environmental impact of power plants

7/31/2019 Environmental Impact of Power Plants

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1. Introduction

Power generation is a significant source of pollutants that can impair human health

and the environment, including sulfur dioxide (SO2), nitrogen oxide (NOx), and

mercury. The Clean Air Act has been successful in reducing these emissions, but

power generation still contributes approximately 70% of SO2, 20% of NOx, and

40% of mercury emissions into the environment. These emissions from power

generation contribute to a range of human health and environmental problems, and

interstate and long range transport of emissions continue to play significant roles in

these problems. Cap and trade programs benefit human health and the environment

and address transport by significantly reducing emissions over large geographicareas.

When emitted into the atmosphere, SO2 and NOx react with water and other

compounds to form various acidic compounds, fine particles, and ozone. These

pollutants can remain in the air for days or even years. Prevailing winds can

transport them hundreds of miles, often across state and national borders. The

pollutants then fall to the earth in either a wet form (rain, snow, and fog) or a dry

form (gases and particles). Impacts include impaired air quality; damage to public

health; degradation of visibility; acidification of lakes and streams; harm to

sensitive forest and coastal ecosystems; and accelerated decay of materials, paints,

and cultural artifacts such as buildings, statues, and sculptures nationwide.

Mercury, a product of coal-burning, can be deposited locally or it can be

transported through the atmosphere for days to years before being deposited into

water bodies. Once mercury reaches lakes, rivers and oceans, it can be transformed

into methylmercury and bioaccumulate in the food chain. This results in predatory

fish and fish-eating birds and mammals accumulating mercury concentrations

millions of times higher than what is found in the water or air.


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2. Power Plant Impacts

2.1 Human Health

SO2 and NOx emissions form fine particles in the atmosphere. Particulate matter is

the term used for a mixture of solid particles and liquid droplets found in the air;

fine particles (PM2.5) are smaller than 2.5 microns (millionths of a meter) in

diameter. Power plants emit particles directly into the air, but their major

contribution to particulate matter air pollution is emissions of SO2 and NOx, which

are converted into mammals and birds are also exposed in this manner. The

primary symptoms of mercury exposure are neurological, including brain damage,

lack of motor skills, impaired cognitive skills, and difficulty speaking and hearing.

These effects are most pronounced on those exposed during the development of the

nervous system, such as fetuses and young children. Forty-four states have

advisories warning the public to restrict eating fish from their lakes, rivers,

streams, and/or coastal waters due to methylmercury. EPA estimates that 12

million acres of lakes and 475,000 miles of rivers, as well as the coastal waters of

11 states, are impaired by mercury.

2.2 Environment

SO2 and NOx emissions react in the atmosphere to form acidic compounds that

harm lakes and streams. When the acidic compounds that are formed as a result of

SO2 and NOx emissions are deposited to the earths surface, they can acidify lakes

and streams. Acidification (low pH) and the chemical changes that result, including

higher aluminum levels, make it difficult for some fish and other aquatic species to

survive, grow, and reproduce. In the 1980s, acid rain was found to be the dominant

cause of acidification in 75% of acidic lakes and 50% of acidic streams.

Acid deposition harms forests and trees. Acid rain can harm forest ecosystems

by directly damaging plant tissues. One of the best examples of direct damage


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involves the leaching of nutrients from the needles of red spruce, which reduces

the ability of the trees to tolerate cold winter temperatures and has contributed to

the decline of red spruce forests throughout the mountains of the eastern U.S. In

other cases, acid rain can combine with other pollutants, such as ozone, to weaken

trees and make them vulnerable to threats such as sulfate and nitrate particles in the

atmosphere. These particles make up a large proportion of the fine particle

pollution in most parts of the country. A substantial body of published scientific

literature recognizes a correlation between elevated fine particulate matter and

increased incidence of illness and premature mortality. The health effects of PM2.5

include:

Increased incidence of premature death, primarily in the elderly and those

with heart or lung disease;

Aggravation of respiratory and cardiovascular illness, leading to

hospitalizations and emergency room visits for children and individuals with

heart or lung disease;

Decreased lung function and symptomatic effects, including acute

bronchitis, particularly in children and asthmatics;

New cases of chronic bronchitis;

Increased work loss days, school absences, and emergency room visits.

2.2.1 NOx emissions

NOx emissions react in the atmosphere to form ozone. NOx and volatile organic

compounds react in the atmosphere in the presence of sunlight to form ground-

level ozone. Ground-level ozone is a major component of smog in our cities and in

many rural areas as well. Though naturally occurring ozone in the stratosphere

provides a protective layer high above the earth, the ozone that we breathe at

ground level has been linked to respiratory illness and other health problems,

including:


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Decreases in lung function, resulting in difficulty breathing, shortness of

breath, and other symptoms;

Respiratory symptoms, including bronchitis, aggravated coughing, and chest

pain;

Increased incidence/severity of respiratory problems (e.g. aggravation of

asthma, susceptibility to respiratory infection) resulting in more hospital

admissions and emergency room visits;

Chronic inflammation and irreversible structural changes in the lungs, that,

with repeated exposure, can lead to premature aging of the lungs and other

respiratory illness.

2.2.2 Mercuryemissions

Mercury emissions are deposited in watersheds and transformed into

methylmercury, which contaminates fish. In the U.S., human exposure to mercury

is primarily the result of consumption of fish contaminated with methylmercury.

Other fish-eating pests, which cause mortality. Acid deposition can also affect

forest ecosystems indirectly by changing the chemistry of forest soils, including

the leaching of plant nutrients from soils. It can also elevate levels of aluminum in

soil water, which impairs the ability of trees to use soil nutrients and can be

directly toxic to plant roots.

2.2.3 Nitrogen deposition

Nitrogen deposition contributes to impaired coastal water quality. Nitrogen

deposited from the atmosphere is a substantial source of nitrogen in many estuaries

and coastal waters. Large amounts of nitrogen in estuaries and coastal waters can

have significant ecological impacts, including massive die-offs of estuarine and

marine plants and animals, loss of biological diversity, and degradation of essential

coastal ecosystem habitat such as seagrass beds. For many species of fish and


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shellfish, these seagrass beds are essential nurseries and places to escape from

predators. Excessive amounts of nitrogen in coastal waters from atmospheric

deposition are thought to be a contributor to harmful algal blooms, such as red

tides, that kill millions of fish each year and can be toxic to humans as well.

2.2.4 CO2 Emissions

Coal is the only natural resource and fossil fuel available in abundance in such

country. Consequently, it is used widely as a thermal energy source and also as

fuel for thermal power plants producing electricity. In some country about 90,000

MW installed capacity for electricity generation, of which more than 70% is

produced by coal-based thermal power plants. Hydro-electricity contributes about25%, and the remaining is mostly from nuclear power plants (NPPs). The problems

associated with the use of coal are low calorific value and very high ash content.

The ash content is as high as 5560%, with an average value of about 3540%.

The installed electricity generating capacity has to increase very rapidly (at present

around 810% per annum), as India has one of the lowest per capita electricity

consumptions. Therefore, the problems for the future are formidable from

ecological, radio-ecological and pollution viewpoints. A similar situation exists in

many developing countries of the region, including the Peoples Republic of

China, where coal is used extensively. The paper highlights some of these

problems with the data generated in the authors laboratory and gives a brief

description of the solutions being attempted. The extent of global warming in this

century will be determined by how developing countries like India manage their

energy generation plans. Some of the recommendations have been implemented for

new plants, and the situation in the new plants is much better. A few coal

washeries have also been established. It will be quite some time before the steps to

improve the environmental releases are implemented in older plants and several

coal mines due to resource constraints.


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Fossil fuels, particularly coal, also contain dilute radioactive material, and burning

them in very large quantities releases this material into the environment, leading to

low levels of local and global radioactive contamination, the levels of which are,

ironically, higher than a nuclear power station as their radioactive contaminants are

controlled and stored.

Coal also contains traces of toxic heavy elements such as mercury, arsenic and

others. Mercury vaporized in a power plant's boiler may stay suspended in the

atmosphere and circulate around the world. While a substantial inventory of

mercury exists in the environment, as other man-made emissions of mercury

become better controlled, power plant emissions become a significant fraction of

the remaining emissions. Power plant emissions of mercury in the United States

are thought to be about 50 tons per year in 2003, and several hundred tons per year

in China. Power plant designers can fit equipment to power stations to reduce

emissions.

3 Emission Control Technologies

The availability and cost of technology to control emissions of harmful air

pollutants from electric power plants have been key factors in the development of

environmental regulations and standards over the past several decades. Emissions

from coal-fired power plants have been the subject of substantial scrutiny and

attention. Today, power plant emissions are again the subject of intense study in

the context of a new environmental to adverse human health effects (particulate

matter, sulphur dioxide, nitrogen oxides and, most recently, mercury), the climate

change issue centers primarily around emissions of carbon dioxide (CO2 ), a

greenhouse gas widely linked to global warming and climate change impacts. In

looking prospectively at potential technological options for controlling power plant

emissions of CO2 , historical experience in controlling other major pollutants can


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serve as a guide for expectations (and projections) of future cost trends for similar

environmental technologies.

The historical development of two widely used emission control technologies now

required on all new coal-fired power plants in the US and elsewhere. These

technologies are flue gas desulphurisation (FGD) systems used to control SO2

emissions, and selective catalytic reduction (SCR) systems used to control NO x

emissions. These two technologies are post-combustion control systems applied to

the flue gas stream emanating from a coal-fired boiler or furnace. In contrast to

other environmental control technologies that are applied either prior to or during

combustion, FGD and SCR systems represent technologies having the highest

pollutant removal efficiencies currently available for coal-burning plants. They are

also the most expensive technologies for emission control, and for this reason,

requirements for their use have been highly controversial.

3.1 Regulatory requirements for SO 2 control

Although the earliest applications of FGD at coal-burning power plants can be

traced back to the early 1930s in England, the modern era of environmental

controls dates from the late 1960s and early 1970s. In the US, the 1970 Clean Air

Act Amendments (CAAA) adverse effects on human health and welfare. The

principal sources of SO2 at that time were (and continue to be) coal-burning power

plants. When burned, the sulphur in coal is converted primarily to SO2 and

released to the atmosphere. The sulphur content of coals varies widely, from less

than 0.5% to over 5% by weight, depending on coal type and source. In the early

1970s, the average sulphur content of coals burned at US power plants was

approximately 2.5%. For new power plants, SO 2 emission regulations were

directly established by the EPA in the form of New Source Performance Standards

(NSPS) requiring the use of for coal-fired power plants, established in 1971,

defined BACT as a performance-based standard limiting SO 2 emissions to 1.2


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pounds per million Btu (lb/MBtu) of fuel energy input to the boiler. This emission

standard corresponded to roughly a 75% reduction from the average emission rates

at the time, but it allowed new plants to comply either by burning a sufficiently

low-sulphur coal or by installing an FGD system while burning high-sulphur coals.

Table 1 also lists the more recent SO 2 control requirements stemming from the

1990 amendments to the Clean Air Act. To address the problem of acid deposition,

EPA established a national emission cap for SO 2 at a level of 9.8 million tons/yr,

to be achieved by the year 2000. To achieve this limit, existing power plants were

required to further reduce their SO 2 emissions by roughly 40% below their 1990

levels. Power plants could comply either by switching to cleaner (low-sulphur)

fuels, by installing an FGD system, purchasing emission credits under a newly

created emission trading scheme, or by some combination of these approaches.

Table 1 Major US regulations for SO2 emissions from electric power plants


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Figure 1 depicts the worldwide growth in FGD installations over the past three

decades. The y-axis measures the total electrical capacity of power plants whose

flue gases are treated with wet lime or limestone scrubbers. The onset of FGD use

in each country corresponds to the time at which regulations were adopted that

were sufficiently stringent so as to require or encourage the use of FGD as an

emission control strategy. Figure 1 also shows that USA has dominated in the

deployment of this technology. Today, approximately 30% (90 GW) of US coal-

fired capacity is equipped with FGD systems, most of them wet limestone

scrubbers.

Figure 1 Cumulative installed capacity of wet lime/limestone FGD systems in different countries

3.2 Regulatory requirements for NO x control

In addition to SO2 , the 1970 CAAA also identified nitrogen dioxide (NO2 ) and

ground-level ozone (O3 ) as criteria that linked air pollutants to adverse human

health effects. Both pollutants are formed by chemical reactions that occur in the

atmosphere, although some NO2 is also emitted directly from high-temperature

combustion processes such as that occurring at power plants. Nitric oxide (NO) is

formed in much greater quantities during combustion and is gradually oxidised to

NO2 once emitted to the atmosphere. The combination of NO and NO 2xacid rain


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and (together with volatile organic compounds) the formation of ground-level

ozone.

In the US, the control of NO x emissions from power plants initially followed the

same timetable and regulatory approach as for SO 2 (see Table 2). The key

difference was the stringency of applicable requirements. Under the 1970 CAAA,

existing power plants were largely unaffected by state-level requirements to

achieve the NO 2 air quality standards. For new plants, the EPA New Source

Performance Standards imposed only modest requirements that could be met at

low cost using improved low-NO x burners (LNB) for combustion. During the

1970s and 1980s, as SO 2 emission restrictions grew more stringent (and more

costly), NO x emission requirements for coal plants changed only slightly as LNB

technology improved.

Table 2 Major US regulations for NO x emissions from electric power plants


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In contrast to the US situation, the use of SCR in other industrialised countries

began many years earlier in response to stricter NO x emission limits. Japan first

enacted strict requirements in the 1970s and pioneered the development of SCR

technology for power plant applications. In the mid-1980s, Germany required the

use of SCR systems on large coal-fired power plants as part of its acid rain control

program. Subsequently, other European countries also began to adopt this

technology. SCR systems also have been deployed at some power plants burning

oil or natural gas, including gas turbine plants used for peak power generation.

Figure 2 shows the historical trend in the worldwide growth of SCR capacity.

As with FGD systems, the onset of growth reflects the stringency and timetable for

NOx reductions in different countries. The earliest use of SCR is seen in Japan

beginning in the 1970s, followed by widespread adoption in Germany in the mid-

1980s. The US has been the laggard in SCR use, with the first units on coal-fired

plants installed only in 1993.

Figure 2 Cumulative installed capacity of SCR systems on coal-fired power plants in different countries


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3.3 Conventional Technologies

Babcock & Wilcox (B&W), through its Environmental Equipment and Research &

Development Divisions, has been an active participant in the development,

demonstration, and commercialization of many of these technologies. With wetscrubber sales of 16,859 MWe and dry scrubber sales of 1017 MWe, it is one of

the major worldwide suppliers of FGD systems. In addition, B&W has been and is

participating in four sorbent injection projects (one 5 MWe and three ~100 MWe

demonstrations) sponsored by the U.S. Department of Energy (DOE) and the U.S.

Environmental Protection Agency (EPA). It is from this perspective that the

balance of this paper seeks first to provide the reader with a background

appreciation of some of the more important features of the conventional wet and

dry scrubbers offered by B&W today. This forms the basis from which the

development of the lower capital cost sorbent injection technologies preceded. The

paper goes on to describe the results of these efforts as the technologies begin to be

accepted as fully commercial.

3.4 Wet Scrubbing

Current state-of-the-art systems offer significantly improved performance

compared to the first-generation FGD systems. Much of this is attributed to

engineering designs developed to conform better with fundamental process

chemistry. The largest single improvement has been the development of sulfite

oxidation control. Scale formation in the early systems tended to occur as the result

of uncontrolled crystallization of the naturally oxidized product calcium sulfate

(CaSO4 2H2O [gypsum]) from the recirculating slurry. The blocky gypsumcrystals typically represented 15 to 50 mol % of the absorbed SO2 and, when

intermingled with those of unoxidized calcium sulfite (CaSO3 1/2H2O) platelets

in the slurry, were responsible for much of the difficulty in dewatering. For

limestone systems, blowing air into the slurry to force oxidation to near 100%


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provides seed crystals that minimize scaling, while at the same time producing

more homogeneous slurries that dewater to concentrations in excess of 90% solids.

For these reasons, the Limestone Forced Oxidation (LSFO) system has become the

preferred technology worldwide.

The prime benefits of scale control derived from forced oxidation are greater

scrubber reliability and availability. Confidence in the design and operation of

these wet systems has risen to the point that a number of utilities in the U.S. and

Canada are now specifying and/or buying single absorber systems, with no

redundant absorber towers, to satisfy their compliance requirements. Figure 3

shows the primary components of the absorber towers currently being offered by

B&W.

Figure 3 B&W wet FGD absorber tower.


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3.5 Dry Scrubbing

Commercial utility installations using dry scrubber technology first appeared in the

U.S. in the late 1970s and early 1980s. Derived from spray drying technology, this

method of SO2 emission control relies on the atomization of a sorbent mostcommonly an aqueous lime slurryin a reaction chamber upstream of a particulate

collection device. Typically, the systems are designed to operate at a 15 to 25C (27

to 45F) approach to the adiabatic saturation temperature of the flue gas. The fine

droplets absorb SO2 and form the product calcium sulfite and sulfate as the water

evaporates. The B&W dry scrubber in use at two utilities is shown in Figure 4. The

design incorporates a patented, dual-fluid atomizer design that has proven to be

particularly effective and durable.

Figure 4 B&W dry scrubber module.

A downstream electrostatic precipitator (ESP) or baghouse collects the dry salts

along with fly ash present in the flue gas. Use of a baghouse enhances the

performance of the dry scrubber because additional SO2 absorption occurs as the

flue gas passes through the accumulated cake on the bags. Operation nearer the


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flue gas saturation temperature further promotes the increased removal efficiency

obtained through the intimate contact in this configuration.

3.6 Advanced Technologies

While the wet FGD systems provided the benefits of high removal efficiencies,their relatively high capital cost made them unattractive for those applications

where it was desirable to minimize the initial investment. In the late 1970s, interest

in developing lower cost technologies heightened when one eastern U.S. utility

determined that a 25% SO2 removal technology, when combined with coal

cleaning, would permit it to meet the regulated emission limit on one of its units.

At about the same time, the U.S. EPA was continuing support of bench- and pilot-

scale projects to develop low capital cost processes for many of the smaller and

older units not regulated by the original Clean Air Act of 1970. Initially using

limestone injection through staged low-NOx burners, these studies went on to

show that moderate levels of SO2 emission control were possible by injecting

sorbent within certain windows within a boilers time-temperature profile.

3.6.1 Furnace Sorbent Injection (LIMB)

Furnace sorbent injection for SO2 emission control was first attempted on a

commercial scale in England in the 1930s, and was the subject of several studies in

the U.S. just preceding passage of the Clean Air Act in the late 1960s. These early

efforts, using limestone as the sorbent, typically produced low (20 to 30%)

removal efficiencies that were generally regarded as less than adequate for the

objectives set at the time. It was only when interest rekindled in the late 1970s and

early 1980s that more detailed investigations determined how to overcome some ofthe chemical and mechanical limitations involved. The LIMB projects at

Edgewater went on to demonstrate that furnace sorbent injection represents a low

capital cost technology capable of achieving moderate levels of SO2 control. As

such, it is particularly applicable for older, smaller units burning lower sulfur coals.


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The first (EPA-sponsored) LIMB project at Edgewater had the primary objective

of attaining in excess of 50% SO2 removal at an inlet Ca/S ratio of 2.0 while the

unit burned 3% sulfur coal. To accomplish this, the project:

undertook an extensive review of the literature to determine the limiting

factors, both chemical and mechanical, thought to be responsible for the

lower removals observed previously

recommended and conducted further supporting studies in those areas where

more information was required

developed and installed a system accordingly designed for calcitic hydrated

lime injection in that region of the upper furnace where the sulfation

reactions would be maximized

developed a humidifier design, based on B&Ws dry scrubber experience,

that not only overcame the adverse impact of sorbent injection on the

electrostatic precipitator (ESP), but also provided a mechanism for enhanced

SO2 removal by being capable of operating at an 11C (20F) approach to the

adiabatic saturation temperature of the flue gas

Figure 5 The LIMB process at the Edgewater Station.


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Figure 5 shows the LIMB process flow diagram as operated at the Edgewater

Station. The hoppers shown under the humidifier in the diagram were covered by

steel plates throughout all testing, so that humidification was effectively carried out

as an in-duct process. (The humidifier was constructed in a bypass loop over the

hoppers of a retired ESP as a precautionary measure. If major ash deposits had

formed as the result of humidification, this part of the process could have been

isolated and hoppers used for removal. Fortunately, they were never needed.)

The DOE-sponsored LIMB Extension Project sought to demonstrate the generic

applicability of the process by characterizing the performance to be expected for a

variety of sorbents and coals. Sorbents tested included limestones reflecting three

increasingly finer grinds, commercial calcitic and dolomitic hydrated limes, and

lingo lime. Tests were conducted while the unit burned coals containing 1.6, 3.0,

and 3.8% sulfur. Characteristic curves showing the relative importance of the more

important variables are summarized in Figures 6, 7, and 8.

Figure 6 Effect of different sorbents on SO2 removal while burning1.6% sulfur coal and injecting at elevation 55.2 m (181 ft).


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Figure 7 Effect of limestone grind on SO2 removal while burning1.6% sulfur coal and injecting at elevation 55.2 m (181 ft).

[Note: These figures portray a first-order relationship between SO2 removal

efficiency and Ca/S ratio. This is approximately true over the range of conditions

tested, as can be seen in Figure 7. A second-order fit with a diminishing increase in

removal would describe the dependency more appropriately at higher

stoichiometries.]

Figure 8 Effect of humidification on SO2 removal.


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The effects of such variables as injector tilt, coal sulfur content, injection level

(temperature), and momentum flux ratio (velocity) were also examined. Factors

associated with the time-temperature profile (temperature and velocity) can,

however, be system-dependent. It is believed that the relative insensitivity of the

Edgewater system to these parameters was due to design near the optimal

operating conditions.

The LIMB demonstration at Edgewater also provided an opportunity to observe the

effects of furnace sorbent injection on boiler and ash collection and handling

equipment operation. The increased dust loading associated with the process can

cause additional ash accumulation on tubes. Depending on the amount of sorbent

to be injected, and the number, capacity, and position of any existing sootblowers

in a retrofit situation, it may be necessary to add sootblowers to clean convection

pass surfaces. The LIMB ash was found to be as easily removed as normal fly ash.

It was also observed that the hydrated limes had a much greater tendency to coat

the tubes than did the coarsely ground limestone. While the opposite had been

anticipated as the result of inertial impaction, it may be that the larger particles

were self-scouring. There were no means available to establish any quantitative

relationships, however.

3.6.2 Duct Sorbent Injection (Coolside)

Similar to the furnace sorbent injection systems, the duct sorbent injection systems

utilize the duct between the air heater outlet and the particulate collector inlet to

capture SO2 with either lime- or sodium-based compounds. Limestone sorbents are

quite unreactive in the 175C (347F) to 60C (140F) temperature range of interest forthis technology. While the sodium-based systems can be effective, concern over

the solubility of the product salts in the waste effectively limits application to a few

units in the western U.S.


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Duct sorbent injection systems have undergone extensive testing just within the

past few years. The largest of these was performed as the Coolside process

demonstration in conjunction with the DOE-sponsored LIMB extension project on

the 105 MWe unit at the Edgewater Station. Initially developed by CONSOL Inc.,

the process entailed injection of dry calcitic hydrated lime at the inlet of the same

humidifier that had been used during the LIMB demonstration. Most of the tests

were conducted with the humidifier operating in the range of an 11 to 17C (20 to

30F) approach to the saturation temperature.

Figure 9 depicts typical performance achieved in the course of the Coolside

process tests. Although the added NaOH was directly responsible for some of the

SO2 removal, results indicate that the sodium salts improve lime utilization,

presumably because their hygroscopic nature maintains a humid environment in

the vicinity of the particles. Similar behavior was noted during CONSOLs pilot

tests with neutral sodium salts added.

Figure 9 SO2 removal for the Coolside process.


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3.6.3 Limestone Injection Dry Scrubbing (LIDS)

Experience with both dry scrubbing and furnace sorbent injection prompted B&W

to integrate the two into the LIDS process, as it offered the advantages of

combining the use of the lower cost limestone sorbent with higher overall SO2removal and sorbent utilization. Figure 10 shows the flow diagram of the process

with particulate collection by either a baghouse or an ESP. In the process, injection

of limestone into the furnace effects SO2 removal as represented in Figure 7. The

unreacted quicklime continues through the system until it is collected in the

baghouse or ESP. Depending on the SO2 removal efficiency desired, a portion of

the collected ash is slurried with water through an appropriately sized slaking

device. The slurry is then fed to the dry scrubber where the bulk of the SO2

removal occurs. Significant additional SO2 removal may also occur during

particulate collection, especially if the flue gas must pass through a baghouse at a

temperature relatively close to saturation.

Figure 10 LIDS process flow diagram

B&Ws Research and Development Division carried out the LIDS tests at its

Alliance Research Center in Alliance, Ohio. A major portion of the facility already

existed as a pilot-scale combustion furnace called the small boiler simulator (SBS).

Rated at 1.8 MJ/s (6.0 x 106 Btu/hr), the SBS had much of the auxiliary equipment

in place as the result of earlier furnace sorbent injection tests. To this was added a

cylindrical, down-flow dry scrubber designed for testing with gas residence times


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in the 5 to 10 s range. Its dimensions were 9.1 m (30 ft) high and 1.5 m (5 ft) in

diameter. The baghouse contained 46 Nomex bags 3.0 m (10 ft) long and 12 cm

(4.6 in.) in diameter, providing a design air-to-cloth ratio of 51 m/hr (2.8 ft/min) at

66C (150F).

The cost of achieving continuous operation to achieve true steady-state conditions

made simulation of recycle necessary. This was accomplished by operating the

pilot in a batch mode, and collecting the ash produced each day for preparation of

the following days slurry in a 7.57 m3 (2000 gal) stirred tank. Recycle ratios,

defined in terms of mass of recycled ash per mass of fresh sorbent, ranged from 0.4

to 1.9 for the tests conducted.

Figure 11 LIDS combined furnace and dry scrubber SO2 removal.

The LIDS test program characterized the SO2 removal efficiency over a range of

stoichiometries and approaches to the saturation temperature. The results are

summarized in Figures 11 and 12 which show the overall removals obtained at the

outlet of the dry scrubber and the baghouse, respectively.


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Figure 12 LIDS combined furnace, dry scrubber, and baghouse SO2 removal.

3.6.4 SOx-NOx-Rox Box (SNRB)B&W is developing the SNRB process as a combined SOx, NOx, and particulate

(Rox) emission control technology by which all three pollutants are removed from

flue gas in a high-temperature baghouse. SNRB incorporates lime- or sodium-

based sorbent injection to capture SOx, selective catalytic reduction (SCR) of NOx

by ammonia (NH3), and particulate removal in a high-temperature, pulse-jet

baghouse, as depicted in Figure 13.

Figure 13 The SOx-NOx-Rox Box (SNRB) process.

The tests run thus far have concentrated on characterizing SO2 removal with

calcitic hydrated lime injected at various temperatures and stoichiometries.

Preliminary results indicate that inlet Ca/S ratios near 2.0 reduce SO2 emissions by


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80 to 90%, well beyond the original 70% goal. Part of this is ascribed to more

complete conversion in the baghouse than anticipated, although the removal

appears to be sensitive to the baghouse temperature (Figure 14).

Figure 14 SNRB SO2 removal.

Results on NOx and particulate emissions control have also been promising. Figure

15 shows typical data being developed on NOx reduction for the process. Removal

efficiency in excess of 90% has been achieved near NH3/NOx stoichiometry of

0.85. At the same time ammonia slip, a term describing the undesirable bypass

of unreacted NH3, has generally been measured at levels of less than 4 mg/ Nm

3

(5ppmv).

Figure 15 SNRB NOx removal


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4 Conclusion

Flue gas desulphurisation (FGD) systems and selective catalytic reduction

(SCR) systems are the most widely used environmental technologies for high-

efficiency removal of SO 2 and NO x , respectively, at coal-fired electric power

plants. These systems also are the most expensive environmental technologies

employed at power plants worldwide. Nonetheless, substantial decreases in capital

costs have been realised over the past several decades as a result of investments in

R&D, learning by doing at power plant facilities, competition among equipment

manufactures, and other factors. The combined effect of these activities has been

represented in this paper by experience curves that quantify historical rates of cost

decrease as a function of the cumulative installed capacity (the measure of

experience) of FGD and SCR systems at coal-fired power plants. These rates were

found to be similar to those of other energy-related and market-based technologies.

The empirical data also show that widespread deployment of high-efficiency (but

costly) environmental technologies like FGD and SCR systems requires the

adoption of sufficiently stringent government regulations, policies, and other

actions to create and sustain a market for these technologies. Given such policies,

failure to account for the effects of technology innovation can lead to erroneous.

The control of SO2 emissions from fossil fuel-fired boilers has progressed

dramatically over the past 25 years. Wet scrubbers, and especially those employing

the LSFO and MEL technologies, have become the state-of-the-art methods for

achieving removal efficiencies in the 90% to 98% range. (Spray) dry scrubbing

with lime slurries for lower removal efficiency is seen as a technology more useful

for lower sulfur coals. However, it may prove to be economically viable for some

higher sulfur coal applications as well, especially when combined with sorbent

injection as is done in LIDS. Interest in the sorbent injection technologies alone,


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for moderate levels of removal at relatively low capital cost, at first grew out of

anticipation of the CAAA in the U.S

5 References

1 Soud, H.N. (1994) FGD Installations on Coal-Fired Plants, IEA Coal Research,

London.

2 Soud, H. (2001) Personal Communication, IEA Coal Research, London.

3 for the NOx SIP call, FIP, and section 126 Environmental Protection Agency,

Office of Air and Radiation, Washington DC.

4 Northeast States for Coordinated Air Use Management, Progress Report

Boston, MA, May 2001.

5 McIlvaine Company (2002) Utility Data Tracking Service, SCR Projects: Bid

and Award Tracking, http://www.mcilvainecompany.com/, October 30.

6 U.S. EPA (2002) EPA Clean Air Market Program: Emissions Data &

Compliance Reports, http://www.epa.gov/airmarkt/emissions/, June, 2002.

environmental impact of power plants

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