Gland steam condenser for combined cycle power plants and its operating method

Abstract

To provide systems and methods that enable a gland steam condenser to be fluidly isolated from a condensate extraction pump so that the gland steam condenser may be installed with consistent design specifications.SOLUTION: A steam turbine 104 receives steam 140 from an HRSG 130. A primary condenser 162 is fluidly coupled to the steam turbine 104 and receives a first portion 164 of exhaust steam from the steam turbine. A gland steam condenser 176 is fluidly coupled to the steam turbine 104 and receives a second portion 172, 173 of exhaust steam from the steam turbine. A cooling module 182 is fluidly coupled to the gland steam condenser 176 and supplies a cooling fluid 180 to the gland steam condenser. The cooling module 182 is fluidly isolated from a condensate extraction pump 168.SELECTED DRAWING: Figure 1

Description

Technical Field

[0001] The present disclosure generally relates to a main steam condenser, and more particularly to a system and method for operating a main steam condenser in a combined cycle power plant.

Background Art

[0002] The steam gas turbine of a combined cycle power plant uses a primary condenser that condenses the main exhaust steam and a main steam condenser that helps control leakage of exhaust steam that can occur during operation of the steam gas turbine. Known main steam condensers operate at a negative pressure with respect to the ambient environment, whereby the main steam condenser receives a mixture of steam and air from the steam gas turbine. Air is extracted from the mixture using a centrifugal blower, and steam is extracted from the mixture using a heat exchanger containing cooling feed water.

[0003] In a conventional combined cycle power plant, a condensate extraction pump supplies cooling feed water from the primary condenser to the main steam condenser and supplies water to a feed water pump. The feed water pump discharges water into a heat recovery steam generator to generate steam for a steam turbine. Since the condensate extraction pump supplies both the main steam condenser and the feed water pump, the main steam condenser system usually has to be redesigned each time it is installed according to the operating parameters of the condensate extraction pump. Also, in some combined cycle power plant systems, the main steam condenser has to operate continuously to keep the steam turbine under vacuum overnight. To operate the main steam condenser continuously, the condensate extraction pump also has to operate continuously.

[0004] For example, at least some known gland steam condensers operate under rising temperatures and pressures, require high-throughput feedwater, and become a parasitic load on the output of a combined cycle power plant due to their continuous operation, thereby reducing the overall efficiency of the power plant. Furthermore, the operating parameters of a gland steam condenser can unnecessarily burden the condensate extraction pump, and a large amount of relatively high-pressure water may be required within the gland steam condenser. Additionally, in some known power plants, the gland steam condenser is the only condenser that uses water supplied from the primary condenser as a cooling source. [Overview of the Initiative]

[0005] In one embodiment, a combined cycle power plant is provided. The power plant includes a gas turbine engine, a heat recovery steam generator, a steam turbine, a primary condenser, a condensate extraction pump, a gland steam condenser, and a cooling module. The heat recovery steam generator generates steam. The steam turbine is fluid-coupled to the heat recovery steam generator and receives steam from the heat recovery steam generator. The primary condenser is fluid-coupled to the steam turbine and receives a first portion of exhaust steam from the steam turbine and condenses the exhaust steam into a liquid. The condensate extraction pump is fluid-coupled to the primary condenser and receives a first portion of the condensed exhaust steam. The gland steam condenser is fluid-coupled to the steam turbine and receives a second portion of exhaust steam from the steam turbine and condenses the exhaust steam into a liquid. The cooling module is fluid-coupled to the gland steam condenser and supplies cooling fluid to the gland steam condenser. The cooling module is fluid-isolated from the condensate extraction pump.

[0006] In another embodiment, a gland steam condenser for a combined cycle power plant is provided. The gland steam condenser is fluidly coupled to a sealed cooling water fin fan cooler.

[0007] In yet another embodiment, a method for operating a combined cycle power plant is provided. This method includes generating steam in a heat recovery steam generator. This method also includes sending the steam from the heat recovery steam generator to a steam turbine. This method further includes sending a first portion of the exhaust steam from the steam turbine to a primary condenser and a condensate extraction pump. This method further includes sending a second portion of the exhaust steam into a gland steam condenser. Finally, this method includes sending a cooling fluid from a cooling module to the gland steam condenser to condense the second portion of the exhaust steam, the cooling module being fluidly isolated from the condensate extraction pump. [Brief explanation of the drawing]

[0008] [Figure 1] This is a schematic diagram of an example combined cycle power plant. [Figure 2] Figure 1 is a schematic diagram of an example cooling system used in a combined cycle power plant. [Figure 3] This flowchart illustrates an exemplary method for operating a combined cycle power plant. [Modes for carrying out the invention]

[0009] Embodiments described herein relate to systems and methods for operating a gland steam condenser in a power plant. Specifically, in the systems and methods described herein, steam generated from feedwater in a heat recovery steam generator (HRSG) is circulated through various components of a steam turbine, and a first portion of the exhaust steam is sent to a primary condenser and then to a condensate extraction pump. The condensed first portion of the exhaust steam is sent from the condensate extraction pump to a feedwater pump and then back to the HRSG. A second portion of the exhaust steam, which is leaky steam from the components of the steam turbine and high-pressure exhaust steam, is sent to a gland steam condenser as a mixture of air and steam. In the gland steam condenser, the steam is condensed from the mixture using a cooling fluid supplied from a cooling module, and the air is removed using a centrifugal blower. The cooling module is fluidically isolated from the condensate extraction pump. In some embodiments, the cooling module is also coupled to other components in the power plant that require cooling fluid, such as generator coolers and lubricating oil coolers. Therefore, the systems and methods described herein allow for the fluid isolation of the gland steam condenser from the condensate extraction pump, thus enabling the installation of the gland steam condenser in a consistent design specification.

[0010] Unless otherwise specified, the approximation terms used herein, such as “generally,” “substantially,” and “approximately,” indicate that the terms thus modified may apply only to an approximate degree as recognized by those skilled in the art, and not to an absolute or complete degree. Therefore, values ​​modified with terms such as “approximately,” “about,” and “substantially” are not limited to the specified exact values. In at least some examples, the approximation terms may correspond to the precision of the instrument used to measure the value. Furthermore, unless otherwise specified, terms such as “first,” “second,” etc., are used herein merely as indicators and are not intended to impose any order, position, or hierarchical requirements on the items referred to. Moreover, a reference to, for example, “second” item does not require or exclude the existence of, for example, “first” or a lesser-numbered item, or “third” or a more-numbered item.

[0011] Figure 1 is a schematic diagram of an exemplary combined cycle power plant 100. In an exemplary embodiment, the power plant 100 includes a gas turbine engine 102 and a steam turbine 104. The steam turbine 104 is housed in a steam turbine chamber 106. The gas turbine engine 102 includes a compressor section 108, a combustor 110, and a turbine section 112, all coupled together in a series flow relationship. During operation, the combustor 110 receives air 114 from the compressor section 108 and fuel 116 from the fuel supply section, uses the fuel and air to produce a fuel-air mixture, which is burned to produce combustion gas 118. The combustion gas 118 passes through the turbine section 112 and is discharged as exhaust gas flow 122 from the rear outlet 120 of the turbine section 112.

[0012] In an exemplary embodiment, the power plant 100 also includes a heat recovery system 124 associated with a gas turbine engine 102. The heat recovery system 124 includes an emissions reduction system 128 and a heat recovery steam generator (HRSG) 130 coupled to the emissions reduction system 128 in fluid communication. During operation, the exhaust gas flow 122 is received by the emissions reduction system 128, and nitrogen oxides (NOx) from the exhaust gas flow are recovered. x This promotes at least partial removal of the emissions. Next, the reducing gas stream 134 is discharged from the emissions reduction system 128 due to its interaction with the feedwater 136 in the HRSG 130. The reducing gas stream 134 heats the feedwater 136 from the feedwater pump 138 to generate steam 140, which is then sent to the steam turbine 104 for additional power generation.

[0013] In an exemplary embodiment, the HRSG 130 includes a high-pressure ("HP") steam section 142, an intermediate-pressure ("IP") steam section 144 downstream of the HP steam section 142, and a low-pressure ("LP") steam section 146 downstream of the IP steam section 144. The steam turbine 104 includes an HP steam turbine 148, an IP steam turbine 150, and an LP steam turbine 152, each arranged along the central axis 153. During operation, the HP steam section 142 converts feedwater 136 into HP steam and delivers the HP steam to the HP steam turbine 148 via the HP steam line 154. Similarly, the IP steam section 144 converts feedwater 136 into IP steam and delivers the IP steam to the IP steam turbine 150 via the IP steam line 156. Furthermore, during operation, the LP steam section 146 converts feedwater 136 into LP steam and delivers the LP steam to the LP steam turbine 152 via the LP steam line 158. As the steam 140 passes through turbines 148, 150, and 152 of the steam turbine 104, the steam turbine 104 generates output power 160.

[0014] In an exemplary embodiment, the power plant 100 includes a primary condenser 162 fluid-coupled to a steam turbine 104. After steam 140 passes through the steam turbine 104, a first portion 164 of the exhaust steam moves through an exhaust line 166 to the primary condenser 162, where the primary condenser condenses the first portion 164 of the exhaust steam into a liquid state, at least partially. The primary condenser 162 is fluid-coupled to a condensate extraction pump 168, which also condenses the first portion 164 of the exhaust steam and pumps the condensate 170 to a feedwater pump 138, where the condensate 170 is pressurized and used as high-pressure feedwater 136 for the HRSG 130.

[0015] The above-described cycle of water passing through the feedwater pump 138, HRSG 130, steam turbine 104, primary condenser 162, and condensate extraction pump 168 is provided for illustrative purposes only. It will be understood that several other configurations are possible without departing from the scope of this disclosure. For example, the steam turbine 104 may include multiple LP steam turbines 152. Alternatively, the power plant 100 may not include the IP steam section 144 and / or the IP steam turbine 150.

[0016] During operation of the steam turbine 104, the HP turbine 148, IP turbine 150, and LP turbine 152 may each leak steam 172 into the steam turbine chamber 106. In an exemplary embodiment, a steam seal regulator 174 facilitates the control of the flow of leaked steam 172 from various components of the steam turbine 104. Furthermore, HP exhaust steam 173 from the HP steam turbine 148 is in fluid communication with the steam seal regulator 174 and controlled by an exhaust valve 175. During operation, the HP exhaust steam 173 is either sent to the components of the steam turbine 104 or directed to the steam seal regulator 174.

[0017] The steam seal regulator 174 is fluid-coupled to the gland steam condenser 176. In an exemplary embodiment, the gland steam condenser 176 generates negative pressure relative to the ambient atmosphere, drawing the steam-air mixture 178 passing through the steam seal regulator 174 into the gland steam condenser 176, thereby preventing steam from escaping from the steam turbine room 106. Inside the gland steam condenser 176, a cooling fluid 180 condenses the steam from the steam-air mixture 178, and a centrifugal blower (not shown) removes the air portion.

[0018] In an exemplary embodiment, the cooling fluid 180 is supplied to the gland steam condenser 176 from a cooling module 182 in a cooling system 183 via a supply line 181. In an exemplary embodiment, the cooling module 182 is fluidically isolated from the condensate extraction pump 168. In an exemplary embodiment, the cooling module 182 is a sealed cooling water fin fan cooler, and the cooling fluid 180 is water. In one example, the cooling module 182 is also used to supply the cooling fluid 180 to the generator cooler 184 and lubricating oil cooler 186 of the power plant 100. In an alternative embodiment, the cooling module 182 may also supply the cooling fluid 180 to other components of the power plant, or it may supply it only to the gland steam condenser 176. In yet another embodiment, the cooling module 182 may be any cooling system that enables the gland steam condenser 176 to function as described herein. After the steam in the steam-air mixture 178 is condensed by the gland steam condenser 176, the heated water 188 is discharged from the gland steam condenser 176 through the return line 189 to the cooling module 182, where it is cooled into a cooling fluid 180.

[0019] In contrast to some known gland steam condensers that supply cooling feedwater to both the gland steam condenser and the HRSG and operate under pressures of 550–675 pounds-force per square inch gauge pressure (PSIG), the gland steam condenser 176 operates with a cooling fluid 180 flowing through it at less than approximately 500 PSIG. In a further embodiment, the gland steam condenser 176 operates with the cooling fluid 180 passing through it at approximately 100–180 PSIG. In yet another embodiment, the gland steam condenser 176 operates with the cooling fluid 180 passing through it at approximately 110–130 PSIG or approximately 120 PSIG.

[0020] In one exemplary embodiment, the flow rate of the cooling fluid 180 passing through the gland steam condenser 176 is less than approximately 1250 gallons / minute (GPM), while the flow rate of the cooling fluid in some conventional gland steam condensers is between 1500 and 8000 GPM. In a further embodiment, the flow rate of the cooling fluid 180 passing through the gland steam condenser 176 is approximately 400 to approximately 600 GPM. In yet another embodiment, the flow rate of the cooling fluid 180 passing through the gland steam condenser 176 is approximately 450 to approximately 550 GPM or approximately 500 GPM.

[0021] Conventional gland steam condensers use a cooling fluid with a temperature of approximately 150 to 200 degrees Fahrenheit, but the temperature of the cooling fluid 180 passing through the gland steam condenser 176 of the present invention is less than approximately 125 degrees Fahrenheit. In yet another embodiment, the temperature of the cooling fluid 180 passing through the gland steam condenser 176 is approximately 50 to 100 degrees Fahrenheit.

[0022] In one exemplary embodiment, the gland steam condenser 176 operates using an input power of less than approximately 13 kilowatts. In a further embodiment, the gland steam condenser 176 operates using an input power of less than approximately 10 kilowatts. In yet another embodiment, the gland steam condenser 176 operates using an input power of approximately 4 to 8 kilowatts or approximately 5 kilowatts. For comparison, a conventional gland steam condenser uses at least 15 kilowatts of power.

[0023] FIG. 2 is a schematic diagram of an exemplary cooling system 200 that can be used in place of the cooling system 183 in the combined cycle power plant 100 shown in FIG. 1. In an exemplary embodiment, the cooling system 200 includes a cooling module 202 fluidly coupled and in communication with a generator cooler 204 via a supply line 206. In one example, the cooling module 202 is a sealed cooling water fin fan cooler. Also, in one embodiment, the generator cooler 204 is a heat exchanger used to remove heat from a generator used in connection with the power plant 100. In one embodiment, during operation of the cooling system 200, a cooling fluid 207 at a temperature of about 125°F to about 135°F is supplied to the generator cooler 204 at a rate of about 1800 to about 2200 GPM. More specifically, in one embodiment, during operation of the cooling system 200, a cooling fluid 207 at a temperature of about 130°F is supplied to the generator cooler 204 at a rate of about 2000 GPM.

[0024] In one embodiment, after the cooling fluid 207 passes through the generator cooler 204, a heated fluid 208 is discharged from the generator cooler 204. In one embodiment, the primary heated fluid 208 has an initial temperature of about 135°F to 145°F, more specifically a temperature of about 140°F. In one embodiment, a first portion 212 of the primary heated fluid 208 is sent to a lubricating oil cooler 210. Specifically, in one embodiment, the first portion 212 of the primary heated fluid 208 is circulated through the lubricating oil cooler 210 at a flow rate of 900 to 1100 GPM, and in a further embodiment at a flow rate of about 1000 GPM. In such an embodiment, after the first portion 212 of the primary heated fluid 208 exits the lubricating oil cooler 210, the first portion 212 of the primary heated fluid 208 has a temperature of about 155°F to about 165°F, more specifically a temperature of about 160°F.

[0025] In another embodiment, the second portion 216 of the primary heating fluid 208 is sent to a main steam condenser 214 that receives steam 215 (shown as a mixture 178 of steam and air in FIG. 1) from a steam turbine. Specifically, in such an embodiment, the second portion 216 of the primary heating fluid 208 is circulated through the main steam condenser 214 at a flow rate of about 450 - 550 GPM, and in one embodiment, at a flow rate of about 500 GPM. In such an embodiment, after the second portion 216 of the primary heating fluid 208 exits the main steam condenser 214, the second portion 216 of the primary heating fluid 208 has a temperature of about 145°F to about 155°F, more specifically, a temperature of about 150°F.

[0026] In one embodiment, the third portion 218 of the primary heating fluid 208 does not pass through any additional coolers and thus remains at its original temperature. The first portion 212, the second portion 216, and the third portion 218 are reconnected in a return line 220 that produces a final heating fluid 222. In such an embodiment, the final heating fluid 222 passes through the return line 220 at a flow rate of about 1800 - about 2200 GPM, more specifically, at a flow rate of about 2000 GPM. In a further exemplary embodiment, the final heating fluid 222 has a temperature of about 145°F to about 155°F, more specifically, a temperature of about 150°F.

[0027] Figure 3 is a flowchart showing an exemplary method 300 for operating a combined cycle power plant, such as a combined cycle power plant 100. In one embodiment, method 300 includes step 302 for generating steam, such as steam 140, in an HRSG, such as an HRSG 130. In an exemplary embodiment, method 300 also includes step 304 for sending the steam from the HRSG to a steam turbine, such as a steam turbine 104. Method 300 also includes step 306 for sending a first portion of exhaust steam, such as a first portion of exhaust steam 164, from the steam turbine through a primary condenser, such as a primary condenser 162, to a condensate extraction pump, such as a condensate extraction pump 168. Method 300 also includes step 308 for sending a second portion of exhaust steam, such as leak steam 172 and HP exhaust steam 173, into a gland steam condenser, such as a gland steam condenser 176. Steps 306 and 308 may be performed simultaneously. Method 300 further includes step 310 of sending a cooling fluid, such as a cooling fluid 180, from a cooling module, such as a cooling module 182, to a gland steam condenser to condense a second portion of exhaust steam, wherein the cooling module is fluidly isolated from the condensate extraction pump.

[0028] The systems and methods described herein offer numerous advantages compared to the operation of conventional gland steam condensers. Because the gland steam condenser is coupled to a sealed cooling system, its operating parameters can be standardized. Therefore, its operation is independent of the specific equipment within the combined cycle power system. Furthermore, the systems and methods described herein can increase operating efficiency. For example, in at least some known systems where the gland steam condenser is fluidly coupled to a condensate extraction pump, the condensate extraction pump must operate continuously to maintain the vacuum within the gland steam condenser. However, in the systems and methods described herein, the cooling module can operate continuously using less energy and water, thereby enabling the gland steam condenser to operate with less overall energy and water consumption. Furthermore, in some embodiments described herein, the cooling module is used to cool other components within the power plant, such as generator coolers and lubricating oil coolers. In some such embodiments, the cooling module also operates continuously over those components. Therefore, the burden on the cooling module by adding the gland steam condenser is minimized compared to the continuous operation of the condensate extraction pump.

[0029] In some embodiments of the systems and methods described herein, the power input to the condensate extraction pump can be reduced from about 350 kilowatts to about 300 kilowatts. In these embodiments, the power consumption by the cooling module increases from about 185 kilowatts to about 215 kilowatts. In some such systems, the overall system performance is approximately 526.95 megawatts in energy and a combined cycle net efficiency of 60.74%. Furthermore, these systems and methods can increase the efficiency of a power plant without requiring a significant redesign of the main components of the power plant.

[0030] The exemplary technical effects of the systems, apparatus, and methods described herein include (a) standardizing the design and operating parameters of the gland steam condenser, (b) increasing the efficiency of the power plant without requiring the redesign of major components, and (c) reducing the operating load of the condensate extraction pump and / or primary condenser.

[0031] The above description is for illustrative purposes only, and those skilled in the art will recognize that modifications may be made to the described embodiments without departing from the scope of the disclosed invention. For example, the process steps described herein may be modified, for instance, in terms of duration, temperature, or time between cycles. Further modifications that fall within the scope of the invention will be obvious to those skilled in the art in light of the examination of this disclosure, and such modifications fall within the scope of the appended claims.

[0032] Exemplary embodiments of combined cycle power plants are described in detail above. Methods for operating combined cycle power plants are not limited to the specific embodiments described herein; rather, steps of the method can be used independently of other steps described herein. For example, the methods described herein are not limited to implementation in the combined cycle power plants described herein. Rather, exemplary embodiments can be implemented and used in connection with many other applications.

[0033] Certain features of various embodiments of the present invention may be shown in some drawings and not in others, but this is merely for convenience. Furthermore, the reference to “one embodiment” in the above description should not be construed as excluding the existence of additional embodiments that also incorporate the enumerated features. According to the principles of the present invention, any feature in the drawings may be referenced and / or claimed in combination with any feature in any other drawing.

[0034] Although the present invention is described in relation to various specific embodiments, those skilled in the art will recognize that the present invention can be put into practice with modifications within the spirit and scope of the claims. [Explanation of Symbols]

[0035] 100 Combined Cycle Power Plants 102 Gas turbine engine 104 Steam Turbine 106 Steam Turbine Room 108 Compressor Section 110 Combustor 112 Turbine Section 114 Air 116 Fuel 118 Combustion gases 120 Rear exit 122 Exhaust gas flow 124 Heat Recovery System 128 Emission Reduction Systems 130 Heat Recovery Steam Generator (HRSG) 134 Reducing gas flow 136 Water supply, high-pressure water supply 138 Water supply pump 140 steam 142 High-Pressure ("HP") Steam Section 144 Medium Pressure ("IP") Steam Section 146 Low-pressure ("LP") steam section 148 HP steam turbine, HP turbine 150 IP steam turbine, IP turbine 152 LP steam turbine, LP turbine 153 Central axis 154 HP steam line 156 IP Steam Line 158 LP steam line 160 Output Power 162 Primary condenser 164 The first part of the exhaust steam 166 Exhaust Line 168 Condensate extraction pump 170 Condensate 172 Leaked steam 173 HP exhaust steam 174 Vapor Seal Regulator 175 Exhaust valve 176 Grand Steam Condenser 178 A mixture of steam and air 180 Cooling fluid 181 Supply Line 182 Cooling Modules 183 Cooling System 184 Generator Cooler 186 Lubricating oil cooler 188 Heated water 189 Return line 200 Cooling System 202 Cooling Module 204 Generator Cooler 206 supply line 207 Cooling fluid 208 Main heating fluid 210 Lubricating oil cooler 212 Part 1 214 Grand Steam Condenser 215 Steam 216 Part 2 218 Part 3 220 Return Line 222 Final heating fluid 300 ways

Claims

1. Gas turbine engine (102) and A heat recovery steam generator (130) configured to generate steam (140), A steam turbine (104) is fluidly coupled to the heat recovery steam generator (130) and receives the steam (140) from the heat recovery steam generator (130), A primary condenser (162) is fluid-coupled to the steam turbine (104), receives a first portion (164) of exhaust steam from the steam turbine (104), and condenses the first portion (164) of exhaust steam into a liquid fluid. A condensate extraction pump (168) is fluid-coupled to the primary condenser (162) and receives the first portion (164) of the condensed exhaust steam, A gland steam condenser (176, 214) is fluidly coupled to the steam turbine (104), receives a second portion (172, 173) of exhaust steam from the steam turbine (104), and condenses the second portion (172, 173) of exhaust steam into a liquid state, A cooling module (182, 202) that is fluidly coupled to the gland steam condenser (176, 214) and supplies a cooling fluid (180) to the gland steam condenser (176, 214), wherein the cooling module (182, 202) is fluidly isolated from the condensate extraction pump (168) and A combined cycle power plant (100) including the above.

2. The combined cycle power plant (100) according to claim 1, further comprising a feedwater pump (138) fluidly coupled to the condensate extraction pump (168) and sending the liquid fluid from the condensate extraction pump (168) to the heat recovery steam generator (130).

3. The combined cycle power plant (100) according to claim 1, wherein the cooling modules (182, 202) are equipped with a sealed cooling water fin fan cooler.

4. The combined cycle power plant (100) according to claim 3, wherein the cooling modules (182, 202) are fluidly coupled to at least one of the generator coolers (184, 204) and the lubricating oil coolers (186, 210).

5. The combined cycle power plant (100) according to claim 1, wherein the gland steam condenser (176, 214) operates through which the cooling fluid (180) passes at a pressure of 100 to 180 pounds-force per square inch gauge pressure.

6. The combined cycle power plant (100) according to claim 1, wherein the gland steam condenser (176, 214) operates through which the cooling fluid (180) passes at a flow rate of 400 to 600 gallons / minute.

7. The combined cycle power plant (100) according to claim 1, wherein the gland steam condenser (176, 214) operates at a temperature of 50 to 100 degrees Fahrenheit.

8. The combined cycle power plant (100) according to claim 1, wherein the gland steam condenser (176, 214) operates using an input power of 4 to 8 kilowatts.

9. A method (300) for operating a combined cycle power plant (100), wherein the method (300) is The heat recovery steam generator (130) generates steam (140) (302), Sending the steam (140) from the heat recovery steam generator (130) to the steam turbine (104) (304), The first portion (164) of the exhaust steam from the steam turbine (104) is sent (306) to the primary condenser (162) and the condensate extraction pump (168), Sending the second portion of the exhaust steam (172, 173) into the gland steam condenser (176, 214) (308), The cooling fluid (180) is sent from the cooling modules (182, 202) into the gland steam condenser (176, 214) to condense the second portion (172, 173) of the exhaust steam (310), wherein the cooling modules (182, 202) are fluidly isolated from the condensate extraction pump (168). A method including (300).

10. The method according to claim 9 (300), wherein the delivery (310) of the cooling fluid (180) from the cooling modules (182, 202) to the gland steam condenser (176, 214) further comprises delivering the cooling fluid (180) at a flow rate of 400 to 600 gallons / minute.

11. The method according to claim 9 (300), further comprising delivering the cooling fluid (180) from the cooling modules (182, 202) to the gland steam condenser (176, 214) (310) at a pressure of 110 to 130 pounds-force per square inch gauge pressure.

12. The method according to claim 9 (300), further comprising operating the gland steam condenser (176, 214) with an input power of 4 to 8 kilowatts.

13. The method according to claim 9 (300), further comprising directly supplying a cooling fluid (180) from the cooling modules (182, 202) to the gland steam condenser (176, 214).

14. The cooling fluid (180) is sent from the cooling modules (182, 202) to the generator coolers (184, 204), The cooling fluid (180) is sent from the generator cooler (184, 204) to the gland steam condenser (176, 214). The method according to claim 9 (300), further comprising:

Images