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

TABLE 1.1 Gas Turbine Pricing

Note: A host of factors affect pricing, and the above numbers give an idea only and should be used with caution.

Source: Ref. 14.

increasing the plant efficiency to 55% LHV. Table 1.2 presents data for a few systems that are being commercially offered. The data are typical only.

In spite of all the advantages mentioned, it should be noted that the output of a gas turbine decreases significantly as the ambient temperature increases. The lower density of warm air reduces the mass flow through the turbine and the exhaust gas flow through the HRSG, which in turn reduces its steam generation and hence the steam turbine power output. Unfortunately, hot weather also corresponds to peak electrical loads in many areas of the world. Hence a few methods are used to improve the gas turbine power output in summer. The three most common methods of increasing the gas turbine (GT) output are [7]

Injection of steam into the gas turbine

Precooling of the inlet air

Supplementary firing in the HRSG

Steam Injection

Injecting steam into the gas turbine has been a strategy adopted by turbine users for a long time to increase its power output. The increased mass flow coupled with the higher thermal conductivity and specific heat of the exhaust gases (due to the higher percent by volume of water vapor) generates more power in the gas turbine and higher steam output in the HRSG. The Cheng cycle, discussed later, is a good example of this technique. Besides increasing the power output, it reduces the turbine NOx levels.

Precooling of the Inlet Air

Evaporative cooling boosts the output of the gas turbine by increasing the density and mass flow of the air. Water sprayed into the inlet air stream cools the air to

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TABLE 1.2 Typical Combined Cycle Plants

Source: Ref. 9.

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near its wet bulb temperature. The effectiveness of the evaporative cooling systems is limited by the relative humidity of the air. At 95 F dry bulb temperature and 60% relative humidity, an 85% effective evaporative cooler can alter the air inlet temperature and moisture content to 85 F dry bulb and 92% humidity, respectively. This boosts the gas turbine output and the HRSG steam generation (due to the larger gas mass flow). The incremental cost of this system is about $180=kW. The cost of treated water, which is lost to the atmosphere, must also be considered in evaluating this system. The effectiveness of the same system in less humid conditions, say 95 F and 40% relative humidity, is much higher. The same evaporative cooler can reduce the inlet air temperature to 75 F dry bulb and 88% humidity. The combined cycle plant output increases by 7%, and the heat rate by about 1.9%. With evaporative coolers, the air cannot be cooled below the wet bulb temperature, so chillers are used for this purpose.

Chillers can be mechanical or absorption systems. Water is the refrigerant, and lithium bromide (LiBr) is the absorber in single-effect LiBr absorption systems. A low grade heat source such as low pressure steam drives the absorption process, which produces chilled water. Absorbers draw little electrical power and are well suited to cogeneration plants where steam is readily available. Sometimes the HRSG generates the low pressure steam required for chilling, or it can be taken from some low pressure steam header. Unlike mechanical chillers, the efficiency of an absorber is unchanged as its load is decreased. Chilled water output is limited to around 44 F, yielding inlet air at 52 F.

A mechanical chiller can easily reduce the temperature of GT inlet air from 95 F to 60 F dry bulb and achieve 100% humidity. This increases the plant output by 8.9% but also degrades the net combined cycle heat rate by 0.8% and results in a 1.5 in. WC inlet air pressure drop due to the heat exchanger located at the chilling section. Costs could be about $165=kW. Absorption systems are more complex than mechanical chillers.

Off-peak thermal storage is another method of chilling inlet air. A portion of the plant’s electrical or thermal output is used to make ice or cool water during lean periods. During peak periods, the chilling system is turned off and the stored ice is used to chill the inlet air.

The performance of HRSGs with varying ambient temperatures is discussed later. One can appreciate from the example why inlet air cooling is necessary, particularly in locations where ambient temperatures are very high.

Improvements in Gas Turbines

In order to handle the high firing temperatures, in the range of 2500–2600 F, gas turbine suppliers are doing research and development work on turbine blades for protection against corrosion and thermal stresses. Thermal barrier coatings have been used on turbine blades for several years. The base high alloy material

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ensures the mechanical integrity, while the coatings protect against oxidation and corrosion as well as reducing the blade surface temperature. The rotating blades are manufactured by using single-crystal casting technology, which allows the chemical composition of the alloys to be modified to improve their resistance to fatigue and creep. Thermal barrier coatings comprise two layers: the outer ceramic layer, which prevents flow of heat into the turbine blade, and a metallic bond coating, which is a nickelor cobalt-based material.

General Electric uses closed loop steam cooling for the blades in its quest for higher firing temperatures. This unique cooling system allows the turbine to fire a higher temperature, around 2600 F, for higher performance. Earlier designs were cooled by compressor discharge air, which causes a large temperature drop in the first-stage nozzle. Cooling with steam systems has been found to be more effective because it picks up heat for use in the steam turbine, transforming what was waste heat to usable heat. In conventional gas turbines, compressor air is also used to cool rotational and stationary components downstream of the stage 1 nozzle. This is called chargeable air because it reduces performance. In advanced systems, this air is replaced by steam, which enhances performance by 2% and increases the gas turbine output because all the compressor air can be channeled through the turbine path to do useful work in the turbine as well as in the HRSG [9]. The high pressure steam from the HRSG is expanded through the steam turbine’s high pressure section. The exhaust steam from this turbine section is then split. One part is returned to the HRSG while the other is combined with the intermediate pressure steam and used for cooling in the gas turbine. Steam is used to cool the stationary and rotational parts of the turbine. In turn, the heat transferred from the gas turbine increases the steam temperature to approximately reheat temperature. The gas turbine cooling steam is mixed with the reheat steam from the HRSG and introduced into the intermediate pressure steam turbine section [8].

COAL-BASED SYSTEMS

Though combined cycle plants based on natural gas (Fig. 1.9a) are widely used, with the increasing cost of natural gas several coal gasification technologies are gaining acceptance. The technology is proven, and there are several plants in operation throughout the world. The advantages of integrated coal gasification combined cycle (IGCC) are

Ability to use of low grade fuels such as coal and biomass.

High efficiency, about 7–8% higher than conventional coal-based plants. A net efficiency of 45% is not impossible. With improvements in gasification and gas turbine technologies, the efficiency can reach 50% by 2010.

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Fuel flexibility. The combined cycle portion of the plant can be fueled by natural gas, oil, or coal. A plant can switch from gas to coal as gas becomes unavailable or very expensive. Most gasifiers can handle different grades of coal. Gas turbine combustors can also handle different fuels with different heating values and gas analysis from low to high Btu.

Low SO2, NOx, and CO2 emissions. In an IGCC, 90% of the coal’s sulfur is removed before combustion. NOx is reduced by 90%, as is also the CO2 on lb=kWh basis. The coal gas is purified before combustion, unlike in a conventional coal-fired plant, where the flue gases are cleaned. Hence the quantity of effluent to be handled is much smaller. The composition of the fuel gas also allows for better chemistry while cleaning.

Low water consumption due to higher efficiency and lower heat losses. Marketable by-products such as sulfur, sulfuric acid, and carbon dioxide. A wide range of technologies such as fixed bed, fluidized bed, and entrained

bed gasification.

Ability to make use of advances in gas turbine technology.

Availability of IGCC plants, which has been in excess of 90% and is improving.

Higher gas turbine power output possible due to about 14% larger mass flow of flue gases at the same combustion temperature compared to natural gas.

Decreasing installation costs due to advances in technology. $1000=kW will be achievable in the near future. Unit sizes range from 100 to 500 MW.

In an IGCC, coal is gasified in a gasifier by using steam and either air or oxygen to generate a low or high Btu gas, which is cleaned and fired in a gas turbine combustor. There are three processes for gasifying coal: fixed bed, fluidized bed, and entrained bed. Figure 1.3 shows an IGCC plant. Typically, coal is gasified in the gasifier at pressure using steam, oxygen or air, and coal. The coal gas is cooled in a synthesis gas cooler, which also generates steam or superheats the steam generated elsewhere. It is then cleaned in a gas cleaning system, where the particulates and sulfur are removed. Hot gas cleaning methods are also being developed, which can improve the efficiency of the system even more. The clean coal gas is fired in the gas turbine combustor. The exhaust gases generate high pressure steam for the steam turbine and also for gasification. A portion of the air from the gas turbine compressor is also sent to the gasifier. There are several plants in operation throughout the world. In the United States the Wabash River plant, which began operation in 1995 (Fig. 1.3) generates 262 MW using the Destec process for gasification, which uses an entrained flow

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oxygen-blown gasifier. Coal is slurried, combined with 95% pure oxygen, and injected into the first stage of the gasifier, which operates at 400 psig and 2600 F. The coal slurry undergoes a partial oxidation reaction at temperatures that bring the coal’s ash above its melting point. From the gasifier the fluidized ash falls through a tap hole at the bottom. The synthesis gas flows into the second stage, where additional coal slurry is injected. At this stage the coal is pyrolyzed in an endothermic reaction with the hot synthesis gas. This enhances the heating value of the synthesis gas.

After leaving the second stage the synthesis gas flows into a gas cooler, which is a waste heat boiler that generates high pressure saturated steam at 1600 psia. After cooling, any remaining particulates are removed in a hot=dry filter. Further cooling of gas takes place in a series of exchangers. It is scrubbed to remove chlorides and passed through a catalyst that hydrolyzes the carbonyl sulfide into hydrogen sulfide. The H2S is removed by an acid gas removal system. A marketable elemental sulfur is produced as a by-product. Finally the sweet gas is moisturized and preheated before being sent to the gas turbine. The power block consists of a GE 192 MW MS7001A gas turbine, The exhaust gases generate steam in the HRSG, which generates power via a steam turbine. This is presently the largest gasification repowering project. The heat rate is around 8910 Btu=kWh (HHV) with SO2 emissions around 0.1 lb=MM Btu, NOx 0.15, and particulates below detectable limits [10].

Coal will remain a major fuel, more so with the significant run-up in the price of gas, and IGCC plants have earned a permanent place in power generation technology. The heat exchanger and the HRSG are designed to meet the special requirements of this process. Oxygen-blown gasification has dominated commercial gasification processes, because these plants produce chemicals based on synthesis gas (H2 and CO) and premium fuels. Air-blown gasifiers, which generate low Btu gas, are also widely used in the industry. Air-blown gasification produces a gas in which the desirable chemical reactants are diluted by massive amounts of nitrogen. The gasifier capacity is cut in half when it is air-blown. The efficiency of conversion of feed to fuel gas is higher with oxygen-blown gasification. The air-blown gasification produces over twice as much gas as is generated by oxygen-blown operation; hence investment costs for air-blown systems and cleanup systems are higher. Cleanup costs are also higher because the partial pressures of the pollutants are higher in air-blown system raw gas. Compression costs are lower because the mass flow of an oxygen-blown system is smaller by 20–40%.

The Sierra Pacific Power Company’s Pinon-Pine project employs an airblown system and a fluidized bed gasification process that uses low sulfur coal, most of which is captured in the bed itself by the use of limestone injection methods. A low Btu gas is generated, on the order of 130 Btu=scf.

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EFFECT OF AMBIENT TEMPERATURE ON HRSG

PERFORMANCE

The power output of a gas turbine without inlet air temperature cooling or conditioning suffers at high ambient temperature owing to the effect of lower air density, which in turn reduces the mass flow of air. The power output could drop by as much as 15–25% between the coldest and hottest temperatures. The exhaust gas flow, temperature, and gas analysis also vary with ambient temperature, which affects the HRSG performance. Table 1.3 shows the data for a typical LM 5000 gas turbine.

Naturally, the performance of an unfired HRSG behind the gas turbine would be affected by the changes in exhaust gas flow and temperature. Using the ‘‘HRSGS’’ program (see Chap. 2), one can evaluate the HRSG performance under varying ambient conditions; the results are shown in Fig. 1.11. One can see the large variation in the HRSG performance between summer and winter months. In order to minimize the effect of ambient temperature on power output, several methods are resorted to, such as the use of evaporative coolers, mechanical chillers, absorption chillers, and thermal storage systems as discussed above.

EFFECT OF GAS TURBINE LOAD ON HRSG

PERFORMANCE

Generally gas turbines perform poorly at low loads, which affect not only their [11, 12] performance but also that of the HRSG located behind them. Because of the low exit gas temperature at lower loads, the HRSG generates less steam and also has the potential for steaming in the economizer. Table 1.4 shows the exhaust flow and temperature of a small gas turbine as a function of load. It should be noted that the data are typical, presented to illustrate the point that at low gas

TABLE 1.3 Gas Turbine Performance at Selected Ambient Temperatures

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FIGURE 1.11 HRSG performance versus ambient temperature. Gas flow shown has a multiplication factor of 0.1.

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TABLE 1.4 Typical Gas Turbine Performance at Low Loads

turbine loads the HRSG performance will be poor. Note that at low loads the exhaust temperature is lower but the mass flow changes little.

The HRSG performance at 100% and 40% loads is given in Figs. 1.12a and 1.12b. The HRSG was designed for the 100% case, and its performance was checked at 40% load using the ‘‘HRSGS’’ program. It may be seen that the economizer generates some steam. Also, the exit gas temperature from the HRSG at low load is very high compared to the normal case. This is due to the fact that less steam is generated in the evaporator and hence the flow through the economizer is also small, resulting in only a small gas temperature drop; the heat sink at the economizer is not large enough to cool the gases to a low temperature. Thus it is recommended that the HRSG not be operated at low loads of the gas turbine for long durations. If it is absolutely required, then a gas bypass damper should be used, or methods suggested in Q8.41, may be tried to minimize economizer steaming.

EFFECT OF STEAM PRESSURE ON HRSG PERFORMANCE

Combined cycle plants today operate in sliding pressure mode; if extraction steam is desired at a given pressure for process reasons, then a constant pressure may be required at the steam turbine inlet. Typically the steam pressure is allowed to float by keeping the turbine throttling valves fully open and ensuring full arc admission. The load range over which sliding operation is allowed varies from about 40% or 50% to 100%. Large variations in steam pressure affect the specific volume of steam, which in turn affects the velocity and pressure drop through superheater tubes and pipes, valves, etc. Large variations in steam pressure also affect the saturation temperature at the drum and hence thermal stresses across

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FIGURE 1.12a HRSG performance at 100% load of gas turbine.

thick components such as drum and superheater headers, which in turn limits the rate of load changes. Sliding pressure operation increases the efficiency of the turbine at low loads due to lower throttling losses and also lowers the cost of pumping if variable-speed pumps are used.

The steam pressure at turbine inlet increases linearly as the load increases; however, the unfired HRSG steam output decreases as the steam pressure increases. By matching the steam turbine and HRSG characteristics, one can

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