into the producing reservoir to minimize the decline in
reservoir pressure. The key factor in determining the optimum injection plan
is the spatial variation of water temperature and permeability in the reser-
voir.
Cooling and pressure decline around the injection wellbore may cause
formation plugging by the deposition of dissolved and suspended solids, and
thus increase resistance to injection. In order to maintain the injection
rate, pressure must then be increased. Increase in injection pressure in-
creases operating cost and mechanical problems. If the injection system
reaches its maximum pressure capacity, more injection wells may need to be
drilled, or the old wells stimulated, to maintain the total injection rate,
thus escalating costs. There is no simple way yet to estimate loss of in-
jectivity with time. The only sure means of assessing injection potential
is to inject continuously for an extended period, at least a few months, and
monitor wellhead injection pressure versus flow rate.
The geological suitability of the reservoir for injection has to be
investigated. The reservoir must have a relatively impermeable cap rock to
confine the waste from moving upward and polluting ground water aquifers. If
fracture zones or faults exist, they may allow upward movement of the waste
and consequent pollution.^8
Where injection causes the pore fluid pressure to exceed the hydrostatic
pressure for the area, seismic activity may be induced, if there are pre-
existing faults or major fracture zones near the injection zone. At Denver,
Colorado, earthquakes were apparently caused by subsurface injection of waste
from the Rocky Mountain Arsenal. However, earthquake activity has not yet
been linked to injection in any geothermal field. It appears that the possi-
bility of injection-induced earthquakes may be alleviated by minimizing the
difference between the injection pressure and the original pore pressure of
the reservoir fluids, particularly if there is a fault near the injection
area.
Injection wells should be completed carefully to isolate the injection
horizon from shallow, fresh water aquifers. Any abandoned well near an
injection well may provide a pathway for movement of the waste to shallow
fresh water aquifers.58 Inadequate cementing behind casings and/or corrosion
of liners can result in upward migration of water from geothermal reservoirs.
The efficiency of any injection operation depends to a great extent on
the physical, chemical, and thermodynamic characteristics and interrelation-
ships of the waste fluid, the reservoir fluids, and the reservoir rock.
89
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Various types of plugging of the porespaces around the injection well bore
may occur due to the interaction between the waste and the formation, and the
waste and the reservoir fluid. The problems of formation plugging, scaling
in the injection lines and well bore, and corrosion of pipes are essentially
chemical in nature.
Scaling and plugging may result from one or more of the following :-*y' u
(1) precipitation and polymerization of silica and silicates; (2) precipi-
tation of alkaline earths as insoluble carbonates, sulfates, and hydroxides;
(3) precipitation of heavy metals as sulfides; and (4) precipitation of redox
reaction products, e.g. iron compounds. Silica and calcium carbonate are the
principal materials likely to cause pipe scaling and formation plugging.
Surface pretreatment of the wastewater from geothermal operations may be
needed to ensure success of a subsurface disposal operation. Generally the
pretreatment would involve one or more of the following:^9
• storage in impervious impoundments to permit, under quiescent
conditions, settling and physical separation of the unwanted com-
ponents;
• corrosion control by proper pH control, deaeration, and use of
inhibitors;
• coagulation and clarification to accelerate gravity sedimentation;
• filtration and addition of bactericide to prevent plugging by
bacterial growth; and
• application of electric potential to reduce scaling.
One of the major problems in geothermal energy conversion and injection
systems is silica precipitation and scale formation. Monomeric silica in
solution will not precipitate nor adhere until it starts to polymerize.
Polymerization reduction can be achieved in several ways:61
• by maintaining a sufficiently high temperature to keep the
silica solubility above saturation;
• by reducing turbulence in order to avoid fluctuations in the
velocity gradients and collision of particles; and
• by lowering the pH of the solution: a reduction in pH below 6.5
causes a substantial decrease in polymerization.
i
Silica-laden discharge waters have been successfully treated with
slaked lime to precipitate silica and any arsenic, if present.44 xhe waste-
water in the Otake geothermal field in Japan is treated with slaked lime and
ponded for about one hour. Colloidal silica is formed, polymerization ceases,
precipitation and settling takes place, and the water can then be disposed
of."' Various scale inhibitors (polyelectrolytes, esters of phosphoric acid,
phosphonates, etc.) have been used to slow down the precipitation rate of
90
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calcium carbonate. A glassy phosphate called Calgon has been used as a scale
preventer as well as corrosion controller. Application of a negative electri-
cal potential has been found to reduce silica scaling of the Salton Sea
geothermal brines.^3
Although prevention of scaling can be achieved by treatment, it is also
possible to remove scale. Silica scale has been successfully removed from a
well-head in the Matsukawa field in Japan by allowing the scale to react with
concentrated NaOH.64 The scale was completely removed in 30 minutes, although
it was necessary to maintain a high temperature and pressure. Shock treatment,
subjecting the formation to an almost instantaneous applied pressure differ-
ential (implosion) and sustaining the differential temporarily, has been
reported to be successful in loosening the material plugging the injection
formation.^5
Geothermal steam condensate often has a significant amount of dissolved
H2S, which may create both scaling and corrosion. The H2S may be removed by
one of the technologies 'discussed earlier under Air Pollution.
Generally, high salinity accelerates electrical corrosion by increasing
the conductivity of the medium. Downhole corrosion rates are a function of
temperature, flow rate, well depth, pressure, brine chemistry, pH, and dis-
solved gases (such as C^, CG^, HnS and NH3). The most common types of corro-
sion damage to metals used in geothermal environments are (1) uniform attack
(ordinary rusting), (2) pitting, and (3) stress corrosion cracking.°
Experimental tests of corrosion in the Salton Sea geothermal field have
shown that corrosion is generally a problem below 300 meters and increases
in severity with depth; above 300 meters, silica scale apparently protects
the casing from corrosion. In several downhole tests, little corrosion was
observed because of the development of a so-called "hard scale", a friable
glassy (amorphous) material, formed as a thin film on the production lines.
The composition of the "hard scale" was primarily silica and iron oxide, with
some sulfide. Several tests also were done at The Geysers steam field.
Corrosion was found to have been caused by sulfuric acid formed by sulfation
of part of the l^S in the steam by oxidation. 67
\
Lowering the temperature usually decreases the corrosion rate. Increas-
ing fluid velocity generally increases corrosion attack, with exceptions such
as stainless steel. Very high velocities should be avoided where possible
because of erosion-corrosion effects. Removing oxygen or oxidizer is an old
corrosion-control technique, and may be accomplished by vacuum treatment,
inert gas sparging, or oxygen scavengers. Decreasing the concentration of
the corrosive and increasing pH (to control acidic conditions) may be effec-
tive.
Inhibitors may be used to retard corrosion. There are numerous inhibitor
types which can be classified according to their mechanism and composition:
(1) adsorption-type inhibitors—organic compounds which adsorb on the metal
surface; (2) hydrogen-evolution retardants; (3) scavengers such as sodium
sulfite, sulfur dioxide, sodium thiosulfate, and hydrazine, which remove
91
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dissolved oxygen from aqueous solutions; (4) oxidizers; and (5) vapor-phase
inhibitors. Inhibitors may, in themselves, be significant pollutants.
Use of alloys does not stop corrosion. It must be remembered that when
an alloy or other noble metal is used, any less noble metal directly coupled
to it will be sacrificed to corrosion (cathodic protection). Corrosion can
be inhibited by couplings of inert materials, such as plastics. Some alloys
are more corrosion-resistant than others. For example stainless steels with
a chrome content higher than 10% is generally recommended.6°
Protective coatings may be used to retard corrosion. With any protective
coating, however, the protection it affords is directly proportional to the
continuity of the coating. The most common coatings are cement, plastic,
tar, and epoxy, including teflons. Also, controlled sodium silicate and
calcium carbonate scale and glassy phosphates have been used as protective
coating materials.
Injection Well Cost Estimates - Capital costs for injection include the
costs for drilling, casing and cementing, logging, perforation, well head
equipment (including pumps and piping), control systems, and engineering
supervision. Operation and maintenance costs consist of expenditures for the
operation and routine maintenance of well head equipment, piping, and pumps.
Factors affecting the capital cost of an injection system include hole
and pipe diameters, the pumping system required, depth of wells, number of
wells, and the hydrology and geology of the site.
The variation of cost per well with well diameter is shown in Figure 41.
Pump cost may vary by over 100% per well, depending on the rating and material
requirements.
For a given geologic formation, the cost for drilling an injection well
increases with depth. The relationships between drilling cost and well depth
and lithology have not been clearly established for geotherinal applications.
Based on one study, the injection well drilling costs for sedimentary lithol-
ogy vary between $150 and $300 per meter depth in 1976 dollars.69 The capital
cost of drilling and injection in volcanic formations may be 60 to 70 percent
higher than in sedimentary formations.
The flow capacity per well determines the number of wells that must be
drilled at the site. At a given site the flow capacity depends upon aquifer
formation constants that describe the permeability, thickness, and storage
capacity of the aquifer. These constants vary markedly from site to site,
and, thus far, have been determined at each existing site by pumping tests
prior to construction of the injection system.
Because of the wide variations in site specific geology and hydrology,
and a lack of complete data characterizing existing wells, injection well
cost data have not been usefully parameterized. In the absence of such cost
data, the capital cost of injection wells was derived by a simplistic approach
involving the selection of a representative well cost using empirical cost
data for actual wells. This representative cost was then used to develop
92
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WJ
o
u
1.4
1.3
1.2
1.1
1.0
J_
8 9 10
HOLE SIZE (INCHES DIAMETER)
11
12
Figure 41. Well hole size cost comparison (capital cost only)
total costs for multiple well systems capable of receiving various wastewater
flow rates generated by the four energy conversion processes. The total cost
of the well system was also estimated for four selected well capacities
representative of existing wells.
Injection well cost data surveyed indicates that the capital investment
for an injection well varies from $400,000 to $1,000,000. The individual
construction costs also vary widely. The average capital cost of an injection
well was taken as $500,000.
The well depth associated with the selected cost data varies from 3,000
to 10,000 feet (914-3,048 m), averaging about 6,000 feet (1,828 m).
The flow capacity selected for a well is based on inspection of the
results of a 1971 survey of facilities using injection well systems to dis-
pose of liquid.70 At that time, 82% of the injection wells were at refiner-
ies, chemical plants, and steel mills. The survey shows that the potential
flow for an aquifer can be quite high (16,000 1pm), although the median (512
1pm) indicates that the bias of the survey data is definitely in favor of the
lower flows. On the basis of the results of a 1970 survey70 of 75 injection
facilities, four well capacities have been selected for cost analysis: 200,
1000, 4000, and 8000 1pm.
93
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The calculation of capital cost of various multiple well systems which
achieve the expected geothermal wastewater generation rates (up to 350,000
1pm) is shown in Table 14. The total capital cost is determined from the
number of wells required to achieve the required disposal flow rate. Total
capital cost is then amortized over a 30 year period at an 8% interest rate.
Replacement of equipment is considered negligible compared to drilling costs.
The demand factor has been assumed to be 80% (i.e., the system is not opera-
ting 20% of the time).
The annualized costs for the multiple injection well systems are shown
in Figure 42, normalized to each 1000 liters of wastewater flow. Four curves
are shown, each representing an injection well system utilizing one of the
selected capacities. Clearly, the injection system consisting of larger
wells is more economical, since fewer wells must be drilled to accomplish the
required disposal rate. However, some caution should be exercised in apply-
ing the data of Figure 42. The plots are predicated on the assumption that
capital cost of a well is invariant regardless of its capacity. Actually,
wells of different capacities, all other site parameters being equal, may use
different pumps, different pump injection pressure, or a different hole size.
If a different hole size is used to accomplish additional flow capacity, such
as from 4000 to 8000 1pm, the relative cost of the larger diameter well would
be about 1.2 times that of the smaller well. Still, the cost information
developed in Figure 42 is useful to establish preliminary cost estimates and
to judge feasibility of multiple well injection systems. For example, it can
be seen that the total annualized capital cost of injecting high flow
levels of geothermal wastewater from flashed steam plants is relatively low
compared to other environmentally acceptable disposal methods.
The operating cost for an injection system will consist mostly of the
energy cost for pumping. Routine labor costs will be negligible, and main-
tenance costs over a thirty-year period will depend primarily on the appli-
cation and service required. In many cases, repair costs will be almost
zero, while in others, anticipated maintenance or repair (due to corrosion,
plugging, or wear) will prohibit the use of injection entirely. For the
purpose of costing, it is assumed that 0.5% of the capital investment is
annual maintenance costs. This corresponds to $2,500 per well. Depending on
the flow temperature and the operating pressure of the injection well, the
maintenance costs may vary somewhat.
Energy costs for pumping, in cents per thousand liters, are independent
of flow rate, but are instead, a function of the pressure requirement for the
particular injection system. This pressure requirement depends on frictional
losses in the tubing, elevation changes for the pumped fluid, and the hydro-
logic pressure requirement (that is, the pressure required to push the waste
liquid into the injection aquifer). '
Frictional losses in the well tubing area are usually negligible. For a
flow rate of 8000 1pm, the losses are 1.3 psi per 100 feet of tubing. On
the other hand, the pressure gain due to the elevation head of the waste is
42 psi per 100 feet (9.37 at m/lOOm) vertical depth (assuming the waste brine
has the density equal to that of water at 100°C). The hydrologic pressure
requirement (that is, the pressure required to push the waste liquid into the
94
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TABLE 14. CAPITAL COSTS FOR INJECTION SYSTEMS AT FOUR WELL CAPACITIES
Well Capacity: 200 Ipm/well Well Capacity: 1000 Ipm/well Well Capacity: 4000 Ipm/well Well Capacity: 8000 Ipm/well
Annualized Annualized Annualized Annual i^fed
Flow No. Wells Initial Cost Per No. Wells Initial Cost Per No. Wells Initial Cost Per No. Hells Initial Cost Per
Req'd Capital Unit of Req'd Capital Unit of Req'd Capital Unit of Req'd Capital Ur.it of
Cost Flowb Cost Flowb Cost Flowb Cost Flowb
(liters/ ($106) ($/1000JO ($/10002) ($106) ($/1000i)
min.)
10 1 0.5 10.60
100 0.5 1.06
500 2 1.0 0.42
1000 5 2.5 0.53
4000 20 10. 0.53
5000 25a 12/5 0.53
10,000
15,000
30,000
50,000
100,000
350,000
1 0.5 1.06
1 0.5 0.212
1 0.5 0.106 1
4 2.0 0.106 1
5 2.5 0.106 2
10 5.0 0.106 3
15 7.5 0.106 4
30a 15. 0.106 8
13
25a
($106)
0.5
0.5
1.0
1.5
2.0
4.0
6.5
12.5
($/ioooa)
0.106
0.0264
0.0422
0.0316
0.0281
0.0281
0.0274
0.0264
1
1
2
2
4
7
13
44
($106)
0.5
0.5
1.0
1.0
2.0
3.5
6.5
22 .
($/1000i)
0.0264
0.0211
0.0211
0.0141
0.0141
O.Ol-.S
0.0137
0.0133
a. Arbitrary limit
b. Total cost ie annualized based on C = P(CSF), where I -
interest and 30 year period. The demand factor for the
total coat and CRF is capital recovery factor at 8%
well is assumed to be 80%.
-------
10
1.0
o
o
o
.10
200 1/min EACH WELL
1000 1/min EACH WELL
4000 1/min EACH WELL
8000 1/min EACH WELL
I
.01
1.0x10 1.0X102 l.OxlO3 l.OxlO4 1.0X105 1.0x10*
WASTE FLUID FLOW RATE (l/min)
Figure 42. Annualized capital cost for injection of geothermal wastewaters.
injection aquifer) is considered the strongest determinant for pumping energy
because of high variabilities in pressure differences.
Table 15 shows the expected energy cost for pumping at various values
for the pressure requirement. These pressure values are representative of
anticipated requirements, based on surveys of existing injection facilities.
In some cases, the initial pressure requirement may be zero because of injec-
tion aquifer conditions and/or the pressure gain in the well tubing. However,
a pump should still be included in the design to allow for eventual increases
in pressure requirements. Pressure requirements can change because permeabil-
ity of the stratum can change as solids are filtered fron the injected waste.
Ocean Disposal
Methodology - The disposal of spent geothermal fluids to ocean waters
may be an acceptable alternative in some cases since the most common consti-
tuent in geothermal brine is sodium chloride. However, if the geothermal
waste significantly increases the salinity or toxicity in the area of the
outfall, it will not be acceptable without appropriate prior treatment.
Ocean disposal of spent geothermal fluids would, in principle, be an
uncomplicated operation. It involves the conveyance of the liquid, probably
by a pipeline, from the geothermal operation to the shore and thence through
96
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TABLE 15. OPERATING ENERGY COST FOR INJECTION PUMPS
Pressure Requirement Cost
(psi) (cents/1000 1)
50
100
200
500
1000
1500
2000
4000
0.714
1.43
2.86
7.14
14.3
21.4
28.6
57.2
a pipe laid on or in the ocean bottom to some distance offshore. At the
outfall the wastewater may be released in a simple stream or jetted through a
manifold or multiple port diffuser. The diffuser facilitates the mixing of
wastewater with sea water, both upward and laterally, thus causing rapid
dilution.
Because of the large volumes of geothermal waters that will generally be
used per unit of energy extracted, pipelines would be large - perhaps one
meter or larger in diameter.
Ocean Disposal Costs - The technical and economic advantages associated
with ocean disposal of wastewaters have been diminished greatly in recent
years as a result of new and more stringent pollution standards.
In addition to costly pretreatment requirements, costs of conveyance and
ocean disposal of geothermal plant wastewaters from sites at least 200 miles
(322 km) from the ocean are exorbitant. Approximate costs for conveyance and
ocean disposal of wastewaters may be obtained from compilations of existing
cost data such as those prepared for the San Francisco Bay and Sacramento-San
Joaquin Delta Area Wastewater Management Survey Report.71 Costs are based
upon open country routing, pre-cast pipe foundations, land costs of $3000/acre,
and assumed life of 50 years. Further assumptions are an elevation head
between 40 and 100 feet (12-30m), head loss of 1.5 feet per 1000 feet (1.5m/
1000m), pump efficiency of 72%, and pump life of 30 years. Costs also include
ocean outfall at a depth of 200 feet (61m) with a diffuser; they do not
include the cost of any required wastewater pretreatment. Gross estimates -
are thus provided, in Table 16, for ocean disposal at various flow rates.
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TABLE 16. COST OF OCEAN DISPOSAL OF GEOTHERMAL WASTEWATERS
Wastewater Annualized Cost of Annual Cost Annualized
Flow 1/min Conveyance Lines3 of Pumping^ Outfall Costc Total Cost
1,000
5,000
10,000
100,000
350,000
8,000,000
11,800,000
13,300,000
22,200,000
35,000,000
972,000
3,880,000
6,920,000
48,500,000
136,000,000
18,450,000
29,500,000
54,200,000
87,400,000
113,800,000
27,422,000
45,180,000
74,420,000
158,100,000
284,800,000
aThe cost of conveyance is based on an assumed open country routing of 200
miles.
bit is assumed that wastewater is pumped through an elevation gain of 100 feet.
CAn offshore outfall distance of 1 mile is assumed. The outfall cost is the
sum of the annualized costs for the outfall line and the diffuser.
Evaporation Ponds
Methodology - Where large land areas are available, evaporation ponds
could provide a very simple approach to geothermal wastewater disposal.
Evaporation ponds are more practical in arid regions where evaporation losses
may reach 60 to 100 inches per year (150 to 250 cm/yr).
Construction of evaporation ponds involves excavation and/or diking,
depending upon the topography of the area. In some cases, natural depressions
may be utilized. In a few instances, it may be possible to enhance natural
salt marshes as a wildlife habitat, principally by providing a constant water
supply. It is not expected that evaporation ponds would normally have a
surface drainage outlet.
Unless the soil is impermeable, evaporation ponds must be lined to
prevent ground water pollution. Types of liners include clay, rubber,
asphalt, concrete, and plastics.
Table 17 shows the expected water surface area required for evaporation
ponds accepting wastewaters from the various geothermal energy conversion
processes. The flow approximations represent the median of the range of
wastewater production rates associated with the various processes.
Costs of Evaporation Ponds - Cost of evaporation ponds are related to
various dependent factors in a recent study conducted for the Environmental
Protection Agency.72 The data apply to average situations in the United
States, and have been based on actual costs of projects over a wide geographic
area, including varied construction conditions. The cost estimates developed
in the study are representative of national average price levels as of January
1971.
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TABLE 17. ESTIMATED WATER SURFACE AREA REQUIRED
FOR DISPOSAL OF GEOTHERMAL WASTEWATERS
Geothermal Median Water Surface
Conversion System Wastewater Rate, 1/min Area, Acres3
Direct steam 17,000 1,450
power generation
Flashed steam, 80,000 5,335
binary, total flow
power generation
Direct heating 500 43
open and closed
systems
Desalination ' 3,000 257
aThis is the amount of surface area required to maintain level of evaporation
ponds at steady state. The required area is estimated by A = Q/E, where A =
area required, Q = wastewater generation rate, and E - evaporation rate. It
is assumed that losses through the pond liner are neglibible.
The total capital investment cost includes the costs of construction,
pond liner, embankmant protection, engineering, land, and administrative
requirements. The total operating and maintenance cost includes the costs of
materials, supplies and labor. An estimate of total annual costs versus size
of the evaporation pond is provided in Figure 43. Variations in these costs
are to be expected with variations in the controlling factors.
Land Spreading
Methodology - Land spreading is a treatment method that relies primarily
on biodegradation of the waste constituents. Inorganic wastes, such as those
found in geothermal wastewaters, may not be suitable for land application.
Significant concentrations of'heavy metals would accumulate in the soil,
posing threats to plant and animal life, and surface and ground water uses.
The hazards of disposing of non-biodegradable materials on land are causing
increasing concern, and regulations are becoming more restrictive.
Spraying on irrigable land, wooded areas, and hillsides has been used
primarily for the disposal of municipal wastes. Treated effluents have been
used for golf course and park watering. The amount of wastewater that can be
disposed of by spraying depends largely on the climatic conditions, the
infiltration capacity of the soil, the types of crops or grasses grown, and
the quality standards imposed where runoff is allowed.
In general, spraying systems may be classified as either low rate or
h-foH rate svstems. Low rate systems utilize wastewater application rates of
Jp|?oximitl!| 2 ?o 10 ft7yr, (6.6-3m/yr) whereas high rate systems achieve
application rates of 150 to 350 ft/yr (45-107m/yr).
99
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100,000
10,000
o
Q
z 1,000
o
o
u
z
z
100
10
1
TOTAL
ANNUAL
COST
^
ANNUALIZED
CAPITAL
INVESTMENT
^
^
JS
^
^
s
JS
sy
OPERATING AND
MAINTENANCE
COST
I
10 100 1,000 10,000 100,000
WATER SURFACE AREA, ACRES
Figure A3. Total annual cost of evaporation ponds versus surface area.
Low rate systems are segmented into two types of application systems.
Spray irrigation is defined as the controlled spraying of liquid onto the
land at a rate measured in inches per week, with the flow path of the liquid
being infiltration and percolation through the soil. Overland runoff is
defined as the controlled discharge (by spraying or other means) of liquid
onto the land at a rate measured in inches per week, with the flow path of
the liquid being downslope across the land.
High rate systems consist of rapid infiltration, which is defined as the
controlled discharge of liquid onto the land at a rate measured in feet per
week, with the flow path being high rate infiltration and percolation through
the soil.
100
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The land area required for wastewater effluent disposal depends on the
loading rate used. The loading rate in turn depends on many factors in-
cluding:
• the soil capacity for infiltration and percolation;
• hydraulic conductivity (percolation capacity) of the root zone
of cover vegetation;
• evapotranspiration capacity of site vegetation; and
• assimilation by soil and vegetation of nitrogen, phosphorus,
suspended solids, BOD, heavy metals, and pathogenic organisms.
The maximum hydraulic loadings of wastewater for various soil textures
is shown in Table 18.
TABLE 18. ESTIMATED MAXIMUM HYDRAULIC LOADING OF WASTEWATER EFFLUENT
FOR VARIOUS SOIL TESTURES (IDEAL CONDITIONS)
Movement Through the Soil Root Zone*
cm/day cm/yr
Fine sand 38.1 762
Sandy loara 19.0 457
Silt loam 8.9 229
Clay loam 3.8 102
Clay 1.3 25.4
*Precipitation plus effluent less evapotranspiration~~
The infiltration capacity of the soil limits the rate at which water can
be applied to an area without runoff. Steeper slopes, previous erosion, and
lack of dense vegetative cover also reduce the infiltration capacity and
necessitate a corresponding reduction in application rates.
The hydraulic conductivity of the soil in a vertical direction deter-
mines the total precipitation and effluent application that can be trans-
mitted to the ground water. Increased precipitation in a wet year reduces
the amount of effluent which can be applied to various soil textures under
ideal conditions.
Costs - The major advantage with wastewater land spreading is the low
cost of the approach. Table 19 shows the total annualized cost of land
spraying for the range of geothermal fluid flows anticipated. Capital
investment costs and operating costs are based on an overland flow waste
treatment system at Paris, Texas.73 The system reported total construction
costs at $1170 per acre and operating costs at $.052 per 1000 gallons
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($.014/1000 1) of wastewater. Application rate was a relatively high 0.6
inches (1.5 cm) per day. Compared to other land application methods (e.g.,
evaporation ponds), the cost for disposal of geothermal wastewaters is rela-
tively low using the land spreading technique. However, a major disadvantage
to this approach is that which confronts all land application approaches;
namely, the vast amount of land required. For example, a typical size geo-
thermal plant (e.g., 100,000 1/min) would require 5 square miles of land
designated for waste disposal.
TABLE 19. ANNUAL COST OF DISPOSAL OF GEOTHERMAL
WASTEWATERS BY LAND SPREADING
1/min
1,000
10,000
100,000
350,000
Land
Surface
Area
Required,3
Acres
23.4
234
2,340
8,200
Capital
Investment,@
$1170/acre
27,400
274,000
2,740,000
9,600,000
Annualized
Capital Cost
30 Years
Life
2,440
24,400
244,000
855,000
Operating
Cost
@$.052/
1000 gal.
($.014/10004)
7,200
72,000
720,000
2,520,000
Total
Annual
Cost, $
9,640
96,400
964,000
3,375,000
aBased on application rate of .6 inches/day, (1.5 cm/day).
Containment of Unplanned Releases (Spills)
Methodology - Geothermal energy conversion systems will generally include
the distribution of large volumes of geothermal fluids through a dispersed
well and pipeline system. The possibility of system ruptures should be
anticipated, and surface containment should be provided at points of high
risk. Containment can include impermeable diking and/or excavation of
areas large enough to contain the potential flow until the flow can be stopped.
Containment involes the routing of spills to a nearby holding basin,
similar in design to an evaporation pond. Factors which will affect the
design of the holding basin include: the availability of nearby land, the
permeability of the soil and the ability of the environment to accept the
spill without adverse effect, the presence of other lagoons or ponds already
serving the plant, site topography, and geology. Generally, a holding basin
will require construction to depths of 10 to 15 feet by forming an embankment
with earth moving equipment.
Costs - The cost for construction of holding basins may be estimated
using cost data for aerated stabilization ponds similar in design. ^ The
costs shown in Figure 44 are derived from these data. Costs are shown for
surface containment ponds suitable to manage unplanned releases of geothermal
fluids at various flows and durations. The surface area requirements for the
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specified flow ranges (10 to 350,000 1/min.) vary from 12 square feet (1.1 m2)
to 41 acres depending on the duration of the spill.
100
o
o
o
O
LU
N
•z.
z
10
T
12
1
1000
24 HOUR SPILL
HOUR SPILL
6 HOUR SPILL
10,000
100,000
FLOW RATE, 1/MIN
Figure 44. Annualized invetment cost of spill containment ponds (10 foot depth)
SOLID WASTE DISPOSAL
In contrast to air and water treatment technologies with a diversity of
options, solid waste disposal techniques are generally prescribed by regula-
tions. The regulations usually require burial in a dry environment above and
impermeably separated from the water table. Infiltration of runoff water
must be prevented or confined. Clay, shale, or other low permeability forma-
tions around the disposal site cannot always be taken as a guarantee against
infiltration and consequent leaching. If any parts of the waste are soluble
and leaching does occur, the le'achate must be confined and treated just as a
liquid waste of similar composition. Solid wastes containing significant
amounts of heavy metals and other substances considered "hazardous waste" are
subject to special disposal regulations that may add to the disposal cost.
Treatment of geothermal wastes, particularly for removal of waterborne
constituents, can produce very large quantities of sludge, including hazard-
ous materials, depending of course upon the original concentration and the
percentage removed. Materials added to facilitate treatment, particularly if
not regenerated, can add substantially to the sludge quantity. Hydrogen
sulfide removal from power generating facilities may typically generate
several hundred metric tons of sludge per day. Removal of dissolved solids
from high-salinity fluids may produce hundreds of thousands of metric tons
per day.
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The cost for disposal of hazardous waste in an appropriate landfill
varies from $8 to $12 per ton of waste. This rate is independent of quantity
accepted, although reduced rates up to 25% are available when disposal can be
expected on a repetitive and high volume basis.^ Normally, the greatest
cost associated with waste disposal at a landfill is the hauling expenditure.
Typical hauling rates are approximately $32 per hour for a truck having a
capacity of 20-25 metric tons. Hauling time consists of about 2 hours load-
ing and unloading plus actual road-trip travel time. When hauling is to be
conducted on a repetitive and high volume basis, charges to the user may be
reduced by 10 to 25%.7^
It is estimated that the cost of sludge disposal would be $21.40 per
metric ton under the following conditions: hauling distance is 200 miles
(322 km); disposal cost is $10 per metric ton; and the cost of hauling is
$224 per truckload of 20 metric tons. Based on these costs, waste solids
disposal from a high-salinity system, in which dissolved solids must be
removed, would be prohibitive in most cases, and would be a very significant
cost in any case. The disposal costs assumed here do not include the costs
of sludge dewatering. The degree of dewatering required would depend on the
economic tradeoff between wet transportation and drying before transport.
NOISE CONTROL
Noise from geothermal operations, as discussed previously, can be severe.
Abatement technologies include prevention, shielding, and attenuation.75
The greatest sources of noise are the escape of air during compressed
air drilling, and the direct escape of raw geothermal fluid at wellheads,
separators, and vents in the fluid distribution system. Secondary sources,
such as those associated with a steam turbine generation plant and cooling
tower, are significant, but are of far less off-site environmental signifi-
cance.
A variety of silencers have been designed to attenuate noise from
escaping air and fluid. They range from relatively crude rock-filled cham-
bers, to baffled sound-absorbent mufflers, to large twin-cylinder centrifugal
expansion towers. Two examples are shown in Figures 45 and 46. The type
needed will depend upon the volume and nature of the escaping medium. For
example, the large centrifugal type has generally been used for flashed-
separated brine, whereas the smaller sound-absorbent type has been used for
steam venting. At the wellhead, air or steam venting may be into a rock and
water-filled pit. Most techniques are effective, but leave much room for
improvement. Noise levels as high as 140 dB are typically reduced to 100 dB
or less, by methods not necessarily expensive or complex. Attenuation can
often be very effectively accomplished with very simple designs.
Noise from machinery operation can be reduced by applying state-of-the-
art techniques such as shielding, baffling, vibration dampening, proper
alingment, adequate lubrication, and other techniques, or by developing new
technology.
104,
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Noise from permanent facilities can often be dampened by judicious
placement, taking advantage of the absorbent properties of topography and
various types of vegetation.
The costs of reducing noise are comparatively low, and in most cases,
will not be significant in total operational costs.
Figure ,45. Typical multi-chamber silencer.
STEAM EXHAUST
BORE DISCHARGE
APPROX.
GROUND LEVEL
PIPE JOINT
DRAINS
WATER OUTLET
Figure 46.
Twin-cylinder centrifugal expansion muffler
for large volume fluid wasting. (Ref. 76)
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VII. SUGGESTED POLLUTANT DISCHARGE LIMITS
GENERAL
The principal intent of this document is to provide pollution control
guidance by way of suggested pollutant emission and discharge limitations,
based upon an analysis of available data as presented herein. It must be
emphasized again that the suggested limitations are not definitive, nor can
they be until the character of the geothermal industry and associated technol-
ogy is more firmly established with an adequate operational data base, in-
cluding costs. Furthermore, health and environmental effects of many of the
pollutants have not yet been adequately investigated. Such investigations
will also have an impact on future limitations, most likely toward tightening
of restrictions.
AIR POLLUTANT LIMITATIONS
Hydrogen Sulf ide
Hydrogen sulfide is the only air pollutant from geothermal operations for
which there is sufficient information to suggest emission limits. Several
factors must be considered; these include existing ambient standards, health
effects, range of concentrations in steam, and control technology.
Federal ambient air quality criteria do not include H£S . California has
imposed a State ambient standard of 0.03 ppm by volume as a 1-hour average,
applicable state-wide. This state standard has had a profound effect at The
Geysers in forcing control technology development. Not widely known is the
fact that New Mexico has a standard of 0.003 ppm, one-tenth the concentration
allowed in California. These state standards are based upon odor nuisance
rather than health effects. The odor threshold is near 0.03 ppm.
As indicated in Section V, Table 8, I^S at less than 1 ppm can have
undesirable effects, although apparently it is not known to be a significant
health hazard at that level. The current Occupational Safety and Health
Administration regulations list an acceptable ceiling concentration of 2C) ppm
without respirabory protection.
According to the control technology information given in Section IV,
about 90% H2S removal is the most that can be expected from geothermal fluids,
using available control processes. In the case of The Geysers this would be
an emission average of 20 to 30 ppm, on a weight basis, of the total steam
produced. This, of course, is not directly translated to an emission concen-
tration, i.e., as an extreme, treatment of a stream of 100% H2S might still
106
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result in an emission of 100% H2S, although the amount might be only one-tenth
as much.
Emission limits must thus be in weight per unit of time, per unit of
production, or per unit of raw fluid used. In geothermal electric production
the obvious units are megawatt-hours or kilowatt-hours. If electricity pro-
duction at The Geysers is taken as 80% of the 502 MW capacity, it produces an
average of about 400 MW. If a produced H2S rate of 812 kg/hr (1788 Ib/hr) is
assumed, then the raw load is about 2 kg/MWH, including pre-plant losses.
Ninety percent reduction would result in an emission rate of 0.2 kg/MWH. Such
a limitation assumes total t^S control, from the wellhead through the power
plant.
Emission and ambient concentrations are related but are not definitely
correlatable. Calculating an emission rate based strictly upon an ambient
standard at the property line or some other point is not possible now and
would certainly be site-specific.
Based upon the assumptions that (1) The Geysers situation is typical with
respect to hydrogen sulfide raw loadings, (2) 90% removal can be economically
accomplished, and (3) adverse environmental effects will not occur with this
degree of removal, it is suggested that emissions be limited to 10% of the
loading in the raw geothermal fluid. Assuming that raw loadings will range up
to twice those at The Geysers, it is expected that such a limit will be equiv-
alent to an average between 0.2 and 0.4 kg/MWH of normal power generation
(rated capacity X plant factor). For perspective, these figures, for a 100 MW
capacity plant, translate to 16 to 32 kg/hr. Facilities producing raw loads
less than 0.2 kg/MWH of normal power generation probably will not require
treatment.
For non-electric uses, where H~S may require control, loadings may be
based upon raw fluid used as steam. Limits, comparable to those suggested for
power generation, are suggested to be within the range of 20 to 40 kg/10° kg
steam used.
It is expected that environmental damage from hydrogen sulfide will not
occur if the suggested limits are met. The ambient air limit at The.Geysers
is 0.03 ppm and is apparently met most of the time without treatment. Con-
sistent 90% reduction should eliminate violations, particularly if individual
sources remain dispersed.
Other Noncondensible Gases
Limitations are not suggested in this document for other noncondensible
gases and metal vapors because as yet they have not been of proven concern,
removal technologies have not been described, and effects have not been shown.
WATER POLLUTANT LIMITATIONS
By far the greatest volume of water in geothermal operations will be
spent water variously contaminated by natural constituents from the geothermal
reservoir. If the reservoir is dry steam-dominated, such as at The Geysers,
107
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the liquid will be principally condensate, relatively clean and low in volume.
However, dry steam reservoirs are rare; the great bulk of useful geothermal
energy will be derived from water-dominated reservoirs. From these, large
volumes of water will be withdrawn.
In suggesting pollutant limitations, the potential uses of geothermal
energy are categorized into electric power generation and non-electric uses.
The greatest rates of geothermal fluid withdrawal will be for power genera-
tion, where the fluids are also likely to be the hottest and the most con-
taminated. Non-electric applications, while they may be more numerous, will
probably use lower temperature waters of lower chemical content.
Electric Power Generation
Two kinds of waste water will, in most cases, result from electric power
generation. One is the residual water left after flashing or otherwise
extracting the heat. The second type is cooling water and condensate. The
cooling water may be from an external source; however, in most cases it is
likely to be condensate recycled through cooling towers. In the latter case,
the waste would be excess condensate and blowdown.
Residual geothermal liquid may contain heat and chemical constituents in
quantities unacceptable for direct discharge to fresh waters. In a few cases,
direct discharge to the ocean may be feasible where the waste characteristics
are similar to sea water. Otherwise, treatment would be required for surface
water discharges.
Alternative treatment technologies for geothermal brines were discussed
in Section VI. They include evaporation ponds, forced evaporation and dis-
tillation, membrane filtration, and ion exchange. Except for totally con-
tained evaporation ponds, which are taken to dryness, each of these techno-
logies creates an even more concentrated brine residual that must be disposed
of. At present, it does not appear that most of these technologies will be
feasible for large volume treatment. Evaporation ponds may be, but very large
areas would be required.
Subsurface injection of spent geothermal liquid to the producing reser-
voir now appears to be the most feasible disposal alternative. Because it has
been demonstrated, and because it is considered necessary to minimize reser-
voir depletion and subsidence, injection is recommended.
Injection of excess condensate is also feasible and is recommended. It
can be injected along with, and may in fact facilitate by dilution, spent
brine injection. ,
The suggested maximum limitation therefore, for spent brine and cooling
water from geothermal electric power generation, is no discharge to surface
waters except where the discharge quality is equivalent to or exceeds that
defined by receiving water quality standards for chemical constituents and
radioactivity.
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The no discharge limitation foresees subsurface injection in most
cases. Thus, limitations must be established, in turn, for injection. Since
it has the potential for contamination of ground waters used for other pur-
poses, it is suggested that no change be allowed in the chemical or physical
properties of waters outside the geothermal reservoir as a result of injection.
This means injection in most cases to or below the geothermal reservoir.
Ponding capability should be provided for containment of potential unplanned
releases due to system failure.
Geopressured geothermal systems may not feasibly allow reinjection to
the geothermal reservoir. In these cases injection to otherwise unusable
saline aquifers at shallower levels may be allowed.
Non-electric Uses
Non-electric uses of geothermal energy, such as space heating, crop
drying, soil heating, and spas, are expected to utilize relatively low-
temperature sources since they do not require the high temperatures needed by
thermodynamic cycles to obtain reasonable efficiencies. Low-temperature
geothermal fluids are characteristically lower in chemical content. In many
cases, they may be of lower salinity than surface waters in the vicinity. In
fact, clean raw water may be required, especially in domestic uses where it
has the potential to come into direct contact with the user.
Spent geothermal water after non-electric uses may often be directly
discharged to surface waters without treatment. Cooling is part of the
utilization process, so that additional cooling prior to discharge will
probably not be required. Injection to the reservoir is recommended where
surface water quality standards would be violated, or where the water may
contain trace metals that might cause adverse effects (i.e., any heavy metal
in concentrations above 1 mg/1 is likely to cause concern). The need to
inject to prevent depletion may not be required in most low-salinity reser-
voirs because they often may be sufficiently recharged by surface water
percolation.
Where injection is carried out, prevention of ground water contamination
is especially important, in some cases even within the geothermal reservoir.
This is because the reservoir itself may be a source of potable water.
Suggested upper limits for surface water discharges from non-electric
uses are equivalent to receiving water quality standards.
Sanitary Wastes and Construction Wastes
These wastes are typical of most industrial activities, including
geothermal, and are subject to established sewage treatment and water quality
standards attainable by conventional treatment technologies such as bio-
oxidation and sedimentation. These technologies are routinely capable, if
well-operated, of removing 90% of the raw pollutants.
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LAND-DISPOSED WASTE LIMITATIONS
As discussed earlier, solid wastes are already subject to state regula-
tion. Regulation is likely to soon become more restrictive under the newly
enacted federal Resource Conservation and Recovery Act, particularly with
respect to land-disposed toxic and hazardous materials.
Regulation of land-disposed waste generators, transporters, and disposal
facilities may prescribe control methods that must be used. These methods
will be applicable to geothermal land-disposed wastes such as drilling muds,
well cuttings, and sludges resulting from treatment of gases and liquids, as
well as surface impoundments of potentially hazardous wastes. Permanent
exclusion and perpetual maintenance of disposal sites may be needed after
plant de-commissioning.
The suggested limitations for geothermal solid wastes are total confine-
ment and no significant emissions or discharges therefrom to the air, surface
water or ground water. Wherever it is not possible to permanently contain
the leachate, it must be further treated for removal of any contaminant that
would have an adverse impact.
NOISE LIMITATIONS
The information on noise and its effects, as presented in this document,
is not sufficient to independently suggest limitations for geothermal opera-
tions. It is therefore suggested that limitations, similar to the U.S.
Geological Survey regulations currently imposed on Federal lands be observed
as a minimum at all sites. Thus the suggested limitation is 65 dBA at the
property line or at a distance of one-half mile from the source, whichever is
greater. Several states have more restrictive limitations, and these should
be observed. Regulations of the Occupational Safety and Health Administration
limit noise, without ear protection, to a daily limit of 90 dBA for eight
hours and 115 dBA for 15 minutes.
As indicated in the previous section, noise suppression technology for
geothermal applications has not received a great deal of attention and can
probably be improved significantly at relatively small cost. This in turn
indicates that noise limits might become more restrictive in the future.
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VIII. FUTURE DEVELOPMENT OF EFFLUENT AND EMISSION STANDARDS
As indicated throughout this document, pollution control for the geo-
thermal industry, during its development stages and later full-scale commer-
cialization, will be regulated by discharge and disposal permits. The permit
systems will be implemented and principally administered by the States under
approval by the Administrator of the U. S. Environmental Protection Agency.
On Federal lands the U. S. Geological Survey supervises geothermal operations
and issues operational permits. It also monitors operations for regulatory
compliance, including pollution control. The USGS interface with other
agencies in the area of pollution control has not yet been clearly defined.
During the development stages, permits are likely to be issued on a
case-by-case basis, with discharge loadings based upon the maintenance of
ambient standards. Later permits, during established commercialization, may
restrict loadings based upon water Effluent Guidelines and air New Source
Performance Standards. These guidelines and standards would, in turn, be
based upon concurrent pollution control and conversion process technology
development during the pre-commercial stages.
Effluent Guidelines and New Source Performance Standards must be founded
upon demonstrated control technology. The geothermal industry and its regu-
lation are unique in that the industry is just beginning, and the inertial
resistance characteristic of established industries toward pollution control,
created by past less restrictive requirements, is virtually nonexistent. The
principal geothermal industrial development agency, the U. S. Department of
Energy, is committed by law to concurrently develop pollution control tech-
nology. Thus, in the case of geothermal development the heretofore rare
opportunity exists to create an industry with integral pollution control from
the outset.
Effluent Guidelines and New Source Performance Standards are normally
based upon demonstrated achievable pollutant control technology. In some
cases, this may not effect the achievement of ambient standards. Thus,
ambient standards in the development stage may be useful in forcing the
development of improved, economically viable control technology where re-
quired .
Geothermal pollution control research, development, and demonstration
costs will be largely borne by government prior to large private investment.
The result should be that the geothermal industry will find itself, when it
is ready to become fully operational, in the advantageous position of having
pollution control limits and technology that are available and compatible.
Ideally, the application of control technology then would result in no
111
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ambient standards violations in any case. This would increase industry's
confidence in its ability to develop within the limits of environmental
regulation.
The evolution of pollution control standards by EPA should be a coopera-
tive process involving inputs principally from the Department of Energy, the
U. S. Geological Survey, the States, and private developers. It must include
a free exchange of information among all interested parties. The principal
contributions of each are suggested as follows, with the most significant
underlined:
• Environmental Protection Agency
Overview of environmental and health research and develop-
ment by other agencies and the industry.
- Characterization and evaluation of pollutants.
- Evaluation of pollutant environmental and health effects.
Regionwide pollution monitoring.
- Guidance as to limitations based upon effects.
- Evaluation of control systems and suggestions for improvements.
- Development of new water quality criteria.
- Support of pollution control research and development.
Development of pollution control regulations and promulgation
of Effluent Guidelines, New Source Performance Standards,
reinjection regulations, solid waste regulations, and
guidance to states on permitting programs.
• Department of Energy
- Design, construction, and operation of pollution control
systems.
- Conduct and support of control technology research,
development, and demonstration.
- On-site environmental baseline characterization.
- Initial effluent characterization and evaluation of effects.
- Establishment and maintenance of liaison with all developers.
- Input to pollution control regulations development.
112
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U. S. Geological Survey
Assurance of compliance with pollution limitations on Federal
lands.
Development of resource characterization data.
- Establishment of environmental regulations on federal lands
where otherwise lacking.
Input to pollution control regulations development.
States (regulatory and development agencies)
Implementation of interim pollution Control program by permit
and monitoring systems.
Support of baseline monitoring.
Statewide water and air quality monitoring and planning.
- Input to pollution control regulation development.
Private developers
- Design, construction, and operation of pollution control
systems to meet established and/or anticipated pollution
control limits.
Monitoring of effluents and emissions throughout development
and operation.
Evaluation of pollution control systems.
Environmental baseline characterization.
Input to pollution control regulations development.
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IX. EFFLUENT AND EMISSION MONITORING
Monitoring as described here is primarily for the purpose of determining
the quantity of pollutants discharged to the air, surface water, and ground
water. As such, monitoring must include sampling and analysis for contami-
nants at effluent and emission points. These measurements will be required
as a part of permit conditions to ensure that permitted loading limits are in
fact met.
Pollutant loading limitations may be based, as discussed earlier, upon
effluent and emission standards when such are developed. In the interim,
those limitations will be based upon calculations and judgments, by the
permitting agency, as to loadings that will allow ambient air and water
standards to be met. Also as discussed earlier, ambient standards may control
limitations even after the development of effluent and emission standards,
where the latter would allow ambient standards to be violated. Thus, ambient
monitoring at receptor points will also be required, in most cases, in addi-
tion to effluent and emission monitoring.
This document suggests pollutant monitoring locations and frequencies.
It does not describe actual sampling and analytical techniques. It recognizes
that initial monitoring may be more cumbersome until the industry and a data
base have been sufficiently developed, and until geothennal specific monitor-
ing methodologies have been developed. EPA's Environmental Monitoring and
Support Laboratory-Las Vegas is currently engaged in methodology development.
AIR AND WATER POINT SOURCE MONITORING
Any planned waste liquid discharges or gas emissions resulting from
materials used in the geothermal energy conversion process must be monitored
by the operator in accordance with permit requirements. For liquid dis-
charges, the required measurements may include volume, selected chemical
constituents, suspended solids, temperature, pH, and radioactivity. Gas
emission measurements will include volume and concentrations of regulated
constituents such as hydrogen sulfide. Radiological analysis may be required.
Any or all of the pollutants listed in Sections IV and V may require measure-
ment .
Some planned direct discharges and emissions are likely to be inter-
mittent, such as at wellheads, vents, and bypasses, while others may be
continuous, such as at separators, mufflers, scrubbers, gas ejectors, cooling
towers, and spent liquid drains. It is anticipated that, on the whole,
continuous discharges, where permitted, will greatly exceed intermittent
discharges in volume.
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Monitoring of wastewater surface discharges and gas emissions should be
conducted at each planned discharge site at a frequency commensurate with the
character of discharge, e.g. less frequently for discharges of uniform char-
acter. Often, liquid effluents and gases will be combined and can be sampled
simultaneously.
The frequency, duration, and method of sampling should be such that a
calculated average constituent loading ± 50% will encompass the true average
loading over any period of time.
In most cases, it is expected that discharges and emissions will be
fairly uniform to the extent that they result from fluid consistently with-
drawn from the geothermal reservoir. This would suggest that high frequency
sampling is probably not demanded. The sampling frequency for continuous
discharges might reasonably be monthly, with a sampling duration of 24 hours.
For treated effluents and emissions, where treatment may not provide con-
sistently predictable results, the required frequency may be weekly or more
often. Planned, intermittent, direct discharges, where the content and
volume are not known prior to release, should be sampled whenever they occur,
for a duration proportional to that for continuous discharges, perhaps 1/7 to
1/30 of the total discharge time.
All discharge permits will require that monitoring be done by the opera-
tor, that records of measurements be maintained for inspection by the regu-
latory agency, that loading data for all releases be submitted periodically
to the regulatory agency and that standard violations be reported. The
regulatory agency may sample discharges to confirm operator monitoring re-
sults and to determine permit compliance.
AMBIENT AIR MONITORING
An initial ambient air sampling and analysis program should be estab-
lished by the geothermal operator for all geothermal energy conversion facil-
ities which require emission monitoring. Such a program can be expected to
last at least until data accumulation is sufficient to show that ambient air
quality standards are not violated or adverse impacts do not occur as a
result of the emissions.
Ambient air monitoring should be designed on a case-by-case basis to
ensure receptor protection (or to detect standards violations) at the facil-
ity's boundary with other private or public property or even within its
boundaries if the property is accessible for public use. Monitoring sites
should be selected to conform with principal directions of pollutant transport
by increased sampling frequencies at those points.
Ambient monitoring sites should be established on the basis of a prior
continuous sampling program at all compass octants from the production facil-
ities or the geographic center of the production field. Sites should be at
distances from the source(s) sufficient to delineate pollutant dispersion
characteristics and to encompass any area where concentrations above ambient
may be caused by such source(s). The continuous sampling program should be
of sufficient duration to include characteristic weather variations throughout
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the year. Sampling should be done within 5 meters (15 feet) of ground level,
so that concentrations may be related to terrestrial receptor effects.
Where patterns are developed by the continuous sampling program, the
same stations may be used for monitoring, with the sampling frequencies
ascertained from an analysis of the concentrations vs. time distributions.
The monitoring program might thus lie somewhere between the extremes of
continuous sampling at all stations to no sampling at any stations. The
latter would not be expected in most cases.
Any ambient air monitoring program will likely be subject to criticism,
periodic reevaluation, and redesign to conform to expanded or reduced pro-
duction or to natural factors not known at the time of program establishment.
This may be particularly true for larger and expanding production facilities
and/or those with relatively high non-condensible gas fractions in the raw
geothermal fluid.
AMBIENT WATER MONITORING
In the past, it has been common to require industries to monitor dis-
charges, but not surface receiving water quality. The bulk of those measure-
ments have been made by regulatory agencies. Permits may require geothermal
developers to monitor ambient water quality. Even if ambient monitoring is
not required, voluntary monitoring will likely be to their advantage, particu-
larly if discharge loading limitations are based upon water quality standards.
Limitations, thus developed, are intended to prevent violations of concen-
tration limits within the receiving waters under all flow conditions.
Monitoring points should be selected to ensure, as a minimum, that the
quality of surface water be monitored where it is accessible to the use of
others. In many cases, this may be at the downstream point of intersection
of the developer's property line and surface drainage. However if the
developer's property is leased public land, water quality and thus monitoring
stations may be maintained within the leasehold, since all but operationally
unsafe areas may still be publicly accessible.
Surface water quality monitoring may be required even if there are no
planned surface water discharges. One of the reasons for this is air pollu-
tants from geothermal operations may result in atmospheric "fallout" contami-
nation. Another is that, if surface containment is employed, leakage may
occur.
Water quality monitoring should include the same constituents and
properties for which effluents are monitored.
The locations, frequency, and duration of surface water ambient monitor-
ing should be determined after consideration of several factors such as:
• size, flow, and flow variability of the receiving water body
• stream mixing characteristics
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• volume of the discharge
• chemical and physical characteristics of the discharge and the
consistency thereof
• waste water treatment system characteristics
• air emission characteristics
• downstream water uses
• upstream pollutional discharges
• stream ecology
Despite the apparent complexity of the monitoring selection process, the
resulting monitoring scheme would be expected to be relatively simple. One
extreme might be represented by a uniformly low volume, low salinity discharge
into a large flowing stream. Monitoring then might be one grab sample up-
stream and one downstream taken monthly at points of well-mixed stream flow.
The other extreme might be represented by a high volume, high salinity, rela-
tively nonuniform discharge into a low or variably flowing stream already
contaminated by upstream users. In this case, much more frequent monitoring
might be required at several upstream and downstream stations. Several cross-
sectional grab samples might be taken, flows measured, and data ccmposited.
In addition to determining constituent concentrations, effluent loadings may
be confirmed.
Frequency of ambient water monitoring should be commensurate with varia-
bility in effluent characteristics and stream flow. However, it appears
likely that in most cases, monthly sampling might be acceptable, because of
the expected uniformity of discharge characteristics.
GROUND WATER MONITORING
Spent fluid is likely to be injected in many, if not most, cases to or
below the geothermal reservoir to alleviate reservoir depletion and subsi-
dence. Injection is also likely to be the most environmentally acceptable
disposal method for high salinity fluids, if performed properly.
Subsurface injection may be the disposal method of choice, even if spent
fluid cannot be feasibly returned to the geothermal reservoir. This is the
case in known geopressured areas, where injection would probably be to shal-
lower aquifers with similar chemical characteristics.
Injection in any case will have the potential, as a result of unplanned
or accidental system disruption, of contaminating aquifers usable for other
purposes, such as drinking water. Such contamination could have the most
serious consequences. If such contamination occurs, it may be difficult, if
not impossible, to return the aquifer to its original condition. Careful
monitoring may be the only way to ensure that significant contamination does
not occur with injection.
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Because of the serious nature of potential ground water contamination,
the Environmental Protection Agency is currently conducting a study to design
an adequate ground water monitoring methodology for geothermal operations.
Many other studies of geology, hydrology, scaling and corrosion, reservoir
dynamics, etc. by other agencies will have direct bearing on injection tech-
nology and, in turn, monitoring methodology. Until monitoring methodologies
are fully developed, interim requirements will necessarily be imposed, based
upon state-of-the-art injection technologies.
The ground water chemical characteristics of all aquifers overlying the
geothermal reservoir should be monitored. The monitored constituents should
include all those that would be measured if the waste water were surface-
discharged, and perhaps others, if chemicals are added to promote injection.
Methods, principally electro-chemical, are being researched to monitor by
injection well instrumentation, the location and extent of migration of in-
jected fluids. Until such methods are perfected, monitoring may require
sampling from wells into each aquifer. Sampling, by fluid retrieval, of
multiple aquifers from one well should not be encouraged because of potential
mixing. Sampling wells should surround the geothermal operation, and all
should be located within a few hundred yards of reinjection wells. The
capability should exist to sample each aquifer at two or more points down-
gradient from principal injection wells. Existing water supply wells may be
used where determined appropriate.
The frequency of ground water aquifer sampling will depend principally
upon the rate of injection and the quality characteristics of the injected
fluid vs. those of the aquifer. Higher injection rates of more saline brines
would probably demand higher frequency sampling than lower injection rates of
"cleaner" fluids. In most cases, however, it is expected that a 30-day sam-
pling frequency will be near the optimum. Various characteristics may demand
more frequent sampling.
Simple grab samples should be sufficient for ground water monitoring.
LAND-DISPOSED WASTES
Land-disposed wastes requiring control by isolation are determined by
chemical characterization. Monitoring of storage, treatment, and disposal
sites under control of the geothermal operator will be required under State
and Federal regulations to determine whether any constituents escape by
leaching or percolation to surface and/or ground water. Monitoring require-
ments will be similar to those described above for ambient surface waters and
for ground water. The most significant difference is that probably only the
uppermost ground water aquifer may need to be monitored.
NOISE MONITORING
Monitoring of noise is accomplished by noise measurements at the property
line or the boundary with other use areas, at points nearest the noise source.
It is probable that a set monitoring schedule need not be established. Rather,
measurements should be made upon a change in type or mode of operation.
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Measurement methodologies have been developed for many specific noise sources
and can be integrated to measure overall noise at the boundary site.
A noise monitoring program should be established by the operator to
assure himself that violations of local, State and Federal regulations do not
occur. Because noise cannot be ignored, it may be monitored frequently by
regulatory agencies.
BASELINE AIR AND WATER MONITORING
Prior to geothermal energy production, the existing state and natural
variations of air and water quality should be determined in detail by the
developer in accord with the needs of regulating agencies. Baseline descrip-
tions are in fact part of the requirement for environmental impact reports and
analyses, which in turn are required for all projects on Federal lands and
most on state lands. Baseline assessment may require long-term, detailed
measurements to establish the basis for differentiating natural and operation-
caused changes.
The U. S. Department of Interior's Geothermal Environmental Advisory
Panel (GEAP) has prepared a document entitled "Guidelines for Acquiring
Environmental Baseline Data on Federal Geothermal Leases."77 The document
describes procedures for gathering chemical, physical and biological data for
a one-year period prior to submission of a plan for production, as required by
the Geothermal Steam Act of 1970. The data are submitted to the U. S. Geo-
logical Survey Area Geothermal Supervisor, who may alter the requirements
according to specific needs.
The Department of Energy, Division of Geothermal Energy has developed
general requirements for describing baseline date acquisition and evaluation
methodology in environmental reports on DOE-sponsored geothermal activities.78
The U. S. Fish and Wildlife Service has prepared a handbook for gathering and
assessing biological data, and for mitigating impacts.7' Each of the sources
of information should be used by the developer in setting up a baseline moni-
toring program.
Baseline water and air quality monitoring should be viewed as setting the
stage for later ambient monitoring during full-scale operations. Thus, it
should include measurements of the same constituents that will be monitored
later during construction and operation of the energy conversion facility.
With this view in mind, it would be expected that the operational monitoring
would utilize baseline stations established earlier. This of course requires
coordinated planning throughout development.
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Energy Development; a report by the Institutional Barriers Panel;
June 30, 1976; unpublished.
2. White, Donald E.; Characteristics of Geothermal Resources in
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January 1976.
7. Rascheri, R. and Cook, W. S.; Exploration and Development of Geothermal
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9. Douglas, J. G., R. J. Serne, D. W. Shannon, and E. M. Woodruff;
Geothermal Water and Gas—Collected Methods for Sampling and Analysis
BNWL-2094, Battelle Pacific Northwest Laboratories; August 1976.
10. Cosner, S. R.; Geothermal Brine Data File; Lawrence Berkeley Laboratory,
University of California; revision February 3, 1977 (available as
updated via computer printout).
11. Sanyal, S. K., Preliminary Compilation of Chemical Composition of
Geothermal Waters; Geonomics, Inc.; January 28, 1977 (personal
communication).
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12. Wood, B.; Geothermal Power in Geothermal Energy Review of Research
and Development, ed. by H. C. H. Armstead; UNESCO Paris, 1973.
13. O'Connell, M. F. and R. F. Kaufman; Radioactivity Associated with
Geothermal Waters in the Western United States; Technical Note
ORP/LV-75-8A, U. S. Environmental Protection Agency; March 1976.
14. Finney, John P.; Design and Operation of The Geysers Power Plant,
in Geothermal Energy edited by Kruger and Otte; Stanford University
Press, 1973.
•x
15. Aytmann, Robert C.; Environmental Impact of a Geothermal Power Plant;
Science, Vol. 187, no. 4179, March 1975.
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and Assessment of Pollution Potential and Control Technology Applica-
tions for Geothermal Resources Development, Phase II Report; prepared
for Office of Research and Development, Contract No. 68-03-2371,
March 1977 (preliminary draft).
17. Pacific Gas and Electric Company; Amended Environmental Data Statement,
Geysers Unit 13; March 1975.
18. Environmental Protection Agency; Information on Levels of Environmental
Noise Requisite to Protect Public Health and Welfare with an Adequate
Margin of Safety; Report No. 550/9-74-004, Office of Noise Abatement
and Control; March 1974.
19. Environmental Protection Agency; Public Health and Welfare Criteria
for Noise; Report No. 550/9-73-002, Office of Noise Abatement and
Control; July 1973.
20. Sax, N. I.; Dangerous Properties of Industrial Materials; Rheinhold
Book Corp., New York; 1968.
21. Gleason, M. N., R. E. Gossclin, H. C. Hodge, and R. P. Smith;
Clinical Toxicology of Commercial Products; Williams and Wilkison
Co., Baltimore; 1969.
22. U. S. Public Health Service; Public Health Service Drinking Water
Standards; PHS pub. 956, U. S. Government Printing Office; 1962.
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Water Regulations; 40 CFR Part 142; Federal Register, Vol. 41,
No. 3; January 20, 1976.
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25. National Academy of Sciences; Water Quality Criteria 1972; A Report
of the Committee on Water Quality Criteria; 1973.
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26. Federal Water Pollution Control Administration; Water Quality Criteria;
Report of the National Technical Advisory Committee to the Secretary
of the Interior; April 1, 1968.
27. U. S. Public Health Service; Preliminary Air Pollution Survey of
Hydrogen Sulfide - A Literature Review; Consumer Protection and
Environmental Health Service; APTD 69-37; 1969.
28. American Conference of Governmental Industrial Hygienists; Threshold
Limit Values for Chemical Substances in Workroom Air Adopted by
ACGIH for 1976; ACGIH, 1976.
29. Sung, R., G. Houser, G. Richard, J. Cotter, P. Walker, and E. Pulaski;
Preliminary Cost Estimates of Pollution Control Technologies for
Geothermal Development; EPA Contract No. 68-03-2560, Work Directive
T-S004; review draft, January 1978.
30. Laszlo, J.; Application of the Stretford Process for H2S Abatement
at The Geysers Geothermal Power Plant; Proceedings of the llth Inter-
society Energy Conversion Engineering Conference, 1976.
31. Griebe, M.; personal communication to TRW, Inc.; Ralph M. Parsons
Company, December 2, 1977.
32. Stanford Research Institute; Environmental Analysis for Geothermal
Energy Development in The Geysers Region; report for the California
Energy Resources Conservation and Development Conservation, Volume I -
Summary, May 1977.
33. Fairfax, J. P., and H. K. McCluer; Hydrogen Sulfide Abatement—
Geysers Power Plant Progress Report 7485.3-71; Pacific Gas and
Electric Company; January 1972.
34. Tolmasof; Report on H2S Air Quality and The Geysers Geothermal
Development; Northern Sonoma County Air Pollution Control District;
January 1976.
35. Galeski, J.; personal communication to TRW, Inc.; Midwest Research
Institute, December 7, 1977.
36. Allen, G. W.; personal communication to TRW, Inc.; Pacific Gas and
Electric Company; November 18, 1977.
37. EIC Corporation; Control of Hydrogen Sulfide Emissions from Geothermal
Power Plant; Annual Status Report, ERDA Contract EY-76-C-02-2730;
July 1976.
38. Hesketh, E. H.; Understanding and Controlling Air Pollution; Ann Arbor
Science Publishers, Inc.; 1973.
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39. Dow Chemical Company, Texas Division; Removal of Hydrogen Sulfide from
Simulated Geothermal Brines with Oxygen; ERDA Contract No. 76-C-02-2797;
April 1977.
40. Battelle Pacific Northwest Laboratories; Removal of Hydrogen Sulfide
from Geothermal Steam; ERDA Contract No. E-45-1-1830; September 1976.
41. ECOVIEW; Environmental Impact Report on Borax Lake Area, Lake County,
California; April 1976.
42. Bond, R. G., and C. P. Straub; Handbook of Environmental Control -
Vol. IV, Wastewater Treatment and Disposal; CRC Press, Cleveland,
Ohio; 1973.
43. Bell, G. R.; Design Criteria for Diatomite Filters; Jour. AWWA, Vol. 54;
October 1962.
44. Gulp, R, L., and G. L. Gulp; Advanced Wastewater Treatment; Litton
Educational Publishing, Inc.; New York, 1971.
45. Van Note, R. H., et al.; A Guide to the Selection of Cost-Effective
Wastewater Treatment Systems; EPA Report No. 430/9-75-002, July 1975.
46. Chen, C. L., and R. P. Miele; Demineralization of Sand-Filtered
Secondary Effluent by Spiral-Wound Reverse Osmosis Process; EPA
Report No. 600/2-77-169; September 1977.
47. UOP Report; Reverse Osmosis Principle and Applications; prepared by
Fluid Systems Division, San Diego, CA; September 1974.
48. Chan, C. L., H. H. Takenaka, and R. P. Miele; Demineralization of
Wastewater by Electrodialysis; EPA Report No. 600/2-75-047; October 1975.
49. San Francisco Bay—Delta Water Quality Program; Costing of Electro-
dialysis System; March 1968.
50. Dryden, F. D.; Mineral Removal by Ion Exchange and Electrodialysis;
presented at Workshop on Wastewater and Reuse, sponsored by UC-Berkeley
at South Lake Tahoe, CA; July 1970.
51, Faber, H. A.; Improving Community Water Supplies with Desalting
Technology; Jour. Am. Waterworks Assoc.; November 1972.
52. Chen, C. L., and R. P. Miele; Wastewater Demineralization by Two-Stage
Fixed Bed Ion Exchange Process; EPA Report No. 600/2-77-146; September
1977.
53. Rosenblad, A. E.; Evaporator Systems for Black Liquor Concentration;
Chemical Engineering Progress 72:53; April 1976.
54. Guthrie, K. M.; Process Plant Estimating, Evaluation, and Control;
Craftsman Book Co.; 1974.
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55. Perry, R. H., C. H. Chilton, and S. D. Kirkpatrick, eds; Chemical
Engineers' Handbook; McGraw-Hill Book Co., Inc., New York; 1973.
56. Howe, E. D.; Fundamentals of Water Desalination; Marcel Dekker; 1974.
57. Spiegler, K. S.; Principles of Desalination; Academic Press; 1966.
58. Ostroot, G. W., and Ramos, J.; Deep-Well Acid Disposal—Planning and
Completion; Underground Waste Management and Environmental Implications,
Memoir 18, American Association of Petroleum Geologists; 1972.
59. Sadow, R.; Pretreatment of Industrial Waste Water for Subsurface
Injection; Underground Waste Management and Environmental Implications,
Memoir 18, American Association of Petroleum Ge'ologists; 1972.
60. Warner, D.; Deep-Well Disposal of Industrial Wastes; Chemical
Engineering, Vol. 72, p. 73-78; 1965.
61. Cuellar, G.; Behavior of Silica in Geothermal Waste; Proceedings of the
Second UN Symposium on the Development and Utilization of Geothermal
Resources, San Francisco; May 20-29, 1975.
62. Yanagase, T., Y. Suginohara, and K. Yanagase; Properties of Scales
and Methods to Prevent Them; UN Symposium on the Development and
Utilization of Geothermal Resources, Vol. 2, Pt. 2; Pisa; 1970.
63. Schock, R., and A. Duba; Effect of Electrical Potential on Scale
Formation in Salton Sea Brine; Lawrence Livermore Laboratory,
Contract W-740 S-Eng-48; November 1975.
64. Ozawa, T., and Y. Fuji; Phenomenon of Scaling in Production Wells and
the Geothermal Power Plant in the Matsukawa Area; UN Symposium on the
Development and Utilization of Geothermal Resources, Vol. 2, Pt. 2;
Pisa; 1970.
65. Van Windle, W., and Mignotte, H.; Journal of Petroleum Technology;
161-28; 1964.
66. Hoffman, M.; Jet Propulsion Laboratory, Environmental Quality
Laboratory; Memoir 14; 1975.
67. Dodds, F. J., A. E. Johnson, and W. C. Ham; Material and Corrosion
Testing at the Geysers Geothermal Power Plant; Proceedings of the ;
Second UN Symposium on the Development and Utilization of Geothermal>
Resources; San Francisco, May 20-29, 1975.
68. Tolivia, M.; Corrosion Measurements in a Geothermal Environment;
UN Symposium on the Development and Utilization of Geothermal Resources;
Vol. 2, Pt. 2; Pisa; 1970.
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69. Geonomics, Inc.; A Comparison of Hydrothermal Reservoirs of the Western
United States; prepared for Electric Power Research Institute; March
1976.
70. National Industrial Pollution Control Council; Waste Disposal in Deep
Wells; Subcouncil Report, COM-71-50242; February 1971.
71 U. S. Army, Corps of Engineers; Cost Curves for Conveyance, Treatment and
Storage of Wastewater; U. S. Army Engineer District, San Francisco; April
1972.
72. Black and Veatch Consulting Engineers; Wastewater Stabilization Ponds;
report prepared for the U. S. Environmental Protection Agency; 1977.
73. Liptek, B. G., editor; Environmental Engineering Handbook; Vol. Ill, Land
Pollution; Chilton Book Co.; 1974.
74. Kinna, L.; personal communication; Chancellor and Ogden, Inc., Wilmington
Landfill; December 1977.
75. Jhaveri, A. G.; Environmental Noise and Vibration Control at Geothermal
Sites; Proceedings Second UN Symposium on Development and Use of
Geothermal Resources; San Francisco; May 20-29, 1975.
76. Smith, J. H., Collection and Transmission of Geotl-iermal Fluids in
Geothermal Energy Review of Research and Development; ed. byH.C.H. Arm-
stead; UNESCO Paris; 1973.
77. U. S. Department of Interior, Geothermal Environmental Advisory Panel;
Guidelines for Acquiring Environmental Baseline Data on Federal
Geothermal Leases; U. S. Geological Survey, Menlo Park, CA; January 1977.
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APPENDIX
SUMMARY OF LAWS REQUIRING OR
RELATED TO GEOTHERMAL POLLUTION CONTROL
Federal Pollution Control Laws Administered
by the Environmental Protection Agency
Any geothermal energy development is subject to many pollution control
laws and regulations. The most significant of the federal laws, which apply
to all industrial development, are:
(1) the Federal Water Pollution Control Act Amendments of 1972
(PL 92-500);
(2) the Clean Air Act as amended (PL 91-604 and PL 95-95),
(3) the Safe Drinking Water Act (PL 93-523);
(4.) the Resource Conservation and Recovery Act of 1976 (PL 94-580);
(5) the Noise Control Act of 1972 (PL 92-574); and
(6) the Toxic Substances Control Act (PL 94-469).
All but the last of the above federal laws allows and fosters delegation
of authority to the states upon their meeting certain requirements. In
effect, the federal laws extend down through state, regional, and local
levels.
Federal Water Pollution Control Act Amendments (FWPCA) of 1972
Several sections of this Act apply to geothermal development. Probably
the most significant sections are in Title III - Standards and Enforcement.
Section 301 calls for the application of "best practicable control technology
currently available" by July 1, 1977, for point sources other than publicly
owned treatment works. This section further calls for the application of
"best available technology economically achievable" by July 1, 1983. This
section further requires the elimination of all pollutants where technologi-
cally and economically achievable. Section 304 calls for the definition by
the EPA of such technologies, and effluent limits attainable thereby, through
the issuance of "Effluent Guidelines" regulations. For the geothermal energy
industry, those regulations have not yet been developed and are not currently
scheduled. However, such regulations may be expected when the industry is
firmly established and technologies have been demonstrated. Effluent
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guidelines are promulgated, upon development, as regulations in 40 CFR Parts
402 through 699.
Section 303 of the FWPCA calls for the establishment and maintenance of
receiving water quality standards for both interstate and intrastate surface
waters. Such standards have been established by the States and approved by
the Administrator (40 CFR Part 120). They are subject to periodic revision.
The provisions of this section interact with those of Section 301 and prevail
in establishing permit limitations where the application of Effluent Guide-
lines limits is not sufficient to meet receiving water quality standards.
This is likely to be the case in many, if not most, areas of early geothermal
energy development.
Section 306 of the FWPCA calls for the establishment of "national stan-
dards of performance" for new sources of water pollution after the EPA Admin-
istrator publishes a list of such sources. Past development of such stan-
dards indicates that they would be similar to "best available technology
economically achievable." There is currently no schedule for establishing
new source performance standards for the geothermal industry but they also
can be expected in the future. New source performance standards are promul-
gated along with effluent guidelines in 40 CFR Parts 402 through 699.
Section 307 of the FWPCA calls specifically for the identification of
toxic pollutants and the establishment of effluent standards, regardless of
the source, for such pollutants. Standards were proposed in 1973 for nine
substances. Final regulations were published in January and February 1977
for six substances: aldrin/dieldrin, benzidine, DDT (ODD, DDE), endrin, PCB
and toxaphene. These regulations have been promulgated in 40 CFR Part 129.
Since such materials are not in geothermal fluids they have no bearing on the
development of geothermal energy. Any toxic substance limitations applicable
to geothermal development are likely to be established by effluent guidelines
(Sections 301 and 304) and water quality standards (Section 303).
The implementation of effluent guidelines and water quality standards is
carried out under authority of Section 402 of the FWPCA by way of the "Nation-
al Pollutant Discharge Elimination System" (NPDES). This requires a dis-
charge permit based upon Effluent Guidelines and/or Water Quality Standards
for any point source discharge1 to surface drainage. Permitting authority has
been delegated to those States which have met implementation program require-
ments. Implementing regulations have been published in 40 CFR Part 125.
Section 308 of the FWPCA requires dischargers regulated by the Act to
sample and maintain records of discharge loadings and make them available to
authorized federal and state regulatory personnel. It also authorizes right
of entry to the discharger's premises by those personnel. The recorded data
must be gathered and maintained as prescribed in permit conditions, and may
be used as evidence in enforcement of pollutant limitations.
Clean Air Act as Amended
The Clean Air Act also has several sections which may significantly
affect geothermal energy development.
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Section 107 of the Clean Air Act allows and provides for the establish-
ment of intrastate and interstate Air Quality Control Regions in which the
states must provide implementation plans under Section 110 for assuring air
quality.
Under Section 108 of the Clean Air Act and Section 106 of the 1977
amendments, the Administrator of the Environmental Protection Agency may
publish air quality criteria. Based upon the criteria, he then publishes
national primary (to protect public health) and secondary (to protect public
welfare) ambient air quality standards (Section 109 of the Clean Air Act) for
pollutants determined to have adverse effects. National air quality stan-
dards have thus far been established for six pollutants: particulates,
sulfur dioxide, nitrogen oxides, hydrocarbons, photochemical oxidants, and
carbon monoxide (40 CFR Part 50). Lead may be added in the near future. The
states must establish implementation plans (Section 110 of the Clean Air
Act), including emission limits, first to meet primary standards and later to
meet secondary standards, in each Air Quality Control Region. These plans
are approved by the Administrator and promulgated in 40 CFR Part 52. Since
the listed pollutants may not be significant in most geothermal sources, the
importance of current ambient standards may not be great. However, the
states may unilaterally include other constituents, and some have done so,
e.g., hydrogen sulfide in California.
Section 111 of the Clean Air Act and Section 109 of the 1977 amendments
allow the Administrator of the Environmental Protection Agency to establish
New Source Performance Standards for air pollutants from stationary source
categories. Once established, these standards oecome applicable to all new
sources in such a category, and further, the States must then establish
emission limits for the same constituents from existing sources within that
category. This is likely to be the principal route for federal regulation of
air emissions, although such standards have not been developed yet for the
geothermal industry. New Source Performance Standards are based upon best
demonstrated economically achievable emission reduction, similar to the basis
for water discharge National Standards of Performance. They are published as
regulations in 40 CFR Part 60.
Section 112 of the Clean Air Act and Section 110 of the 1977 amendments
provide for the establishment of emission standards for hazardous air pollu-
tants from stationary sources. Such standards are based upon a determination
that a pollutant causes or contributes to an increase in mortality or serious
illness in humans. Thus far, standards have been established for specific
sources of mercury, asbestos, beryllium and vinyl chloride (40 CFR Part 61).
These standards do not apply to geothermal sources. However, geothermal
sources may in some cases contain hazardous air pollutants, leaving open the
possibility that such standards may be developed. The proof-of-harm require-
ment may make such development very difficult.
Section 122 of the Clean Air Act Amendments of 1977 provides for the
regulation of emissions of radioactive substances, cadmium and arsenic, all
of which may be found in geothermal fluids.
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Safe Drinking Water Act
This Act is administered by the Environmental Protection Agency and
allows and provides for State implementation of its provisions. Part C of
the Act, "Protection of Underground Sources of Drinking Water," is of great-
est significance to geothermal energy development in that it requires the
promulgation of regulations to control underground injection. Reinjection is
an integral part of most existing and proposed geothermal development.
Regulations under this Act have been proposed (40 CFR 146), but their appli-
cability to geothermal operations has not yet been established. Any regula-
tions may be further extended by more restrictive state regulations. Rein-
jection permits will be required, as they already are in most states, the
issuance of which is likely to be based upon an analysis of geological,
hydrological, and injection system design and operational information.
Under the Geothermal Steam Act of 1970, the U. S. Geological Survey has
issued Geothermal Resources Operational Orders, which include specific require-
ments for reinjection wells on Federal lands. Regulations which may be
developed under the Safe Drinking Water Act for reinjection are not likely to
be in conflict with the Operational Orders.
The Environmental Protection Agency already has some control over under-
ground injection via NPDES permits using Administrative Order No. 5, which
provides for approval of injection systems that are part of any other project
subject to EPA regulation.
Resource Conservation and Recovery Act of 1976
The provisions of this Act, administered by the Environmental Protection
Agency, are principally concerned with solid wastes. Subpart C - Hazardous
Waste Management, important to geothermal energy development, involves regu-
latory control of storage, treatment, and disposal of potentially hazardous
wastes in landfills and surface impoundments. The potentially hazardous
wastes may be liquid, solid, or a combination. Wastes considered potentially
hazardous are those which may cause or contribute to adverse effects on human
health or the environment when not properly controlled. Regulations to be
developed under the Act are likely to have significant ramifications for the
geothermal industry in those cases where spent brine surface impoundments are
used and where waste sludges are created, such as in the treatment of waters
and noncondensible gases.
Section 3001 calls for the Administrator to identify and list hazardous
wastes in conformance with criteria he must first establish.
Sections 3002, 3003, and 3004 require the establishment of standards for
the identified hazardous wastes applicable to waste generators, transporters,
and disposal operators, respectively. Complete traceable records are to be a
principal feature of the regulations. Geothermal developers may be subject
to all three sets of regulations.
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Section 3005 requires permits for hazardous waste disposal facilities,
with permits to be approved when certain conditions are met. Section 3006
authorizes the states to administer and enforce hazardous waste programs upon
approval by the Administrator.
Section 3007 authorizes access to any facility handling hazardous wastes
and to its records for regulatory development and enforcement purposes.
Regulations have not yet been developed under any sections of the
Resource Conservation and Recovery Act, although they are imminent.
Toxic Substances Control Act
This Act is aimed principally at manufacturers and distributors of toxic
chemicals, in order to control indiscriminate proliferation of such materials
in the environment. The provisions of the Act can conceivably apply to miner-
als which might be commercially produced from geothermal development.
Section 4 may require testing by the producer to determine health and
environmental effects and the degree of risk. Testing will be done in accor-
dance with standards to be promulgated.
Section 5 requires notice of intent and submission of test data prior to
manufacture of new chemicals.
Under Section 6, the Administrator may prohibit the manufacture or
distribution of chemical substances if he determines that such substances
present an unreasonable risk.
Section 8 requires maintenance of records and authorizes official access
to such records.
The Toxic Substances Control Act, unlike the others thus far described,
does not provide for State control of the program, but does allow states to
apply rules not in conflict with the Act.
Noise Control Act of 1972
This Act contains broad noise control provisions for regulating and
labeling products, many of which are used at geothermal facilities. In
addition, EPA has been given coordination authority of all programs of other
Federal agencies relating to noise research and noise control. It has also
been given authority to insure that all Federal facilities comply with appro-
priate Federal, State, and local noise regulations. Many states and local
communities regulate noise, and the U. S. Geological Survey has noise regu-
lations (in Geothermal Resources Operational Order 4) for developers on
leased Federal lands.
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Other Federal Laws Requiring or
Related to Geothermal Pollution Control
Pollution control considerations have been included in several other
laws affecting geothermal energy development. These laws are aimed princi-
pally at (1) broad-scale encouragement of energy resource development or (2)
broad-scale protection of environmental values. The most significant of the
first type are the following:
• Geothermal Steam Act of 1970
• Federal Nonnuclear Energy Research and Development Act of 1974
• Geothermal Energy Research and Development Act of 1974
The second type includes:
• National Environmental Policy Act of 1969
• Fish and Wildlife Coordination Act
• Endangered Species Act of 1973
• Wilderness Act
• Marine Protection, Research and Sanctuaries Act of 1972
Geothermal Steam Act of 1970
This Act is one of the most significant laws affecting the pace and
direction of geothermal energy development. It essentially controls leasing
of federal lands and all phases of post-lease operations on those lands;
those lands include a large number of the known geothermal resource areas^
(KGRA's). The Department of the Interior, Bureau of Land Management, admin-
isters pre-lease and leasing requirements. The Department of the Interior,
U. S. Geological Survey, administers post-lease requirements, through an
"Area Geothermal Supervisor." ( Currently there is only one Area Geothermal
Supervisor with broad responsibilities over most activities including those
that result in air and water pollution.
On other than Federal lands, State and local regulations have generally
been patterned after those of the Geothermal Steam Act.
The protection of the environment through regulation is provided for in
Section 24 of the Geothermal Steam Act. Regulations have been published in
30 CFR 270, under which the Area Geothermal Supervisor operates. Environ-
mental provisions require preproduction studies, for at least one year, of
air and water quality, noise and ecological systems. In addition, the regu-
lations require compliance with all federal and state standards for air,
water, land, and noise pollution. Geothermal Resource Operational Orders
(GRO) are issued by the Area Geothermal Supervisor to implement the regula-
tions. The principal set of environmental requirements is contained in GRO
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Order 4, which requires conformance with all federal and state air and water
pollution control standards, and establish detailed noise standards.
Federal Nonnuclear Energy Research and Development Act of 1974
This is the Act which mandated the activities of the Energy Research and
Development Administration (ERDA). One of those activities is the active
encouragement of geothermal energy technology development through commercial
demonstration. The Act (Section 6(b)(3)(K)) also provides for the accelera-
tion of the commercial demonstration of environmental control systems for
energy technologies. The objectives are restated in several problem defini-
tion and planning reports prepared by ERDA.
Geothermal Energy Research and Development Act of 1974
This Act authorizes and defines more specifically the responsibilities
of the federal government, through the direction of ERDA, in developing and
demonstrating the commercial viability of geothermal energy conversion. The
objectives of the Act are to be accomplished in concert with private develop-
ers through grants, contracts, and loan guarantees.
This Act includes a requirement for the development of environmentally
acceptable processes (Section 2(12)). More specifically, Section 104 re-
quires that the geothermal research and development program develop and
evaluate improved waste control, disposal and monitoring methods; evaluate
environmental effects of geothermal development; improve impact assessment
procedures; prepare environmental impact statements; and assure compliance
with standards and criteria. Meeting environmental standards is one of the
specific goals of the demonstration program (Section 105(a)(1)). Section 301
of the Act requires particular emphasis of all participants upon protection
of the environment and safety.
National Environmental Policy Act of 1969
This Act has had profound effects in calling public attention to the
environmental consequences of major new projects. Section 102 of the Act
requires an environmental impact statement for all major federal actions
affecting the quality of the human environment. The Act produced a ripple
effect in that most states have similar laws for state actions. In most
cases of major development, an environmental impact statement can be anti-
cipated at some stage prior to commercial energy production, whether it is on
federal, state, or private land.
The environmental impact statement requirements at the federal level are
applicable to geothermal development on federal lands and to any government-
supported research and demonstration projects. In many cases, an initial
environmental assessment report may indicate that the action is sufficiently
significant to require a full impact statement.
The impact statement must describe adverse impacts, including those
caused by any kind of pollution, on society and its environment. It also
must discuss alternatives to the proposed development and their consequences,
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and must describe irretrievable resource commitments. Details on the mate-
rials to be included have been published as regulations by several federal
agencies. Examples of these are the general guidelines published by the
Council on Environmental Quality (40 CFR 1500) and the more specific guide-
lines of ERDA for its projects (10 CFR 711). ERDA has recently published
"Guidelines to the Preparation of Environmental Reports for Geothermal Devel-
opment Projects," which outline in detail the material to be included.
Further useful information may be found in "Geothermal Handbook" prepared by
the U. S. Fish and Wildlife Service.
Environmental impact statements often require detailed field and analyti-
cal work and result in long comprehensive reports.
Fish and Wildlife Coordination Act; Endangered Species Act; Wilderness Act;
and Marine Protection, Research and Sanctuaries Act
These federal laws do not directly address pollution control and its
requirements. Instead they allow for prohibition of or advisory action
against certain activities in the interest of preserving wildlife habitats
and esthetic values. They also may allow for or require mitigating measures
where harm may occur.
State and Local Pollution
Control Laws and Regulations
It is not the intent of this document to detail the pollution control
laws and regulations of the various state and local governments. Suffice it
to say that most of these regulations are intimately tied to the implementa-
tion of federal regulations, generally by authority delegated to the states
by the EPA Administrator. Generally, where the EPA Administrator feels that
such delegated authority is not being implemented satisfactorily, he may
retrieve or retain that authority. It is important to note that state and
local regulations may impose restrictions on pollution discharges and emis-
sions beyond those required by federal law, but may not be less restrictive.
Thus far, because federal laws are relatively weak, state and local
regulations have dominated in control of (1) solid wastes and (2) noise from
stationary sources. The degree of federal influence (with state implementa-
tion) will sharply increase in the area of solid wastes under the new Re-
source Conservation and Recovery Act of 1976. The control of noise pollution
from stationary sources, including geothermal development activities, will
likely continue to be at the discretion of state or local regulators, except
for those operations on federal lands controlled by USGS noise regulations
(GRO Order No. 4).
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TECHNICAL REPORT DATA
(Please read Instructions on the reverse before completing)
1. REPORT NO.
EPA-600/7-78-101
3. RECIPIENT'S ACCESSIOONO.
4. TITLE AND SUBTITLE
Pollution Control Guidance for
Geothermal Energy Development
5. REPORT DATE
June 1978 issuing date
6. PERFORMING ORGANIZATION CODE
7. «iUTHOR(S)
Robert P. Hartley
8. PERFORMING ORGANIZATION REPORT NO.
9. PERFORMING ORGANIZATION NAME AND ADDRESS
Same as below
10. PROGRAM ELEMENT NO.
INE610
11. CONTRACT/GRANT NO.
N/A
12. SPONSORING AGENCY NAME AND ADDRESS
Industrial Environmental Research Lab- Cinn., OH
Office of Research and Development
U. S. Environmental Protection Agency
Cincinnati. Ohio 4S?6ft
13. TYPE OF REPORT AND PERIOD COVERED
In House
14. SPONSORING AGENCY CODE
EPA/600/12
15. SUPPLEMENTARY NOTES
16. ABSTRACT
This report summarizes the EPA regulatory approach toward geothermal energy
development. The state of knowledge is described with respect to the constituents
of geothermal effluents and emissions, including water, air, solid wastes, and noise.
Pollutant effects are discussed. Pollution control technologies that may be appli-
cable are described along with preliminary cost estimates for their application.
Finally discharge and emission limitations are suggested that may serve as interim
guidance for pollution control during early geothermal development.
7.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b.lDENTIFIERS/OPEN ENDED TERMS
c. COSATI Field/Group
Geothermal prospecting
Electric power plants
Pollution
Heating
Air pollution
Water pollution
Regulations
geothermal energy
pollution control
97G
68D
8. DISTRIBUTION STATEMENT
RELEASE TO PUBLIC
19. SECURITY CLASS {ThisReport)
UNCLASSIFIED
21. NO. OF PAGES
146
20. SECURITY CLASS (Thispage)
UNCLASSIFIED
22. PRICE
EPA Form 2220-1 (9-73)
134
*U.S.COVDll«BITPminiKOOfnCfcia7B— 757-140/6823
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