Acidification of steam condensate for incompatibility control during mixing with geothermal brine

A method is provided for combining a high pH steam condensate with a flow of a acidic geothermal brine from which the steam is extracted so as to inhibit the formation of suspended particulate matter, such as heavy metal sulfides, calcium carbonate and iron hydroxide, by the chemical reacting of such impurities as hydrogen sulfide and ammonia in the condensate with such impurities as heavy metals, iron and calcium in the brine. The method includes acidifying the steam condensate, preferably by hydrochloric acid, to reduce the pH to between about 7 and about 4.5 and then combining the acidified condensate with the brine. In a silica crystallizer stage in which flashed brine is contacted with a silica seed material to cause silica removal from the brine, the treated condensate is combined with the brine in a low pressure crystallizer upstream of brine clarification and reinjection stages. Part of the treated condensate may be flowed to various pumps in the geothermal brine power production system to purge pump seals and prevent pump scaling and excessive wear.

FIELD OF THE INVENTION 
The present invention relates generally to processes for generating 
electrical power by use of hot geothermal aqueous liquids and more 
particularly to processes for controlling the formation of scale in 
geothermal brine power plants and associated brine injection equipment. 
DISCUSSION OF THE PRIOR ART 
Large subterranean reservoirs of naturally occurring steam and/or hot 
aqueous liquids (water or brine) have been found in many regions of the 
world. Such geothermal reservoirs are especially prevalent where the 
thermal gradient near the earth's surface is abnormally high, as in 
regions of volcanic, geyser or fumarole activity, as is commonly found 
along the rim of the Pacific Ocean. 
In some regions, where relatively abundant and readily accessible, hot 
geothermal fluids have, for some time, been used for therapeutic treatment 
of bodily disorders, in industrial processes, for heating purposes and the 
like. Although effort in further developing geothermal resources for such 
purposes continues, substantial effort has recently been directed towards 
using geothermal fluids to generate electric power which is usually much 
less site-restricted than is the more direct use of geothermal fluids for 
the above mentioned purposes. These interests in geothermal resources for 
power generation have been heightened by recent steep increases in 
petroleum and natural gas costs, as well as by the actual or threatened 
shortages of such fuels. 
The general processes for using hot geothermal fluids to generate electric 
power are quite well known. For example, geothermal steam can, after 
treatment to remove particulate material and polluting gases, be used in 
the manner of boiler-generated steam to drive conventional steam 
turbine-generators. Naturally pressurized, high temperature (above about 
400.degree. F.) geothermal water or brine is typically flashed to a 
reduced pressure to release steam which is used to drive steam 
turbine-generators. Lower temperature geothermal liquids are, in contrast, 
generally useful in binary fluid systems in which a low boiling point 
working fluid is vaporized by the hot geothermal liquid and the vapor is 
used to drive gas turbine-generators. 
As can be appreciated, geothermal steam is preferred over geothermal 
liquids for the production of electric power because the steam can be used 
almost as extracted from the earth in generally conventional steam-turbine 
power plants. As a result, where abundantly available and favorably 
located, as at The Geysers in California, geothermal steam has been used 
for a number of years to generate substantial amounts of electric power at 
competitive costs. Unfortunately, however, abundant sources of geothermal 
steam are relatively scarce, and at current estimates are only about 
one-fifth as prevalent as good sources of geothermal aqueous liquids. 
Because of the maturity of geothermal steam power generating processes and 
the scarcity of large grothermal steam sources, much of the current 
development effort in the geothermal field is directed towards developing 
commercially viable geothermal water/brine power generating facilities; 
particularly in such regions as the Imperial Valley in Southern 
California, where there is an abundance of geothermal brine. 
General processes and techniques for using geothermal aqueous liquid to 
generate electric power are, as above-mentioned, known. Such processes and 
techniques are, in theory, relatively straight forward. However, in actual 
practice many serious problems are usually encountered in handling the 
geothermal aqueous liquids, particularly the brines. Geothermal aqueous 
liquids typically have wellhead temperatures of several hundred degrees 
Farenheit and pressures of several hundred p.s.i.g. and are typically 
heavily contaminated with dissolved materials. For example, in many 
regions, the geothermal aqueous liquids contain high levels of dissolved 
gases, such as hydrogen sulfide, carbon dioxide, and ammonia, as well as 
high levels of metals, such as, lead, iron, arsenic, and cadmium. In 
addition, many hot geothermal aqueous liquids are saturated with silica 
and many are also highly saline in nature, being therefore termed brines. 
Because of their high levels of contaminants and high wellhead 
temperatures, most geothermal aqueous liquids are not only corrosive to 
equipment and have scale forming characteristics, but the reduced-energy, 
geothermal effluent discharged from the power generating facility cannot 
be easily disposed of, particularly considering that flow rates in excess 
of one million pounds per hour are not uncommon. Effluent contaminants, 
such as lead and arsenic, preclude safe use of the discharged liquid for 
such otherwise potential uses as crop irrigation, and in most localities 
discharging of the effluent into rivers, lakes and other water supplies is 
prohibited. Ponding and evaporation of the discharged geothermal effluent 
is generally impractical because of the large volumes involved. Moreover, 
because of their typical heavy metal content, the evaporated residues may 
be considered hazardous or toxic wastes and disposal is accordingly 
costly. 
The most, and often the only, practical manner of disposing of the 
geothermal effluent is, therefore, by pumping it back into the ground 
through injection wells. Additional advantages of this method of disposal 
are that ground subsidence which might otherwise be caused by depletion of 
underground geothermal reservoirs is eliminated, and useful life of the 
underground reservoirs is usually increased. 
Although reinjection often provides the only feasible method for disposing 
of geothermal effluent, serious problems, usually related to high silica 
content of the geothermal liquid, are nevertheless associated with such 
disposal. As mentioned, in many locations, the hot pressurized geothermal 
liquid, as extracted, is saturated with silica. When the geothermal liquid 
is flashed to produce steam for power production, the pressure of the 
liquid is reduced and the liquid becomes supersaturated with silica. As a 
result, silica rapidly precipitates from the liquid to form a hard scale 
on downstream piping and injection equipment, including the injection 
wells themselves. With many geothermal aqueous liquids, a silica scale 
formation rate of several inches per month is not unusual. As scaling of 
the piping, equipment and injection wells builds up, the geothermal liquid 
flow through the system becomes choked off and facility shutdown is then 
necessary for system reconditioning, which may include costly reboring of 
the injection wells. Because the silica scale is ordinarily very hard and 
tough, and clings tenanciously to equipment, the renovation process is 
difficult, time-consuming and costly, both in terms of actual renovation 
costs and in terms of nonproductive facility downtime. 
Two general methods are typically used to minimize the silica scaling 
problems in geothermal liquid power producing facilities. One method is to 
treat or handle the geothermal liquid in such a manner as to keep the 
silica in solution through reinjection. The other method is to cause 
sufficient silica precipitation from the geothermal liquid, in a 
controlled manner and in specific facility stages from which the 
precipitated silica can be easily removed, to keep the silica level below 
saturation during the reinjection stage. 
As can be appreciated, when the geothermal aqueous liquid is saturated with 
silica at wellhead temperatures and pressures, it is very difficult to 
keep the silica in solution when the liquid temperature and pressure is 
substantially reduced during the energy extraction process. The silica 
scale preventing method of controlled removal of sufficient silica so that 
the silica saturation level is not exceeded during the energy extraction 
process, although not without problems, may, therefore, be preferred in 
many instances where silica scaling would otherwise be a problem. 
One of the greatest difficulties with silica removal processes is the 
removal of the right amount of silica at the right stage in the system. If 
an insufficient amount of silica is removed, silica scaling will not be 
prevented and if the silica is not precipitated where intended, the 
precipitate may carry over into other stages of the system and cause flow 
restriction problems. On the other hand, excessive removal of silica may 
overload the silica disposal stages and add to the silica waste disposal 
costs. Therefore, to assure a practical and relatively trouble-free 
system, the silica removal process must be carefully controlled. 
With respect to the silica removal process, seeding of the geothermal 
aqueous liquid with a seed material, onto which the silica in solution 
crystallizes, appears to offer advantages of rapid, and hence 
location-controlled, silica removal. Such seeding processes typically pump 
some of the silica precipitate removed from one stage of the system into 
the flow of geothermal aqueous liquid at an upstream point, typically a 
flash-crystallizing stage which may be comprised of one or more 
flash-crystallization vessels. As the flashed geothermal liquid is 
contacted with the silica seed material in the flash crystallization 
stage, silica crystallizes from the liquid onto the seed material; the 
resulting precipitate is then removed, for example, in a downstream 
reactor-clarifier stage. 
Problems have heretofore, however, been associated with disposing of the 
large flow of high pH steam condensate which results from using the steam 
extracted from the geothermal aqueous liquid. Typically the flow of 
condensate is about 10 percent of the flow of flashed geothermal liquid 
and may accordingly be as great as several hundred thousands pounds per 
hour. Although the steam extracted from the geothermal aqueous liquid by 
the flashing process is generally much less contaminated than the 
geothermal liquid, it usually has enough contaminants, notably boron and 
arsenic, which are carried over into the steam to cause the steam 
condensate to be unusable and, as in the case of geothermal liquid, the 
most practical disposal method for the condensate is reinjection. 
Therefore, the basic steam condensate is ordinarily recombined with the 
acidic, flashed geothermal liquid upstream of the injection stage. The 
steam condensate may also contain appreciable levels of dissolved hydrogen 
sulfide, hydroxides (such as ammonium hydroxide) and carbonates all of 
which tend to be suppressed or maintained in solution by the normally high 
condensate pH. 
The present inventors have, however, discovered that because of the 
substantial differences in the chemical composition and also the pHs of 
the steam condensate and the flashed geothermal aqueous liquid, combining 
of the steam condensate with the flashed geothermal liquid upsets the 
chemical equilibrium in the liquid, thereby disrupting the silica 
crystallization process. Moreover, it has been found that such 
recombination also results in the formation of fine particulate matter, 
for example, heavy metal sulfides, carbonates, and/or hydroxides, when 
heavy metal impurities in the brine combine with the sulfides, hydroxides 
and carbonates in the condensate. Most of the particulate matter formed 
tends to remain in suspension and subsequently clogs up media filters 
through which the combined geothermal liquid and steam condensate are 
passed before reinjection. However, some of the particulate matter 
precipitates, and equipment scaling has been discovered to occur in 
regions of condensate-flashed liquid recombination. 
It is, therefore, an object of the present invention to provide a method 
for combining high pH steam condensate with an acidic, flashed, 
silica-rich geothermal aqueous liquid in a silica precipitating-type of 
system so as to prevent the formation of unwanted, suspended particulate 
matter. 
A further object of the present invention is to provide a method of 
combining, in a silica crystallization stage, a flow of high pH steam 
condensate with a flow of acidic, silica-rich, geothermal aqueous liquid, 
in which the pH of the steam condensate is adjusted so as to optimize the 
silica precipitation in the silica crystallization stage. 
A still further object of the present invention of to provide a method for 
combining a flow of high pH steam condensate with a flow of hot, acidic 
geothermal aqueous liquid containing heavy metals in solution, which 
substantially reduces the formation of suspended heavy metal compounds. 
Still another object of the present invention is to provide a method for 
combining a flow of high pH steam condensate with a flow of hot, acidic 
geothermal aqueous liquid in which at least part of the steam condensate 
is used as a pump seal purge for pumps used in the system. 
Additional objects, advantages and features of the invention will become 
apparent to those skilled in the art from the following description, when 
taken in conjunction with the accompanying drawing. 
SUMMARY OF THE INVENTION 
In accordance with the present invention, a method is provided for 
combining condensate of geothermally derived steam with a flow of 
geothermal liquid containing water and impurities, the geothermal liquid 
having an acidic pH, the condensate having a basic pH and containing water 
and volatile impurities, the geothermal liquid and condensate being such 
that, if combined without treatment, suspended particulate matter would 
form in the resultant mixture, the method comprising reducing the 
formation of the suspended particulate matter by treating the flow of 
steam condensate so as to reduce the pH thereof to a level of no more than 
about 7 and preferably to a level of between about 7 and about 4.5. The 
flow of reduced pH steam condensate is then combined with the flow of 
geothermal liquid upstream of an injection stage which injects the 
combined flow of condensate and geothermal liquid into the ground. 
As a result, the formation of suspended particulate matter, which could 
otherwise cause clogging of such geothermal treating equipment as media 
filters, is substantially prevented, as is localized scaling of equipment 
in the region of condensate-geothermal liquid combination. 
Treating of the flow of steam condensate preferably comprises contacting 
the condensate with an acidifying agent. More preferably, the acidifying 
agent is selected from the group consisting of hydrochloric acid, acetic 
acid and acetic acid derivatives. Most preferably, the acidifying agent 
used is hydrochloric acid because of its good condensate acidifying 
characteristics, ready availability and relatively low cost. 
In an exemplary system for handling silica-rich geothermal liquid, silica 
is removed in a flash crystallization stage in which the geothermal liquid 
is flashed to extract steam therefrom, and in which silica seed material 
is introduced. Silica then crystallizes from solution in the geothermal 
liquid onto the seed material for removal from the system. According to 
the present invention, the flow of reduced pH steam condensate is combined 
with the flashed geothermal liquid in such flash-crystallization stage of 
the system. 
Also, according to the present invention, some of the reduced pH steam 
condensate may be diverted to various of the fluid pumps used in the 
system for purging the pump seals, the steam condensate so used being 
thereby combined in the pumps with geothermal liquid being pumped thereby. 
Silica particle size in the seed crystallization process has been found 
also affected by pH of the steam condensate. Within the adjusted pH range 
of steam condensate which is preferred, that is, between about 7 and about 
4.5, the present method may thus also provide for adjusting the pH level 
in response to monitoring the mean size of particles produced in the 
flash-crystallization stage. The steam condensate pH is lowered, by 
increased acidification thereof, to increase the mean particle size and is 
maintained at, or increased, by reduced acidization to decrease mean 
particle size. Preferably, the steam condensate pH is adjusted to provide 
a mean particle size of between about 9 and 15 microns. The present method 
therefore also enables "fine tuning" of the silica removal process.

DESCRIPTION OF THE PREFERRED EMBODIMENT 
The present steam condensate treatment method is especially directed toward 
the acidizing of a flow of condensate of steam extracted in a hot 
geothermal brine power generating facility or system, and the subsequent 
combining of the acidized steam condensate with the geothermal brine for 
reinjection of the combined liquids into the earth through injection 
wells. As more particularly described below, the method is particularly 
adapted for use in a system in which a seed crystallization process is 
used to induce controlled precipitation of silica from silica-rich brine 
after steam, used for power generation, is flashed from the brine. Such 
controlled silica precipitation and removal is intended to greatly reduce 
or substantially eliminate silica scaling in system piping, equipment and 
injection wells. 
An exemplary hot geothermal aqueous liquid (for example, brine) electric 
power generating facility or system 10, in which the present method may be 
practiced to advantage, is depicted in the drawing, a description of 
system 10 being helpful to an understanding of the method. 
Hot, pressurized, saline geothermal aqueous liquid, hereinafter, for 
convenience, referred to as "geothermal brine" or "brine", is provided to 
system 10 from first and second extraction wells 12 and 14 respectively. 
It is to be appreciated that although only two wells 12 and 14 have been 
depicted in the Figure, a number of other wells may also be used to 
provide, for example, a total brine flow of about 1.2 million pounds per 
hour for a 10 megawatt power output from system 10. At the wellhead, 
geothermal brine may have a temperature of about 500.degree. F. and a 
natural pressure of about 450 psig. 
From wells 12 and 14, the extracted brine, which typically contains rubble, 
including sand and rock, is fed through respective conduits 16 and 18 to a 
separation stage 20. Included in separation stage 20 are first and second 
wellhead separation vessels 22 and 24, to which conduits 16 and 18 are 
respectively connected. Within separation vessels 22 and 24 some dissolved 
steam escapes from the brine, being fed by respective separate conduits 30 
and 32 to a common conduit 34 which, in turn, feeds the steam to a steam 
conditioning stage 36, described below. 
Brine is discharged from separators 22 and 24 through respective conduits 
38 and 40 to a common brine conduit 42 which, in turn, feeds the brine to 
a flash crystallization stage 52. 
Comprising flash crystallization stage 52 are high pressure flash 
crystallizer 54, low pressure crystallizer 56 and atmosphere flash tank 
58. Brine conduit 42 feeds high temperature, high pressure geothermal 
brine into the bottom of high pressure crystallizer 54 which is operated 
at a pressure of about 100 p.s.i.g. so as to enable flashing of dissolved 
steam from the brine. 
Within crystallizer 54, steam washing means 60 are provided for washing the 
extracted steam before the steam is fed through a steam conduit 62 to 
combine with separator steam in conduit 34. 
Although steam from separating stage 20 and flash crystallizer 54 is 
relatively low in impurities, as compared with the geothermal brine, a 
number of impurities dissolved in the brine are usually carried over into 
the flow of steam. These typically include ammonia, (in the form of 
ammonium hydroxide) carbon dioxide (in the form of carbonates), and 
hydrogen sulfide. Amounts of such other contaminants, notably boron, are 
also typically carried over from the brine into the flow of steam. 
Within steam conditioning stage 36, steam is fed through conduit 34 into a 
preliminary steam wash scrubber 64. Steam from scrubber 64 is then fed by 
a conduit 66 to a final wash scrubber 68. Washed steam from final scrubber 
68 is flowed through conduit 70 to a power generating facility 72 in which 
the flow of steam is used to generate electric power by generally 
conventional steam turbine-electric generator apparatus (not shown). Water 
from scrubbers 64 and 68 is fed through conduits 74 and 76, respectively, 
to a common discharge conduit 78 through which the water is fed to a 
diffuser sump 80 for subsequent disposal, as described below. 
Within power generating facility 72, energy is extracted from the steam 
flow from conduit 70 so that the steam condenses. The flow of steam 
condensate, which may, for a total brine extraction rate of about 1.2 
million pounds per hour, be about 155,000 pounds per hour, is discharged 
through a condensate conduit 88 to a condensate treatment stage 90, 
described below. As above-mentioned, the steam condensate is ordinarily 
too contaminated, with such materials as boron, to be usable and the most 
practical disposal is by reinjection into the ground with the "used" 
(flashed) geothermal brine. 
Within flash crystallizing stage 52, flashed brine from high pressure flash 
crystallizer 54 is fed through a conduit 92, to low pressure flash 
crystallizer 56, which may be maintained at a pressure between atmospheric 
and about 30 p.s.i.g. Some additional steam is flashed from the brine in 
low pressure flash crystallizer 56. As shown in the drawing, the steam 
extracted in crystallizer 56 is fed through a conduit 94 to atmospheric 
flash tank 58 from which it is discharged into the atmosphere. It is to be 
appreciated, however, that the steam from low pressure flash crystallizer 
contains substantial energy and so may be used for such purposes as 
additional power generation in a binary fluid system (not shown), for 
heating or for other energy-related purposes. In such cases, additional 
steam condensate, requiring disposal in the manner described herein, might 
be produced. 
Brine and silica precipitate from crystallizer 56 is flowed through a 
conduit 96 to atmospheric flash tank 58, and from such tank, through a 
conduit 98, to a large clarifier vessel 100 which forms part of a 
clarification/separation stage 102. 
Silica precipitate, formed in flash crystallizers 54 and 56 and continuing 
to form in clarifier 100, is separated from the geothermal brine in the 
clarifier, the wet precipitate being discharged from the bottom of the 
clarifier via a conduit 104. The wet silica precipitate, which also 
contains impurities such as lead, zinc, arsenic and other metals carried 
along with the precipitating silica, is flowed through conduit 104 to a 
thickener vessel 106 which also forms part of clarification and separation 
stage 102. 
Silica seed material for the silica crystallization process in flash 
crystallization stage 52 is withdrawn by a pump 112, through a conduit 
114, from the bottom of thickener vessel 106. Pump 112 feeds the seed 
material through a conduit 116 to high pressure flash crystallizer 54 in 
which a counterflow of seed material and geothermal brine enhances silica 
crystallization from the brine onto the seed material. 
A major portion of the silica precipitate discharged from thickener vessel 
106 is fed (controlled by valves, not shown) by pump 112 through a conduit 
118 into a filter press 120. Solid cake precipitate is removed from filter 
press 120 for disposal. 
Clarified geothermal brine is discharged from clarifier 100 and thickener 
vessel 106 through brine conduits 120 and 122, respectively, to respective 
brine pumps 124 and 126. Such pumps 124 and 126 pump the brine, through 
conduits 128 and 130, respectively, to common conduits 132 and 134, which 
discharge into first and second media filters 136 and 138. Filter bypass 
conduits 140 and 142, connected respectively to brine conduits 132 and 
134, enable bypassing of media filters 136 and 138 (by use of valves, not 
shown). Bypass conduits 140 and 142 are connected to a common conduit 144 
which discharges brine into a settling basin 146. Brine from filter press 
120 is also fed, through a conduit 148, to settling basin 146. From 
settling basin 146, brine is recycled, by a pump 160, through conduits 162 
and 164 back to atmospheric flash tank 58. 
Clarified brine is discharged from media filters 136 and 138 through 
respective conduits 166 and 168 to a common conduit 170 which is, in turn, 
connected to an injection pump 172. A conduit 174 is connected between 
conduit 170 and a backwash holding tank 176. 
A pump 180, connected to holding tank 176 by a conduit 182, enables the 
pumping of filtered brine, through conduits 184, 186 and 188, to media 
discharge conduits 166 and 168, to enable back flashing of media filters 
136 and 138. Flow of brine for such purpose is controlled by various 
valves, not shown. 
An additional pump 196, connected to holding tank 176 by a conduit 198, is 
provided for recirculating, by a conduit 200, filtered brine back through 
media filters 136 and 138. 
Filters 136 and 138, holding tank 176, pumps 160, 180, and 196, diffuser 
sump 80 and settling basin 146 form a filtration and settling stage 202. 
Filtered brine is pumped by injection pump 172 through conduits 204, 206, 
and 208, into first and second injection wells 210 and 212 respectively, 
such wells and pump forming an injection stage 214. 
CONDENSATE TREATMENT STAGE 90 
In condensate treatment stage 90, steam condensate received via conduit 88 
from power generating facility 72 is treated prior to recombining with 
flashed brine in low pressure flash crystallizer 56 and/or for other use, 
as described below. The untreated steam condensate flowing through conduit 
88 into stage 90 has, due to dissolved impurities, a basic pH which is 
typically about 9 or 10. Impurities dissolved in the untreated condensate 
typically include ammonia, principally as ammonia hydroxide, carbon 
dioxide, principally in the form of various carbonates, and hydrogen 
sulfide. Such impurities are carried over into the steam from the brine 
from which the steam is produced. At a condensate pH level of 9 or 10, the 
ammonia reacts with the hydrogen sulfide and carbon dioxide in a manner 
suppressing their outgassing. 
As above-described, the flashed brine contains appreciable levels of 
impurities including heavy metals, iron, and calcium compounds. When 
untreated, condensate is combined with the flashed brine, for example, in 
low pressure flash crystallizer 56, such impurities in the brine react 
with the above-mentioned impurities in the untreated condensate to form 
insoluble materials which principally include heavy metal sulfides, 
calcium carbonate, iron hydroxide and lead hydrochloride. By insoluble it 
is meant that the formed materials remain substantially undissolved in the 
mixed condensate brine flow through subsequent reinjection; although, 
given sufficient contact time most of the material would eventually be 
dissolved. 
Typically the insoluble materials resulting from the combination of the 
untreated, basic condensate and the acidic brine are in the form of very 
small particles, typically less than about 0.5 microns in size, which tend 
to remain in suspension. As a result, these small particles flow through 
clarifier 100 and are discharged therefrom into media filters 136 and 138 
which collect many of the particles and become increasingly clogged 
thereby. Some of the particles, however, pass through filters 136 and 138 
and are deposited in injection wells 210 and 212, causing eventual 
clogging thereof. 
Moreover, the lead hydrochloride so formed has been found to be corrosive 
to the metal brine handling equipment, including piping, vessels and 
fittings, into which it comes into contact. 
The extent to which the above-described insoluble materials are formed 
depends not only upon the amount of related impurities in the condensate 
and brine, but also upon the localized pH where the condensate is 
introduced into the brine. With respect to the latter factor, it has been 
discovered that reactions resulting in the formation of the insoluble 
material proceed rapidly when the pH of the brine is raised much above its 
normal level of about 5-5.5. Such brine pH elevation is caused in the 
region of introduction when appreciable amounts of basic condensate are 
introduced into the brine flow. Accordingly, when a flow of basic 
condensate is introduced into or merged with a flow of acidic brine, brine 
pH is locally increased and a continual flow of insoluble materials is 
formed. 
As described in our above-cited copending application Ser. No. 567,254, 
when the untreated condensate is acidified to provide closer pH matching 
with the brine, the hydrogen sulfide and carbon dioxide impurities in the 
condensate become "untied". An acidified condensate outgassing step is 
then provided, for example, by flowing the acidified condensate into and 
through an open pond or tank, so that some of the hydrogen sulfide and 
carbon dioxide can outgas. As a result, there remains less hydrogen 
sulfide and carbon dioxide in the acidized condensate to combine with 
impurities in the brine. 
In some circumstances, such outgassing of the acidified condensate may be 
impractical, undesirable or not allowed for environmental reasons. 
Moreover, it has been found by the present inventors, that much, although 
usually not all, of the benefits provided by acidizing the condensate and 
then allowing the condensate to outgas before combining with the acid 
brine can be obtained by directly combining the acidized condensate with 
the brine without first outgassing the acidified condensate. 
In accordance therewith, in present condensate treatment stage 90, an 
acidifying agent (described below), is fed by a pump 216, through conduits 
218 and 220, from a storage tank 222 into the flow of steam condensate in 
conduit 88. A conventional mixer 224 may be installed in conduit 88 just 
downstream of the connection between acidifying agent conduit 220 and 
condensate conduit 88 to provide rapid, thorough intermixing of the 
acidifying agent and the condensate. 
Downstream of mixer 224, condensate conduit 88 is connected to a condensate 
pump 230 through a conduit 232. Pump 230 pumps the acidified condensate 
through a conduit 234 into low pressure flash crystallizer, wherein the 
discharged condensate is combined with flashed brine. 
A second condensate pump 240 may be connected, by a conduit 242, to 
condensate conduit 88 downstream of mixer 224 for pumping a small amount 
of condensate, for example, about 200 pounds per hour, through a conduit 
244 to seal regions of pumps 112, 124, 126, 160, 172, 180, 196, 216, 230 
and 240, as well as other pumps (not shown) which may be included in 
system 10, for cooling the pump seals and for flushing the seals to 
prevent solid particles, which may be entrained in the liquid being 
pumped, from damaging sealing surfaces. Condensate provided by pump 240 to 
the various mentioned pumps typically flows through the seals and combines 
with the pumped liquid. 
Sufficient acidizing agent is introduced by pump 216 into condensate 
conduit 88 to substantially prevent the formation of the above-described 
insoluble materials otherwise caused by combining the condensate with the 
brine in low pressure crystallizer 56. Typically, sufficient acidizing 
agent should be introduced into conduit 88 by pump 216 to reduce the pH of 
the condensate from its natural level of about 9-10 to at least about 7 
and sufficient amounts may be added to reduce the condensate pH to about 
4.5, which is slightly lower than the typical 5-5.5 pH range of the brine. 
Such lower level of condensate pH may be required in some instances to 
offset the elimination of the post-acidizing condensate outgassing step. 
Moreover, pH of the steam condensate as it combines with the brine in 
crystallizer 56 has been found to affect the silica crystallizing 
processes in flash crystallization stage 52, the amount of silica removed 
from the geothermal brine being ideally just that amount which prevents 
any substantial scaling of downstream equipment. Size of the silica 
precipitate particles formed in flash crystallization stage 52 is 
important to amount of silica removed and its removal rate. As particle 
sizes increase, less surface area per precipitate volume is provided. 
Since in the silica removal process silica crystallization from the 
flashed geothermal brine onto seed particles depends upon surface area of 
the particles, the formation of large particles inhibits the silica 
removal process. On the other hand, if the particles formed are too small, 
precipitation thereof may not occur and the particles may be carried over 
into, and cause clogging of, media filters 136 and 138. 
As a result, it has been found possible to "fine tune" the silica 
crystallization process in crystallization stage 52 by adjusting the 
acidizing of the steam condensate while maintaining the condensate pH 
between about 7 and about 4.5. Such fine tuning of the silica 
crystallization process may, for example, be important to accommodate 
fluctuations over time in brine characteristics. 
Monitoring the size of particles flowing with the geothermal brine into 
clarifier 100, therefore, permits determining the extent to which the 
steam condensate should, within the above-expressed approximate limits, be 
acidified. It is found, for example, for a particularly exemplary brine, 
that mean particle size of clarifier 100 is preferably between about 9 to 
about 15 microns for good silica crystalliation, and acidification of the 
steam condensate is adjusted so as to maintain such a mean particle size. 
If the mean particle size falls below the preferred range, acidifying of 
the condensate is increased and if the mean particle size increases 
appreciably over the desired range, the acidifying of the condensate is 
decreased. 
According to a preferred embodiment, pH of the steam condensate is reduced 
by the addition of an acidifying agent provided by pump 216, through 
conduits 218 and 220 from storage tank 222. Preferably the acidifying 
agent is hydrochloric acid because of its low cost, ready availability and 
effectiveness in reducing condensate pH. Other acids, such as acetic acid 
or acetic acid derivatives, can alternatively be used. Use of sulphuric 
acid to acidize the steam condensate has been found to cause formation of 
additional solids and use of nitric acid has been found to cause corrosion 
problems in the system; hence, use of these acids is not preferred. 
The present invention may be further described with reference to the 
following example: 
EXAMPLE 
A sample of flashed geothermal brine is extracted from a geothermal brine 
clarifier corresponding generally to clarifier 100, ferric (Fe.sup.+3) ion 
concentration in the brine samples is measured and are found to be between 
about 7 and about 13 ppm. Normal pH of the brine sample is about 5.5. The 
brine sample is heated by an oil bath to a temperature of about 
220.degree. F., which is approximately the temperature of the brine in the 
clarifier. 
Samples of steam condensate, as returned from power generating facility 72 
or the equivalent thereof, are obtained. Nominal pH of the condensate 
samples is about 8.6. 
A sample of such steam condensate is contacted with hydrochloric acid to 
reduce the pH thereof to a level of about 7.0. Another sample of the steam 
condensate is contacted with hydrochloric acid to reduce the pH thereof to 
about 5.5. 
Samples of the 8.6, 7.0 and 5.5 pH condensate, having temperatures of about 
90.degree.-100.degree. F., which is about the normal temperature of 
condensate at the brine combination point (in low pressure flash 
crystallizer 56), are individually combined and mixed with samples of the 
approximate 220.degree. F. flashed brine so as to provide various weight 
percentages of condensate and brine in the mixture. The acidized 
condensate samples are not permitted to outgas before being combined with 
the samples of brine. The mixtures are agitated for about an hour, which 
approximates the average brine transit time from low pressure flash 
crystallizer through reinjection by wells 210 and 212. Thereafter, ferric 
ion concentrations in each of the samples are measured and are expressed 
in percentages of the original amounts (7-13 ppm) of ferric ions in the 
brine. 
Calculations are also made as to the percentages of the original amounts of 
ferric ions based only upon the amount of dilution provided by the 
combined amounts of condensate. The results obtained for brine/condensate 
percent mixtures of 90/10, 80/20, 70/30, 60/40 and 50/50 are tabulated in 
the following table, (a percent mixture ratio of about 88/12 
brine/condensate is typical in above-described system 10). 
______________________________________ 
Calculated amount 
of suspended 
% composition Suspended solids in mixture 
of mixture by 
Condensate 
solids in as percent of 
weight pH mixture as % 
solids in brine 
Con- (8.6 = of solids 
only as a result 
Brine densate normal) in brine only 
of dilution only. 
______________________________________ 
90 10 8.6 111 90 
7.0 93 
5.5 75 
80 20 8.6 110 80 
7.0 88 
5.5 85 
70 30 8.6 108 70 
7.0 83 
5.5 66 
60 40 8.6 110 60 
7.0 75 
5.5 53 
50 50 8.6 122 50 
7.0 68 
5.5 40 
______________________________________ 
The above table shows, for example, for a 90/10% brine/condensate mixture, 
the expected (calculated) amount of solids (as determined from ferric ion 
concentration measurements) due to brine dilution is about 90% of the 
original concentration of solids in brine. However, combining unacidified 
brine at a pH of about 8.6 causes the amount of solids to be about 110% 
that of solids initially in the brine and is about 21% higher than that 
calculated for the diluted brine. For a condensate pH of about 7.0, the 
percent of solids is found to be about 93% of the amount initially in the 
brine and is only about 3% higher than that calculated for the diluted 
brine. For a condensate pH of about 5.5, the percent of solids is found to 
be about 75% of the initial amount, and is about 15% lower than that 
calculated for the diluted brine. 
Accordingly, for the 90/10% samples, the combining of untreated condensate 
(pH about 8.6) with the brine causes substantial production of solids, 
whereas, the combining of acid-treated condensate having a pH of about 7 
causes only slight production of solids. The combining of acid-treated 
condensate having a pH of about 5.5 actually causes a reduction in the 
expected amount of solids, indicating that a dissolving of preexisting 
solids occurs at such condensate pH. 
The table shows similar results for the 80/70%, 70/30%, 60/40% and 50/50% 
brine/condensate mixture. 
Although a particular embodiment of the invention has been described, it 
will, of course, be understood that the invention is not limited thereto, 
since many obvious modifications can be made, and it is intended to 
include within this invention any such modifications as fall within the 
scope of the claims.