U.S. patent application number 13/678311 was filed with the patent office on 2013-05-16 for method of producing power.
This patent application is currently assigned to SHELL OIL COMPANY. The applicant listed for this patent is SHELL OIL COMPANY. Invention is credited to Stanley Nemec MILAM, Richard Bruce TAYLOR.
Application Number | 20130119677 13/678311 |
Document ID | / |
Family ID | 48279869 |
Filed Date | 2013-05-16 |
United States Patent
Application |
20130119677 |
Kind Code |
A1 |
TAYLOR; Richard Bruce ; et
al. |
May 16, 2013 |
METHOD OF PRODUCING POWER
Abstract
A process for producing power from a fuel stream containing at
least 30 mol % hydrogen sulfide is provided. The fuel stream is
combusted with an oxidant stream containing molecular oxygen to
generate a combusted gas stream containing thermal power, where the
molar ratio of molecular oxygen to hydrogen sulfide is at least
1:1. Electrical power is generated from the thermal power of the
combusted gas stream.
Inventors: |
TAYLOR; Richard Bruce;
(Sugar Land, TX) ; MILAM; Stanley Nemec; (Houston,
TX) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
SHELL OIL COMPANY; |
Houston |
TX |
US |
|
|
Assignee: |
SHELL OIL COMPANY
Houston
TX
|
Family ID: |
48279869 |
Appl. No.: |
13/678311 |
Filed: |
November 15, 2012 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
61559846 |
Nov 15, 2011 |
|
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|
Current U.S.
Class: |
290/1R |
Current CPC
Class: |
F01D 15/10 20130101;
Y02E 20/16 20130101; F02C 3/22 20130101; C10L 3/103 20130101 |
Class at
Publication: |
290/1.R |
International
Class: |
F01D 15/10 20060101
F01D015/10 |
Claims
1. A method of producing power comprising combusting an oxidant
stream and at least a portion of a fuel stream comprising one or
more feed streams to generate a combusted gas stream containing
thermal power, wherein the fuel stream has a hydrogen sulfide
content of at least 30 mol %, at least 90 mass % of the components
of the fuel stream are gaseous, the oxidant stream contains
molecular oxygen, and the molar ratio of molecular oxygen to
hydrogen sulfide is at least 1:1; and generating electrical power
from the thermal power of the combusted gas stream.
2. The method of claim 1 wherein the molar ratio of molecular
oxygen to hydrogen sulfide is from 1.3:1 to 1.7:1.
3. The method of claim 1 wherein electrical power is generated from
the thermal power of the combusted gas stream by exchanging
sufficient heat between the combusted gas stream and a liquid
aqueous stream to convert the liquid aqueous stream to steam and to
cool the combusted gas stream, where the cooled combusted gas
stream is a flue gas stream comprising sulfur dioxide; expanding
the steam through an expander to generate mechanical power and an
expanded steam stream; and, converting the mechanical power to
electrical power.
4. The method of claim 3, further comprising the steps of
exchanging heat between the expanded steam stream and a fluid
having a boiling point at least 50.degree. C. lower than the liquid
of the liquid aqueous stream at 0.101 MPa and having a latent heat
of vaporization of at least 350 kJ/kg to condense water from the
expanded steam stream and to form a heat transfer gas from the
fluid, where the heat transfer gas contains thermal power
transferred from the expanded steam stream by heat exchange with
the fluid; expanding the heat transfer gas through an expander to
generate mechanical power and to form the fluid; and generating
electrical power from the mechanical power generated by expanding
the heat transfer gas.
5. The method of claim 4 wherein a portion of the thermal power
transferred from the expanded steam stream to the fluid is derived
from the latent heat of condensation of water in the expanded steam
stream.
6. The method of claim 4 wherein the fluid is selected from the
group consisting of anhydrous ammonia, aqueous ammonia, anhydrous
sulfur dioxide, carbon dioxide, and diethyl ether.
7. The method of claim 4 wherein the water condensed from the
expanded steam stream has a temperature of at most 85.degree. C.
and is provided as the liquid aqueous stream to cool the combusted
gas stream.
8. The method of claim 3, wherein the flue gas stream further
comprises steam and has a temperature of from greater than
100.degree. C. to 150.degree. C., further comprising the steps of
exchanging heat between the flue gas stream and a fluid having a
boiling point at least 50.degree. C. lower than the liquid of the
liquid aqueous stream at 0.101 MPa and having a latent heat of
vaporization of at least 350 kJ/kg to cool the flue gas stream to a
temperature of from greater than 0.degree. C. to 50.degree. C. and
condense and separate water therefrom and to form a heat transfer
gas from the fluid, where the heat transfer gas contains thermal
power transferred from the flue gas stream to the fluid by heat
exchange with the fluid; expanding the heat transfer gas through an
expander to generate mechanical power and to form the fluid; and
generating electrical power from the mechanical power generated by
expanding the heat transfer gas.
9. The method of claim 8, wherein the fluid formed by expanding the
heat transfer gas through an expander has a temperature of from
-25.degree. C. to -100.degree. C., further comprising the steps of
exchanging heat between the fluid having a temperature of from
-25.degree. C. to -100.degree. C. and a scrubbing solvent in which
sulfur dioxide, carbon dioxide, or both may be dissolved to chill
the scrubbing solvent to a temperature of from -100.degree. C. to
0.degree. C. and to raise the temperature of the fluid to at least
0.degree. C. without converting the fluid to a gas; and contacting
the flue gas stream from which water has been separated with the
chilled scrubbing solvent to separate sulfur dioxide, carbon
dioxide, or both from the flue gas stream into the scrubbing
solvent.
10. The method of claim 9 further comprising the steps of heating
the chilled scrubbing solvent to a temperature at which sulfur
dioxide, carbon dioxide, or both separate from the scrubbing
solvent, and separating sulfur dioxide, carbon dioxide, or both
from the scrubbing solvent.
11. The method of claim 10 further comprising the step of
exchanging heat between the scrubbing solvent from which sulfur
dioxide, carbon dioxide, or both have been separated and the fluid
having a temperature of from -25.degree. C. to -100.degree. C. to
chill the scrubbing solvent to temperature of from -100.degree. C.
to 0.degree. C. and to heat the fluid to a temperature of at least
0.degree. C. without converting the fluid to a gas.
12. The method of claim 1 wherein electrical power is generated
from at least a portion of the thermal power of the combusted gas
stream by expanding the combusted gas stream through an expander to
generate mechanical power and an expanded combusted gas stream, and
converting the mechanical power to electrical power.
13. The method of claim 12 wherein the molar ratio of molecular
oxygen in the oxidant stream to hydrogen sulfide in the fuel stream
is at least 2:1.
14. The method of claim 12 wherein electrical power is generated by
exchanging heat between the expanded combusted gas stream and a
liquid aqueous stream to convert the liquid aqueous stream to steam
and to cool the expanded combusted gas stream, where the cooled
expanded combusted gas stream is a flue gas stream comprising
sulfur dioxide; expanding the steam through an expander to generate
mechanical power and an expanded steam stream; and, converting the
mechanical power to electrical power.
15. The method of claim 14, further comprising the steps of
exchanging heat between the expanded steam stream and a fluid
having a boiling point at least 50.degree. C. lower than the liquid
of the liquid aqueous stream at 0.101 MPa and having a latent heat
of vaporization of at least 350 kJ/kg to condense water from the
expanded steam stream and to form a heat transfer gas from the
fluid, where the heat transfer gas contains thermal power
transferred from the expanded steam stream by heat exchange with
the fluid; expanding the heat transfer gas through an expander to
generate mechanical power and to form the fluid; and generating
electrical power from the mechanical power generated by expanding
the heat transfer gas.
16. The method of claim 15 wherein the fluid is selected from the
group consisting of anhydrous ammonia, aqueous ammonia, anhydrous
sulfur dioxide, carbon dioxide, and diethyl ether.
17. The method of claim 15 wherein a portion of the thermal power
transferred from the expanded steam stream to the fluid is derived
from the latent heat of condensation of water in the expanded steam
stream.
18. The method of claim 15 wherein the water condensed from the
expanded steam stream has a temperature of at most 85.degree. C.
and is provided as the liquid aqueous stream to cool the expanded
combusted gas stream.
19. The method of claim 14, wherein the flue gas stream further
comprises steam and has a temperature of from greater than
100.degree. C. to 150.degree. C., further comprising the steps of
exchanging heat between the flue gas stream and a fluid having a
boiling point at least 50.degree. C. lower than the liquid of the
liquid aqueous stream at 0.101 MPa and having a latent heat of
vaporization of at least 350 kJ/kg to cool the flue gas stream to a
temperature of from greater than 0.degree. C. to 50.degree. C. and
condense and separate water therefrom and to form a heat transfer
gas from the fluid, where the heat transfer gas contains thermal
power transferred from the flue gas stream to the fluid by heat
exchange with the fluid; expanding the heat transfer gas through an
expander to generate mechanical power and to form the fluid; and
generating electrical power from the mechanical power generated by
expanding the heat transfer gas.
20. The method of claim 19, wherein the fluid formed by expanding
the heat transfer gas through an expander has a temperature of from
-25.degree. C. to -100.degree. C., further comprising the steps of
exchanging heat between the fluid having a temperature of from
-25.degree. C. to -100.degree. C. and a scrubbing solvent in which
sulfur dioxide, carbon dioxide, or both may be dissolved to chill
the scrubbing solvent to a temperature of from -100.degree. C. to
0.degree. C. and to raise the temperature of the fluid to at least
0.degree. C. without converting the fluid to a gas; and contacting
the flue gas stream from which water has been separated with the
chilled scrubbing solvent to separate sulfur dioxide, carbon
dioxide, or both from the flue gas stream into the scrubbing
solvent.
21. The method of claim 20 further comprising the steps of heating
the chilled scrubbing solvent to a temperature at which sulfur
dioxide, carbon dioxide, or both separate from the scrubbing
solvent and separating sulfur dioxide, carbon dioxide, or both from
the scrubbing solvent.
22. The method of claim 21 further comprising the step of
exchanging heat between the scrubbing solvent from which sulfur
dioxide, carbon dioxide, or both have been separated and the fluid
having a temperature of from -25.degree. C. to -100.degree. C. to
chill the scrubbing solvent to a temperature of from -100.degree.
C. to 0.degree. C. and to heat the fluid to a temperature of at
least 0.degree. C. without converting the fluid to a gas.
23. The method of claim 12 wherein the expanded combusted gas
stream contains at least 5 vol. %, or at least 10 vol. % molecular
oxygen, further comprising the steps of combusting a
sulfur-containing fuel and the expanded combusted gas stream to
generate a second combusted gas stream containing thermal power and
generating electrical power from the thermal power of the second
combusted gas stream.
24. The method of claim 23 further comprising the step of providing
the sulfur-containing fuel for combustion in an amount effective to
consume at least 99 mol % of the molecular oxygen in the expanded
combusted gas stream.
25. The method of claim 23 wherein a portion of the fuel stream is
provided as the sulfur-containing fuel.
26. The method of claim 23 wherein electrical power is generated by
exchanging sufficient heat between the second combusted gas stream
and a liquid aqueous stream to convert the liquid aqueous stream to
steam and to cool the second combusted gas stream, where the cooled
second combusted gas stream is a flue gas stream comprising sulfur
dioxide; expanding the steam through an expander to generate
mechanical power and an expanded steam stream; and converting the
mechanical power to electrical power.
27. The method of claim 26, further comprising the steps of
exchanging heat between the expanded steam stream and a fluid
having a boiling point at least 50.degree. C. lower than the liquid
of the liquid aqueous stream at 0.101 MPa and having a latent heat
of vaporization of at least 350 kJ/kg to condense water from the
expanded steam stream and to form a heat transfer gas from the
fluid, where the heat transfer gas contains thermal power
transferred from the expanded steam stream by heat exchange with
the fluid; expanding the heat transfer gas through an expander to
generate mechanical power and to form the fluid; and generating
electrical power from the mechanical power generated by expanding
the heat transfer gas.
28. The method of claim 27 wherein the fluid is selected from the
group consisting of anhydrous ammonia, aqueous ammonia, anhydrous
sulfur dioxide, carbon dioxide, and diethyl ether.
29. The method of claim 27 wherein a portion of the thermal power
transferred from the expanded steam stream to the fluid is derived
from the latent heat of condensation of water in the expanded steam
stream.
30. The method of claim 27 wherein the water condensed from the
expanded steam stream has a temperature of at most 85.degree. C.
and is provided as the liquid aqueous stream to cool the second
combusted gas stream.
31. The method of claim 26, wherein the flue gas stream further
comprises steam and has a temperature of from greater than
100.degree. C. to 150.degree. C., further comprising the steps of
exchanging heat between the flue gas stream and a fluid having a
boiling point at least 50.degree. C. lower than the liquid of the
liquid aqueous stream at 0.101 MPa and having a latent heat of
vaporization of at least 350 kJ/kg to cool the flue gas stream to a
temperature of from greater than 0.degree. C. to 50.degree. C. and
condense and separate water therefrom and to form a heat transfer
gas from the fluid, where the heat transfer gas contains thermal
power transferred from the flue gas stream to the fluid by heat
exchange with the fluid; expanding the heat transfer gas through an
expander to generate mechanical power and to form the fluid; and
generating electrical power from the mechanical power generated by
expanding the heat transfer gas.
32. The method of claim 31 wherein the fluid is selected from the
group consisting of anhydrous ammonia, aqueous ammonia, anhydrous
sulfur dioxide, carbon dioxide, and diethyl ether.
33. The method of claim 31, wherein the fluid formed by expanding
the heat transfer gas through an expander has a temperature of from
-25.degree. C. to -100.degree. C., further comprising the steps of
exchanging heat between the fluid having a temperature of from
-25.degree. C. to -100.degree. C. and a scrubbing solvent in which
sulfur dioxide, carbon dioxide, or both may be dissolved to chill
the scrubbing solvent to a temperature of from -100.degree. C. to
0.degree. C. and to raise the temperature of the fluid to at least
0.degree. C. without converting the fluid to a gas; and contacting
the flue gas stream from which water has been separated with the
chilled scrubbing solvent to separate sulfur dioxide, carbon
dioxide, or both from the flue gas stream into the scrubbing
solvent.
34. The method of claim 33 further comprising the steps of heating
the chilled scrubbing solvent to a temperature at which sulfur
dioxide, carbon dioxide, or both separate from the scrubbing
solvent, and, separating sulfur dioxide, carbon dioxide, or both
from the scrubbing solvent.
35. The method of claim 34 further comprising the step of
exchanging heat between the scrubbing solvent from which sulfur
dioxide or carbon dioxide has been separated and the fluid having a
temperature of from -25.degree. C. to -100.degree. C. to chill the
scrubbing solvent to a temperature of -100.degree. C. to 0.degree.
C. and to heat the fluid to a temperature of at least 0.degree. C.
without converting the fluid to a gas.
Description
[0001] The present application claims the benefit of U.S. Patent
Application No. 61/559,846, filed Nov. 15, 2011, the entire
disclosure of which is hereby incorporated by reference.
FIELD OF THE INVENTION
[0002] The present invention relates to methods of generating
power. In particular, the present invention is directed to a method
of producing power from a hydrogen sulfide-rich fuel stream.
BACKGROUND OF THE INVENTION
[0003] Natural gas is recovered from natural gas reservoirs and is
combusted to produce electrical energy, typically after being
transported via pipeline to an energy producing facility. The
composition of the gas stream recovered from the reservoir impacts
the economic viability of recovering and producing electrical power
from the gas stream. Gas streams recovered from different
reservoirs may have significantly different compositions. For
example, sweet, non-acid gas contains large quantities methane,
typically greater than 90 mole %, and may contain small quantities
of hydrogen sulfide and carbon dioxide. Sweet, non-acid gas streams
are the most preferred gas streams for production of electrical
power, requiring little processing for conditioning and
pipelining.
[0004] Acid gas contains significant quantities of carbon dioxide,
for example, greater than 5 mole % CO.sub.2 and is less desirable
than sweet non-acid gas since energy must be expended to remove
CO.sub.2 from the gas stream prior to pipelining to avoid corroding
the pipeline. The energy is frequently provided by burning a
portion of the methane from which the CO.sub.2 is separated,
reducing the amount of natural gas that is supplied to the
pipeline. Significant quantities of CO.sub.2 in the gas stream also
reduce the overall energy value of the gas stream relative to a
sweet non-acid gas since CO.sub.2 has no thermal energy value.
[0005] Sour gas contains significant quantities of hydrogen
sulfide, at least 5 mole %, or at least 10 mole %, often at least
30 mole %, and sometimes greater than 50, 75, or even 90 mole %
H.sub.2S. Moderate quantities of hydrogen sulfide in a gas stream
render the gas stream less desirable for recovery and production of
natural gas since the hydrogen sulfide must be removed from the
reservoir gas stream. This requires a portion of the energy of the
gas stream to effect the separation, reducing the overall energy
that may be captured from the gas stream. Large quantities of
hydrogen sulfide in a gas stream, e.g. at least 30 mole % H.sub.2S,
preclude the development and recovery of the gas stream reservoir
since the energy required to separate the H.sub.2S from the natural
gas becomes too great for the reservoir to be developed
commercially.
[0006] Prior to about 1970, hydrogen sulfide from gas streams
containing small to moderate amounts of hydrogen sulfide was flared
to allow recovery of natural gas and associated hydrocarbon
liquids. Flaring the hydrogen sulfide resulted in the emission of
sulfur dioxide to the atmosphere, which is now limited by
restrictions on sulfur emissions. The Claus process was introduced
as a means to separate and capture H.sub.2S as elemental sulfur
from hydrogen sulfide containing natural gas streams, while
capturing some of the heat energy value of the H.sub.2S for use in
the separation process. The Claus process burns 1/3 of the H.sub.2S
substoichiometrically with air and reacts the resulting sulfur
dioxide with the remaining H.sub.2S over a catalyst to recover
elemental sulfur. The thermal energy produced by burning a portion
of the hydrogen sulfide is generally used to separate the hydrogen
sulfide from the gas stream.
[0007] The Claus process, however, is effective commercially only
for gas streams containing moderate amounts of hydrogen sulfide,
for example, up to 30 mole % H.sub.2S. As shown in the chart in
FIG. 1 for a natural gas field containing 35 mole % H.sub.2S and
minor amounts of carbon dioxide and nitrogen along with natural gas
liquids and methane, less than 50% of the energy of the natural gas
in the gas stream is available after energy losses associated with
separating H.sub.2S, CO.sub.2, and natural gas liquids even
including the energy provided by the Claus process. This leaves
only half of the stream available as marketable gas to pay for
field development, a complex processing operation, and delivery
infrastructure--a cost that is frequently too high to justify
developing and producing the sour natural gas field. Producing
natural gas from sour gas reservoirs containing even higher levels
of hydrogen sulfide is even less commercially desirable, and, at
concentrations of about 65-70 mole % hydrogen sulfide and above,
cannot be done without utilizing more energy to produce the natural
gas than is present in the natural gas produced.
[0008] What is needed is a process to capture the energy of a gas
stream containing a large quantity of hydrogen sulfide, e.g., gas
streams containing at least 30 mole % hydrogen sulfide.
SUMMARY OF THE INVENTION
[0009] In one aspect, the present invention is directed to a method
for producing electrical power in which at least 90 vol. % of a gas
stream containing at least 30 mole % hydrogen sulfide is combusted
to generate thermal power contained in a combustion gas stream. The
combustion gas stream comprises sulfur dioxide. Electrical power is
generated from the thermal power of the combustion gas stream.
[0010] In another aspect, the present invention is directed to
method for producing electrical power in which a gas stream
containing at least 30 mole % hydrogen sulfide is separated from a
subterranean geological formation and is combusted to generate
thermal power contained in a combustion gas stream comprised of
sulfur dioxide. Electrical power is generated from the thermal
power of the combustion gas stream.
[0011] In an embodiment, sulfur dioxide is captured from the
combustion gas stream and is injected into a geological
subterranean formation.
BRIEF DESCRIPTION OF THE DRAWINGS
[0012] FIG. 1 is a chart showing the energy capture efficiency of a
process utilizing a prior art Claus process to capture sulfur from
a gas stream containing 35 vol. % hydrogen sulfide.
[0013] FIG. 2 is a schematic of a system for practicing the process
of the present invention for treating a feed gas stream high in
hydrogen sulfide to produce electrical power.
[0014] FIG. 3 is a schematic of a system for practicing the process
of the present invention for treating a feed gas stream high in
hydrogen sulfide to produce electrical power, where the system
includes a gas turbine and a heat recovery steam generator.
[0015] FIG. 4 is a schematic of a system for practicing the process
of the present invention for treating a feed gas stream high in
hydrogen sulfide to produce electrical power, where the system
includes a gas turbine, a supplemental firing unit, and a heat
recovery steam generator.
[0016] FIG. 5 is a schematic of a system for practicing the process
of the present invention for treating a feed gas stream high in
hydrogen sulfide to produce electrical power, where the system
includes a binary power cycle.
DETAILED DESCRIPTION OF THE INVENTION
[0017] The present invention describes methods for utilization of
one or more feed streams containing high levels of hydrogen sulfide
to produce electrical power. Electrical power is produced from such
feed streams in the process of the present invention by combusting
a fuel stream comprised of one or more of the feed streams--the
fuel stream being comprised of at least 30 mol. % hydrogen
sulfide--to produce thermal power, and subsequently generating
electrical power from the thermal power produced by combusting the
fuel stream.
[0018] Feed streams containing high levels of hydrogen sulfide are
available from subsurface geological formations such as sour
gas-rich reservoirs, and a fuel stream for use in the process of
the present invention may be formed from one or more feed streams
separated from a subsurface geological formation. The invention
described herein allows for the processing of fuel streams
previously deemed not suitable for commercial development. Such
fuel streams contain at least about 30 mole %, or at least 35 mole
%, or at least about 40 mole %, or at least about 50 mole %, or at
least about 90 mole % hydrogen sulfide.
[0019] The fuel stream utilized in the process of the present
invention may contain non-H.sub.2S components. The fuel stream may
contain substantial amounts of methane, other hydrocarbonaceous
gases, and/or hydrocarbon liquids, and may contain up to 70 mole %,
or up to 50 mole %, or up to 30 mole % hydrocarbonaceous gases,
including methane, and hydrocarbon liquids. The fuel stream may
also contain up to 30 mole % carbon dioxide, however, less carbon
dioxide is preferable since carbon dioxide provides no thermal
energy upon combustion of the fuel stream. The fuel stream may also
include minor amounts of entrained hydrocarbon liquids, minor
amounts of inert gases such as nitrogen and helium, and entrained
particulates.
[0020] The fuel stream utilized in the process of the present
invention may be formed from one feed stream from a subsurface
geological formation or more than one feed stream from one or more
subsurface geological formations. If the fuel stream is formed from
more than one feed stream, an individual feed stream may contain
less than 30 mole % hydrogen sulfide, however, the combined feed
streams that form the fuel stream will contain at least 30 mole %
hydrogen sulfide. Similarly, if the fuel stream is formed from more
than one feed stream an individual feed stream may contain more
than 70 mole % hydrocarbonaceous gases and liquids, however, the
combined feed streams the form the fuel stream will contain at most
70 mole % hydrocarbonaceous gases and liquids. In like manner, if
the fuel stream is formed from more than one feed stream an
individual feed stream may contain more than 30 mole % carbon
dioxide, however, the combined feed streams that form the fuel
stream will contain at most 30 mole % carbon dioxide.
[0021] The fuel stream utilized in the process of the present
invention will be formed primarily of gaseous components, but may
contain small amounts of hydrocarbon liquids, non-hydrocarbon
liquids, and particulate solids. The gaseous components of the fuel
stream, at the temperature and pressure at which the fuel stream is
provided to the process of the present invention, may comprise at
least 90 mass %, or at least 95 mass %, or at least 99 mass % of
the total components in the fuel stream. In an embodiment, the fuel
stream may contain entrained hydrocarbon liquids (C.sub.2+), where
the entrained hydrocarbon liquids may comprise up to at most 10
mass %, or up to 5 mass %, or up to 1 mass % of the fuel stream.
Alternatively, entrained hydrocarbon liquids (C.sub.2+) may be
separated from a feed stream prior to utilizing the feed stream as
at least a portion of the fuel stream that is combusted to generate
power. Preferably the fuel stream contains no solid particulates,
and may be filtered to remove substantially all particulates prior
to combustion.
[0022] The feed streams used to form the fuel stream utilized in
the process of the present invention are preferably obtained from a
subsurface geological formation. One or more feed streams used to
form the fuel stream, however, may be provided from a source other
than a subsurface geological formation, for example, from a
processing plant, a reformer, or a refinery.
[0023] If a feed stream used in the process of the present
invention is provided from a subsurface geological formation, the
feed stream may be separated from the subsurface geological
formation in accordance with conventional methods and means for
separating gas streams from subsurface geological formations. For
example, the feed stream may be separated from a subsurface
geological formation in the same manner that natural gas is
conventionally recovered from subsurface geological formations.
Subsurface geological formations from which a feed stream may be
separated include gas reservoirs, condensate reservoirs, and oil
reservoirs.
[0024] Due to the difficulty and danger of pipelining a gas stream
containing at least 30 mole % of hydrogen sulfide over substantial
distances, the process of the present invention is preferably
effected near the subsurface geological formation from which the
feed stream is recovered. In particular, the process of the present
invention is preferably effected without having to pipeline the
feed stream to a processing facility located more than 25 miles, or
more than 50 miles, or more than 100 miles from the location of the
subsurface geological formation from which the feed stream is
recovered.
[0025] In an embodiment of the present invention, the process may
be effected at a location near one or more subsurface geological
formations located near a power grid so that electrical power
produced by the process of the present invention may be easily
exported to a power grid or utilized to provide power to a load. If
located near a power grid, preferably the power grid is located
near a consumer of electrical power to reduce the amount of
shrinkage (energy loss) due to transmission of the power over
distance. If the process is effected at a location remote from an
electrical power grid, electrical power produced by the process may
be transmitted to a power grid utilizing efficient electrical
transmission lines having low line power loss to reduce shrinkage.
For example, electrical power produced by the process of the
present invention may be transmitted from remote location to a
power grid and to power consumers via a 765 kV 6 conductor
transmission line having a line loss of from 0.3 MW to 0.7 MW, or
from 0.4 MW to 0.6 MW, per 100 miles at a 1000 MW load--which is
comparable to losses of transporting a natural gas from a remote
location via pipeline to an electrical power production facility.
Alternatively, if the subsurface geological formation is in a
remote location, electrical power consuming units may be located
near the subsurface geological formation to utilize the electrical
power generated from a feed stream separated from the subsurface
geological formation. For example, computer server farms may be
located near the subsurface geological formation to utilize the
electrical power generated from a feed stream separated from the
formation.
[0026] Referring now to FIG. 2, a feed stream 101 may be recovered
from a subsurface geological formation 103. The feed stream 101 may
be utilized directly as the fuel stream, or alternatively, the feed
stream 101 may be processed to separate at least a portion, and
preferably substantially all, of liquids and/or solids that may be
entrained in the feed stream 101. To separate liquids and/or solids
that may be entrained in the feed stream 101, the feed stream 101
may be passed to a separator 105. The separator 105 may be a simple
closed tank where the force of gravity serves to separate liquids
from the gas. The separator 105 may also include an expander, where
the feed stream is expanded to cool and condense the liquids from
the gas, where the expansion is preferably a limited expansion so
the resulting feed stream retains significant pressure. The
separator may include a filter or a membrane effective to separate
particulate solids, preferably substantially all particulate
solids, from the feed stream 101, preferably while maintaining
significant pressure in the feed stream 101. If the separator 105
includes an expander, the filter or membrane for separating
particulate solids from the feed stream 101 is preferably
positioned in the separator 105 to remove particulate solids from
the feed stream 101 prior to expanding the feed stream 101 through
the expander. Entrained hydrocarbonaceous liquids 107, other
condensable liquids such as water 108, and solids 110 may be
separated from the feed stream 101 in the separator 105 to produce
a feed stream 111 that may be utilized as a portion of the fuel
stream for combustion or as the entire fuel stream for
combustion.
[0027] In an embodiment, further natural gas liquids
(C.sub.2-C.sub.5) may be separated from a feed stream 111 by
absorbing the natural gas liquids from the feed stream 111 in a
lean oil unit 109 after separation of heavier hydrocarbon liquids,
water, and particulate solids from the feed stream 101. The feed
stream 111 may be contacted with an oil in the lean oil unit 109 to
absorb non-methane hydrocarbons which may be recovered from the
lean oil unit 109 as natural gas liquids 115 and to produce a feed
stream 117 from which most or all of the natural gas liquids have
been removed.
[0028] The feed stream 117, or the feed stream 111, or the feed
stream 101 forms at least a portion of, or all of, the fuel stream
119 that is combusted in the process of the present invention. At
least a portion of, or all of, the fuel stream 119 is combusted in
combustor 121 to generate a combusted gas stream containing thermal
power. An oxidant stream 125 is provided to the combustor 121 for
combustive reaction with the fuel stream 119 to produce the
combusted gas stream.
[0029] The oxidant stream 125 is provided in an amount effective to
provide a stoichiometric amount, or a slight stoichiometric excess,
or a substantial stoichiometric excess of molecular oxygen relative
to combustible fuel components in the fuel stream. The oxidant
stream 125 is provided in an amount, or at a rate, sufficient to
provide at least 1.0 mole, or at least 1.5 moles, or at least 2
moles of molecular oxygen per mole of hydrogen sulfide in the fuel
stream. If the fuel stream also comprises methane, the oxidant
stream may be provided in an amount, or at a rate, sufficient to
provide at least 2 moles of molecular oxygen per mole of methane in
addition to the amount of molecular oxygen provided relative to
hydrogen sulfide.
[0030] As used herein, "oxidant" refers to a composition that
contains molecular oxygen that may be combustively reacted with
hydrogen sulfide as a fuel source. Examples of oxidants include
oxygen, oxygen admixed with steam, oxygen admixed with carbon
dioxide, air, and/or enriched air. "Enriched air" refers to air
having an oxygen content greater than about 21 percent by volume.
Enriched air may be used to increase, relative to air, the
combustion temperature of the fuel stream 119 at a constant fuel
input rate and/or to facilitate post combustion processing of the
combustion effluent gases.
[0031] The combustor 121 may comprise a combustion zone and a steam
generator, where the steam generator may be boiler, a superheated
steam boiler, or a supercritical steam generator. The fuel stream
119 and the oxidant stream 125 may be combustively reacted in the
combustion zone to produce the combusted gas stream. Steam may be
produced by exchanging heat between the combusted gas stream and a
liquid aqueous stream 122, preferably water, and/or steam at the
steam generator in the combustor 121.
[0032] The fuel stream 119, or the portion of the fuel stream 119
that is to be combusted, and the oxidant stream 125 are provided to
the combustor 121, and are mixed and combustively reacted in the
combustion zone of the combustor 121. Combustion of the fuel stream
119 generates a significant amount of thermal energy that is
contained in the combusted gas stream produced by the combustion of
the fuel stream. The thermal energy contained in the combusted gas
stream may be transferred to the liquid aqueous stream/steam in the
steam generator portion of the combustor 121. Preferably the
thermal energy is transferred from the combusted gas stream to the
liquid aqueous stream/steam by indirectly contacting the combusted
gas stream with the liquid aqueous stream/steam, for example by
passing the combusted gas stream through a coil surrounded by the
liquid aqueous stream and/or steam or by passing the combusted gas
stream over a coil containing the liquid aqueous stream and/or
steam. Sufficient thermal energy may be transferred from the
combusted gas stream to the liquid aqueous stream and/or steam to
generate superheated or supercritical steam and a cooled combusted
gas stream 127. The cooled combusted gas stream 127 is a flue gas
stream that comprises sulfur dioxide and water.
[0033] In an embodiment, the combustor 121 is a pressurized steam
generator, and the fuel stream 119 and oxidant stream 125 are
provided to the pressurized steam generator at relatively high
pressure, e.g., at least 1.7 MPa, or at least 3.4 MPa, or at least
6.9 MPa. The fuel stream and the oxidant stream should be provided
to the pressurized steam generator at substantially similar
pressures to prevent an overpressurized stream blowing an
underpressurized stream back out of the pressurized boiler or steam
generator. The one or more feed streams that comprise the fuel
stream 119 may be at a pressure of at least 1.7 MPa when separated
from the geological subterranean formation and often may be at a
high pressure of at least 6.9 MPa or at least 10 MPa, or at least
13.8 MPa, or at least 15 MPa, or at least 20 MPa when separated
from the geological subterranean formation. One or more of the feed
streams may be passed through an expander in the separator 105 to
reduce the pressure of the feed stream 101 comprising the fuel
stream 119. If the fuel stream 119 has a very high pressure
relative to the oxidant stream 125, the fuel stream may be expanded
in one or more expanders 124 to reduce the pressure of the fuel
stream to be substantially the same as the pressure of the oxidant
stream. In an embodiment of the process of the invention the fuel
stream 119 may be at a pressure of from 1.7 MPa to 13.8 MPa when
provided to the combustor 121 after any expansion of one or more
feed streams in the separator 105 and/or expansion of the fuel
stream in one or more expanders 124. One or more of the expanders
124 and/or an expander in separator 105 may be utilized to generate
mechanical rotational power upon expansion of the fuel stream 119
through the expander(s) which may be used to generate electrical
power.
[0034] The oxidant stream 125 may be compressed using a
conventional compressor 126 to compress the oxidant stream to a
pressure of from 1.7 MPa to 13.8 MPa prior to being provided to the
combustor 121 comprising a pressurized steam generator, and
preferably is compressed to about the pressure of the fuel stream
119 entering the pressurized boiler or steam generator. Power to
operate the oxidant compressor 126 may be provided to the
compressor 126 by a shaft 128 coupled to an expander 124 through
which the fuel stream 119 is expanded. It is preferred to
substantially compress the oxidant stream to maximize the power
produced relative to the size of the combustor 121.
[0035] Combustion in a combustor 121 comprising a pressurized steam
generator may be further preferred when the fuel stream contains
substantial quantities of methane and/or carbon dioxide so that
carbon dioxide present in the cooled combusted gas stream 127 may
be more easily separated from the cooled combusted gas stream.
Carbon dioxide contained in the cooled high pressure combusted gas
stream 127 may be easily separated from the cooled combusted gas
stream, for example, by pressure swing absorption, due to the high
pressure of the cooled combusted gas stream.
[0036] In the steam generator, whether pressurized or not, a
substantial portion, preferably substantially all, of the thermal
power generated by combustion of the fuel stream 119 and produced
in the combusted gas stream may be captured in superheated steam,
e.g., at least 80%, or at least 85%, or at least 90%, up to 95%, or
up to 97% of the thermal power generated by combustion of the fuel
stream may be captured in steam. A substantial portion, preferably
substantially all, of the thermal power in the combusted gas stream
may be captured as steam having a selected temperature and/or
pressure profile. A substantial portion, preferably substantially
all, of the thermal power in the combusted gas stream may be used
to generate steam at pressures ranging from 0.34 MPa to 34.5 MPa,
or from 13.8 MPa to 34.5 MPa, or from 22.2 MPa to 34.5 MPa, or from
30 MPa to 34.5 MPa; and temperatures ranging from 240.degree. C. to
650.degree. C., or from 335.degree. C. to 650.degree. C., or from
375.degree. C. to 650.degree. C. Preferably the steam generated by
capturing the thermal power from the combusted gas stream is
supercritical steam (temperature of at least 374.degree. C. and a
pressure of at least 22.15 MPa) or ultrasupercritical steam
(temperature of at least 374.degree. C. and a pressure of at least
30 MPa).
[0037] Electrical power 131 may be generated from the thermal power
captured in the steam generated in the combustor 121. The steam 123
generated in the combustor 121 may be passed through one or more
steam expanders 129 to expand the steam 123 and form an expanded
steam stream 133 and to generate mechanical rotational power by
turning a shaft. The mechanical rotational power may be converted
to electrical power utilizing conventional electrical power
generation equipment and processes for converting mechanical power
to electrical power. Expansion of the steam 123 through the one or
more expanders may generate substantial electrical power, where the
electrical power generated may be at least 100 MW.sub.e, or at
least 200 MW.sub.e, or at least 300 MW.sub.e, or at least 400
MW.sub.e. The one or more steam expanders 129 are preferably steam
turbines.
[0038] The steam 123 is cooled by Joule-Thompson cooling as it
passes through the one or more steam expanders 129, converting the
thermal power contained in the steam 123 into mechanical power,
which is then converted to electrical power. The cooled expanded
steam stream 133 may have a temperature of from 100.degree. C. to
150.degree. C., or from 110.degree. C. to 130.degree. C., and may
have a pressure corresponding to the vapor pressure of water at the
temperature of the steam, e.g. from 0.101 MPa to 0.5 MPa.
[0039] The expanded steam stream 133 may be cooled further to
liquefy the steam into the liquid aqueous stream 122 that may be
recycled into the combustor 121. The expanded steam stream 133 may
be cooled by passing the expanded steam stream into a cooling tower
135, where the steam is condensed to the liquid aqueous stream
having a temperature that is low enough so that the liquid aqueous
stream 122 may be pumped back into the combustor 121 through pump
137 without causing cavitation in the pump, preferably at most
95.degree. C., or at most 90.degree. C., or at most 85.degree. C.,
and typically from 75-85.degree. C. at a pressure of 0.101 MPa, or
at a temperature of up to 150.degree. C. at a pressure of up to 0.5
MPa. Alternatively, and more preferably, the expanded steam stream
133 is cooled using a heat exchanger 135 where heat is exchanged
between the expanded steam stream 133 and a fluid 138 having a
boiling point at least 50.degree. C. cooler than the boiling point
of the liquid of the liquid aqueous stream 122 at 0.101 MPa and
having a latent heat of evaporation of at least 350 kJ/kg to
condense water from the expanded steam stream 133 and capture the
latent heat of condensation of water of the liquid aqueous stream
as thermal power, as described in further detail below. The liquid
aqueous stream 122 produced by cooling the expanded steam stream
133 may then be recycled back to the combustor 121 by pumping the
liquid aqueous stream 122 into the combustor 121 with a boiler
water pump 137.
[0040] In another embodiment, shown in FIG. 3, the combustor 121
may be comprised of a gas turbine 139 and a steam generator 141.
The fuel stream 119 and the oxidant stream 125 may be combustively
reacted in the gas turbine 139 to produce a combusted gas stream
containing thermal power. In an embodiment, the oxidant stream 125
and the fuel stream 119 may be provided for combustion in the gas
turbine in relative amounts, or at relative rates, such that the
molar ratio of molecular oxygen and hydrogen sulfide provided for
combustion is at least 2:1. Providing the oxidant stream and the
fuel stream for combustion at a molar ratio of at least 2:1
molecular oxygen:hydrogen sulfide may limit the temperature of the
resulting combusted gas stream relative to combustion of the
streams at substantially stoichiometric amounts of molecular oxygen
and hydrogen sulfide, where limiting the temperature of the
combusted gas stream may be desirable to avoid damaging the gas
turbine or to avoid the necessity of utilizing a gas turbine
constructed with specialized high heat resistant metallurgy. The
fuel stream 119 and the oxidant stream 125 may be provided to the
gas turbine 139, respectively, at a pressure of from 1 MPa to 5
MPa, where preferably the pressures at which the fuel stream 119
and the oxidant stream 122 are provided to the gas turbine are
within 0.5 MPa of each other.
[0041] At least a portion of the thermal power contained in the
combusted gas stream may be utilized to generate electrical power
by expanding the combusted gas stream in the gas turbine 139 to
generate rotational mechanical power that may be converted to
electrical power 144. Expansion of the combusted gas stream in the
gas turbine 139 may generate mechanical rotational power by turning
a shaft. The mechanical rotational power may be converted to
electrical power 144 utilizing conventional electrical power
generation equipment and processes for converting rotational
mechanical shaft power to electrical power.
[0042] The expanded combusted gas stream 145 is cooler than the
combusted gas stream due to the Joule-Thompson effect, however, the
expanded combusted gas stream may still contain a significant
amount of thermal power. In an embodiment of the process of the
present invention, the expanded combusted gas stream has a
temperature above the autoignition temperature of hydrogen
sulfide--at least 260.degree. C.--and more preferably has a
temperature of at least 300.degree. C., or at least 400.degree. C.,
or at least 500.degree. C., or at least 600.degree. C., and
typically has a temperature of from 500.degree. C. to 650.degree.
C.
[0043] The expanded combusted gas stream 145 may be passed to a
steam generator 141 to generate a steam stream 123 from the thermal
power contained in the expanded combusted gas stream 145 and to
generate a flue gas stream containing sulfur dioxide and water
formed of the cooled expanded combusted gas stream. The steam
stream 123 may be produced by indirectly exchanging heat between
the expanded combusted gas stream 145 and a liquid aqueous stream
122, preferably water, and/or steam in the steam generator 141. A
substantial portion, preferably substantially all, of the thermal
power in the expanded combusted gas stream 145 may be captured in
superheated steam, e.g., at least 80%, or at least 85%, or at least
90%, up to 95%, or up to 97% of the thermal power in the expanded
combusted gas stream 145 may be captured in superheated steam. A
substantial portion, preferably substantially all, of the thermal
power in the expanded combusted gas stream 145 may be captured as
steam having a selected temperature and/or pressure profile. A
substantial portion, preferably substantially all, of the thermal
power in the expanded combusted gas stream 145 may be used to
generate steam at pressures ranging from 0.34 MPa to 34.5 MPa, or
from 13.8 MPa to 34.5 MPa, or from 22.2 MPa to 34.5 MPa, or from 30
MPa to 34.5 MPa; and temperatures ranging from 240.degree. C. to
650.degree. C., or from 335.degree. C. to 650.degree. C., or from
375.degree. C. to 650.degree. C. Preferably the steam generated by
capturing the thermal power from the expanded combustion gas stream
145 is supercritical steam (temperature of at least 374.degree. C.
and a pressure of at least 22.15 MPa) or ultrasupercritical steam
(temperature of at least 374.degree. C. and a pressure of at least
30 MPa).
[0044] Electrical power 131 may be generated from the steam
produced in the steam generator 141 as described above with respect
to generating power from steam produced in combustor 121--the steam
123 may be passed through one or more steam expanders 129 to
generate rotational mechanical power that may be converted to
electrical power 131. The resulting expanded steam stream 133 may
be cooled in heat exchanger 135 by heat transfer with fluid 138 to
condense water and produce the liquid aqueous stream 122, as
described above, where the fluid 138 has a boiling point at least
50.degree. C. lower than the boiling point of the liquid aqueous
stream 122 at 0.101 MPa and has a latent heat of evaporation of at
least 350 kJ/kg, as described in further detail below. The
resulting liquid aqueous stream 122 may be recycled back into the
stream generator 141 via pump 137. Expansion of the steam 123
through the one or more steam expanders 129 may generate
substantial electrical power, where the electrical power generated
may be at least 100 MW.sub.e, or at least 200 MW.sub.e, or at least
300 MW.sub.e, or at least 400 MW.sub.e. The one or more steam
expanders 129 are preferably steam turbines.
[0045] In another embodiment, as shown in FIG. 4, the combustor 121
may be comprised of a gas turbine 139, a supplemental firing unit
147, and a steam generator 141. The fuel stream 119, or a portion
thereof 143, and the oxidant stream 125 may be combustively reacted
in the gas turbine 139 to produce a combusted gas stream containing
thermal power as described above. Further, the combusted gas stream
may be expanded in the gas turbine 139 to generate rotational
mechanical power that may be converted to electrical power 144 and
an expanded combusted gas stream 145, as described above.
[0046] The oxidant stream 125 and the fuel stream 119, or portion
thereof 143, may be provided for combustion in the gas turbine 139
in relative amounts, or at relative rates, such that the molar
ratio of molecular oxygen to hydrogen sulfide that are provided for
combustion is at least 2:1. The resulting expanded combusted gas
stream 145 exiting the gas turbine 139 will contain at least 5 vol.
% or at least 10 vol % molecular oxygen, and may contain from 5 vol
% to 20 vol % molecular oxygen, and typically may contain from 8
vol % to 12 vol % molecular oxygen. The relatively large volume of
oxidant stream needed to provide molecular oxygen in a molar ratio
of at least 2:1 relative to hydrogen sulfide in the fuel stream
inhibits excessive heating within the gas turbine 139 and ensures
that sufficient molecular oxygen is contained in the expanded
combusted gas stream 145 for further combustive reaction in the
supplemental firing unit 147 without requiring the addition of
further oxidant.
[0047] The expanded combusted gas stream 145 and a supplemental
fuel stream 149, preferably a sulfur-containing fuel and most
preferably a portion of the fuel stream 119, may be combustively
reacted in the supplemental firing unit 147 to produce a second
combusted gas stream 151 containing thermal power. The second
combusted gas stream 151 may have a temperature of from 600.degree.
C. to 1000.degree. C.
[0048] The supplemental fuel stream 149 may be any fuel that may be
combusted with the expanded combusted gas stream 145, where the
expanded combusted gas stream 145 contains at least 5 vol. %
molecular oxygen. The supplemental fuel stream 149 may be natural
gas or coal. Preferably, the supplemental fuel stream 149 is a
sulfur-containing fuel. Sulfur-containing fuels include hydrogen
sulfide and high-sulfur content coal. Most preferably, the
supplemental fuel stream 149 comprises or consists of a portion of
the fuel stream 119.
[0049] The supplemental fuel stream 149 is preferably provided to
the supplemental firing unit 147 in an amount sufficient to consume
all, or substantially all, the molecular oxygen in the expanded
combusted gas stream 145 to prevent the formation of oleum. The
supplemental fuel stream 149 may be provided in an amount effective
to consume at least 99% of the molecular oxygen in the expanded
combusted gas stream 145.
[0050] The second combusted gas stream 151 may be passed to a steam
generator 141 to generate a steam stream 123 from the thermal power
contained in the second combusted gas stream 151 and to generate a
flue gas stream containing sulfur dioxide and water formed of the
cooled second combusted gas stream. Steam may be produced by
exchanging heat between the second combusted gas stream 151 and a
liquid aqueous stream 122, preferably water, and/or steam in the
steam generator 141. A substantial portion, preferably
substantially all, of the thermal power in the second combusted gas
stream 151 may be captured in superheated steam, e.g., at least
80%, or at least 85%, or at least 90%, up to 95%, or up to 97% of
the thermal power in the second combusted gas stream 151 may be
captured in superheated steam. A substantial portion, preferably
substantially all, of the thermal power in the second combusted gas
stream 151 may be captured as steam having a selected temperature
and/or pressure profile. A substantial portion, preferably
substantially all, of the thermal power in the second combusted gas
stream 151 may be used to generate steam at pressures ranging from
0.34 MPa to 34.5 MPa, or from 13.8 MPa to 34.5 MPa, or from 22.2
MPa to 34.5 MPa, or from 30 MPa to 34.5 MPa; and temperatures
ranging from 240.degree. C. to 650.degree. C., or from 335.degree.
C. to 650.degree. C., or from 375.degree. C. to 650.degree. C.
Preferably the steam generated by capturing the thermal power from
the second combusted gas stream 151 is supercritical steam
(temperature of at least 374.degree. C. and a pressure of at least
22.15 MPa) or ultrasupercritical steam (temperature of at least
374.degree. C. and a pressure of at least 30 MPa).
[0051] In an embodiment of the invention, the supplemental firing
unit 147 and the steam generator 141 may form a single unit. In the
combined supplemental firing unit and steam generator, heat may be
exchanged between the second combusted gas stream and the liquid
aqueous stream 122 and/or steam as the second combusted gas stream
is formed immediately upon combustion of the expanded combusted gas
stream 145 and the supplemental fuel stream 149. The temperature of
the second combusted gas stream may be maintained at a selected
temperature, preferably below 800.degree. C., by the immediate
exchange of heat between the second combusted gas stream and the
liquid aqueous stream and/or steam.
[0052] Electrical power 131 may be generated from the steam
produced in the steam generator 141 as described above with respect
to generating power from steam produced in combustor 121--the steam
123 may be passed through one or more steam expanders 129 to
generate rotational mechanical power that may be converted to
electrical power 131. The resulting expanded steam stream 133 may
be cooled by heat transfer with fluid 138 to condense water and
produce the liquid aqueous stream 122, as described above, where
the fluid 138 has a boiling point at least 50.degree. C. lower than
the boiling point of the liquid aqueous stream 122 at 0.101 MPa and
has a latent heat of evaporation of at least 350 kJ/kg, as
described in further detail below. The resulting liquid aqueous
stream 122 may be recycled back into the steam generator 141 via
pump 137. Expansion of the steam 123 through the one or more steam
expanders 129 may generate substantial electrical power, where the
electrical power generated may be at least 100 MW.sub.e, or at
least 200 MW.sub.e, or at least 300 MW.sub.e, or at least 400
MW.sub.e. The one or more steam expanders 129 are preferably steam
turbines.
[0053] Referring now to FIG. 5, additional electrical power may be
generated by capturing the latent heat of condensation of water by
condensing water from the expanded steam stream 133. Fuel stream
119 and oxidant stream 125 are combusted in combustor 121, and
steam stream 123 is generated by exchanging heat between a liquid
aqueous stream 122 and a combusted gas produced by the combustion,
as described in the various embodiments of combustion and heat
exchange described above. Electrical power 131 is generated by
expanding the steam stream 123 through the steam expander 129 to
produce the expanded steam stream 133, where the steam stream 123
may have a temperature of from 600.degree. C. to 1000.degree. C.,
and the expanded steam stream 133 may have a temperature of from
greater than 100.degree. C. to 150.degree. C., typically from
120.degree. C. to 135.degree. C.
[0054] The expanded steam stream 133 may be cooled to condense
water therefrom and produce the liquid aqueous stream 122 by
exchanging heat with a portion of a fluid 138 in heat exchanger
135, producing a heat transfer gas 153 from the fluid 138. The
fluid 138 may have a boiling point at 0.101 MPa that is at least
40.degree. C., or at least 50.degree. C., lower than the boiling
point of the liquid aqueous stream 122, which may be water, and has
a latent heat of evaporation of at least 350 kJ/kg, preferably at
least 500 kJ/kg, and most preferably at least 1000 kJ/kg.
Preferably the fluid 138 has a boiling point at 0.101 MPa that is
from -50.degree. C. to 65.degree. C., or from 0.degree. C. to
50.degree. C. The fluid 138 may be selected from the group
consisting of anhydrous ammonia, anhydrous carbon dioxide, carbon
disulfide, sulfur dioxide, diethyl ether, dimethyl ether, methylene
chloride, methanol, and acetone. In an embodiment, the liquid is
inorganic.
[0055] The heat exchanger 135 may provide means for the expanded
steam stream 133 and the fluid 138 to exchange heat indirectly, for
example by conduction. The heat exchanger 135 may comprise a coil
through which the fluid 138 may pass and over which the expanded
steam stream 133 may flow to transfer thermal power from the steam
stream 133 to the fluid 138 to convert the liquid to a heat
transfer gas 153. Water from the expanded stream stream 133 may
condense on the coil in the heat exchanger 135, permitting the
transfer of thermal power of the latent heat of condensation of
water from the expanded steam stream 133 to the liquid/heat
transfer gas in the coil.
[0056] Preferably, the fluid 138 is provided to the heat exchanger
135 at a rate and a temperature relative to the rate and
temperature of the expanded steam stream 133 effective to induce
condensation of water from the expanded steam stream 133 and to
convert the expanded steam stream 133 to the liquid aqueous stream
122 having a temperature of at most 95.degree., or at most
90.degree. C., or at most 85.degree. C., and preferably from
70.degree. C. to 85.degree. C. so that the liquid aqueous stream
122 may be pumped without significant cavitation through the pump
137. The fluid 138 may be provided to the heat exchanger at a
temperature of at least 0.degree. C., and from 0.degree. C. to
50.degree. C., or from 0.degree. C. to 25.degree. C., and
preferably from 0.degree. C. to 15.degree. C.
[0057] The fluid 138 should also be provided to the heat exchanger
135 at a rate and a temperature relative to the rate and
temperature of the expanded steam stream 133 effective to permit
the heat exchange between the fluid 138 and the expanded steam
stream 133 to vaporize the fluid 138 and produce a heat transfer
gas 153. The resulting heat transfer gas 153 may have a temperature
of from 20.degree. C. up to 120.degree. C., typically from
50.degree. C. to 70.degree. C.
[0058] A significant portion of the thermal power transferred from
the expanded steam stream 133 to the fluid 138 in the process of
converting the expanded steam stream 133 to the liquid aqueous
stream 122 is derived from the latent heat of condensation of water
in the expanded steam stream 133 as water is condensed from the
expanded steam stream. In an embodiment of a process of the present
invention, at least 20%, or at least 30%, or at least 40% of the
total electrical power produced by the process is derived from
thermal power produced by the latent heat of condensation of water
from the expanded steam stream 133 and transferred to the fluid 138
or the heat transfer gas 153.
[0059] The fluid 138 may also be utilized to capture thermal power
from the flue gas stream 127 exiting the combustor 121. The flue
gas stream 127, typically comprising sulfur dioxide, water,
nitrogen and smaller quantities of carbon dioxide and argon, may
exit the combustor 121 at a temperature of from greater than
100.degree. C. to 200.degree. C., typically from 115.degree. C. to
150.degree. C., where the flue gas stream is formed of the
combusted gas stream, the expanded combusted gas stream, or the
second combusted gas stream cooled by heat exchange with the liquid
aqueous stream 122 in the steam generator. The fluid 138, having a
boiling point at least 50.degree. C. lower than the boiling point
of the liquid aqueous stream 122 and having a latent heat of
evaporation of at least 350 kJ/kg, may be indirectly contacted with
the flue gas stream 127 in an evaporator 155 to transfer thermal
power from the flue gas stream 127 to the fluid 138--cooling the
flue gas stream 127 and converting the fluid 138 to a heat transfer
gas 157. The fluid 138 may be provided to the evaporator 155 for
heat transfer duty at a temperature of from greater than 0.degree.
C. to 50.degree. C., typically from 3.degree. C. to 10.degree. C.
The fluid 138 may be indirectly contacted with the flue gas stream
127 to transfer the thermal energy from the flue gas stream 127 to
the fluid 138/heat transfer gas 157 by passing the flue gas stream
127 through a coil surrounded by the fluid 138 and/or heat transfer
gas 157 or by passing the flue gas stream 127 over a coil
containing the fluid 138 and/or the heat transfer gas 157.
[0060] Sufficient thermal energy may be transferred from the flue
gas stream 127 to the fluid 138 and/or heat transfer gas 157 to
generate a heat transfer gas 157 having a temperature of from
100.degree. C. to 150.degree. C., typically from 110.degree. C. to
130.degree. C., at a pressure of 1 MPa to 15 MPa, or from 2 MPa to
10 MPa. The flue gas stream 127 may be cooled by the heat transfer
to produce a cooled flue gas stream 159 having a temperature of
from greater than 0.degree. C. to 25.degree. C., typically from
3.degree. C. to 10.degree. C.
[0061] The heat transfer gas 157 containing thermal power derived
by heat transfer with the flue gas stream 127 in the evaporator 155
and the heat transfer gas 153 containing thermal power derived by
heat transfer with the expanded steam stream 133 may be combined
and then expanded through an expander 161 to transfer at least a
portion of the thermal power into rotational mechanical power which
may be converted to electrical power 163. The electrical power
produced by expanding the heat transfer gas 157 through the
expander may be at least 50 MW, or at least 100 MW, or at least 150
MW, or at least 200 MW. The amount of electrical power 163 produced
by expanding the combined heat transfer gases 157 and 153 through
the expander 155 may be at least 25%, or 30%, or 35%, or 40%, or
50% of the total electrical power produced by the process of the
present invention. The amount of electrical power 163 produced by
expanding the combined heat transfer gases 157 and 153 through the
expander 161 may be up to 100%, or up to 90%, or up to 80% of the
electrical power produced by expansion of the combusted gas and
expansion of the steam stream. A large portion of the electrical
power 161 produced by expansion of the heat transfer gases 153 and
157 is derived from capture of the latent heat of condensation of
water from the expanded steam stream since the latent heat of
condensation of water provides from 1 MW, to 1.3 MW.sub.t per 1
MW.sub.e produced by expansion of the combusted gas stream and
expansion of the steam stream.
[0062] In an embodiment of the process of the invention, a portion
of the fluid 138 may be indirectly contacted with the steam stream
123 in a heat exchanger 165 to form a supercritical heat transfer
gas 167 from the fluid 138. The steam stream 123 may have a
temperature of from 600.degree. C. to 1000.degree. C., and may
easily heat the fluid 138 to a supercritical state, e.g. if the
liquid is anhydrous ammonia the ammonia heat transfer gas 167 may
be heated to a temperature greater than 130.degree. C. up to
150.degree. C. at a pressure of at least 11.4 MPa. The fluid 138
may be provided for heating with the steam stream 123 in the heat
exchanger 165 in sufficient quantity or at a sufficient rate so
that, upon combination with the heat transfer gas 153 and with the
heat transfer gas 157 the combined heat transfer gases 153, 157,
and 165 are in a supercritical state. Expansion of a supercritical
heat transfer gas in the expander 161 may be desirable to avoid
damage to the expander that might be caused by condensation of the
heat transfer gas as it is expanded through the expander 161.
[0063] In a preferred embodiment, the flue gas stream is scrubbed
to capture sulfur dioxide, water, and any carbon dioxide prior to
venting the effluent gases from the system. As discussed above, the
flue gas stream 127 is indirectly contacted with the fluid 138 in
the evaporator 155 to transfer thermal power from the flue gas
stream 127 to the liquid--forming the heat transfer gas 157 and a
cooled flue gas stream 159. The cooled flue gas stream 159 may have
a temperature of from 0.degree. C. to 50.degree. C., more
preferably the cooled flue gas stream 159 may have a temperature of
from 3.degree. C. to 10.degree. C. An aqueous liquid stream 169
comprising sulfur dioxide and water from the flue gas stream 127
may be separated from the cooled flue gas stream 159 in the
evaporator 155 as a result of the heat transfer to the fluid 138.
The aqueous liquid stream 169 may be drained from the evaporator
155 and fed to a separator 171. The aqueous liquid stream 169 may
be heated in the separator to a temperature of at least 12.degree.
C., or at least 15.degree. C. up to 50.degree. C., preferably up to
25.degree. C. to separate sulfur dioxide gas 173 from liquid water
175.
[0064] The cooled flue gas stream 159 may be introduced into a
scrubber 177 and may be scrubbed with a solvent 179 to separate
sulfur dioxide and carbon dioxide (if any) from the cooled flue gas
stream 159 and into the solvent. The cooled flue gas stream 159 may
be scrubbed with the solvent 179 utilizing conventional liquid/gas
scrubbing equipment. The scrubbed flue gas 181 may contain nitrogen
and argon, and may be vented to the atmosphere.
[0065] The solvent 179 may be any solvent which is effective to
physically or chemically separate sulfur dioxide from a gas stream,
preferably is also effective to physically or chemically separate
carbon dioxide from a gas stream, and preferably has a freezing
point below -80.degree. C. For example, the solvent 177 may be
methanol, a methanol:water mixture, N-methyl-2-pyrrolidine,
propylene carbonate, dimethyl ethers of polyethylene glycol, and
ethanolamines. Preferably the solvent is anhydrous methanol.
[0066] The solvent 179 may be fed to the scrubber 177 at a
temperature and pressure at which the selected solvent is effective
to absorb sulfur dioxide, and preferably carbon dioxide as well,
from the cooled flue gas stream 159. The solvent may be fed to the
scrubber at a temperature of from -100.degree. C. to 0.degree. C.,
and may be mixed with the cooled flue gas stream in the scrubber at
a pressure of from 1.7 MPa to 10.3 MPa. The solvent 179 may be
provided at a temperature within 5.degree. C. of the freezing point
of fluid 138 by exchanging heat with cold fluid 191 produced by
expansion of the heat transfer gas in the expander 161, as
described in further detail below. In preferred embodiment, the
solvent is methanol, and the cooled flue gas stream 159 is scrubbed
with the methanol solvent at a temperature of from -50.degree. C.
to -85.degree. C. and a pressure of from 3.4 MPa to 6.9 MPa.
[0067] The solvent 183 containing sulfur dioxide and carbon dioxide
(if any) scrubbed from the cooled flue gas stream 159 may be fed
from the scrubber 177 to a separator 185 in which sulfur dioxide
and carbon dioxide (if any) may be separated from the solvent and
captured. Sulfur dioxide and carbon dioxide may be separated from
the solvent 183 by heating the solvent to a temperature at which
sulfur dioxide gas and carbon dioxide gas separate from the liquid
solvent and/or by reducing the pressure on the solvent to a
pressure at which sulfur dioxide gas and carbon dioxide gas
dissociate from the liquid solvent. The temperature of the solvent
exiting the scrubber may be from 5.degree. C. to 40.degree. C., or
from 5.degree. C. to 20.degree. C., and the temperature of the
solvent may be raised to a temperature of greater than 40.degree.
C. up to 60.degree. C. to separate sulfur dioxide and carbon
dioxide from the solvent. In a preferred embodiment, the
temperature of the solvent may be raised to a temperature at which
carbon dioxide is separated from the solvent, and then raised to a
second temperature at which sulfur dioxide is separated from the
solvent, wherein the carbon dioxide and the sulfur dioxide
separated from the solvent are captured separately.
[0068] The heated solvent 187 may be cooled for recirculation to
the scrubber 177 by exchanging heat in a heat exchanger 189 with
the cold fluid 191 produced by expansion of the heat transfer gas
153, 157, and 167 through the expander 161. The outlet pressure of
the expander 161 may be selected and controlled to produce the cold
fluid 191 at a temperature near the freezing point of the fluid
138. For example, if the fluid 138 is anhydrous ammonia, the outlet
pressure of the expander 161 may be selected to produce the cold
fluid 191 at a temperature of from -75.degree. C. to -80.degree. C.
The heated solvent 187 may be cooled to the temperature selected to
absorb sulfur dioxide and carbon dioxide from the cooled flue gas
stream 159 by selecting an appropriate feed rate of the solvent
from the separator 185 to the heat exchanger 189, where pump 193
may be utilized to pump the heated solvent 187 to the heat
exchanger 189 at the selected rate.
[0069] The cold fluid 191 is heated by exchanging heat with the
heated solvent 187 in heat exchanger 189 to produce the fluid 138
for use in cooling the flue gas stream 127 in the evaporator 155
and for cooling the expanded steam stream 133 in heat exchanger
135. The rate the supercooled fluid is fed to the heat exchanger
189 may be selected to produce the fluid 138 at a temperature of
from 0.degree. C. to 50.degree. C., or from 0.degree. C. to
25.degree. C., and preferably from 0.degree. C. to 15.degree. C.
The resulting fluid 138 may be pumped to the evaporator 155, heat
exchanger 135, and heat exchanger 165 via pump 197, and the
relative amounts of fluid 138 pumped to each element may be
controlled by metering devices 199 and 201.
[0070] The process of the present invention is effective to produce
substantial electrical power from a fuel stream containing
significant quantities of hydrogen sulfide.
[0071] To facilitate a better understanding of the present
invention, the following examples of certain aspects of some
embodiments are given. In no way should the following examples be
read to limit, or define, the scope of the invention.
Example 1
[0072] Calculations were performed demonstrating that combusting a
fuel stream containing 100 mol % H.sub.2S and an oxidant stream
containing about 3 moles of molecular oxygen per mole of hydrogen
sulfide in the fuel stream in a gas turbine to produce a combusted
gas stream containing thermal energy, and expanding the combusted
gas stream in the gas turbine to produce mechanical power that is
converted to electrical power, is effective to produce electrical
power on a scale comparable to producing electrical power from a
natural gas stream.
[0073] The mass flow rates of a fuel stream formed of 100 vol. %
(100 mol %) hydrogen sulfide and an oxidant stream formed of air,
respectively, required to be provided for combustion and subsequent
expansion of the combusted gas stream in a simple cycle gas turbine
to produce an amount of electrical power were calculated and
compared with the mass flow rates of a fuel stream formed of 100
vol. % methane and an oxidant stream formed of air, respectively,
required to be provided for combustion and subsequent expansion of
the combusted gas stream to produce an identical amount of
electrical power in the same simple cycle gas turbine. Relevant
characteristics of each of the fuel streams are provided in Table 1
and the composition of the oxidant stream at 0.degree. C. and 0.101
MPa is provided in Table 2.
TABLE-US-00001 TABLE 1 Lower Auto-ignition Heating Value
temperature Flammability limits Fuel Composition (kJ/kg) (.degree.
C.) (vol % in air) 100 vol. % CH.sub.4 49862 538 5.3-14.0 100 vol.
% H.sub.2S 15226 260 4.3-45.5
TABLE-US-00002 TABLE 2 Component Vol. % L/m.sup.3 g/m.sup.3 Weight
fraction Molecular Nitrogen 78.09 780.9 976.1 0.7551 Molecular
Oxygen 20.95 209.5 299.3 0.2315 Argon 0.93 9.3 16.6 0.0128 Carbon
Dioxide 0.038 0.38 0.8 0.0006
[0074] The mass rate flow calculations were based in part on
specifications provided for the production of electrical power
using a General Electric 7FA Simple Cycle gas turbine. In
particular, the heat rate in units of kJ/kW-h, the gas turbine mass
flow rate in units of kg/s, and the gas turbine electrical power
generation in megawatts (MW.sub.e) for the GE 7FA Simple Cycle gas
turbine that were necessary to perform the calculations are
provided in General Electric publication GE12985H, and are shown in
Table 3.
TABLE-US-00003 TABLE 3 Heat rate Mass flow rate Electrical power
System (kJ/kW-h) (kg/s) generation (MW.sub.e) GE 7FA Simple Cycle
9873 436 183 gas turbine
[0075] The mass flow rate of each respective fuel stream provided
to the simple cycle gas turbine to produce 183 MW.sub.e of
electrical power was determined from the power to be produced, the
efficiency of the gas turbine's conversion of thermal power to
electrical power, and the lower heating value of the fuel
composition. In particular, each fuel stream mass flow rate was
calculated according to formula (1):
Fuel Stream Mass Flow Rate = ( Electrical Power Generation ( kJ h )
* 1 Turbine Efficiency for converting Thermal Power to Electrical
Power ) Lower Heating Value ( kJ kg ) , ( 1 ) ##EQU00001##
where the Electrical Power Generation is provided in Table 3 as 183
MW.sub.e (where 183 MW.sub.e=658,800,000 kJ/h) and the Lower
Heating Value for each fuel is provided in Table 1. The Turbine
Efficiency for conversion of Thermal Power to Electrical Power for
the GE 7FA Simple Cycle gas turbine was determined according to the
formula (2):
Turbine Efficiency = 3600 kJ kWh Heat Rate kJ kWh ( 2 )
##EQU00002##
which is
3600 kJ / kWh 9873 kJ / kWh = 0.365 , ##EQU00003##
or 36.5%. Using the formulas above, the mass flow rate of the fuel
stream containing 100 vol. % H.sub.2S required to be provided for
combustion in the GE 7FA Simple Cycle gas turbine to produce 183
MW.sub.e was calculated to be 118660 kg/h, and the mass flow rate
of the fuel stream containing 100 vol. % CH.sub.4 required to be
provided for combustion in the gas turbine to produce the same
amount of electrical power was calculated to be 36235 kg/h.
[0076] The mass flow rates of the oxidant stream to be provided for
combustion in the gas turbine with each of the fuel streams to
produce 183 MW.sub.e were calculated from the total mass flow rate
in the gas turbine as provided in Table 3 (436 kg/s) and the
calculated mass flow rate of each respective fuel stream according
to formula (3)
Oxidant stream mass flow rate (kg/h)=total mass flow rate in gas
turbine (kg/h)-mass flow rate of fuel stream in gas turbine
(kg/h)=1569600 kg/h-mass flow rate of fuel stream (kg/h). (3)
The mass flow rate of the oxidant stream to be combustively reacted
with the fuel stream containing 100 vol. % H.sub.2S to produce 183
MW.sub.e in the gas turbine was calculated to be 1450939 kg/h, and
the mass flow rate of the oxidant stream to be combustively reacted
with the fuel stream containing 100 vol. % CH.sub.4 to produce 183
MW.sub.e was calculated to be 1533365 kg/h.
[0077] The molar ratio of molecular oxygen to hydrogen sulfide in
the combustion of the fuel stream containing 100 vol. % H.sub.2S
with the oxidant stream in the gas turbine to generate 183 MW.sub.e
was calculated to be greater than 1:1. The relative mass flow rates
of the components of the oxidant stream were calculated based on
the relative weight fractions of the components multiplied by the
mass flow rate of the oxidant stream. The calculated input mass
flow rates of the oxidant stream components are shown in Table
4.
TABLE-US-00004 TABLE 4 Input Mass Flow Rate Component Calculation
(kg/h) Oxygen (molecular) 1450939 kg/h * 0.2315 335892 Nitrogen
(molecular) 1450939 kg/h * 0.7551 1095604 Argon 1450939 kg/h *
0.0128 18572 Carbon Dioxide 1450939 kg/h * 0.0006 871
The input molar flow rate of oxygen was calculated from the input
mass flow rate of oxygen: [(335892 kg/h)*(1000 g/kg)]/32 g/m
(O.sub.2)=10496625 m/h O.sub.2, and the molar flow rate of hydrogen
sulfide was calculated from the input mass flow rate of the fuel
stream, where the fuel stream consisted only of hydrogen sulfide,
[(118661 kg/h)*(1000 g/kg)]/34 g/m (H.sub.2S)=3490029 m/h H.sub.2S.
The ratio of molecular oxygen to hydrogen sulfide provided by the
fuel stream containing hydrogen sulfide and the oxidant stream over
the same period of time, therefore, was calculated to be
10496625/3490029=3.0.
[0078] A summary of the data and calculations for each of the fuel
streams and the oxidant stream and production of power in the gas
turbine is provided in Table 5.
TABLE-US-00005 TABLE 5 Comparative Calculation 1 Calculation 1 Gas
Turbine GE 7FA GE 7FA Cycle Type Simple Cycle Simple Cycle Fuel
Composition, CH.sub.4 (vol. %) 0 100 Fuel Composition, H.sub.2S
(vol. %) 100 0 Lower Heating Value, CH.sub.4 (kJ/kg) -- 49862 Lower
Heating Value, H.sub.2S (kJ/kg) 15226 -- Heat Rate (kJ/kWh) 9873
9873 Total Gas Turbine Mass Flow Rate 1569600 1569600 (kg/h) Gas
Turbine CH.sub.4 Fuel Mass Flow Rate 0 36235 (kg/h) Gas Turbine
H.sub.2S Fuel Mass Flow Rate 118660 0 (kg/h) Oxidant Stream Mass
Flow Rate (kg/h) 1450939 1533365 Molecular Oxygen Mass Flow Rate
335892 354974 (kg/h) Molecular Nitrogen Mass Flow Rate 1095604
1157844 (kg/h) Argon Mass Flow Rate (kg/h) 18572 19627 CO.sub.2
Mass Flow Rate (kg/h) 871 920 Exhaust Temperature (.degree. C.) 604
604 Total Output Power (MW.sub.e) 183 183
[0079] The calculations demonstrated that a fuel stream consisting
of H.sub.2S can be combusted in a simple cycle gas turbine to
produce electrical power equivalent to the electrical power
produced by combusting a natural gas stream consisting of methane
in a similar manner. The fuel stream consisting of H.sub.2S must be
provided for combustion at a rate about 3 times greater than a fuel
stream consisting of methane to produce an equivalent amount of
power.
Example 2
[0080] The electrical power produced by combusting selected fuel
streams in a combined cycle gas-turbine/heat recovery steam
generator system was calculated. For the calculations, the GE 7FA
Simple Cycle gas turbine comprised the first cycle of the combined
cycle power generation system and a heat recovery steam generator
(HRSG) utilizing a GE S107FA steam turbine comprised the second
cycle. The total electrical power produced in the combined cycle
system is produced from expansion of a combusted gas stream in the
gas turbine, as described above with respect to a single cycle
system, and from expansion of a steam stream through a steam
turbine, where the steam stream is produced by exchange of heat
between the expanded combusted gas stream and water/steam in the
HRSG. Calculations were made to determine the total electrical
power produced by combustion of the selected fuel streams in the
gas turbine, expansion of the resulting combusted gas stream
through the gas turbine, exchanging heat between the expanded
combusted gas stream and water and/or steam in the HRSG, and
expansion of the resulting hot steam stream through a steam turbine
in the HRSG. As shown above, the electrical power produced in the
GE 7FA gas turbine is 183 MW.sub.e, where the mass input flow rate
of the fuel stream is adjusted to generate the electrical power
produced by the gas turbine. The electrical power produced by the
HRSG is dependent on the temperature of the expanded combusted gas
stream exiting the gas turbine, the components, and relative
quantity of these components, of the expanded combusted gas stream,
and on the efficiency of the heat recovery cycle of the HRS G.
[0081] The temperature of the expanded combusted gas stream exiting
the GE 7FA gas turbine produced from a fuel stream consisting of
100% CH.sub.4 is provided in the specifications of the GE 7FA as
604.degree. C. in GE Publication GEH12985H. For purposes of the
electrical power calculations, the exit temperature for each of the
expanded combusted gas streams produced from the selected fuel
streams was assumed to be 604.degree. C.
[0082] The efficiency of the heat recovery cycle of the combined
cycle system utilizing a GE 7FA gas turbine and an HRSG with a GE
S107FA steam turbine was calculated by determining the thermal
power (MW.sub.t) that would be exchanged between an expanded
combusted gas stream produced by combusting the fuel stream
containing 100% CH.sub.4 as described above in Example 1 and
water/steam, then calculating the efficiency of the heat recovery
cycle from the electrical power output specification of the heat
recovery cycle of the system as published in GE Publication
GEH12985H relative to the thermal power exchanged between the
expanded combusted gas stream and the water/steam. The thermal
power exchanged between the expanded combusted gas stream and
water/steam in the HRSG was calculated from the temperature
difference between the expanded combusted gas stream exiting the
gas turbine and the flue gas stream exiting the HRSG, the mass flow
rate of each of the components of the expanded combusted gas stream
exiting the gas turbine, and the heat capacity of each of the
components of the expanded combusted gas stream.
[0083] The temperature difference between the expanded combusted
gas stream and water/steam in the HRSG and the flue gas stream is
484.degree. C. (484.degree. K), assuming that the flue gas stream
exits the HRSG at 120.degree. C. and the expanded combusted gas
stream exits the gas turbine at 604.degree. C. as set forth in GE
Publication GEH12985H. A temperature of 120.degree. C. is a typical
flue gas stream temperature when the flue gas stream is formed by
exchanging heat between a combusted gas stream and steam.
[0084] Calculation of the mass flow rate of each of the components
of the expanded combusted gas stream produced from a fuel stream
containing 100% CH.sub.4 as the expanded combusted gas stream exits
the gas turbine was dependent on determining the components of the
expanded combusted gas stream and on calculation of the relative
quantities of such components. The components and relative quantity
of the components of the expanded combusted gas stream depends in
turn on the components and relative quantities of such components
of the fuel stream and the oxidant stream, and on the stoichiometry
of the combustion reaction of the fuel stream and oxident stream.
For the fuel stream containing 100% CH.sub.4, the combustion
reaction of CH.sub.4 with air is
CH.sub.4+2O.sub.2.fwdarw.CO.sub.2+2H.sub.2O. The components of the
expanded combusted gas stream and the relative mass flow rate of
these components in the expanded combusted gas stream, therefore,
were determined from the components of air as the oxidant stream as
set forth in Table 4 and their relative mass flow rates to the gas
turbine as reacted with the CH.sub.4 of the fuel stream at its mass
flow rate to the gas turbine. Complete combustion and consumption
of CH.sub.4 was assumed since a substantial stoichiometric excess
of oxygen is provided for combustion relative to CH.sub.4. The mass
flow rate of molecular oxygen in the expanded combusted gas stream
was calculated according to formula (4):
mass flow rate of molecular oxygen in expanded combusted gas stream
( kg / h ) = [ mass flow rate of oxygen in oxidant stream ( kg / h
) ] - { [ 2 * ( molecular wt . of molecular oxygen ( g m ) )
molecular wt . methane ( g m ) ] * [ mass flow rate of fuel stream
of 100 vol . % methane ( kg / h ) ] } . ( 4 ) ##EQU00004##
The mass flow rates of carbon dioxide and water vapor components in
the expanded combusted gas stream were calculated according to
formula (5):
mass flow rate of component ( kg / h ) = { [ [ mass flow rate of
component in oxidant stream ( kg / h ) ] + ( moles of component
produced per mole of methane ) * ( molecular wt . of component ( g
m ) ) molecular wt . methane ( g m ) ] * [ mass flow rate of fuel
stream of 100 vol . % methane ( kg/h ) ] } . ( 5 ) ##EQU00005##
The mass flow rate in the expanded combusted gas stream of
components of the oxidant stream that are inert in the combustion
reaction was assumed to be equivalent to the mass flow rate of
those components in the oxidant stream fed to the gas turbine.
Table 6 provides the calculated mass flow rates of components of
the expanded combusted gas stream formed by combustion of the fuel
stream containing 100 vol. % methane with a dry air oxidant stream
in a GE 7FA gas turbine utilizing the fuel stream and oxidant
stream mass flow rates set forth in Example 1 above.
TABLE-US-00006 TABLE 6 Combusted Gas Stream Component Calculated
Mass Flow (kg/h) Oxygen 210032 Nitrogen 1157844 Argon 19627 Carbon
Dioxide 100567 Water Vapor 81530
[0085] The thermal power contained in each component of the
expanded combusted gas stream component was calculated according to
formula (6):
Thermal Power Provided by Component For Electrical Power Generation
= [ ( heat capacity of component ( kJ / kg ) ) * ( mass flow rate
of component ( kg / h ) * ( .DELTA. T max expanded combusted gas
stream T - flue gas stream T ) ] 3600000 kJ / MW t . ( 6 )
##EQU00006##
The calculated thermal power of the components is shown in Table
7.
TABLE-US-00007 TABLE 7 Combusted Gas Mass Flow Temperature Thermal
Stream Heat Capacity Rate Change Power Component (kJ/(kg * K)
(kg/h) (.degree. C.) MW.sub.t Oxygen 0.92 210032 484 26.0 Nitrogen
1.04 1157844 484 161.9 Argon 0.52 19627 484 1.4 Carbon Dioxide 0.84
100567 484 11.4 Water Vapor 1.97 81530 484 21.6
The total thermal power contained in the expanded combusted gas
stream available upon cooling the expanded combusted gas stream to
120.degree. C. was calculated to be 222.3 MW.sub.t by summing the
thermal power of the combusted gas stream components.
[0086] The efficiency of the HRSG system in converting the thermal
power of the expanded combusted gas stream to electrical power was
then calculated. According to General Electric Publication GEH
12985H, the second cycle of the combined cycle power generation
system produces 86 MW.sub.e electrical power utilizing a methane
fuel stream. The efficiency of the second cycle of the combined
cycle system, therefore, was calculated as
86 MW ( electrical ) 222.3 MW ( thermal ) * 100 = 38.7 % .
##EQU00007##
[0087] Based on the calculated efficiency of the HRSG cycle in the
combined cycle gas turbine/HRSG system, the electrical power
capable of being produced by selected fuel streams containing
H.sub.2S and, optionally CH.sub.4 and/or CO.sub.2 was calculated.
In particular, the electrical power capable of being produced in a
combined cycle gas turbine/HRSG system by a fuel stream containing
100 vol % H.sub.2S provided at a rate effective to produce 183
MW.sub.e in the gas turbine cycle, as described in Example 1, was
calculated. In addition, the electrical power capable of being
produced in a combined cycle gas turbine/HRSG system by a fuel
stream containing 50 vol. % H.sub.2S and 50 vol. % CH.sub.4, and by
a fuel stream containing 33 vol. % H.sub.2S, 33 vol. % CH.sub.4,
and 34 vol. % CO.sub.2 was calculated. Mass flow rates of the
selected fuel streams into the gas turbine were calculated in
accordance with formula (1) above, where the lower heat capacity of
the blended fuel streams was calculated in accordance with formula
(7):
Lower Heating Value of Fuel Stream (kJ/kg)=[(wt. fraction
H.sub.2S)*(lower heating value of H.sub.25 (kJ/kg))]+[(wt. fraction
CH.sub.4)*(lower heating value of CH.sub.4 (kJ/kg)). (7)
[0088] For each selected fuel stream, components of the expanded
combusted gas stream produced by combustion of the fuel stream and
air and their relative quantities were determined as set forth
above with respect to the fuel stream containing 100 vol. %
CH.sub.4, except where H.sub.2S is a component of the fuel stream
the expanded combusted gas stream will contain sulfur dioxide and
water vapor produced in accordance with the combustion reaction
H.sub.2S+1.5O.sub.2.fwdarw.SO.sub.2+H.sub.2O. In this case, the
mass flow rate of molecular oxygen in the expanded combusted gas
stream was adjusted to reflect consumption of molecular oxygen by
reaction with H.sub.2S by including the amount of oxygen consumed
by reaction with H.sub.2S in the calculation of the mass flow rate
of molecular oxygen in the expanded combusted gas stream, where the
amount of oxygen consumed by reaction with H.sub.2S was calculated
according to formula (8):
molecular oxygen consumed by combustive reaction with H 2 S ( kg /
h ) = [ ( 1.5 * molecular weight of molecular oxygen ( g m )
molecular weight of hydrogen sulfide ( g m ) ) * mass flow rate of
hydrogen sulfide in fuel stream ( kg / h ) ] . ( 8 )
##EQU00008##
The mass flow rate of sulfur dioxide in an expanded combusted gas
stream produced by combusting a fuel stream containing H.sub.2S,
and optionally CH.sub.4 and/or CO.sub.2, was calculated according
to formula (9):
mass flow rate of sulfur dioxide in expanded combusted gas stream (
kg / h ) = [ ( moles of SO 2 produced per mole of H 2 S ) * ( mol .
wt . SO 2 ( g m ) ) mol . wt . H 2 S ( g m ) ] * [ mass flow rate
of H 2 S in fuel stream ( kg / h ) ] . ( 9 ) ##EQU00009##
The mass flow rate of water vapor in an expanded combusted gas
stream produced by combusting a fuel stream containing H.sub.2S,
and optionally CH.sub.4 and/or CO.sub.2, was calculated according
to formula (10):
mass flow rate of water vapor in expanded combusted gas stream ( kg
/ h ) = { [ ( moles of H 2 O produced per mole of H 2 S ) * ( mol .
wt . H 2 O ( g m ) ) mol . wt . hydrogen H 2 S ( g m ) ] * [ mass
flow rate of H 2 S in fuel stream ( kg / h ) ] } + { [ ( moles of H
2 O produced per mole of CH 4 ) * ( mol . wt . H 2 O ( g m ) ) mol
. wt . CH4 ] * [ mass flow rate of CH 4 in fuel stream ( kg / h ) ]
} ( 10 ) ##EQU00010##
The mass flow rate of carbon dioxide in an expanded combusted gas
stream produced by combusting a fuel stream containing H.sub.2S,
and optionally CH.sub.4 and/or CO.sub.2, was calculated according
to formula (11):
mass flow rate of carbon dioxide in expanded combusted gas stream (
kg / h ) = { [ ( moles of CO 2 produced per mole of CH 4 ) * ( mol
. wt . CO 2 ( g m ) ) mol . wt . CH 4 ( g m ) ] * [ mass flow rate
of CH 4 in fuel stream ( kg / h ) ] } + [ mass flow rate of CO 2 in
fuel stream ( kg / h ) ] + [ mass flow rate of CO 2 in oxidant
stream ( kg / h ) ] ( 11 ) ##EQU00011##
The heat capacities of the components of expanded combusted gas
stream produced by combustion of each selected fuel stream were
used to calculate the thermal power contained in each component of
the expanded combusted gas stream in accordance with formula (6),
where the heat capacity of sulfur dioxide is 0.64. The electrical
power capable of being produced from the selected fuel streams and
the relevant data for calculating the electrical power is provided
in Table 8.
TABLE-US-00008 TABLE 8 Comparative Calculation 2 Calculation 3
Calculation 4 Calculation 2 Gas Turbine GE 7FA GE 7FA GE 7FA GE 7FA
Cycle Type Combined Combined Combined Combined Fuel stream
composition, CH.sub.4 (Vol. %) 0 50 33 100 Fuel stream composition
H.sub.2S (Vol. %) 100 50 33 0 Fuel stream composition (CO.sub.2)
(Vol. %) 0 0 34 0 Lower Heating Value, CH.sub.4 (kJ/kg) -- 49862
49862 49862 Lower Heating Value H.sub.2S (kJ/kg) 15226 15226 15226
-- Lower Heating Value, Fuel Blend (kJ/kg) -- 26310 13799 -- Heat
Rate (kJ/kWh) 9873 9873 9873 9873 Gas Turbine Mass Flow (kg/s) 436
436 436 436 Gas Turbine Power Generation (MW.sub.e) 183 183 183 183
Expanded Combusted Gas Temperature (.degree. C.) 604 604 604 604
Gas Turbine Total Fuel Rate (kg/h) 118661 68673 130936 36235 Gas
Turbine CH.sub.4 Fuel Rate (kg/h) 0 21975 21975 36235 Gas Turbine
H.sub.2S Fuel Rate (kg/h) 118661 46698 46698 0 Gas Turbine CO.sub.2
Fuel Rate (kg/h) 0 0 62263 0 Gas Turbine Oxidant (Dry Air) Stream
Rate (kg/h) 1450939 1500927 1438664 1533365 Gas Turbine Molecular
Oxygen Rate (Oxidant Stream) (kg/h) 335892 347465 333051 354974 Gas
Turbine Nitrogen Rate (Oxidant Stream) (kg.h) 1095604 1133350
1086335 1157844 Gas Turbine Argon Rate (Oxidant Stream) (kg/h)
18572 19212 18415 19627 Gas Turbine Carbon Dioxide Rate (Oxidant
Stream) (kg/h) 871 901 863 920 Molecular Oxygen Consumption (kg/h)
167521 153827 153827 144942 Expanded Combusted Gas Stream Carbon
Dioxide (kg/h) 871 61333 123559 100567 Expanded Combusted Gas
Stream Sulfur Dioxide (kg/h) 223361 87901 87901 0 Expanded
Combusted Gas Stream Oxygen (kg/h) 168372 193637 179223 210032
Expanded Combusted Gas Stream Nitrogen (kg/h) 1095604 1133350
1086335 1157844 Expanded Combusted Gas Stream Argon (kg/h) 18572
19212 18415 19627 Expanded Combusted Gas Stream Water Vapor (kg/h)
62820 74167 74167 81530 Recoverable Thermal Power from Expanded
Combusted Gas Stream 211 218 217 222 604.degree. C. to 120.degree.
C. (MW.sub.t) Calculated HRSG Cycle Efficiency (%) 38.7 38.7 38.7
38.7 Flue Gas Stream Exhaust Temperature 120 120 120 120 HRSG Cycle
Power (MW.sub.e) 82 84 84 86 Total Output Power (MW.sub.e) 265 267
267 269
[0089] The calculations demonstrated that a fuel stream consisting
of H.sub.2S, or containing 50 vol. % H.sub.2S and 50 vol. %
CH.sub.4, or containing 33 vol. % H.sub.2S, 33 vol. % CH.sub.4, and
34 vol. % CO.sub.2 can be combusted in a combined cycle gas
turbine/HRSG to produce electrical power equivalent to the
electrical power produced by combusting a natural gas stream
consisting of methane in a similar manner. The fuel streams
containing H.sub.2S must be provided for combustion at rates
greater than a fuel stream consisting of methane to produce an
equivalent amount of power.
Example 3
[0090] The electrical power produced by combusting selected fuel
streams in a combined cycle gas-turbine/heat recovery steam
generator system with supplemental firing to combust the oxygen in
the expanded combusted gas stream of each combusted fuel stream was
calculated. The fuel streams selected were the same as those
selected in Example 2 except that each contained some quantity of
hydrogen sulfide. No calculation of electrical power produced by
supplemental firing of a fuel stream containing only methane was
conducted since, as shown above, comparison of the electrical power
produced in the gas turbine cycle versus the electrical power
produced in the HRSG cycle indicates the gas turbine cycle produces
more electrical power, therefore, the most efficient method for
producing electrical power with a methane fuel stream would avoid
using some of the fuel stream as fuel for supplemental firing.
Supplemental firing, however, is preferred when utilizing a fuel
stream containing hydrogen sulfide to combust all oxygen in the
expanded combusted gas stream to prevent sulfur dioxide in the
expanded combusted gas stream from reacting with oxygen and water
to form sulfurous or sulfuric acid. For the calculations, the GE
7FA Simple Cycle gas turbine comprised the first cycle of the
combined cycle power generation system and a supplemental firing
unit in combination with a heat recovery steam generator (HRSG)
utilizing a GE S107FA steam turbine comprised the second cycle.
[0091] The electrical power produced in the gas turbine cycle of
the combined gas turbine/supplemental firing unit/HRSG using a GE
7FA gas turbine for each of the selected fuel streams is 183
MW.sub.e, as discussed above.
[0092] The electrical power produced by the combined supplemental
firing unit and HRSG was calculated by determining the thermal
power contained in a second combusted gas stream produced by
combusting all of the molecular oxygen in the expanded combusted
gas stream with a selected supplemental fuel stream, calculating
the efficiency of conversion of the thermal power in the second
combusted gas stream to electrical power in the HRSG, and
calculating the amount of electrical power produced in the HRSG
from the thermal power contained in the second combusted gas stream
and the efficiency of converting that thermal power to electrical
power in the HRSG when the second combusted gas stream was cooled
to 120.degree. C. in the HRSG. Each supplemental fuel stream was
selected to have the same composition as the fuel stream used to
produce power in the gas turbine cycle as set forth in Example 2
above.
[0093] The amount of thermal power in the second combusted gas
stream available for conversion to electrical power in the HRSG
system was calculated by adding the enthalpy of combustion produced
by combusting the supplemental fuel stream and the expanded
combusted gas stream in the supplemental firing unit and the
thermal power contained in each component of the second combusted
gas stream exchanged to produce steam in the HRSG, and subtracting
the amount of thermal power required to raise the temperature of
the expanded combusted gas stream from the temperature of the
expanded combusted gas stream exiting the gas turbine (604.degree.
C.) to a selected temperature. The amount of thermal power
converted to electrical power in the second combusted gas stream,
therefore, was calculated according to formula (12):
Thermal power of second combusted stream converted to electrical
power in HRSG=[(Enthalpy of Combustion (MW.sub.t)+Thermal Power
Contained in Components of Second Combusted Gas Stream Exchanged in
HRSG (MW.sub.t))-Thermal Power Required to Raise Expanded Combusted
Gas Stream to Selected Temperature (MW.sub.t)]. (12)
The amount of electrical power produced by the combined cycle gas
turbine/supplemental firing unit/HRSG system was calculated for
each selected fuel stream using a second combusted gas stream
temperature of 604.degree. C. (the temperature of the expanded
combusted gas stream), 800.degree. C., and 1000.degree. C.
[0094] The enthalpy of combustion produced by combusting the
supplemental fuel stream and the expanded combusted gas stream in
the supplemental firing unit was calculated for each selected fuel
stream according to formula (13):
Enthalpy of Combustion MW t = Mass Flow Rate of Supplemental Fuel
Stream ( kg h ) * Lower heating value of Supplemental Fuel Stream (
kJ kg ) 3600000 ( MWt kJ h ) ( 13 ) ##EQU00012##
The mass flow rate of the supplemental fuel stream required to
consume the oxygen present in the expanded combusted gas stream was
calculated based on the mass flow rate of oxygen present in the
expanded combusted gas stream as calculated above, the relative
amounts of hydrogen sulfide and methane in the supplemental fuel
stream, and on the molar ratios of molecular oxygen to hydrogen
sulfide, and if present methane, as set forth in the reaction
equations above. In particular, the mass flow rate of supplemental
fuel stream needed to consume the oxygen present in the expanded
combusted gas stream when the fuel stream contains 100 vol. %
H.sub.2S was calculated according to formula (14):
mass flow rate of supplemental fuel stream to consume oxygen
present in the expanded combusted gas stream ( kg / h ) = (
molecular wt . H 2 S ( g m ) 1.5 * molecular wt O2 ( g m ) ) * (
mass flow rate of molecular oxygen in expanded combusted gas stream
( kg / h ) ) . ( 14 ) ##EQU00013##
When the fuel stream contains 50 vol. % H.sub.2S and 50 vol. %
CH.sub.4, the mass flow of the supplemental feed stream was
calculated according to formula (15):
mass flow of supplemental fuel stream to consume oxygen present in
the expanded combusted gas stream ( kg / h ) = mass flow rate of
molecular oxygen in expanded combusted gas stream ( kg h ) { [ ( 2
* mol . wt . of O 2 ( g m ) mol . wt . of CH 4 ( g m ) ) * wt
fraction CH 4 in s . fuel stream ] + [ ( 1.5 * mol . wt . of O 2 (
g m ) mol . wt . of H 2 S ( g m ) ) * wt fraction of H 2 S in s .
fuel stream ] } ( 15 ) ##EQU00014##
where the weight fraction of methane in the supplemental fuel
stream is 0.32 and the weight fraction of hydrogen sulfide in the
supplemental fuel stream is 0.68. When the supplemental fuel stream
contains 33 vol. % H.sub.2S, 33 vol. % CH.sub.4, and 34 vol. %
CO.sub.2, the mass flow rate of the supplemental fuel stream needed
to consume the oxygen present in the expanded combusted gas stream
was calculated using formula (15) above where the weight fraction
of methane in the fuel stream is 0.168 and the weight fraction of
H.sub.2S in the fuel stream is 0.357. The lower heating value of
the supplemental fuel stream was calculated based on the lower
heating values of H.sub.2S and CH.sub.4 and the relative weight
ratios of these components in the supplemental fuel stream
according to formula (16):
Lower Heating Value of Supplemental Fuel Stream=[(Lower Heating
Value H.sub.2S*Weight Fraction H.sub.2S in Supplemental Fuel
Stream)+(Lower Heating Value CH.sub.4*Weight Fraction of CH.sub.4
in Supplemental Fuel Stream)]. (16)
Table 9 shows the calculated enthalpies of combustion of the
selected supplemental fuel streams, the calculated mass flow rates
of the selected fuel streams necessary to consume oxygen in the
expanded combusted gas stream, and the lower heating values of the
selected supplemental fuel streams for a combined cycle system
producing 183 MWe in a GE 7FA gas turbine in a first cycle.
TABLE-US-00009 TABLE 9 50% H.sub.2S/50% 33% H.sub.2S/33% 100%
H.sub.2S CH.sub.4 CH.sub.4/34% CO.sub.2 (vol. %) (vol. %) (vol. %)
Mass flow rate fuel stream to gas turbine (from 118661 68673
1300936 Table 8) to produce 183 MWe in gas turbine (kg/h) Mass flow
rate of oxidant stream to gas turbine 1450939 1500927 1438664 (from
Table 8) to produce 183 MW.sub.e in gas turbine (kg/h) Mass flow
rate of molecular oxygen in expanded 168372 193637 179223 combusted
gas stream (from Table 8) (kg/h) Wt. Fraction of CH.sub.4 in
supplemental fuel stream 0 0.32 0.17 Wt. Fraction of H.sub.2S in
supplemental fuel stream 1 0.68 0.35 Lower Heating Value of
supplemental fuel stream 15226 26310 13799 (kJ/kg) Mass flow rate
of supplemental fuel stream to 119263 86445 152553 supplemental
firing unit to combust oxygen in expanded combusted gas stream
(kg/h) Enthalpy of combustion of supplemental fuel in 504 632 585
supplemental firing unit (MW.sub.t)
[0095] The thermal power contained in the components of second
combusted gas stream that is exchanged to produce steam in the HRSG
was determined by calculating the thermal power contained in each
of the components that is exchanged to produce steam in the HRSG
and summing the results. The thermal power contained in each of the
components of the second combusted gas stream that is exchanged to
produce steam in the HRSG was calculated by determining the mass
flow rate of each of the components of the second combusted gas
stream produced by combustion of the expanded combusted gas stream
and the selected supplemental fuel stream and multiplying the heat
capacity for each component of the second combusted gas stream by
its mass flow rate and the temperature difference of the second
combusted gas stream and the flue gas stream exiting the HRSG at
120.degree. C. and dividing the result by 3600000 kj/MW.sub.t. The
thermal power contained in the second combusted gas stream may be
expressed by formula (17):
Thermal Power Of the Second Combusted Gas Stream Exchanged to
Produce Steam in H R S G = [ Heat Capacity of Component X ( kJ kg )
* Mass Flow Rate of Component X in 2 d combusted gas stream ( kg h
) * .DELTA. T 3600000 ( MWt kJ kg ) ] ( 17 ) ##EQU00015##
where X ranges from 1 to n, where n is the total number of
components in the second combusted gas stream, and .DELTA.T is the
difference between the temperature of the second combusted gas
stream (604.degree. C., 800.degree. C., or 1000.degree. C.
depending on the selected temperature) and the temperature of the
flue gas stream exiting the HRSG (120.degree. C.).
[0096] Calculation of the mass flow rate of the components of the
second combusted gas stream was effected by 1) determining the
components of the second combusted gas stream and 2) calculating of
the relative quantities of such components. The components and
relative quantity of the components of the second combusted gas
stream depends on the components of the supplemental fuel stream
and relative mass flow rates of such components (provided above in
Table 9 for each of the selected fuels), on the components of the
expanded combusted gas stream and the relative mass flow rates of
such components (provided above in Table 8), and on the
stoichiometry of the combustion reaction of the supplemental fuel
stream and expanded combusted gas stream. Each of the supplemental
fuel streams contains H.sub.2S, where, as noted above, the
combustion reaction of H.sub.2S with molecular oxygen is
H.sub.2S+1.5O.sub.2.fwdarw.SO.sub.2+H.sub.2O. For the supplemental
fuel streams containing CH.sub.4, the combustion reaction of
CH.sub.4 with molecular oxygen, as noted above, is
CH.sub.4+2O.sub.2.fwdarw.CO.sub.2+2H.sub.2O. The components of the
second combusted gas stream and the relative mass flow rates of
these components in the second combusted gas stream, therefore,
were determined from the components of the expanded combusted gas
stream as set forth in Table 8 and their relative mass flow rates
to the supplemental firing unit as reacted with the H.sub.2S, and
if present the CH.sub.4, of the supplemental fuel stream at its
mass flow rate to the supplemental firing unit. Complete combustion
and consumption of H.sub.2S and CH.sub.4, if present in the
supplemental fuel stream, and O.sub.2 was assumed since the
supplemental fuel stream is provided at a mass flow rate relative
to the mass flow rate of oxygen in the expanded combusted gas
stream to stoichiometrically react with all of the oxygen in the
expanded combusted gas stream. The mass flow rate of sulfur dioxide
in the second combusted gas stream was calculated according to
formula (18):
mass flow rate of sulfur dioxide in second combusted gas stream = {
[ ( molecular wt . of SO 2 ( g m ) ) molecular wt . H 2 S ( g m ) ]
* [ mass flow rate of hydrogen sulfide in supplemental fuel stream
( kg / h ) ] } + mass flow rate of sulfur dioxde in expanded
combusted gas stream . ( 18 ) ##EQU00016##
The mass flow rate of carbon dioxide in the second combusted gas
stream was calculated according to formula (19):
mass flow rate of carbon dioxide in second combusted gas stream = {
[ ( molecular wt . of CO 2 ( g m ) ) molecular wt . CH 4 ( g m ) ]
* [ mass flow rate of methane in supplemental fuel stream ( kg / h
) ] } + mass flow rate of carbon dioxide in expanded combusted gas
stream . ( 19 ) ##EQU00017##
The mass flow rate of water vapor in the second combusted gas
stream was calculated according to formula (20):
mass flow rate of water vapor in second combusted gas stream = { [
( ( molecular wt . of H 2 O ( g m ) ) molecular wt . H 2 S ( g m )
) * ( mass flow rate of supplemental fuel stream ( kg / h ) * wt .
fraction of H 2 S in supplemental fuel stream ) ] + [ ( molecular
wt . of H 2 O ( g m ) molecular wt . of CH 4 ( g m ) ) * ( mass
flow rate of supplemental fuel stream ( kg / h ) * wt . fraction of
( CH 4 ) ] } + mass flow rate of water vapor in expanded combusted
gas stream ( 20 ) ##EQU00018##
The mass flow rate in the second combusted gas stream of components
of the expanded combusted gas stream that are inert in the
combustion reaction in the supplemental firing unit was assumed to
be equivalent to the mass flow rate of those components in the
expanded combusted gas stream fed to the supplemental firing unit.
Table 10 provides the calculated mass flow rates of components of
the second combusted gas stream formed by combustion each of the
selected supplemental fuel streams, the heat capacity of these
components, the calculated thermal power of the components of the
second combusted gas stream at temperatures of 604.degree. C.,
800.degree. C., and 1000.degree. C. when cooled to produce a flue
gas stream at 120.degree. C., the enthalpy of combustion of each
supplemental fuel stream in the supplemental firing unit, and the
total thermal power for conversion to electrical power [(calculated
thermal power of the components of the second combusted gas
stream+enthalpy of combustion)-thermal power required to raise the
temperature of the expanded combusted gas stream to selected
temperature for heat exchange in the HRSG].
TABLE-US-00010 TABLE 10 Calculation Calculation Calculation
Calculation Calculation 2 (cont.) 3 (cont) 4 (cont) 5 6
H.sub.2S/CH.sub.4/CO.sub.2 content of fuel stream and supplemental
fuel 100/0/0 50/50/0 33/33/34 100/0/0 100/0/0 stream (vol. %) Max.
Temp. of 2d combusted gas stream (.degree. C.) 604 604 604 800 1000
.DELTA. T in heat exchange of 2d combusted gas stream (.degree. C.)
484 484 484 680 880 Mass Flow Rate SO.sub.2 in 2d combusted gas
stream (kg/h) 447857 198551 190315 447857 447857 SO.sub.2 Heat
Capacity (kJ/kg) 0.64 0.64 0.64 0.64 0.64 SO.sub.2Thermal Power
Contribution in heat exchange of 2d 38.5 17.1 16.4 54.1 70.1
combusted gas stream (MW.sub.t) Mass Flow Rate Water Vapor in 2d
combusted gas stream (kg/h) 125960 167528 160578 125960 125960
Water Vapor Heat Capacity (kJ/kg) 1.97 1.97 1.97 1.97 1.97 Water
Vapor Thermal Power Contribution in heat exchange of 33.4 44.4 42.5
46.9 60.7 2d combusted gas stream (MW.sub.t) Mass Flow Rate
CO.sub.2 in 2d Combusted Gas Stream (kg/h) 871 137405 193968 871
871 CO.sub.2 Heat Capacity (kJ/kg) 0.84 0.84 0.84 0.84 0.84
CO.sub.2 Thermal Power Contribution in heat exchange of 2d 0.1 15.5
21.9 0.1 0.2 combusted gas stream (MW.sub.t) Mass Flow Rate of
Nitrogen in 2d Combusted Gas Stream (kg/h) 1095604 1133350 1086335
1095604 1095604 Nitrogen Heat Capacity (kJ/kg) 1.04 1.04 1.04 1.04
1.04 Nitrogen Thermal Power Contribution in heat exchange of 2d
153.2 158.5 151.9 215.2 278.6 combusted gas stream (MW.sub.t) Mass
Flow Rate of Argon in heat exchange of 2d combusted gas 18572 19212
18415 18572 18572 stream (MW.sub.t) Argon Heat Capacity (kJ/kg)
0.52 0.52 0.52 0.52 0.52 Argon Thermal Power Contribution in heat
exchange of 2d 1.3 1.3 1.3 1.8 2.4 combusted gas stream (MW.sub.t)
Thermal Power Produced in Heat Exchange from components of 226.5
236.8 234.0 318.1 412.0 2d combusted gas stream (MW.sub.t) Enthalpy
of Combustion of Supplemental Fuel Stream (MW.sub.t) 504 632 585
504 504 Thermal Power Required to Raise 2d Combusted Gas Stream to
0 0 0 (86) (173) its Max. Temp from 604.degree. C. (MW.sub.t) Total
Thermal Power available for conversion to electrical 730.5 868.8
819 736.1 743 power in Second Cycle (MW.sub.t) Calculation
Calculation Calculation Calculation 7 8 9 10
H.sub.2S/CH.sub.4/CO.sub.2 content of fuel stream and supplemental
fuel 50/50/0 50/50/0 33/33/34 33/33/34 stream (vol. %) Max. Temp.
of 2d combusted gas stream (.degree. C.) 800 1000 800 1000 .DELTA.
T in heat exchange of 2d combusted gas stream (.degree. C.) 680 880
680 880 Mass Flow Rate SO.sub.2 in 2d combusted gas stream (kg/h)
198551 198551 190315 190315 SO.sub.2 Heat Capacity (kJ/kg) 0.64
0.64 0.64 0.64 SO.sub.2Thermal Power Contribution in heat exchange
of 2d 24.0 31.1 23.0 29.8 combusted gas stream (MW.sub.t) Mass Flow
Rate Water Vapor in 2d combusted gas stream (kg/h) 167528 167528
160578 160578 Water Vapor Heat Capacity (kJ/kg) 1.97 1.97 1.97 1.97
Water Vapor Thermal Power Contribution in heat exchange of 62.3
80.7 59.8 77.3 2d combusted gas stream (MW.sub.t) Mass Flow Rate
CO.sub.2 in 2d Combusted Gas Stream (kg/h) 137405 137405 193968
193968 CO.sub.2 Heat Capacity (kJ/kg) 0.84 0.84 0.84 0.84 CO.sub.2
Thermal Power Contribution in heat exchange of 2d 21.8 28.2 30.8
39.8 combusted gas stream (MW.sub.t) Mass Flow Rate of Nitrogen in
2d Combusted Gas Stream (kg/h) 1133350 1133350 1086335 1086335
Nitrogen Heat Capacity (kJ/kg) 1.04 1.04 1.04 1.04 Nitrogen Thermal
Power Contribution in heat exchange of 2d 222.7 288.1 213.4 276.2
combusted gas stream (MW.sub.t) Mass Flow Rate of Argon in heat
exchange of 2d combusted gas 19212 19212 18415 18415 stream
(MW.sub.t) Argon Heat Capacity (kJ/kg) 0.52 0.52 0.52 0.52 Argon
Thermal Power Contribution in heat exchange of 2d 1.9 2.4 1.8 2.4
combusted gas stream (MW.sub.t) Thermal Power Produced in Heat
Exchange from components of 332.7 430.5 328.8 425.5 2d combusted
gas stream (MW.sub.t) Enthalpy of Combustion of Supplemental Fuel
Stream (MW.sub.t) 632 632 585 585 Thermal Power Required to Raise
2d Combusted Gas Stream to (88) (178) (88) (177) its Max. Temp from
604.degree. C. (MW.sub.t) Total Thermal Power available for
conversion to electrical 876.7 884.5 825.8 833 power in Second
Cycle (MW.sub.t)
[0097] The electrical power produced from the total thermal power
in the heat recovery cycle of the combined cycle system was
calculated by multiplying the total thermal power by the efficiency
of the heat recovery cycle of the combined cycle system utilizing a
GE S107FA steam turbine. The efficiency of the heat recovery cycle
utilizing a GE S107FA at a temperature differential of 484.degree.
C. was calculated above in Example 2. For the examples in which the
maximum second combusted gas temperature is 800.degree. C. or
1000.degree. C. and the temperature differential between the
maximum second combusted gas temperature and the flue gas
temperature was 680.degree. C. or 880.degree. C., the net
efficiency of the heat recovery cycle was assumed to increase 1%
for every 20.degree. C. difference between the maximum second
combusted gas temperature and the temperature of the expanded
combusted gas stream exiting the gas turbine (604.degree. C.),
where the basis for this assumption is the National Coal Council
Issue Paper 2009, Higher Efficiency Power Generation Reduces
Emissions, J. M. Beer, p. 2. The heat recovery efficiency for the
selected fuel streams and supplemental fuel streams at the selected
maximum second combustion gas stream temperatures, the calculated
electrical power produced from the thermal power in the heat
recovery cycle, and the total electrical power of the combined
cycle system for the selected fuel streams is shown in Table
11.
TABLE-US-00011 TABLE 11 Calcu- Calcu- Calcu- lation lation lation
Calcu- Calcu- Calcu- Calcu- Calcu- Calcu- 2 (con- 3 (con- 4 (con-
lation lation lation lation lation lation tinued) tinued) tinued) 5
6 7 8 9 10 H.sub.2S/CH.sub.4/CO.sub.2 content of fuel stream and
100/0/0 50/50/0 33/33/34 100/0/0 100/0/0 50/50/0 50/50/0 33/33/34
33/33/34 supplemental fuel stream (vol. %) Total Thermal Power
available for conversion to 730.5 868.8 819 736.1 743 876.7 884.5
825.8 833 electrical power in the Heat Recovery Cycle (MW.sub.t)
Efficiency of conversion of Thermal Power to 0.387 0.387 0.387
0.487 0.587 0.487 0.587 0.487 0.587 Electrical Power in the Heat
Recovery Cycle Electrical Power from Heat Cycle (MW.sub.e) 282.7
336.2 316.9 358.4 436.1 426.9 519.2 402.2 489.0 Electrical Power
from Gas Turbine Cycle (MW.sub.e) 183 183 183 183 183 183 183 183
183 Total Electrical Power of Combined Cycle System 465.7 519.2
499.9 541.4 619.1 609.9 702.2 585.2 672.0 (MW.sub.e)
The calculations demonstrated that a fuel stream consisting of
H.sub.2S, or containing 50 vol. % H.sub.2S and 50 vol. % CH.sub.4,
or containing 33 vol. % H.sub.2S, 33 vol. % CH.sub.4, and 34 vol. %
CO.sub.2 can be combusted in a combined cycle gas turbine/HRSG with
supplemental firing to produce substantial electrical power.
Example 4
[0098] The electrical power produced by combusting selected fuel
streams in a combined cycle gas-turbine/heat recovery steam
generator system with supplemental firing and capturing electrical
power from cooling the resulting flue gas to 3.degree. C. was
calculated. The selected fuel streams were the fuel streams
utilized in Example 3. The total electrical power produced when
cooling the flue gas stream to 3.degree. C. is the electrical power
calculated in Example 3 plus the additional electrical power
produced from the thermal power available from the flue gas stream
upon cooling the flue gas stream from 120.degree. C. to 3.degree.
C.
[0099] The calculations were performed based on using ammonia as a
heat transfer fluid, where liquid ammonia at a temperature of about
0.degree. C. is contacted in an evaporator with the flue gas stream
exiting the HRSG to cool the flue gas stream from 120.degree. C. to
3.degree. C. and to transfer thermal power from the flue gas stream
to the ammonia, producing an evaporated ammonia heat transfer gas.
The evaporated ammonia heat transfer gas is expanded in an
isentropic expander to convert the thermal power contained therein
to electrical power. The amount of thermal power available for
conversion to electrical power produced by cooling the flue gas
stream from 120.degree. C. to 3.degree. was calculated according to
formula (21):
thermal power of flue gas stream ( 120 .degree. C . 3 .degree. C .
) = { [ ( Heat Capacity of Non - Water Component X ( kJ / kg ) *
Mass Flow Rate of Non - Water Component X in flue gas stream ( kg /
h ) * .DELTA. T 1 ) * ( Heat Capacity of Water Vapor ( kJ / kg ) *
Mass Flow Rate of Water Vapor ( kg / h ) * .DELTA. T 2 ( .degree. C
. ) ) + ( Heat Capacity of Liquid Water ( kJ / kg ) * Mass Flow
Rate of Liquid Water ( kg / h ) * .DELTA. T 3 ( .degree. C . ) ) +
( Mass Flow Rate of Water Vapor ( kg / h ) * Latent Heat of
Condensation of Water ( kJ kg ) ) ] / ( 3600000 ( ( MWt / kJ ) / kg
) ) } ( 21 ) ##EQU00019##
where X ranges from 1 to n, where n is the total number of
non-water components in the flue gas stream, .DELTA.T1 is the
difference between the temperature of the flue gas stream exiting
the HRSG (120.degree. C.) and the temperature of the flue gas
stream exiting the expander (3.degree. C.), .DELTA.T2 is the
difference between the temperature of the flue gas stream exiting
the HRSG (120.degree. C.) and the temperature at which water
condenses (100.degree. C.), .DELTA.T3 is the difference between the
temperature at which water condenses (100.degree. C.) and the
temperature of the flue gas stream exiting the expander (3.degree.
C.), and the latent heat of condensation of water is 2260 kJ/kg.
The gaseous components of the flue gas stream, their heat
capacities, and mass flow rates of these components are the same as
the components of the second combusted gas stream, their heat
capacities, and the mass flow rate of these components in the
second combusted gas stream as set forth in Table 10. Water is
converted to liquid upon cooling the flue gas stream from
120.degree. C. to 3.degree. C.: the mass flow rate of the liquid
water is equivalent to the mass flow rate of water vapor in the
flue gas stream but the heat capacity of liquid water is 4.18
kJ/kg. The electrical power produced by expanding the ammonia heat
transfer gas in an isentropic expander was calculated by
multiplying the calculated thermal power produced by cooling the
flue gas stream from 120.degree. C. to 3.degree. C. by the
isentropic turbine efficiency for producing electrical power from
an ammonia heat transfer gas, where the isentropic turbine
efficiency was assumed to be 0.3. The calculated thermal power
produced by cooling the flue gas stream; the calculated electrical
power produced from the thermal power produced by cooling the flue
gas stream; and the total electrical power of the combined cycle
system including electrical power produced by cooling the flue gas
stream for the selected fuel streams is shown in Table 12.
TABLE-US-00012 TABLE 12 Calcu- Calcu- Calcu- Calcu- Calcu- Calcu-
Calcu- Calcu- Calcu- lation lation lation lation lation lation
lation lation lation 2 (con- 3 (con- 4 (con- 5 (con- 6 (con- 7
(con- 8 (con- 9 (con- 10 (con- tinued) tinued) tinued) tinued)
tinued) tinued) tinued) tinued) tinued) H.sub.2S/CH.sub.4/CO.sub.2
content of fuel stream and 100/0/0 50/50/0 33/33/34 100/0/0 100/0/0
50/50/0 50/50/0 33/33/34 33/33/34 supplemental fuel stream (vol. %)
Total thermal power available for conversion to 141 172 167 141 141
172 172 167 167 electrical power from cooling the flue gas stream
from 120.degree. C. to 3.degree. C. (MW.sub.t) Assumed efficiency
of conversion of thermal power 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3
to electrical power in the ammonia heat transfer gas isentropic
expander Electrical Power from Cooling the Flue Gas Stream 42 52 50
42 42 52 52 50 50 (MW.sub.e) Total Electrical Power of Combined
Cycle System 508 571 550 583 661 662 754 635 722 with Flue Gas
Cooling (MW.sub.e)
[0100] The calculations set forth in Table 12 demonstrated that
considerable more electrical power may be generated by cooling the
flue gas stream to capture the thermal power therein utilizing a
non-aqueous heat transfer gas having a boiling point at least
50.degree. C. less than water and converting the thermal power from
the flue gas stream to electrical power.
[0101] The present invention is well adapted to attain the ends and
advantages mentioned as well as those that are inherent therein.
The particular embodiments disclosed above are illustrative only,
as the present invention may be modified and practiced in different
but equivalent manners apparent to those skilled in the art having
the benefit of the teachings herein. Furthermore, no limitations
are intended to the details of construction or design herein shown,
other than as described in the claims below. While compositions and
methods are described in terms of "comprising," "containing," or
"including" various components or steps, the compositions and
methods can also "consist essentially of" or "consist of" the
various components and steps. All numbers and ranges disclosed
above may vary by some amount. Whenever a numerical range with a
lower limit and an upper limit is disclosed, any number and any
included range falling within the range is specifically disclosed.
In particular, every range of values (of the form, "from about a to
about b," or, equivalently, "from approximately a to b," or,
equivalently, "from approximately a-b") disclosed herein is to be
understood to set forth every number and range encompassed within
the broader range of values. Also, the terms in the claims have
their plain, ordinary meaning unless otherwise explicitly and
clearly defined by the patentee. Moreover, the indefinite articles
"a" or "an", as used in the claims, are defined herein to mean one
or more than one of the element that it introduces.
* * * * *