2.2.1 Types of Gas Turbine Generating Plants
Operating characteristics, and relatively high exhaust temperature of gas turbines afford a wide variety of applications in the generation, and co‐generation of power and steam. The most direct application is in simple‐cycle, or single‐cycle (SC) power generation, using the fast‐starting capability of gas turbines to provide near‐term supplemental power to the electric grid. These applications are often called “peaking plants” or simply “peakers” as they are primarily employed during the peak load periods of the day, or when there is a sudden increase in power price. Peaking plants are often used to back up renewable energy sources that depend on weather or time of day.
Gas turbines in peaking services are mostly modified gas‐turbine models designed for aircraft: aeroderivatives. Aeroderivatives are lightweight, with short starting times, and typi- cally high compression ratios that yield lower exhaust temperatures than larger frame machines for utility service.
Figure 2.2 shows a sketch of a gas turbine exhausting into an HRSG, abbreviated “1 × 1.”
This arrangement is often used in combined heat and power (CHP) facilities to provide the host company or facility with a portion of its steam requirements. A drawback of the simple configuration shown in Figure 2.2 is that the steam generation is a function of the gas turbine load. A host with a variable steam demand with a majority of the steam provided by the CHP would result in unpredictable power sales. An improvement to the design is to add
supplemental firing in the HRSG, sometimes referred to as “duct firing” to provide the flexi- bility require by the host.
Another drawback of this design is the reliability of the steam supply. Where steam is critical to the host facility, a second gas turbine / HRSG combination, backup steam supply, or both may be required to satisfy reliability requirements.
The net effective efficiency for this type of cycle can be very high because the latent heat of condensation is treated as useful energy supplied to the process host. Combining the energy outputs of electricity and heat can yield efficiency well over 50% on a higher heating value basis.
An HRSG is a large heat exchanger converting the energy in a high‐temperature exhaust gas, usually a gas turbine exhaust into steam. Figure 2.3 is a three‐dimensional rendering of a three‐pressure subcritical HRSG. The gas turbine exhaust enters the HRSG from the left through the diffusion section. Across the top are the HP, IP and LP steam drums in the direction of steam flow. An emissions removal catalyst section is shown in the drawing following the HP evaporator section. The LP section is an integral deaerator, which provides removal of essentially all the oxygen in the feedwater to the remainder of the steam cycle. Exhaust gases exit through the stack located on the right in the figure. A photograph of a similar unit is shown in Figure 2.4.
Addition of a steam turbine to create a combined cycle (Brayton gas turbine cycle plus a Rankine steam cycle,) as shown in Figure 2.5, improves the efficiency of power generation.
Here, a nonreheat steam cycle operating on the waste heat from a gas turbine adds additional electrical output from the single fuel source creating a 1 × 1 ×1 configuration (one gas tur- bine, one HRSG, and one steam turbine.) More complex steam cycles including reheat can further improve the overall cycle efficiency through better use of the gas turbine waste heat.
The steam turbine output in these cycles is nominally one‐third of the gas turbine generator output. Due to the rejection of heat in the condenser, these power cycles have efficiencies generally lower than well designed simple cycle CHP facilities consisting of a gas turbine and HRSG.
As with a 1 × 1 design, duct firing can be added to the 1 × 1 ×1 to provide the ability to generate more electricity in the steam turbine when market conditions are favorable. This additional capacity is an economic choice built at a cost ranging from one‐third to one‐half the cost of the base facility on a capacity basis of $/MW. But it comes with an efficiency cost.
When duct firing is not used, the steam turbine operates a nonoptimum output thereby reducing HRSG
Steam to process
Feedwater Gas turbine
Fuel G
Figure 2.2 1 × 1 CHP.
Figure 2.3 Rendering of HRSG. Source: Reproduced by permission of Nooter / Eriksen.
Figure 2.4 A photograph of an installed HRSG. Source: Reproduced by permission of Nooter / Eriksen.
the base cycle efficiency. When duct firing is in service, generation is added incrementally at a single Rankine cycle efficiency lowering the overall combined cycle efficiency.
A common configuration for combined cycle generating plants is a 2 × 2 × 1 – two gas turbines, two HRSGs and one steam turbine. This configuration improves the economy of scale by reducing the steam cycle costs in proportion to those of the gas turbine / HRSG combination. Unlike gas turbines, which are manufactured in discrete sizes and models, steam turbines are custom built for the specific application. Therefore, the steam cycle can be opti- mized for one or more gas turbines, environmental constraints and the business case to improve the overall project economics.
Combined cycle CHP plants are a combination of Figure 2.2 and Figure 2.3. Process steam may be provided directly from the HRSG or through an extraction port in the steam turbine. The efficiency of these CHP facilities can approach that of the SC CHP but will always be less due to the condenser heat rejection. Combined cycle CHP facilities provide excellent operating flexibility for steam and power supply when combined with duct firing. Electrical output can be maintained at a constant level through variations in process steam demand. The process steam demand may be provided from a variety of sources – direct from the HRSG or extracted from the steam turbine. Adding gas turbines, and steam turbines to the facility design improves reli- ability offering the ability to provide steam during normal or unexpected maintenance outages.
Auxiliary features can be added to the gas turbine cycle including:
• Steam power augmentation: steam injection downstream of the combustion zone to increase output.
• Water or Steam injection for NOx control: water or steam injected in the combustion zone to moderate the flame temperature and reduce the production of NOx.
• Inlet air cooling to increase mass flow and gas turbine output in the summer.
◦ Inlet fogging: direct sprays of water into the air inlet duct to the gas turbine.
◦ Inlet evaporative cooling: indirect evaporative cooling.
◦ Mechanical inlet air chilling: using a refrigeration cycle to chill the inlet air stream.
• Compressor water injection: water spray at an intermediate point within the compressor section to lower the compressor temperature and add mass flow to the latter stages of the gas turbine.
HRSG
Steam to process
Feedwater Gas turbine
generator Fuel
G
Steam turbine generator
Condenser G
Figure 2.5 1 × 1 × 1 combined cycle generating plant.
• Wet compression: a combination of inlet fogging and compressor water injection carried out in the inlet duct. A quantity of water in excess of that required to reach 100% relative humidity sprays into the inlet air stream resulting in liquid droplets of water entering the first stages of the gas turbine. These droplets evaporate in latter compression stages, providing cooling and reducing power required for compression.