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

FIGURE 1.5 Packaged steam generator with completely water-cooled furnace. (Courtesy of ABCO Industries, Abilene, TX.)

environmental regulations relating to emissions of NOx, SOx, CO, and CO2, which adds to the complexity of their designs.

RANKINE CYCLE

A discussion on boilers would be incomplete without mentioning the Rankine cycle. The steam-based Rankine cycle has been synonymous with power generation for more than a century. In the United States, utility boilers typically use subcritical parameters (2400 psi, 1050=1050 F), whereas in Europe and Japan, supercritical plants are in vogue (4300 psi, 1120=1120 F). The net efficiency of power plants has increased steadily from 36% in the 1960s for subcritical coal-fired plants to 45% for supercritical units commissioned in the 1990s. Several technological improvements in areas such as metallurgy of boiler tubing, reduction in auxiliary power consumption, improvements in steam turbine blade design and metallurgy, pump design, burner design, variable pressure condenser design, and multistage feedwater heating coupled with low boiler exit gas temperatures have all contributed to improvements in efficiency. An immediate advantage of higher efficiency is lower emissions of CO2 and other pollutants. Current state-of-the-art coal-fired supercritical steam power systems operate at up to 300 bar and 600 C with net efficiencies of 45%. These plants have good

Copyright © 2003 Marcel Dekker, Inc.

efficiencies even at partial load compared to subcritical units, and plant costs are comparable to those of subcritical units. At 75% load, for example, the efficiency reduction in a supercritical unit is about 2% compared to 4% for subcritical units. At 50% load, the reduction is 5.5–8% for supercritical versus 10–11% for subcritical. These units are of once-through design. Cycle efficiencies of 36% in the 1960s (160 bar, 540=540 C) rose to about 40% in 1985 and to 43–45% in 1990. These gains have been made through [1–3]

Increases in the main and reheat steam temperatures and main steam pressure, including transitions to supercritical conditions

Changes in cycle configuration, including increases in the number of reheat stages and the number of feedwater heaters

Changes in condenser pressure and lowering of the exit gas temperature from the boiler (105–115 C)

Reductions in auxiliary power consumption through design and development

Improvements in the performance of various types of equipment such as turbines and pumps, as mentioned above

One of the concerns with the steam-based Rankine cycle is that a higher steam temperature is required with higher steam pressure to minimize the moisture in the steam after expansion. Moisture impacts the turbine performance negatively through wear, deposit formation, and possible blockage of the steam path. As can be seen in Fig. 1.6, a higher steam pressure for the same temperature

FIGURE 1.6 T–S diagram showing expansion of steam.

Copyright © 2003 Marcel Dekker, Inc.

results in higher moisture after expansion. Hence steam temperatures have been increasing along with pressures, adding to metallurgical concerns. This implies a need for higher boiler tube wall thickness and materials with higher stress values at high temperatures. Multistage reheating minimizes the moisture concern after expansion; however, this adds to the complexity of the boiler and HRSG design. Also with HRSGs, the steam-based Rankine cycle limits the effectiveness of heat recovery, because steam boils at constant temperature and significant energy is lost, which brings us to the Kalina cycle.

KALINA CYCLE

A recent development in power generation technology is the Kalina cycle, which basically follows the Rankine cycle concept except that the working fluid is 70% ammonia–water mixture. It has the potential to be 10–15% more efficient than the Rankine cycle and uses conventional materials of construction, making the technology viable. Figure 1.4 shows the scheme of the demonstration plant at Canoga Park, CA, which has been in operation since 1995 [4–6]. In the typical steam–water-based Rankine cycle, the loss associated with the working fluid in the condensing system is large; also, the heat is added for the most part at constant temperature; hence there are large energy losses, resulting in low cycle efficiency.

In the Kalina cycle, heat is added and rejected at varying temperatures (Fig. 1.7a), which reduces these losses. The steam–water mixture boils or condenses at constant temperature, whereas the ammonia–water mixture has varying boiling and condensing temperatures and thus closely matches the temperature profiles of the heat sources. The distillation condensation subsystem (DCSS) changes the concentration of the working fluid, enabling condensation of the vapor from the turbine to occur at a lower pressure. The DCSS brings the mixture concentration back to the 70% level at the desired high inlet pressure before entering the heat recovery vapor generator (HRVG). The HRVG is similar in design to an HRSG.

The ammonia–water mixtures have many basic features unlike those of either ammonia or water, which can be used to advantage:

1.The ammonia–water mixture has a varying boiling and condensing temperature, which enables the fluid to extract more energy from the hot stream by matching the hot source better than a system with a constant boiling and condensing temperature. This results in significant energy recovery from hot gas streams, particularly those at low temperatures, such as the geothermal heat source of Fig. 1.7b. By changing the working fluid concentration from 70% to about 45%, condensation of the vapor is enabled at a lower pressure, thus

Copyright © 2003 Marcel Dekker, Inc.

FIGURE 1.7 (a) Cycle diagram: Kalina vs. steam Rankine systems. (b) Temperature profiles of (left) Kalina and (right) steam heat recovery systems.

recovering additional energy from the vapor in the turbine with lower energy losses at the condenser system. As can be seen in Fig. 1.7b, the energy recovered with a steam system is very low, whereas the ammonia–water mixture is able to recover a large fraction of the available energy from the hot exhaust gases. A steam plant would have to use a multiple-pressure system to recover the same fraction of energy, but this increases the complexity and cost of the steam plant. The lower the temperature of the gas entering the boiler, the better is the Kalina system compared to the steam system.

2.The thermophysical properties of an ammonia–water mixture can be altered by changing the ammonia concentration. Thus, even at high ambient temperatures, the cooling system can be effective, unlike in a steam Rankine system, where the condenser efficiency drops off as the cooling water temperature or ambient temperature increases. The Kalina cycle can also generate more power at lower cooling water temperatures than a steam Rankine cycle.

Copyright © 2003 Marcel Dekker, Inc.

3.The ammonia–water mixture has thermophysical properties that cause mixed fluid temperatures to change without a change in heat content. The temperature of water or ammonia does not change without a change in energy.

4.Water freezes at 32 F, whereas pure ammonia freezes at 108 F. Ammonia–water solutions have very low freezing temperatures. Hence at low ambient temperatures, the Kalina plant can generate more power without raising concerns about freezing.

5.The condensing pressure of an ammonia–water mixture is high, on the order of 2 bar compared to 0.1 bar in a steam Rankine system, resulting in lower specific volumes of the mixture at the turbine exhaust and consequently smaller turbine blades. The expansion ratio in the turbine is about 10 times smaller. This reduces the cost of the turbine condenser system. With steam systems, the condenser pressure is already at a low value, on the order of 1 psia; hence further lowering would be expensive and not worth the cost.

6.The losses associated with the cooling system are smaller due to the lower condensing duty, and hence the cooling system components can be smaller and the environmental impact less.

Example of a Kalina System

A 3 MW plant has been in operation in California for more than a decade. In this plant, 31,450 lb=h of ammonia vapor enters the turbine at 1600 psia, 960 F and exhausts at 21 psia. The ammonia concentration varies throughout the system. The main working fluid in the HRVG is at 70% concentration, whereas at the condenser it is at 42%. The leaner fluid has a lower vapor pressure, which allows for additional turbine expansion and greater work output. The ability to vary this concentration enables the performance to be varied and improved irrespective of the cooling water temperature.

Following the expansion in the turbine, the vapor is at too low a pressure to be completely condensed at the available coolant temperature. Increasing the pressure would increase the temperature and hence reduce the power output. Here is where the DCSS comes in. The DCSS enables condensing to be achieved in two stages, first forming an intermediate mixture leaner than 70% and condensing it, then pumping the intermediate mixture to higher pressure, reforming the working mixture, and condensing it as shown in Fig. 1.4. In the process of reforming the mixture (back to 70%), additional energy is recovered from the exhaust stream, which increases the power output. Calculations show that the power output can be increased by 10–15% in the DCSS compared to the Rankine system based on a steam–water mixture.

Copyright © 2003 Marcel Dekker, Inc.

The HRVG for the Kalina cycle is a simple once-through steam generator with an inlet for the 70% ammonia liquid mixture, which is converted into vapor at the other end. The vapor-side pressure drop is large, on the order of hundreds of pounds per square inch due to the two-phase boiling process. Conventional materials such as carbon and alloy steels are adequate for the HRVG components.

Studies have been made on large combined cycle plants using the Kalina cycle concept. Using an ABB 13 E gas turbine, 227 MW can be generated at a heat rate of 6460 Btu=kWh (52.8%). This system produces an additional 12.1 MW compared to a two-pressure steam bottoming cycle. Though the cost details are not made available, it is felt that they are comparable on the basis of dollars per kilowatt.

Several variations of the Kalina cycle have been studied. One of the options for power generation cycles is shown in Fig. 1.8. It employs a reheat turbine. A cooling stage is included between the high pressure and intermediate turbines. First the vapor is superheated in the HRVG and expanded in the high pressure stage. Then it is reheated in the HRVG and expanded in the intermediate stage to generate more power. At this point the superheat remaining in the vapor is removed to vaporize a portion of the working fluid, which has been preheated in the economizer section. This additional vapor is then combined with the vapor generated in the HRVG and then superheated. The cooled vapor is then expanded in the low pressure stage. These heat exchanges enable the working fluid to recover more energy from the exhaust gas stream. A 4.5 MW Kalina system is in operation in Japan that uses energy recovered from a municipal incineration heat recovery system, and a 2 MW plant using geothermal energy is in operation in

FIGURE 1.8 Kalina system to improve energy recovery in a combined cycle plant.

Copyright © 2003 Marcel Dekker, Inc.

Iceland. It may be noted that as the temperature of the heat source is reduced, the Kalina system offers more efficiency than a steam or organic vapor system.

ORGANIC RANKINE CYCLE

The Rankine cycle is a thermodynamic cycle used to generate electricity in many power stations and is the practical approach to the Carnot cycle. Superheated steam is generated in a boiler, then expanded in a steam turbine. The turbine drives a generator to convert the work into electricity. The remaining steam is then condensed and recycled as feedwater to the boiler. A disadvantage of using the water–steam mixture is that superheated steam has to be generated; otherwise the moisture content after expansion might be too high, which would erode the turbine blades. Organic substances that can be used below a temperature of 400 C do not have to be overheated. For many organic compounds superheating is not necessary, resulting in a more efficient cycle. In a heat recovery system, it may be shown that if the degree of superheating is reduced, more steam can be generated and hence more energy can be recovered from the heat source as shown in Q8.36.* The working fluid superheats as the pressure is reduced, unlike steam, which becomes wet during the expansion process. Organic fluids also have low freezing points and hence even at low temperatures there is no freezing. The ratio of latent heat to sensible heat allows for greater heat recovery than in steam systems.

An Organic Rankine Cycle (ORC) can make use of low temperature waste heat such as geothermal heat to generate electricity. At these low temperatures a steam cycle would be inefficient, because of the enormous volume of low pressure steam, which would require very voluminous and costly piping resulting in inefficient plants. Small-scale ORCs have been used commercially or as pilot plants in the last two decades. Several organic compounds have been used in ORCs (e.g., CFCs, Freon, isopentane, or ammonia) to match the temperature of the available waste heat. Waste heat temperatures can be as low as 70–80 C. The efficiency of an ORC is estimated to be between 10% and 20%, depending on temperature levels. To minimize costs and energy losses it is necessary to locate an ORC near the heat source. It is also necessary to condense the working vapor; therefore, a cooling medium should be available on site. These site characteristics will limit the potential application. Condensing pressure is higher than atmospheric, so there is no need for vacuum equipment. ORC is expensive on the basis of cost per kilowatt-hour compared to other systems, but the main advantage is that it can generate power from low temperature heat sources. ORC plants can also be of large capacity. A 14 MW power plant using Flurinol 85 as the working

*Q8.36 refers to the Q and A section in Chapter 8. This nomenclature will be used throughout.

Copyright © 2003 Marcel Dekker, Inc.

fluid is in operation in Japan, using the energy recovered from the effluents of a sintering plant. The low boiling point and low latent heat of this fluid compared to steam help recover a significantly greater amount of energy from the hot gases.

COMBINED CYCLE AND COGENERATION PLANTS

Gas turbine plants operate in both combined cycle and cogeneration mode (Fig. 1.9). Figure 1.10 shows the arrangement of an unfired HRSG used in such plants. Large combined cycle plants with thousands of megawatts in capacity are being built today. Chemical plants, refineries, and process plants use HRSGs in cogeneration mode to supply steam for various purposes. The combined cycle plant with a gas turbine exhausting into an HRSG that supplies steam to a steam turbine is the most efficient electric generating system available today. It exhibits lower capital costs than fossil power plants. Table 1.1 shows the average cost of a gas turbine. The HRSG price ranges from about $80 to $130 per kilowatt. Combining the Brayton and Rankine cycles results in efficiencies significantly above the 40% level, which was an upper limit of large coal-fired utility plants built 30–50 years ago. Distillate oils and natural gas are typically fired in the gas turbines. Combined cycle plants have a number of advantages:

Modular designs enable increases in plant capacity as time passes.

These plants have short start-up periods. They come on-line in a couple of hours from the cold.

Combined cycle plants can be built within 12–20 months, unlike a large utility plant, which takes 3–4 years.

FIGURE 1.9a Combined cycle system showing the Brayton–Rankine cycle.

Copyright © 2003 Marcel Dekker, Inc.

FIGURE 1.9b Cogeneration systems.

Advances in gas turbine technology and cooling systems can be made use of to improve the overall system efficiency. We are close to 60% LHV efficiency with recent developments such as high pressure, multiplepressure steam systems and reheat steam cycles.

Emissions of NOx and CO for plants burning natural gas are in single-digit plants per million (ppm).

Cooling water requirements are low due to higher efficiency and the small ratio of Rankine cycle power to total power output. The Brayton cycle portion does not require cooling water.

Large-capacity additions are feasible. Today’s combined cycle plant is rated in thousands of megawatts, which is otherwise feasible only with coalfired power plants.

Recent developments in gas turbine technology such as closed steam cooling of blades enable firing temperatures to be increased, thus increasing the simple cycle efficiency. Every 100 F increase in firing temperature increases the turbine power output by 10% and gives a 4% gain in simple cycle efficiency. In large systems, an HRSG with three pressure levels and reheat is used,

Copyright © 2003 Marcel Dekker, Inc.

FIGURE 1.10 Unfired HRSG in a gas turbine plant.

Copyright © 2003 Marcel Dekker, Inc.