Integrated air separation plant - integrated gasification combined cycle power generator

An integrated cryogenic air separation unit power cycle system is disclosed wherein the air separation unit (ASU) is operated at elevated pressure to produce moderate pressure nitrogen. The integrated cycle combines a gasification section wherein a carbon source, e.g., coal is converted to fuel and combusted in a combustion zone. The combustion gases are supplemental with nitrogen from the air separation unit and expanded in a turbine. Air to the cryogenic air separation unit is supplied via a compressor independent of the compressor used to supply air to the combustion zone used for combusting the fuel gas generated in the gasifier system.

TECHNICAL FIELD 
In recent years electric utilities have been developing alternative 
technologies for power generation to meet the increased demands of 
society. One alternative technology that is of recent interest is referred 
to as the Integrated Coal Gasification Combined Cycle (IGCC). In this type 
of facility, coal is converted into a liquid or gaseous fuel through 
gasification followed by combustion and expansion of the combusted gases 
in a turbine. Power is recovered from the turbine. A significant advantage 
of an IGCC system is that capacity can be added in stages which permits 
incremental capital expenditures for providing the additional power 
demands of society. In that regard, business decisions become easier. 
Although the IGCC systems permits phasing in terms of providing additional 
capacity and makes decisions easier from a business perspective, it 
presents problems to the design engineer because of the inability to match 
performance and efficiency requirements in the IGCC system. 
One of the earlier integrated IGCC systems involved a cryogenic 
air-separation system and power turbine and is Swearingen U.S. Pat. No. 
2,520,862. The air separation unit was of common design, e.g., it employed 
a liquefaction and dual column distillation system with the dual column 
distillation system having a higher pressure and lower pressure column. 
Low purity, low pressure oxygen generated in the air separation unit was 
used for oxidizing the fuel with the resulting gases being expanded in the 
power turbine. To enhance efficiency of the power turbine, waste 
nitrogen-rich gas was taken from the higher pressure column and mixed with 
the compressed feed air for combustion. Two problems were presented by 
this approach, the first being that it was impossible to independently set 
the pressures of the higher pressure column with that of the inlet 
pressure to the turbine to achieve an optimum operating efficiency for 
both the air separation unit and for the power turbine and, secondly, 
nitrogen separation in the lower pressure column was inefficient due to 
the lack of nitrogen reflux available for that column. 
Coveney in U.S. Pat. No. 3,731,495 disclosed an IGCC comprising an 
integrated air separation unit and power system wherein the cryogenic air 
separation unit employed a conventional double-column distillation system. 
In contrast to Swearingen, Coveney quenched combustion gases with a waste 
nitrogen-rich gas obtained from the lower-pressure column. However, in 
that case, it was impossible to independently control the pressure in the 
lower pressure column and the pressure at the inlet to the power turbine. 
As a result it was impossible to operate the lower pressure column and the 
turbine at its optimum pressures. 
Olszewski, et al. in U.S. Pat. No. 4,224,045 disclosed an improved process 
over the Coveney and Swearingen processes wherein an air separation unit 
was combined with a power generating cycle. Air was compressed via a 
compressor with one portion being routed to the air separation unit and 
the other to the combustion zone. In order to nearly match the optimum 
operating pressures of the air separation unit with the optimum operating 
pressures of the power turbine cycle, waste nitrogen from the lower 
pressure column was boosted in pressure by means of an auxiliary 
compressor and then combined with the compressed feed air to the 
combustion unit or to an intermediate zone in the power turbine itself. 
Through the use of the auxiliary nitrogen compressor there was an inherent 
ability to boost the nitrogen pressure to the combustion zone independent 
of operation of the air separation unit. By this process, Olszewski was 
able to more nearly match the optimum pressures for the air separation 
unit and power turbine systems selected. 
One problem associated with each of the systems described above is that 
even though the air separation units were integrated into an IGCC power 
generating system, the processes were not truly integrated in the sense 
that the air separation unit and IGCC power system were able to operate at 
their optimum pressures independent of each other. Although Olszewski 
reached a higher degree of independent operability than Coveney and 
Swearingen, the process scheme was only suited for those processes wherein 
air was taken from the air compression section of the gas turbine and used 
for the air feed to the air separation unit. The air inlet pressure to the 
air separation unit could be varied by using either a turbo expander on 
the air inlet stream or a booster compressor. Although it was possible to 
obtain an optimum pressure in the air separation system in the Olszewski 
process, for example, each prior art process received a part or all of the 
feed for the air separation unit from the gas turbine compressor section. 
However, the inlet pressure to the Olszewski air separation unit required 
a lower-pressure rectification stage having a pressure of at least 20 psi 
lower than the optimum ignition pressure in the combustion zone. In many 
cases enhanced operating efficiences of the lower pressure column in the 
air separation unit may require a higher operating pressure than available 
in Olszewski, et al., particularly when moderate pressure nitrogen is 
desired. 
SUMMARY OF THE INVENTION 
This invention pertains to an improved integrated gasification combined 
cycle for power generation. The integrated gasification combined cycle 
power generation system incorporating an air separation unit, a 
gasification system for partial oxidation of a carbon containing fuel to 
produce a fuel gas and a gas turbine combined cycle power generation 
system which comprises 
a) independently compressing feed air to the air separation unit to 
pressures of from 8 to 20 bar; 
b) cryogenically separating the air in a process having at least one 
distillation column operating at pressures of between 9 and 20 bar; 
c) producing a lower purity oxygen stream and utilizing at least a portion 
of such oxygen stream for effecting gasification of a fuel; 
d) generating a fuel gas in from a carbon containing fuel source by partial 
oxidation; 
e) removing nitrogen gas from the air separation unit and boosting the 
pressure of at least a portion thereof to a pressure substantially equal 
to that of the fuel gas stream onto a pressure for introduction to the gas 
turbine between its compressor discharge and expander inlet; and 
f) expanding at least another portion of the balance of the nitrogen rich 
gas stream in an expansion engine and obtaining either shaft power or 
refrigeration or both. 
It is an object of the invention to provide an arrangement for the 
integration of an air separation unit with an integrated gasification 
combined cycle power generation system such that the optimum pressure and 
hence efficiency can be achieved for both the air separation unit and the 
gas turbine system by using a stand-alone air compressor for the air 
separation system while feeding compressed nitrogen from the low pressure 
column of the air separation unit into the gas turbine between the gas 
turbine compressor discharge and the expander inlet, or mixing it with the 
fuel gas entering the combustion chamber or by a combination of these 
routes. Another object is to employ an air separation unit design in which 
air is compressed to an elevated pressure of between 8 to 20 bar abs and 
substantially all of the air is separated into oxygen and nitrogen which 
are fed to the gasifier gas turbine auxilliary expander on the ASU or are 
used internally in the ASU.

DETAILED DESCRIPTION OF THE INVENTION 
Referring to the drawing an air separation unit defined within the 
boundaries of Box 1 is described as follows: 
The air separation unit generally comprises a single column or double 
column distillation system with a high pressure column linked at its top 
end in heat exchange relationship via a reboiler condenser with a low 
pressure distillation column. The important feature of the air separation 
unit is that it operates at an elevated air inlet pressure of 8 to 20 bar 
absolute, giving optimum separation in a simple double column for the 
production of low purity oxygen in the range of 85 to 98% oxygen with 
substantially all of the feed air being separated into an oxygen product 
stream and nitrogen product stream at elevated pressure. 
A feed air stream is fed via line 10 to a main air compressor 12 and 
compressed to pressures of from about 8 to 20 bar. Typically, the pressure 
will range from 9 to 14 bar. After compression, the feed air stream is 
aftercooled, usually with an air cooler or water cooler, removed via line 
14, and then processed in contaminant removal unit 16 for the purpose of 
removing any contaminants which would freeze at cryogenic temperatures. 
Typically, the contaminant removal unit 16 will comprise an adsorption 
mole sieve bed for removing water and carbon dioxide although other means 
for removing such contaminants may be utilized. The compressed, water and 
carbon dioxide free air is then fed to a main heat exchanger 20 via line 
18 where it is cooled to near its dew point. The cooled feed air stream is 
then removed via line 21 and fed to the bottom of a double column 
distillation system comprising a high pressure column 22 and a low 
pressure column 24 for separation of the feed air into a nitrogen overhead 
stream and an oxygen-enriched bottoms liquid. 
High pressure column 22 operates within a pressure range from 8 to 20 bar, 
preferably from 9 to 14 bar. A crude liquid oxygen stream is obtained as a 
bottoms and nitrogen vapor is obtained as an overhead. The nitrogen 
overhead obtained at the top of high pressure column 22 is conveyed via 
line 25 and split into two substreams. The first substream is fed via line 
26 to reboiler/condenser 28 located in the bottom portion of the low 
pressure column 24 wherein it is liquefied and then returned to the top of 
high pressure column 22 via line 30 to provide reflux for the high 
pressure column. The second substream is removed from high pressure column 
22 via line 32 warmed in main exchanger 20 to provide refrigeration and 
removed from the process as a gaseous nitrogen stream (GAN) via line 34. 
This high pressure nitrogen stream then is boosted in pressure through the 
use of compressor 36 and passed via line 37 for addition to a gasifier 
unit to be described. 
An oxygen-enriched liquid is removed from the bottom of high pressure 
column 22 via line 38, reduced in pressure and charged to low pressure 
column 24. A vaporized oxygen-enriched waste stream is removed from the 
overhead of the sump area surrounding reboiler/condenser 28 via line 40 
wherein it is warmed in main heat exchanger 20 and removed via line 42. 
The resultant oxygen vapor in line 42 is compressed in auxiliary 
compressor 46 and delivered via line 48 for effecting gasification of a 
carbon containing fuel source such as pulverized coal in the gasifier to 
be described. 
With an air inlet pressure to the high pressure column of from 8 to 20 bar, 
the low pressure column will operate at pressures from 2 to 8 bar. These 
pressures give efficient separation of air in the low pressure column to 
produce oxygen at from 85 to 98% purity, and preferably from 93% to 98% 
purity, while allowing the production of nitrogen product stream having 
low oxygen content of from 0.1 to 2% oxygen and preferably from 0.1 to 1% 
oxygen. All streams leave the cold box at elevated pressure. Reflux to low 
pressure column 24 is provided by withdrawing a nitrogen-rich stream from 
an intermediate point in high pressure column 22 via line 50, expanding 
that high pressure nitrogen fraction and then introducing that fraction 
near the top of low pressure column 24. 
A nitrogen stream is removed from the top of low pressure column 24 via 
line 55 and warmed. The warmed nitrogen stream in line 56 is split into 
two portions. One portion is introduced into the gas turbine between the 
gas turbine compressor outlet, and the expander inlet or into the fuel 
stream in order to maximize the flowrate of gases entering the expander 
section of the gas turbine subject to design limitations. The use of 
injected nitrogen further acts to reduce NO.sub.x formation by reducing 
adiabatic flame temperatures. The use of nitrogen addition ensures maximum 
overall power production efficiency and is superior to the inherent 
practice of injecting water into the system to suppress NO.sub.x formation 
and maximize power output. Discharge pressures of compressor 58 range from 
10 to 30 psia. At least a portion, but generally the balance of the 
nitrogen stream, is removed via line 62, heated using available heat 
energy, and expanded in an expansion engine 64 for obtaining additional 
shaft power. The exhaust is removed via line 66. Alternatively, this 
nitrogen stream can be passed through an additional cold expander within 
the ASU to produce refrigeration for LOX/LIN production. Refrigeration for 
the air separation unit is supplied by splitting the feed air into two 
parts with one part in line 21 going to the distillation system as 
described. The other part in line 70 is expanded in expansion engine 72 
and the expanded gas removed via line 54 and introduced to low pressure 
column 24. 
The gasifier section is generally defined within Box 2. Gasification of 
coal or other fuel to produce fuel gas is well known and any of these 
processes can be used. In a coal gasification process, for example, coal 
is pulverized and mixed with high pressure oxygen and high pressure 
nitrogen at high temperatures and converted to a gaseous fuel. Any solid 
residue from the gasifier generally is removed as slag (not shown). A fuel 
gas is generated in the gasifier unit and is removed via line 100. From 
there it is passed to mixing unit 102 wherein it is mixed with high 
pressure nitrogen being introduced through line 104. The resulting mixture 
then is ready for combustion. The addition of nitrogen at this point 
effects dilution of the fuel gas to reduce combustion temperatures and 
reduce NO.sub.x formation. Optionally, the nitrogen or portion thereof 
could have been introduced to the power turbine. This routing is simply a 
matter of choice. 
The power cycle is described in the area defined as Box 3. Air is 
introduced via line 200 to compressor 202 and compressed to a pressure of 
from 7 to 25 bar. This compressed air is removed via line 204 and sent to 
a combustion chamber or combustion zone 206 wherein the air is contacted 
with the fuel mixture generated in mixing zone 102 and the mixture is 
ignited. Hot gases are removed from combustion zone 206 via line 208 
wherein the gases are expanded in a dual expansion engine consisting of 
expanders 210 and 212. Expanded gases are then removed via line 214 
wherein the residual heat is recovered in a heat recovery stream 
generation scheme comprising waste heat boiler 216. The heat recovered 
from waste heat boiler 216 can be used to generate high and low pressure 
steam and used to generate power in conventional steam turbine systems 
(not shown). 
The above integrated air separation unit-IGCC power cycle through the 
independent compressor systems for providing air to the air separation 
unit and to the combustion chamber permits the selection of operating 
pressures which are optimum for both the air separation unit and 
combustion processes. In addition the quantities of air introduced to each 
unit can be more closely controlled to match nitrogen and oxygen 
requirements, whereas in the past a portion or all of the feed air to the 
air separation unit was supplied by the compressor system for the 
combustion chamber. The inlet air to each system was at equal pressures. 
Not only does this limit the air volume control, but also the pressure by 
this combined system. In some cases where there was insufficient nitrogen 
available for providing optimum flow rates in the gas turbine and water 
was added which reduces efficiency. 
The following examples are provided to illustrate preferred embodiments of 
the invention and are not intended to restrict the scope thereof. 
EXAMPLE 1 
An air separation unit-LGCC was constructed in accordance with the drawing. 
Table 1 provides stream flowrates and properties. 
TABLE 1 
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PRES- COMPO- 
STREAM FLOW SURE TEMP SITION 
NO. LBMOL/HR BAR DEG F. % OXYGEN 
______________________________________ 
10 16060 1.01 60 21 
18 15739 11.7 75 21 
37 1110 10.9 65 0.5 
42 3432 3.5 65 95 
48 3432 3.5 90 95 
56 11048 3.4 65 98 
60 5334 18.4 446 98 
62 5714 3.4 218 98 
100 12698 18.4 570 
200 100000 1.01 60 21 
204 100000 14.4 724 21 
208 112000 14.4 2200 13 
214 112000 1.03 1137 13 
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After heating using available heat energy, i.e. heat of compression of the 
air compressor to the air separation unit. 
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Fuel Gas Composition Percent 
______________________________________ 
Nitrogen 1.9 
Argon 1.9 
Carbon Monoxide 65.0 
Carbon Dioxide 1.2 
Hydrogen 10 
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The following table gives a comparison between the Olszewski process, with 
either total air separation unit feed or partial feed from the gas turbine 
(GT) compressor, and the process according to the present invention, with 
a stand alone air compressor. Note that in each case the ratio of gas 
turbine expander to compressor flow is 1.12, as in Table 1. The total air 
bleed case uses water injection into the combustion chamber of the gas 
turbine to reach the required gas turbine expander flow. 
TABLE 2 
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Steam Turbine 
Case Power (MW) % Efficiency 
______________________________________ 
Stand Alone ASU - Ex. I 
217.4 44.0 
Partial Air Feed From GT 
218.2 44.1 
(no water) 
Total Air Feed From GT 
235 40.5 
(water addition) 
______________________________________ 
The above results show comparable results in terms of power and efficiency 
for the Example 1 and partial air feed from the gas turbine. However, 
through the independent control in the stand alone system enhanced 
efficiencies may be achieved at alternative separation pressures.