Process to abate geothermal hydrogen sulfide

A process for removing hydrogen sulfide from geothermal steam and from vent streams, or concentrated portions produced by a hydrogen sulfide separation process, includes the steps of introducing an oxygen-containing gas, such as air into the steam, or vent stream, and thereafter contacting the steam and oxygen-containing gas in a contacting stage with iron oxide supported by a carrier resistant to deterioration. The steam having a temperature of at least 250.degree. F. is mixed with oxygen to provide a molar ratio of oxygen-to-hydrogen sulfide ratio of less than about 10. During the contacting stage the pressure of the steam and oxygen-containing gas is maintained at a pressure sufficient to enable removal of a majority of the hydrogen sulfide from the steam and oxygen-containing gas.

BACKGROUND OF THE INVENTION 
The present invention relates generally to the purification of steam 
produced by geothermal sources and more particularly to a process for 
abating, or removing, the hydrogen sulfide content of the steam. 
In many areas of the world, geothermal steam is present at temperatures and 
pressures sufficient for utilization in turbines for the generation of 
electricity. Unfortunately, the geothermal steam contains a number of 
contaminating gases such as carbon dioxide, ammonia, nitrogen and hydrogen 
sulfide among others. 
It has been widely recognized that in many instances, the hydrogen sulfide 
content of geothermal steam is sufficiently high to make discharge of the 
steam into the air environmentally unexceptable. 
Therefore, it has been the object of many investigators to remove, or 
abate, the hydrogen sulfide in the geothermal steam in order to make 
release to the atmosphere an exceptable procedure. 
Many methods for removing hydrogen sulfide from gases, have been developed. 
For example, gas containing hydrogen sulfide may be contacted with 
activated carbon to catalyze the oxidation of hydrogen sulfide to 
elemental sulfur and water. Some investigators, for example, see U.S. Pat. 
No. 4,330,307 issued to Coury in 1982, have developed methods to separate 
the geothermal steam into a usuable portion, having a low hydrogen sulfide 
content, and a vent portion or stream, containing the majority of the 
hydrogen sulfide, the latter being disposed of by reinjection into the 
ground. Reinjection of this vent portion is not desireable, however, 
because the H.sub.2 S may migrate and present itself in newly extracted 
steam. 
The process described in U.S. Pat. No. 4,374,106 to Tipton is directed to a 
process for removing hydrogen sulfide from a geothermal steam by 
contacting the steam which is mixed with an oxygen containing gas, such as 
air, with iron oxide and wherein the molar ratio of oxygen to hydrogen 
sulfide in the steam and oxygen containing gas is at least 10. 
It has now been discovered that hydrogen sulfide can be effectively removed 
from geothermal steam by mixing an oxygen containing gas with the 
geothermal steam to provide a molar ratio of oxygen to hydrogen sulfide 
less than 10 and contacting the mixture with iron oxide under specific 
process conditions. Further, it has been found that elemental sulfur can 
be recovered on a continuous basis from the geothermal steam after it is 
contacted with the iron oxide. 
More specifically, the process is effective in removing high concentration, 
of hydrogen sulfide from geothermal steam such as concentrated in the vent 
stream of processes such as described by Coury (U.S. Pat. No. 4,330,307). 
These results are unexpected and not anticipated by the prior art which has 
been extensively discussed in Tipton et. al. (U.S. Pat. No. 4,374,106). 
SUMMARY OF THE INVENTION 
In accordance with the present invention a process for removing hydrogen 
sulfide from geothermal steam includes the steps of introducing an 
oxygen-containing gas into steam produced by a geothermal source, 
contacting steam and oxygen containing gas in a contacting stage with iron 
oxide supported by a carrier resistant to deterioration by the steam and 
providing the steam and oxygen-containing gas in the contacting stage at a 
pressure sufficient to enable removal of a majority of hydrogen sulfide 
from the steam and oxygen containing gas. 
The steam comprises water vapor and hydrogen sulfide and has a temperature 
of at least 250.degree. F. while the oxygen-containing gas is introduced 
into the steam in an amount to provide a molar ratio of oxygen-to-hydrogen 
sulfide in the steam and oxygen-containing gas to be less than about 10. 
More particularly, the process for removing hydrogen sulfide for geothermal 
steam in accordance with the present invention includes the steps of 
removing the steam from the geothermal source, throttling the removed 
steam to a preselected pressure, straining the throttled steam to remove 
any large solid particles, separating any liquid droplets from the 
strained steam, introducing the separated steam and air into a first stage 
thermal compressor in which the air is compressed and mixed with the steam 
introduced thereinto. The mixed compressed air and steam are withdrawn 
from the first stage thermal compressor and introduced into a second stage 
thermal compressor with additional strained steam to further compress the 
mixed compressed air and steam to a final mixture of compressed air and 
steam having a molar ratio of oxygen-to-hydrogen sulfide of less than 
about 10. 
The final mixture is contacted in a reactor with iron oxide supported by 
pumice and the pressure of the final mixture in the reactor is controlled 
by means of a back pressure valve. Finally, the steam having a majority of 
the hydrogen sulfide removed therefrom is removed from the reactor and 
vented to the atmosphere. 
Alternatively, when the concentration of the hydrogen sulfide in the 
geothermal steam is sufficiently high, elemental sulfur may be separated 
from the steam and air after it passes through the reactor.

DETAILED DESCRIPTION 
As illustrated in FIG. 1, geothermal steam from a geothermal steam well 
head 10 may be throttled by an inlet steam throttle valve 12 to a 
preselected pressure. The preselected pressure may vary depending upon the 
quantity and final utilization of the steam from which hydrogen sulfide 
has been removed in addition to other parameters including the size and 
volume capability of the overall process equipment. 
Downstream from the throttle valve 12 is a strainer 14 and an in-line steam 
separator 16, both of which may be of conventional design for removing any 
large solid particles and liquid droplets from the geothermal steam 
extracted from the well head 10. The liquids removed by the in-line steam 
separator 16, which may otherwise cause damage to the thermal compressor 
18 are discharged to the atmosphere through a steam trap 20. 
After separation of the solids and liquids therefrom, the steam flow rate 
may be measured by orfice flow meter 22, as it is introduced into the 
first stage 28 of the thermal compressor, or ejector 18. The two-stage 
ejector, 18 may be of conventional design and utilizes the steam ejected 
thereinto for compressing air, which is introduced to the first stage 28, 
through an air flow meter 30 and an air throttle valve 32. 
A distinct advantage is realized through the use of the thermal compressor 
18 because part of the geothermal steam to be treated is utilized as the 
motive force in compressing and mixing the air, which is the 
oxygen-containing gas, with the geothermal steam. 
It is to be appreciated that a separate air compressor (not shown) which 
may be driven by an electric motor or diesel engine may be utilized to 
compress the air to the proper pressure, however additional power must be 
provided therefore and its use will not realize to the fullest extent the 
advantages and features of the present invention. 
The effluent from the first stage 28 is passed through a second stage 36 of 
the thermal compressor 18 along with additional steam which has been 
strained to remove solid particles and liquid droplets contained therein. 
A final mixture of steam and air is then produced by the sccond stage 36 
which has a molar ratio of oxygen-to-hydrogen sulfide of less than about 
10. 
Preferably, when the pressure of the final mixture of steam and air is 
about 100 psi, the molar ratio of oxygen-to-hydrogen sulfide in the steam 
and air final mixture is approximately 5. 
This is to be distinguished from the process described by Tipton in U.S. 
Pat. No. 4,374,106 which is directed to a similar process in which the 
oxygen to hydrogen sulfide ratio in the steam and air final mixture is 
greater than 10. Tipton found that with oxygen-to-hydrogen sulfide molar 
ratio less than about 10, the amount of hydrogen removed from the 
geothermal steam was significantly reduced. 
The molar ratio of oxygen-to-hydrogen sulfide is controlled by adjusting 
the valve 32 and may be monitered by the air flow meter 30. 
The final mixture of steam and air is passed through a reactor 40 packed 
with an iron oxide, which is coated on a carrier suitable for withstanding 
steam and water at the operating temperatures and pressures without 
deterioration thereof. Pumice may be suitable for this carrier, but other 
carriers which may absorb water, expand or crumble are not desirable. The 
pressure in the reactor 40 may be regulated by a valve, or orifice plate, 
42 which is situated down-stream from the reactor 40. 
Following removal of the steam having a majority hydrogen sulfide removed 
therefrom in the reactor 40, the steam is vented to the atmosphere through 
a rock muffler 44 or the like to reduce the noise level of the exiting 
steam. 
Turning now to FIG. 2 there shown another embodiment of the present 
invention used in conjunction with a hydrogen sulfide concentrator 50 such 
as that described by Coury in U.S. Pat. No. 4,330,307 for separating 
geothermal steam from a well head 52 into clean useable steam and a vent 
portion, or stream, having a high concentration hydrogen sulfide. Typical 
operating parameters in terms of gas flow temperatures and pressures are 
indicated in FIG. 2 adjacent to the lines representing the flow of gases 
and indicate flow rates expected for providing steam to a 5 mega-watt 
electric generating plant. 
Usually, the distribution of H.sub.2 S between the vent stream and the bulk 
stream is a function of the fraction of the inlet stream that is vented. 
According to Coury, about 94% of the inlet H.sub.2 S will be in the vent 
stream, if 5% of the total inlet stream is vented. That is, the H.sub.2 S 
content of the vent stream will be about 20 times more concentrated than 
the inlet stream. Hence, if the concentration of H.sub.2 S in the 
geothermal steam is about 100 ppm (parts per million), the concentration 
of H.sub.2 S in the vent portion, or stream, will be about 2000 ppm. 
Prior art teachings, as represented by a consultant report prepared by the 
Stanford Research Institute for the California Resource Conservation and 
Development Commissioner on page D-6, last paragraph, shows that: "Once 
the sulfur melts and flows over the surfaces of the granules of absorbent, 
it will form an impervious film and make the absorbent surface 
inaccessible to the H.sub.2 S. If the quantity of sulfur in the absorbent 
bed were sufficient when melting occurred, the molten sulfur could flow 
through the bed in the direction of gas flow, making the entire bed 
inoperative. Upon shutdown, the freezing of the sulfur would virtually 
cement the absorbent mass together, so that it would have to be chipped 
out. Consequently, the steam temperature must be limited to not more than 
about 230.degree. F." 
Thus, it is apparent that the present invention produces an unexpected 
result in that it is effective in removing H.sub.2 S from concentrated 
vent streams, and, additionally useful in recovering elemental sulfur from 
the vent stream of a Coury type process, the latter adding economic 
advantage to the invention. 
In accordance with the present invention an externally driven compressor 54 
may be used to compress air, as an oxygen-containing gas, to approximately 
120 psia after which it is mixed with the vent stream flowing from the 
concentrator 50 in a conduit 56 prior to entering the reactor 58. 
As was previously discussed, a reactor back pressure valve 62 may be used 
to provide the steam and oxygen-containing gas in the reactor, or 
contacting stage, at a pressure sufficient to cause formation of elemental 
sulfur and removal of hydrogen sulfide from the steam and 
oxygen-containing gas. 
The elemental sulfur remains as a vapor in the steam and oxygen-containing 
gas and is passed by the reactor back pressure valve into a conventional 
venturi scrubber 66 for separating the elemental sulfur from the steam and 
oxygen-containing gas. The steam and air are then vented through a valve 
68 from the scrubber 66 and the sulfur is passed by a pump 70 to a steam 
heated storage tank 72 for accumulation of the sulfur which is kept in a 
molten form for later transportation. Part of the sulfur stream may be 
recirculated through the venturi scrubber 66 via a conduit 76, to serve as 
the scrubbing medium. 
The following examples are provided for the purpose of showing the process 
of the present invention in removing hydrogen sulfide from geothermal 
steam. 
EXAMPLES 
Example 1 
247 grams of Iron Oxide catalyst (the catalyst support was Lake County, 
California Red Pumice) was packed in a stainless steel 316 column of 2.3 
cm I.D., The bed height was about 58 cm. The reactor temperature was 
maintained at 314.degree. F., pressure at 85 psia. steam flow rate=95 
grams/hr., Oxygen flow rate=341 cm.sup.3 /min, a gas mixture 160 cm.sup.3 
/min (containing 5.41% of H.sub.2 S by volume, the balance is nitrogen). 
The above three gas streams were well mixed and sent to the top of 
reactor. This reactor inlet gas stream has H.sub.2 S content 5305 ppm by 
weight. The O.sub.2 to H.sub.2 S molar ratio is 3.93. The effluent gas 
from the reactor contained only 912 ppm by weight of H.sub.2 S. Therefore, 
the H.sub.2 S removal by the reactor was 82.8%. 
Example 2 
The same reactor used in example 1 was operated under the following 
conditions: 
Steam flow rate=88.6 grams/hr. 
Steam pressure=85 psia. 
Oxygen flow rate=17.1 cm.sup.3 /min. 
H.sub.2 S & N.sub.2 mixture flow rate=80 cm.sup.3 /min (containing 5.41% by 
volume of H.sub.2 S) 
The reactor inlet stream's H.sub.2 S content was 3825 ppm by weight. The 
oxygen to H.sub.2 S molar ratio was 3.95. The measured H.sub.2 S content 
in the reactor effluent was only 99 ppm wt. Therefore, the H.sub.2 S 
removal by the reactor was 97.4%. 
Example 3 
The same reactor used in example 1 was operated under the following 
conditions: 
Steam flow rate=92.6 grams/hr. 
Steam pressure=85 psia. 
Oxygen flow rate=13.65 cm.sup.3 /min. 
H.sub.2 S & N.sub.2 mixture flow rate=160 cm (containing 5.41% by volume of 
H.sub.2 S) 
The reactor inlet stream had a H.sub.2 S content of 6819 ppm by weight. The 
O.sub.2 to H.sub.2 S molar ratio was 1.58. The measured H.sub.2 S content 
in the reactor effluent was 1773 ppm wt. Therefore, the H.sub.2 S removal 
by the reactor was 74%. 
Example 4 
The same reactor as in example 1 was operated in the following conditions: 
Steam flow rate=125 grams/hr. 
Steam pressure=85 psia. 
Oxygen flow rate=136.3 cm.sup.3 /min 
H.sub.2 S & N.sub.2 mixture flow rate=320 cm.sup.3 /min (containing 5.41% 
by volume of H.sub.2 S) 
This reactor inlet stream has a H.sub.2 S content of 8477 ppm by weight. 
The O.sub.2 to H.sub.2 S molar ratio was 7.9. The measured reactor 
effluent H.sub.2 S content was only 34 ppm wt. Therefore, the reactor 
removed 99.6% of the incoming H.sub.2 S. 
Example 5 
A demonstration unit located at Geysers area, Lake County, Calif. was 
operating for 1055 hrs., the reactor size and process conditions are 
outlined in Table 1. 
The results of the field data collected with this demostration reactor are 
shown in Table 2 which shows a variety of pressure and molar ratios of 
oxygen to hydrogen sulfide. It is apparent that the results therein, where 
the molar ratio of oxygen to hydrogen sulfide was greater than 10, confirm 
the results of Tipton in U.S. Pat. No. 4,374,106. 
Surprisingly and contrary to the teaching of Tipton, the process of the 
present invention is effective in removing hydrogen sulfide from 
geothermal steam at molar ratio of oxygen to hydrogen sulfide of 
significately less than 10. 
Importantly in run No. 2015 the reactor effluent was condensed and a 96 
gram liquid example was collected which contained yellowish solids. After 
filtration and separating the yellow solids on electron microprobe 
analysis identified the yellow solids to be 99% sulfur. 
Although there has been described hereinabove a specific process for 
removing hydrogen sulfide from geothermal steam directly or from the vent 
stream of an H.sub.2 S separation, in accordance with the invention for 
purposes of illustrating the manner in which the invention may be used to 
advantage, it will be appreciated that the invention is not limited 
thereto. According by, any and all modifications, variations or equivalant 
arrangements which may occur to those skilled in the art should be 
consider to be within the scope of the invention as defined in the 
appended claims. 
TABLE 1 
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Reactor Dimension 42 inch diameter 
Catalyst Volume 48 ft.sup.3 
Total duration of run 
1060 hours 
Catalyst support Scoriaceous Volcanic 
Rock (Lake Coundy Red 
Pumice) 
Steam Flow Rate, lb/hr 
4,900-11,783 
Reactor Pressure, PSIA 
35-129 
Inlet H.sub.2 S Content, ppm wt 
215-1,055 
Inlet H.sub.2 S concentration 
0.9 .times. 10.sup.-6 -6.6 .times. 10.sup.-6 
lb-mole/ft.sup.3 
Molar ratio O.sub.2 to H.sub.2 S 
0-48 
H.sub.2 S Removal 26%-99.2% 
Contact time based on 
3.0-5.9 
total flow, second 
Superficial linear 0.8-1.7 
Velocity, ft/sec 
H.sub.2 S weight space time 
1.3 .times. 10.sup.4 -9.0 .times. 10.sup.4 
lb-hour/lb-mole 
Pressure drop across 
1-3 
reactor, PSI 
Steam (inlet) temperature, .degree.F. 
279-352 
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TABLE 2 
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RE- H.sub.2 S CON- 
ACCU- ACTOR TENT IN MOLAR % RE- 
MU- PRES- REACTOR RATIO MOVAL 
RUN LATED SURE INLET, O.sub.2 TO 
OF 
NO. HOURS PSIA PPM WT H.sub.2 S 
H.sub.2 S 
______________________________________ 
1010 28. 35. 509. 15.4 79.0 
1049 108. 111. 276. 30.0 91.3 
1106 223. 111. 692. 13.3 82.9 
1123 257. 112. 786. 6.7 77.0 
1149 310. 111. 1055. 9.4 64.4 
1174 354. 112. 308. 19.0 87.5 
1212 435. 110. 823. 8.6 64.5 
1234 479. 109. 658. 7.6 73.6 
1254 600. 117. 902. 3.7 54.3 
1308 774. 71. 401. 21.7 80.8 
1315 818. 71. 700. 12.8 78.9 
2005 845. 97. 271. 16.1 97.8 
2015 938. 95. 262. 5.0 97.3 
2020 1006. 92. 292. 0.0 26.0 
2026 1055 53. 267. 6.8 59.0 
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