Flue Gas Heat Recovery in Power Plants, Part I

7/27/2019 Flue Gas Heat Recovery in Power Plants, Part I

1/12

10/13/13 Power 101: Flue Gas Heat Recovery in Power Plants, Part I | POWER Magazine

www.powermag.com/power-101-flue-gas-heat-recovery-in-power-plants-part-i/?printmode=1 1/12

Power 101: Flue Gas Heat Recovery in

Power Plants, Part I

04/01/2010 | By Nenad Sarunac

Every power engineer must have a firm grasp of the rudiments of how fuel is

processed to produce electricity in a power generation facility. With this article,

we begin a series of Power 101 tutorials that present these fundamentals in a

clear and concise way. First up are the essentials of recovering heat from flue

gas.

The major operating cost of a coal-fired power plant is for fuel. Given the higher

heating value (HHV), the amount of coal required to generate a desired power

output depends on unit efficiency (net unit heat rate). Therefore, unit efficiency

is an important economic factor, and recovering heat from the stack gas will

further improve the plant economics.

Some Preliminaries

A relationship between the net unit efficiency and net unit heat rate (HRnet) is

presented in Figure 1. [Download this ppt file [1] to view all figures at a legible

size.] Thermal efficiency, or efficiency (), is defined as the electric energy

output as a fraction (or percentage) of the fuel energy input. Heat rate is an

inverse of efficiency (multiplied by the unit conversion factor of 3,412). Both theefficiency and heat rate can be expressed on an HHV or a lower heating value

(LHV) basis. In the U.S., HHV is used for the coal-fired power plants, while in

Europe, efficiency calculations are based on LHV. A recent article in POWER[2]

provided a comprehensive discussion of power plant efficiency. Bottom line: Be

careful when comparing efficiencies from different data sources. To avoid

confusion, a note on HHV basis or LHV basis should be added next to the

numerical value of efficiency or heat rate.

Reference also is often made in the literature to changes in efficiency by

percentage points (%-points), which should be distinguished from relative

changes in percentage. For example (Figure 1), a change of 1%-point in
http://www.powermag.com/Assets_coal/File/CP%20Apr%2010%20HR%20Figures.ppthttp://www.powermag.com/coal/2432.htmlhttp://www.powermag.com/Assets_coal/File/CP%20Apr%2010%20HR%20Figures.ppt


2/12



efficiency (from 36% to 37%) represents a relative change of 2.7%. The

difference in efficiency between HHV and LHV for bituminous coal is about 2%-

points (5% relative), while for the high-moisture subbituminous coals and

lignites, the difference is about 3% to 4 %-points (8% to 10% relative,

depending on the coal composition).

Besides lower fuel cost, reduced fuel use results in lower emissions of NOx, SOx,

Hg, PM, and other pollutants. Efficiency improvement, as the only practical

option for reducing CO2 emissions in the short term, has become a key

consideration when choosing technology for new plants and for upgrades of

existing power plants. A relationship between heat rate improvement and

reduction in CO2 emissions, presented in Figure 2, shows that CO2 reduction is

proportional to the heat rate improvement. That is, 1% improvement in heat

rate results in 1% reduction in CO2 emissions, regardless of the coal type or its

rank.

Savings in the fuel and CO2 emissions cost for a typical 580-MW power plant

firing Illinois coal are presented in Figure 3 as functions of the heat rate

improvement and cost per ton of CO2 over an assumed range of carbon

allowance prices. The results show that 1% improvement in net unit heat rate

(on a relative basis) results in annual fuel savings of $1.6 million, assuming an

energy cost of $4/million Btu (MBtu) and unit capacity factor of 85%. With aCO2 cost of $30 per ton, annual savings are almost doubled ($2.8 million/year).

The efficiency of a coal-fired power plant also will have a strong effect on the

cost of carbon capture; with higher efficiency, the flow rate of flue gas that

needs to be treated will be lower, resulting in a smaller and less-expensive

carbon capture and sequestration (CCS) system. A smaller CCS will have smaller

negative effect on plant efficiency.

There are numerous opportunities and options for improving the efficiency of

existing power plants. Utilization of waste heat for boiler efficiency

improvement, improvement of steam turbine cycle heat rate, and stack reheat

are described below. Boiler efficiency improvement achieved by using heat

recovered from the flue gas for drying of high-moisture and washed coals will be

discussed in Part II. The improvement in steam cycle performance achieved by

using heat recovered from the flue gas for feedwater heating and preheating of

combustion air will be discussed in Part III.


3/12



Heat Recovery from Flue Gas

The temperature of the flue gas leaving the boiler is commonly reduced in an air

preheater (APH) when the sensible heat in the flue gas leaving the economizer

is used to preheat combustion air. Preheating of combustion air has a

significant positive effect on boiler efficiency. Common practice is to recover

sensible heat from flue gas until the temperature of the flue gas drops toapproximately 300F. The primary impediment to recovering heat by additional

cooling is the risk of condensing sulfuric acid on the APH heat transfer surfaces

and downstream ductwork.

Acid deposition leads to corrosion of affected surfaces, as well as to fouling and

plugging of the APH heat transfer passages. The APH fouling increases pressure

drop across the APH (both on the air and flue gas sides), which increases power

requirements for the forced draft (FD) and induced draft (ID) fans, resulting in

higher station service power and higher net unit heat rate (lower net unit

efficiency). Higher pressure drops also lead to higher pressure differentials

between the air and flue gas streams, which result in higher air-to-flue gas

leakage. Higher leakage increases fan power requirements and increases the flow

rate of flue gas through the pollution control equipment.

Sulfuric acid in the flue gas is formed in gas-phase reactions of SO3 and H2O

upstream of the APH. The SO3 is formed from SO2 by homogeneous and

heterogeneous reactions in the furnace and convection pass of the boiler. The

presence of SO3 in the flue gas increases the dew point of the flue gas. The acid

dew point temperature is presented in Figure 4 as a function of the SO3 and

H2O concentration in the flue gas. Sulfuric acid condenses as temperature is

decreased bellow the dew point temperature. The condensed sulfuric acid (acid

and water mixturesulfuric acid is hydroscopic) is corrosive to the inexpensive

materials used in construction of the APH heat transfer surfaces anddownstream ductwork. Heat rate improvement that could be achieved by

increasing heat transfer in the APH is typically inadequate to justify higher-cost

corrosion-resistant materials that would be needed for the APH cold end,

electrostatic precipitator (ESP), and the ductwork, and to deal with higher APH

fouling and plugging.

Assuming the SO3 concentration in the flue gas of 5 ppm and bituminous coal

(H2O concentration in the flue gas of 8% by volume) gives the acid dew pointtemperature of approximately 263F. It has to be noted that although the flue gas

temperature at the APH exit is typically 50F or more above the acid dew point

temperature, metal surface temperatures could be below that, as in the case of


4/12



the Ljungstrom APH. In a Ljungstrom APH, temperature of the heat transfer

surfaces located in the cold end layer of the APH are controlled by the inlet air

temperature and are significantly lower than the acid dew point temperature.

More details on the APH heat transfer, performance, and fouling and plugging

will be presented in Part II.

Besides acid deposition, the other impediment to recovering heat from the flue

gas by additional cooling in the APH is the ESP performance. As presented in

Figure 5, resistivity of flyash decreases as the flue gas temperature is reduced

below 300F. However, in case of the high-resistivity ash (Figure 5), the

temperature reduction would not be a problem, for the low-resistivity ash low

flue gas temperatures will have a significant negative effect on the ESP

performance.

Steam generators that employ ammonia injection for selective catalytic

reduction (SCR) or selective noncatalytic reduction (SNCR) of NOx encounter an

additional challenge in design and operation of low-temperature heat-recovery

equipment, particularly APHs. Unreacted ammonia combines with SO3 in the

flue gas stream and SO3 produced on the SCR catalysts to form ammonium

bisulfate (ABS). The ABS forms in a temperature range between the APH flue gas

inlet and outlet temperatures. The deposits are sticky and corrosive to steels

commonly employed in the APHs.

Upon exiting the ESP, it is common to cool the flue gas by evaporative cooling

to a temperature close to the adiabatic saturation temperature by spraying water

into the flue gas stream within a wet flue gas desulfurization (FGD) system.

According to an FGD manufacturer, the optimal flue gas temperature for a

desulfurization process is approximately 149F (65C). Cooling of the flue gas to

the saturation temperature occurs in a spray area, and the flue gas leaves the

FGD reactor at a temperature close to the saturation temperature. In same cases,the flue gas is leaving the FGD in a supersaturated state with a temperature

slightly below the saturation temperature. This practice results in significant

use of water for evaporative cooling. More importantly, the sensible heat of flue

gas is not beneficially used.

Saturation temperature is a function of the moisture content in the flue gas,

which depends on the total coal moisture (TM) content of coal, and humidity of

inlet air. The moisture content of the flue gas is presented in Figure 6 as a

function of the total coal moisture content. Calculations were performed for the

excess air coefficient (E) of 17.2% and humidity of inlet air of 0.01149 mole


5/12



H2O/mole air.

The flue gas moisture content and saturation temperature for the bituminous

and washed Illinois coals, subbituminous (Powder River Basin, PRB) coals, and

lignites are summarized in Table 1. The saturation temperature is presented in

Figure 7 as a function of TM. For these coals and combustion conditions,

saturation temperature varies in the 104F to 134F range.

Table 1. Saturation temperature for various coals. Source: Energy Research

Center

Low-Temperature Heat Recovery

The amount of heat available in the flue gas is presented in Figure 8 as a

function of the flue gas temperature for four coals: bituminous, washed Illinois,PRB, and lignite. Washed Illinois coals contain significant amount of moisture

(18% to 22%, or more), which reduces its HHV value. Most of this moisture is

surface moisture, which can be removed by drying. As the flue gas temperature

is reduced, the amount of available sensible heat increases. The sensible heat

that could be recovered from the flue gas by cooling it in a flue gas cooler (FGC)

from the APH gas outlet temperature of 310F to the FGD inlet temperature of

140F is 43 to 46 Btu per pound of flue gas (depending on the coal type).

As the flue gas is cooled below its saturation temperature, flue gas moisture

condenses to maintain partial pressure of the water vapor in flue gas that is

consistent with the flue gas temperature, and water vapor content of the flue

gas decreases (Figure 9). The amount (mass) of condensed water increases as the

temperature of the flue gas is reduced and is a strong function of the coal

moisture content.

As moisture condenses out of the flue gas steam, the flow rate of flue gasdecreases, causing a slight decrease in the amount of sensible heat in flue gas

(Figure 8). The kink in the sensible heat curve occurs at the saturation

temperature of flue gas.


6/12



As shown in Figure 9, most of the moisture can be removed from the flue gas by

cooling it to a very low temperature. The chilled ammonia concept, developed

by Alstom Power, employs cooling of the flue gas to a very low temperature

using chillers. At the current state of technology development, such low-

temperature cooling of the flue gas is expensive due to high power requirements

for the chillers.

Condensation of the flue gas moisture liberates latent heat. The amount of

latent heat released is a function of the flue gas temperature and coal type

(Figure 10). The amount of released latent heat increases as TM content of the

coal increases and temperature of the flue gas decreases. The latent heat can be

recovered in condensing heat exchangers (CXEs), but due to the low

temperature of a cooling fluid, there are practical temperature limits

(approximately 100F to 110F) that impose limits on the amount of latent heat

than can be economically recovered from the flue gas. Available heat sinks limit

the amount of low-temperature heat that can be beneficially used.

The total (sensible and latent) heat of the flue gas is presented in Figure 11. As

the flue gas is cooled below its saturation temperature, the amount of total heat

greatly increases. However, as discussed previously, there are practical

limitations associated with cooling of the flue gas to low temperatures and

beneficial use of the recovered low-temperature heat.

To illustrate total amount of heat available in the flue gas, sample calculations

were performed for a conventional supercritical pulverized coal-fired power

plant and four different coals. The gross power output of a 642.18-MW, turbine

cycle heat rate (HRcycle) of 7,467 Btu/kWh (cycle,gross = 45.69%), APH leakage

of 10%, flue gas temperature at the boiler outlet of 680F, and coal TM content

from Table 1 were assumed in the calculations. The results are presented in

Table 2 and Figure 12. The sensible heat was determined for the case where theflue gas is cooled in a FGC located upstream of the FGD from a temperature of

310F (APH gas outlet) to 140F (FGD inlet).

Table 2. Baseline power plant. Source: Energy Research Center


7/12



The total heat (including latent heat) was determined for the case where the

flue gas was cooled in the FGC and CXE from a temperature of 310F (APH gas

outlet) to 110F (inlet to a CO2 absorber). Flue gas cooling down to about 110F

will be needed for efficient operation of the post-combustion CO2 capture

system (CO2 absorber). Even deeper cooling is needed for the chilled ammonia

process.

The results show that for low-moisture bituminous and washed Illinois coals

having low saturation temperatures, the benefit of cooling the flue gas down to

110F is small. As TM content of the coal increases, such for the PRB and

lignites, the amount of total heat increases significantly, especially for the

lignites. Therefore, for high-moisture coals it might be economical to recover

the low-temperature heat. This is not the case for the low-moisture coals,

where cooling of the flue gas in a FGC upstream of the FGD is most economical

option.

Feedwater Heating and Combustion Air Preheat

The technology to recover low-temperature heat from flue gas originated in

Europe, where it has been used to improve performance of coal-fired power

plants and industrial plants for more than 15 years. Utility companies such as

RWE Power, Vattenfall, and others utilize the low-temperature heat from flue

gas for feedwater (FW) heating and preheating of combustion air. Several

different configurations with different commercial names, such as Powerise,

were developed and successfully used at power plants such as Schwarze Pumpe,

Mehrum, Niederaussem, Lippendorf, and Werndorf in Germany; Voitsberg in

Austria; and at other locations, including industrial plants and waste-to-energy

plants, such as Vestforbraending in Denmark, where recovered low-temperature

heat is used for district heating.

Typical configurations for using low-temperature heat from the flue gas include

configurations allowing FW heating and preheating of the combustion air. The

low-temperature heat is recovered from the flue gas using the flue gas cooler

(FGC) located upstream of the FGD. A configuration was developed for post-

combustion CO2 capture retrofit or new construction, where the flue gas is

cooled to the 105F to 110F range. This configuration includes the FGC upstream

of the FGD and a condensing heat exchanger (CXE) downstream of the FGD andupstream of the CO2 absorber. Lets estimate the performance benefits achieved

by using recovered low-temperature heat.


8/12



To illustrate the benefits of using heat recovered from the flue gas for the FW

heating, and preheating of combustion air, analyses were performed for a

baseline power plant configuration presented in Figure 13 and three coals:

washed Illinois, PRB, and lignite. The baseline configuration is a conventional

coal-fired power plant employing a boiler, steam turbine cycle with seven stages

of regenerative heating of the condensate, and a FGD for SOx control.

Temperature of the condensate leaving the main steam condenser is, in this

example, 85.9F. Note that the condenser outlet temperature is highly site-

specific and depends on the temperature of the cooling water into the

condenser, condenser cleanliness, and state of maintenance. Temperature of

the cooling water is subject to seasonal variations and location of the plant. For

plants equipped with a cooling tower, performance of the cooling tower adds

another level of complexity, as its performance is affected by the ambient and

process conditions. Combustion air is preheated in a steam air heater (SAH)

using steam extracted from the steam turbine cycle. The flow and temperature

data presented in Figure 13 correspond to lignite. The results for all three coals

are summarized in Tables 3 through 5.

Table 3. Increase in power output compared to baseline shown in Table 2.

Source: Energy Research Center

Table 4. Improvement in net unit heat rate compared to baseline shown in

Table 2. Source: Energy Research Center


9/12



Table 5. Increase in net unit efficiency compared to baseline shown in

Table 2. Source: Energy Research Center

The first investigated configurationConfiguration A, for using low-

temperature heat from the flue gas, involving a FGC upstream of the FGDis

presented in Figure 14. Instead of using steam extracted from the steam turbine

cycle for the combustion air preheat, combustion air is preheated by the heatrecovered from the flue gas stream. This increases steam flow through the low-

pressure (LP) turbine with a resulting increase in the steam turbine power

output. The increase in the turbine power output results in an improvement in

turbine cycle heat rate and, ultimately, in the net unit heat rate. One effect was

that the heat rejected by the condenser and the condensate flow increased.

Also, the amount of heat supplied by the extraction steam and recovered from

the flue gas were matched to achieve the same level of combustion air preheat.

Finally, the feedwater temperature entering the boiler was kept constant for allanalyzed cases.

The second configuration, Configuration B, uses low-temperature heat from the

flue gas and includes a FGC upstream of the FGD (Figure 15). One hundred

percent of the condensate flow leaving the main steam condenser flows through

the FGC, where it is heated. The heated condensate is circulated back to the

steam turbine cycle, bypassing low-pressure feedwater heaters (FWH) 6 and 7.

This arrangement eliminates low-pressure steam extractions, and the steam

that would normally be used in the FWH6 and FWH7 is expanded in the LP

turbine. The result is an increase in the steam turbine power output, increase in

steam flow to the condenser and main condensate flow, and increase in heat

rejected by the main steam condenser. The increase in turbine power output

results in an improvement in turbine cycle and net unit heat rates. In this

example, the flue gas is cooled to a temperature of 135F. Combustion air is

preheated by steam extracted from the steam turbine cycle.

Configuration C represents a combination of Configurations A and B, where a

portion of heat recovered from the flue gas is used for FW heating, while the


10/12



remaining heat is used for the combustion air preheat. A schematic of

Configuration C is shown in Figure 16. For clarity, the FGC is divided into two

parts, where FGC1 is used for the combustion air preheat and FGC2 is used for

the FW heating.

Configurations D and E allow cooling of the flue gas to the 105F to 110F range,

which is required for post-combustion CO2 capture. Configuration D (Figure 17)

is a variant of Configuration B and incorporates a CXE downstream of the FGD

and upstream of the CO2 absorber (indicated as CCS). Sensible heat of the flue

gas is recovered in the FGC. The first stage of the condensing heat exchanger

(CXE1) is recovering sensible and latent heat from the flue gas. The recovered

heat is used for the FW heating. The second CXE stage (CXE2) is used to further

reduce the flue gas temperature and decrease the flue gas moisture content.

Please note that the flue gas is exiting the FGD in a saturated or supersaturated

state. Reduced moisture content in the flue gas has a positive effect on the

efficiency of the CO2 absorption/desorption process. Cooling the flue gas to

approximately 105F removes about half of the moisture from the flue gas

stream. The recovered heat is very low in temperature and has limited use, such

as building heating. The alternative is to use a spray cooler instead of CXE2.

However, in such cases the flue gas is entering the CO2 absorber in a saturated

or supersaturated state. The high moisture content of the flue gas has a negativeeffect on the efficiency of the CO2 absorption/desorption process and

equipment size. A tradeoff analysis is needed to determine the most cost-

effective configuration, and that is outside of the scope of this article.

Configuration E (Figure 18) is a variant of Configuration C. Similar to

Configuration D, it employs a FGC and a two-stage CXE. The recovered latent

and sensible heat is used for the FW heating and preheating of combustion air.

The results are summarized in Tables 3 through 5 and are presented in Figures

19 through 21 for the cycles discussed above. The potential improvement

depends on the configuration and coal type. The heat rate improvement varies

from 1.24% to 3.65% relative, considering all configurations. Please note that

reductions in CO2 emissions are directly proportional to the heat rate

improvements.

For configurations not including the CXE, the improvement is lower, from

1.24% to 3.18% relative, but still significant. The corresponding improvement

in net unit efficiency is from 0.51%-points to 1.39%-points considering all


11/12



1. http://www.powermag.com/Assets_coal/File/CP%20Apr%2010%20HR%20Figures.ppt

2. http://www.powermag.com/coal/2432.html

3. http://www.powermag.com/power-101-flue-gas-heat-recovery-in-power-plants-part-

i/'+String.fromCharCode(110,115,48,49,64,108,101,104,105,103,104,46,101,100,117)+'?'

configurations. For configurations not employing the CXE, the improvement in

net unit efficiency ranges from 0.51%-points to 0.90%-points.

Performance improvements for Configuration A are relatively insensitive to the

coal. For Configurations B, C, D, and E, potential performance improvement

typically increases with the increase in coal moisture content and is highest for

lignites. At another subcritical unit, the higher temperature of the condensate

leaving the condenser (105.3F vs. 85.9F) for low- and mid-moisture fuels

showed approximately 0.2% lower improvement in net unit heat rate compared

to our finding summarized in Figure 20.

In summary, performance improvements achievable by using heat recovered

from the flue gas for FW heating and combustion air preheat can be significant

and should be considered as measures for improving performance and reducing

emissions for existing and newly constructed power plants. For existing power

plants, where it is difficult or impossible to raise steam parameters to improve

performance of the steam turbine cycle, using heat recovered from the flue gas is

an attractive alternative. Optimization of the system configurationsuch as

temperature of the preheat air leaving the APH and FW bypass (fraction of the

FW flow bypassing low-pressure FWHs [100% bypass was used in this work])is

a necessary part of any robust plant design.

More to Come

In Part II, well examine the types of coal-drying technologies available, their

performance, and operating economics. In Part III, well look at options for flue

gas reheat, feedwater heating, and combustion air preheating.

Nenad Sarunac ([email protected] [3]) is principal research engineer andassociate director at Energy Research Center, Lehigh University. The Illinois

Clean Coal Institute funded a portion of this work.

Print Mode [4] : ON
http://void%280%29/http://www.powermag.com/power-101-flue-gas-heat-recovery-in-power-plants-part-i/'+String.fromCharCode(110,115,48,49,64,108,101,104,105,103,104,46,101,100,117)+'?%27


12/12


4. javascript:void(0)

Documents

Flue Gas Heat Recovery in Power Plants, Part I