C ARACTERIZACIÓN DE LAS MUJERES ENTREVISTADAS

Various industries require steam to meet many of their needs: heating and air conditioning; turbine drives for pumps, blowers, or compressors;

drying and other processes; water heating; cooking; and cleaning. This so-called industrial steam, because of its lower pressure and tempera-ture as compared with utility requirements, also can be used to gener-ate electricity. This can be done directly with a turbine for electric production only, or as part of a cogeneration system, where a turbine is used for electric production and low-pressure steam is extracted from the turbine and used for heating or for some process. The elec-tricity that is produced is used for in-plant requirements, with the excess often sold to a local electric utility.

Another method is a combined cycle system, where a gas turbine is used to generate electric power and a heat recovery system is added using the exhaust gas from the gas turbine as a heat source. The

Steam and Its Importance 21

generated steam flows to a steam turbine for additional electric genera-tion, and this cogeneration results in an improvement in the overall efficiency. The steam that is generated also can be used as process steam either directly or when extracted from the system, such as an extraction point within the turbine.

One of the most distinguishable features of most industrial-type boilers is a large saturated water boiler bank between the steam drum and the lower drum. Figure 1.8 shows a typical two-drum design. This particular unit is designed to burn pulverized coal or fuel oil, and it generates 885,000 lb/h of steam. Although not shown, this boiler also requires environmental control equipment to collect partic-ulates and acid gases contained in the flue gas.

Figure 1.8 Large industrial-type pulverized coal- and oil-fired two-drum boiler.

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The boiler bank serves the purpose of preheating the inlet feedwater to the saturated temperature and then evaporating the water while cooling the flue gas. In lower-pressure boilers, the heating surface that is available in the furnace enclosure is insufficient to absorb all the heat energy that is needed to accomplish this function. Therefore, a boiler bank is added after the furnace and superheater, if one is required, to provide the necessary heat-transfer surface.

As shown in Fig. 1.9, as the pressure increases, the amount of heat absorption that is required to evaporate water declines rapidly, and the heat absorption for water preheating and superheating steam increases. See also Table 1.1 for examples of heat absorption at system pressures of 500 and 1500 psig.

The examples shown in the table assume that the superheat is con-stant at 100° higher than the saturated temperature for the particu-lar pressure (see Chap. 3).

It is also common for boilers to be designed with an economizer and/or an air heater located downstream of the boiler bank in order to reduce the flue gas temperature and to provide an efficient boiler cycle.

It is generally not economical to distribute steam through long steam lines at pressures below 150 psig because, in order to minimize

Figure 1.9 Effect of steam pressure on evaporation in industrial boilers. (Babcock & Wilcox, a McDermott company.)

Steam and Its Importance 23

the pressure drop that is caused by friction in the line, pipe sizes must increase with the associated cost increase. In addition, for the effective operation of auxiliary equipment such as sootblowers and turbine drives on pumps, boilers should operate at a minimum pres-sure of 125 psig. Therefore, few plants of any size operate below this steam pressure. If the pressure is required to be lower, it is common to use pressure-reducing stations at these locations.

For an industrial facility where both electric power and steam for heating or a process are required, a study must be made to evaluate the most economical choice. For example, electric power could be pur-chased from the local utility and a boiler could be installed to meet the heating or process needs only. By comparison, a plant could be installed where both electricity and steam are produced from the same system.

1.5.1 Fluidized bed boilers

There are various ways of burning solid fuels, the most common of which are in pulverized-coal-fired units and stoker-fired units. These designs for boilers in the industrial size range have been in operation for many years and remain an important part of the industrial boiler base for the burning of solid fuels. These types of boilers and their features continue to be described in this book.

Although having been operational for nearly 40 years, but not with any overall general acceptance, the fluidized bed boiler is becoming more popular in modern power plants because of its ability to handle hard-to-burn fuels with low emissions. As a result, this unique design can be found in many industrial boiler applications and in small utility power plants, especially those operated by independent power producers (IPPs). Because of this popularity, this book includes the features of some of the many designs available and the operating characteristics of each.

In fluidized bed combustion, fuel is burned in a bed of hot particles that are suspended by an upward flow of fluidizing gas. The fuel is generally a solid fuel such as coal, wood chips, etc. The fluidizing gas

TABLE 1.1 Heat Absorption Percentages for Water Preheating, Evaporation, and of Steam Superheating

500 psig 1500 psig

Water preheating 20% 34%

Evaporation 72 56

Steam superheating 8 10

TOTAL 100% 100%

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is a combination of the combustion air and the flue gas products of combustion. When sulfur capture is not required, the fuel ash may be supplemented by an inert material such as sand to maintain the bed.

In applications where sulfur capture is required, limestone is used as the sorbent, and it forms a portion of the bed. Bed temperature is maintained between 1550 and 1650°F by the use of a heat-absorbing surface within or enclosing the bed.

As stated previously, fluidized bed boilers feature a unique concept of burning solid fuel in a bed of particles to control the combustion process, and the process controls the emissions of sulfur dioxide (SO₂) and nitrogen oxides (NO_x). These designs offer versatility for the burning of a wide variety of fuels, including many that are too poor in quality for use in conventional firing systems.

The state of fluidization in a fluidized bed boiler depends mainly on the bed particle diameter and the fluidizing velocity. There are two basic fluid bed combustion systems, the bubbling fluid bed (BFB) and the circulating fluid bed (CFB), and each operates in a different state of fluidization.

At relatively low velocities and with coarse bed particle size, the fluid bed is dense with a uniform solids concentration, and it has a well-defined surface. This system is called the bubbling fluid bed (BFB) because the air in excess of that required to fluidize the bed passes through the bed in the form of bubbles. This system has rela-tively low solids entrainment in the flue gas.

With the circulating fluid bed (CFB) design, higher velocities and finer bed particle size are prevalent, and the fluid bed surface becomes diffuse as solids entrainment increases and there is no defined bed surface. The recycle of entrained material to the bed at high rates is required to maintain bed inventory.

It is interesting that the BFB and CFB technologies are somewhat similar to stoker firing and pulverized coal firing with regard to fluidiz-ing velocity, but the particle size of the bed is quite different. Stoker firing incorporates a fixed bed, has a comparable velocity, but has a much coarser particle size than that found in a BFB. For pulverized-coal firing, the velocity is comparable with a CFB, but the particle size is much finer than that for a CFB.

Bubbling fluid bed (BFB) boiler. Of all the fluid bed technologies, the bubbling bed is the oldest. The primary difference between a BFB boiler and a CFB boiler design is that with a BFB the air velocity in the bed is maintained low enough that the material that comprises the bed (e.g., fuel, ash, limestone, and sand), except for fines, is held in the bottom of the unit, and the solids do not circulate through the rest of the furnace enclosure.

Steam and Its Importance 25

For new boilers, the BFB boilers are well suited to handle high-moisture waste fuels, such as sewage sludge, and also the various sludges that are produced in pulp and paper mills and in recycle paper plants. The features of design and the uniqueness of this tech-nology, as well as the CFB, are described in Chap. 2. Although the boiler designs are different, the objectives of each are the same, and the designs are successful in achieving them.

Circulating fluid bed (CFB) boiler. The CFB boiler provides an alterna-tive to stoker or pulverized coal firing. In general, it can produce steam up to 2 million lb/h at 2500 psig and 1000°F. It is generally selected for applications with high-sulfur fuels, such as coal, petroleum coke, sludge, and oil pitch, as well as for wood waste and for other biomass fuels such as vine clippings from large vineyards. It is also used for hard-to-burn fuels such as waste coal culm, which is a fine residue generally from the mining and production of anthracite coal.

Because the CFB operates at a much lower combustion temperature than stoker or pulverized-coal firing, it generates approximately 50 percent less NO_xas compared with stoker or pulverized coal firing.

The use of CFB boilers is rapidly increasing in the world as a result of their ability to burn low-grade fuels while at the same time being able to meet the required emission criteria for nitrogen oxides (NO_x), sulfur dioxide (SO₂), carbon monoxide (CO), volatile organic com-pounds (VOC), and particulates. The CFB boiler produces steam eco-nomically for process purposes and for electric production.

The advantages of a CFB boiler are reduced capital and operating costs that result primarily from the following:

1. It burns low-quality and less costly fuels.

2. It offers greater fuel flexibility as compared with coal-fired boilers and stoker-fired boilers.

3. It reduces the costs for fuel crushing because coarser fuel is used as compared with pulverized fuel. Fuel sizing is slightly less than that required for stoker firing.

4. It has lower capital costs and lower operating costs because addi-tional pollution control equipment, such as SO₂ scrubbers, is not required at certain site locations.

1.5.2 Combined cycle and cogeneration systems

In the 1970s and 1980s, the role of natural gas in the generation of electric power in the United States was far less than that of coal and oil. The reasons for this included

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1. Low supply estimates of natural gas that projected it to last for less than 10 years

2. Natural gas distribution problems that threatened any reliable fuel delivery

3. Two OPEC (Organization of Petroleum Exporting Countries) oil embargoes that put pressure on the domestic natural gas supply 4. Concerns that natural gas prices would escalate rapidly and have

an impact on any new exploration, recovery, and transmission For these reasons, a Fuel Use Act was enacted in the late 1970s that prohibited the use of natural gas in new plants.

This situation has changed dramatically because now the electric power industry is anticipating a continuing explosive growth in the use of natural gas. The reasons for this growth are

1. Continued deregulation of both natural gas and electric power 2. Environmental restrictions that limit the use of coal in many areas

of the country

3. Continued perception of problems with the use of oil as a fuel for power plants because of greater dependence on foreign oil

4. Rapidly advancing gas turbine and combined cycle technology with higher efficiencies and lower emissions

5. Easier financing of power projects because of shorter schedules and more rapid return on investments

Perhaps the greatest reason for the growth is the current projection of natural gas supplies. Where before the natural gas supply was expected to last approximately 10 years, the current estimate is approximately 90 years based on the current production and use lev-els. Although this optimistic estimate is very favorable, it could pro-mote a far greater usage, which could seriously deplete this critical resource in the future, far sooner than expected. Therefore, careful long-term plans must be incorporated for this energy source.

This greater use of natural gas places additional demands on the natural gas pipeline industry. Now, pipelines require regulatory approvals and also must accommodate any local opposition to a project.

Most of the attention on the increased demand for natural gas has been focused on exploration and production of the fuel. Significantly less publicized but just as important is the need for handling this capacity with more capability for its delivery. This requires new pipelines to deliver the natural gas, new facilities to ship and receive liquefied natural gas (LNG), and additional underground aquifers or salt caverns for the storage of natural gas.

North America has an extensive network of natural gas pipelines.

However, because of the projected demands, it is estimated that approx-imately 40,000 miles of new pipelines are required over the next decade.

Many areas of the country are rejecting the addition of these pipelines in their area and thus causing additional cost and routing problems.

Advancements in combustion technology have encouraged the application of natural gas to the generation of electric power. The gas turbine is the leader in combustion improvements. By using the most advanced metallurgy, thermal barrier coatings, and internal air cool-ing technology, the present-day gas turbines have higher outputs, higher reliability, lower heat rates, lower emissions, and lower costs.

At present in the United States, nearly all new power plants that are fired by natural gas use gas turbines with combined cycles.

Combined cycles (or cogeneration cycles) are a dual-cycle system. The initial cycle burns natural gas, and its combustion gases pass through a gas turbine that is connected to an electric generator. The secondary cycle is a steam cycle that uses the exhaust gases from the gas turbine for the generation of steam in a boiler. The steam generated flows through a steam turbine that is connected to its electric generator.

Figure 1.10 shows a block diagram of a cogeneration system.

The interest in the combined cycle for power plants has resulted from the improved technology of gas turbines and the availability of natural gas. The steam cycle plays a secondary role in the system

Steam and Its Importance 27

Figure 1.10 Diagram of a cogeneration system using a gas turbine and a steam cycle.

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because its components are selected to match any advancement in technology such as the exhaust temperatures from gas turbines.

The recovery of the heat energy from the gas turbine exhaust is the responsibility of the boiler, which for this combined cycle is called the heat-recovery steam generator (HRSG). As the exhaust temperatures from the more advanced gas turbines have increased, the design of the HRSG has become more complex.

The standard configuration of the HRSG, as shown in Fig. 1.11, is a vertically hung heat-transfer tube bundle with the exhaust gas flowing horizontally through the steam generator and with natural circulation for the water and steam. If required to meet emission regulations, selective catalytic reduction (SCR) elements for NO_x control (see Chap. 12) are placed between the appropriate tube bundles.

The HRSG illustrated in Fig. 1.11 shows the SCR (item 18) located between selected tube bundles. This HRSG design also incorporates a duct burner (item 16). The duct burner is a system designed to increase high-pressure steam production from the HRSG. Its primary function is to compensate for the deficiencies of the gas turbine at high ambient temperature, especially during peak loads. The duct burner is seldom used during partial loads of the gas turbine and is not part of every HRSG design.

The advantages of gas turbine combined cycle power plants are the following:

1. Modular construction results in the installation of large, high-efficiency, base-loaded power plants in about 2 to 3 years.

2. Rapid, simple cycle startup of 5 to 10 minutes from no load to full load, which makes it ideal for peaking or emergency backup service.

3. High exhaust temperatures and gas flows enable the efficient use of heat-recovery steam generators for the cogeneration of steam and power.

4. Low NO_xand CO emissions.