Process for treating condensate of steam derived from geothermal brine

A process is provided for controlling the emission of hydrogen sulfide from, and the growth of living organisms in, steam condensate cooling towers and catch basins used in conjunction with steam and condensate of steam derived from hydrogen sulfide-containing geothermal brine. The process comprises contacting the condensate, in a substantially continuous manner, with a small, substantially less-than-stoichiometric amount of an oxidizing biocide, such as trichloro-isocyanuric acid or oxidizing biocide, such as trichloro-isocyanuric acid or 1-bromo-3-chloro-5,5-dimethyl-hydantoin, which results in the oxidation of such hydrogen sulfide precursors as ammonium bisulfide in the condensate to a water-soluble sulfite and/or sulfate, and which slows the growth of organisms in the cooling tower and catch basin. The process additionally includes periodically contacting the condensate with larger amounts of a second biocide, such as dodecylguanidine hydrochloride or isothiazalone, which provides most of the control of organism growth in the cooling tower and catch basin. Still further, the process includes combining hydrogen sulfide gas separated from the steam with the condensate for treatment therewith. To prevent system corrosion, the process may include treating the condensate with a non-organic, phosphate-based corrosion inhibitor and scale dispersant.

BACKGROUND OF THE INVENTION 
1. Field of the Invention 
The present invention relates generally to processes for controlling the 
emission of hydrogen sulfide from, and the growth of organisms, such as 
bacteria and algae, in, open cooling towers and the like in which hydrogen 
sulfide-containing waters are cooled, and, more particularly, in open 
cooling towers and the like in which condensate of steam derived from 
hydrogen sulfide-containing geothermal brine is cooled. 
2. Background Discussion 
Subterranean reservoirs of aqueous geothermal fluids--steam, hot water, and 
hot brine--exist in many regions of the world. Such geothermal fluid 
reservoirs, many of which contain vast amounts of thermal energy, are most 
common where the near-surface temperature gradient of the earth is 
abnormally high, as is evidenced by unusually great volcanic, fumarole, 
and/or geyser activity. As an example, significant geothermal sources are 
found along the Pacific Ocean Rim--a region long known for its high level 
of volcanic activity. 
Aqueous geothermal fluids have, in some inhabited regions, been used for 
centuries for the therapeutic treatment of physical disorders. In these 
and/or in some other inhabited regions, such as Iceland and the Paris 
Basin of France, geothermal fluids have also long been used as heat 
sources for industrial processes and for heating dwellings and other 
buildings. Moreover, in some places, such as Italy and Northern 
California, geothermal steam has been successfully used for a number of 
years to generate commercially significant amounts of electric power. In 
the late 1970s, for example, about 2 percent of all the electric power 
used in the State of California was produced by geothermal steam at The 
Geysers in Northern California, and presently enough electric power is 
generated at The Geysers to satisfy the combined electricity needs of the 
cities of San Francisco and Oakland, Calif. More recently, moderate 
amounts of electric power have been generated, notably in the Imperial 
Valley of Southern California near the Salton Sea, by geothermal brine, 
which is much more difficult to use than geothermal steam. 
Such factors as the steep increases, in the early 1970s, in the cost of 
petroleum products and natural gas and projected future shortages and high 
costs of such resources have led to the recently increased interest in 
further developing the use of geothermal fluids as alternative, and 
generally self-renewing, electric power plant "fuels." Much of this effort 
has been and is being directed toward developing more economically 
practical systems and processes for using geothermal brine to generate 
electric power because, although more difficult than geothermal steam to 
use, there are many more good sources of geothermal brine than there are 
good sources of geothermal steam. 
General processes by which geothermal brine can be used to generate 
electric power have, of course, been known for some time. Geothermal 
brine, having a wellhead temperature of over about 400.degree. F. and a 
wellhead pressure of over about 400 psig, can, for example, be flashed to 
a reduced pressure to convert some of the water or brine into steam. Steam 
produced in this manner is then used in generally conventional steam 
turbine-type power generators to generate electricity. On the other hand, 
cooler, less pressurized, geothermal brine can be used in closed-loop, 
binary fluid systems in which a low-boiling point, secondary liquid is 
vaporized by the hot brine. The vapor produced from the secondary liquid 
is then used in a gas turbine-type power generator to generate 
electricity, the vapor being recondensed and reused. In both such cases, 
the "used" geothermal brine is most commonly reinjected into the ground to 
replenish the aquifer from which the liquid was produced and to prevent 
ground subsidence. Reinjection of geothermal brine is also often important 
to avoid problems typically associated with the disposal of the large 
amounts of saline and usually highly-contaminated liquid involved. 
In spite of such general processes for using geothermal brine for producing 
electric power being known, difficult and costly problems are commonly 
encountered with the actual use of the heavily contaminated, saline, and 
corrosive brines. Moreover, these problems are frequently so costly to 
solve that the production of reasonable amounts of electric power at 
competitive rates by the use of geothermal brines has often been extremely 
difficult to achieve in many locations. 
As mentioned above, many of these serious problems associated with the 
production and use of geothermal brines for the generating of electric 
power can be attributed to the usually complex chemical composition and 
extremely corrosive nature of many geothermal brines. At aquifer 
temperatures and pressures--which are often well in excess of 400.degree. 
F. and 400 psig--aqueous geothermal liquids leach large amounts of salts, 
minerals, and elements from the aquifer formations, the geothermal liquids 
(brines) presumably being in chemical equilibrium with their producing 
formations. 
Thus, although their compositions may vary considerably from location to 
location, geothermal brines typically contain very high levels of 
dissolved salts and silica, and appreciable amounts of dissolved metals 
and such non-condensable gases as hydrogen sulfide, ammonia, and carbon 
dioxide. Geothermal brines are usually acidic, with typical wellhead pH's 
of between about 5 and about 5.5. As a combined result of their 
composition and high temperature, geothermal brines are not only 
frequently some of the most corrosive liquids known, but most tend, 
without appropriate treatment, to rapidly deposit a tough, tenacious, 
siliceous scale onto contacted surfaces of pipe, valves, vessels, and so 
forth, especially in regions of the brine handling system downstream of 
flashing vessels in which brine pressure is greatly reduced. 
Adding greatly to the problems associated with producing and using 
geothermal brines for the generation of electric power is the need for 
very large, continuous flows of brine in order to generate even relatively 
moderate amounts of electric power. As an illustration, the production of 
only about 10 megawatts of electric power requires a continuous flow of 
over a million pounds per hour of high temperature and pressure geothermal 
brine. Consequently, even relatively low-capacity geothermal brine power 
plants ordinarily require several very costly brine production and 
reinjection wells, and large quantities of expensive, large size, 
corrosion-resistant pipe, fittings, pumps, valves, flashing and clarifying 
vessels, filters and so forth just for extracting, handling, and disposing 
of the huge flows of geothermal brine needed. In addition, an associated 
power generating facility is ordinarily required for each brine handling 
facility. 
One of the many problems which has added significantly to the overall cost 
of producing electric power by the use of geothermal brines, relates to 
the undesirable, and frequently unlawful, emission of hydrogen sulfide 
from the mixture of steam and non-condensable gases obtained from hydrogen 
sulfide-containing brines. Although the amount of hydrogen sulfide 
contained in the separated/extracted steam and gas mixture usually varies 
from one brine source to another, levels of at least about 50 PPM (parts 
per million) are common. As an indication of the magnitude of this 
emission problem, at an assumed hydrogen sulfide concentration (in the 
steam) of about 50 PPM and for an assumed steam production rate of about 
200,000 to 220,000 pounds per hour (the amount of steam typically obtained 
from a brine flow of about a million pounds an hour), nearly 50 tons a 
year of hydrogen sulfide gas is "produced" as an unwanted by-product of 
the power generating process. 
In the past, this hydrogen sulfide has most commonly just been mixed with 
air and discharged into the atmosphere--usually from open cooling towers 
used to cool the condensate as part of the power generation process. 
However, the emission of hydrogen sulfide into the atmosphere is now 
strictly regulated in many locations in which geothermal brine power 
plants are situated, and the discharge into the atmosphere of even much 
smaller amounts of hydrogen sulfide than that mentioned above either is or 
is soon likely to be prohibited in most of these locations. 
Other difficult problems which, as is apparent from the discussion below, 
are related to the hydrogen sulfide emissions problem are the corrosion, 
by the steam condensate (which is used for cooling tower makeup), of metal 
parts of the condensate handling system and the rapid growth of organisms 
(including bacteria, fungi, and algae) in such parts of the condensate 
handling systems as open cooling towers and associated condensate catch 
basins. Unless controlled, these corrosion problems require the use of 
costly, corrosion-resistant materials or the frequent costly replacement 
of common steel components. In turn, the growth of organisms in the 
condensate cooling towers and catch basins usually not only adds 
substantially to condensate-handling system corrosion problems but also 
causes the fouling and loss of efficiency of cooling towers and other 
parts of the condensate handling system, the latter requiring frequent, 
costly system cleaning. It is, of course, to be appreciated that whenever 
system shutdown is required to replace corroded pipe or equipment or to 
clean the system of organism-caused contaminants, the resulting loss of 
electric power revenue during shutdown usually adds substantially to the 
overall cost associated with the servicing operations. 
To overcome these and other corrosion problems in condensate-handling 
systems, corrosion inhibitors are commonly added to the condensate of 
steam derived from hydrogen sulfide-containing geothermal brines. 
Corrosion inhibitors comprised of heavy metal compounds have generally 
been favored for this purpose because the heavy metals control hydrogen 
sulfide emissions from the condensate by reacting with hydrogen 
sulfide-releasing compounds (that is, hydrogen sulfide precursors) in the 
condensate to form insoluble, heavy metal sulfides. An additional 
advantage associated with the use of heavy metal corrosion inhibitors is 
that such corrosion inhibitors have usually also been effective in 
controlling the growth of organisms in open condensate cooling towers and 
catch basins. 
Such multi-function, heavy metal corrosion inhibitors would, therefore, 
seem to be ideal for use in systems which handle corrosive condensate of 
steam derived from hydrogen sulfide-containing geothermal brine. However, 
a serious disadvantage is that the heavy metal sulfides formed by the use 
of heavy metal corrosion inhibitors is now classified as a toxic or 
hazardous waste material in many localities. Consequently, the disposal of 
the heavy metal sulfides, which may, for example, be formed at the rate of 
about a ton a day in a 10 megawatt geothermal brine power plant, is 
difficult and expensive--and is destined to become even more difficult and 
expensive in the future, as more stringent controls are applied to the 
disposal of such materials and as hazardous waste disposal sites become 
scarcer, more remote, and more costly to use. 
Thus, in spite of their effectiveness in inhibiting corrosion and also for 
controlling hydrogen sulfide emissions and the growth of organisms, the 
continued use of heavy metal corrosion inhibitors in systems handling 
hydrogen sulfide-containing condensate is becoming increasingly less 
practical. 
Non-heavy metal corrosion inhibitors, which do not form hazardous waste 
materials in the presence of hydrogen sulfide, have thus recently been 
used in some condensate handling systems of the type mentioned above. 
Representative of these non-heavy metal corrosion inhibitors are such 
inorganic, phosphate-based materials as Betz Dianodic II, available from 
Betz Laboratories, Inc., Trevose, Pa. 
However, unlike their counterpart heavy metal corrosion inhibitors, 
phosphate-type corrosion inhibitors have not been effective in controlling 
either hydrogen sulfide emissions or the growth of organisms. The use of 
such alternative types of corrosion inhibitors has, as a result, created 
an important need for a compatible process (or processes) for controlling 
hydrogen sulfide emissions and organism growth in systems for handling 
steam and condensate derived from hydrogen sulfide-containing geothermal 
brines. 
It is, however, important that any new process for controlling hydrogen 
sulfide emissions from, and the growth of organisms in, steam condensate 
handling portions of geothermal brine power plants not only be effective, 
for example, to avoid penalties for excessive hydrogen sulfide emissions, 
but that it also be economical to use. If a process is effective for 
controlling hydrogen sulfide emissions and organism growth but is 
uneconomical--for example, if it is more costly than the cost of disposing 
of the heavy metal sulfides produced by the use of heavy metal corrosion 
inhibitors--the process is of little, if any, practical use in actual 
geothermal brine power plants. 
SUMMARY OF THE INVENTION 
According to the present invention, an effective and economical process is 
provided for controlling both the emission of hydrogen sulfide from, and 
the growth of organisms in, systems for handling flows of steam and 
condensate of steam derived from a hydrogen sulfide-containing geothermal 
source. The present process comprises: (i) contacting, in a substantially 
continuous manner, the flow of condensate with an amount of an oxidizing 
biocide or an oxidation inducing material which substantially prevents the 
emission of hydrogen sulfide from the system but does not substantially 
inhibit the growth of organisms such as algae, fungi and bacteria in the 
system, and (ii) contacting, in a periodic manner, the flow of condensate 
with an amount of a second biocide which substantially reduces the amount 
of live organisms in the system. 
The oxidizing biocide is preferably selected from the group consisting of 
trichloro-isocyanuric acid and salts thereof, 
1-bromo-3-chloro-5,5-dimethyl-hydantoin and other halogenated substituted 
hydantoins, and mixtures thereof, the more preferred oxidizing biocide 
being the trichloro-isocyanuric acid. Although the second biocide can be 
the same as the oxidizing biocide, it is preferably a non-oxidizing 
biocide selected from the group consisting of dodecylguanidine 
hydrochloride, isothiazalone, and mixtures thereof. 
In the common situation in which the source of hydrogen sulfide (the 
hydrogen sulfide precursor) in the condensate as ammonium bisulfide, an 
amount of oxidizing biocide is added to the flow of condensate which is 
effective for causing at least substantial amounts of the ammonium 
bisulfide to be converted to a stable, water-soluble sulfate or sulfite, 
the breakdown of the ammonium bisulfide in a manner releasing hydrogen 
sulfide being thereby prevented. In the preferred embodiment, the amount 
of the oxidizing biocide added to the flow of condensate is, however, very 
small compared to the stoichiometric amount of biocide which would itself 
be needed to oxidize all of the ammonium bisulfide in the condensate to a 
sulfate, a catalytic effect being apparently involved which causes 
oxidation of the ammonium bisulfide to ammonium sulfate. Preferably less 
than about 10 percent, and more preferably less than even about 0.2 
percent, of the stoichiometric amount of oxidizing biocide is needed to 
substantially prevent the emission of hydrogen sulfide from the 
condensate. In this regard, it is preferred that between about 0.5 and 
about 20 PPMW (parts per million by weight) relative to the condensate of 
the oxidizing biocide, and more preferably between about 0.5 and about 5 
PPMW relative to the condensate, is added to the condensate to control 
hydrogen sulfide emissions and which does not substantially inhibit the 
growth of organisms in the condensate. 
The second biocide is added to the flow of condensate in amounts and at 
periodic intervals which have been determined to effectively control the 
growth of organisms in the condensate handling system to below problem 
levels. In this regard, preferably between about 25 and 200 PPMW, relative 
to the condensate, of the second biocide is preferably added to the 
condensate, at preferred intervals of between about 1 week and about 4 
weeks, to periodically reduce the live organism count to relatively low 
levels. 
Alternatively, the second biocide may be added to the condensate when or 
after the level of live organisms in open regions of the condensate 
handling system reaches a predetermined level, for example, between about 
1 million and about 10 million per liter of condensate. In such case, the 
second biocide is preferably added to the condensate to reduces the level 
of live organisms to less than about 10,000 per liter. 
Further in accordance with the preferred embodiment of the invention, the 
process may include contacting the condensate with with preferably between 
about 10 and about 50 PPMW, relative to the condensate, of an inorganic, 
phosphate-based corrosion inhibitor, such as Betz Dianodic II. 
For a steam and condensate handling system which includes a steam condenser 
for condensing the steam and in which at least some hydrogen sulfide is 
separated from the steam before condensation, and which includes an open 
cooling tower for cooling the steam condensate which is then recirculated 
through the condenser, the process includes combining the hydrogen sulfide 
separated from the steam in the condenser with the flow of condensate to 
the cooling tower so that the hydrogen sulfide is mixed with the 
condensate for treating by the present process. 
The present process controls the emission of hydrogen sulfide from the 
condensate handling system in a substantially continuous manner, as is 
needed, while the organism growth in the system is controlled in a 
periodic, "saw-tooth" manner, as is satisfactory. Such a two-stage biocide 
treatment of the condensate provides an effective, yet economical, process 
for controlling hydrogen sulfide emissions and organism growth in 
condensate handling systems, and is particularly useful in systems for 
handling condensate derived from hydrogen sulfide-containing geothermal 
brine.

DESCRIPTION OF THE PREFERRED EMBODIMENT 
According to the present invention, a process is provided for controlling, 
in an effective and economical manner, hydrogen sulfide emissions from, 
and the growth of organisms, such as bacteria, fungi, and algae, in, 
systems for handling condensate of steam derived from hydrogen 
sulfide-containing geothermal brine. It is, however, considered that the 
present process can be more readily understood and appreciated by first 
briefly considering an exemplary geothermal brine power plant 10 
(depicted, in block diagram form, in FIG. 1) in which steam is obtained 
from geothermal brine and is used for the generation of electric power. In 
the process of using the derived steam in this manner, the steam is 
condensed and the condensate is advantageously treated by the present 
process for the stated control purposes. 
Shown as generally comprising geothermal brine power plant 10 are a brine 
handling portion 12 and a power generating portion 14. As more 
particularly described below, brine handling portion 12 is constructed for 
extracting, separating, flashing, treating (that is, clarifying and 
filtering), and reinjecting the geothermal brine used to provide steam for 
electric power production in portion 14. Also, as is more particularly 
described below, steam is provided from brine handling portion 12 by both 
the brine separating and flashing operations. Power generating portion 14 
is constructed for using the steam from brine handling portion 12 to 
generate electric power and for subsequently condensing the steam. 
BRINE HANDLING PORTION 12 
Brine handling portion 12, as shown in FIG. 1, comprises respective first 
and second brine extraction wells 16 and 18, each of which may be several 
thousand feet deep. More or fewer than two such wells may, however, be 
needed for some geothermal brine power plants. From wells 16 and 18, the 
extracted, two-phase mixture of brine and steam (with non-condensable 
gases), having a typical wellhead temperature and pressure of about 
450.degree. F. and about 400 psig, is flowed, through respective conduits 
20 and 22, to a wellhead separation stage 24. Steam and non-condensable 
gases, including hydrogen sulfide and carbon dioxide, are separated from 
the brine in wellhead separation stage 24. The steam and gases are flowed, 
through a conduit 32, from separation stage 24 to a steam conditioning 
stage 34, the brine being flowed, through a conduit 36, from the 
separation stage to a flash-crystallization stage 38. 
The geothermal brine entering flash-crystallization stage 38 through 
conduit 36 is flashed, usually in a series of steps, to a reduced or 
atmospheric pressure, thereby converting some (for example, about 10 
percent) of the brine into steam. At least the high pressure steam from 
flash-crystallization stage 38 is supplied, through a conduit 40, to steam 
conditioning stage 34. To reduce the formation of siliceous scale on 
downstream brine handling equipment, flash-crystallization stage 38 may be 
configured for removing dissolved silica from the brine by a 
crystallization or seeding process. 
Flashed brine, with siliceous material suspended therein, is flowed from 
flash-crystallization stage 38, through a conduit 42, into a brine 
clarification stage 44 wherein most of the siliceous material is gravity 
separated from the brine. Clarified brine overflow, usually still with 
small amounts fine suspended siliceous material, is flowed from 
clarification stage 44, through a conduit 50, into a brine filtration and 
settling stage 52. Dewatered sludge (still containing some brine) is 
discharged from brine clarification stage 44, through a conduit 54, for 
disposal. Brine from the dewatering operation in clarification stage 44 is 
discharged, through a conduit 56, into a sump 58. A slurry of siliceous 
sludge is fed back upstream from clarification stage 44, through a conduit 
60, into flash-crystallization stage 38 as seed material for the silica 
crystallization purposes. 
Filtered brine from brine filtration and settling stage 52 is pumped, 
through a conduit 62, into an injection well 64 through which the brine is 
injected into the ground--usually into the underground aquifer from which 
it is extracted. Brine from the backwashing of filters in filtration and 
settling stage 52 is discharged from such stage, through a conduit 68, 
into sump 58. 
Steam and non-condensable gases from conduits 32 and 40 are cleaned in 
steam conditioning stage 34, the cleaned steam and gases being then 
flowed, through a conduit 70, into power generating portion 14. Wash water 
from steam conditioning stage 34 is discharged, through a conduit 72, into 
sump 58. As is described below, some steam condensate and condensate 
blowdown is discharged from power generating portion 14, through a conduit 
78, into sump 58. 
Brine, water, and condensate overflow from sump 58 is fed, through a 
conduit 80, back upstream into flash-crystallization stage 38 for 
processing along with unflashed brine from conduit 36. 
POWER GENERATING PORTION 14 
Exemplary power generating portion 14, in which the present invention is 
used, is depicted in some--but not complete--detail in FIG. 2. The steam 
and non-condensable gas mixture, provided to power generating portion 14 
(through conduit 70) from steam conditioning stage 34, is flowed into 
respective first and second demisters 100 and 102 through conduits 104 and 
106. A steam venting conduit 108 connected between conduit 70 and a drain 
sump 110 enables the discharge of steam in the event of steam or power 
generating problems. Valves 112 and 114 in respective conduits 70 and 108 
control the flow of steam and non-condensable gases into power generation 
portion 14 and sump 110. 
From demisters 100 and 102, the steam and non-condensable gas mixture is 
flowed, through respective conduits 118 and 120 and through a common 
conduit 122, into a steam turbine-generator 124. To increase the 
efficiency of turbine-generator 124 in a known manner, the steam 
discharged therefrom is typically cooled and condensed. To this end, 
steam--with substantially reduced energy--and non-condensable gases are 
discharged from turbine-generator 124, through a conduit 126, into a main 
condenser 128. A small slipstream of steam and gases is diverted from 
conduit 122, through a conduit 130, to a steam eductor 132. From eductor 
132, the slipstream is flowed, through a conduit 134, to a second 
condenser 136, which is commonly referred to as an "inner condenser". 
Separated non-condensable gases are discharged from main condenser 128, 
through a conduit 142, into eductor 132, and from there, through conduit 
134, into inner condenser 136. In turn, the non-condensable gases from 
inner condenser 136 are fed, through a conduit 144, to a compressor 146. 
Compressed gases are normally discharged from compressor 146 through a 
discharge conduit 154 into the top of an open, cascade-type, condensate 
cooling tower 156. 
Steam condensate is discharged from inner condenser 136, through a conduit 
166, into an outlet region 168 of main condenser 128. From condenser 
outlet region 168, steam condensate (from both condensers 128 and 136) is 
flowed, through a conduit 170, to a condensate pump 172 which pumps the 
condensate, through conduits 174 and 176, into a make-up water return 
conduit 178 at a point downstream of inner condenser 136. 
A bypass conduit 180, connected at the junction of conduits 174 and 176, 
enables steam condensate to be discharged by pump 172 into conduit 78, 
which empties into sump 58 (FIG. 1). Valves 182 and 184 in respective 
conduits 176 and 180 enable dividing the condensate between these two 
conduits. 
An open condensate catch basin 190, having a sump region 192, is disposed 
beneath cooling tower 156 to receive cooled condensate therefrom. A pump 
194 pumps condensate from sump region 192, through a conduit 196, into 
main condenser 128 for steam condensation purposes. A conduit 198, 
connected into conduit 196, enables condensate to be pumped also into 
inner condenser 136. Make-up water return conduit 178 is connected between 
main condenser 128 and the top of cooling tower 156, a conduit 200 from 
inner condenser 136 being connected into the return conduit. 
A condensate blowdown conduit 202 is connected between make-up return 
conduit 178 and conduit 78 which discharges into sump 58 (FIG. 1). A valve 
204 in conduit 202 is operated whenever blowdown is needed, for example, 
when the condensate in catch basin 190 reaches an excessive level or when 
an excessive amount of sludge builds up in catch basin 190. 
Typically, the condensate handling portions (including condensers 128 and 
136, cooling tower 156, catch basin 190, and the various associated 
condensate conduits, such as conduits 178 and 196) have a 
condensate-holding capacity or volume which is at least several times, for 
example, at least about five times, as great as the rate at which steam is 
flowed into power plant portion 14. Accordingly, most of the condensate is 
recirculated for a period of time through such condensate handling 
portions before it evaporates from cooling tower 156. 
THE PRESENT CONDENSATE TREATMENT PROCESS 
As mentioned above, about two-thirds of the hydrogen sulfide gas entering 
power generating portion 14 with the steam typically passes into the 
condensate phase in condensers 128 and 136. This is presumably due to an 
excess of ammonia in the steam which increases the solubility of hydrogen 
sulfide in the condensate by reacting (as a base) with hydrogen sulfide to 
form ammonium bisulfide, according to the reaction: 
##STR1## 
However, it is possible that other hydrogen sulfide precursors (that is, 
compounds from which hydrogen sulfide may outgas or be released during 
condensate treatment operations) may be formed in the condensate, and the 
present invention is not limited to any particular theory of operation. 
Without adequate treatment, when the condensate then cascades downwardly 
through cooling tower 156, the ammonium bisulfide (or whatever other 
hydrogen sulfide precursor is present in the condensate) breaks down and 
releases hydrogen sulfide, which is then mixed with air and blown into the 
atmosphere by a cooling tower fan 210. 
Moreover, even when the condensate itself is treated (in the manner 
described below) to prevent hydrogen sulfide emissions therefrom, the 
remaining about one-third of the hydrogen sulfide (from compressor 146) 
has generally heretofore been emitted directly into the atmosphere through 
conduit 154 which discharges gases into the top of cooling tower 156. 
Depending upon geothermal brine power plant size and hydrogen sulfide 
content in the geothermal brine, the amount of the hydrogen sulfide 
emitted into the atmosphere with other gases from compressor 146 may 
presently, or may soon, exceed hydrogen sulfide emission limits in some 
localities. 
To solve this particular facet of the hydrogen sulfide emission problem, 
the present inventor has determined that the emission of hydrogen sulfide 
gas from compressor stage 146 can be effectively and economically 
eliminated by instead flowing the compressed gases, through a conduit 212 
(shown in phantom lines in FIG. 2), into make-up water return conduit 178 
at a point well upstream of cooling tower 156. At least most of the 
hydrogen sulfide discharged in this manner from conduit 212 into conduit 
178 probably reacts with excess ammonia in the condensate to form 
additional ammonium bisulfide, in accordance with reaction Equation (1) 
above. This additional ammonium bisulfide is then treated for hydrogen 
sulfide emission prevention along with the ammonium bisulfide already in 
the condensate, in the manner described below. Moreover, the emission from 
the condensate of any hydrogen sulfide gas which is merely dissolved in, 
or intermixed with, the condensate, without forming ammonium bisulfide, 
has been found by the present inventor also to be prevented by the same 
treatment (described below) which prevents hydrogen sulfide outgassing 
from the ammonium bisulfide in the condensate. 
Many types of air-borne organisms have been found to grow at a very rapid 
rate in the hot, wet environment of cooling tower 156 and condensate catch 
basin 190. As an example, among the bacteria usually found in cooling 
tower 156 and catch basin 190 when sulfur compounds are present are 
nitrifying bacteria such as Nitrosomonas and Nitrobacter, which consume 
ammonia in the cooling tower and produce nitric and nitrous acids which 
thereby add to system corrosion problems, and such sulfate-reducing 
bacteria as autotropic Thiobacillus thiooxidans, the biological action of 
which, on sulfur in the condensate, tends to add to hydrogen sulfide 
emissions. Furthermore, the slime formed by most types of bacteria, as 
well as by algae, in cooling tower 156 and catch basin 190 tends to cause 
severe fouling thereof and the subsequent loss of efficiency. Moreover, 
cooling tower 156 and catch basin 190 then become a source of organisms 
which are blown into the atmosphere by the cooling tower by fan 210. 
The present inventor has determined that hydrogen sulfide emissions from, 
and the growth of organisms in, cooling tower 156 and catch basin 190 can 
be effectively controlled in an economic manner by the present process 
without creating any new problems. 
According to the hydrogen sulfide and organism growth controlling process 
of the present invention, it is preferred that small amounts of a first, 
oxidizing biocide are introduced into (for contact with) the condensate in 
a continuous, or at least a substantially continuous, manner and 
preferably at a rate effective for substantially eliminating the emission 
of hydrogen sulfide from cooling tower 156 and catch basin 190 and which 
does not substantially inhibit the growth of living organisms in the 
cooling tower and catch basin. 
As used herein the term "biocide" is to be considered to include biostats 
(which stop or retard the growth of organisms without necessarily killing 
the organisms), and therefore include, without limitation, bacteriacides, 
bacteriastats, algicides, algistats, fungicides, and fungistats. 
As an example, the first biocide may be slowly and continuously added to 
catch basin 190 from a source 214 through a conduit 216. Alternatively, a 
slowly-dissolving pellet or pellets of solid first biocide may be 
periodically dropped into catch basin 190. In either of such cases, the 
first biocide is to be considered, for purposes of the present invention 
as being "added" to the condensate in a continuous or substantially 
continuous manner. 
It has, however, been determined by the present inventor (for reasons 
described below) that when just enough of the first biocide is added to 
the condensate to effectively control hydrogen sulfide emissions on a 
continuous basis, the growth of organisms in cooling tower 156 and/or 
catch basin 190 is not substantially inhibited. Although much greater 
quantities of the first biocide could be continuously added to the 
condensate to completely inhibit the growth of organisms in cooling tower 
156 and catch basin 190, the resulting process would be excessively 
expensive, since it is not considered essential to completely control the 
growth of organisms in the system on a continuous basis. 
It is thus preferred to completely control the growth of organisms in 
cooling tower 156 and catch basin 190 by periodically adding to the 
condensate an additional, relatively large, "shock" amount of a biocide. 
In combination with the organism-growth control provided by the oxidizing 
biocide, the periodic shock treatment of the condensate relatively large 
slugs of biocide results in a generally sawtooth-shaped "curve" 214 (FIG. 
3) in which the growth of organisms is plotted as a function of time 
(expressed in terms of periods "P." Gradually upward sloping portions 220 
of curve 218 represent the gradual organism growth rate permitted by the 
continuous addition to the condensate of only small amounts of the 
oxidizing biocide and steeply decreasing portions 222 of curve 218 
represent the periodic rapid decrease in the amount of organisms caused by 
the periodic addition to the condensate of relatively large amounts of the 
second biocide. 
The described two phase process of adding to the condensate small amounts 
of the oxidizing biocides on a continual basis and large amounts of the 
shock biocide on a periodic basis has been found to be more cost effective 
than the continual adding of a larger amount of oxidizing biocide 
sufficient to constantly control the growth of organisms, and to be just 
as satisfactory. 
As indicated in FIG. 2, the second biocide can be introduced into catch 
basin 190 from a source 224 and through a conduit 226. Since the second 
biocide is intended to act rapidly on organisms in cooling tower 156 and 
catch basin 190, the entire periodic slug of second biocide can be dumped 
into the catch basin at one time. 
As can be appreciated, the actual amounts of the shock biocide and the 
intervals between the addition thereof to the condensate depend upon the 
organism growth characteristics, which may, in turn, depend upon such 
factors as the geographic location of power plant portion 14, the 
temperature in cooling tower 156 and catch basin 190, and the type(s) of 
organisms present. However, the amounts and intervals can be readily 
determined for a particular cooling tower 156 and catch basin 190 by the 
simple expedient of measuring the live bacteria count therein from time to 
time. In general, however, intervals of between about 1 and about 4 weeks 
are preferred. 
It is preferred that the first, oxidizing biocide be selected from 
trichloro-isocyanuric acid and the salts thereof, 
1-bromo-3-chloro-5,5-dimethyl-hydantoin and other halogenated 
substitutions of hydantoin, and mixtures thereof. For such reasons as 
lower cost and lesser amounts required to achieve good control of hydrogen 
sulfide emissions and organism growth, the more preferred oxidizing 
biocide is the trichloro-isocyanuric acid (triazine). Although the shock 
biocide can be the same as the oxidizing biocide, for greater 
effectiveness, it is preferred that it be a non-oxidizing biocide and that 
it be selected from dodecylguanidine hydrochloride, isothiazalone, and 
mixtures thereof. 
A corrosion inhibitor, which is preferably a non-heavy metal inhibitor and 
which is preferably selected from an inorganic phosphate passivator and 
scale dispersant, such as Betz Dianodic II, may, as shown in FIG. 2, be 
fed from a source 224 which discharges through a conduit 226 into catch 
basin 190. Alternatively, the corrosion inhibitor can be dumped directly 
into catch basin 190. It is also preferred that the corrosion inhibitor be 
added to the condensate in a concentration of between about 10 and about 
50, and more preferably an inhibitor concentration of between about 18 and 
about 28, PPMW relative to the condensate to which the inhibitor is added. 
As used herein, the concentration notation "PPMW relative to the 
condensate" (regardless of the additive material involved) is to be 
understood to mean the concentration of the added material in parts per 
million by weight relative to the total volume of condensate handling 
portions--including condensers 128 and 136, cooling tower 156, catch basin 
190 and such conduits as 178 and 196--of power plant portion 14. This is 
the case even though condensate is continually being added (from 
condensers 128 and 136) to, and condensate is continually being removed 
(by evaporation in cooling tower 156) from the condensate handling 
portion, and is further the case even when the amount of material added 
does not go into solution immediately. In either such case, an extracted 
sample of the condensate would generally not actually have the stated 
concentration of the added material. Such a designation for concentration 
of added materials is, however, consistent with the standard practices 
followed in the water treatment industry. 
In an actual practice of the present process, it was anticipated by the 
present inventor that the oxidizing biocide would oxidize the ammonium 
bisulfide in the steam condensate to form soluble ammonium bisulfate 
(NH.sub.4 HSO.sub.4) and/or ammonium sulfate ((NH.sub.4).sub.2 SO.sub.4). 
Probable reactions for the oxidation of the ammonium bisulfide in the 
condensate to ammonium bisulfate by the trichloroisocyanuric acid and 
hydantoin biocides are given by respective equations (2) and (3) below: 
##STR2## 
By similar reactions (not shown) the trichloroisocyanuric acid and 
hydantoin biocides would be expected also to oxidize the ammonium 
bisulfide in the condensate to ammonium sulfate. Any small amounts of 
unreacted hydrogen sulfide in the steam condensate (for example, from 
conduit 212) is expected by the present inventor to be oxidized by the 
oxidizing biocide and/or oxygen to form sulfuric acid, with such other 
acids as hydrochloric and hydrobromic acids being possibly also formed. 
It was also expected that the amount of oxidizing biocide required to 
prevent the emission of hydrogen sulfide from the condensate would be the 
stoichiometric amount for reacting with the ammonium bisulfide in 
accordance with such reaction equations as Equations (2) and (3). A 
concern was that a process using a stoichiometric amount of the oxidizing 
biocide would not be a very economical process. 
It was, however, unexpectedly and surprisingly discovered by the present 
inventor that the amount of oxidizing biocide needed to virtually 
eliminate hydrogen sulfide emissions from cooling tower 156 and catch 
basin 190 is only an extremely small percentage--for example, only about 
0.05 to about 0.1 percent--of the stoichiometric amount of oxidizing 
biocide which was expected to be required. Why only such a very small 
amount of oxidizing biocide is needed to completely control hydrogen 
sulfide emissions from cooling tower 156 and catch basin 190 is not 
completely understood. Apparently, however, the biocide--possibly in 
conjunction with the small amounts of some materials, such as iron, 
carried over into the condensate from the geothermal brine--functions as a 
catalyst in the oxidation of the ammonium bisulfide by oxygen in the 
condensate (for example, from air picked up as the condensate cascades 
through cooling tower 156) in accordance with the following oxidation 
reaction: 
##STR3## 
The theory that a catalytic reaction is somehow involved is borne out by 
the observation that much less oxidation of the ammonium bisulfide in the 
condensate occurs, in accordance with reaction Equation (6), in the 
absence of small amounts of the oxidizing biocide in the condensate. It 
is, of course, to be understood that the present invention is not to be 
held to this or to any other theory of operation. 
The present invention may be further described with reference to the 
following Example in which the same reference numbers identified above are 
used. 
EXAMPLE 
A two-phase mixture of geothermal brine and steam, having a wellhead 
temperature of about 450.degree. F. and a wellhead pressure of about 450 
psig, is extracted at a rate of about one million pounds per hour from 
brine production wells wells 16 and 18 (FIG. 1). The two-phase mixture has 
a hydrogen sulfide concentration of about 10 PPMW and an ammonium 
concentration of about 350 PPMW (relative to the two-phase mixture from th 
well). 
A combined amount of between about 180,000 and about 220,000 pounds per 
hour of separated and flashed steam is supplied by the above-stated amount 
of the two-phase mixture to steam conditioning stage 34 from wellhead 
separation stage 24 and flash crystallization stage 38. This amount of 
supplied steam contains about 10 pounds per hour of hydrogen sulfide (as a 
non-condensable gas) and about 50 pounds per hour of ammonia, also as a 
non-condensable gas. 
After exiting turbine 124, the steam is condensed in condensers 128 and 
136, about 70 percent of the 10 pounds per hour of hydrogen sulfide--that 
is, about 7 pounds per hour--entering the condensate to form ammonium 
bisulfide. The pH of the condensate is about 9.0. About 28 pounds per hour 
of sulfate is produced when all 10 pounds per hour of the hydrogen sulfide 
is converted to sulfate. 
The condensate capacity of the condensate handling portion (including 
condensers 128 and 136, cooling tower 156 and catch basin 190) of power 
plant portion 12 is about one million pounds. 
Betz Dianodic II corrosion inhibitor is added to the condensate in catch 
basin 190 to provide an inhibitor concentration of between about 18 and 
about 28 PPMW relative to the condensate. 
Between about 1 and about 4 pounds per day of 
1-bromo-3-chloro-5,5-dimethyl-hydantoin oxidizing biocide is added to the 
condensate in catch basin 190 so as to provide a concentration of between 
about 1 and about 4 PPMW relative to the condensate (as above-defined). 
The biocide is added in the form of one or more pellets weighing about 0.6 
pounds each which slowly dissolve in the condensate over about a 24 hour 
period. Since steam is provided to power generating portion 14 at a rate 
of between about 4.32 million and about 5.28 million pounds in a 24 hour 
period, the oxidizing biocide is added to the condensate at a rate which 
can alternatively be considered to be between about 0.18 and about 0.93 
PPMW relative to the flow of steam into power plant portion 14. With the 
addition of between about 1 and about 4 pounds of oxidizing biocide a day 
into the condensate, the emission of hydrogen sulfide from cooling tower 
156 and catch basin 190 is about 3 pounds per hour and results from the 
discharge of hydrogen sulfide from compressor stage 146 into the cooling 
tower. 
The stoichiometric amount of the above-mentioned hydantoin biocide 
required, in accordance with Equation (3), to oxidize all of the ammonium 
bisulfide in the condensate formed from 7 pounds per hour of hydrogen 
sulfide is calculated to be about 66 pounds per hour, or about 1590 pounds 
per day. The amount of the hydantoin actually required to substantially 
abate the emission of hydrogen sulfide from the condensate is thus between 
about 0.063 and about 0.25 percent of the stoichiometric amount of the 
hydantoin expected to be required. 
Isothiazalone is used at the second, non-oxidizing biocide and is added to 
the condensate in catch basin 190 about every two weeks in an amount of 
about 50 PPM relative to the condensate. 
The addition of the above-described amounts of the hydantoin and 
isothiazalone biocides is found to effectively control the growth of 
organisms in cooling tower 156 and catch basin 190. 
When the non-condensable gases (containing about 3 pounds per hour of 
hydrogen sulfide) from compressor stage 146 are combined with the 
condensate, excellent abatement of all hydrogen sulfide from cooling tower 
156 and catch basin 190 is still achieved with the addition to the 
condensate of no more than the above-mentioned amount of between about 1 
and about 4 pounds per day of the hydantoin biocide. If all 10 pounds per 
hour of hydrogen sulfide were to be oxidized by the hydantoin, about 94 
pounds per hour (2260 pounds per day) of the hydantoin would be required. 
Instead, only about 0.044 to about 0.18 percent of the stoichiometric 
amount of the hydantoin biocide is found to be required to abate all of 
the hydrogen sulfide. 
Although there has been described above a preferred embodiment of a process 
for controlling the emission of hydrogen sulfide from, and the growth of 
organisms in, a system for handling steam and steam condensate derived 
from hydrogen sulfide-containing geothermal brine in accordance with the 
present invention for the purpose of illustrating the manner in which the 
invention may be used to advantage, it will be appreciated that the 
invention is not limited thereto. Accordingly, any and all process 
modifications or variations which may occur to those skilled in the art 
should be considered to be within the scope of the invention as defined in 
the appended claims.