Emission Characteristics of Diesel Engine Powered Cogeneration Systems

Power Efficiency Guide

Ultimate Guide to Power Efficiency

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Aysegul Abusoglu and Mehmet Kanoglu

12.1 Introduction

The industrial sector is a major electricity consumer. The growth rate of electricity demand is high especially in the developing countries and a continuous growth is anticipated for coming years. Many governments revise their energy policy introducing legislative and economic incentives to encourage private participation in the power generation investments. Generally, a favorable economic environment is created for the industries that make use of energy conservation, and cogeneration is an effective method of achieving this. Unfortunately power facilities have the potential of environmental pollution by the emission of harmful gases and other hazardous components. Power plants and cogeneration facilities emit some undesirable content in exhaust gases including solid particles, and these emissions, depending on their level, can be very harmful for human beings and other organisms (Frangopoulos, 1993; EPA, 2000).

Cogeneration or combined heat and power production (CHP) is a technology used by many industries all over the world since the beginning of the 20th century as an economic means of providing industrial plant energy requirements. Reciprocating engine-powered cogeneration systems are commonly applied in the 2.5-50 MW range for power production. They are widely available as compact, fully packaged, and skid-mounted units that are easy to install. Reciprocating engine systems usually use turbocharged, intercooled industrial engines. The main fuel used is heavy fuel oil. Natural gas, diesel oil, LPG, propane, and biogas can also be used. For the diesel engine-powered cogeneration (DEPC) applications, heavy fuel oil and natural gas are the major fuels due to lower cost and high availability (Stenhede, 2004).

A major portion of environmental pollution is caused by the exhaust emission from the internal combustion engines. The three main pollutants which are subject to exhaust emission legislation are carbon monoxide (CO), unburned

I. Dincer et al. (eds.), Global Warming, Green Energy and Technology,

DOI 10.1007/978-1-4419-1017-2_12, © Springer Science+Business Media, LLC 2010

hydrocarbons (HC), and nitrogen oxides (NOx) (Abdel-Rahman, 1998). Normally nitrogen is very inert but at high temperatures oxygen and nitrogen get the chance to mate for the formation of NOx as in the case of combustion processes of diesel engines. Other important pollutants contained in exhaust emissions are aldehydes (H-C-O compounds), lead components produced by use of leaded fuels, sulfur dioxide (SO2), and particulates especially with diesel engines.

Heavy fuel oil has a high share in fossil fuel consumption especially for diesel engine-powered cogeneration applications. Two major categories of heavy fuel oil are distillate oils and residual oils. Being more viscous and less volatile than distillate oils, the heavier residual oils may need to be heated for ease of use and to facilitate proper atomization for combustion. Residual oils are used mainly in industrial applications, especially in power production facilities.

In the utilization of residual heavy fuel oils for industrial power production, two major problems arise: hazardous emissions and depletion of fuel reserves in the world. Cogeneration which generates heat and power simultaneously from same fuel supply may be the most appropriate method to address these concerns (Kaarsberg et al., 1999; Stenhede, 2004). In literature, two methods were used for measuring the effectiveness of cogeneration systems in fuel savings and emission reduction. In the first method, emissions were compared between cogeneration systems and separate power heat systems (SPHS) by using the difference between the heat rates of conventional fossil fuel-fired systems and the cogeneration systems (Kaarsberg et al., 1999; Voorspools and D'haeseleer, 2000a; 2000b). In the second method, emissions released from cogeneration systems were distributed to the products (power and heat) and compared to the conventional power and heat production systems separately (Sevilgen et al., 2003). In these studies, fuel saving analysis (FSA) was performed in terms of the first law efficiency (also called fuel utilization efficiency). The first law efficiency treats power and heat equally and this is a weakness for its use as a performance parameter for environmental studies as in the case of thermoeconomic analysis of cogeneration systems.

In this chapter, the exergetic efficiency is used for environmental assessment of the diesel engine-powered cogeneration systems. For this, emissions released from an actual diesel engine-powered cogeneration system (DEPCS) are investigated and the operations of desulfurization (DeSOx) and denitrification (DeNOx) units are described. The emissions assessment from DEPCS are performed by using fuel saving analysis method based on the exergetic efficiency rather than fuel utilization efficiency that is commonly used in literature. Exhaust emission reduction is expressed with an analogy to fuel savings and compared to SPHS. First, we present information on air pollution and environmental concerns in Turkey.

12.2 Air Pollution and Environmental Concerns in Turkey

Air pollution is becoming a great environmental concern in Turkey. Air pollution from energy utilization in the country is due to the combustion of coal, lignite, petroleum, natural gas, wood and agricultural and animal wastes. On the other hand, owing mainly to the rapid growth of primary energy consumption and the increasing use of domestic lignite, NOX and SO2 emissions, in particular, have increased rapidly in recent years in Turkey. The major source of these emissions is the power sector, contributing more than 50% of the total emissions (IEA, 2005).

12.2.1 CO2 Emissions and greenhouse gases

Carbon dioxide (CO2), methane (CH4), and nitrous oxide (N2O) emissions are all produced during fuel oil combustion. Nearly all of the fuel carbon in fuel oil is converted to CO2 during combustion process. Turkey's total carbon dioxide (CO2) emissions amounted to 193 million tons (Mt) in 2002. Public electricity and heat production were the largest contributors of CO2 emissions, accounting for 28% of the country's total. The industry was the second largest, representing 26% of total emissions, followed by transport, which represented 19%, and direct fossil fuel use in the residential sector with 10% (Hepbasli, 2005 IEA, 2005; Say and Yucel, 2006;). In Fig. 12.1, CO2 emissions by fuel types between 1973 and 2002 are given (IEA, 2005). Other sectors, including other energy industries, account for 17% of total emissions. Since 1990, emissions from public electricity and heat production have grown rapidly than in other sectors, increasing by 6%. Simultaneously, the shares of emissions from the residential and transport sectors both dropped by 7% and 3%, respectively, while the share of emissions from the power production and manufacturing industries and construction sector remained stable (Hepbasli, 2005; Say and Yucel, 2006).

12.2.2 NOX and SOX emissions

The main air pollutants related to the power production and use of energy are sulfur oxides (SOX) - in particular sulfur dioxide (SO2), - nitrogen oxides (NOX), and suspended particulates. Sulfur oxides (SOX) emissions are generated during oil combustion from the oxidation of sulfur contained in the fuel. The emissions of SOX from conventional combustion systems are predominantly in the form of SO2. On average more than 95% of the fuel sulfur is converted to SO2, about 1-5% is further oxidized to sulfur trioxide (SO3), and 1-3% is emitted as sulfur particulate. SO3 readily reacts with water vapor (both in the atmosphere and in flue gases) to form a sulfuric acid mist. The use of high-sulfur lignite in particular is an important source of air pollution. In 2002, Turkey emitted a total of 2.08 Mt of SO2, equivalent to 30.4 kg per capita. This is slightly below the OECD average, which at the end of the 1990s was 32.9 kg per capita (IEA, 2005). Electricity generation and industry are by far the largest contributors to SO2 emissions in the country, representing respectively 65% and 21% of total emissions in 2001 (Ocak et al., 2004).

Years

Fig. 12.1 CO2 emissions by fuel types between 1973 and 2002 in Turkey (IEA, 2005).

The term NOX refers to the composite of nitric oxide (NO) and nitrogen dioxide (NO2). For most fossil fuel combustion systems, over 95% of the emitted NOX is in the form of nitric oxide. Nitrous oxide (N2O) is not included in NOX but has recently received increased interest because of atmospheric effects. Emissions of NOX totaled approximately 0.90 Mt in 2003, slightly below the 2000 levels of 0.92 Mt. On a per capita level, emissions were of 12.8 kg in 2003, substantially below the OECD average of approximately 40 kg at the end of the 1990s. Transportation and predominantly road-based transport, is the largest source of NOX emissions, representing 36% of total emissions. Electricity generation and industry represent over 20% each (IEA, 2005; Ocak et al., 2004).

12.2.3 Particulate matter (PM) emissions

Particulate emissions maybe categorized as either filterable or condensable. Filterable particulate matter emissions depend predominantly on the grade of fuel fired. Combustion of lighter distillate oils results in significantly lower PM formation than does combustion of heavier residual oils. In general, filterable PM emissions depend on the completeness of combustion as well as on the oil ash content (EPA, 2000). The PM emitted by distillate oil-fired combustion processes primarily comprises carbonaceous particles resulting from incomplete combustion of oil and is not correlated to the ash or sulfur content of the oil. However, PM

emissions from residual oil burning are related to the oil sulfur content. This is because low-sulfur residual oil (heavy fuel oil no. 6), either from naturally low-sulfur crude oil or desulfurized by several processes, exhibits substantially lower viscosity and reduced asphaltene, ash, and sulfur contents, which results in better atomization and more complete combustion (IEA, 2005). The emission standards for power plants in Turkey are given in Table 12.1 with the revision in 2004. These standards remain significantly less stringent than those currently in force at the EU (European Union) level as defined by the revised Large Combustion Plants (LCP) directive (IEA, 2005; Ulutas, 2005). For example, for new liquid fuel-fired power plants (authorized after November 2003) with a thermal input greater than 300 MW, the NOX emissions limit is set at 200 mg/Nm3 at the EU level, while the NOX emissions limit is 800 mg/Nm3 in Turkey.

Table 12.1 Emission standards for power plants in Turkey (IEA, 2005).

1986 REGULATION (mg/Nm3)

PM

CO

NO,

SO2

OP 1 NP

OP 1 NP

<300 MWth

>300 MWth

ROH>20,000

NP

ROH<50,000 and OP

ROH>50,000 and NP

SFFP

250

150

250

1000

800

3200

2000

3200

1000

LFFP

110

110

175

1000

800

3200

1700

1700

800

GFP

10

10

100

500

500

60

60

60

60

2004 REGULATION (mg/Nm3)

SFFP

100

200

800

2000 (<100 MWth) 1300 (100-300 MWth)

1000

>300 MWth

LFFP

110-170 >15 MWth

150

800

1700 (1% Sa) 2400 (1.5% S) (<100 MWth) 1700 (100-200 MWth)

800 >300 MWth

GFP

10

100

500

60

60

SFFP: solid fuel-fired plants, LFFP: liquid fuel-fired plants, GFP: gas-fired plants,

OP & NP: old plants and new plants, refer to power plants built before and after Air Quality Protection regulation came into force in 1986

ROH: remaining operating hours a Sulfur content (mass percentage) of the fuel used

SFFP: solid fuel-fired plants, LFFP: liquid fuel-fired plants, GFP: gas-fired plants,

OP & NP: old plants and new plants, refer to power plants built before and after Air Quality Protection regulation came into force in 1986

ROH: remaining operating hours a Sulfur content (mass percentage) of the fuel used

12.3 Description of Exhaust Flow in the DEPC Plant

The actual DEPC plant, SANKO Energy, is located in the southeastern Turkey, the city of Gaziantep (Abusoglu and Kanoglu, 2008). The electricity is generated by three, diesel engine-actuated generator sets each having two turbochargers.

Each diesel engine-generator set in the plant produces 8.44 MW electricity and 2.7 tons/h saturated steam at 8 bars and 170°C. The engine operating and performance characteristics are listed in Table 12.2. For calculated engine parameters, related data can be found from related papers and reference books (Abusoglu and Kanoglu, 2008, 2009a, 2009b; Pulkrabek, 1997). The schematic diagram of the plant's exhaust flow line for one engine set is shown in Fig. 12.2. The permissible annual electricity production is 217 GWh and the annual heavy fuel oil consumption is nearly 45,000 tons at designed operating conditions.

The exhaust gases leaving the engine flow through the turbine of the turbocharger unit to produce the necessary shaft work for the compressor. The exhaust gases leaving the turbine is sent to the DeNOx (denitrification) unit in which the NOx emission is lowered to acceptable legal values by spraying urea solution onto the exhaust gases. Then, the exhaust gases leaving the turbine enter the waste heat recovery unit to transfer heat to the feedwater to produce steam for manufacturing facilities in the factory and for preheating of streams in the auxiliary equipments such as fuel forwarding module and fuel oil in daily usage tank. Finally, the exhaust gases flow through a DeSOx (desulfurization) unit before being exhausted to the atmosphere.

Atmosphere

Atmosphere

Fig. 12.2 Exhaust flow schematic of the DEPC plant. Only one engine set is shown. 12.3.1 Denitrification unit (DeNOx)

The main aim of the denitrification unit is to treat NOx exhaust emissions as N2 and water. During burning of fuel the molecules including nitrogen reacts with oxygen in the intake air and produce NO. If the amount of oxygen is less, then instead of NO, the product will be N2. This process is the basic of the denitrification principle by improving the quality of combustion. For each engine-

Fig. 12.2 Exhaust flow schematic of the DEPC plant. Only one engine set is shown. 12.3.1 Denitrification unit (DeNOx)

The main aim of the denitrification unit is to treat NOx exhaust emissions as N2 and water. During burning of fuel the molecules including nitrogen reacts with oxygen in the intake air and produce NO. If the amount of oxygen is less, then instead of NO, the product will be N2. This process is the basic of the denitrification principle by improving the quality of combustion. For each engine-

generator set one DeNOX unit is installed. Casing of the units are insulated to prevent heat transfer. NOX emissions are treated into the nitrogen (N2) and water (H2O) by selective catalytic reduction (SCR) process. The SCR reaction is catalyzed by vanadium/titanium catalysts at temperatures in the range 300-500°C as shown below:

The catalytic reactors are made of special ceramics shaped in honeycomb modules. Ammonia (NH3) obtained from urea in liquid form is used as redactor element. The exhaust gas at 300-450°C is transferred from cylinders to DeNOX units by insulated exhaust ducts. Exhaust gases at high temperature pass through the catalytic reactors; here NH3 is injected into the exhaust gases, and so NOX react with NH3 and produce nitrogen (N2) and water (H2O).

Table 12.2 Operating and performance characteristics of Diesel 32 V 40 engine.

Cylinder diameter, D (mm)

32G

Cylinder bore, B (mm)

32G

Stroke, S (mm)

4GG

Crank offset, a (mm)

2GG

Number of cylinders, Nc

18

Piston area, AP (m2)

G.G8

Compression ratio, rc

12.31

Displacement volume, Vd (m3)

0.03211

Clearance volume, Vc (m3)

G.GG283

Air flow rate, m a (kg/s)

18.4

Fuel flow rate, m f(kg/s)

G.46

Air-fuel ratio, AF

4G.G

Exhaust flow rate (kg/s)

11.G

Piston mean speed, Up (m/s)

1G.G

Engine speed, N (rpm)

15G

Break power, WVb (kW)

844G

Brake mean effective pressure, bmep (kPa)

249G

Torque, T (Nm)

114.6

Brake-specific fuel consumption, bsfc (g/kWh)

184.G

Specific power, SP (kW/m2)

6211

Specific volume, SV (m3/MW)

G.G6434

Output per displacement, OPD (kW/L)

14.58

Combustion efficiency, nc

G.98

Volumetric efficiency, nv

1.29

Thermal efficiency, nth

G.41

These two final products are natural materials and have no harmful effect on the environment. The total solid urea consumption of DeNOX unit is about 260 kg/h, where total NOX mass flow is 402 kg/h. The treated flue gas should include NOX at a total amount less than 800 mg/Nm3 as indicated in Table 12.1.

12.3.2 Desulfurization unit (DeSOx)

From process point of view the proposed flue gas desulfurization system is referred to as "limestone-gypsum" process, based on the use of common limestone (CaCO3) in powder form as reagent and the production of gypsum as by-product. The limestone consumption is nearly 750 kg/h. The waste gas purification process is performed for each gas stream in a scrubber with integrated quencher where SO2 and other pollutants (SO3 - HCI) are removed by washing liquid which is a suspension of limestone in water. The waste gas enters laterally above the bottom of the scrubber into the quenching zone of the scrubber. The waste air is cooled down to the saturation temperature in the quencher zone. From here the waste gas flows vertically upward to the subsequent nozzle lever where the pollutants absorption, as well as some dust separation takes place. During the absorption of SO2, SO3, and HF, hardly soluble deposits such as CaSO4, H20, CaSO3, and CaF2 are formed and suspended in the scrubbing solution. In order to prevent larger deposits in the scrubbing liquid tank, an agitator is installed in the scrubber sump. This serves at the same time for dispersing the oxidation air. The reaction that takes place during the desulfurization process is CaCO3(S) + SO2(g) + 0.5H20 ^ CaS03.0.5H20 + CO2(g) (12.2)

When the oxidation with air take place

CaCO3(S) + 0.5H20(l) + 1.5H2O(g) ^ CaSO4.2H2O(s) (12.3)

Due to the continuous recirculation and subsequent formation of some sulfites and sulfates a portion of recirculated liquid is bled off to a dewatering system that provides a reduction of moisture down to 15% residual water content, in order to handle the gypsum removal. The scrubbing and cooling liquid suspension is accumulated in the scrubber lower sump from where it is taken and recirculated by suitable wear-resistant recirculation pumps. The treated flue gas should include SO2 at a total amount less than 2400 mg/Nm3 (see Table 12.1). In Tables 12.3 and 12.4, emission content of exhaust gases before and after the flue gas treatment units (DeNOX and DeSOX) are given.

12.4 Fuel Savings Analysis

The diesel engine-powered cogeneration system (DEPCS) converts waste heat, which is a consequence of electricity production by diesel engines, to useful heat. In these systems, the conversion ratio of fuel chemical or heat energy to electrical energy can be defined as electricity (or thermal - first law) efficiency and the conversion ratio to heat energy is defined as heat efficiency Electricity and heat generation are denoted by W and Q, respectively.

Table 12.3 Emission content of exhaust gases before the flue gas treatment for the DEPC plant._

Content

Engine 1

Engine 2

Engine 3

O2 (%)

13.40

13.45

13.55

CO2 (%)

5.55

5.55

5.45

CO (mg/m3)

75.5

90

105

NO (mg/m3)

1485

1500

1532

SO2 (mg/m3)

935.5

1149

1053

Gas temperature (°C)

309.5

312.5

310

In separate power heat systems (SPHS), separate fuels are used to obtain electricity and heat. Fuel consumption in these systems was treated as dependent parameter on electricity generation system efficiency ^se and boiler heat efficiency ^sh in literature (Kaarsberg et al., 1998, 1999, Voorspools and D'haeseleer, 2000a, 2000b; Sevilgen et al., 2003).

Table 12.4 Emission values of exhaust gases after the flue gas treatment for the DEPC plant._

Type of fuel

Fuel oil no. 6

Power produced (MW)

25.32

Exit exhaust temperature (°C)

53.7

Velocity of exhaust gas at the exit (m/s)

8.1±0.1

Mass flow rate of exhaust gas at the exit (m3/h)

123,464

Particulate matter concentration (mg/m3)

96.78

Particulate matter emission (kg/h)

11.8695±2.6904 (limit value: 15)

CO concentration (mg/m3)

101.67

CO emission (kg/h)

12.5507±1.4898 (limit value: 5)

SO2 concentration (mg/m3)

40.95

SO2 emission (kg/h)

5.0673±0.6036 (limit value: 100)

NO concentration (mg/m3)

1282.14

NO emission (kg/h)

158.3056±18.7665 (limit value: 20)

NO2 concentration (mg/m3)

1983.75

NO2 emission (kg/h)

244.94

O2 concentration (%)

12.8

CO2 concentration (%)

6.3

In the analysis of fuel savings, the exergetic efficiency is used for environmental assessment of DEPCS system versus SPHS. In comparing DEPCS and SPHS, it is assumed that they produce the same amount of electricity and heat. Electricity and heat generation are calculated from

where LHVf is the lower heating value of the fuel, mf is the rate of fuel used, £eand £ hare the exergetic efficiencies of DEPCS in terms of electric power produced and steam generated, respectively. The amount of fuel required to produce the same amount of electricity in SPHS can be determined from m sef = m f C e

where C e is the ratio of the lower heating value of the fuel used in DEPCS to the lower heating value of the fuel used in SPHS, and £se is the exergetic efficiency of SPHS in terms of power produced. The amount of fuel required to produce heat in the boiler, which is equal to the heat produced in DEPCS, is calculated from mshf = mf Ch ih.

where Ch is the ratio of the lower heating value of the fuel used in DEPCS to the lower heating value of the fuel used in the boiler of SPHS, and £sh is the exergetic efficiency of SPHS in terms of steam generated. The amount of fuel savings in this case can be expressed as (Kaarsberg et al., 1999)

The limit condition in Eq. (12.8) that needs to be satisfied to obtain fuel savings in DEPCS is

In case of using the same fuel in both systems Ce = Ch = 1 ■

becomes

The required data and the results of thermodynamic calculations for DEPCS are given in Table 12.5 (Abusoglu and Kanoglu, 2008, 2009a, 2009b). For SPHS, required data is taken from literature (Sevilgen et al., 2003). The net electrical power produced and steam generated for DEPCS are 25,320 kW and 176.1 kW, respectively. The mass flow rate of fuel oil in DEPCS is 1.38 kg/s (see Table 12.5).

Using the equations in this section, the mass flow rates of fuel for the power production unit and the boiler unit of SPHS are determined to be 1.66 kg/s and 0.20 kg/s, respectively. It is clear that using separate units of power and heat production increases the fuel consumption by 34.8% with respect to the existing DEPCS.

Table 12.5 The data of the DEPC plant for the fuel savings analysis (Abusoglu and Kanoglu, 2008, 2009a, 2009b)._

Mass flow rate of fuel oil (kg/s)

1.38

Lower heating value of fuel oil (kJ/kg)

42,100

Power produced (MW)

25.32

Generated steam output (kW)

116.1

Mass flow rate of exhaust gas (kg/s)

51.G

Exergetic efficiency of DEPC plant, se (%)

4G.6

Exergetic efficiency of diesel engine, £ de (%)

4G.4

Exergetic efficiency of waste heat boiler, s h (%)

11.4

12.5 Emission Difference Analysis

The amount of emission produced depends on the electricity production in DEPCS while it depends on both electricity and heat generation in SPHS. The amount of emission released by DEPCS is calculated from

where 6>DEPC stands for the specific emission of DEPCS (amount of emission released per unit electricity production) and "i" represents emission type (CO2, SO2, and NOX). Emission amounts of SPHS for electricity and heat production are given respectively as (Kaarsberg et al., 1999)

where MSP,i and MSH,i are emission amounts of SPHS for power and heat production respectively, and and are the specific emissions of power and heat produced in SPHS, respectively. The amount of emission reduction (A M) owing to DEPCS is given by

where fi is the heat-power ratio (ratio of heat energy to electrical energy in the cogeneration system). The limit condition for the emission reduction is given as #SP,i + fi#SH,i > #DEPC,i (12.15)

When specific emissions are constant, a change in heat-power ratio will change the emission reduction provided by DEPCS or any cogeneration facility. The heat-power ratio for the case of equal emission production from the DEPC

and SPH systems is defined as critical heat-power ratio fi* and expressed as / = - ^ (12.16)

Average specific emissions of the DEPC plant can be obtained using the values in Table 12.5. For SPHS, these values can be taken from literature (Kaarsberg et al., 1998, 1999; Voorspools and D'haeseleer, 2000a, 2000b; Sevilgen et al., 2003). Table 12.6 contains specific emissions for gas turbines, DEPC, and gas engines for both cogeneration and conventional power plant applications. Comparison of these specific emissions and the efficiencies of the DEPC and SPH systems are given in Figs. 12.3 and 12.4, respectively. Exergetic efficiencies and the heat-power ratio of the DEPC plant are given in Table 12.7. Natural gas, lignite, and heavy fuel oil are considered as fuels in boilers used for heat production in SPHS and average specific emissions of these fuels are shown in Table 12.8.

Table 12.6 Specific emissions of various cogeneration plants and conventional power plants (g/kWeh) (Kaarsberg et al., 1998, 1999; Voorspools and D'haeseleer, 2000a, 2000b; Sevilgen et al., 2003)._

Emission

Cogeneration systems

Conventional power plants

Gas turbine

DEPC

Gas engine

SPH

Combined cycle

NO*

0.25

0.41

1.34

3.3

0.18

CO2

580

500

529.1

997.3

400

SO2

-

2.20

-

3.7

-

By using the emission values in Table 12.4, the amount of each emission can be calculated for DEPCS for full load power production as 10.381 kg for NOX, 12.66 m3 for CO2, and 55.704 kg for SO2. Corresponding values for SPHS owing to the same amount of power produced and steam generated as DEPCS are determined, respectively, as 83.56 kg and 0.110 kg for NOX, 25.25 m3 and 0.05 m3 for CO2, and 93.68 kg and 1.28 kg for SO2. It is clear that the DEPC plant can reduce NOX, CO2, and SO2 emissions by 87.6%, 50% and 41.3%, respectively, in comparison to SPHSs.

Table 12.7 Exergetic efficiencies and heat-power ratios for the DEPCS and SPHS (Abusoglu and Kanoglu, 2008, 2009a, 2000b; Sevilgen et al., 2003). _

£

ß

DEPC

0.404

Steam turbine power system Combined cycle system boiler

0.334

-

0.480

-

0.770

DEPC

Fig. 12.3 NO* and SO2 emissions comparison of DEPC and SPH at full load condition.

E 1000

600 400

DEPC

SHPS

Fig. 12.4 CO2 emissions comparison of DEPC and SPH at full load condition.

Table 12.8 Emissions produced in boiler for producing heat (g/kWh) (Kaarsberg et al., 1999; Voorspools and D'haeseleer, 2000a, 2000b; Sevilgen et al., 2003)._

Fuel type

NO,

CO2

SO2

Natural gas

0.93

201.92

-

Coal (lignite)

0.89

364.25

9.21

Fuel oil no. 6

0.62

263.95

7.25

In DEPCS, amount of emissions increase with load as shown in Fig. 12.5 since specific emissions are constant. However, determining emissions reduction by using fuel savings method may cause errors because it ignores specific emission differences for different technologies utilizing the same fuel type. It can be seen that these differences are important parameters which should be taken into consideration. Parameters affecting emission differences are specific emissions, fuel type in cogeneration (i.e., emissions will be different when diesel oil or heavy fuel oil is used in DEPCS) and SPHS, and heat-power ratios of the cogeneration system.

Load Conditions of DEPC

100%

Fig. 12.5 Variation of NO* and SO2 emissions with respect to the load variation in DEPCS.

12.6 Conclusions

In this chapter, exhaust emission characteristics of an actual DEPC plant and the operations of denitrification (DeNOX) and desulfUrization (DeSOX) flue gas treatment units in the facility are studied. Exhaust emission assessment is performed by using fuel savings analysis method and exergetic efficiency. Exhaust emission reduction is expressed using an analogy to fuel savings. The results show that replacing separate heat-power producing applications by cogeneration applications such as DEPC greatly reduces unwanted emissions, namely, the DEPC plant can reduce NOX, CO2, and SO2 emissions by 87.6%, 50% and 41.3%, respectively, in comparison to SPHS. However, in light of actual case study presented in this chapter the following conclusions can be listed for using fuel saving analysis methodology and emission reduction:

• Emission reduction is affected by system parameters such as specific emission amounts, fuel types, cogeneration types, and different specific heat and power applications.

• Emission reduction calculated by fuel saving method can cause errors since with this method, specific emission differences are ignored for different technologies which use the same type of fuel.

• Fuel saving analysis method cannot determine the limit conditions for required emission reduction. For this reason cogeneration applications cannot always reduce emissions (Sevilgen et al., 2003).

• The emissions assessment from DEPCS is performed by using fuel saving analysis method based on the exergetic efficiency rather than fuel utilization efficiency that is commonly used in literature (Kaarsberg et al., 1999; Voorspools and D'haeseleer, 2000a, 2000b; Sevilgen et al., 2003). Exergy-based fuel saving analysis methodology usage accounts for the quality of outputs of power production systems and thus the arbitrariness of the results can be removed. However, for rational results, with the exergy-based evaluation methodologies, the allocation of emissions to the power and heat produced should be performed directly.

Acknowledgments

The authors acknowledge the support provided by the Scientific Research Projects Unit at the University of Gaziantep and greatly appreciate the plant management and engineers of SANKO Energy for their cooperation throughout this study and for supplying data for the plant.

Nomenclature

W power, kW Q heat rate, kW LHV lower heating value, kJ/kg m mass flow rate, kg/s M amount of emission (mg/Nm3) Greek letters r first law (energy) efficiency s second law (exergetic) efficiency

0 specific amount of emission (g/kWh) P heat to power ratio P critical heat to power ratio

Subscripts se se separate electricity separate heat electricity heat fuel sh e h f

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