Fouling factors must be considered in all heat exchanger selections. Fouling reduces the efficiency of heat transfer because it reduces the overall heat transfer coefficient. Usual causes include: external tube deposits, such as oil films or solids from a liquid or gaseous stream; internal tube-surface scaling due to precipitation of solid compounds from solution; or corrosion of surfaces, external or internal. To minimize fouling, natural gas exhaust is preferred. Using gas rather than oil will allow greater heat transfer efficiency and smaller heat exchange surface requirements.

Another critical parameter, in heat recovery system design is the exit temperature of the exhaust gas as it enters the stack and the potential for corrosion of the heat exchange surfaces. The limiting factor is the temperature at which, combustion product acids and water condense onto metal surfaces, causing corrosion.

The acid dewpoint, the temperature at which acids in the exhaust gas will begin to condense, is a function of the amount of sulfur in the fuel and, subsequently, in the exhaust gas. Exhaust streams from natural gas firing have a lower dewpoint than exhaust from fuels containing sulfur, allowing improved heat recovery efficiency.

In an HRSG, corrosion is a major concern in the economizer section, where exhaust gases are at their coolest prior to exiting the stack. Attention must be paid to both the cooling gas and the feedwater temperatures. Because the temperature of the tube metal tends to be near that of the feedwater at the inlet, it is advisable to maintain feedwater temperatures above 212°F (100°C) to avoid dewpoint precipitation. Deaerators operating at pressures above 5 psig (1.4 bar), which corresponds to a saturation temperature of 228°F (109°C), often provide for this.

The potential for water dewpoint corrosion increases when water or steam is injected into a gas turbine for emissions control or, in the case of steam, for increased power output and thermal fuel efficiency. Injection results in a higher dewpoint due to the moisture content of the exhaust stream.

The size of the heat recovery unit also depends on the pressure drop on both the gas and liquid side. The pressure drop of an exhaust gas system includes the exhaust gas ducting, heat recovery unit, auxiliary silencers, and outlet duct to the stack. System designs typically allocate as high of a pressure drop as possible at the heat recovery unit in order to minimize size and cost. Typical HRSG back-pressures are 10 to 15 in. wg (1.9 to 2.8 cm Hg).

Excess pressure drop can impose a high backpressure on prime mover systems, resulting in loss of power and efficiency, as well as overheating. In relation to gas turbines, back-pressure reduces the pressure ratio across the turbine section and, therefore, the power output of the turbine. The turbine will lose about 0.25% of power per inch of water back pressure.

The pressure and temperature of the steam being generated are limiting factors in exhaust gas temperature and in resulting heat recovery efficiency. Figure 8-40 is an example of the impact of final stack temperature on overall system efficiency.

Fig. 8-40 Gas Turbine System Overall Thermal Efficiency vs. Stack Temperature. Source: General Electric Company

Fig. 8-40 Gas Turbine System Overall Thermal Efficiency vs. Stack Temperature. Source: General Electric Company

Performance Correction Factors

Figure 8-41 shows the steam production capability for the exhaust of a 17,000 hp (12,500 kW) single-shaft gas turbine at full load under ISO conditions with both an unfired and fired HRSG. These curves cover a wide range of steam pressures and temperatures typical of many industrial applications. The full load gas turbine heat rate in this example is about 9,000 Btu/hp-h (7,000 kJ/kWh) and the exhaust flow rate is about 385,000 lbm (175,000 kg) per hour at a temperature of about 1,017°F (547°C). The HRSG pinch point temperature difference is 27°F (15°C) and both inlet and exhaust losses are assumed to be 3 in. wg (0.6 cm Hg). With supplementary firing, the after-burning firing temperature is assumed to be about

Correction factors must be applied to rated exhaust flow and temperature to accurately establish steam production capability under actual site conditions over the full range of operating loads. Manufacturers provide correction factors for elevation, compressor inlet temperature, inlet and exhaust pressure losses, water or steam injection, and part-load operation.

The following example lists correction factors for the gas turbine unit described above (Note that while there is a degree in similarity between gas turbines, correction factors will vary from one model to another.): 1. If site elevation was 1,400 ft (430 m) above sea level, the correction factor for exhaust flow is about 0.95. Thus, the

Stea-n Generator Pinch Point Terrp- 2TF


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