01 POWER ISLAND / 01 CCPP / V. Ganapathy-Industrial Boilers and HRSG-Design (2003)

Solution. The design mode run is shown in Fig. 1.16a. The evaporator generates 37,883 lb=h, and 17,883 lb=h is sent through the superheater as 20,000 lb=h is taken off for process from the drum.

In the off-design mode, almost all of the steam, 35,270 lb=h, is sent through the superheater. As a result the steam temperature is lower, only 749 F, as shown in Fig. 1.16b. Note that without the program it would be tedious to perform this

FIGURE 1.16a Performance of a HRSG with process steam use.

Copyright © 2003 Marcel Dekker, Inc.

FIGURE 1.16b Performance of the HRSG when process steam is not required.

calculation, because we have no idea of the exit gas temperature in the design mode.

COMBINED CYCLE PLANT HRSG SIMULATION

The HRSG simulation concept is helpful in predicting the performance of an HRSG at various modes of operation. The HRSG need not be designed to perform this study. Figure 1.17a shows a multiple-pressure HRSG used in a combined cycle plant with nine modules. Module 1 superheater is fed by module 3, which consists of a superheater, evaporator, and economizer. Module 2 is a reheater. Module 7 evaporator feeds module 4 superheater. Module 5 economizer

Copyright © 2003 Marcel Dekker, Inc.

FIGURE 1.17a HRSG scheme in a combined cycle plant. Modules 1, 3, and 5 are HP sections. Modules 6, 8, and 9 are LP sections. Modules 4 and 7 are IP sections. Module 2 is a reheater.

FIGURE 1.17b Temperature profiles and performance of the HRSG.

Copyright © 2003 Marcel Dekker, Inc.

feeds module 2, and module 9 evaporator feeds module 6 superheater. Module 8 economizer feeds both modules 5 and 7.

The HRSGS program can be used to arrive at the design case performance as shown in Fig 1.17b. The US value (product of overall heat transfer coefficient and surface area) for each surface is also shown. One may also use this information to predict the HRSG performance at other off-design cases and study, for example, the effect of steam pressure or the feedwater temperature on the HRSG performance.

IMPROVING HRSG PERFORMANCE

By nature, HRSGs are inefficient, particularly the unfired units, because of the large gas mass flow associated with the low exit gas temperature from the gas turbine. The large mass flow forces one to use a boiler with a large cross section, though the steam generation may not be compatible with the size of the HRSG. The low ratio of steam to gas flow (15–18%) also results in a small heat sink at the economizer leading to higher stack gas temperature. Hence single-pressure units are inefficient. In addition,

1Gas=steam temperature profiles are dictated by the steam pressure and

steam temperature, unlike in a steam generator, where one can easily attain about 300 F stack gas temperature in a single-pressure unit even with high steam pressures on the order of 2000–2500 psi. In a single-

pressure HRSG, the exit gas temperature is a function of the steam pressure and temperature. With 600 psig steam superheated to 700 F, it

is difficult to get the economizer exit gas temperature below 380 F in an unfired HRSG.

2The higher the steam pressure, the lower the exit gas temperature (single-pressure unit). This point is explained under HRSG simulation:

see Q8.36.

3The higher the steam temperature, the lower the steam generation and

the higher the exit gas temperature. This is due to the smaller amount of steam generated with higher steam temperature and hence a smaller heat sink at the economizer.

4Partial load operation of a gas turbine also results in poor HRSG performance, as shown above.

So how can we improve the HRSG performance? There are several options.

Designs with Low Pinch and Approach Points

Pinch and approach points determine HRSG temperature profiles. If we have to work with only a single-pressure HRSG and there is no additional heat recovery

Copyright © 2003 Marcel Dekker, Inc.

equipment such as a deaerator coil or condensate heater, we can use low pinch and approach points to maximize steam generation. However, the surface area requirements increase due to the low log-mean temperatures in the evaporator and economizer, which adds to the cost of the HRSG slightly and increases the gas pressure drop. The major components of the HRSG such as controls and instrumentation, drum size, casing, and insulation do not change in a big way, and the additional cost of heating surfaces may not be that significant if we look at the overall picture. However, an economic evaluation may be done as shown in Q8.40.

Fired HRSGs

The advantages of fired HRSGs were discussed earlier. Firing increases the steam generation and lowers the HRSG exit gas temperature with a fuel utilization of nearly 100%. The additional fuel fired increases the HRSG duty by the same amount compared to, say, 92% in a steam generator.

Using Secondary Surfaces

Because single-pressure HRSGs are not very efficient, one may consider adding secondary surfaces such as as a deaerator coil or condensate heater or a heat exchanger as shown in Fig. 1.18 to lower the stack gas temperature.

Multiple-Pressure HRSGs

Before going into this option, one should clearly understand when multiplepressure options are justified. From the discussion on HRSG simulation, it can be seen that the exit gas temperature in an HRSG depends on the steam pressure and temperature. The higher the steam pressure, the higher the exit gas temperature. Hence when high pressure steam is generated, it will not be possible to cool the exhaust gases to an economically justifiable level with a single-pressure HRSG. Hence multiple-pressure steam generation is warranted. Also, one can maximize energy recovery by doing several things such as rearranging heat transfer surfaces, splitting up economizers, superheaters, and evaporators so that the gas temperature profiles match the steam and water temperatures and no large imbalance exists between the gas and steam temperatures. This can be done by using a program such as the HRSGS program (see Q8.37). In small HRSGs, multiple-pressure steam generation may not often be viable due to the complexity of the HRSG design and cost.

Copyright © 2003 Marcel Dekker, Inc.

FIGURE 1.18a Secondary surfaces to improve HRSG efficiency. 1, turbine; 2, deaerator; 3, HRSG; 4, mixing tank; 5, pump; 6, deaerator coil; 7, condenser; 8, heat exchange; 9, condensate heater.

Copyright © 2003 Marcel Dekker, Inc.

FIGURE 1.18b Continued

Copyright © 2003 Marcel Dekker, Inc.

HIPPS

Several teams of large companies in the United States are developing a coal-fired high performance system, also called HIPPS. In this combined cycle plant, a fluid bed air-blown pyrolyzer converts coal into fuel gas and char. The char is fired in a high temperature advanced furnace, which heats up both air for a gas turbine and steam for a steam turbine. The air is heated to 1400 F. The gas turbine combustor raises the air temperature to 2350 F and generates power in the gas turbine. High pressure steam is also generated in the HRSG [11].

CHENG CYCLE

One of the variations in cogeneration systems using gas turbines is the Cheng cycle. This system is ideal for plants with varying electrical and steam loads. It consists of a gas turbine with an HRSG, which has a superheater, evaporator, and economizer (Fig. 1.19). A duct burner is located between the superheater and evaporator. The HRSG generates saturated steam, which is superheated in the superheater and injected into the gas turbine, which increases its electrical power output significantly. The figure shows an Allison 501K machine, which normally generates 3.5 MW, in injection mode about 6 MW. The superheater is capable of running dry, that is, without steam. When only process steam is required, saturated steam from the evaporator is used. When additional process steam is required, the duct burner is fired. Hence the HRSG can operate in a variety of modes and at various points as shown in the figure by varying the amount of steam injected into the gas turbine and by varying the amount of fuel fired in the duct burner. Thus the plant can vary the ratio of power to process steam significantly according to the cost of fuel or electricity and thus optimize the overall efficiency. Cogeneration plants with fluctuating steam and power demands are ideal candidates for the Cheng cycle. The system’s proven success in smallscale plants is now being applied to midsized gas turbines ranging from 50 to 125 MW. Cheng cycle systems are in operation in over 50 installations worldwide.

HAT CYCLE

Another concept that is being studied is the humidified air turbine (HAT) cycle. This is an intercooled, regenerated cycle with a saturator that adds a considerable amount of moisture to the compressor discharge as shown in Fig. 1.20. The combustor inlet contains 20–40% water vapor, depending on whether the fuel is natural gas or gasified coal gas. The intercooling reduces the compressor work, while the water vapor in the exhaust gases increases the turbine output. Capital cost is lowered by the absence of steam turbine and condenser system. The gas

Copyright © 2003 Marcel Dekker, Inc.

FIGURE 1.19 Cheng cycle scheme.

Copyright © 2003 Marcel Dekker, Inc.

FIGURE 1.20 HAT cycle scheme. A, intercooler; B, aftercooler; C, recuperator.

turbine combustor design is modified to handle the large amount of water vapor in the incoming air. Cycle efficiency is expected to be in the range of 55% LHV with a significant increase in power output.

DIESEL ENGINE HEAT RECOVERY

Diesel engines are widely used as sources of power when an electrical utility supply is not available. They may be fired on gaseous or liquid fuels. They are mostly employed in low and medium power cogeneration units, typically 50 kW to 10 MW for natural gas firing, 50 kW to 50 MW for diesel, and 2.5–50 MW for heavy fuel oils. They are widely used in countries where the electricity supply is not reliable. Diesel plants have several advantages and features:

Medium-sized reciprocating engines have substantially higher electrical efficiencies than gas turbines of similar size (34–40% vs. 25–30%). Partial load efficiencies are also higher.

They require lower fuel gas pressure for operation—20–40 psig compared to 180–400 psig for gas turbines.

Electrical power output is less sensitive to ambient air temperature. The output of a gas turbine drops off at higher ambient temperatures as discussed above.

Capital costs are higher than these for gas turbines by 10–25%. Operating and maintenance costs are also higher, but diesel engines can be used on heavy fuel oils, so fuel costs are lower. Developing countries use diesel engine sets for on-site power needs because the power supply is not dependable in many locations.

In applications calling for high power to heat recovery, hot water or lowpressure steam, reciprocating engines are preferred to gas turbines. A lower exhaust gas temperature (650–800 F) makes them less suitable for high pressure heat recovery systems than gas turbines; also, the exhaust

Copyright © 2003 Marcel Dekker, Inc.