For example, for coal-fired power plants, the choice of an appropriate furnace design and the design of other plant components often depends at least to some extent on the rank of the coal and its properties. The choice of furnace design can influence baseline emission rates. For example, tangentially fired furnaces promote the formation of a rotating fireball in a furnace, so their NO x emissions are different from those from a wall-fired boiler.
Operational practices, such as optimization of fuel and air ratios, also influence emissions; a well-tuned furnace can have substantially lower NO x emissions than one that is not well tuned. Figure illustrates a generic power plant burning pulverized coal that is equipped with postcombustion controls for NO x , PM, and SO 2. The furnace, also often referred to as a boiler, is the structure where combustion of the coal takes place. The burner design and methods for staging combustion affect the formation of NO x. The walls of the furnace structure typically are composed of steam tubes, so most of the surfaces in the furnace are actually heat exchangers.
Therefore, the flue-gas temperatures decrease as the fuel gas leaves the flame zone and travels past the heat-exchanger tubes. The temperature window in portions of the convective pass can be appropriate for selective noncatalytic reduction SNCR , which is an NO x -control technique involving injection of ammonia or urea to promote conversion of NO x in the flue gas to molecular nitrogen e.
After the convective pass, at which point the flue-gas temperature has been reduced because of heat exchange, the flue gas reaches the economizer, which is also a heat exchanger. Flue gas leaving the SCR, if present, or the economizer, if SCR is not present, flows through the air preheater, which is a heat exchanger. A typical air-preheater design is a slowly rotating basket, portions of which are exposed to the hot flue gas and then the cooler inlet air. An intake-air fan is typically used to force air into the furnace. In some power-plant designs, an induced-draft fan downstream pulls gas through the system.
If a power plant is equipped with a flue-gas desulfurization FGD system, also commonly referred to as a scrubber, the FGD system is typically downstream of the fly ash collection device. A common design for FGD systems is a spray tower in which a slurry of limestone is sprayed into the flue gas, promoting contact of the gas with liquid droplets containing dissociated limestone Cooper and Alley ; DeNevers There are numerous other FGD system designs, such as dry systems.
FGD systems are also classified as throwaway if there is a substantial waste stream or regenerative if the sorbent is regenerated and reused in a continuous cycle. For illustrative purposes, we focus on wet limestone FGD because it is one of the more common designs. The spray tower thus.
A forced-oxidation variation of the limestone-based FGD promotes a larger conversion toward calcium sulfate, which is a more desirable product for handling. If sufficiently purified and dewatered, the calcium sulfate from an FGD system can be used to make gypsum wallboard, although in many applications the sludge that includes calcium sulfate is ultimately disposed of in a settling pond or landfill.
Reheating can be adjusted as needed by the plant operator in response to visual observation of plume buoyancy.
The other major components are part of the steam cycle. Some of the critical elements of the steam cycle are steam drums, steam turbines, generators, and associated pumps and piping. The plant includes a transmission system to deliver power to high-voltage power lines. The balance of the plant typically includes many items of auxiliary and support equipment and facilities, such as the control room, administrative and storage buildings, shops, roads, rail, and others. The thermal efficiency of such plants has not changed dramatically over time. The prospect of increased use of supercritical steam cycles may lead to a marginal increase in efficiency for a new plant.
Alternative technologies, such as integrated gasification combined cycle IGCC systems, may also be capable of providing some efficiency improvement compared with existing subcritical steam cycle plants Frey and Zhu However, without a dramatic increase in thermal efficiency, it appears to be the case that many producers of electric power do not have a major economic incentive to replace existing plants with newer ones, as long as the existing plants can be operated with adequate reliability and competitive marginal costs. A typical natural-gas-fired gas turbine combined-cycle system is illustrated in Figure A gas turbine has three main components: compressor, combustor, and turbine also referred to as an expander.
The compressor increases the pressure of ambient air for delivery into the combustor, where pressurized gaseous fuel typically natural gas or liquid fuel is introduced.
The high-pressure, high-temperature combustion products enter the turbine via an inlet nozzle, and as the gases are expanded and cooled,. Much of the shaft work is used to turn the compressor, and the balance is available for turning a generator. In some designs, a steam turbine is on the same shaft, and the gas and steam turbines turn the same generator. Thus, additional thermal energy can be recovered from the exhaust gas via a heat-recovery steam generator HRSG.
The HRSG is composed of multiple heat exchangers that serve tasks ranging from heating boiler feedwater to superheating steam. Steam typically is produced at two or three pressures to feed multiple stages of the steam turbine. Because SCR requires a specific temperature window, it is typically located in the HRSG so that the exhaust gas that passes through it is at an appropriate temperature during normal operations.
This section reviews the typical repair and replacement considerations for electricity-power plants, with a primary focus on coal-based power plants and secondary consideration of natural-gas-fired combined-cycle systems. The types of activities reviewed here are related to typical industry practice but are not evaluated here with respect to implications for NSR. A given repair or replacement activity may or may not trigger a requirement for an NSR permit, depending on the specifics of each case.
Key elements of repair and replacement at a typical fossil-fuel-fired steam power plant are the following Babcock and Wilcox :. Safety considerations: These often involve proper operation of various monitoring, observation, and detection systems, such as burner observation, flame failure, unburned combustibles, fuel:air ratios, water levels, feedwater and boiler conditions, pressures, and temperatures.
Outages: These are scheduled outages for preventive maintenance in the colloquial sense.
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Internal cleanliness and inspection for example, measuring internal boiler-tube deposits and chemical or acid cleaning of tube internals. External cleanliness and inspection for example, for external fouling not removable by normal sootblowing; external signs of pending tube failure, such as blistering or warping, signs of erosion or corrosion, misalignments, and deposits of ash or slag; condition of equipment; and condition of exposed refractory.
Identification of needed corrective actions for example, preventing recurrence of problems identified during inspection, such as startup procedures that are too rapid and lead to overheating of superheater tubes.
Cleaning of internal heating surfaces for example, with chemical cleaning techniques. Specific areas of a typical coal-fired power plant that require repair and replacement include the following ERCC :. A summary of common repair and replacement activities for each of those areas is given in Appendix E in Table E Many of the common repair and replacement requirements at coal-fired power plants are attributable to exposure of key components to the erosive effects of ash or other solids during fuel handling or in the flue-gas stream; the corrosive effects of acid gases in the flue-gas stream; and impurities, such as in steam.
Wear and tear on turbine blades, heat-transfer surfaces, and other components can lead to a loss of system efficiency, reliability, capacity, or some combination of the three. Thus, common repair and replacement activities are often aimed at attempting to maintain the original efficiency, reliability, or capacity of the plant. Over time, new designs or materials may become available for replacement parts, such as turbine blades, and potentially offer improved efficiency, reliability, or capacity compared with the original equipment used in the plant.
It may be easier, more economical, or more energy-efficient to use the more recently available replacement parts than to attempt to create the original parts. Many repair or replacement projects also can prevent more catastrophic failure of a plant. For example, replacing worn heat-exchanger tubes potentially could prevent a catastrophic failure that could substantially damage a plant or injure personnel.
Thus, there is clearly a role for preventive repair and replacement to maintain the safety of a plant and for prudent timing of replacement of worn or damaged parts or components of the plant to maintain efficiency, reliability, and capacity. The costs of repair and replacement projects typically are higher on a per-unit-capacity basis for smaller units than for larger units.
Thus, the percentage of the total plant cost represented by a particular type of repair project typically may be larger for smaller units than for larger units. Appendix E does not attempt to summarize less frequent major replacements at a plant, such as repowering with a new furnace using an existing steam cycle or replacing major components such as a turbine-generator with an entirely new system. Air-pollution-prevention and -control options for coal-fired power plants typically focus on emissions of PM, NO x , SO 2 , and mercury Hg.
Control of Hg emissions is a recent development, necessitated by the Clean Air Mercury Rule CAMR ; there is no standard Hg emissions-control technology, although Hg-adsorption and -oxidation technologies have been extensively tested. For natural-gas-fired gas turbine-based systems, NO x emissions are usually of primary concern, and emissions of other pollutants, such as CO and VOCs, are of secondary concern. There is often a tradeoff between NO x prevention with combustion-based approaches for example, wet injection and low-NO x burners and emissions of products of incomplete combustion, such as CO and VOCs.
Changes into the combustion process, such as lower flame temperatures, that prevent a portion of NO x emissions can lead to reduced combustion efficiency. However, most of this section focuses on coal-based systems. For NO x , control options are typically classified as combustion based or postcombustion. Combustion-based approaches typically include low-NO x burners, overfire air, and other methods aimed at staging combustion to prevent at least some conversion of fuel-bound nitrogen to NO x while preventing at least some creation of thermal NO x from nitrogen in the combustion air.
Postcombustion approaches typically involve injecting a reactant, such as ammonia, to react with NO x in the flue gas, either without a catalyst SNCR or with a catalyst SCR.
Evaluating FCC flue gas emission-control technologies
To be effective, SNCR requires a specific temperature window, typically found in the convective pass of the boiler, and excellent mixing of ammonia or other reagents, such as urea with the flue gas. SCR operates at a lower temperature window, typically in a dedicated reactor downstream of the economizer heat exchanger. For SO 2 , the typical control options are to switch to a low-sulfur fuel or to use postcombustion control in the form of FGD.
Switching to a low-sulfur fuel often requires changes elsewhere in the plant. For example, when switching from a bituminous to a low-sulfur subbituminous coal, it is often necessary to modify the pulverizer mills. Furthermore, because the electric resistivity of fly ash from subbituminous coal can differ from that of bituminous coal, retrofits to an ESP if present are often required. Thus, a fuel switch can entail some capital cost associated with changes within a plant.
For background information, a budgetary cost analysis of typical NO x and SO 2 control technologies applied to generic types of new coal-fired power plants was conducted. The analysis of NO x control-technology costs is predicated on generic types of coal-fired electricity-generating furnaces as summarized by EPA d.
Examples of generic types of furnaces are wall-fired, tangentially fired, wet-bottom wall-fired, cell, and cyclone types. The estimates are summarized in Table According to EPA d , no boilers of the wet-bottom wall-fired, cell, or cyclone designs have been built since promulgation of applicable NSPS. Table is useful in providing a baseline for uncontrolled emission rates that can be used to assess the overall effectiveness of pollution-prevention and pollution-control strategies that reduce emissions.
In practice, a typical power plant has one or more methods for source reduction or control of NO x emissions and therefore has emissions lower than the uncontrolled rates shown in Table Levelized cost includes annualized cost recovery for capital cost plus annual fixed and operating costs and is expressed in dollars per year.
The annual emission reduction is in tons per year. Therefore, cost effectiveness has units of dollars per ton of emission reduction. The software provides results like those summarized in Table for two case studies based on a tangentially fired. The algorithm was used mainly to illustrate the sensitivity of cost to various key factors; other cost estimates can be obtained by using another EPA costing algorithm EPA f or the Integrated Environmental Control Model Rubin et al. Control Option a. The two case studies were chosen to represent scenarios that would lead to high values of cost effectiveness, such as for a smaller boiler used for peaking service, versus scenarios that lead to lower values of cost effectiveness, such as for a larger boiler used for baseload service.
The purpose of the comparison is to demonstrate the wide range in cost, depending on boiler size and capacity factor.