Combined cycle power plant having improved cooling and method of operation thereof

An improved combined cycle power plant (10) having a plurality of kettle boilers (30,31,32) used in sequence for cooling the compressed air being directed via line (29) to cool portions of the gas turbine (20). The kettle boilers remove heat from the compressed air and produce a plurality of steam flows in lines (70,71,73) at pressures in parallel with the heat recovery steam generator (41,42,43) steam flows. Steam in line (72) for cooling other portions of the gas turbine is maintained at a very high level of purity by providing a high rate of blowdown through line (65) from the steam drum (45) providing the steam. Heat from the blowdown flow is directed to heat exchanger (66) to heat incoming fuel gas from source (26), or alternatively to heat the condensate via line (74) during periods of fuel oil operation.

FIELD OF THE INVENTION 
This invention relates to the field of combined cycle power plants having a 
combustion turbine system which produces electricity and exhaust gas, a 
heat recovery steam generator which uses the exhaust gas from the 
combustion turbine system to produce steam, and a steam turbine which uses 
the steam to produce electricity. The invention relates more particularly 
to an improved apparatus and method for cooling a combined cycle power 
plant. The invention relates in particular to an apparatus and method for 
providing both cooled compressed air and highly pure steam for cooling of 
an advanced combustion turbine system while simultaneously reducing the 
waste heat produced and improving the overall efficiency of the plant. 
BACKGROUND OF THE INVENTION 
Combined cycle power plants are known in the art as an efficient means for 
converting fossil fuels to thermal, mechanical and/or electrical energy. 
Such systems are described in U.S. Pat. No. 4,932,204 dated Jun. 12, 1990; 
U.S. Pat. No. 5,255,505 dated Oct. 26, 1993; U.S. Pat. No. 5,357,746 dated 
Oct. 25, 1994; U.S. Pat. No. 5,431,007 dated Jul. 11, 1995; and U.S. Pat. 
No. 5,697,208 dated Dec. 16, 1997; each of which is incorporated by 
reference herein. 
It is known in the art to use air from the outlet of the compressor section 
of a gas turbine system to cool selected turbine parts, and further, it is 
known to cool the compressed air after it leaves the compressor and before 
reintroducing it into the turbine. Typical prior art methods for cooling 
this air are discussed in the above mentioned U.S. Pat. No. 5,697,208. 
These include using a fin/fan heat exchanger that would discharge the 
removed heat into the atmosphere as waste, or using this energy to 
pre-heat fuel for the gas turbine. As the compression ratios of 
compressors have increased, the temperature of the compressed air produced 
by the compressor has increased. At the same time, the cooling 
requirements for the hot turbine parts has increased due to increased 
firing temperatures. Most recently, it has become known in the art to cool 
this compressed air by passing it through a once-through cooler, and using 
the heat to generate high pressure steam. However, such prior art systems 
do not provide optimal levels of cooling for combined cycle power plants 
utilizing the most modern engine designs. 
Due to high firing temperatures and the need to design higher efficiency 
combustion turbines, efficient methods for cooling hot components with the 
combustion turbine have been developed. One particular cooling scheme that 
has been developed passes steam through very small cooling passages in 
various parts of the turbine. These passages may be subject to blockage if 
the cooling steam is not maintained at a very high purity level. 
Furthermore, exotic alloys are being developed and used for these higher 
temperature applications. These materials may be subject to degradation if 
the cooling steam is not very pure. The source of cooling steam in prior 
art applications is often the intermediate pressure steam produced in the 
heat recovery steam generator. With a traditional blowdown scheme and for 
the pressure range in which the intermediate pressure evaporator may 
typically operate, the American Boiler Manufacturers Association (ABMA) 
recommends a maximum concentration of total dissolved solids (TDS) of 
about 2,500 ppm within the drum. The maximum fractional carryover 
recommended by the ABMA for this typical pressure is 0.0005. This 
corresponds to a steam TDS of about 1 ppm which is unacceptable for some 
new steam cooled combined cycle plant applications. Prior to this 
invention, the steam purity has been improved by improving the quality of 
the incoming feedwater to maintain the concentration of impurities in the 
drum to low levels. This is done by using condensate polishing systems. 
Such systems have proven to be expensive and unable to provide the desired 
steam quality. 
There is also an ongoing need to reduce the boiler blowdown flow from 
combined cycle plants. Waste water is both difficult to dispose of and 
expensive to replace as makeup to the cycle. As such, it is advantageous 
to offer a power plant design which has the lowest level of boiler 
blowdown flow. 
The market continues to demand increasing efficiency from combined cycle 
power plant designs. Modern advanced turbine systems have plant efficiency 
goals of 60% and more. To achieve such levels of performance, system 
designs must incorporate even higher compression ratios and higher 
combustion temperatures, as well as advanced cooling techniques with new 
exotic metals capable of withstanding such operating conditions. 
Furthermore, system designs which waste heat to the environment are no 
longer favored for both environmental and efficiency reasons. 
SUMMARY 
Accordingly, it is an object of this invention to provide a combined cycle 
power plant, and a method for operating the same, that has improved means 
for cooling of the combustion turbine system in order to provide improved 
thermal efficiency, reduced water and heat discharge to the environment, 
and higher quality cooling steam. 
In order to achieve the above and other objects of the invention, a 
combined cycle power plant according to one aspect of this invention 
includes a combustion turbine system having a compressor for providing 
compressed air, a combustor for combusting a fuel in said compressed air 
to produce combustion air, and a gas turbine for expanding said combustion 
air to produce mechanical energy and exhaust gas; a steam generator having 
an inlet for receiving said exhaust air and a plurality of sections 
located sequentially in a flow path of said exhaust gas for removing heat 
from said exhaust gas to produce a first plurality of steam flows at a 
plurality of pressures; a steam turbine having a plurality of inlets for 
receiving said first plurality of steam flows; a cooling air flow path for 
directing a portion of said compressed air to said gas turbine for cooling 
of a portion thereof; wherein said cooling air flow path further comprises 
a plurality of boilers arranged in sequence for receiving said portion of 
said compressed air and for removing heat from said portion of said 
compressed air to produce a second plurality of steam flows. A combined 
cycle power plant according to another aspect of this invention may also 
have a means for providing cooling steam from a first of said sections to 
said combustion turbine system; and a means for providing a blowdown flow 
from said first of said sections to a second of said sections. According 
to another aspect of this invention, the plant may also have a heat 
exchanger operable to transfer heat from said blowdown flow to said fuel, 
and further a means for bypassing said blowdown flow around said heat 
exchanger when said fuel is a fuel other than fuel gas.

DESCRIPTION OF THE PREFERRED EMBODIMENTS 
Referring to FIG. 1, there is shown a combined cycle power plant 10 having 
a combustion turbine system 20, a heat recovery steam generator 40, and a 
steam turbine system 60. 
Combustion turbine system 20 is shown to have an air inlet 22, a compressor 
23, a combustor 24, and a gas turbine 25. During operation, the compressor 
23 receives ambient air from the air inlet 22 and delivers compressed air 
to the combustor 23 where it is combined with fuel supplied from a fuel 
source 26 via line 34 to form hot combustion air. The hot combustion air 
is then expanded in the gas turbine 25 to provide mechanical energy to an 
electrical generator 27 via shaft 28 and an exhaust gas. 
Exhaust gas from the gas turbine 25 is directed via duct 33 to the heat 
recovery steam generator 40. Within the heat recovery steam generator 40, 
the exhaust gas comes in sequential contact with a plurality of steam 
generator sections such as high pressure (HP) steam generator section 41, 
intermediate pressure (IP) steam generator section 42, and low pressure 
(LP) steam generator section 43. Each steam generator section includes a 
drum 44,45,46 at its upper end where the steam/water interface is 
maintained. Feedwater is provided to the LP steam generator section 43 
from a condensate supply 11 through an LP economizer 12. Feedwater is 
provided to the IP steam generator section 42 and the HP steam generator 
section 41 from the drum 46 of the LP steam generator section via line 14 
by a boiler feed pump 15. These feedwater supplies are directed through an 
IP economizer 16 and an HP economizer 17 respectively. The steam generator 
sections remove heat from the flow of exhaust gas and produce a plurality 
of steam flows at a plurality of pressures; such as for example, 1800 psia 
(124.0 Bar) at the HP steam generator outlet, 460 psia (31.7 Bar) at the 
IP steam generator outlet, and 50 psia (3.4 Bar) at the LP steam generator 
outlet. 
A portion of the compressed air from the compressor 23 is directed via line 
29 to the turbine 20 for use in cooling selected portions of the gas 
turbine 25, such as the turbine stationary vanes or rotating shaft and/or 
blades (not shown). In accordance with the current invention, the hot 
compressed air is directed via line 29 sequentially through a plurality of 
kettle boilers, such as high pressure boiler 30, intermediate pressure 
boiler 31, and low pressure boiler 32 to produce cooled compressed air 
which is then directed to the turbine 25. These boilers may be tube and 
shell type heat exchangers having the compressed air on the tube side and 
water/steam on the shell side, and they may be located external to the 
heat recovery steam generator as shown in FIG. 1, or may be constructed as 
part of the heat recovery steam generator 40. The operating pressures of 
the HP, IP and LP kettle boilers 30,31,32 correspond to the steam 
pressures of the HP, IP and LP steam generator sections 41,42,43 
respectively of the heat recovery steam generator 40. Feedwater for the 
kettle boilers 30,31,32 is drawn from either the corresponding steam 
generator section 41,42,43 via lines 47,48,49, or from the boiler feed 
pump discharge (not shown). The boilers 30,31,32 serve to transfer heat 
from the hot compressed air within the tubes to the shell side feedwater, 
thereby cooling the compressed air and producing a plurality of steam 
flows at a plurality of pressures in parallel with the HP steam generator 
section 41, IP steam generator section 42 and LP steam generator section 
43, respectively. Steam that is produced by the boilers 30,31,32 is 
directed to the corresponding HP, IP or LP drum 44,45,46, or as shown in 
FIG. 1 is joined with the steam flow from the steam generator sections 
41,42,43 via lines 70,71,73. Recovering heat energy from the hot 
compressed air by producing steam in a plurality of boilers 30,31,32 
operating at a plurality of pressure levels in parallel with the heat 
recovery steam generator sections 41,42,43 is a very efficient means of 
providing sufficiently cooled air for cooling of the gas turbine 25 while 
at the same time improving the overall cycle performance. 
The plurality of kettle boilers 30,31,32 also provides a means for reducing 
the total system blowdown from a combined cycle power plant 10. As 
discussed above, lines 47, 48, 49 provide feedwater to the boilers 
30,31,32 from the respective steam generator drums 44,45,46. Solids 
accumulating in the drums 44,45,46 as a result of the process of 
evaporation are removed via lines 47,48,49 to the respective boiler. A 
blowdown flow is provided via line 50 from the high pressure boiler 30 to 
the intermediate pressure boiler 31. Similarly, a blowdown flow is 
provided via line 51 from the intermediate pressure boiler 31 to the low 
pressure boiler 32. A system blowdown flow is provided via line 52 from 
the low pressure boiler 32 to a blowdown tank 53. The blowdown tank 53 is 
drained via line 54 vented via line 55. Blowdown flow through line 52 is 
the entire system blowdown. Because of the natural concentration of solids 
and other non-volatile contaminants which occurs in each of the boilers, 
there is a sequential concentration of the system blowdown flow as it 
passes from the high pressure boiler 30, through the intermediate pressure 
boiler 31, to the low pressure boiler 32. By taking the entire system 
blowdown flow from the low pressure boiler 32, the contaminants from each 
of the steam generator drums 44,45,46 and each of the boilers 30,31,32 is 
concentrated in a single system blowdown flow. By taking advantage of the 
concentration action of a plurality of kettle boilers, the current 
invention provides a means for reducing the overall system blowdown flow, 
thereby minimizing the amount of water and heat which is passed to the 
environment through the blowdown tank 53. By example, a prior art plant 
which may produce a typical system blowdown flow of 6,500 lbs/hr (0.82 
kg/sec) could be designed in accordance with this invention to have a 
total system blowdown flow in the range of only 500-550 lb/hr (0.063-0.069 
kg/sec). 
As is known from the prior art, steam from the high pressure steam 
generator section 41 and the low pressure steam generator section 43 are 
directed to a high pressure steam turbine 61 and a low pressure steam 
turbine 62 respectively. In accordance with the current invention, steam 
from the high pressure kettle boiler 30 is provided via line 70 and from 
the low pressure kettle boiler 32 via line 71 to be combined with these 
steam flows and also directed to the high pressure and low pressure steam 
turbines 61,62 respectively. These turbines expand their respective steam 
flows to develop mechanical energy to turn shaft 63, thereby driving 
electrical generator 64. 
As is known from the prior art, steam may be drawn from either the high 
pressure steam generator section 41 (in the form of cold reheat steam) or, 
as shown in FIG. 1, the intermediate pressure steam generator section 42, 
and may be directed via line 72 to cool parts of the gas turbine system 
20, such as the combustor transition piece or turbine blades and vanes 
(not shown). In accordance with the current invention, steam from the 
intermediate pressure kettle boiler 31 is provided via line 73 and is 
combined with the steam from the intermediate pressure steam generator 
section 42 to cool parts of gas turbine 25. To maintain the desired level 
of quality in this cooling steam, the dissolved solids of the steam must 
be maintained to a predetermined level which satisfies the design 
requirements for the particular plant. An advanced combustion turbine 
system design may, for example, limit the sodium in the cooling steam to 
no more than 0.1 ppb or even 0.01 ppb, which is two orders of magnitude 
change from the typical prior art allowable range of 1-10 ppb of sodium. 
To achieve this level of steam quality, the present invention controls the 
steam quality by providing a connection for blowdown of the intermediate 
pressure steam generator section 42 (or high pressure steam generator 
section if that is the source of the cooling steam) at a high rate of 
flow. Such a connection for a high rate of blowdown flow is shown in FIG. 
1 as line 65, and it may be sized to provide a blowdown flow rate which is 
in the range of 30-40%, or advantageously at least 33%, of the feedwater 
flow rate to that steam generator section. The use of such a high rate of 
blowdown flow will result in a reduction of dissolved solids in the IP 
drum 45 and will achieve the desired levels of dissolved solids in the 
steam, such as limiting the dissolved sodium to no more than 0.1 ppb or 
even 0.01 ppb. 
Prior art combined cycle plants typically utilized a phosphate chemistry to 
control the pH in the HP and IP steam generator drums 44,45. Prior art 
plants typically utilized an all-volatile treatment (AVT) in the LP steam 
generator drum 46, since the high rate of outflow from that drum used to 
feed the HP and IP steam generator sections 44,45 made the control of 
phosphates impractical. A combined cycle plant built in accordance with 
this invention will use AVT chemistry control in both the LP steam 
generator drum 46 and the drum from which the cooling steam is drawn (the 
IP drum 45 as shown in FIG. 1) since the high rate of blowdown flow will 
make phosphate chemistry control impractical. 
The high rate of blowdown flow may be directed by line 65 to a fuel gas 
heat exchanger 66, where heat energy is transferred from the blowdown flow 
to an incoming flow of fuel from fuel source 26 which may be supplying 
fuel gas, thereby pre-heating the fuel gas. The temperature of the 
blowdown flow from the intermediate pressure steam generator section 42 
may typically be in the range of 450-475 degrees F. (232-246 degrees C.), 
which when used in a typical fuel gas heat exchanger 66 will achieve a 
fuel gas temperature of approximately 400 degrees F. (204 degrees C.). If 
the HP steam generator section 41 is used as the source for the cooling 
steam, the blowdown flow may be in the range of 630-640 degrees F. 
(332-338 degrees C.), thereby permitting the fuel gas to be heated to a 
temperature of approximately 600 degrees F. (316 degrees C.) These 
elevated fuel temperatures result in improved combustion efficiencies, and 
the use of this heat to raise the temperature of the fuel gas prevents it 
from being wasted to the environment. 
The blowdown flow leaving the fuel gas heat exchanger 66 is recirculated to 
the LP economizer 12 inlet of the heat recovery steam generator 40 via 
line 67. For typical combined cycle plant operation, the temperature of 
the water from the condensate supply 11 may be approximately 100 degrees 
F. (38 degrees C.). To maintain the tubes in the heat recovery steam 
generator 40 above the carbonic acid dew point, it is necessary to 
maintain the condensate at a temperature of between 120-140 degrees F. 
(49-60 degrees C.). By recirculating blowdown via line 67 to the 
condensate inlet in accordance with this invention, the need for 
additional condensate pre-heating is minimized. 
It is also known to provide a combined cycle power plant with the 
capability of operating on fuel gas and on a fuel other than fuel gas, 
such as fuel oil. During operation of the combined cycle plant 10 on oil 
fuel, sulfuric acid condensation on the cold end tubes of the heat 
recovery steam generator 40 becomes a problem due to the higher 
concentration of sulfur in fuel oil than in fuel gas. For oil operation, 
the last stage of the heat recovery steam generator is typically bypassed 
and the low pressure drum 46 is used as a direct contact heat exchanger. 
Because the duty required to heat the condensate to a temperature above 
the sulfuric acid dew point is typically greater than what the low 
pressure circuit can support, intermediate pressure steam is often used in 
the prior art to "peg" the low pressure drum 46 pressure, in other words, 
to add heat to the low pressure circuit. For a plant built in accordance 
with the current invention, this pegging steam requirement can be 
eliminated by providing a means for bypassing the fuel gas heat exchanger 
66 during oil fuel operation. In FIG. 1 such a means for bypassing the 
fuel gas heat exchanger 66 is shown as valve 69 and line 74. During oil 
operation, the fuel gas heat exchanger 66 is bypassed but blowdown water 
is still drawn from the intermediate pressure drum 45 at a flow rate which 
is the same as, or is close to, that drawn during fuel gas operation. The 
hot blowdown water recirculates to the LP system either via the condensate 
piping or, as shown in FIG. 1, directly to the LP drum 46 via line 74, 
thereby pre-heating the feedwater which enters the low pressure drum 46, 
and in doing so acts as the supplemental heat source to the low pressure 
circuit. Also, by drawing similar flow rates of blowdown for both modes of 
fuel operation, stability is maintained in the IP economizer section 16 
which otherwise might experience steaming were the flow rate reduced. 
Other aspects, objects and advantages of this invention may be obtained by 
studying the FIGURE, the disclosure, and the appended claims.