&EPA
United States
Environmental Protection
Agency
Industrial Environmental Research
Laboratory
Cincinnati OH 45268
EPA 600 7-79-225
October 1979
Research and Development
Preliminary Cost
Estimates of
Pollution Control
Technologies for
Geothermal
Developments
Interagency
Energy/Environment
R&D 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-600/7-79-225
October 1979
PRELIMINARY COST ESTIMATES OF POLLUTION CONTROL
TECHNOLOGIES FOR GEOTHERMAL DEVELOPMENTS
by
R. Sung, G. Houser, G. Richard,
J. Cotter, P. Weller, and E. Pulaski
TRW Environmental Engineering Division
Redondo Beach, California 90278
Contract No. 68-03-2560
Project Officer: Ivars J. Licis
Technical Project Monitor: Robert 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 publication.
Approval does not signify that the contents necessarily reflect the views and
policies of the U.S. Environmental Protection Agency, nor does mention of trade
names or commercial products 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 cost estimates for
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
m
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ABSTRACT
The utilization of geothermal resources for electrical power generation
may contribute to energy production in the near future. A substantial capi-
tal investment will be required to control air and water pollutant emissions
from geothermal power plants. This study is a preliminary investigation of
the costs incurred in controlling H2S emissions and treating waste fluids with
a variety of applicable control technologies. Estimates include capital and
operational/maintenance costs.
Air pollution control cost estimates for F^S abatement utilizing the
Stretford, EIC, Dow oxygenation, and iron catalyst processes have been devel-
oped. These process control technologies are in various stages of develop-
ment, ranging from laboratory testing of a pilot unit to operating field in-
stallations. The location of a H2S abatement unit in the power production
process is dictated by the specific control technology used. Condenser
ejector gases are controlled utilizing the Stretford process; the EIC process
scrubs geothermal steam upstream of the power plant; geothermal brine is
treated by the Dow oxygenation process; and the iron catalyst process is
applied to geothermal steam condensation equipment (direct contact condenser
and cooling tower water). The cost is 2.1 mills per KWH for the Stretford
process and is 1.25 mills per KWH for the Iron Catalyst process under the
following conditions: HoS concentration of 220 ppm, steam flow of 907,000
kg/hr, pressure of 7.8 arm, and a temperature of 180°C. The cost for the EIC
process is 3.6 mills per KWH at 830 ppm H2S, 150°C, 11.9 atm and 71,000 kg/hr
of steam. Depending on the type of mixers used, the cost for the Dow Oxygena-
tion process is 9.2 mills per KWH for in-line mixers and is 8.6 mills per KWH
for concurrent packed tower under the following operating conditions: 500 ppm
H2S, double flash conversion system, brine temperature of 177°C and pressure
and brine flow of 11.2 atm and 100,000 1pm respectively. Due to the vari-
ability of application of the control technologies and the "site-specific"
data base, it is difficult to make a conclusive comparison of H2S control
technology costs with the information presently available.
Cost estimates for water treatment technologies were developed based on:
brine flow rates, raw geothermal brine concentrations, and discharge brine
concentrations. Sedimentation, chemical precipitation and filtration process
costs were generated for preliminary treatment of geothermal brines. Cost
estimates for additional treatment including reverse osmosis, electrodialysis,
ion exchange, and evaporation processes for the reuse of treated brine were
developed. Injection, ocean disposal, evaporation ponds, and land application
(utilized for brine disposal) costs were estimated. Costs for treatment and
disposal of sludge generated by brine treatment technologies were also deter-
mi ned .
IV
-------
The type and cost of brine treatment technologies required for geothermal
energy conversion processes are dependent upon the concentration of constitu-
ents and the degree to which these constituents must be removed. Subsurface
injection of geothermal brines appears to be the most economical and techni-
cally feasible alternative. Minimal treatment is necessary for subsurface
injection; sedimentation may be sufficient for low or moderate salinity brines;
high salinity brine requires additional treatment.
Treatment of brine for disposal by sedimentation is significantly less
costly than technologies required for brine reuse. For a geothermal waste-
water flow of 120,000 liters per minute, the cost of treatment is most eco-
nomical for sedimentation (at 0.4 cents/1000 liters) and is most expensive for
reverse osmosis (at 12.9 cents/1000 liters).
Existing discharge regulations result in prohibitive treatment costs for
ocean disposal of geothermal brines. Treatment of geothermal brines with
evaporative systems (multiple stage evaporators or compression stills) is
not economically attractive or technically feasible. Exorbitant costs
result for sludge disposal if brines are treated sufficiently for reuse
purposes.
As stated previously, the cost estimates presented in this report are pre-
liminary and should not be construed as firm estimates. Further investiga-
tion and study are required to develop more accurate costs information. The
costs for brine treatment processes were derived from data based principally
on municipal wastewater treatment systems. The use of these data to develop
costs for geothermal -rine treatment systems requires additional investigation
to validate their technological and economic applications.
Treatability studies to demonstrate the performance of air and water con-
trol technologies evaluated in this report are recommended over a range of
operating conditions expected to exist at geothermal sites. Research and
development of additional control technologies should be encouraged to con-
tinue. For example, with additional investigation, the Deuterium H2S removal
process may prove to be economically and technically attractive.
The long-term feasibility of subsurface injection of brine should be
determined. If long-term injection is not practical, the alternatives (drill-
ing additional wells to continue subsurface injection or more efficient brine
treatment) may incur additional pollution control costs.
Removal of boron (frequently existing in geothermal brines) has not been
demonstrated to be technically feasible at the present time. Recent research
and development studies utilizing specific adsorbents or foam separation have
shown significant promise.
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CONTENTS
Foreword iii
Abstract iv
Figures viii
Tables xi
Acknowledgments xiii
1. Introduction 1
2. Conclusions 2
3. Recommendations 5
4. Potential Geothermal Conversion Processes and Associated
Waste Streams 7
Geothermal energy conversion systems 7
Identification of air pollutant emission sources 12
Identification of water pollution discharge sources ... 13
5. Air Pollution Control Technology Evaluations and Cost
Estimates 15
Stretford process 16
Iron catalyst process 22
EIC process 28
Dow oxygenation process 37
Other HgS removal processes 41
6. Water Pollution Control Technology Evaluations and Cost
Estimates 52
Wastewater treatment technologies 52
Wastewater disposal technologies 75
7. Solid Waste Generation and Disposal Costs 101
Pollutant loading 101
Waste products generated by pollution control
equipment 101
Cost of sludge disposal 107
References 114
vii
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FIGURES
Number Page
1 Direct steam process 8
2 Flashed steam process 9
3 Binary cycle (flashed steam) process 9
4 Binary cycle (hot water) process 10
5 Total flow process 11
6 Direct heating (closed system) 11
7 Flow diagram of a Stretford process 17
8 Stretford annual cost vs. steam flow rate 21
9 Stretford annual cost vs. power generation 21
10 Stretford annual cost vs HgS concentration 22
11 Iron catalyst hydrogen sulfide removal process 23
12 Iron catalyst cost vs. steam flow rate 27
13 Iron catalyst annual cost vs. power generation 27
14 Iron catalyst annual cost vs. H2S concentration 28
15 EIC hydrogen sulfide removal process with regeneration by
roasting 29
16 EIC hydrogen sulfide removal process with regeneration by
leaching 30
17 EIC annual cost vs. steam flow rate 35
18 EIC annual cost vs. power generation 36
19 EIC annual cost (mill/KWH) vs. H2S concentration 36
20 Dow oxygenation hydrogen sulfide removal process with in-line . 37
21 Dow oxygenation sulfide removal process with cocurrent packed
tower 38
22 Dow oxygenation - in-line system annual cost vs. brine flow
rate 44
23 Dow oxygenation - packed column system annual cost vs. brine
flow rate 44
24 Dow oxygenation - in-line system annual cost vs. power
generation 45
25 Dow oxygenation packed system annual cost vs. power
generation 45
26 Dow oxygenation - in-line system annual cost vs. HpS
concentration 46
vi ii
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27 Dow oxygenation - packed column annual cost vs. HLS
concentration 46
28 Solid sorption hydrogen sulfide removal process 48
29 Glaus sulfur recovery process 48
30 Cut-away view of a granular mixed-media filter 55
31 Cost estimates for sedimentation 59
32 Cost estimates for chemical precipitation with single-stage
lime addition 59
33 Cost estimates for chemical treatment 2-stage lime addition. . 60
34 Cost estimates for chemical precipitation with alum addition . 60
35 Cost estimates for chemical precipitation with ferric chloride
addition 61
36 Cost estimates for filtration 61
37 Schematic presentation of reverse osmosis 62
38 Cost estimate for reverse osmosis system 63
39 Electrodialysis cell 64
40 Cost estimates for electrodialysis system 65
41 Mixed-bed ion exchange process 66
42 Cost estimates for ion exchange system 67
43 Multiple-effect evaporation 68
44 Multiple-stage flash evaporation 68
45 Compression still 69
46 Total costs for evaporation. Basis: 50% of feed evaporated;
40°C feed temperature 70
47 Application of treatment technologies for achieving three
effluent quality levels from high level waste 76
48 Application of treatment technologies for achieving three
effluent quality levels from mid level waste 77
49 Application of treatment technologies for achieving three
effluent quality levels from low level waste 78
50 Typical injection well set-up 80
51 Well hole size cost comparison (capital cost only) 83
52 Annualized capital cost Tor injection of geothermal wastewaters 89
53 Annualized cost of installation of wastewater conveyance lines
for open country routing 92
IX
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54 Annual cost of pumping wastewater for head of 40 ft (12 m)
to 100 ft (30 m) 92
55 Cost of conveyance lines for ocean outfalls offshore to depths
of 200 feet (61 m) 93
56 Cost of ocean outfall diffuser 93
57 Total annual cost of evaporation ponds versus surface area. ... 97
58 Annualized investment cost of spill containment ponds (10 foot
depth) 100
59 Hydrogen sulfide loading rate to turbine as a function of steam
flow rate 102
60 Wastewater polluntant loading for direct steam power generation
system 102
61 Wastewater pollutant loading for flashed steam, binary, total
flow power generation system 102
62 Wastewater pollutant loading for direct heating, open and closed
systems 103
63 Wastewater pollutant loading for desalination system 103
64 Sulfur generation from Stretford unit for various stream flow
rates through turbine 106
65 Potential solid waste as sludge generated by Dow oxygenated
system. *(Brine flow rate is gpm) 106
66 Sludge generation from EIC process for various steam flow rates
through turbine 106
67 Sludge generation from iron catalyst process for various steam
flow rates through turbine 106
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„ u TABLES
Number Page
1 Air Pollutant Emission Sources 14
2 Water Pollutant Discharge Sources 14
3 Stretford Annual Costs Vs. Steam Flow Rate (220 ppm HgS). ... 20
4 Stretford Annual Costs Vs. Hydrogen Sulfide Concentration in
Steam. 907,000 kg/hr Steam Flow Rate 20
5 Iron Catalyst Annual Cost Vs. Steam Flow Rate. (220 ppm H2S). . 26
6 Iron Catalyst Annual Cost Vs. Hydrogen Sulfide Concentration in
Steam. (907,000 kg/hr Steam Flow Rate) 26
7 EIC Annual Cost for 50 MW and 500 MW Plants (EIC, 1976). 830 ppm
H2S 34
8 EIC Annual Cost for 50 MW Plant Vs. Hydrogen Sulfide Concentration
in Steam 35
9 Dow Oxygenation Annual Cost* for In-Line System Vs. Geothermal
Brine Flow Rate. 40 ppm HgS 42
10 Dow Oxygenation Annual Cost* for Packed Column System Vs.
Geothermal Brine Flow Rate 40 ppm HgS 42
11 Dow Oxygenation Annual Cost for 100,000 1/Min In-Line System Vs.
Hydrogen Sulfide Concentration in Geothermal Brine 43
12 Dow Oxygenation Annual Cost for 100,000 1/Min Packed Column
System Vs. Hydrogen Sulfide Concentration in Geothermal Brine . 43
13 Flow Variable Cost Elements for Wastewater Treatment 56
14 Assumptions Used to Determine Wastewater Cost Curves for Pre-
treatment and Ion Exchange 57
15 Component Costs for Evaporation 71
16 Reported Efficiencies of Control Technologies for Treatment of
Specific Constituents from Wastewaters (percent removal). ... 72
17 Assumed Geothermal Waste Brine and Surface Water Discharge
Concentrations (mg/1) 73
18 Geothermal Waste Brine Flow Rates and Levels for Various Uses . 73
19 Removal Efficiencies (%) Required for Treating Various Levels
of Raw Geothermal Fluids 74
20 Assigned Efficiencies of Various Treatment Systems for Removing
Gross Constituents 74
21 Capital Cost of Injection Wells, Data from the Literature ... 84
22 Average Capital Cost for an Injecti.on Well 86
xi
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23 Survey of 124 Injection Wells for Disposal of Liquid Waste
(NIPCC, 1971) 87
24 Survey of 75 Injection Wells for Disposal of Liquid Waste
(NIPCC, 1971) 87
25 Capital Costs for Injection Systems at Four Well Capacities. . . 88
26 Operating Energy Cost for Pumps 91
27 Normalized Cost of Ocean Disposal of Geothermal Plant
Wastewaters ($71000 1/min) 94
28 Estimated Water Surface Area Required for Disposal of
Geothermal Wastewaters 95
29 Estimated Maximum Hydraulic Loading of Wastewater Effluent for
Various Soil Textures (Ideal Conditions) 98
30 Annual Cost of Disposal of Geothermal Wastewaters by Land
Spreading 99
31 Solids Removal Rate Accomplished by Wastewater Cleanup Systems . 108
32 Sludge Generation Rates Associated with Cleanup of Geothermal
Wastewaters 108
33 Sludge Generation Rate (Metric Tons/Day) as a Function of Flow
Rates for Specified Conversion Processes 109
34 Cost of Landfill for Geothermal Wastewater Treatment Sludges . . Ill
35 Total Annual Cost of Waste Sludge Treatment, Removal and Disposal
at "Median" Sludge Generation Rates 112
36 Land Requirement and Cost of Sludge Evaporation Ponds 113
xi i
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ACKNOWLEDGMENTS
TRW is most appreciative of the cooperation and helpful guidance Mr. R.
Hartley has provided throughout the progress of this project. Special thanks
are also due to Mr. A. Sims of Ben Holt Co., Mr. R. Smith of EPA, and Mr. M.
Griebe of Ralph M. Parsons Co. for their valuable technical input. This
report could not have been completed without the unqualified support of the
following individuals: Mrs. Pat Conant, Ms. Joni Nagle, and Mrs. Carol Ewer.
xiii
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SECTION 1
INTRODUCTION
The development of geothermal resources as an alternative energy resource
is not without environmental concern. Extraction and processing of geothermal
fluids can result in undesirable air emissions, toxic pollutant discharges
and contamination of surface and subsurface waters, potential land subsidence,
seismic activity, noise pollution, and possible blowouts of producing wells.
The uncertainties of these potential environmental problems have led to vari-
ous studies undertaken by the geothermal industries, the Department of Energy
(DOE) and academia (through federal and industrial funding) to develop control
measures.
The Environmental Protection Agency (EPA) has taken an Initial step
towards the establishment of regulatory standards for the geothermal industry
by preparing a document entitled "Pollution Control Guidance for Geothermal
Energy Development". This report supports that document by providing pollu-
tion control cost information.
The objective of this report is to provide preliminary cost estimates for
air and water pollution treatment and disposal technologies applicable for geo-
thermal energy conversion systems. Cost estimates include both annualized
capital investment and operation and maintenance (O&M) costs for various levels
of environmental requirements.
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SECTION 2
CONCLUSIONS
This study is an effort undertaken by TRW to provide preliminary cost
estimates for applicable air and water pollution control systems. The asso-
ciated costs for the handling and disposal of solid wastes were also evalu-
ated. The culmination of the study produced the following conclusions.
AIR POLLUTION CONTROL
t The control technologies available for hydrogen sulfide (principal
air pollutant) abatement are in various stages of technical develop-
ment, ranging from field installations to preliminary design concepts.
At present, the Stretford, EIC and Dow Oxygenation processes appear
to be the most feasible control technologies.
t The cost of H£S abatement at a power generation rate of 10,000 KW is
2.1 mills per KWH for the Stretford process and is 1.25 mills per KWH
for the Iron Catalyst process under the following conditions: H?S con-
centration of 220 ppm, steam flow of 907,000 kg/hr, pressure of 7.8 atm,
and a temperature of 180°C. The cost for the EIC process is 3.6 mills
per KWH at 830 ppm h^S, 150°C, 11.9 atm and 71,000 kg/hr of steam and
a power generation rate of 10,000 KW. Depending on the type of mixers
used, the cost for the Dow Oxygenation process is 9.2 mills per KWH
for in-line mixers and is 8.6 mills per KWH for cocurrent packed tower
under the following operating conditions: 500 ppm H2$, double flash
conversion system, brine temperature of 177°C and pressure and brine
flow of 11.2 atm and 100,000 1pm respectively. Comparisons of cost
estimates should not be made without consideration of these baseline
differences.
0 The primary sources of hydrogen sulfide emissions from geothermal elec-
tric power generation processes are cooling towers and condenser
ejectors. Hydrogen sulfide dissolved in the cooling water and conden-
sate steam can be removed by the iron cataoyst process. Efficiency of
removal by this process is still under investigation.
• Hydrogen sulfide emissions from condenser ejector gases can be effec-
tively controlled by utilizing the Stretford process. However, the
Stretford process for H?S abatement requires the use of a surface
condenser rather than the conventional direct contact condenser.
• Dow Oxygenation process can remove H?S from unf lashed geothermal brine
and is applicable only to liquid-dominated resources.
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WATER POLLUTION CONTROL
• Wastewater treatment technologies required for geothermal conversion
processes are highly dependent on the concentrations of constituents
present and the quantities of pollutants in the waste stream that must
be removed.
• Because of the prevailing environmental discharge regulations, dis-
posal of high salinity geothermal wastewaters by direct ocean dis-
charge or land application will probably not be generally adequate
without costly treatment.
a Subsurface injection appears to be economically and technically
feasible for the disposal of excess wastewater and concentrated brine.
Minimum treatment of the geothermal wastewater is required by this
method. For low and moderate salinity geothermal fluids, sedimentation
may be the only treatment necessary prior to its disposal. High
salinity geothermal fluids may require additional treatment.
• Costs for chemical precipitation and filtration are substantially less
than costs for treatment processes such as reverse osmosis, ion ex-
change or electrodialysis. For a geothermal wastewater flow of 120,000
liters per minute, the cost of treatment is most economical for sedi-
mentation (at 0.4 cents/1000 liters) and is most expensive for reverse
osmosis (at 12.9 cents/1000 liters). The cost for subsurface injection
at the same wastewater flow is estimated at 1.3 cents/1000 liters of
water injected.
a The use of evaporative systems (multiple stage evaporators or compres-
sion stills) for complete treatment of geothermal fluids is both eco-
nomically unattractive (more than 10 times as costly as ion exchange
process) and technically infeasible because of corrosion and scaling
problems. The direct cost for disposal of geothermal fluids by ocean
disposal is likely to be prohibitive even when environmental regulatory
requirements are ignored, because the distance from the ocean, and
large quantities of water compared to the economic value of energy
produced.
t In arid regions, where fresh water supplies are at a premium, treatment
of a portion of the spent geothermal fluid for reuse may be a viable
alternative to complete disposal by subsurface injection.
• The wastewater control technologies discussed in this report are
applicable for low and medium salinity geothermal fluids. The eco-
nomics as well as the applicability of these treatment systems for
removing pollutants from high salinity geothermal fluids need further
Investigation. In particular, the technology for boron removal (from
geothermal fluids) is still under research and development; as such
there is no proven technology for effective removal of boron at present.
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SOLID WASTE DISPOSAL
• Sludge generated from the various wastewater treatment systems is high-
ly dependent on the flow rate and the nature of the geothermal brine
to be treated.
• Sludge disposal cost can be prohibitive for the treatment of high level
waste for either disposal or reuse purposes. If subsurface injection
is to be used for the disposal of spent geothermal fluids, the cost of
sludge disposal can be substantially reduced by incorporating treatment
processes which can minimize sludge production such as acidification
and/or chelation of the wastewater.
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SECTION 3
RECOMMENDATIONS
Based on the findings and conclusions of this report, the following
recommendations are made:
0 The pollution control cost estimates presented in this report should
be viewed only as preliminary. Since most of the data were derived
from municipal and industrial applications other than geothermal
developments, cost data should be updated and revised as necessary
when they become available.
• Air pollution cost estimates presented in this report for the
Stretford, EIC, Dow Oxygenation and Iron Catalyst processes in HoS
control were based on specific plant operating conditons. In order
to prepare cost estimates for other geothermal manifestations with
varied operating conditions, site-specific detailed laboratory or
pilot plant data should be developed.
• Research and development of additional t^S emission control tech-
nologies should continue. l^S is highly reactive making it
especially amenable to process research.
a Additional study should include an evaluation of the technical and
economic feasibility of combining individual air pollution control
technologies to abate H2S emissions from geothermal conversion pro-
cesses. As an example, Dow Oxygenation and EIC processes might be
applied to the brine and steam respectivley in a flash energy
conversion system.
• For air emission control from geothermal developments, further investi-
gation should include both technical and economic evaluations of
abatement of other air pollutants such as methane, ammonia and carbon
monoxide.
• The effectiveness and economics of the water pollution control systems
were based primarily on data derived from treatment of wastewater
significantly different from that expected in a geothermal development.
Additional programs should, therefore, include treatability studies
of the geothermal waste fluid including low, medium and high salinity
waters by using the control technologies discussed in this report,
and other innovative technologies.
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t The applicability of reverse osmosis as a candidate geothermal
wastewater treatment system for achieving the various effluent quality
requirements needs to be demonstrated.
• Although effective boron removal has not been demonstrated in commer-
cial scale operations, recent research and development studies by
specific adsorbents and foam separation processes have shown signifi-
cant promise. These programs should be encouraged to include both
technical and economic feasibility evaluations.
• Sludge disposal appears to be a major cost constraint in waste brine
treatment for compliance with potential effluent quality requirements,
particularly for high salinity geothermal waters. Additional studies
should focus on technologies minimizing or eliminating sludge pro-
duction, such as acidification, metal chelation, etc.
a Subsurface injection appears to be the best alternative for waste
brine disposal. To minimize the cost for injection, it is recommended
that pumping tests be performed at potential geothermal sites to
determine the minimum wastewater quality requirements for injection.
• The cost of pollution control processes depends greatly on the quality
of the wastewaters and steam. Additional research is needed to
characterize the geothermal fluid resources. This information may
permit the assessment of the cost of control equipment by specific
geographic region.
• Detailed studies are needed to better understand subsurface injection
cost as a function of the various cost determinants (e.g., drilling
depth, lithoiogy, etc., which would affect drilling costs).
a The cost and feasibility of pollution control equipment is dependent
greatly on the energy conversion efficiency of the plant and the
utilizable energy in the geothermal resources. Data are needed to
relate plant efficiency, geothermal resource quality, and pollution
control cost per unit of energy generation.
• Before definitive effluent discharge requirements for the geothermal
industry are adopted, it is recommended that demonstration studies be
conducted to validate the effectiveness and economics of the control
technologies presented in this report.
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SECTION 4
POTENTIAL GEOTHERMAL CONVERSION PROCESSES AND ASSOCIATED WASTE STREAMS
GEOTHERMAL ENERGY CONVERSION SYSTEMS
Geothermal resources may exist as steam (vapor-dominated resources), but
the major geothermal resources to be developed in the United States will most
likely exist as hot water (liquid-dominated resources). Air and water pol-
lutant emission sources from geothermal developments are dependent upon the
resource type and the energy conversion process used. In addition to direct
heating, five types of power generation are under development: (1) direct
steam turbine, (2) flash steam turbine, (3) flash steam binary cycle, (4) hot
water binary cycle, and (5) total flow turbine systems (Cheremisinoff, 1976,
and Library of Congress, 1974),
Direct Steam Turbine Power Generation
Electrical power is produced from vapor-dominated geothermal resources by
expanding the steam through a turbine coupled to a generator. Turbines are
designed to operate on relatively low steam temperatures and pressures com-
pared to those utilized for conventional fuel-fired power generation. A cen-
trifugal separator, upstream of the turbine, removes particulate matter. A
barometric contact condenser or a surface condenser 1s generally used to con-
dense the steam from the turbine at sub-atmospheric pressure to Increase tur-
bine efficiency. The condenser is equipped with an ejector to remove the
noncondensible gases. The condenser fluid, condensate plus cooling water,
may be pumped to a forced-draft cooling tower, and then back to the condenser
to cool incoming steam. Excess cooling water may be subsurface-injected or
discharged to the surface. A surface condenser or dry cooling tower can be
substituted for the respective equipment described above. A schematic diagram
of the direct process 1s shown in Figure 1.
Flashed Steam Turbine Power Generation
Steam for power generation from liquid-dominated geothermal resources is
obtained by partial flashing of the liquid to a lower pressure. The flash
chamber also acts as a centrifugal separator to remove liquid and particulates
from the steam. The remaining brine can be: flashed again if Us temperature
is sufficiently high; subsurface-injected; or discharged on the ground sur-
face. The separated steam is expanded through a turbine coupled to a generator.
A barometric condenser and cooling tower may be utilized in the same manner
as described for the previous system. A surface condenser may not be appro-
priate because of a two-phase flow. This condition may create problems for
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BAROMETRIC
CONDENSER
COOLING TOWER
OR EXTERNAL
COOLING SOURCE
IF AVAILABLE
BRINE
WATER-
Figure ]. Direct steam process.
the condenser and the pump because of the non-condensible gases. A flashed
steam system 1s depicted 1n Figure 2.
Binary Cycle - (Flashed steam to heat a secondary working fluid)
Steam obtained by flashing geothermal liquid, 1s passed through heat
exchangers (boiler and superheater) to vaporize a low boiling point secondary
fluid, such as Isobutane. The high-pressure secondary fluid vapor 1s expand-
ed through a turbine coupled to a generator. The secondary fluid vapor ex-
hausted from the turbine 1s condensed and pumped back to the heat exchangers
at a high pressure. The steam used 1n the heat exchangers 1s condensed and
the no neon dens 1b1e gases removed. BHne from the flash separator and steam
condenser Is Injected or discharged above ground. The steam condensate may be
passed through a cooling tower and recycled to provide condenser coolant for
both the working fluid and flashed steam. A binary cycle flashed steam system
Is shown in Figure 3.
Binary Cycle - (Hot water to heat a secondary working fluid)
Hot geothermal water is used directly to vaporize a secondary fluid by
circulating both countercurrently through a boiler and superheater. The
high pressure secondary fluid vapor is expanded through a turbine coupled to
8
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BAROMETRIC
•tH |
CONDENSER
COOLING
TOWER
T
FLASH CHAMBER
AND SEPARATOR
/
BRINE
DOWN HOLE
PUMP
BRINE
NOTE; SEPARATOR DISCHARGE BRINE
CAN BE FLASHED IF ITS
TEMPERATURE IS SUFFICIENTLY
HIGH
Figure 2. Flashed steam process.
WORKING FLUID VAPORv
f ^\
£
CONDENSER
WORKING
I SUPER- FLUID
I HEATER BOILER
h^
L
STEAM
1
AND SEPARATOR
*- BRINE
H
DOWN HOLE
PUMP
COOLING
TOWER
BAROMETRIC
CONDENSER
Figure 3. Binary cycle (flashed steam) process,
BRINE
-------
a generator. The secondary fluid vapor exhausted from the turbine 1s condensed
with coolant from a cooling tower, and pumped back to the heat exchangers at a
high pressure. The spent geothermal water 1s Injected or discharged on the
surface. This system differs from those described previously 1n that cooling
water must be supplied from an outside source. A flow diagram of the binary
cycle hot water system 1s illustrated 1n Figure 4*
Total Flow Turbine Power Generation
A total flow geothermal energy conversion system utilizes an over-pres-
surized hot water resource. The geothermal fluid 1s allowed to expand as it
ascends to the surface. The fluid then passes through a pressure-reducing
nozzle to Increase Its velocity. The kinetic energy of the fluid drives an
impulse turbine coupled to an electric generator. The impulse turbine re-
quires special design and materials of construction to minimize erosion and
corrosion caused by direct contact with the geothermal fluid. The turbine
discharge fluid may be injected or discharged above ground. Coolant 1s not
required in the system; thus there 1s no cooling water discharge. A schematic
diagram of this total flow system 1s shown in Figure 5.
Direct Heating
Low to moderate temperature (<90°C) geothermal resources, not suitable
for power generation, may be used in a variety of direct heating applications.
Such applications Include space heating, Industrial process heat, crop drying,
soil warming, etc. In most cases the heat is extracted by heat exchangers and
the spent fluid 1s Injected or discharged on the surface. An example process
for direct heating 1s shown 1n Figure 6.
I
WORKING FLUID VAPOR-^
f "
COOLING
I TOWER
MAKE-UP
WATER
BRINE
DOWN HOLE
PUMP
Figure 4. B1mry cycle (hot water) process.
10
-------
GENERATOR
BRINE
IMPULSE
TURBINE
PRESSURE
REDUCING
NOZZLE
. BRINE EXPANDS
JO SURFACE
Figure 5. Total flow process.
HOT WATER
STORAGE
HEAT EXCHANGERS
HOT WATER
SUPPLY
DOWN HOLE
PUMP
BRINE
Figure 6. Direct heating (closed system),
11
-------
Low-temperature geothermal resources can be used for agricultural land
application, providing the salt content 1s suitable for plant life. Purposes
may include frost prevention, plant nutrition and simple irrigation. The heat
and carbon dioxide from the geothermal resource can be contained in a green-
house to increase plant growth or crop yield throughout the year.
Desalination - (For mineral and/or water recovery)
Due to the high temperatures of many geothermal resources, they may con-
tain high concentrations of valuable minerals. If economically profitable,
mineral recovery alone could justify geothermal resource development. Mineral
recovery may, 1n some cases, reduce the cost of a wastewater treatment process
for power production. Various desalination processes can produce fresh water
suitable for secondary uses. The Bureau of Reclamation has several programs
under Investigation at the East Mesa plant, California, for desalting geo-
thermal fluids to supplement the Colorado River. Evaporation, distillation,
reverse osmosis, electrodialysis, etc. are applicable desalination processes.
IDENTIFICATION OF AIR POLLUTANT EMISSION SOURCES
For geothermal energy conversion systems the major sources of air emissions
are from operations relating to:
t well drilling
• well cleanout
• pipeline venting
• power plant by-pass
• condenser ejector
• cooling tower
Air pollutants will be emitted from energy conversion systems operating on
geothermal steam; they will not be emitted, however, from conversion systems
that do not condense steam (e.g., binary cycle using hot geothermal brine to
heat a secondary working fluid). The principal air pollutants Include non-
condenslble gases and particulate material such as metals. Noncondensible
gases (those that do not condense at normal operating temperatures) 1n geo-
thermal steam vary in concentration from one resource to another and include
the following major constituents: hydrogen sulfide, carbon dioxide, methane,
ammonia, nitrogen and hydrogen. Hydrogen sulfide, which exists 1n essentially
all geothermal steam, 1s the most likely to cause an environmental hazard due
to Its toxlclty and noxious odor. The control technologies for hydrogen
sulfide are discussed 1n detail 1n Section 5.
During well drilling and development of vapor-dominated resources, steam
1s released through well venting to remove debris. Wells may also be vented
periodically during flow testing. Steam traps and separators are vented
to remove condensate. If electrical load decreases or a power unit fails,
steam may be by-passed by venting upstream of the turbine. Free noncondenslble
12
-------
gases are removed from the turbine condenser by a gas ejector to prevent their
accumulation. Those dissolved 1n the condensate can be emitted when the con-
densate-coollng water 1s evaporated 1n the cooling tower. Table 1 summari-
zes the sources of air pollutant emissions for various geothermal energy con-
version systems.
IDENTIFICATION OF'WATER POLLUTION DISCHARGE SOURCES
Water pollutants from geothermal energy conversion systems can be dis-
charged from any one of the following sources:
• steam separator
• flash separator
• cooling tower overflow
t cooling tower blowdown
• brine discharged directly from energy cycle
• venting of wells and pipelines
• once-through cooling
A variety of potentially hazardous materials may be contained in the spent
fluids from each of the conversion processes. In addition to the major
chemical constituents of sodium, chloride and silica, the fluid may also con-
tain dissolved solids, Iron, manganese, boron, zinc, barium, fluoride, lead,
copper, arsenic, mercury, selenium, chromium, silver and cadmium. These
constituents, 1f not probably contained, may create environmental problems
when discharged to receiving streams. In general, the higher temperature
geothermal resources contain higher concentrations of dissolved solIds.
The control technologies for water pollutants are discussed in Section 6.
Water produced in the steam separator contains significant amounts of
dissolved solids and suspended participates. This water 1s normally combined
with the cooling tower overflow and treated for surface discharge or subsur-
face Injection. Conversion systems utilizing flashed steam will emit brine
from the flash separator and cooling tower. Cooling tower water needs to be
blown down periodically to prevent the accumulation of dissolved solids in the
cooling water. Wastewater 1n the form of concentrated brine 1s also dis-
charged from the energy cycle Involving the use of boilers, Impulse turbine
and heat exchangers. In addition, the venting of wells and pipelines and
once-through cooling systems also produce liquid wastes which are potential
sources of pollutants discharge. Table 2 summarizes the probable sources
of water pollutants discharge as they relate to the energy conversion systems
Identified in this section.
13
-------
TABLE 1. AIR POLLUTANT EMISSION SOURCES
Conversion system
Direct steam
Flashed steam
Binary cycle
(flashed steam)
Binary cycle
(hot water)
Total flow
Direct heating
(closed system)
EMISSION SOURCES
Well Well Pipeline
drilling cleanout vent
X XX
X X
X X
Does not utilize steam
Does not separate steam
Does not utilize steam
Power
plant Condenser Cooling
by-pass ejector tower
XX X
XX X
X X
TABLE 2. WATER POLLUTANT DISCHARGE SOURCES
Conversion system
Direct steam
*
Flashed steam
Binary cycle
(flashed steam)
Binary cycle
(hot water)
DISCHARGE SOURCES
Cooling
Steam Flash tower
separator separator overflow
X X
X X
X X
Cooling Brine discharged
tower directly from
blowdown energy cycle
X
X
X
X
Total flow
Direct heating
(closed system)
X
X
14
-------
SECTION 5
AIR POLLUTION CONTROL TECHNOLOGY EVALUATIONS AND COST ESTIMATES
This section discusses air pollution control technologies that are or
may be applicable to air emissions from geothermal energy conversion systems.
It also examines the costs of those technologies to the extent that they can
be determined.
Because the geothermal Industry 1s still in Its early stages of develop-
ment, most of the control technologies described herein either have not been
applied or have been utilized only on a limited scale to geothermal develop-
ments. Thus, their applicability and cost must be considered preliminary
judgements based primarily on the use of those technologies in related
Industries.
Technologies to control air pollution from geothermal operations are
directed primarily at incoming steam, condenser vent emissions and cooling
tower emissions. Although a number of pollutants can be emitted from these
sources, a single pollutant that has caused significant environmental concern
is hydrogen sulfide (HgS). For this reason, the control technologies to
be discussed in the following sub-section are directed towards l^S removal.
Published cost data for the H2S control technologies, directly applicable
to the range of conditions occurring at potential qeo thermal sites, is limit-
ed and in many cases non-existent. These cost estimates were derived from a
particular set of operating parameters at a given flow rate. Several assump-
tions were made to facilitate the evaluation of costs for a control technology
within the range of hydrogen sulfide concentrations and steam or brine flow
rates possibly existing at future geothermal energy conversion sites, oper-
ation and maintenance cost estimates were based on a control system with
stable operation and did not Include any major upset conditions or extended
repair periods. The reference costing data for each control technology and
the assumptions utilized to develop cost estimates for additional operating
conditions are delineated in the following discussion. Costs for disposal
of residuals generated by the hydrogen sulfide control technologies are esti-
mated in Section 7.
Cost estimates were determined for total, installed capital and oper-
ation/maintenance costs. These costs were estimated for (1) varying geo-
thermal steam (or brine) flow rates with a specific hydrogen sulfide con-
centration, and (2) a specific geothermal steam (or brine) flow rate with
varying hydrogen sulfide concentrations. Normalized control costs (cost per
killowatt-hour or cost per unit flow rate) were also estimated for varying
power generation rates with a specific hydrogen sulfide concentration.
15
-------
Costs have been standardized to the end of the second quarter 1977 dollars
by utilizing the Marshall and Stevens process industries average equipment cost
index. Capital costs have been amortized by the capital recovery factor (CRF)
over the estimated life of the control technology equipment at an annual in-
terest rate of 8 percent. Amortizing the cost of the control system over its
anticipated Hfe, and not calculating the reinvestment necessary for a 30-year
operating period, is valid because the cost (in present dollars) for future
replacement of the system is equivalent to that incurred for the initial sys-
tem installation (Grant, 1970). Operating cost for electrical energy consump-
tion is assumed to be 4 cents per killowatt-hour.
STRETFORD PROCESS
The Stretford process is designed to remove H2S from a gaseous stream and
is applicable to geothermal steam conversion processes.
Process Description
A simplified flow diagram of the Stretford process is shown in Figure 7.
The process produces elemental sulfur and 1s applicable to those geothermal
energy conversion processes condensing steam (Laszlo, 1976). Noncondensible
gases from the condenser ejector are scrubbed with an aqueous solution contain-
ing sodium carbonate, sodium metavanadate , and anthraquinone disulfonic add
(ADA). An alkaline solution of sodium carbonate and bicarbonate is produced
with the carbon dioxide present in the scrubbed gas stream. The gas stream 1s
scrubbed countercurrently with the alkaline solution in the absorber, and
hydros ulfide (HS~) 1s formed:
H2S + Na2C03 *
NaHS(aq) -.-Na"1" + HS"
The hydros ul fide is oxidized by 5-valent state vanadate to form elemental
sulfur and 4-valent state vanadate:
HS" + V+5 -*S + V*4
The above reaction is hindered by pH over 9.5, thus the pH 1s controlled 1n
the optimum range of 8.5 to 9.5 by adding sodium hydroxide. Scrubbing solu-
tion 1s regenerated by blowing air into the oxidlzer, and the reduced vana-
date 1s restored to the 5-valent state through a mechanism involving oxygen
transfer by the ADA:
V+4 + ADA -+V*5 + reduced ADA
reduced ADA + 02 -»-ADA + HgO
Air blown into the oxidlzer brings the suspended elemental sulfur to the
surface. The sulfur froth is removed to the skim tank and 1s filtered, cen-
trlfuged, or washed and melted to produce high quality sulfur. The Stretford
16
-------
ABSORBER
CLEAN GAS TO
COOLING TOWER
NONCONDENSIBLE
GAS FROM POWER
PLANT-
REACTION
ZONE
CENTRIFUGATION
AND HEATING
SULFUR TO
STORAGE
FOUL LIQUOR
Figure 7. Flow diagram of a Stretford process.
process removes over 99 percent of the hydrogen sulfide from the condenser off
gases. The overall reaction 1s:
2H2S
2H20
2S
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 1n 1s significantly reduced.
However, with a surface condenser approximately 10 to 20 percent of the
hydrogen sulfide remains 1n solution with the condensate to be stripped out
of solution in the cooling tower and emitted to the atmosphere. Therefore, 1f
a Stretford process 1s applied to a geothermal energy conversion system de-
signed with a surface condenser, 80 to 90 percent of the hydrogen sulfide
existing 1n 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, retrofitting the conventional geo-
17
-------
thermal energy conversion system requires redesigning to include a surface
condenser.
Costs
Stretford process cost estimates are based on the process currently being
designed for installation on the 117.5 MW, unit 14 power plant at the Pacific
Gas and Electric Geysers facility in 1978 (Laszlo, 1976).
The installed capital cost of approximately $2,432,000 was used as a basis
for the Stretford cost estimates presented herein (Laszlo, 1976). The Geysers
unit 14 will produce electrical power from a vapor-dominated resource with the
following operating conditions:
• Steam quality: 180°C (355°F)
: 7.8 atm (114 psia)
: 220 ppm average hydrogen sulfide concentration
: 1200 Btu/lb
0 Steam flow rate: 907,000 kg/hr (2,000,000 Ib/hr)
t Scrubbing efficiency: 99 percent, or greater
All capital costs for the Stretford process include the differential in-
vestment required for a surface condenser in lieu of a direct contact conden-
ser. Capital costs for units with hydrogen sulfide concentration or steam
flow rates differing from those given for The Geysers unit 14 base case can be
computed utilizing the following formulas obtained from Mark Griebe of the
Ralph M. Parsons Company (Griebe, 1977):
IA = IB (||j-) °'4 for: 0.5 < SA < 5 metric tons of sulfur per day
IA - IB (HJ-) °'5 for: 5 < SA < 250 metric tons of sulfur per day
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
Based on the above equations, the capital cost for a Stretford unit is as-
sumed to be exponentially dependent upon the quantity of elemental sulfur pro-
duced. Ninety percent of the total sulfur entering the power plant as hydro-
gen sulfide is assumed to be removed by the Stretford process.
18
-------
The following assumptions were used to estimate the annual capital and
operating/maintenance costs for a Stretford unit:
• Amortization period: 15 years (SRI, 1977)
• Maintenance materials: 2 percent of the installed capital cost
(Griebe, 1977)
• Maintenance labor: 10 percent downtime, requiring a two-man mainte-
nance crew, earning approximately $30 per hour per person
• Electrical power usage: 66 operating BMP per metric ton of sulfur
produced per day (Griebe, 1977)
§ Chemical cost: $35 per metric ton of sulfur produced per day (Griebe,
1977)
0 Sulfur credit: $20 per metric ton
0 Construction site: The Geysers
The accepted market value of commercial grade elemental sulfur is approx-
imately $40 per metric ton. However, the market value is dependent upon the
demand in the vicinity of the geothermal site, and in some areas could be as
low as $3 to $4 per metric ton (Griebe, 1977). Since geothermal sites are
likely to be located in remote areas, a market value of $20 per ton was used
to compensate for transportation and other costs. A credit for the elemental
sulfur produced by the Stretford process was deducted from the annual opera-
tion and maintenance cost.
The Stretford annual costs as a function of steam flow rates ranging from
100,000 kg/hr to 907,000 kg/hr for a constant hydrogen sulfide concentration
are presented in Table 3. Costs as a function of hydrogen sulfide concentra-
tion varying between 220 ppm and 10,000 ppm at a constant steam flow rate are
given in Table 4. Table 3 is based on a hydrogen sulfide concentration of
220 ppm, equivalent to that normally found at The Geysers. Table 4 is based
on a steam flow rate of 907,000 kg/hr, equivalent to that of The Geysers 117.5
MW unit 14. Normalized total, capital, and operation/maintenance annual costs,
based on the estimates given in Table 3 and 4, are presented in Figures 8, 9,
and 10. The costs are based specifically on the design conditions for The
Geysers unit 14 power plant and do not apply to geothermal energy conversion
systems in general. At other geothermal sites, greater or lesser quantities of
steam may be required to produce the same amount of electrical energy. Since
the cost of a Stretford process is a function of the sulfur mass flow rate,
costs will vary from those presented for other geothermal applications.
Figure 8 gives the costs, in dollars per kg/hr of steam, for steam flow
rates varying from 100,000 kg/hr to 907,000 kg/hr and-a hydrogen sulfide con-
centration of 220 ppm. Costs, in mills per KWH, for power generation capaci-
ties ranging from 12.95 MW to 117.5 MW and a hydrogen sulfide concentration
of 220 ppm are presented in Figure 9. The dependency of the Stretford process
costs, in mills per KWH, on hydrogen sulfide concentration in the steam is
shown in Figure 10. Costs were estimated for hydrogen sulfide concentrations
ranging from 220 ppm (0.022 percent) to 10,000 ppm (1.0 percent). A cost es-
19
-------
TABLE 3. STRETFORD ANNUAL COSTS VS. STEAM FLOW RATE.
(220 ppm H2S)
Steam Flow Rate (kg/hr)
Costs ($)
Annual Capital
Maintenance Material
Maintenance Labor
Electrical Power
Chemicals
Sulfur Credit
Total 0 & M Cost
Total Annual Cost
100,000
122,800
21 ,800
50,000
7,200
5,500
-3,100
80,600
203,400
400,000
213,700
36,600
50,000
28,700
21 ,800
-12,500
124,600
338,300
700,000
267,400
45,800
50,000
50,200
38,200
-21 ,800
162,400
429,800
907,000*
284,200
48,700
50,000
58,500
44,500
-25,400
176,300
460,500
NOTE: *Based on The Geysers unit 14 steam flow rate (Laszlo, 1976)
TABLE 4. STRETFORD ANNUAL COSTS VS. HYDROGEN SULFIDE
CONCENTRATION IN STEAM
907,000 kg/hr STEAM FLOW RATE
Costs ($)
Annual Capital
Maintenance Material
Maintenance Labor
Electrical Power
Chemicals
Sulfur Credit
Total 0 & M Cost
Total Annual Cost
220
284,200
48,700
50,000
58,500
44,500
-25,400
176,300
460,500
ppm H2S
2000
857,400
146,800
50,000
531 ,900
405,300
-231 ,600
902,400
1,759,800
10,000
1,916,700
328,100
50,000
2,658,300
2,025,500
-1,157,400
3,904,500
5,821,200
NOTE: A 50,000 ppm (5% by weight) H«S concentration at the given steam flow rate,
results in a sulfur production rate beyond the range of this cost estimate.
20
-------
OPERATING &
MAINTENANCE
100,000
1.000,000
STEAM FLOW RATE
(kg/hr)
Figure 8. Stretford annual cost vs. steam flow rate
in
8
220 ppm HgS
Steam conditions:
180-C (355»F)
7.8 ATM (114 psla)
OPERATING &
MAINTENANCE
o.l
10,000 100,000
POWER GENERATION (KWH)
Figure 9. Stretford annual cost vs. power generation
21
-------
10.0
907.000 kg/hr (2.000.000 Ib/hr) st
-------
/\
NONCONDENSIBLE
GASES FROM
CONDENSER EJECTOR
COOLING WATER
RETURNED TO COOLING
CYCLE
SLUDGE -
DISPOSAL
FILTRATION
STEP
SLUDGE
HOLING
TANK
CONDENSATE/COOLING WATER
FROM CONDENSER
COOLING
TOWER
00
BRINE
FERRIC SULFATE
INJECTION
FERRIC SULFATE
STORAGE TANK
Figure 11. Iron catalyst hydrogen sulfide removal process
Ferric sulfate, 1n solution, 1s added to the cooling water, thus oxi-
dizing the hydrogen sulfide contained 1n the aqueous phase. The nonconden-
sible condenser ejector gases are ducted to the cooling tower and hydrogen
sulfide 1s scrubbed by the falling water containing the ferric sulfate cata-
lyst. Operational experience at The Geysers Indicates that, without control,
practically all of the hydrogen sulfide dissolved in the cooling water/conden-
sate stream 1s stripped out Into the air stream as it passes through the
cooling tower. Therefore, any process controlling hydrogen sulfide emissions
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 dis-
solved hydrogen sulfide, thus forming elemental sulfur, water, and ferrous
Ions. The reaction mechanism 1s given below:
H2S(aq) * 2H+ + S
-2
+3
Fe2(S04)3 + 2Fe + 3S04
'2
2Fe
2Fe
*3
+2
* 2Fe
+ 2HH
+2
2Fe+3 + H20
23
-------
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 which is removed from the cooling water by filtration. The original
design for this system at The Geysers facilities included the use of sand
filters; however, significant plugging and maintenance problems have been
encountered. To resolve these difficulties, 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 causes 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. Insoluble salts carried over into the cooling tower blowdown may
cause plugging problems in the injection well, if the blowdown is injected.
The iron catalyst system is the only present control technology 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 was originally projected to be 90 to 92 percent,
Actual field demonstrations by PG&E, however, indicated that the process is at
best only 50 percent efficient in H2S removal. This discrepancy is a result
of two major problems which were not accounted for in the original pilot scale
tests. The first problem was due to H2S concentration differences. In the
original pilot test unit the H2S content was substantially lower than that
found in the demonstration units. The cooling towers in the demonstration
units were not able to adequately oxygenate the cooling waters to achieve more
than 50 percent control. Experiments are currently underway to improve the
iron oxide process removal efficiency by utilizing caustic soda and hydrogen
peroxide as an oxidant source. The second problem was due to mechanical dif-
ficulties associated with the use of the process. Plugging of cooling tower
nozzles/heat exchangers and corrosion of condenser tubes/pipings are major ele-
ments contributing to mechanical failures and loss of efficiency.
Costs
The iron catalyst (or Ferrifloc) system is currently in operation at the
Pacific Gas and Electric Geysers facility on the 110 MW unit 11 and the 27 MW
units 3 and 4. This system has experienced operational difficulties in the
filtration of precipitated sulfur from the cooling water stream (Galeski, 1977),
Due to this filtration problem, sludge thickeners will replace the sand filters
used in the present installation, thereby resulting in an increased capital in-
vestment. The installed capital cost of The Geysers unit 11 iron catalyst sys-
tem is $1,718,000 and was used as a basis for the cost estimates presented
(Laszlo, 1976). The installed capital cost includes a differential estimated
investment of $300,000 for sludge thickeners in lieu of sand filters (Galeski,
24
-------
1977). The operating conditions of the unit 11 power plant are as follows:
• Steam quality : 180°C (355°F)
: 7.8 atm (114 psia)
: 220 ppm average hydrogen sulfide concentration
: 1200 Btu/lb
• Steam flow rate : 907,000 kg/hr (2,000,000 Ib/hr)
Capital costs for iron catalyst systems with steam flow rates differing
from that given above can be calculated using the following formula:
Tfl - TR (STA^O.6
IA - IB UTR-)
STA = Steam flow rate of desired case
STB = Steam flow rate of base case (907,000 kg/hr)
I = Capital investment for the desired or base (A or B) case.
The above equation assumes that the capital investment depends exponentially
on the steam flow rate according to the Williams sixth-tenths rule (Hesketh,
1973). 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 hy-
drogen sulfide concentration. Operation and maintenance costs for electrical
power and chemical usage were 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 due to the operational problems encountered at The
Geysers (Allen, 1977).
The following assumptions were used for the iron catalyst annual capital
and operation/maintenance cost estimates:
• Amortization period: 15 years
0 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 per person
• Electrical power usage: 68 KW per hour (Galeski, 1977)
• Ferric sulfate usage: 0.5 kg ferric sulfate per kg of hydrogen
sulfide, with a loss factor of 20 percent
(Laszlo, 1976)
• Ferric sulfate cost: $0.05 per Ib or $0.11/kg (Galeski, 1977)
• Removal efficiency: 90 to 92 percent
•
Construction site: The Geysers
25
-------
The annual costs for the iron catalyst system as a function of steam flow
rate ranging from 100,000 kg/hr to 907,000 kg/hr for a constant hydrogen sul-
fide concentration, and as a function of hydrogen sulfide concentration vary-
ing from 220 ppm to 50,000 ppm for a constant steam flow rate, are given in
Tables 5 and 6, respectively. Table 5 is based on a hydrogen sulfide concen-
tration of 220 ppm, equivalent to that normally found at The Geysers. Table
6 is based on a steam flow rate of 907,000 kg/hr equivalent to that of The
Geysers 110 MW unit 11. Based on these tables, normalized total, capital and
operation/maintenance annual costs are shown in Figures 12, 13 and 14. Gener-
ation capacities are based specifically on the operating conditions for The
Geysers unit 11 power plant and cannot be applied to geothermal energy conver-
sion systems in general. Figure 14 shows the costs, in mills per KWH, for a
907,000 kg/hr steam flow rate and hydrogen sulfide concentrations varying from
220 ppm (0.022 percent) to 50,000 ppm (5.0 percent).
TABLE 5. IRON
Costs ($)
Annual Capital
Maintenance Material
Maintenance Labor
Electrical Power
Chemicals
Total 0 & M Cost
Total Annual Cost
CATALYST
100,000
53,400
4,600
50,000
2,100
10,200
66,900
120,300
ANNUAL COST VS. STEAM
Steam Flow Rate
400,000
122,800
10,500
50,000
8,400
40,800
109,700
232,500
FLOW RATE.
(kg/hr)
700,000
171,800
14,700
50,000
14,700
71 ,300
150,000
322,500
(220 ppm H2S)
907,000*
200,700 ^
17,180
50,000
19,000
92,400
178,600
379,300
NOTE: * Based on The Geysers unit 11 steam flow rate (Laszlo, 1976)
TABLE 6. IRON CATALYST ANNUAL COST VS. HYDROGEN SULFIDE CONCENTRATION
IN STEAM. (907.000 kg/hr STEAM FLOU RATE)
Costs ($)
Annual Capital
Maintenance Material
Maintenance Labor
Electrical Power
Chemicals
Total 0 & M Cost
Total Annual Cost
220
200,700
17,200
50,000
19,000
92,400
178,600
378,300
H2S
2000
200,700
17,200
50,000
19,000
923,800
1,010,000
1/210,700
ppm
10,000
200,700
17,200
50,000
19,000
4,199,800
4,286,000
4,486,700
50,000
200,700
17,200
50,000
19,000
21,999,800
21,086.000
21,286,700
26
-------
190.000
1.000.000
STEAM FLOW RATE (kg/hr)
Figure 12. Iron catalyst cost vs. steam flow rate
220 ppa HjS
Steta conditions:
180*C (355°F)
7.8 ATM (114 pilt)
10.000
109 000
NHER KNERATNN (HM)
Figure 13. Iron catalyst annual cost vs* power generation
27
-------
907.000 kg/hr (2,000.000 Ib/hr)
180"C (355°F)
7.8 AIM (114 pslt)
0.
0.01
Figure 14. Iron catalyst annual cost vs. H2S concentration
EIC PROCESS
The EIC process removes hydrogen sulfide (H2S) from raw geothermal steam
by scrubbing it with a aqueous solution of copper sulfate upstream of the
power plant (EIC Corp., 1976). The hydrogen sulfide and copper sulfate react
in a scrubber, forming a copper sulfide precipitate. The process is poten-
tially valuable because it can remove hydrogen sulfide from the plant input
steam thus controlling emissions even while the plant may be shut down and
bypassing steam. Another benefit of an upstream scrubbing process is the
reduction of corrosive effects of l^S on the turbine and condensing/cooling
cycle equipment. 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).
Process Description
A simplified flow diagram of the EIC process, with copper sulfate re-
generation by roasting, is shown in Figure 15. Figure 16 shows the process
with regeneration by leaching.
The process consists of three primary operations: scrubbing, liquid/
solid separation, and regeneration. A packed column, sieve tray column, ven-
turi scrubber, or spray scrubber could be used to provide sufficient contact
28
-------
SCRUBBING
ENUOY
RECOVERY
CLEANED
STEAM
RAW
STEAM
HOT
MAKE-UP
SOLUTION]
LIQUID/
SOLID
SEPARATION
MAKE-UP
WATER
ROASTING
AIR
SOLIDS/GAS
SEPARATION
SCRUBBING/
NEUTRALIZATION
VENT LIME
LIQUID/
SOLID
SEPARATION
PURGE
SLURRY
MAKE-UP
SCRUB
SOLUTION
MAKE-UP Cu*
AIR
MAKE-UP
ACID
1 COOLED — |
PURGE
LIQUIDS
SOLUBLES
PURGE
»
1 • r-
\ soilOS •—?—— OFFGAS
. 1
1
1
~~' PRECIPITATE
Co0
CALCIUM
SULFITE
SOUDS
QUENCH/
REDISSOLVE
V
IRON
COPPER-FREE
SOLUBLES
PURGE
9
LIME
NEUTRALIZED
PURGE
SOLID
WASTES
GYPSUM
LIQUID WASTES
DISSOLUTION
Figure 15,
CEMENTATION
AND L/S
SEPARATION
NEUTRALIZATION
LIQUID/
SOLID
SEPARATION
PROCESS
WASTES
DISPOSAL
EIC hydrogen sulfide removal process
with regeneration by roasting
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 geotherm-
al steam is absorbed in an aqueous solution containing dissolved copper sul-
fate and suspended copper oxide particles by the following reaction sequences:
H2S(aq) + H+ + HS"
HS" + H+ + S"2
CuS04(aq) + Cu+2 + S04"2
-2
2H +
Cu« +
bU4
-»• n«3
* CuS
U4
Overal1
reaction CuS04 + H2S—^CuS + H2S04
29
-------
SCRUBBING
INIIOY
RECOVERY
LIOUIO/
SOLID
SEPARATION
IE ACHING
UOUIO/
SOIIO
SEPARATION
PROCESS
WASTES
DISPOSAL
CLEANED
STEAM
RAW
STEAM
MA
HOT MAKE -I
SOLUTION
PURGE
SLURRY
MAKE-UP
SCRUB
SOLUTION
KE-UP Cu* ».
AIR
ft
_ MAKE-U
IP
1
IAK
WATER
, COOLED
PURGE
1* AIR VENT
JJ
'
SOLUBLES
PURGE
E-UP
SOLIDS
LIQUIDS
RECYCLE ACID
1
1
1
i '
. -' PRECIPITATE
LEACHED
SLURRY
REGENERATED
C«S04 SOLUTION
Cu'
1
COPPER -FREE
SULFUR
SOLID
WASTE
GYPSUM
n
NEUTRALIZED 1 1 „«„„,
SOLUBLES
PURGE
PURGE
WASTES
IRON
LIME
DISSOLUTION
CEMENTATION
AND l/S
SEPARATION
NEUTRALIZATION
UOUIO/SOLID
SEPARATION
Figure 16. EIC hydrogen sulffde removal process
with regeneration by leaching.
Overall
npJVaM/ '
HS" •*• H* +
CuO -»• Cu+2
Cu*2 + S'2
2H+ + O"2 -
CuO + H2S-
n T nj
s-2
•* CuS
^ H20
-*CuS
+ H20
30
-------
The two reaction chains given above produce a highly insoluble copper sulfide
precipitate. The reactions given may be only part of the 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 expansion in the turbine.
Copper sulfide slurry purged from the scrubber column is pumped to a cen-
trifuge for liquid-solid separation. The regeneration technique used will de-
termine further requirements of the 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 requiring chemical
flocculants together with filtration to obtain acceptable separation and cla-
rification. To reduce copper sulfate losses, washing of the cake may be re-
quired. Clear liquid from the liquid/solid separation process is returned to
the scrubber.
Fluid-bed roasting burns the copper sul fide/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 •»• CuSO^
CuS + 3/2 02 -> CuO + S02
S02 + 1/2 02 + S03
The 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 sul-
fur trloxide produced in the regeneration step are scrubbed by an ammoniacal
solution. The liquid discharge stream from the sulfur dioxide scrubber 1s
mixed with cooling tower blowdown and injected.
Oxygen pressure leaching 1s another alternative for recovering copper
compounds. The copper sulfide/cuprous sulfide cake requires approximately
two to four hours contact time with pressurized oxygen (100 psla) to obtain
acceptable conversion rates. The copper sulfide 1s oxidized to copper sulfate
and elemental sulfur, the ratio being a function of residence time, pH, and
temperature. If desirable, operating conditions can be controlled to increase
elemental sulfur production in the leaching step. The possible reactions for
copper sulfate regeneration by leaching are:
31
-------
CuS + 2 02 •» Cu+2 + S04"2
Cu2S + 5/2 02 + 2H* -»• 2 Cu"1"2 + SO^"2 + HgO
The possible reactions for elemental sulfur formation are:
CuS + 1/2 02 + 2H+ H. Cu"1"2 + S + H20
Cu2S + 02 + 4H+ -* 2 Cu"1"2 + S + 2H20
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 h^S removal efficiencies generally
over 97 percent. Entrainment of copper from the scrubbed solution into the
steam was less than measurable (<0.05 ppm). In addition to hydrogen sulflde,
approximately 80 percent of ammonia and boric acid were removed. The field
test scrubber was constructed from Carpenter 20 Cb 3 and showed excellent ser-
vice under the field test operating conditions. Corrosion tests with various
stainless steels have shown 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 Report (EIC, 1976) for a 50 MW geothermal
power plant with the following design parameters:
Steam to be treated
Scrubbing efficiency
Regeneration process
Construction site
17,100 kg/hr (37,700 Ib/hr) steam
53,900 kg/hr (118,900 Ib/hr) inerts
830 ppm H2S
150°C (300°F)
11.9 atm (160 psig)
97.5 percent, or greater
Leaching
Well-developed site, adjacent to existing
facilities
The above steam conditions are based on those encountered for vent gases
at the Niland geothermal loop experimental facility, located in Imperial Valley,
California. The estimated installed capital cost of an EIC process removing
hydrogen sulfide from steam utilized in a 50 MW geothermal power plant, oper-
ating with the above conditions, is $4,400,000 (EIC, 1976). Total annual op-
erating cost, including capital, is given in the EIC Annual Status Report as
1.5 mills per KWH for a 500 MW power plant.
32
-------
Capital costs for EIC units with hydrogen sulfide concentrations differ-
ing from that given above for the Nil and facility can be computed utilizing
the following formula:
IA - 0.85 IB (jj|) °'6 + 0.15 IB
HA = Hydrogen sulfide concentration of the desired case
HB = Hydrogen sulfide concentration for the base case (830 ppm)
I = Capital investment for the desired or base (A or B) case
Eighty-five percent of the capital investment for the EIC process involves
reactors, tanks, vessels, heat exchangers, filters, pumps, and other associ-
ated process equipment. The remaining 15 percent of the capital investment
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 (Hesketh, 1973). The
capital investment for the scrubbing tower (15 percent of total) is assumed to
depend upon steam flow rate and is relatively independent of hydrogen sulfide
concentration.
Assumptions used to estimate the annual capital and operation/maintenance
costs for an EIC unit are (EIC, 1976):
t Amortization period: 10 years
• Maintenance materials: 2 percent of the installed capital cost
0 Maintenance labor: 4 operators at $18,000 per year per person
1 maintenance man at $20,000 per year
1 supervisor at $22,000 per year
t 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)
0 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 - $19,000
33
-------
The EIC process annual costs for a 50 MW and 500 MW .geothermal power
plant are given in Table 7. The annual costs for a 50 MW power plant with
hydrogen sulfide steam concentrations varying from 830 ppm to 50,000 ppm are
presented in Table 8. The cost estimates given in Table 7 were derived from
the basic EIC data given for a 50 MW power plant with a hydrogen sulfide con-
centration in the steam of 830 ppm. Capital costs as a function of increased
hydrogen sulfide concentration were calculated, based on the formula given
previously. Operation and maintenance costs for electrical power, water,
chemicals, and process materials were assumed to increase linearly with an in-
crease in hydrogen sulfide concentration. Normalized total, capital and oper-
ation/maintenance annual costs given in Tables 7 and 8 are shown in Figures
17, 18 and 19. The cost estimates presented for the EIC process were develop-
ed from the specific set of operating conditions previously outlined, and may
not necessarily apply to geothermal resources with different operating condi-
tions.
Figure 17 gives the cost, in dollars per kg/hr, for steam flow rates of
71,000 kg/hr to 7,100,000 kg/hr (corresponding to 50 MW and 500 MW) and a
hydrogen sulfide concentration of 830 ppm. Costs, in mills per KWH, for power
generation capacities ranging between 50 MW and 500 MW and a hydrogen sulfide
concentration of 830 ppm are given in Figure 18. Costs, in mills per KWH,
estimated for a generating capacity of 50 MW and hydrogen sulfide concentra-
tions from 830 ppm (0.083 percent) to 50,000 ppm (5.0 percent), are shown in
Figure 19.
TABLE 7. EIC ANNUAL COST FOR 50 MW AND 500 MW PLANTS (EIC, 1976). 830 PPM
Plant Generating Capacity (MW)
Costs ($) 50 500
Annual Capital 655,700 3,725,800
Maintenance Material 88,000
Maintenance Labor 114,000
Electrical Power 88,000
Water 5,000
Chemicals and Process Material 100,000
Total 0 & M Cost 395,000 3,413,000 *
Total Annual Cost 1,050,700 7,138,800
NOTE: * Derived from EIC cost data for total annual operating costs (EIC, 1976)
34
-------
TABLE 8. EIC ANNUAL COST FOR 50 MW PLANT VS. HYDROGEN SULFIDE CONCENTRATION
IN STEAM
Costs ($)
Annual Capital
Maintenance Material
Maintenance Labor
Electrical Power
Water
Chemicals and Process
Material
Total 0 & M Cost
Total Annual Cost
830
655,700
88,000
114,000
88,000
5,000
100,000
395,000
1 ,050,700
H2S ppm
2000
1,040,300
170,300
114,000
211,200
12,000
240,000
747,500
1,787,800
10,000
2,573,000
631 ,700
114,000
1,056,000
60,000
1,200,000
3,061,700
5,634,700
50,000
6,613,700
2,451,600
114,000
5,297,600
301 ,000
6,020,000
14,184,200
20,797,900
SO.O-
1WC (300"F)
11.9 AW (160 pill)
1.0
10.000
100.000
STEM FLOUUTE
(kB/hr)
1.000.000
Figure 17. EIC annual cost vs. steam flow rate
35
-------
830 pp>
SUM conditions:
iwc (tart)
11.9 AIM (160 pilg)
POWER GENEMTION (D«)
Figure 18. EIC annual cost vs. power generation
100.0
so.o
. 71.000 kg/hr (1S6.SOO Ib/kr)
-SUM and liwrU
. SO M Smntlon capacity
150°C 1300°F)
•11.9 ATO (160 pslg)
0.1
0.01
10.0
0.1 1.0
HjS Mt.I Of StMB
Figure 19. EIC annual cost (mill/KWH) vs. HgS concentration
36
-------
DOW OXYGENATION PROCESS
The Dow oxygenation process removes hydrogen sulfide from geothermal liq-
uid at the wellhead; thus, it is applicable only to liquid-dominated resources.
Removal of hydrogen sulfide at the wellhead would provide a less corrosive liq-
uid in the pipelines and in the power cycle. The Dow process oxidizes the a-
queous hydrogen sulfide by injecting oxygen directly into the geothermal brine
(Dow Chemical Co., 1976). Thorough mixing to facilitate contact of the brine
and oxygen can be accomplished by using either in-line mixers or a cocurrent
packed tower. Although this process appears conceptually feasible, its opera-
tion is still in the experimental stage. Full-scale operations are needed to
demonstrate its technical as well as economic feasibilities.
Process Description
Simplified flow diagrams of these two systems (in-line mixers and packed
tower) are shown in Figures 20 and 21, respectively. Figure 20 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 valuable in-line
mixer at an acceptable pressure drop.
In general the oxidation reaction occurs very rapidly, less than one
minute for -temperatures expected for geothermal fluids. One proposed
MAGNETIC
FLOWMETER
| FROM 02 -. FC } TEFLON LINED
COMPRESSOR -l — JI PIPE
CONTROL
MONITOR
FROM
GEOTHERMAL
WELL
TO POWER
PLAINT
Figure 20. Dow oxygenation hydrogen sulfide
removal process with in-line mixers
37
-------
FROM OXYGEN f
COMPRESSOR 7"
FROM
GEOTHERMAL
WELL
FLOW CONTROLLER
CORROSION
MONITOR
MAGNETIC
FLOW METER
PACKED
COLUMN
TO POWER
PLANT
Figure 21. Dow oxygenation sulfide removal
process with cocurrent packed tower.
.reaction chain for the aqueous oxidation of hydrogen sulfide 1s as
follows:
HS(aq)
HS
2HS" + 3 02 -v 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 -v S04'2 + S
The second reaction given above has an oxygen/sulflde mole ratio of 3:2 (or
1.5:1). However, Dow's laboratory experiments yielded results Indicating
complete sulfide oxidation occurred at oxygen/sulflde mole ratios of 1.25:1
38
-------
to 1.5:1, depending on temperature and total dissolved salts in the simulated
geothermal brine. Thus, 1t would appear that other reactions, such as the
following, must occur:
HS" + H+ + S"2
S"2 + 1/2 02 + H20 -»• S + 2 OH"
S"2 + 02 + H20 -v 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 1s converted to sulfate 1on, approximately 10 percent to elemental
sulfur, and 10 percent or less to sulfite.
After oxygen 1s Injected Into the geothermal fluid, and until it reacts
with the sulfide, the corroslvity of the fluid increases. This condition re-
quires special materials of construction for both mixing and 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 constructed of tef-
lon.
The in-line mixer system shown 1n Figure 20 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. Each flowmeter is
electrically Interlocked with a control valve, to ensure that each line has an
equal brine flow rate, and interlocked with a control valve injecting compress-
ed cryogenic oxygen Into the brine. The brine-oxygen stream passes through
the in-line mixers to ensure complete reaction. Injection of excess oxygen 1s
detected with a corrosion rate monitor downstream of the mixers. The brine
streams are combined after mixing and the brine is sent to the power plant in
mild steel piping.
The packed tower system shown in Figure 21 does not require the duplica-
tion of equipment and Instrumentation necessary for the in-line system. The
geothermal well fluid flow rate 1s measured with a magnetic flowmeter and
oxygen injection 1s controlled as described for the in-line 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 Oow oxygenation process has been tested and shown to be technically
feasible on a small 3gpm (11.3 1pm) laboratory pilot-plant scale utilizing
the in-line mixer system. Initially, catalytic agents were believed necessary
to achieve acceptable reaction rates; however, additional 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 per-
cent over a pH range of 5.2 to 11.3.
39
-------
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 and the following process conditions (Dow,
t Brine to be treated: 3785 liters per minute (1000 gpm)
: 40 ppm H2S
: 177°C (350°F)
: 11 .2 atm (150 psig)
• Brine phase : single-phase liquid
• Oxygen : hydrogen
sulfide mole ratio: 1.25 : 1.0
t Construction site : Imperial Valley, California
The preliminary installed capital cost estimates for an in-line and for
a packed column system, with the above operating conditions, are $373,600 and
$216,500, respectively. Over 31 percent of the capital cost investment for
the in-line system is required for instrumentation. Ten in-line mixer trains
are required due to the 100 gpm (378 1pm) mixer capacity limitation; thus
necessitating a duplication of instrumentation. Capital costs would be sig-
nificantly reduced if larger capacity mixers could be utilized to minimize
duplication.
Capital cost for an in-line system was assumed to depend linearly on
brine flow rates. This is due to the required duplication of equipment, ne-
gating any possible savings resulting from economies of scale. Capital costs
for a packed column system with differing brine flow rates can be computed
utilizing the following formula:
D 0.85
IA = IB
BA = Brine flow rate of desired case
BB = Brine flow rate of base case (1000 gpm or 3785 1pm)
I = Capital investment for the desired or given (A or B) case
The capital cost of a packed column system is therefore assumed to be exponen-
tially dependent upon the brine flow rate. The exponential factor was based
on that for stainless steel packed towers, 36 to 100 inches in diameter
(Hesketh, 1973). The Dow preliminary cost estimate was based on a Carpenter
20 alloy column, packed with teflon pall rings. The exponent utilized in the
cost calculation applies to these materials of construction. 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.
40
-------
The following assumptions were utilized to estimate the annual capital
and operation/maintenance costs for the in-line and packed column Dow oxyge-
nation systems:
• Amortization period: 15 years
t Maintenance materials: 1 percent of the installed capital cost
t Maintenance labor: 10 percent down time, requiring a two-man crew,
earning approximately $30 per hour per person
t Electrical power usage: 5 horsepower oxygen compressor required for
1000 gpm (3785 1pm) system (Galeski, 1977)
t Cryogenic oxygen usage: Calculated for an oxygen/hydrogen sulfide
mole ratio of 1.25 : 1.0, an additional 20
percent required to account for system losses.
• Cryogenic oxygen cost: $0.65 per 100 cubic feet ($0.23 per cubic
meter).
The annual cost of maintenance materials was taken as 1 percent of the in-
stalled capital cost because of the relative simplicity of equipment and de-
sign for the Dow process.
The annual costs of the in-line and packed column Dow oxygenation pro-
cesses as a function of brine flow rates ranging from 15,000 to 350,000 1/min,
with a hydrogen sulfide concentration in the brine of 40 ppm, are given in
Tables 9 and 10. Annual costs for the Dow processes for a 100,000 1/min brine
flow rate and hydrogen sulfide concentrations of 40 ppm, 500 ppm and 1000 ppm
are presented in Tables 11 and 12. Figures 22 through 27 are graphs of the
normalized total, capital and operation/maintenance costs given in Tables 9
through 12. Cost estimates for the Dow oxygenation in-line and packed column
systems have been developed from specific data and conditions, thus cannot be
applied to geothermal resources in general.
Figures 22 and 23 give the cost, in dollars per 1/min, for brine flow
rates from 15,000 1/min to 350,000 1/min with a hydrogen sulfide concentration
of 40 ppm for the in-line and packed column systems. 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 24 and 25. Generation
capacities were computed based on a double flash energy conversion system with
8 percent overall efficiency, operating with brine conditions given previously.
Figures 26 and 27 represent the costs, in mills per KWH, of the Dow processes
as a function of hydrogen sulfide brine concentration at a 100,000 1/min flow
rate (98.2 MW).
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.
41
-------
TABLE 9. DOW OXYGENATION ANNUAL COST* FOR IN-LINE SYSTEM VS. GEOTHERMAL BRINE
FLOW RATE 40 ppm HS
Costs ($)
15,000
Brine Flow Rate (1/min)
100,000 225,000
350,000
Annual Capital
Maintenance Material
Maintenance Labor
Electrical Power
Oxygen
Total 0 & M Cost
Total Annual Cost
173,100
14,800
50,000
2,000
71 ,300
138,100
311,200
1,154,600
98,800
50,000
13,300
475,200
637,300
1 ,791 ,900
2,597,800
222,400
50,000
30,000
1,070,000
1,372,400
3,970,200
4,041,000
345,900
50,000
46,700
1,664,500
2,107,100
6,148,100
NOTE: * Derived from Dow Chemical Co. cost data for 1000 GPM in-line system (Dow, 1977)
TABLE 10. DOW OXYGENATION ANNUAL COST* FOR PACKED COLUMN SYSTEM VS.
GEOTHERMAL BRINE FLOW RATE 40 ppm HS
Costs ($)
Annual Capital
Maintenance Material
Maintenance Labor
Electrical Power
Oxygen
Total 0 & M Cost
Total Annual Cost
15,000
81,500
7,000
50,000
2,000
71 ,300
130,300
211,800
Brine Flow
100,000
409,000
35,000
50,000
13,300
475,200
573,500
982,500
Rate (1/min)
225,000
814,900
69,800
50,000
30,000
1,070,000
1,219,800
2,034,700
350,000
1,186,400
101,600
50,000
46,700
1,664,500
1,862,800
3,049,200
NOTE: * Derived from Dow Chemical Co. cost data for 1000 GPM packed column system.
(Dow, 1977) 42
-------
TABLE 11. DOW OXYGENATION ANNUAL COST FOR 100,000 1/MIN IN-LINE SYSTEM VS.
HYDROGEN SULFIDE CONCENTRATION IN GEOTHERMAL BRINE
Costs ($)
ppm
40
500
1000
Annual Capital
Maintenance Material
Maintenance Labor
Electrical Power
Oxygen
Total 0 & M Cost
Total Annual Cost
1,154,600
98,800
50,000
13,300
475,200
637,300
1 ,791 ,900
1,154,600
98,800
50,000
166,300
5,940,000
6,255,100
7,409,700
1,154,600
98,800
50,000
332,500
11,880,000
12,361,300
13, 51 5, '900
TABLE 12. DOW OXYGENATION ANNUAL COST FOR 100,000 Vmin PACKED COLUMN SYSTEM VS.
HYDROGEN SULFIDE CONCENTRATION IN GEOTHERMAL BRINE
Costs ($)
40
ppm
500
1000
Annual Capital
Maintenance Material
Maintenance Labor
Electrical Power
Oxygen
Total 0 & M Cost
Total Annual Cost
409,000
35,000
50,000
13,300
475,200
573,500
982,500
409,000
35,000
50,000
166,300
5,940,000
6,191,300
6,600,300
409,000
35,000
50,000
332,500
11,880,000
12,297,500
12,706,500
43
-------
50.0-
10.C
_-_
3 I
s.o
1.0
CAPITAL
OPERATING 4
MAINTENANCE
10.000
\ t
40
100.000
GEOTHERNAL BRINE FLOW RATE
(I/Bin)
1.000,000
Figure 22. Dow oxygenation - in-line system annual cost
vs. brine flow rate
1.0
10.000
100.000
GEOTMERJUL BRINE aOH RATE
(1/rin)
1.000,000
Figure 23,
Dow oxygenation - packed column system annual
cost vs. brine flow rate
44
-------
J10.0. .
9 - •
••
TOTAL
OPERATING t
HAIHTENANCE
CAPITAL
1.0
10.000
1 1 1 I I I
500 pp> H2S
Double fluh convirslon lyitc*
brine conditions:
177°C (3SO°F)
11.2 ATH (ISO pslg)
100,000
-I 1 1 I I I I
1.000.000
Figure 24.
POWER GENERATION (KHH)
Dow oxygenation - in-line system annual cost
vs. power generation
10.0
5.0-
1
§ o.s- .
TOTAL
OPERATINSi
NUNTENMKE
CAPITAL
0.1
10.000
500 ppiHjS
Ooutali fluh conversion iyst*n
brlnt conditions:
177°C (3SCrt]
11.2 ATM (ISO pslg)
100.000
POKR GENERATION (Ml)
H 1 1 I | I I
1.000,000
Figure 25. Dow oxygenation - packed system annual cost
vs. power generation
45
-------
CTt
100,000 I/Bin («.«20 6PM)
98.2 NUjwntratlon capacity
Doublt flash c
conversion systw
177°C (350°F)
11.2 ATM (ISOpslg)
OPERATING I
MAINTENANCE
0.001
0.01 0.1
wt.S of gNtlMrwl bHM
Figure 26. Dow oxygenation - in-line system annual
cost vs. H$ concentration
50.0
•100.000 !/•!» (ZC.420 S«)
'96.2 Ml Gmrttlra capldty
'DoubU fluh canvtrslon
•mee (J5o*Fj
.11.2 ATM (ISO
0.1
0.001
vt.I of gMthnwl bHM
Figure 27. Dow oxygenation - packed column annual
cost vs. H2S concentration
-------
Solid Sorbent Process
Battelle Pacific Northwest Laboratories has investigated numerous solid
sorbents for the removal of hydrogen sulfide from geothermal steam (Battelle,
1976). Battelle assumed that the following conditions should be satisfied to
establish a technically and economically feasible 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. Using simulated geothermal steam,
zinc oxide produced the most favorable results among the numerous metal oxide
and organic amine sorbents tested. The zinc oxide-hydrogen sulfide adsorption
reaction is given below:
ZnO + H2S -»• ZnS + HgO
Regeneration is accomplished by reactions with oxygen:
ZnS + 3/2 02 + ZnO + S02
ZnS + 2 02- -»• ZnS04
Low temperatures, with oxygen or air regeneration, favor the second reaction
producing zinc sulfate rather than zinc oxide. Temperatures in excess of
1200°C are necessary to regenerate zinc oxide directly from zinc sulfide.
However, at those temperatures, 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 28. Geothermal steam is introduced to the
bottom of a fluidized bed gas-solid contact vessel and hydrogen sulfide is
adsorbed by the solid sorbent (zinc oxide). The solid sorbent particles sus-
pended 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 contractor to the re-
generator. Regenerated sorbent is returned pneumatically to the top of the
contractor vessel for reuse. Sulfur dioxide generated in the regeneration
process requires treatment in a separate sulfur recovery process. Battelle's
laboratory investigation determined that a zinc oxide solid sorbent process
is not economically viable for the removal of hydrogen sulfide from geother-
mal steam and recommends that no further work on solid sorbents be undertaken.
Claus Process
The Claus 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 Claus process
flow diagram is shown in Figure 29.
The process requires a specific concentration ratio of hydrogen sulfide
to su-lfur dioxide. Sulfur dioxide, obtained by combusting part of the hydro-
gen sulfide, is mixed with the feed stream. The hydrogen sulfide and sulfur
dioxide are reacted with each other in a series of converters to produce ele-
47
-------
CYCLONE
SEPARATOR
TO STEAM TURBINE
BAG POWER GENERATOR
FILTER
CARRIER GAS
VENT
GAS-SOLID
CONTACTOR
GEOTHERMAL
STEAM
CYCLONE
SEPARATOR
TO SULFUR
RECOVERY
REGENERATOR
CARRIER
GAS
PNEUMATIC
PUMP
AIR OR OXYGEN
Figure 28. Solid sorption hydrogen sulfide removal process
NONCONDEN-
SIBIE GAS
FROM POWER
PUNT
CLEAN GAS TO
COOLING TOWER
BOILER
FEEOWATER
AIR
Figure 29. Claus sulfur recovery process
SULFUR TO
STORAGE
48
-------
mental sulfur, which is condensed out of the main gas stream. The converters
contain an activated bauxite catalyst that accelerates the following reaction:
2 H2S + S02 -»• 3 S + 2H20
A tail gas containing residual amounts of hydrogen sulfide and sulfur dioxide
in moderate concentrations is treated by one of the following processes: re-
cycling 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 hydro-
gen 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 + H£S •*• 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 (H202) has been used to remove hydrogen sulfide from
various wastewater streams. The applicability of I^Oo to geothermal cooling
water/condensate 1s somewhat questionable because of the high temperature
environment. Hydrogen peroxide reacts with hydrogen sulfide 1n 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 1s catalyzed by a metal 1on, such as the ferrous
Ion. The rate of the acidic reaction 1s greatly Increased by an Increase 1n
temperature. It 1s 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.
49
-------
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 (SRI, 1977). The results indicate that the hydrogen sul-
fide oxidation rate increases as a result of increases in (ranges tested given
in parenthesis): initial hydrogen sulfide concentration (2.3-12.5 ppm) tem-
perature (40°-51°C), hydrogen peroxide/hydrogen sulfide weight ratio (0.9-3.9
and 400), and ferric sulfide concentration (0-2.0 ppm). Oxidation of 88 per-
cent of HgS was obtained in less than three minutes, without the use of a
catalyst, 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 may be feasible.
Ozone
Oxidation of hydrogen sulfide with ozone in aqueous solutions has not been
adequately investigated to evaluate its applicability for controlling geother-
mal emissions. Ozone has previously been used to oxidize hydrogen sulfide in
the gaseous phase. Elemental sulfur and sulfate are the most likely products
of the 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 pro-
duce elemental sulfur. Because of the high cost of producing ozone, the eco-
nomic 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 hy-
drogen sulfide contained 1n the ejector gases is burned to sulfur dioxide.
The combustion gases are ducted to a scrubber where contact is made with cool-
ing water, thus dissolving the sulfur dioxide. The dissolved sulfur dioxide
reduces the pH of the cooling water, which Increases the amount of hydrogen
sulfide being removed with the noncondensible gases from the condenser. Thus,
more hydrogen sulfide 1s Incinerated, rather than remaining dissolved and
being stripped from the cooling water into the air stream 1n the cooling tower.
The sulfur dioxide may also oxidize the hydrogen sulfide dissolved 1n 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 (Laszlo, 1976).
50
-------
Catalyst-Scrubber Process
The catalyst-scrubber process 1s essentially the same as the burner-
scrubber system, except the hydrogen sulfide Is selectively oxidized to sul-
fur dioxide with a catalyst developed by the Union 011 Company. Since the
hydrogen sulfide 1s oxidized without combustion, this system 1s potentially
less complex and safer than the burner-scrubber process. The efficiency of
the catalyst-scrubber process 1s also expected to be approximately 50 percent,
This process 1s projected to be Installed on The Geysers 53 MWe Units 5 and 6
sometime 1n 1978.
Deuterium Process
The Deuterium process removes hydrogen sulfide from geothermal steam up-
stream of the power plant. This process 1s proprietary and a process des-
cription 1s not currently available. The Deuterium Corporation holds the
patent for heavy water, production of which requires steam containing hydro-
gen sulfide.
51
-------
SECTION 6
WATER POLLUTION CONTROL TECHNOLOGY
EVALUATIONS AND COST ESTIMATES
This section discusses water pollution control technologies that may have
potential applications to wastewater discharges from geothermal conversion pro-
cesses. It also presents preliminary cost estimates based on information de-
rived from related industries. Although treatment cost is a function of many
variables including wastewater quantity and quality, temperature and TDS, it
would be very complicated to develop cost curves based on all these variables.
For preliminary cost considerations, a simplifying assumption is made to con-
sider treatment cost dependent only on flow. Other variables are assumed to
only affect treatment efficiencies and not the cost.
In general, water pollution control technologies include wastewater treat-
ment and wastewater disposal. The following discussion describes both. Depend-
ing on the constituents present and the quantities that must be removed, many
of the treatment technologies may be used individually or in series. The
treatment technologies to be discussed are those applicable primarily to the
removal of suspended and dissolved inorganic solids characteristic of geother-
mai fluids. Treatment system costs have no provision for redundancy.
WASTEWATER TREATMENT TECHNOLOGIES
The major wastewater treatment technologies applicable to geothermal con-
version processes are: sedimentation, chemical precipitation, filtration,
reverse osmosis, electrodialysis, ion exchange, and evaporation-distillation.
The following is a discussion of the technical as well as the economic analysis
of these systems.
Sedimentation, Chemical Precipitation and Filtration
Sedimentation Process Description - Sedimentation is a physical treatment
operation which removes settleable solids from wastewaters. It is generally
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 mate-
rials such as oil. Without other treatment. th«y will not roaove significant
amounts of dissolved or emulsified materials.
52
-------
Sedimentation process efficiency is a function of temperature of the waste-
water, the density and size of suspended particles, the amount and character-
istics of the suspended material, and settling time. Gravity separation can
normally remove 50-65 percent of the suspended solids (Bond, 1974, U.S.D.O.I..
1967).
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 sedi-
mentation of colloidal and highly dispersed particles in the waste stream by
aggregation and coalescence of small particles into larger more readily settle-
able or filterable aggregates. Some dissolved inorganic constituents may also
be precipitated by chemical coagulants.
The function of chemical coagulation 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 phospho-
rus, by chemical precipitation or adsorption on chemical floe. Coagulation In-
volves the reduction of surface charges of colloidal particles and the forma-
tion of complex hydrous oxides or precipitates. Coagulation is essentially
instantaneous in that the only time required is that necessary for dispersing
the chemical coagulants throughout the liquid. Flocculation involves the bond-
ing together of the coagulated particles to form settleable or filterable solids
by agglomeration. Agglomeration is facilitated by stirring the water to in-
crease the collision of coagulated particles. Unlike coagulation, flocculation
requires definite time intervals to be accomplished.
The more common chemical coagulants used are lime, soda ash, filter alum,
ferric or ferrous sulfate and ferric chloride. Anong the coagulant aids used,
the more popular ones are sodium aluminate, 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 for a given coagulant, pH adjustment of the wastewater may be re-
quired to achieve optimum conditions. With proper design of the coagulation/
flocculation system and sedimentation tank, removal efficiencies of 80-90 per-
cent of suspended solids and 20-40 percent of dissolved solids can be readily
attained (Bond, 1974. U.S.D.O.I.. 1967).
Filtration Process Description - Filtration is a solids-liquids separation
technique to remove particulate matter from wastewater. It may be used instead
of or in addition to sedimentation. In filtration, the wastewater to be treat-
ed is passed through a porous medium. Solids separation is accomplished largely
by sieving action. The mechanisms involved in the removal of suspended or col-
loidal 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.
53
-------
Filtration can be accomplished by the use of: (1) a microstrainer, (2) a
diatomaceous earth filter, (3) a sand filter, or (4) a mixed-media filter. The
microstrainer is a screen in the form of a partially submerged 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. Clean-
ing is carried out by backwashing with sprays of product water. Removal effi-
ciencies have been reported for the following parameters (Bond, 1974):
SS 50-80 percent; BOD 40-70 percent; and turbidity 60-76 percent.
Diatomaceous earth filtration is a mechanical separation system that
employs a layer of filter aid such as diatomaceous earth. As filtration pro-
ceeds, 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 becomes 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 (Bell, 1962).
Sand filtration may be employed following chemical coagulation and pre-
ceding carbon adsorption or ion exchange. The length of the average filter
run before backwashing is related to the solids loading on the filter. Gener-
ally, filtration rate is low, and backwashing is frequent because of the rapid
build-up of headless. However, removal efficiency for suspended solids is
usually very good.
Mixed-media filtration was developed in an attempt to approach ideal fil-
tration. 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.
-------
.FILTER BASIN
WASH TROUGHS
BACKWASH
GULLET
EFFLUENT
BACKWASH
HEADER
SINGLE OR
MIXED-MEDIA
GRADED GRAVEL
'PERFORATED LATERALS
FILTER FLOOR
Figure 30. Cut-away view of a granular mixed-media filter.
Capital investment is the cost of purchasing and installing the pollution con-
trol systems. O&M costs are associated costs for the operation, repair, and
routine maintenance of the pollution control equipment. Since the capital in-
vestment as well as the O&M costs are flow dependent, empirical equations have
been developed for costing these pollution control systems. In addition to
flow, the capital investment is a function of the base capital cost (BCC),
land requirement (LR) and, service and interest factor (SIF), and capital re-
covery factor (CRF). The O&M costs, on the other hand, are functions of base
man-hour requirements (BMH) and labor rate (MHR). The total amortized capital
cost (TACC) in cents per thousand gallon is given by the following equation:
TACC - [(BCC)
* (UHULC)]
CRF
and the operation and maintenance costs (O&M) are given by:
fixed operation and maintenance cost in
-------
TABLE 13, FLOW VARIABLE COST ELEMENTS FOR WAST.EWATER TREATMENT _
Und Base
Base capital requirement manhours Base materials
Process _ cost (BCC) _ (LR) _ (BMH) _ cost (BMC) _
PH. sed.
conventional 139753 + 17341. 2Q 0.23 + 0.088Q 1852. 8Q°'42 1158.4Q
Pri. sed.
2-stage lime n .-, n fifi
add 307785 + 33538.6Q 0.16 + 0.18Q 4259. 3QU^' 2956. 2Q u<0°
Pr1. sed.
1 -stage Hme n «
add 198801 + 19934. 9Q .0.68 + 0.11Q 3260.8 + 161. 1Q 1694.4Q °'b5
Pr1. sed. _ 9 _ .5
alum, add 241226 + 33921 .4Q 0.26 + 0.16Q 2783. 4Q°'47 (6.62 + 0.036Q)10
Pri. sed.
add 269563 + 33561. 5Q 0.26 + 0.16Q 2805. 5Q°'43 2982.5 + 14255.3Q
Q .4
Filtration 231495.0Q0'66 0.024 + 0.028Q (6.8 + 5.8Q)10 16491. 9Q °*68
Ion exchange 163270Q0*88 -0.17 + 0.021Q 3746. 2Q0t72 15161. 5Q °'86
where Q = plant capacity or flow (mgd)
-------
TABLE 14. ASSUMPTIONS USED TO DETERMINE WASTEWATER COST CURVES
FOR PRETREATMENT AND ION EXCHANGE
Variables
Q
n
i
SIF
MHR
ULC
WPI
STP
Notations Units
Wastewater
flow MGD
Amorti zed
period Years
Interest
rates %
Service &
1 nterest
factor %
Labor
rate $/man-hour
Land cost $/acre
Wholesale
price index
National
average waste-
water treat-
ment plant
cost Index
Value used to determine
cost curve
0.0038, 0.38, 1.52, 1.9
5.7, 11.4, 133
20
8
27*
12.31**
10,000***
199.1****
275.0*****
* This includes allowance for engineering, contingencies and interest
during construction
** As of October 1977, Including fringe benefits
*** As of October 1977
**** As of October 1977
***** As of October 1977 (Water Resources Council)
57
-------
Using these equations in conjunction with the assumptions presented in
Tables 13 and 14, total capital costs and total operation and maintenance
costs were computed in cents per thousand gallons for sedimentation, various
chemical precipitation systems, and filtration. These values were then con-
verted to cents per thousand liters and plotted in Figures 31 through 36 „
Costs for the disposal of sludges and brine have not been included. These
curves are presented strictly for preliminary cost comparison purposes, based
on the assumptions set forth above. Information contained in these curves
should not be construed as absolute data points for costing a new or existing
treatment system. In particular, variations of geographic locations, climatic
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 (32.600 I/day/m ) 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 chemi-
cal characteristics approximating those found in municipal wastewaters. The
actual amount of chemical dosage for geothermal fluids will have to be deter-
mined by jar test of the geothermal fluid. The chemical dosage in this cost
analysis assumes a dosage rate of: 400 mg/1 as CaO for a 2-stage lime treat-
ment; 200 mg/1 as CaO for a 1-stage lime treatment; 80 mg/1 as Fed3; and 170
mg/1 as alum for a 1-stage treatment. Capital costs for both the sedimenta-
tion basin and chemical precipitation system include costs for sludge removal
devices, piping, pumps and equipment for sludge thickening. Normal allowances
for operation and maintenance of chemical equipment are also included.
The costing curves developed for gravity filtration are based on filtra-
tion rate of 4 gal/min/ft^. This rate is highly dependent on the nature of
the filtered fluid and the characteristic 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). The O&M costs include all power
and labor associated with filtration and backwash cycles.
58
-------
SINGLE STAGE LIME
lOOOj
o
8
en
10
io,ooa
1000- -
100: •
o
o
2 10
8
0.!,.
1000 10,000
FLOW(1/HIN)
100,000 1,000,000
0.01
t| i 11iiuil i i UIHI| ml i i imiil i i in
10 100 1000 10,000 100,000 1,000,000
FLOW(L/HIN)
Figure 31. Cost estimates for sedimentation
Figure 32. Cost estimates for chemical
precipitation with single stage
Hrne addition.
-------
2-STAGE LIME
10,000*
10004-
§
o
g 8
loo-L
104-
1.01
o.il
o.oi
CAPITAL
10,000
I I i mini i t iniii) i 11"»ij—t-iiniiif i i nun| i i iimJ
I 10 100 1000 10,000 100,000 1,000,000
FLOW (L/HIN)
I tit inn[ i 111 mil i i iiiiii|—i » HIIH| i 11 HUM
10 100 1000 10,000 100,000 1,000,000
FLOW(L/MIN)
Figure 33* Cost estimates for chemical treat-
ment 2-stage lime addition
Figure 34. Cost estimates for chemical
precipitation with alum
addition
-------
10fOOOf
1000
8
o
>I
V
7^
8
D.I
10
100
1000 10,000 100.000 1,000,000
FLOW(LXMIN)
Figure 35. Cost estimates for chemical
precipitation with ferric
chloride addition
100,
10
100
11 ll| I I IIIIMi I I HUM! t I IMIlM
1000 10,000 100,000 1,000.000
FLOW(L/MIN)
Figure 36. Cost estimates for filtration
61
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Reverse Osmosis
Process Description - In this, process, a portion of the wastewater is
forced through a semi-permeable membrane. Figure 37 (Chen, 1977)» 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 concen-
trated solution (retentate) must be disposed of in some manner such as
reclaiming it or disposing of it in lined evaporation ponds.
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 technical
feasibility of reverse osmosis is determined by the availability of a membrane
which sufficiently limits passage of the ion to be removed while allowing pas-
sage of a reasonable amount of water. Any solids (suspended or colloidal) pre-
sent in the waste stream will impede the passage of water through the membrane.
For proper operation, a filtration system is usually installed ahead of the
reverse osmosis unit to minimize plugging of the membrane.
PRESSURE
REGULATOR
CONCENTRATED
-BRINE
-*-TREATED WATER
Figure 37, Schematic presentation of reverse osmosis.
Given a suitable membrane, the performance of a reverse osmosis unit is
largely determined by the proportion of permeate to the retentate. As a larger
fraction of the feed is removed as permeate, the concentration of the reten-
tate increases. The increased concentration difference across the membrane
tends to cause ion migration through the membrane. In general, reverse osmosis
produces a permeate with a dissolved solids concentration approximately 10 per-
cent of that in the feed solution. Industrial application of the process has
shown the following removal efficiencies (Argo, 7977, Chen, 1977, and Llptak,
1974): SS 95-98 percent; BOO 90-95 percent; NHg 95-99 percent; and org-N, NOgN
PO.-P, and TDS 95-99 percent.
62
-------
Passage of individual ions varies according to the selectivity of the mem-
brane, feed -temperature, and pH. Water flux usually increases with increasing
temperature, whereas salt rejection remains essentially constant over the nor-
mal 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 this reason, a pH of 3 to 7 should be maintained for op-
timum membrane operation.
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 200°F, Geothermal fluids
may require cooling prior to treatment by reverse osmosis.
Costs - Cost estimates for reverse osmosis were derived from a combina-
tion of studies prepared by the Fluids Systems Division of UOP, Inc. (UOP,
1974), Los Angeles County Sanitation (Chen, 1977), and the Orange County Water
District Factory 21 (Argo, 1977). Figure 38 1s a summary of cost estimates
for the reverse osmosis system. The value plotted 1n the capital Investment
curve was calculated based on a 20-year plant life, using the capital re-
covery factor at 8 percent Interest rate, 15 percent Inflation, and 92 per-
cent plant factor. The operation and maintenance costs Include power,
chemical, membrane replacement and maintenance, and labor costs. Cost data
from the above references were adjusted to the 1977 second quarter costs by
using the Marshall, and Stevens Process Index (MRS) Index. The cost curves thus
developed were found to be comparable to curves produced by tiumerman et al
(1978).
1000.0
•I i i t•ii"l I .tti.nl
1,000 10,000 100.000 1,000,000
FLOW (1/MIN)
Figure 38. Cost estimate for reverse osmosis system.
63
-------
Costs of reverse osmosis depend largely upon the quality and quantity of
wastewater 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 (Chan, 1975). The basic
principles of electrodtalysis are illustrated in Figure 39.
WASTEWATER
INLET ,
ii.
NEGATIVE POLE
OR CATHODE
CONCENTRATED
WASTED-
s^ TREATED
"~ WATER
Figure 39. Electrodialysis cell.
The electrodialysis system uses a series of compartments separated by alter-
nately-placed am"on and cation permeable membranes. The application of an
electrical potential across the system causes the migration of cations to the
cathode and of anions to the anode. The migration results in ion concentra-
tion and dilution in alternate compartments.
Electrodialysis as a wastewater treatment process is still in the prelim-
inary development stages. It has been used for the desalination of brackish
water, but has not been used extensively in the treatment of industrial wastes.
As with reverse osmosis, electrodialysis produces a concentrate that, in turn,
must be disposed of in some manner.
The membranes used in the process are subject to fouling by any suspended
solids or oils (or other organics) in the waste. Such materials must be re-
moved by pretreatment. Membrane life 1s usually determined experimentally.
Electrodialysis has produced water having a total dissolved solIds content of
less than 500 ppm. This process 1s also found to be effective 1n removing
30 percent to 50 percent of NH,-N and PO--P and approximately 40 percent of
TDS (Bond, 1972).
64
-------
Costs - For electrodialysis systems, the cost estimates were derived
from information gathered in the San Francisco Bay-Delta Water Quality Con-
trol Program Study. Data points were extracted directly from the existing
graphical plots. Units were converted to the metric system. These cost
data (capital and O&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 40).were found to correlate relatively well with actual cost data
presented by Los Angeles County Sanitation District (Dryden, 1970) and cost
curves illustrated by Faber (Faber, 1972). 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; thus it was not possible to assess the accuracy and validity
of these data points.
100.0
o
o
o
i- 10.0
tn
O
O&M
I
I
1.0
1 x lo4 1 x 105 ix 106
FLOW (1/MIN)
Figure 40, Cost estimates for electrodialysis system.
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 (Chen, 1977). Most ion exchange materials are synthetic poly-
65
-------
mers containing active groups such as HS03 and NH4 to which the exchangeable
ions (H+ and OH~) are attached. The exchange reaction for removing sodium
chromate by a combination of cationic and anionic exchange resins can be rep-
resented by:
R'H
R-Na+ + H
R++ (OH-) + CrO
R CrO" + 2 OH
where R~ and R represent the anionic and cationic 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 positive
ions of a base and negative ions 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 base ions, such as calcium
(Ca), sodium (Na), or magnesium (Mg), are exchanged for hydrogen ions (H) in
the cation exchange column, thereby converting these positive cations Into their
respective acids. In the second stage the acid negative ions such as silicates
(8103), carbonates (CDs), chloride (Cl), or sulfate ($04) are removed and ex-
changed for hydroxide ions (OH) in the anion exchange column. This completes
the two-step removal of the salt. In mixed-bed ion exchangers, as shown in
Figure 41, the two steps are combined Into one.
RAW WATER
DRAIN
ALKALI
TREATED T— RAW
WATER WATER
BACKWASH
AIR OUT
DRAIN
ACID *—AIR
SERVICE BACKWASH REGENERATION RESIN MIXING
Figure 41. Mixed-bed ion exchange process.
66
-------
Once the demineralized ion exchangers are saturated or .excessive leakage
occurs they have to be regenerated to allow reuse of the resins. Cation ex-
changers are regenerated by strong acids (HgSCty or HC1) and anion exchangers
by caustic soda (NaOH). For continuity of operation during bed regeneration,
two trains of ion exchange columns are needed.
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 (Chen, 1977). 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 42 for ion exchange sys-
tems is from Van Note's publication (Van Note, 1975). The assumptions and
flow variable cost elements are presented in Tables 13 and 14. Chemical
costs for regeneration are part of the O&M costs. The actual cost for ion ex-
change systems is dependent on the exchange resin, the characteristics of the
wastewater, and the effluent quality required. Pretreatment costs or the cost
for disposal of backwash brine have not been included.
100
Figure 42.
1000 10,000 100,000 1,000,000
FLOW (L/MIN)
Cost estimates for ion exchange system.
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.
67
-------
m,v , ^aP°rators generally use steam as the heat source. Some evaporators
may use several stages (termed "effects") to conserve heat. In muUiple-
effect evaporators (Figure 43), 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 solrcl in the
next Vapor condensation occurs on exchanger surfaces cooled by inlet water,
a Passively through each "stage. Reduced pressure is
STEAM IN
BRINE INLET
CONDENSATE
——PRODUCT
Figure 43, Multiple-effect evaporation.
The multiple-stage flash evaporation scheme places all steam heat exchange
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 44)0 A test facility, using this technology on geothermal brines, 1s
being operated by the Bureau of Reclamation, at East Mesa, California. Its ob-
jective is to produce fresh water for augmenting the Colorado River flow and for
irrigation. Multiple flash evaporators are more economical than multi-effect
units, and are frequently used in desalination applications.
VENT
CONDENSATE
TO BOILER
LJ u Is*/:
SAIT
WATER (20°C)
»»- DISTILLATE
BRINE (30°C)
Figure 44. Multiple stage flash evaporation.
68
-------
Vapor recompression techniques can also be used to conserve heat (Figure
45)« 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 incoming feedwater. Com-
pression stills may be economically attractive where cheap electrical power is
available to drive the compressor. The effectiveness of this method is about
the same as that of evaporation ponds, but it is faster and requires heat in-
put.
SEPARATION
SPACE
STEAM
101 °C, 1 atm
MOTOR
?t-—..',>.'.•%/ COMPRESSOR
STARTING HEATER
97
101°
»-4v EVAPORATOR
^^ 105°C
HEAT EXCHANGER
2) SEAWATER
g) LOW PRESSURE STEAM
§3 COMPRESSED STEAM
0) FRESHWATER
BRINE
0.25 m3/hr, 27°C
SEAWATER
1.25 m3/hr, 15°C
•*• FRESHWATER
1.00 m3/hr, 21°C
Figure 45. Compression still.
Evaporation methods are capable of reducing the volume of brine by 70 to
80 percent (Splegler, 1966), The. concentrated salt-brine residue must be
properly disposed of by either ocean dumping, deep well Injection, or after
total evaporation, by landfill.
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 per unit of flow decreases only slightly with increasing
throughput (at a fixed percentage of feed to be evaporated). The total costs
shown in Figure 46 are a composite of the operating costs and annual1zed cap-
ital costs using the following assumptions:
Electricity @ 4tf/KWH, steam @ $2/million Btu
8400 operating hours/year, over a 20-year project life (8 percent
rate of return).
69
-------
Capital and operating costs were obtained from experience in chemical and paper
industry practice (Rosenblad, 1976; Guthrie, 1974; and Perry, 1973) for multi-
effect and vapor recompression evaporators. Most cost data for multistage
flash units are available from desalination installations (Howe, 1974; and
Spiegler, 1966).
cr TOO
o
o
0
•^
V
5 10
o
u
1.0
1 1 II
_ (3 STAGE) MULi
t * *-*<
-^--
1 1
riSTAGE FLASH —
10- STAGE) ^MULTIEFFECT
v
VAPOR RECOMPRESSION
1 1 1 1
1 1
10 100 1000 10,000 100,000 1,000,000
FLOW (1/MIN)
Figure 46. 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 eva-
poration or flashing, and a total cost advantage is obtained from the use of
ten stages versus three stages. Even so, the lower cost of vapor re-
compression units is clearly evident at power costs of 44/KWH, and the cost
could be even lower with cheap power available from an associated power plant.
A cost breakdown of various evaporative systems for typical flow ranges is
summarized in Table 15.
Variables which strongly affect evaporation costs include the percentage
of feed to be evaporated; the inlet feed temperature; and (in the use of re-
duced pressure evaporation) the temperature of cooling water. The cost data
shown in these figures are based on 50 percent evaporation of feed-water, with
an incoming feed temperature of 40°C. There would be considerably more en-
thalpy (heat content) available in the incoming feed from the flash down of a
geothermal power operation, and this extra enthalpy can be translated into in-
creased amounts of evaporation over the base case. If, for example, an eva-
porator was designed to evaporate 30 percent of its feed (at 65°C), the same
evaporator could yield about 75 percent evaporation at a feed temperature of
150bC, and 90 percent evaporation at 225°C.
70
-------
TABLE 15. COMPONENT COSTS FOR EVAPORATION,
Basis: SOX of feed evaporated,
40°C feed temperature
System
Multi-stage
flash;
3 stage
5 stage
10 stage
Multleffect,
6 stage
Vapor compres-
sion
Feed
(Hters/mln)
520
5,200
5,200
26,000
520
5.200
7,584
75,840
52
52.000
0 ft M
Costs. $
175,000
1,750,000
1,312,500
6,562,500
105,000
1.050,000
1 ,780,800
17.808,000
3.473
3,473.433
Annual 1 zed
Installed
cost, $
15,360
76,800
134,400
384-.000
57,600
268,800
199,218
300,000
6.144
1,920.000
Total cost
per year. 1
190,360
1,826,800
1,446,900
6.946,500
162.600
1 .318.800
1 .980,018
18,108,000
9.617
5.393.433
The total costs for evaporation (20 to 70* 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 dis-
posal .
Other Wastewater Treatment Technologies
In addition to the above-described 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 have 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, currently, be considered feasible.
71
-------
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. Table 16 summarizes a survey of control technologies for
the removal of specific pollutants from wastewaters. Since most literature
findings are limited in information on specific pollutant removal, efforts
were made to contact knowledgeable persons in the field, such as equipment
vendors, engineering consultants, government regulatory agencies, and academia,
to seek expert opinions on specific applications of pollutant removal from
wastewater.
TABLE 16. REPORTED EFFICIENCIES OF CONTROL TECHNOLOGIES FOR
TREATMENT OF SPECIFIC CONSTITUENTS FROM WASTEWATERS
(percent removal)
...
^1*
Chemical
Sedimentation Precipitation 'Filtration
..Electro-...
V^*.H«l»»e*«.V^/
Ion (5) Reverse
Osr.osis
TS
IDS
Fe
Mn
B
Zn
B*
P
Pb
Cu
A*
HC
S«
Cr
At
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
Ref: (1) 6.40,63,72; (2) 6,7,23,40,44,60; (3) 40,60.63; (4) 11,40,60,63;
15) 3,17,40,60,63; (6) 6,7,10,21,48,63
Application of Wastewater Treatment Technologies
Wastewater treatment requirements depend upon the characteristics of the
raw wastewater compared to the quality to be maintained in the wastewater dis-
posal area or receiving media. To examine the requirements, three sets of
possible raw wastewater constituent characteristics and three sets of possible
discharge requirements have been compiled in Table 17 based on EPA's work
directive. The values shown are not intended to be actual, but probably in-
clude the ranges to be considered in geothermal wastewater treatment. Possible
ranges of flows for various uses are shown in Table 18. Based on the Informa-
tion shown in Table 17, the required removal efficiencies were calculated, as
shown in Table 19, for the various raw levels vs. discharge levels.
To simplify the regulatory requirements for achieving the removal effici-
encies for each of the constituents in Table 19, 1t Is assumed that the remov-
al of total solids (TS) and the soluble metals (SM) with the most stringent
72
-------
TABLE 17. ASSUMED GEOTHERMAL WASTE BRINE AND SURFACE
WATER DISCHARGE CONCENTRATIONS (mg/1).
G«othermal Waste Brine
Concentration Level
Surface Water Discharge
Concentration level
Constituent
High
Mid
Low
High
Mid
Low
Total Solids
Iron
Manganese
Boron
Zinc
Barium
Fluoride
Lead
Copper
Arsenic
Mercury
Selenium
Chromlu*
Silver
Cadmium
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
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 18. 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 & 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 t Mid
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 strin-
gent removal efficiency generally will also remove SM with less stringent re-
quirements. The only exception is boron, which cannot be effectively removed
by any current control technology.
73
-------
TABLE 19. REMOVAL EFFICIENCIES (%) REQUIRED FOR TREATING
VARIOUS LEVELS OF RAW GEOTHERMAL FLUIDS.
Constituent
Discharge Concentration Levels
High Level Waste Hid Level Waste Low Level Waste
12 3 123 123
Total Solids (TS)
Iron (Fe)
Manganese (Hn)
Boron (B)
Zinc (Zn)
Barium (Ba)
Fluoride (F)
Lead (Fb)
Copper (Cu)
Arsenic (As)
Mercury (Hg)
Selenium (Se)
Chromium (Cr)
Silver (Ag)
Cadmium (Cd)
95
99.5
99.9
99
98
99
99
99
90
95
99.9
50
95
50
95
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
75
95
95
0
0
0
50
50
0
50
80
0
0
0
0
To achieve the three effluent levels, an average value of efficiency was
assigned to each of the treatment processes (Table 20). As the efficiencies
of most treatment systems vary with the nature and flow conditions of the waste
and the engineering design of the treatment processes, these arbitrarily as-
signed efficiencies are not to be interpreted as definitive efficiencies, but
rather as an attempt to demonstrate the number of treatments required for a-
chieving each of the specified effluent levels.
TABLE 20. 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
30Z
50Z
85Z
AOZ
85Z
90Z
99. 9Z
5Z
80Z
85Z
35Z
90X
90Z
95Z
74
-------
Applications of control technologies for achieving the three effluent
level requirements from three levels of raw geothermal fluid are illustrated
1n Figures 47, 48 and 49. These figures depict the treatment units re-
quired that will attain each of the specified effluent levels. Implicit in
these illustrations 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 such as reverse os-
mosis, 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 processes
is 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 effi-
ciencies.
As an example, Figure 47 presents block diagrams of the various treat-
ment systems necessary for achieving the various assumed 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. Removal
of 95 percent of the TS requires sedimentation, chemical precipitation, filtra-
tion and reverse osmosis. The percentage of TS removed from the system is de-
picted by the arrow pointing downward from'the specific unit process. The per-
centage of TS remaining is shown by the arrow pointing to the right. Thus", 30
percent of TS is removed by sedimentation with 70 percent remaining in the treat-
ed waste. Of the 70 percent TS remaining, an additional 35 percent is removed
by chemical precipitation. Effluent from the chemical treatment thus contains
33 percent TS. Filtration then removes another 29.75 percent TS, and reverse
osmosis removes an additional 4.725 percent TS. At the end of this sequence
of treatment, 99.47 percent TS removal has been achieved and only 0.525 per-
cent TS remains in the treated effluent. A similar procedure can be followed
for SM. These flow diagrams show that the treatment requirements for SM remov-
al are always higher than or equal to those designed for TS removal. It ap-
pears logical, therefore, to assume that the effluent water quality require-
ments for each of the three levels should be governed by SM removal rather
than TS removal.
WASTEWATER DISPOSAL TECHNOLOGIES
Wastewater from geothermal conversion operations will require disposal
regardless of its quality or prior treatment. In general, the cleaner the
wastewater, the easier and less expensive the disposal method. For example,
effluents that meet water quality standards can simply be discharged to sur-
face 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 sim-
ply disposal; for example, injection may be practiced for geothermal reservoir
conservation and subsidence prevention.
75
-------
HIGH LEVEL WASTE
(A) Level 1 Requirement
T.S. • 95X removal; S.M. - 99.9X removal
T r r ' ) , 70X fc
T.S. 1 Sed 1
30X | 4
.M. beu f ••
35X | 4
r P iy
5X J + 76X | 4
,. ,, _ ,T-- •t«'*^i ~ n L >. n i1?^*
29.75XJ 4 4i725X| . |9947M j
• nit 2'8M. RO °' . R 0 to 0 n'fl«
16.15X] 4 2.565%| 0.2565XJ = 9g_97%
(B) Level 2 Requirement
T.S. • 99X removal; S.M. - 99.99X
, — _. 70* «* i 9«
1- /u*.
*
30X | 4
v u 1 -Vd 1 9W »
S.M. |__->«a | ^
r D 1. "
35X j 4
ea | •
30X | 4
t u - l 9W *
S.M. bea J *-
C P J
35X | 4
_. i n
r P "
5X j 4 76X j 4
Legend: T.S. Total solids
S.M. Soluble metal wit
Sed Sedimentation
C.P. Chemical preclplt
Flit Filtration
R.O. Reverse osmosis
* * Flit t>OJ*J RO «""•" . 0 " Rn n nn?R5t
16.15X| 4 2.565XJ 4 0.2565X j 4 0.02565XJ - J99.97X |
99.995X removal
* » Flit """"•! R n u.scj» i „ n « nspsx
29.75XJ 4 4.725X j + 0.4725X J = 99.953
* ^ Filt - R 0 °-^\\ . 0 0.0285X nn,Bi;t
16.15XJ 4 2.565XJ 4 Q.2565X [ 4 0.2565% | « (99.997X |
h most stringent requirement
atlon
Figure 47. Application of treatment technologies for achieving
three effluent quality levels from high level waste.
-------
MID- LEVEL WASTE
(A) Level 1 Requirement
T.S. » 50% removal; S.M. » 95% removal
T.S.I Sed
30% !
S.M.I Sed
5% J
/U* r
rl
ncv ,
95*
C.P.
^
* 3b%
19
C.P.
*
" Flit *
+ 76% J + 16.15%J = 9
2.85%
7.15%!'|
(B) Level 2 Requirement
T.S. = 90% removal; S.M. * 99% removal
•""" •""* •- - -
T.S.I Sed
30% !
S.M.I Sed
5* }
ru*
95% r
.r .
35% ! + 29.75 ! = 9
r p !i
% ^ rnt 2.8b%
76% ! + 16.15%} + 2
5oc*v
• tDw
4.75%!
.U. ••'— *• U.^bo*
.565%! = 99. 715% J
(C) Level 3 Requirement
T.S. = 95% removal; S.M.
99.5%
T.S.I Sed }-
70%
35%
S.M. Sed
•30% J +
95%
35%
-H Flit
29.75%
5.25%
^| R.O.
C.P.
~76% f
j^^nrrru^^Lj
16.15%)
4.725%
R.O.
2.565%
. 0.525%
99.475%
-«. 0.285%
99.715%!
Figure 48. Application of treatment technologies for achieving
three effluent quality levels from mid level waste.
-------
00
LOW LEVEL WASTE
(A) Level 1 Requirement
T.S. = 0 removal; S.M. = 50% removal
Se
5
(B) Level 2 R
T.S.
Cp
oe
30
C.P
Jc
5
(C) Level 3 R<
T.S.
CQ
oe
30
Cp
JC
5
95%
I .... ?Yj!L.-». n n _.._
d * t.P.
% t + 76% f
equlrement
= 50% removal; S.M. =
d 70% * C P
% J •»• 35% |
d 95% » C P '
% | + 76% 1
jquirement
= 75% removal : S.M. =
. 7U* _u r p j
% J + 35% |
d 9b* a- C P !<
K J + 76% j •
19%
81% J
90% removal
-j-ar
Ja*
| 65% (
f 16.15%J
95% removal
b% _,,t
H 29.75%J
^ r. Flit
•• 16.15%J
97,15% J
r ^_,y
** -j.tj*
94.75%j
., O oq*
97.15%|
Figure 49 Application of treatment technologies for achieving
* three effluent quality levels from low level waste.
-------
Subsurface Injection
Technology Description - 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 reser-
voir by injection was started in 1969; about eight billion gallons of conden-
sate have been injected to date. The current daily rate of injection is about
5 million gallons. Besides geothermal, many other industries have adopted sub-
surface injection of liquid wastes to prevent 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.
a 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 Injection
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 sys-
tem, will generally be preceded by settling in ponds or tanks to remove sus-
pended solids. Sometimes filters may be used for this purpose. The wastewater
may also require chemical or physical deaeration to reduce its corrosiveness.
Finally, it is injected into the geothermal reservoir through the injection
well. Injection may sometimes be accomplished by gravity alone, without the
79
-------
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 50 is a schematic diagram of a typi-
cal 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)
L_
BOTTOM 9 5/8 IN. 4062 FT. (1244 m]
S = STEAM
TOP 5 IN. LINER, 6703 FT. (2043 m)
P BOTTOM 7 IN.
BOTTOM 5 IN. LINER 8034 FT. (2448 m)
TD 8045 FT.
(2452 m)
Figure 50^ Typical injection well set-up
80
-------
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 well bore may cause forma-
tion plugging by the deposition of dissolved and suspended solids, and thus in-
crease resistance to injection. In order to maintain the injection rate, pres-
sure must then be increased. Increase in injection pressure increases operat-
ing 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 injectivity with time. The only sure
means of assessing injection potential is to inject continuously for an extend-
ed period, at least a few months, and monitor wellhead injection pressure ver-
sus flow rate.
Injection wells should be completed carefully to isolate the injection
horizon from shallow, fresh water aquifers. Any abandoned well near an injec-
tion well may provide a pathway for movement of the waste to shallow fresh water
aquifers (Ostroot, 1972). Inadequate cementing behind casings and/or corrosion
of liners can result in upward migration of water from geothermal reservoirs.
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 (Sadow, 1972):
• storage in impervious impoundments to permit, under quiescent
conditions, settling and physical separation of the unwanted
components;
0 corrosion control by proper pH control, deaeration, and use of
inhibitors;
• coagulation and clarification to accelerate gravity sedimentation;
0 filtration and addition of bactericide to prevent plugging by
bacterial growth; and
• pH and/or temperature control to reduce scaling.
81
-------
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 main-
tenance costs consist of expenditures for the operation and routine main-
tenance of wellhead equipment, piping and pumps.
Capital Costs - The capital cost of an injection well may be estimated
after determining the following well parameters:
- hole and pipe diameters
- the pumping system required (number, type, rating)
- depth of wells
- number of wells
- hydrology and geology of site
Once these data are known, the system design may be developed, and costs may be
estimated based on design specifications for the depth and diameter of the
well, the pumping requirements in terms of flow rate and pressure, and the
drilling equipment and procedure.
The variation of cost per well with well diameter is shown in Figure 51.
Pump cost may vary by over 100% per well, depending on the rating and material
requirements. The depth of the well and the number of wells affects pipe
costs and the time required for drilling, as will site hydrology and geology.
For a given geologic formation, the cost per unit of depth for drilling
an injection well increases with depth. The relationship between drilling
cost and well depth has not been clearly established for geothermal applica-
tions. Based on one study by Geonomics, Inc. in 1976, the injection well
costs for sedimentary lithology vary between $250,000 at 5,000 ft (1,524 m)
depth to approximately $750,000 at 10,000 ft (3,048 m) depth. Translated to
a cost per unit depth basis, the drilling and completion well cost varies
between $150-$300 per meter depth in 1976 dollars (Geonomics, 1977),, These
costs are affected greatly by the site lithology. For example, the capital
cost of drilling and injection per unit of depth in volcanic formations may
be 60 to 70 percent higher than in sedimentary formation. Unfortunately, few
data are presently available relating drilling costs and lithology.
Because of the wide variations in site-specific geology and hydrology,
and lack of complete data characterizing existing wells, injection well cost
data have not been usefully parameterized in terms of the various cost deter-
minants. In the absence of such cost data, the capital cost of injection wells
was derived by a simplistic approach involving the selection of a represen-
tative well cost using empirical cost data for actual wells. This represen-
tative cost was then used to develop total costs for multiple well systems
capable of injecting various wastewater flow rates generated .by the four
82
-------
10
O
u
III
1.4
1.3
1.2
1.1
1.0
J_
_L
7 8 9 10
HOLE SIZE (INCHES DIAMETER)
11
12
Figure 5.U Well hole size cost comparison (capital cost only).
energy conversion processes. The total cost of the well system was also
estimated for four selected well capacities representative of existing
capacities.
\
Table 21 summarizes the injection well cost data surveyed as the basis
for capital cost estimates developed in this report. The capital investment
for an injection well varies from $400,000 to $1,000,000. The individual
construction costs also vary widely. Based on inspection of Table 21, the
average capital cost of an injection well was taken as $500,000. The cost
of individual construction elements were also selected, and are shown in
Table 22. The well depth associated with the selected cost data varies
between 3000 and 10000 ft (915-3050 m), averaging about 6000 ft (1830 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
dispose of liquid waste as shown in Table 23. At that time, 82% of the
injection wells were at refineries, chemical plants, and steel mills.
The survey shows that the potential flow for an aquifer can be quite high,
although the median indicates that the bias of the survey data is definitely
in favor of the lower flows. The results of a 1970 survey, based on 75
injection facilities, are shown in Table 24. The results are grouped in
different ranges of depth, injection rate, and injection pressure, and
83
-------
TABLE 21. CAPITAL COST OF INJECTION WELLS, DATA FROM THE LITERATURE
00
General Information
and Cost Parameters
59.
Date Published Hay 77
Type Well Steam
Production
Location
Diameter (1n.)
Total Verti-
cal Depth(ft.)
Stralght(S) or
Directional (D)
Construction
Cost
• Drilling
Contr'or
Cost
Mud Exp.
Casing &
Tubing
Cementing
Logging
Perforation
Well Head
Equipment
• Engineering
Supervision
0 Control Sys.
Injection Pump
Injection Pipe-
line
Total Capital Cost
Reference Number
4. 32. 32. 62. 47.
1973 July 76 July 76 Dec. 77 c.
Steam Injection Injection Indectlon Add Waste
Production Disposal
Imperial E. Ohio
Valley.Ca.
3,300
$60,000 $128,880 $210.058
23,650 36,600
61,972 77*212
39,300 39,300
22,215 30,434
6,820 6,820
6,050 8,800
$500,000 .$564,000
47. 47. 47. 47
'c. c. c. c.
Add Waste Add Waste Acid Waste Acid Waste
Disposal Disposal Disposal Disposal
W. Pa. W. Pa. SW. NY SW. NY
4,800 6,000 3,060 4,300
$502,000 $447.000
$960,000 $770,000
c Reference publication date 1s 1974
-------
TABLE 21. (Continued
00
en
General Information
and Cost Parameters
56,
Date Published Oct. 76
Type Hell Injection
Location East Mesa,
Ca.
Diameter (1n.)
Total Vertical
Depth (ft.)
Stralght(S) or S
Directional (D)
Construction $403,077
Cost
• Drilling
Contractor
Cost
Hud Expense
Casing &
Tubing
Cementing
Logging
Perforation
Well Head
Equipment
• Engineering
Supervision
• Control Sys. 22.831
Injection Pump 54,200
In jectl on PI pel 1 ne 224 ,000
Total Capital Cost
Reference Number
56. 26. 19.
Oct. 76 Dec. 74
Injection Steam
Production
None
Specif 1c 'ly
9 5/8 9 7/8
7.000 10,000
D (48e) D (30°)
$535,448
$16.9,000
20,000
10,000
25,000
23,000
40,000
33. 16. 16. 16. 16.
Hay 77 June 77 June 77 June 77 June 77
Steam Injection Injection Injection Inject
Production
The Geysers, Roosevelt Coso Hot East Mesa Long
Ca. Hot Spr.Ut Sprg.Ca. Ca. Valley.Ca.
7,000 to
8,000
$658.000
30,000
124,500
50,000
33,000
20,000
28,000a
$700,000 $700,000 $400,000 $700,000
$l,003,500b
(Continued)
Includes overhead
Includes miscellaneous costs amounting to $60,000
-------
TABLE 22. AVERAGE CAPITAL COST FOR AN INJECTION WELL
Capital Cost Parameters Cost
Construction Costs
Drilling Contractor Cost $170,000
Mud Expense or Air Equipment Rental 20,000
Casing and Tubing (including accessories) 70,000
Cementing 40>000
L°99ing 20,000
Perforating 50^00
Well Head Equipment 40,000
Engineering Supervision 10,000
Control System 30>'000
Injection Pump 50t000
Injection Pipeline 0 a.
TOTAL CAPITAL COST $500,000b"
No pipeline is required if directional drilling is used. This
component could cost several hundred thousand dollars* ' if
required.
The total capital cost varies, in actual practice, from
approximately $300,000*32) to $1 mW1on(33). $500,000 is
considered to be a reasonable average.
are consistent with the results in Table 23. On the basis of the range of well
capacities indicated, four well capacities were selected for cost analysis:
200, 1000, 4000, and 8000 1/min.
The calculation of capital cost of various multiple well systems which
achieve the expected geothermal wastewater generation rates (up to 350,000
1/min) is shown in Table 25. 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 based on 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
operating 20% of the time).
The annualized costs for the multiple injection well systems are shown
in Figure 52, 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 re-
quired disposal rate. However, some caution should be exercised in applying
86
-------
TABLE 23. SURVEY OF 124 INJECTION WELLS FOR DISPOSAL OF LIQUID WASTE
(NIPCC, 1971)
Depth (m)
Injection Zone
Depth to Top (m)
Thickness (m)
Injection Rate (1pm)
Injection Pressure (psi)
Maximum
3890
3650
640
16300
4000
Minimum
90
61
1.5
0.57
0
Median
-810
625
56
512
185
TABLE 24. SURVEY OF 75 INJECTION WELLS FOR DISPOSAL OF LIQUID WASTE
(NIPCC, 1971)
Physical Parameters Percent of Total Wells
Depths of Hell
0-1000 feet (0-305 meters) 7
1000-2000 feet (305-610 meters) 29
2000-4000 feet (610-1220 meters) 22
4000-6000 feet (1220-1830 meters) 31
6000-12,000 feet (1830-3660 meters) 9
greater than 12,000 feet 2
Injection Rate
gpm 1pm
0-50 0-190 27
50-100 190-379 17
100-200 379-758 25
200-400 758-1516 26
400-800 1516-3032 4
greater than 800 greater than 3032 1
Injection Pressure,psi
partial vacuum 14
0-150 29
150-300 27
300-600 g
600-1500 20
greater than 1500 1
87
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TABLE 25. CAPITAL COSTS FOR INJECTION SYSTEMS AT FOUR WELL CAPACITIES
Well Capacity:. 200
Flow No. Wells
Req'd.
(liters/
m1n.)
10 1
100
500 2
1000 5
4000 20
5000 25a
10,000
00 15.000
30,000
50,000
100,000
350.000
Initial
Capital
Cost
($106)
0.5
0.5
1.0
2.5
10.
12.5
lorn/well J
Annual 1 zed
Cost Per
Unit of
Flowb
($/1000L)
10.60
1.06
0.42
0.53
0.53
0.53
Well Capacity: 1000
No. Wells
Req'd.
($/1000L)
1
1
1
4
5
10
15
30a
Initial
Capital
Cost
(S/1000L)
0.5
0.5
0.5
2.0
2.5
5.0
7.5
15.
Ipm/well
Annuall zed
Cost per
Unit .of
Flowb
($/1000L)
1.06
0.212
0.106
0.106
0.106
0.106
0.106
0.106
Well Capacity: 4000
No. Wells Initial
Req'd.
1
1
2
3
3
4
8
13
25a
Capital
Cost
($/1000L)
0.5
0.5
1.0
1.5
2.0
4.0
6.5
12.5
Ipm/well Well Capacity : 8000 Ipm/well .
Annuallzed ,, . . , Annual i zed
Cost Per No. Wells Initial Cost Per
Unit of Req'd
Flowb
($/1000L)
0.106
0.0264 1
0.0422 1
0.0316 2
0.0281 2
0.0281 4
0.0274 7
0.0264 13
44
Capital
Cost
($/1000L)
0.5
0.5
1.0
1.0
2.0
3.5
6.5
22.
Unit of
Flowb
(S/1000L)
0.0264
0.0211
0.0211
0.0141
0.0141
0.0148
0.0137
0.0133
a. Arbitrary limit
b. Total cost 1s annual1zed based on C - P(CRF), where P - total cost and CRF
Z IS?1*" "ld 30 Jear "rt-- " ™
-------
the data in Figure 52. The plots are predicated on the assumption that capital
cost of a well 1s 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 l/m1n, the relative cost of the larger diameter well would
be about 1.2 times'that of the smaller well (see Figure 51). Still, the cost
information developed in Figure 52 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 rela-
tively low compared to other environmentally acceptable disposal methods.
The annualized capital cost 1s determined to be only $2 million per year at
350,000 1pm injection, using 44 wells, each with a capacity of 8,000 1pm.
10
i.o
o
o
o
.10
.01
200 1/min EACH WELL
1000 1/min EACH WELL
4000 1/min EACH WELL
^^^•••^^•^•••B
8000 1/min EACH WELL
1.0X10
1.0x10'
l.Oxl Og
l.OxlO4
1,0X10-
WASTE FLUID FLOW RATE (l/«in)
Figure 53. Annualized capital cost for Injection of
geothermal wastewaters.
89
-------
Operation and Maintenance (O&M) Costs - The operating cost for an injec-
tion system will consist mostly of the energy cost for pumping. Routine
labor costs will be negligible, and maintenance costs over a thirty-year
period depend primarily on the application and service required. In many
cases, repair costs will be almost zero, while in others, anticipated main-
tenance or repair (due to corrosion, plugging, or wear) will prohibit the
use of injection entirely. For the purpose of costing, it is assumed that
4.0% of the capital investment is annual maintenance costs. This corresponds
to $20,000 per well. Depending on the flow temperature and the operating
pressure of the injection well, this maintenance 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 hydrologic
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 liters per minute, the losses are 1.3 psi per 100 feet
(30.5 m) of tubing. On the other hand, the pressure gain due to the elevation
head of the waste is 42 psi per 100 feet(30.5 m) of vertical depth (assuming the
waste brine has a 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 injection aquifer) is considered the strongest determinant for
pumping energy because of high variabilities in pressure differences.
Table 26 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.
(See Tables 21 and 22 in the discussion of capital costs.) In some cases,
the initial pressure requirement may be zero because of injection aquifer
conditions and/or the pressure gain in the well tubing. However, a pump
should.be included in the design to allow for eventual increases 1n pressure
requirements. Pressure requirements can change because of pressure built up
from Injection with time and because permeability of the stratum can change as
solids are filtered from 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 for direct disposal without appropriate
prior treatment.
Ocean disposal of spent geothermal fluids would, in principle, be an un-
complicated operation. The process involves the conveyance of the liquid,
probably by a pipeline, from the geothermal operation to the shore and thence
through a pipe laid on or in the ocean bottom to some distance offshore. At
90
-------
TABLE 26. OPERATING ENERGY COST FOR PUMPS
Pressure requirement Cost
(ps1) (cents/10001)
50
100
200
500
1000
1500
2000
4000
0.714
1.43
2.86
7.14
14.3
21.4
28.6
57.2
the outfall the wastewater may be released 1n a simple stream or jetted
through a manifold or multiple port diffuser. The dtffuser facilitates
the mixing of wastewater with sea water, both vertical and laterally, thus
causing rapid dilution and dispersion..
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.
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, the cost for conveyance
and ocean disposal of geothermal plant wastewaters can be exorbitant. Approxi-
mate costs for conveyance and ocean disposal of wastewaters may be obtained
from compilations of existing cost data such as that prepared for the San
Francisco Bay and Sacramento-San Joaquin Delta Area Wastewater Management
Survey Report (U.S. Army, 1972). Cost data from this study is presented in
Figures 53, 54, 55, and 56.
Figure 53 provides annualized capital costs for conveyance lines at
various wastewater flow rates. The curve is based on data for precast pipe
installations in open country routing and for precast pipe-foundations laid
on stable ground. Assumed land costs for conveyance line right-of-way in
rural areas was $3,000/acre ($0.74/m2). The design life of conveyance lines
was assumed to be 50 years.
91
-------
Figure 53.
10 100 1000
Flow (million liters/day)
Annualized cost of installation of wastewater
conveyance lines for open country routing
10,000
J
Discharge Rate
Figure 54. Annual cost of pumping wastewater for
head of 40 ft (12 m) to 100 ft (30 m)
92
-------
10
Figure 55.
'100 1000
Flow (million liters/day)
Cost of conveyance lines for ocean outfalls offshore
to depths of 200 feet (61 m)
10
i^L^^^ii
' ' " TO,
100 iddo
Flow (million liters/day)
Figure 96.. Cost of ocean outfall diffuser
000
93
-------
Figure 54 is a plot of annual cost of pumping wastewater when the ele-
vation head of the pipeline is between 40 and 100 feet (12 m and 30 m). A
head loss of 1.5 m per 1000 m wes assumed for conveyance lines and pipes were
sized accordingly. A peak flow factor varying between 2.9 at 1 MGD (0.044
m3/s) and 1.5 at 300 MGD (13.2 m3/s) was used for pumping station and power
costs. Overall efficiency of pumps was assumed to be 72%. The design life
of the pumping stations was assumed to be 30 years.
Figure 55 shows the cost of conveyance lines for ocean outfall construc-
tion offshore to depths of 200 feet (61 m). Figure 56 is a plot of the cost of
ocean outfall diffusers.
Costs for Figures 53 to 56 were adjusted from the base data (Jan 1972) to
current levels (1977) using the Marshall and Stevens Cost Index. All capital
costs were amortized over a 50-year life-of-project period to compute annual
costs. For facilities having a 30-year lifetime, replacement costs were in-
cluded in the initial capital investment by calculating present worth of the
replacement facilities.
Table 27 illustrates the high cost of disposing wastewaters from geo-
thermal plants in ocean waters. The cost does not include wastewater pre-
treatment necessary to achieve effluent standards for ocean discharge.
TABLE 27. NORMALIZED COST OF OCEAN DISPOSAL OF GEOTHERMAL PLANT WASTEWATERS
($/1000
Wastewater Annualized cost of Annual cost
flow 1/min conveyance lines* of pumping**
Annualized
outfall cost
Annualized
total cost
1,000
5,000
10,000
100,000
350,000
21 ,900
6,470
3,640
600
110
2,660
2,130
1,900
1,330
1,030
50,550
16,200
14,850
2,400
890
75,110
24,800
2Q,390
4,330.
2,070
*The cost of conveyance is based on an assumed open country routing of 200
miles (322 km). **It is assumed that wastewater Is pumped through an elevation
gain of 100 ft (30 m). ***An offshore outfall distance of 1 mile (1.6 km) is
assumed. The outfall cost is the sum of the annualized costs for the outfall
line and the diffuser.
94
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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, de-
pending upon the topography of the area. In some cases, natural depressions
may be utilized. In a few instances, 1t 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 sur-
face drainage outlet.
Unless the soil is impermeable, evaporation ponds must be lined to prevent
ground water pollution. Types of liners include clay, rubber, asphalt, con-
crete, and plastics (EPA, 1975).
Table 28 shows the expected water surface area required for evaporation
ponds accepting wastewaters at median rates from the various geothermal energy
conversion processes.
TABLE 28. ESTIMATED WATER SURFACE AREA REQUIRED
FOR DISPOSAL OF GEOTHERMAL WASTEWATERS
Geothermal Median Water Surface 2
Conversion System Wastewater Rate, 1/min Area, Acres*(km )
Direct steam 17,000 1,436(58)
power generation
Flashed steam, 80,000 6,757 (273)
binary, total flow
power generation
Direct heating 500 42 (1.7)
open and closed
systems
Desalination 3,000 254 (10.3)
*This is the amount of surface area required to maintain level of evaporation
ponds at steady state. The required area 1s estimated by A = Q/E, where A =
area required (acres), Q = wastewater generation rate (1/min), and E =
evaporation rate (in/year). It 1s assumed that losses through the pond
liner are negligible, and the evaporation rate 1s 60 Inches per year.
95
-------
Costs of Evaporation Ponds - Cost of evaporation ponds are related to
various dependent factors In a recent study conducted for the Environmental
Protection Agency (Black & Veatch, 1977). 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.
The total capital investment cost includes the costs of construction,
pond liner, embankment 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 57. 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 practiced
primarily for the disposal of industrial wastes such as cannery, pulp and paper,
dairy and tannery. Treated effluents have often 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 high
rate systems. Low rate systems utilize wastewater application rates of approx-
imately 2 to 10 ft/yr, (0.6-3m/yr) whereas high rate systems achieve applica-
tion rates of 150 to 350 ft/yr (45-107m/yr). Intermediate rates (10-150 ft/yr)
are not widely used.
Low rate systems are segmented into two types of application systems,
spray Irrigation and overland runoff. Spray Irrigation. 1s defined as. the con-
trolled 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 sDrayina
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 and subsequent percola-
tion of wastewater into the soil. The process is defined as the controlled
discharge of liquid onto the land at a rate measured 1n feet per week. Be-
cause of its high loading capacity, this process has a low potential for re-
moving residual pollutants from the wastewater.
96
-------
100,000
i/» 10,000
o
o
in
O
z
t/t
3
O
X
8
Z
1,000
100
10
TOTAL
ANNUAL
COST
ANNUALIZED
AS CAPITAL
INVESTMENT
OPERATING AND
MAINTENANCE
COST
I
I
I
10
100 1,000 10,000
WATER SURFACE AREA, ACRES
100,000
Figure 57. Total annual cost of evaporation ponds versus surface area.
The land area required for wastewater effluent disposal depends on the
loading rate used. The loading rate in turn depends on many factors including:
• the soil capacity and permeability for infiltration and percolation;
t hydraulic conductivity (percolation capacity) of the root zone of
cover vegetation;
t evapotranspiration capacity of site vegetation; and
• assimilation by soil and vegetation of nitrogen, phosphorus,
suspended solids, BOO, heavy metals, and pathogenic organisms.
97
-------
The maximum hydraulic loadings of wastewater for various soil textures
are shown in Table 29. The aqnual loading rate is substantially lower than
might be indicated by the daily loading rate because of the number of rest
periods required between applications.
TABLE 29. ESTIMATED MAXIMUM HYDRAULIC LOADING OF WASTEWATER EFFLUENT
FOR VARIOUS SOIL TEXTURES (IDEAL CONDITIONS)
Movement Through the Soil Root Zone*
cm/day cm/yr
Fine sand
Sandy lo.aci
Silt loam
Clay loam
Clay
38.1
19.0
8.9
3.8
1.3
762
457
229
102
25
o*
.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 neces-
sitate a corresponding reduction in application rates.
The hydraulic conductivity of the soil in a vertical direction determines
the total precipitation and effluent application that can be transmitted to
the ground water. Increased precipitation in a wet year reduces the amount
of effluent that can be applied to various soil textures under ideal condi-
tions.
Costs - The major advantage with wastewater land spreading is the low
cost of the approach. Table 30 snows the total annualized cost of land
spraying for the range of geothermal fluid flows anticipated. Capital invest-
ment costs and operating costs are based on an overland flow waste treatment
system at Paris, Texas (Liptek, 1974). The system reported total construction
costs at $1170 per acre ($3.11 per square meter) and operating costs at $.052
per 1000 gallons ($.014/1000 1) of wastewater. Application rate was a relative-
ly high 0.6 inches (1.5 cm) per day. Compared to other land application methods
(e.g., evaporation ponds), the cost of geothermal wastewater disposal is rela-
tively low by land spreading. However, a major disadvantage to this approach
is the vast amount of land required. For example, a typical size geothermal
plant (e.g., 100,000 1/min) would require 3.7 square miles (9.47 km?) of land
designated for waste disposal.
98
-------
TABLE 30. ANNUAL COST OF DISPOSAL OF GEOTHERMAL
WASTEWATERS BY LAND SPREADING
1/min
1,000
10,000
100,000
350,000
Land
Surface
Area
Required,
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
•Baaed on application rate of ,6 inches/day, (1.5 cm/day).
**At 8 percent interest rate*
•••Assumes 8000 hrs of operation per year.
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. Contain-
ment can include impermeable diking and/or excavation of areas large enough to
contain the potential flow until the flow can be stopped.
A commonly used approach for containment involves 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 environ-
ment 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 form-
ing 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 (Black & Veatch
1972). The costs shown in Figure 58 are derived from these data. Costs are
shown for surface containment ponds suitable to manage unplanned releases of
99
-------
geothermal fluids at various flows and durations. The total annualized costs
include construction cost, engineering design and embankment protection. The
surface area requirements for the specified flow ranges (10 to 350,000 1/min.)
vary from 12 square feet (1.1 m2) to 41 acres (166,000 m*) depending on the
duration of the spill.
100
o
o
o
8
<
z
z
<
_J
<
5
24 HOUR SPILL
HOUR SPILL
6 HOUR SPILL
1000
10.000
100,000
Figure 58,
FLOW RATE, 1/MIN
Annual1zed 1
containment
nvestment cost of spill
ponds (10 foot depth).
100
-------
SECTION 7
SOLID WASTE GENERATION AND DISPOSAL COSTS
Design and costing of pollution control equipment require knowledge of
the kind and quantity of pollutants to be removed. In addition, any pollution
equipment generates waste sludges. The costs for waste sludge handling and
disposal vary with their quantity of generation. This section discusses the
pollutant loading from geothermal development and waste products generated as
a result of pollution control. In addition, the cost for disposal of residual
waste products is also presented.
POLLUTANT LOADING
As discussed in the section 5, the air pollutant currently of greatest con-
cern from geothermal development is hydrogen sulfide (l^S). The generation rate
of H£S is a function of the concentration of H2S in the geothermal resources and
the steam flow rate. For steam flow in the range of 100,000 to 1,000,000 kg/hr,
the H2S loading at various concentrations has been determined (Figure 59).
The pollutant loading from water discharges is a function of brine con-
centration and flow. For the purpose of this repo'rt four major conversion
processes have been identified for detail analyses. They are: direct steam
power generation system; flashed steam; binary; total flow power generation
system;, direct heating, open and closed system; and desalination system.
Arbitrarily assigned concentration levels and flow ranges for analyses of
these geothermal conversion processes have been presented in Tables 17 and 18
in Section 6.
For simplicity, the major wastewater pollutants are grouped as total
solids (TS) and soluble metals (SM). Total solids include both dissolved and
suspended solids. Dissolved solids are mainly sodium, chlorides, sulfates and
carbonates. Soluble metals are quantitatively minor constituents and include
iron, manganese, boron, zinc, barium, lead, copper, arsenic, mercury, selenium,
chromium, silver and cadmium. Suspended solids are primarily silica and metal
silicates. They are often created from dissolved solids within the conversion
system upon reduction of brine temperature and pressure. The pollutant load-
ing from water discharges for these four major conversion processes are depict-
ed in Figures 60, 61, 62 and 63. The loading rates (in kg/hr) are derived
from information presented in Tables 17 and 18.
WASTE PRODUCTS GENERATED BY POLLUTION CONTROL EQUIPMENT
To estimate costs of handling and disposal of residual products, it 1s
necessary to identify and estimate the amount of the residual matter produced
by each control system process. The following sub-sections describe the resi-
dual generation sources and estimate the residual quantities. The discussion
101
-------
10°,
Steam
flow'
rate
Ug/hr)'
10 ' ' ' ' 100
Total Loading of HjS
(metric tons/day)
1000
Figure 59. Hydrogen sulflde loading rate to turbine
as a function of steam flow rate
10"
Wastewater •
Flow 10*.
(Vm1n) :
103
%
X
1 1
X
X
M •>
/'
1 -1 4 I
x ,
>
0 ' ' 100 ' ' TO
/
"ViX vNV
*~\r _r^
X
/
oo ' ' ib'.ooo
LEGEND:
(1) Hid level geo-
thermal waste
(2) Low level geo-
thermal waste
Pollutant Loading (kg/hr)
Figure 60. Wastewater pollutant loading for direct
steam power generation system
Wastewater
Flow n()5
(I/Bin)
LEGEND:
(1) High level geo-
thermal waste
(2) Mid level geo-
thermal waste
(3)-Low level geo-
• thermal waste
10
«T
10' 10* 10'
Pollutant Loading (kg/hr)
o
Figure 61. Wastewater pollutant loading for flashed steam
binary, total flow power generation system
102
-------
1,000
3
LEGEND:
(1) Hid level geo-
thermal waste
(2) Low level geo-
thermal waste
Wastewater Flow (1/mln)
Figure 62. Wastewater pollutant loading for direct
heating, open and closed systems
s
1
100
•
/
\&
1 III
4
«*;>//
i j
/
^ y
-
/
>
100
Hastewater flow (1/raln)
,000
LEGEND:
(1) High level geo-
thermal waste
(2) H1d level geo-
therroal waste
Figure 63- Wastewater pollutant loading for
desalination system
is separated in two parts: 1) residuals from air pollution controls, and 2)
residuals from water pollution controls.
Residuals from Air Pollution Controls
The pollutant of greatest concern is hydrogen sulfide. Candidate control
systems for removal of hydrogen sulfide are the Stretford, iron catalyst, EIC,
and Dow o^genation processes. Applicability of these processes depends on
the type of energy conversion system and the geothermal fluid properties.
For the various air pollution control systems applicable to steam turbine
power generation, the ^S concentration is assumed to range from .02 percent
to 5 percent by weight of the steam input. Steam flow rates in the geothermal
systems are assumed to vary from 100,000 to 1,000,000 kg/hr.
Stretford Process -
The Stretford process is self-maintained as the scrubbing chemicals are
regenerated in multi-stage reactions and high purity elemental sulfur is the
only residual product produced. Thus, the quantity of residuals produced by
the Stretford process is estimated directly from the amount of ^S known to be
present in the ejector gases, and the assumption that the Stretford will re-
move essentially 100 percent of the H2S from the treated gas stream.
103
-------
The quantity of H^S in the ejector gases is approximately 80 to 90 per-
cent of that existing in the turbine stream with the remaining 10 to 20 per-
cent dissolved in the condensate. Figure 64 illustrates the amount of sulfur
produced when the Stretford unit is used to control various concentrations of
H2$ in the turbine discharge stream. The potential rate of sulfur production
can be expressed as .847 QC kg/hr, where Q is the turbine steam rate (kg/hr)
and C is the fraction by weight of H2S in the steam. The constant .847 is the
product of the fraction of H2S in the ejector stream (90 percent) and the
weight fraction of sulfur in ^S (32/34).
Dow Oxygenation -
In the Dow Oxygenation process, H2$ is removed from geothermal liquid by
injecting oxygen into the brine upstream of the power plant. The H2S in solu-
tion is oxidized to sulfate, sulfide, and sulfur. The relative amount of dif-
ferent solids formed depends on the brine temperature and total dissolved
solids in the brine. If the brine is already saturated with salts (e.g., cal-
cium sulfate), free sulfur particles may be generated (J. Wilson, 1977). When
the brine is not saturated with salts, the additional sulfate formed by oxy-
genation will remain in solution which may require treatment after the geotherm-
al fluids are spent. The free sulfur fines will also remain suspended until
removal is effected. In the most probable scenario, a substantial portion of
sulfates, sulfate precipitates, sulfites, and sulfur created by the Oxygenation
process will remain in the geothermal fluid as it is flashed, condensed, and
routed for final disposition as a wastewater. Ideally the residuals would be
injected with the spent water and not require prior separation. However, for
the purpose of the analysis here, it is assumed that the products of the oxy-
genation process will be removed from the wastewater as sludges so that the
residual disposal problems attributable to this air pollution control system
may be assessed.
Bench scale tests of the Dow process have shown that 90 percent to 100
percent of H2$ removal may be expected. Figure 65 shows the amount of solid
material that will require disposal if the Dow Oxygenation process is employed
for liquid dominated geothermal processes. It is assumed that calcium sulfate
(CaS04) is representative of the precipitates in the waste solids which must
be removed, and that the solids are concentrated to 25 percent by weight in
settling ponds before disposal as a heavy sludge. The sludge thus produced
consists of 1/3 free sulfur and 2/3 calcium sulfate.
EIC Process -
In the EIC process, H2S is removed from steam upstream of the power plant.
An aqueous solution of copper sulfate scrubs the H2$ from the steam as copper
sulfide precipitate. A copper sulfide slurry is collected and concentrated
by centrifuging. Copper sulfate is then regenerated from the concentrated
solution. Sulfur dioxide and sulfur trioxide are produced during regeneration
and scrubbed by an ammoniacal solution to produce ammonium sulfate, which is
mixed with cooling tower water and injected underground. Hence, in the normal
operation, all residual matter produced by the EIC process will be carried by
the spent geothermal fluids to the injection wells.
104
-------
Where injection may not be permitted, or where pre-treatment of the waste-
water to facilitate Injection is required, a portion of residual matter creat-
ed by treatment will be attributable to the ammonium sulfate generated by the
EIC control process. For the purpose of the analysis here, it is assumed that
the total quantity of ammonium sulfate in solution will be removed as sludge
and conveyed away for disposal. Reclaiming of the compound for fertilizer
would probably be no more cost effective than outright disposal, since addi-
tional purification of the fertilizer would be necessary due to presence of
other elements such as heavy metals (Brown, 1977). Figure 66 shows the amount
of solid material, as ammonium sulfate, which could be removed as sludge and
conveyed to landfill for disposal. The sulfate is assumed to be present in a
sludge concentrated to 25 percent solids by weight. The efficiency of the EIC
process in removing H2$ from the steam is assumed to be 90 percent.
Iron Catalyst -
In the iron catalyst process, ferric sulfate is added to cooling water
to oxidize hydrogen sulfide contained in the aqueous phase. The cooling waters
are then used additionally to scrub hydrogen sulfide from the condenser ejec-
tor gases. Elemental sulfur, water, and ferrous ions are formed, and the sul-
fur is removed from the cooling water by filtration. The filtration step pro-
duces a thick and toxic sludge that must be conveyed to a landfill for disposal
Tests of the iron catalyst process at The Geysers Geothermal Field have
shown approximately 50 percent removal of hydrogen sulfide to be technically
achievable. This efficiency includes H2S removal from the condensed cooling
tower fluids and from the ejector gases. Figure 67 illustrates the quantities
of waste sludge generated by the iron catalyst control process for various
steam H2$ loadings. The sludge is assumed to be 25 percent solids (primarily
sulfur) by weight.
Residuals from Treatment of Wastewaters
The residual materials removed by treatment of geothermal wastewaters con-
sist of suspended solids and dissolved materials in the wastewater, as well as
chemicals added during treatment. Together, these residual materials, along
with water, constitute a sludge which is usually disposed of in a landfill or
evaporation lagoon.
The amounts of sludge (Rs) produced by the various physical treatment
processes may be approximated by:
Rs = 2CE
where Q = wastewater production rate, 1/min.
C = concentration of constituent in wastewater, mg/1
E = efficiency of system for removal of constituent
f = fraction by weight of constituent in residual sludge
105
-------
106J
Steam
Flow
Rate
(kg/hr)
Figure 64.
10
100 1000
Rate of Sulfur Generation (metric tons/day)
Sulfur generation from Stretford unit for
various steam flow rates through turbine
*(4400) 106r
Steam
Flow
Rate
(kg/hr) -
"(440)
Rate of Sludge Generation (metric tons/day)
Figure 65. Potential solid waste as sludge generated
by Dow oxygenated system *(Brine flow rate
is gpm)
Steam
Flow
Rate
(kg/hr)
10
Figure 66,
10 ' 100
Rate of Sludge Generation (metric tons/day)
10,000
Sludge generation from EIC process for various
steam flow rates through turbine
Steam
Flow
Rate
(kg/hr)
10,000
VO 100 1000
Rate of Sludge Generation (metric tons/day)
Figure 67. Sludge generation from iron catalyst process
for various steam flow rates through turbine
106
-------
The sludge produced by chemical precipitation of constituents is estimated
by:
Rs = QCEx^
me
where mp = molecular weight of precipitate
me = molecular weight of constituent in wastewater
The above equations were used to calculate the amounts of waste sludge
produced by treatment of geothermal wastewaters from three specified levels of
pollution to three acceptable discharge levels as delineated in Tables 17 and
18(Section 6). A total of nine scenario abatement schemes have been considered
consisting of three levels of wastewater composition and three possible levels
of discharge concentrations.
The wastewater treatment systems capable of attaining the various levels
of effluent quality are comprised of combinations of individual treatment tech-
nologies which were discussed in Section 6. These schemes, and the cleanup
scenarios identified above, were utilized as the basis for calculating the
quantities of solid waste associated with the various geothermal conversion
systems.
Table 31 summarizes estimates of the quantities of solid materials re-
moved from the wastewater for each of the cleanup scenarios. The estimates
are presented in terms of solids removal factors (i.e., quantity per unit of
wastewater flow). Chemical precipitation was assumed to produce a solid weigh-
ing 1.5 times the material in the raw wastewater.
Table 32 summarizes estimates of the quantities of waste sludge generated
by the treatments to remove solid materials from the wastewater. The esti-
mates are presented in terms of sludge generation factors. The sludge is as-
sumed to be 98 percent water by weight (a typical dilution rate for municipal
sludges).
Based on the factors developed for solids removal and sludge generation
rates, Table 33 presents a summary of the probable quantities of solid waste
produced by treatment as a function of flow rates from the various conversion
processes with varying raw waste and effluent qualities. It should be noted
that the amounts of sludge generated are based on 2 percent solids concentra-
tion. Before these sludges are disposed of in landfill sites, they are usually
concentrated in settling ponds or by evaporation to approximately 50 percent
solids by weight. Thus the quantities shown in Table 33 can be reduced by a
factor of twenty-five. For high strength waste, the amount of sludge gener-
ated could not be determined by the above equations because the raw waste con-
stitutes a sludge itself (10% solids). For this strength waste, the sludge
generation rate (SGR) was estimated by using the equation SGR = 1.583 Q where
Q is the waste flow rate in 1pm.
COST OF SLUDGE DISPOSAL
The amount of sludge requiring disposal depends on the geothermal process
107
-------
TABLE 31. SOLIDS REMOVAL RATE ACCOMPLISHED BY WASTEWATER CLEANUP SYSTEMS.
Concentration level of raw wastewater constituents, metric tons/day per 1/urln of raw wastewater
Level of
cleanup
High
M1d
Low
Total sollds(TS)
removal rate .169
Soluble metals(SM)
removal rate
Total
(TS + SM) .171
.169 .169 .0162 .0168 .0168 .00238 .00323 .00323
.00161 .00161 .00161 .000281 .000292 .000292 .0000247 .0000281 .0000281
.171 .171 .0165 .0171 .0171 .00241 .00326 .00326
o
00
TABLE 32. SLUDGE GENERATION RATES ASSOCIATED WITH CLEANUP OF GEOTHERMAL WASTEWATERS.
Concentration level of raw wastewater constituents, metric tons/day per l/m1n of raw wastewater
Level of
cleanup
High
1 2
Mid
3123
Low
1 2
3
SIudge
(Assuming 93%
water by weight)
8.55
8.55 8.55 .825
.855 .855
.121
.163 .163
-------
o
10
TABLE 33. SLUDGE GENERATION RATE (METRIC TONS/DAY) AS A FUNCTION OF
FLOW RATES FOR SPECIFIED CONVERSION PROCESSES.
Raw waste
and
treatment
level
High level*
1
2
3
M1d level
1
2
3
Low level
1
2
3
Direct steam
power generation
flow (1pm)
4000 to 30,000
3300
3420
3420
484
652
652
—
to
to
to
to
to
to
24,750
25,650
25,650
3630
4890
4890
Flashed steam, binary,
total flow power gen.
flow (1pm)
15,000 to 350,000
23,750
23.750
23.750
12,375
12,825
12,825
1815
2445
2445
to
to
to
to
to
to
to
to
to
554.000
554.000
554.000
288,750
299,250
299,250
42,350
57,050
57,050
Direct heating
open and closed systems
flow (1pm)
10 to 1000
8.25
8.55
8.55
1.21
1.63
1.63
—
to
to
to
to
to
to
825
855
855
121
163
163
Desalination
process
flow (1pm)
1000 to 5000
1580 to 7910
1580 to 7910
1580 to 7910
825 to 4125
855 to 4275
855 to 4275
—
~
--
* These estimates do not reflect wastewater treatment because the raw waste constitutes a sludge Itself.
Therefore the values reported are the binary wastewater generation rates (corrected to a specific gravity
of 1.1); for high level waste. S.G.R. • 1.583Q.
-------
and the size of the plant. Based on the wastewater flow ranges assumed for
this study, waste sludge will be generated in quantities from one metric ton/
day to 554,000 metric tons/day. The sludge may be disposed of either directly
by landfill or by a two-step process involving settling lagoons and landfill.
If the sludge contains substantial amounts of heavy metals, it will be consi-
dered a "hazardous waste" and therefore subject to special disposal regula-
tions. For example, land spreading of such wastes would not be acceptable.
Lagoons and landfills must meet specified design standards before hazardous
waste may be accepted; these requirements will lead to higher cost of disposal.
Landfill
The cost for disposal of hazardous waste in an appropriate landfill varies
from $8 to $12 per ton of waste. Rate reductions of up to 25 percent may be
available for the disposal of high volume and/or repetitive wastes (Kinna,
1977). Normally, the greatest cost of waste disposal at a landfill is hauling.
Typical hauling rate is $32 per hour for a truck having a capacity of 20-25
tons. Hauling time consists of about 2 hours for loading and unloading, plus
actual road-trip travel time.
Table 34 shows the total cost for waste disposal of geothermal wastewater
treatment sludge when the disposal site is 200 miles (322 km) from the plant.
The sludge is assumed to be 50 percent by weight solids, which implies prior
dewatering in an evaporation lagoon before disposal to the landfill. The dis-
posal costs of Table 34 do not reflect the expense of sludge dewatering re-
quired to prepare the waste sludge for economical landfill disposal. Dewater-
ing of the sludge has been assumed to be carried out to a relatively high
degree (50 percent solids), such that waste conveyance and disposal costs are
minimized. The actual degree of dewatering would depend on the economic trade-
off between wet transportation and drying of the sludge before transport.
Evaporation Ponds
Normally, landfills are used as the ultimate disposal locations, and eva-
poration ponds are used as an interim process for drying or concentrating
sludges before removal to landfill. Evaporation ponds may also be used for
ultimate disposal; however, potential hazards of heavy metal accumulation and
subsequent leakage into the soil and groundwater may rule out permanent dis-
posal of geothermal wastewater sludges in evaporation ponds.
The factors affecting cost of an evaporation pond include: proximity to
wastewater treatment site, lining requirements, local meteorology, construc-
tion costs, cost of land, and administrative costs. Conveyance distance costs
for the sludge to the drying ponds is usually minimized by locating the ponds
near the wastewater treatment site. Unless the ponds are in impermeable soils,
it will be necessary to install ? liner material (e.g., plastic sheet) in the
pond to prevent movement of leachate into water sources. The depth of the
pond is usually about 3 to 5 feet (1-1.5 m) and total surface area and land
requirements are determined by the rate of sludge generation and the precipi-
tation and evaporation occurring at the site. Table 35 summarizes estimates
for the land requirements and cost for evaporation ponds which will accept
110
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TABLE 34. COST OF LANDFILL FOR GEOTHERMAL WASTEWATER TREATMENT SLUDGES
Geothermal
conveHson
system
Median Sludge
generation rate
(concentrated)
Metric ton/day
Cost of
hauling**
$/day
Cost of
disposal**
$/day
Total cost of disposal
$/day $/year
Direct steam
power generation
581
6500
5810
12,310
4,493,200
Flashed steam,
binary, total flow
power generation
6240
70,000
62,400
132,400
48,326,000
Direct heating
open and closed
systems
Desalination
17.2
103
193
1154
172
1030
365
2184
133,200
797,200
Sludge 1s assumed to be concentrated to 50 percent by weight water after dredging from evaporation ponds.
The median rate Is based on the median level of the expected sludge generation range for the
conversion system specified. The quality of the raw wastewater 1s assumed to be at the mid
level anticipated for given conversion system.
**
Cost of disposal 1s taken as $!0/metr1c ton and cost of hauling is estimated at $224 per truckload
of 20 metric tons. Hence, the total dally cost of removal and disposal is $21.4/ton of concen-
trated sludge. Expressed in terms of the diluted sludge (prior to dewataring), the annual cost of
disposal and hauling 1s $312/ton.
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TABLE
35. TOTAL ANNUAL
AND DISPOSAL
COST OF WASTE SLUDGE TREATMENT, REMOVAL
, AT "MEDIAN" SLUDGE GENERATION RATES.*
Energy
conversion
system
Cost of
evaporation
ponds
Hauling Total
cost to Landfill annual
landfill disposal cost
Direct steam
power generation
Flashed steam,
binary, total
flow power
generation
Direct heating,
open and closed
COST IN TOTAL DOLLARS
1,000,000 2,372,500 2,120,700
5,493,000
13,500,000 25,550,000 22,776,000
61,826,000
systems
Desalination
84,000
800,000
70,450
421,210
62,780
376,000
217,230
1,597,000
*(Based on Information developed 1n Table 34).
"median" quantities of waste sludge generated by the various geothermal con-
version systems. The water surface area requirements are estimated based on
the amount of evaporation expected at the geothermal site. A typical net eva-
poration rate of 60 inches/year (1.5 m/year) in the Southwest United States
(Wiessman, 1972) is sufficient to maintain a constant water level in a one
acre evaporation pond accepting 16 metric tons/day of liquid sludge (assuming
negligible water loss through the liner of the pond). The total land area re-
quired to accommodate the evaporation ponds is based on results of a recent
study for EPA (Black & Veatch, 1977) which established a correlation of water
surface area to land area requirement. The required land includes provision
for access roads, dikes, and support equipment. The total cost of the evapo-
ration ponds is dependent on the various factors discussed above, and is deter-
mined from Figure 57 in Section 6.
Table 35 shows that substantial amounts of land area will be needed if
geothermal waste sludges are concentrated in evaporation ponds before removal
to a landfill site. The land requirements would be greatest for flashed steam
power generation systems. It is estimated that a median sludge generation rate
from a flashed steam system would require nearly 10,640 acres (43 km2) of land
for evaporation ponds. The corresponding costs of the evaporation ponds, plus
the cost of conveyance and disposal at landfills is prohibitive, as shown in
Table 36.
112
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TABLE 36. LAND REQUIREMENT AND COST OF SLUDGE EVAPORATION PONDS
Geothermal
conversion
systems
Median sludge
generation rate,
metric ton/day
Water surface
area required,
acres*
Land area Total annual1 zed cost
required cost of evaporation
acres ponds**
Direct steam
power generation
Flashed steam,
binary, total
flow power
generation
Direct heating,
open and closed
systems
Desalination
14,535
156,000
431
2565
901
9672
27
159
991
10,640
46
175
$ 41,000,000
$413,500,000
$ 84,000
$ 800,000
^Determined by A = Q/yE, where A = area required, Q = sludge generation rate, y = density of sludge,
and E = evaporation rate. It 1s assumed that y = 60 lb/ft3 and E = 60 Inches per year. Thus,
A = .062 Q, where A = acres of water surface area required, and Q 1s the wastewater flow in metric
ton/day. (Based on Information developed 1n Table 34).
**Based on evaporation pond cost data presented 1n Section 6 (Figure 58).
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TECHNICAL REPORT DATA
(Please read Instructions on the reverse before completing)
1. REPORT NO.
EPA-600/7-79-225
3. RECIPIENT'S ACCESSIOWNO.
TITLE AND SUBTITLE
Preliminary Cost Estimates of Pollution Control
Technologies for Geothermal' Developments
5. REPORT DATE
October 1979 issuing date
6. PERFORMING ORGANIZATION CODE
7. AUTHOR(S)
R. Sung, G. Houser, G. Richard, J. Cotter, P. Weller,
E. Pulaski
8. PERFORMING ORGANIZATION REPORT NO.
I. PERFORMING ORGANIZATION NAME AND ADDRESS
TRW, Inc.
Environmental Engineering Division
One Space Park
Redondo Beach, CA 90278
10. PROGRAM ELEMENT NO.
1NE624B
11. CONTRACT/GRANT NO.
68-03-2560
Work Directive T5004
12. SPONSORING AGENCY NAME AND ADDRESS
Industrial Environmental Research Lab,
Office of Research and Development
US. Environmental Protection Agency
Cincinnati, Ohio 45268
- Cinn, OH
13. TYPE OF REPORT AND PERIOD COVERED
Final
14. SPONSORING AGENCY CODE
EPA/600/12
15. SUPPLEMENTARY NOTES
16. ABSTRACT
This report provides preliminary cost estimates of air and water pollution
control technologies for geothermal energy conversion facilities. Costs for
solid waste disposal are also estimated. The technologies examined include
those for control of hydrogen sulfide emissions and for control of water dis-
charges containing metals and inorganic dissolved solids.
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
cost estimates
97G
68D
8. DISTRIBUTION STATEMENT
RELEASE TO PUBLIC
19. SECURITY CLASS (ThisReport)
UNCLASSIFIED
21. NO. OF PAGES
131
20. SECURITY CLASS (Thispage)
UNCLASSIFIED
22. PRICE
EPA Form 2220-1 (9-73)
120
o u S OOVtmuEHT nuKIixc WFict u»o.657-146/5495
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