&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 180C.  The cost for the EIC
process is  3.6 mills per KWH at 830 ppm H2S, 150C, 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 177C 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

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     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;
      40C 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 HS 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 180C.  The cost for the EIC process is 3.6 mills
        per KWH at 830 ppm h^S, 150C, 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 177C 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

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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 (<90C) 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

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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

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      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

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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

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                  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

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                                 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

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     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

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           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

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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: 180C (355F)

                      : 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

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     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

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                  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) HS concentration at the given steam flow rate,
       results in a sulfur production rate beyond the range of this cost estimate.

                                         20

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             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 (355F)
                                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

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             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

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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  :   180C (355F)

                       :   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

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     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 (355F)
                                           7.8 ATM (114 pilt)
          10.000
       109 000

NHER KNERATNN (HM)
Figure 13.   Iron catalyst annual cost vs* power generation

                                27

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                   907.000 kg/hr (2,000.000 Ib/hr)
                   180"C (355F)
                   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

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     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
- n3
* CuS
U4
  Overal1
 reaction  CuS04  + H2S^CuS + H2S04
                                          29

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     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
CS04 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

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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

150C (300F)

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

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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

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               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
 150C 1300F)
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

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  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

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     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 350F (175C)
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

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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

                            :  177C (350F)

                            :  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

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     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

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  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

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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

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      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

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 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:
                                          177C (3SOF)
                                          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:
                                           177C (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

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CTt
           100,000 I/Bin (.20 6PM)
           98.2 NUjwntratlon capacity
           Doublt flash c
          conversion systw
177C (350F)
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

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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
1200C 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

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                   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

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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  +  HS  * 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

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     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 (40-51C), 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

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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

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                                  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. thy will not roaove significant
amounts of dissolved or emulsified materials.
                                      52

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     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

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     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"ijt-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 15-30C.  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 200F,  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 tii"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

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     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 , ^aPrators 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 (20C)
                                                                   - DISTILLATE
                                                                      BRINE (30C)
                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
           ^^ 105C
                 HEAT EXCHANGER

2) SEAWATER

g) LOW PRESSURE STEAM

3 COMPRESSED  STEAM

0) FRESHWATER
BRINE

0.25 m3/hr, 27C

SEAWATER
1.25 m3/hr, 15C
                                                      * FRESHWATER
                                                         1.00  m3/hr,  21C
                        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 40C.  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 65C), the same
evaporator could yield about 75 percent evaporation at a feed temperature of
150bC, and 90 percent evaporation at 225C.
                                       70

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                 TABLE 15.  COMPONENT  COSTS  FOR EVAPORATION,

                               Basis:  SOX of feed evaporated,
                                     40C 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

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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^*.Hle*.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

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             TABLE  17.   ASSUMED  GEOTHERMAL WASTE BRINE AND  SURFACE
                         WATER  DISCHARGE CONCENTRATIONS (mg/1).
                           Gothermal 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

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           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

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     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

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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

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   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

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                      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

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                                                       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

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               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

                       L99ing                             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

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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

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     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 100C).  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

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                  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

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        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

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      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

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     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

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     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

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               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

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                                  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 HS 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

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                      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

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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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                                   REFERENCES


 1.   Allen, G.W., Pacific Gas and Electric Company, telephone conversation,
      November 18, 1977.

 2.   Argo, D.G., "Wastewater Reclamation by Reverse Osmosis," presented at
      the 50th Annual Conference of W.P.C.F., Philadelphia, October 1977.

 3.   Battelle Pacific Northwest Laboratories, Removal of H?S from Geothermal
      Steam, September 1976.

 4.   Bell, G.R., Design Criteria for Diatomite Fillers, J. AWWA 54, October
      1962.

 5.   Black & Veatch Consulting Engineers, Wastewater Stabilization Ponds,
      prepared for the Environmental Protection Agency, 1977.

 6.   Bond, R.G., and C.P. Straub, Handbook of Environmental Control, Vol. Ill,
      Water Supply and Treatment, CRC Press, Cleveland, Ohio 1973.

 7.   Bond, R.G., and C.P. Straub, Handbook of Environmental Control, Vol. IV,
      Wastewater Treatment and Disposal, CRC Press, Cleveland, Ohio, 1974.

 8.   Brown, F., Environmental Impact Corporation, personal communication,
      December 1977.

 9.   Chen, C.L., and R.P. Miele, Wastewater Demineralization by Two-Stage
      Fixed Bed Ion Exchange Process, EPA Report EPA-600/2-77-146, September
      1977.

10.   Chen, C.L., and R.P. Miele, Demineralization of Sand-Filtered Secondary
      Effluent by Spiral-Wound Reverse Osmosis Process, EPA Report - EPA-600/
      2-77-169, September 1977.

11.   Chen, C.L., H.H. Takenaka, and R.P. Miele, Demineralization of Wastewater
      by Electrodialysis, EPA Report, EPA-600/2-75-047, October 1975.

12.   Cheremisinoff, P.N. and A.G. Morresi, Geothermal Energy Technology
      Assessment, Technomic Publishing Co., Inc., Westport, Conn., 1976.

13.   Cuellar, G.; Behavior of Silica in Geothermal Waste; Proceedings of the
      Second UN Symposium on the Development and Utilization of Geothermal
      Resources, San Francisco; May 20-29, 1975.

14.   Culp, R.L., and G.L.  Gulp, Advanced Wastewater Treatment, Litton
      Educational  Publishing, Inc.,  New York 1971.
                                      114

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15.  Dodds, F.J., A.E.  Johnson and W.C.  Ham;  Material  and Corrosion Testing
     at The Geysers Geothermal Power Plant;  Proceedings of the Second UN
     Symposium on the Development and Utilization of Geothermal  Resources;
     San Francisco, May 20-29, 1975.

16.  Dow Chemical Co.,  Texas Division, Removal  of Hydrogen Sulfide from
     Simulated Geothermal  Brines by Reaction  with Oxygen, April  1977.

17.  Dryden, F.D., "Mineral  Removal  by Ion Exchange and Electrodialysis,"
     presented at the Workshop on Wastewater  and Reuse, sponsored by UC
     Berkeley at South  Lake  Tahoe, California,  June 1970.

18.  EIC Corporation, Control  of Hydrogen Sulfide Emission from  Geothermal
     Power Plants, Annual  Status Report, July 1976.

19.  Environmental Protection Agency, "Information about Hazardous Waste
     Management Facilities,11 February 1975.

20.  Environmental Protection Agency, "Liners for Land Disposal  Sites,"
     March 1975.

21.  Faber, H.A.; Improving  Community Water Supplies with Desalting Technology;
     Jour. Am. Waterworks  Assoc.; November 1972.

22.  Fairfax, J.P., and H.K. McCluer, Hydrogen  Sulfide AbatmentGeysers Power
     Plant Progress Report 7485.3-71; Pacific Gas and  Electric Co., January
     1972.

23.  Feigenbaum, H.N.,  Removing Heavy Metals  in Textile, Industrial Waste
     Journal, March/April  1977.

24.  Galeski, J., Midwest  Research Institute, Telephone Conversation, December
     7, 1977.

25.  Geonomics, Inc., A Comparison of Hydrothermal  Reservoirs  of the Western
     United States, prepared for Electric Power Research Institute, Palo Alto,
     March 1976.

26.  Glass, W.A., "1977 Drilling Methods and  Costs at  The Geysers," Big Chief
     Drilling Company,  Geothermal; State of the Art, Transactions:  Papers pre-
     sented at the Geothermal  Resources  Council  Annual  Meeting,  9-11  May 1977,
     San Diego, California,  Geothermal  Resources  Council, TRANSACTIONS, Vol.  1,
     May 1977.

27.  Grant, E.L., Principles of Engineering Economics, Ronald  Press Company,
     New York, 1970.

28.  Greene, K., H. Tyson, D.  Pixley, and D.  Werth, "Drilling  Programs: East
     Mesa, Imperial Valley,  California," Oil  Products  Division,  Dresser
     Industries, Inc.,  28  July 1976.
                                     115

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29.  Griebe, M., Ralph M. Parsons Company, telephone conversation,  December 2,
     1977.

30.  Gumerman, R.C., Gulp, R.L. and S.P. Hansen, "Estimating Costs for Water
     Treatment as a Function of Size and Treatment Efficiency", EPA-600/2-78-
     182, MERL Cincinnati, Ohio, August 1978.

31.  Guthrie, K.M., Process Plant Estimating Evaluation and Control,  Craftsman
     Book Co., 1974.

32.  Heckard, J.M., "Deep Well Injection of Liquid Waste," Dames and  Moore
     Engineering Bulletin 35, 1970.

33.  Hesketh, E.H., Understanding and Controlling Air Pollution, Ann  Arbor
     Science Publishers, Inc., 1973.

34.  Hoffman, M.; Jet Propulsion Laboratory, Environmental Quality  Laboratory;
     Memoir 14; 1975.

35.  Howe, E.D., Fundamentals of Water Desalination, Marcel Dekker, 1974.

36.  Hugh Kaufman, Hazardous Waste Management Division of Environmental
     Protection Agency, "United States Environmental Protection Agency's
     Industry Studies on Hazardous Waste Management," presented at  the
     National Conference on Hazardous Waste Management, San Francisco,
     California, February 1977.

37.  Kinna, L. Chancellor and Ogden, Inc., Landfill in Wilmington,  personal
     communication, December 1977.

38.  Kruger, P., and Otte, C., Geothermal  Energy, Stanford University Press,
     Stanford, California, 1974.

39.  Laszlo, J., Application of the Stretford Process for HS Abatement at  The
     Geysers Geothermal Power Plant, AIChE Intersociety Energy Conversion
     Conference, 1976.

40.  Library of Congress, Energy from Geothermal Resources, Science Policy
     Research Division, U.S. Government Printing Office, Washington,  D.C.,
     1974.

41.  Liptek, B.G., Editor, Environmental Engineering Handbook, Vol. 1, Water
     Pollution, Chi 1 ton Book Co., 1974.

42.  Liptek, B.G., Editor, Environmental Engineering Handbook, Vol. Ill, Land
     Pollution, Chi 1 ton Book Co., 1974.

43.  Lockett, Dale E., "Subsurface .Disposal of Industrial Wastewater," 7th.
     Ind. Water and Waste Conference, Texas Water Pollution Control Assoc.,
     Austing, Texas, 1968.
                                     116

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44.  Malina, J.F., and J.C. Moseley, III., "The Cost of Injection Wells for
     Industrial Waste Disposal," Proc. 26th Ind. Waste Conf., Purdue University,
     May 1970.

45.  Maruyama, T., S.A. Hannah, and J.M. Cohen, "Metal Removed by Physical
     and Chemical Treatment Processes," JWPCF, Vol.  47, May 1975.

46.  Metcalf and Eddy, Inc., "Wastewater Engineering," McGraw-Hill  Book Co.,
     1972.

47.  Morrison, R., Prem Saint, and Dallas Weaver, "Surface Disposal  of
     Geothermal Brines," Geothermal: State of the Art Transactions:  Paper
     presented at Geothermal Resources Council Annual Meeting, 9-11  May 1977,
     San Diego, California, Geothermal Resources Council,  TRANSACTIONS, Vol. 1,
     May 1977.

48.  National Industrial Pollution Control Council;  Waste  Disposal  in Deep
     Wells; Subcouncil Report, COM-71-50242;  February 1971.

49.  Nusbaum, L., J.H. Sleight, and S.S. Kremer, Study and Experiment in Waste
     Water Reclamation by Reverse Osmosis, Water Pollution Control  Research
     Series 1704005/70, May 1970.

50.  Ostroot, C.W., and Ramos, J.; Deep-Well  Acid DisposalPlanning and
     Completion; Underground Waste Management and Environmental  Implications,
     Memoir 18, American Association of Petroleum Geologists; 1972.

51.  Ozawa, T., and Y. Fuji; Phenomenon of Scaling in Production Wells and  the
     Geothermal Power Plant in the Matsukawa  Area; UN Symposium on  the Develop-
     ment and Utilization of Geothermal Resources, Vol. 2, Pt. 2; Pisa, 1970.

52,  Pearson, R.O., "Planning and Design of Additional East Mesa Geothermal
     Test Facilities (Phase IB),"  Volume 1 - Final  Report, TRW, October 1976.

53.  Perry, R.H., C.H. Chi 1 ton and S.D. Kirkpatrick, Eds.; Chemical  Engineer-
     ing Handbook; McGraw-Hill Book Co., Inc., New York 1973.

54.  Personal communication with experts in the field.  (Vendors of Equipment,
     State and Federal Regulatory Agencies, Academia).

55.  Phillips, S,L, Mathur, A.K, and R,E. Doebler, A Study of Brine Treatment
     LBL laboratory for EPRI, Report N, EPRI-ER-476, November 1977.

56.  Rosenblad, A.E., "Evaporator Systems for Black Liquor Concentration,"
     Chemical Engineering Progress 72:53 (April 1976).

57.  Sadow, R.; Pretreatment of Industrial Waste Water for Subsurface
     Injection; Underground Waste Management  and Environmental Implications,
     Memoir 18, American Association of Petroleum Geologists; 1972.

58.  San Francisco Bay - Delta Water Quality  Control Program, "Costing of
     Electrodialysis System," March 1968.

                                      117

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59.  San Francisco Bay - Delta Water Quality Control Program, "Construction
     Cost for Ocean Outfalls," March 1968.

60.  Schock, R., and A. Duba; Effect of Electrical Potential on Scale
     Formation in Sal ton Sea Brine; Lawrence Livermore Laboratory, Contract
     W-740 S-Eng-48; November 1975.

61.  Sittig, M., Pollutant Removal Handbook, Specific Chemical  Constituents,
     Noyes Data Corp., New Jersey 1973.

62.  Spiegler, K.S., Principles of Desalination, Academic Press, 1966.

63.  Stanford Research Institute, Environmental Analysis for Geothermal  Energy
     Development in The Geysers Region, Volumes I & III, Summary, May 1977.

64.  Sung, R.D., et al . , "An Evaluation of Control Technologies for Treating
     Oil Shale Wastewaters , " TRW  Internal Report, May 1977.
65.  Tolmasof; Report on HS Air Quality and The Geysers Geothermal Develop-
     ment; Northern Sonoma County Air Pollution Control District; January 1976.

66.  Tolivia, M.; Corrosion Measurements in a Geothermal Environment; UN
     Symposium on the Development and Utilization of Geothermal Resources;
     Vol. 2, Pt. 2; Pisa, 1970.

67.  TRW Environmental Engineering, "Evaluation of Emission Control Criteria
     for Hazardous Waste Management Facilities," Draft Final Report, prepared
     for Environmental Protection Agency, November 1977.

68.  TRW "Experimental Geothermal Research Facilities Study", Vol. 1 Final
     Report, prepared for The National Science Foundation, December 1974.

69,  TRW "Recommended Methods of Reduction, Neutralization, Recovery or Dis-
     posal of Hazardous Waste," Volume III: Disposal Process Descriptions -
     Ultimate Disposal, Incineration and Pyrolysis Processes," prepared for
     Environmental Protection Agency, Contract No. 68-13-0089, 1 February 1973.

70.  TRW Systems and Energy, "A Study of Geothermal Prospects in the Western
     United States," Final Report No. 28455-6001 -RU-00, prepared for Jet
     Propulsion Laboratory, 20 August 1975.

71,  U.O.P. Report, Reverse Osmosis Principle and Applications, prepared by
     Fluid Systems Division of UOP, San Diego, California, 92101, September
     1974.

72.  U.S. Army Engineer District, San Francisco, "Cost Curves for Conveyance,
     Treatment and Storage of Wastewater," April 1972.

73  US  Dept. of Interior, Federal Water Pollution Control Administration,
     "The Cost of Clean Water, Vol. Ill, Industrial Waste Profiles No. 5 -
     Petroleum Refining,"  November 1967.
                                      118

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74.   Van  Note,  R.H., et al.,  "A Guide to the Selection of Cost-Effective
     Wastewater Treatment  Systems," EPA Report, 430/9-75-002, July 1975.

75.   Van  Windle, W., and Mignotte, H.; Journal of Petroleum Technology; 161-28;
     1964.

76.  Warner, D.; Deep-Well Disposal of  Industrial Wastes; Chemical Engineering,
     Vol. 72, p. 73-78,  1965.

77.  Wiessman, W., T.  Harbaugh,  and J.  Knapp,  "Introduction  to  Hydrology,"
     1972.

78.  Wilson, J., Dow Company, Freeport  Texas,  personal  communication,  December
     1977.
                                     119

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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 uo.657-146/5495

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