overview of cogeneration and its status in asia

8/7/2019 OVERVIEW OF COGENERATION AND ITS STATUS IN ASIA

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PART 1:

OVERVIEW OF COGENERATION AND ITS STATUS IN ASIA


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The concept of cogeneration 3

CHAPTER 1: THE CONCEPT OF COGENERATION

1.1 Introduction

Industries and commercial buildings all over the world are the major energy end-users. In thedeveloping countries of the Asia-Pacific region, electricity accounts for only around 20 percent of the total energy demand of the industrial sector, the remaining demand being mostlyin the form of thermal energy. Likewise, as much as 60 per cent of the energy demand ofmodern high-rise buildings in the tropical climate comes from comfort cooling. Typically,state-owned power companies assure electricity supply whereas on-site boilers and chillersmeet the heating and cooling needs of the users, respectively.

Thermal power plants are a major source of electricity supply in many developing countries.The conventional method of power generation and supply to the customer is wasteful in thesense that about a quarter of the primary energy fed into the power plant is actually madeavailable to the user in the form of electricity. The major source of loss in the conversionprocess is the heat rejected to the surrounding water or air due to the inherent constraints ofthe different thermodynamic cycles employed in power generation. Moreover, users may befar from the point of generation, which results in additional transmission and distributionlosses in the network. The concept of cogeneration is based on the principle of thermalcascading which consists of generating power on site where a substantial fraction of wasteheat produced is recovered to satisfy the heating/cooling demand of the end-user. There isthus a considerable enhancement of the overall conversion efficiency.

Combined heat and power generation (CHP), or cogeneration as it is popularly known, is

widely recognized world-wide as an attractive alternative to the conventional power and heatgenerating options due to its low capital investment, shorter gestation period, reduced fuelconsumption and associated environmental pollution, and increased fuel diversity.

Though the concept of cogeneration has been in existence for over a century now, it found itspopularity and renewed interest during the later half of the 70s and the early 80s. The mainfactors that attributed to this phenomenon are the two oil shocks that led to spiralling energyprices and the availability of efficient and small-scale cogeneration systems which becamecost-effective and competed well with the conventional large-scale electricity generationunits. A variety of measures were undertaken by several national authorities to promote thegrowth of cogeneration.

As energy prices started to fall during the mid-80s, some countries lost interest in thistechnology, particularly those that had excess generating capacities. Taking the example ofEurope, a great diversity can be observed among the member countries; electricity producedfrom cogeneration ranged from over 34 per cent in the Netherlands whereas it was less than1.5 per cent in France.

The main reasons that have revived the interest in cogeneration once again are the rapidlyincreasing demand for electricity, constraints faced by the national authorities to financeadditional power generating capacities, and the growing concern to limit the environmentalemission and pollution associated with the use of energy. Cogeneration is presently beingrecommended when there is plan for expansion of existing facilities, development of newindustrial zones, replacement of outdated steam generation systems, or when the cost of

energy is high and there is scope for selling power.


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4 Part I: Overview of cogeneration and its status in Asia

1.2 Principle of Cogeneration

Cogeneration is defined as the sequential generation of two different forms of useful energyfrom a single primary energy source, typically mechanical energy and thermal energy.

Mechanical energy may be used either to drive an alternator for producing electricity, orrotating equipment such as motor, compressor, pump or fan for delivering various services.Thermal energy can be used either for direct process applications or for indirectly producingsteam, hot water, hot air for dryer or chilled water for process cooling.

Cogeneration provides a wide range of technologies for application in various domains ofeconomic activities. The overall efficiency of energy use in CHP mode can be up to 80 percent and above in some cases. A typical small gas turbine based CHP unit can save about40 per cent of the primary energy when compared with a fossil fuel fired conventional powerplant and a boiler house (see Figure 1.1 below). Along with the saving of fossil fuels,cogeneration also allows to reduce the emission of greenhouse gases (particularly CO2emission) per unit of useful energy output. The production of electricity being on-site, the

burden on the utility network is reduced and the transmission line losses eliminated.

(i) Cogeneration System (ii)Conventional System

Input

Energy

100

Electricity

30

Heat

50

Input forPower

Generation

86

Input for

Boiler

56

InputEnergy

142

Heat Loss

20

Heat Loss56

Heat Loss

6

Figure 1.1 Conventional energy system versus cogeneration system

Cogeneration makes sense from both macro and micro perspectives. At the macro level, itallows a part of the financial burden of the national power utility to be shared by the privatesector; in addition, indigenous energy sources are preserved or the fuel import bill is reduced.At the micro level, the overall energy bill of the users can be reduced, particularly when thereis a simultaneous need for both power and heat at the site, and a rational energy tariff ispractised in the country.

1.3 From Self Electricity Generation to Cogeneration

In Asian developing countries, it is not unusual to come across situations of grid powersupply interruptions either due to technical failure of the system or because the consumerdemand during a given time period exceeds the utility supply capacity. Industries andcommercial buildings normally adopt stand-by power generators for taking care of theiressential loads during these periods. It is essential to assure continuity of some activities to

minimize production losses or guarantee minimum comfort of the clients. The stand-bygenerators have limited use in the year; moreover, these devices require investment and


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incur operation and maintenance costs while contributing practically nothing to reduce theoverall energy bill of the site.

Since these generators serve the main purpose of assuring emergency power to priorityareas of the site, no financial analysis is carried out to assess their economic viability.However, these generators offer the possibility of continuous power generation so that themonthly power bill of the site can be reduced. Such benefits accrued can well justify the needfor higher investment that is associated with prime movers which are designed to operatecontinuously and at higher efficiencies.

In a gas turbine or reciprocating engine, typically a third of the primary fuel supplied isconverted into power while the rest is discharged as waste heat at a relatively hightemperature, ranging between 300 and 500C. At sites having a need for thermal energy inone form or the other, this waste heat can be recovered to match the quantity and level ofrequirements. For instance, steam may be needed at low or medium pressures for processapplications. Any heat recovered from the exhaust gases of the prime movers will help to

save the primary energy that would have been otherwise required by the on-site conversionfacility such as boilers or dryers.

An ideal site for cogeneration has the following characteristics:

a reliable power requirement;

relatively steady electrical and thermal demand patterns;

higher thermal energy demand than electricity;

long operating hours in the year;

inaccessibility to the grid or high price of grid electricity.

Typical cogeneration applications may be in three distinct areas:

a) Utility cogeneration: caters to district heating and/or cooling. The cogeneration facilitymay be located in industrial estates or city centres;

b) Industrial cogeneration: applicable mainly to two types of industries, some requiringthermal energy at high temperatures (refineries, fertilizer plants, steel, cement, ceramicand glass industries), and others at low temperatures (pulp and paper factories, textilemills, food and beverage plants, etc.);

c) Commercial/institutional cogeneration: specifically applicable to establishments havinground-the-clock operation, such as hotels, hospitals and university campuses.

1.4 Technical Options for Cogeneration

Cogeneration technologies that have been widely commercialized include extraction/backpressure steam turbines, gas turbine with heat recovery boiler (with or without bottomingsteam turbine) and reciprocating engines with heat recovery boiler.

1.4.1 Steam turbine cogeneration systems

The two types of steam turbines most widely used are the backpressure and the extraction-condensing types (see Figure 1.2). The choice between backpressure turbine and extraction-condensing turbine depends mainly on the quantities of power and heat, quality of heat, and


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economic factors. The extraction points of steam from the turbine could be more than one,depending on the temperature levels of heat required by the processes.

(i) Back-Pressure Turbine (ii) Extraction-Condensing Turbine

FuelTurbine

Steam

Boiler

Process

Steam

TurbineFuel

Boiler

ProcessCondenser

CoolingWater

Figure 1.2 Schematic diagrams of steam turbine cogeneration systems

Another variation of the steam turbine topping cycle cogeneration system is the extraction-back pressure turbine that can be employed where the end-user needs thermal energy at twodifferent temperature levels. The full-condensing steam turbines are usually incorporated atsites where heat rejected from the process is used to generate power.

The specific advantage of using steam turbines in comparison with the other prime movers isthe option for using a wide variety of conventional as well as alternative fuels such as coal,natural gas, fuel oil and biomass. The power generation efficiency of the cycle may besacrificed to some extent in order to optimize heat supply. In backpressure cogenerationplants, there is no need for large cooling towers. Steam turbines are mostly used where thedemand for electricity is greater than one MW up to a few hundreds of MW. Due to thesystem inertia, their operation is not suitable for sites with intermittent energy demand.

1.4.2 Gas turbine cogeneration systems

Gas turbine cogeneration systems can produce all or a part of the energy requirement of the

site, and the energy released at high temperature in the exhaust stack can be recovered forvarious heating and cooling applications (see Figure 1.3). Though natural gas is mostcommonly used, other fuels such as light fuel oil or diesel can also be employed. The typicalrange of gas turbines varies from a fraction of a MW to around 100 MW.

Gas turbine cogeneration has probably experienced the most rapid development in the recentyears due to the greater availability of natural gas, rapid progress in the technology,significant reduction in installation costs, and better environmental performance.Furthermore, the gestation period for developing a project is shorter and the equipment canbe delivered in a modular manner. Gas turbine has a short start-up time and provides theflexibility of intermittent operation. Though it has a low heat to power conversion efficiency,more heat can be recovered at higher temperatures. If the heat output is less than that

required by the user, it is possible to have supplementary natural gas firing by mixingadditional fuel to the oxygen-rich exhaust gas to boost the thermal output more efficiently.


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Exhaust

Heat (~ 150 C)

Steam

Water

Flue

Gases

(~ 500 C)

Fuel Air

Electricity

Generator

Gas Turbine

Boiler

Figure 1.3 Schematic diagram of gas turbine cogeneration

On the other hand, if more power is required at the site, it is possible to adopt a combinedcycle that is a combination of gas turbine and steam turbine cogeneration. Steam generatedfrom the exhaust gas of the gas turbine is passed through a backpressure or extraction-condensing steam turbine to generate additional power. The exhaust or the extracted steamfrom the steam turbine provides the required thermal energy.

1.4.3 Reciprocating engine cogeneration systems

Also known as internal combustion (I. C.) engines, these cogeneration systems have highpower generation efficiencies in comparison with other prime movers. There are two sourcesof heat for recovery: exhaust gas at high temperature and engine jacket cooling water systemat low temperature (see Figure 1.4). As heat recovery can be quite efficient for smallersystems, these systems are more popular with smaller energy consuming facilities,particularly those having a greater need for electricity than thermal energy and where thequality of heat required is not high, e.g. low pressure steam or hot water.

Though diesel has been the most common fuel in the past, the prime movers can alsooperate with heavy fuel oil or natural gas. In urban areas where natural gas distributionnetwork is in place, gas engines are finding wider application due to the ease of fuel handling

and cleaner emissions from the engine exhaust.

These machines are ideal for intermittent operation and their performance is not as sensitiveto the changes in ambient temperatures as the gas turbines. Though the initial investment onthese machines is low, their operating and maintenance costs are high due to high wear andtear.

1.5 Classification of Cogeneration Systems

Cogeneration systems are normally classified according to the sequence of energy use andthe operating schemes adopted.


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ExhaustHeat

~ 200 C

~ 450 C

BoilerI.C. Engine

Coolers

Oil Air WaterProcess

Steam or Hot Water

Figure 1.4 Schematic diagram of reciprocating engine cogeneration

A cogeneration system can be classified as either a topping or a bottoming cycle on thebasis of the sequence of energy use. In a topping cycle, the fuel supplied is used to firstproduce power and then thermal energy, which is the by-product of the cycle and is used tosatisfy process heat or other thermal requirements. Topping cycle cogeneration is widelyused in pulp and paper, food processing, textile industries, districting heating, hotels,hospitals and universities. In a bottoming cycle, the primary fuel produces high temperaturethermal energy and the heat rejected from the process is used to generate power through a

recovery boiler and a turbine generator. Bottoming cycles are suitable for manufacturingprocesses that require heat at high temperature in furnaces and kilns, and reject heat atsignificantly high temperatures. Typical areas of application include cement, steel, ceramic,gas and petrochemical industries.

Cogeneration systems can also be classified according to the operating scheme whosechoice is very much site-specific and depends on several factors, as described below:

1.5.1 Base electrical load matching

In this configuration, the cogeneration plant is sized to meet the minimum electricity demandof the site based on the historical demand curve. The rest of the needed power is purchasedfrom the utility grid. The thermal energy requirement of the site could be met by thecogeneration system alone or by additional boilers. If the thermal energy generated with thebase electrical load exceeds the plants demand and if the situation permits, excess thermalenergy can be exported to neighbouring customers.

1.5.2 Base thermal load matching

Here, the cogeneration system is sized to supply the minimum thermal energy requirementof the site. Stand-by boilers or burners are operated during periods when the demand for heatis higher. The prime mover installed operates at full load at all times. If the electricity demandof the site exceeds that which can be provided by the prime mover, then the remainingamount can be purchased from the grid. Likewise, if local laws permit, the excess electricitycan be sold to the power utility.


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1.5.3 Electrical load matching

In this operating scheme, the facility is totally independent of the power utility grid. All thepower requirements of the site, including the reserves needed during scheduled andunscheduled maintenance, are to be taken into account while sizing the system. This is also

referred to as a stand-alone system. If the thermal energy demand of the site is higher thanthat generated by the cogeneration system, auxiliary boilers are used. On the other hand,when the thermal energy demand is low, some thermal energy is wasted. If there is apossibility, excess thermal energy can be exported to neighbouring facilities.

1.5.4 Thermal load matching

The cogeneration system is designed to meet the thermal energy requirement of the site atany time. The prime movers are operated following the thermal demand. During the periodwhen the electricity demand exceeds the generation capacity, the deficit can becompensated by power purchased from the grid. Similarly, if the local legislation permits,electricity produced in excess at any time may be sold to the utility.

1.6 Important Technical Parameters for Cogeneration

While selecting cogeneration systems, one should consider some important technicalparameters that assist in defining the type and operating scheme of different alternativecogeneration systems to be selected.

1.6.1 Heat-to-power ratio

Heat-to-power ratio is one of the most important technical parameters influencing theselection of the type of cogeneration system. The heat-to-power ratio of a facility shouldmatch with the characteristics of the cogeneration system to be installed.

It is defined as the ratio of thermal energy to electricity required by the energy consumingfacility. Though it can be expressed in different units such as Btu/kWh, kcal/kWh, lb./hr/kW,etc., here it is presented on the basis of the same energy unit (kW).

Basic heat-to-power ratios of the different cogeneration systems are shown in Table 1.1along with some technical parameters. The steam turbine cogeneration system can offer alarge range of heat-to- power ratios.

Table 1.1 Heat-to-power ratios and other parameters of cogeneration systems

Cogeneration System Heat-to- power ratio(kWth / kWe)

Power output(as per centof fuel input)

Overallefficiency(per cent)

Back-pressure steam turbine 4.0-14.3 14-28 84-92

Extraction-condensing steam turbine 2.0-10.0 22-40 60-80

Gas turbine 1.3-2.0 24-35 70-85

Combined cycle 1.0-1.7 34-40 69-83

Reciprocating engine 1.1-2.5 33-53 75-85

1.6.2 Quality of thermal energy needed

The quality of thermal energy required (temperature and pressure) also determines the typeof cogeneration system. For a sugar mill needing thermal energy at about 120C, a toppingcycle cogeneration system can meet the heat demand. On the other hand, for a cement plant


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requiring thermal energy at about 1450C, a bottoming cycle cogeneration system can meetboth high quality thermal energy and electricity demands of the plant.

1.6.3 Load patterns

The heat and power demand patterns of the user affect the selection (type and size) of thecogeneration system. For instance, the load patterns of two energy consuming facilitiesshown in Figure 1.5 would lead to two different sizes, possibly types also, of cogenerationsystems.

kW

Time Time

Electricity Thermal Energy

(i) Factory A (ii) Factory B

kW kW

Figure 1.5 Different heat and power demand patterns in two factories

1.6.4 Fuels availableDepending on the availability of fuels, some potential cogeneration systems may have to berejected. The availability of cheap fuels or waste products that can be used as fuels at a siteis one of the major factors in the technical consideration because it determines thecompetitiveness of the cogeneration system.

A rice mill needs mechanical power for milling and heat for paddy drying. If a cogenerationsystem were considered, the steam turbine system would be the first priority because it canuse the rice husk as the fuel, which is available as waste product from the mill.

1.6.5 System reliability

Some energy consuming facilities require very reliable power and/or heat; for instance, a pulpand paper industry cannot operate with a prolonged unavailability of process steam. In suchinstances, the cogeneration system to be installed must be modular, i.e. it should consist ofmore than one unit so that shut down of a specific unit cannot seriously affect the energysupply.

1.6.6 Grid dependent system versus independent system

A grid-dependent system has access to the grid to buy or sell electricity. The grid-independent system is also known as a stand-alone system that meets all the energydemands of the site. It is obvious that for the same energy consuming facility, the technicalconfiguration of the cogeneration system designed as a grid dependent system would be

different from that of a stand-alone system.


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1.6.7 Retrofit versus new installation

If the cogeneration system is installed as a retrofit, the system must be designed so that theexisting energy conversion systems, such as boilers, can still be used. In such acircumstance, the options for cogeneration system would depend on whether the system is a

retrofit or a new installation.

1.6.8 Electricity buy-back

The technical consideration of cogeneration system must take into account whether the localregulations permit electric utilities to buy electricity from the cogenerators or not. The sizeand type of cogeneration system could be significantly different if one were to allow the exportof electricity to the grid.

1.6.9 Local environmental regulation

The local environmental regulations can limit the choice of fuels to be used for the proposed

cogeneration systems. If the local environmental regulations are stringent, some availablefuels cannot be considered because of the high treatment cost of the polluted exhaust gasand in some cases, the fuel itself.


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State of art review of cogeneration 13

CHAPTER 2: STATE OF ART REVIEW OF COGENERATION

2.1 Technological Advances in Cogeneration

Cogeneration plants benefit from many of the energy efficiency improvements that arebrought about in utility power generation because the same basic technology is employed inboth cases. However, cogeneration being more attractive for small-scale decentralizedapplications, significant technological progress has been made in the development ofmodular and packaged cogeneration systems of lower capacities. Moreover, as suchsystems are being adopted in industrial zones and city centres, the stringent laws andregulations put in place for protecting the local environment has obliged the cogenerationtechnology providers to innovate incessantly. The greater availability of natural gas in manyparts of the world has helped in the maturing of gas turbine technology. In addition, the

possibility of using alternative fuels such as wood, agro-industrial residues, biogas, etc., forpowering small-scale cogeneration systems has led to further technological progresses bytaking the specific characteristics of the fuels into consideration. This section brieflydescribes some of the developments in this domain.

2.2 Reciprocating Engines

Reciprocating engines are mostly employed in low and medium power cogeneration units.The lower and upper limits of engine sizes are often a function of the fuel in use; these canrange from 50 kW to 10 MW for natural gas, from 50 kW to 50 MW for diesel, and 2.5 MW to50 MW for heavy fuel oil. One of the major advantages of reciprocating engines is their higherelectrical efficiency as compared to other prime movers.

The two main types of internal combustion engines employed in cogeneration systems arediesel engines and Otto engines. The characteristic feature of the Otto engine is that anelectric spark from a spark plug ignites a mixture of fuel and air, and this is thus known widelyas a spark-ignition engine. In power generation applications, the Otto engine may be either agasoline engine or a diesel engine converted to have spark-ignition operation. Gasolineengines have the ratings ranging from 20 kW to 1.5 MW. The spark-ignition enginesconverted from diesel engines and running on natural gas are available in ratings from 5 kWto 4 MW. The Otto engines operate at speeds between 750-3,000 rpm and have the electricalefficiencies of 25-35 per cent. These engines can run on different fuels such as gasoline,natural gas, producer gas, and digester gas.

As opposed to Otto engines, fuel is injected into the diesel engine cylinders in which it mixeswith air and is ignited by the heat generated when the pistons compress the fuel/air mixture,and this engine is often known as a compression-ignition engine. Diesel engines cangenerally be classified into two main categories, i.e. two-stroke and four-stroke engines. Thetwo-stroke engine is also known as a low-speed engine, and is characterized by ignitiontaking place once every revolution, and by the engine running at a speed below 200 rpm anddelivering an output of 1-50 MW at a high electrical efficiency of 45-53 per cent. In a four-strike engine, ignition takes place during every other revolution, and this engine can bedivided into two categories. Medium speed engines are those running at speeds between400 and 1,000 rpm and can be designed for ratings between 0.5 and 20 MW with electricalefficiencies of 35-48 per cent. High-speed engines are those operating at speeds between

1,000 and 2,000 rpm and with ratings between a few kW and about 2 MW with electricalefficiencies of 35-40 per cent.


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Diesel engines can run on a variety of fuels such as diesel, heavy fuel oil, light fuel oil, LPG,natural gas, producer gas, digester gas, etc. The diesel engines that are converted to gasengines are also known as dual-fuel engines. In their operation, the main fuel is gas, which isignited by a small quantity of pilot oil, usually diesel oil. The pilot oil is used to make sure thatthe gas in the cylinder will ignite. The gas/oil ratio is normally controlled so that the proportionof pilot oil at full engine power will be around 5 per cent of the fuel quantity supplied. Dieselengines running in gas engine mode can be classified in another way into two groups: low-pressure dual-fuel engines and high-pressure dual-fuel engines.

Typical heat balance diagram of a gas engine is shown in Figure 2.1. About 25 per cent of theheat recovered from the engine cooling system (cooling water, oil cooler and inlet air cooler)is low grade at a temperature of about 95C. Considering the same power output, the amountof heat recoverable at high temperature is lower than that for the gas turbine. That is whycogeneration with reciprocating engine is more commonly used for producing hot water/hotair or low pressure steam. However, medium pressure steam can be generated byemploying supplementary firing since exhaust gases from gas engines have an O2 content of

about 15 per cent.

62%

Rad ia t i onlosses

3 6 .5% 4 9 .5 %

100 %

M echa n i ca l Th e r m a l

38%

5 %

7.5%

Exhaus t gaslosses

1.5%

G e n e r a to r

losses

Elect r ica l Th e r m a l

3 6 .5 % 25 .0 % 24 .5 %

E xh a u s tga s

EngineCoo l i ng

S ys te m

Overa l l e f f ic iency

86%

Figure 2.1 Typical heat balance of a gas engine

In the operation of low-pressure dual-fuel engines, gas at low pressure, i.e. 3-5 bar, ismixed with the engine combustion air during the induction cycle. The gas/combustion airmixture is compressed in the cylinder and is ignited at the top dead centre by a small amount(approximately 5 per cent) of diesel oil being injected into the cylinder and ignited in the usualmanner. Low-pressure dual-fuel engines have relatively low ratings and efficiencies. Thesystem is sensitive to variations in gas quality.

Gas is compressed outside the engine in a separate compressor in a high-pressure dual-fuel engineup to 250 bar and is injected into the cylinder with a minor amount of pilot oilwhen the piston is in the vicinity of the top dead centre. High-pressure dual-fuel engines have


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higher ratings and efficiencies and they are not sensitive to the gas quality. High-pressuredual-fuel engines are available in both two-stroke and four-stroke versions.

2.3 Gas Turbines

Gas turbines used for cogeneration are usually designed for continuous duty because gasturbines for stand-by use normally have low efficiencies and are most suitable forapplications where the operating periods are short.

Gas turbines for continuous duty are traditionally divided into two groups on the basis ofdifferences in design philosophy (there is now some convergence in their design).

The aero-derivative gas turbine, as its name indicates, is more or less derived from anaircraft propulsion engine. The characteristics of aero-derivative gas turbines are low specificweight, low fuel consumption, high reliability, etc. The major advantages of aero-derivativegas turbines are high levels of efficiency and a compact and modular design with easy

access for maintenance. However, because skilled service personnel are required, gasturbines of this type are often taken off the site for maintenance. Aero-derivative gas turbinesrequire a relatively high specific investment cost ($/kWe), high quality fuel and mayexperience a lowering in output and efficiency after a long period of operation.

The industrial gas turbine, also referred to as the heavy duty or heavy frame gas turbine, is arobust unit constructed for stationary duty and continuous operation. It has a somewhat lowerefficiency than the aero-derivative type, but usually maintains its performance over a longerperiod of operation. Maintenance can be easily carried out on site, and maintenance costsare low. The industrial gas turbine usually has a lower specific investment cost than its aero-derivative counterpart. Furthermore, it has the ability to make use of low quality fuel.

The performance of a gas turbine depends on the pressure and temperature of ambient airthat is compressed. Since the ambient conditions vary from day-to-day and from location-to-location, it is convenient to consider some standard conditions for comparative purposes.The standard conditions used by the gas turbine industry are 15C, 1.013 bar (14.7 psia) and60 per cent relative humidity, which are established by the International StandardsOrganization (ISO). The performance of gas turbines is expressed under ISO conditions.

The actual power output of a gas turbine varies with ambient conditions. The power output ofa gas turbine decreases when the ambient temperature rises. In contrast, the power outputincreases with the ambient pressure. The variations in power outputs of a typical gas turbinewith ambient conditions are shown in Figure 2.2 as a percentage of ISO power output.

The heat recovery steam generator (HRSG) is one of the major components of the gasturbine cogeneration system. Since the energy content of the exhaust gas rejected to theatmosphere is considerably high, HRSGs are designed to produce process steam (or hotwater) by recovering a large share of the energy contained in the exhaust stream. Theexhaust gas at 500-550C is cooled in the HRSG to about 150C to extract useful heat. Atemperature of 150C is recommended at the outlet of the HRSG to avoid condensation ofexhaust gases. At lower temperature levels, gases such as SOx and NOx would form acidsalong with the condensation and corrode the materials of HRSG.


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60

70

8090

100

110

120

10 11 12 13 14 15

Ambient Pressure (psia)

60

70

8090

100

110

120

-5 5 15 25 35

Ambient Temperature (C)

%ofISOP

owerOutput

%ofISOPo

werOutput

Figure 2.2 Power output variation of a gas turbine with the ambient conditions

The basic heat-to-power ratio of a simple gas turbine cogeneration system is about two.

However, supplementary firing can double the heat-to-power ratio. The HRSG withsupplementary firing option contains an additional burner to increase the heat output of thewhole system. This is made possible due to the high oxygen content of the exhaust gases,typically 14 to 17 per cent, as a result of the need for high excess air in the combustionchamber (for avoiding very high hot gas temperature that can affect the turbine). By addingsupplemental firing, fuel consumption increases slightly, however the steam productionincreases significantly. Addition of supplemental firing is quite common in gas turbinecogeneration systems.

In a gas turbine cogeneration cycle, the power output can be increased by steam injection.High-pressure steam produced in HRSG can be injected into the combustion chamber sothat the mass flow rate through the turbine is increased. Steam injection allows the flexibility

of matching with the process steam demand and can increase the power output by about 15per cent.

0

5

10

15

20

25

30

35

40

0 5 10 15 20 25 30 35 40

ISO Power Output (MW)

ElectricalEfficiency(%)

0

5

10

15

20

25

30

35

40

0 5 10 15 20 25 30 35 40

ISO Power Output (MW)

ElectricalEfficiency(%)

(i) Aero-Derivative (ii) Industrial

Figure 2.3 Power generation efficiency ranges of gas turbines

The power generation efficiency ranges of aero-derivative and industrial gas turbines arecompared in Figure 2.3. The overall efficiency of the gas turbine cogeneration system is goodwithout post-combustion (70 to 85 per cent), which can be further boosted to between 83 and

89 per cent with post-combustion. When the system is opted as a retrofit in a facility alreadyhaving boilers, it is at times possible to make use of the existing boilers.


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Recuperators are used to increase the power output of gas turbine cogeneration systems ifthe heat demands are low. The recuperator is in fact only a heat exchanger that is employedto heat the air leaving the compressor. The exhaust stream from the turbine is passedthrough the recuperator before going into the HRSG so that a part of the energy contained inturbine exhaust is utilized in the recuperator. The gas turbine cogeneration system withrecuperator is sometimes known as the heat exchange cycle.

2.4 Steam Turbines

Steam turbines are the most commonly employed prime movers for cogenerationapplications, particularly in industries and for district heating. The technology is well proven insugar and paper mills having demand for both electricity and large quantity of steam at highand low pressures. Some steam turbine manufacturers are over 100 years old and haveproducts ranging from a few kW to 80 MW. However, turbines below two MW may beuneconomical except where the fuel has no commercial value.

A cogeneration system using a backpressure steam turbine (see Figure 1.2) consists ofboiler, turbine, heat exchanger and pump. In the steam turbine, the incoming high pressuresteam is expanded to a lower pressure level, converting the thermal energy of high pressuresteam to kinetic energy through nozzles and then to mechanical power through rotatingblades. Thermal energy of the turbine exhaust steam is then transferred to another fluid,water, air, etc., in a heat exchanger, providing heat to the processes. For instance, the airheated by heat exchanger can be used to dry products in food processing industries.

Depending on the pressure (or temperature) levels at which process steam is required,backpressure steam turbines can have different configurations. The most common types ofbackpressure steam turbines are shown in Figure 2.4. In extraction and double extractionbackpressure turbines, some amount of steam is extracted from the turbine after beingexpanded to a certain pressure level. The extracted steam meets the heat demands atpressure levels higher than the exhaust pressure of the steam turbine.

The backpressure steam turbine has a higher heat to power ratio and higher overallefficiency. Furthermore, back pressure turbine cogeneration systems need less auxiliaryequipment than condensing systems, leading to lower initial investment costs.

The extraction condensing turbines have higher power to heat ratio in comparison withbackpressure turbines. Although condensing systems need more auxiliary equipment suchas the condenser and cooling towers, better matching of electrical power and heat demandcan be obtained where electricity demand is much higher than the steam demand and the

load patterns are highly fluctuating.

In the reheat cycle, steam is extracted from the turbine and reheated in the boiler during theexpansion process. Reheat cycles improve the overall thermal efficiency and eliminate anymoisture that may form as the steam pressure and temperature are lowered in the turbine.Steam turbines may also include a regenerative cycle where the steam is extracted from theturbine and used to preheat the boiler feedwater.

The efficiency of a backpressure steam turbine cogeneration system is the highest. In caseswhere 100 per cent backpressure exhaust steam is used, the only inefficiencies are geardrive and electric generator losses, and the inefficiency of steam generation. Therefore, withan efficient boiler, the overall thermal efficiency of the system could reach as much as 90 per

cent.


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High pressure steam Extracted steam Exhaust steam

(i) Simple backpressure (ii) Extraction backpressure (iii) Double extraction

backpressure

Figure 2.4 Different configurations for back pressure steam turbines

The overall thermal efficiency of an extraction condensing turbine cogeneration system islower than that of back pressure turbine system, basically because the exhaust heat cannotbe utilized (it is normally lost in the cooling water circuit). However, extraction condensingcogeneration systems have higher electricity generation efficiencies.

The techniques available for energy generation from fossil fuels are well established. In order

to make greater use of alternative fuels, efforts have been made to take the specificity of fuelcharacteristics into account in order to overcome the technological constraints. The physicalproperties of agro-industrial residues vary considerably and can affect the conversionefficiency. Some areas where technological progresses have been made include fuelhandling, combustion system and pollution abatement equipment.

Fuel handling and transformation is important for appropriate functioning of the installation.Handling biomass residues depends mainly on the fuel granulometry and moisture content.Coarse residues can be transformed into homogeneous mass by crushing and chipping.Reduction of the moisture content by drying represents two main advantages: increases inthe fuel heating value, and decrease in the fuel losses through fermentation during storage.Suitable technologies are available in the market to cover the handling, drying and storage

requirements of different types of fuels.

The selection of combustion system using alternative fuels depends on parameters such asthe size of the unit, energy required, fuel characteristics, etc. Though grate-fired systems(Dutch-oven type or spreader-stokers) have been widely used because of the flexibility theyoffer, suspension burners and fluidized-bed combustors are emerging as relevanttechnologies because of their high conversion efficiencies and improved performance inmeeting the environmental constraints. In suspension burners, ash is dragged out with theexhaust gases or it falls to the furnace bottom. Fluidized-bed combustors control thecombustion better and make use of an inert material capable of absorbing energy, thusmaximizing the heat transfer from the fuel. These units are capable of burning fuels with verylow calorific values. Modern designs of furnaces offer staging combustion and good control ofair-fuel ratio.


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2.5 Trigeneration and Vapour Absorption Cooling

Trigeneration is the concept of deriving three different forms of energy from the primaryenergy source, namely, heating, cooling and power generation. Also referred to as CHCP

(combined heating, cooling and power generation), this option allows having greateroperational flexibility at sites with demand for energy in the form of heating as well as cooling.This is particularly relevant in tropical countries where buildings need to be air-conditionedand many industries require process cooling. A typical trigeneration facility consists of acogeneration plant, and a vapour absorption chiller which produces cooling by making use ofsome of the heat recovered from the cogeneration system (see Figure 2.5).

Generator

HRSG

SteamTurbine

Steam

ELECTRICITY

Steam

Generator

FUEL

HeatExchanger

HotGases

Chiller

AIR

GE Frame 6Gas Turbine

CHILLEDWATER

HOTWATER

STEAM

Figure 2.5 Schematic presentation of a gas turbine based trigeneration facility

Although cooling can be provided by conventional vapour compression chillers driven byelectricity, low quality heat (i.e. low temperature, low pressure) exhausted from thecogeneration plant can drive the absorption chillers so that the overall primary energyconsumption is reduced. Absorption chillers have recently gained widespread acceptancedue to their capability of not only integrating with cogeneration systems but also because they

can operate with industrial waste heat streams. The benefit of power generation andabsorption cooling can be realized through the following example that compares it with apower generation system with conventional vapour compression system.

A factory needs 1 MW of electricity and 500 refrigeration tons (RT)1. Let us first consider thegas turbine that generates electricity required for the processes as well as the conventionalvapour compression chiller. Assuming an electricity demand of 0.65 kW/RT, thecompression chiller needs 325 kW of electricity to obtain 500 RT of cooling. Hence, a total of1325 kW of electricity must be provided to this factory. If the gas turbine efficiency has anefficiency of 30 per cent, primary energy consumption would be 4417 kW. A schematicdiagram of the system is shown in Figure 2.6.

1 Refrigeration ton (RT) is defined as the transfer of heat at the rate of 3.52 kW, which is roughly therate of cooling obtained by melting ice at the rate of one ton per day.

ELEC-TRICITY

Gas Turbine


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Figure 2.6 Schematic diagram of power generation and cooling with electricity

However, a cogeneration system with an absorption chiller can provide the same energyservice (power and cooling) by consuming only 3,333 kW of primary energy. A schematicdiagram of the system is shown in Figure 2.7.

Figure 2.7 Schematic diagram of power generation and absorption cooling

It can be seen that the cogeneration system incorporating an absorption chiller can saveabout 24.5 per cent of primary energy in comparison with the power generation system andvapour compression chiller. Furthermore, a smaller prime mover leads to not only lowercapital cost but also less standby charge during the system breakdown because steamneeded for the chiller can still be generated by auxiliary firing of the waste heat boiler.

Since many industries and commercial buildings in tropical countries need combined powerand heating/cooling, the cogeneration systems with absorption cooling have very high

potentials for industrial and commercial application.

1000 kW

Fuel Input

325 kW

1325 kW

Process

4417 kW

Gas Turbine

GeneratorCompression

Chiller 500 RT Cooling

Fuel Input Generator

3,333 kWGas Turbine 500 RT Cooling

2.25 Tons/hr of Steam AbsorptionRecovery ChillerBoiler

ExhaustHeat

1,000 kW

Process


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2.6 Working Principle of Absorption Chillers

Like the vapour compression chiller (VCC), the vapour absorption chiller (VAC) extracts heatin the evaporator which is placed in the space to be cooled and rejects this heat in thecondenser. However, VAC needs a heat source as the driving force while VCC requiresmechanical power or electricity for the same duty. Figure 2.8 shows the schematic diagramsof VCC and VAC.

Figure 2.8 Comparison between vapour compression and absorption cycles

The improved version of the VAC, commonly known as the double effect type, is designedsuch that it utilizes the vaporized refrigerant as an extra heat source. The generator is dividedinto high and low temperature sections. The refrigerant vapour produced in the hightemperature generator gives up its latent heat to the partially refrigerant-rich solution in thelow temperature generator that operates at a low pressure, hence the lower boiling point ofthe refrigerant. The energy consumption of a double effect VAC is approximately half that ofthe single effect VAC for the same cooling effect. Moreover, heat rejected in the condenser isalso reduced, resulting in smaller condenser and cooling tower.

The performances of absorption chillers strongly depend on the thermo-physical properties of

the working pair, i.e., the refrigerant and absorbent. Binary working pairs such as ammonia-water (NH3-H2O) and lithium bromide-water (LiBr-H2O) have been employed commercially inabsorption chillers for a long time and these are in commercial use. A single effect LIBr-H2Oabsorption chiller requires about 0.8 m3/h of hot water at around 90C or 8.3 kg/h of steam at1.5 bar to provide 1 RT. On the other hand, a double effect chiller requires only 4.5 kg/h ofsteam, though at a higher pressure between 6 and 8 bar.

2.7 District Heating/Cooling Network

Individual buildings and industries may lack economies of scale when setting up cogenerationfacilities and it may not be always possible to optimize the design parameters due to thepeculiarity of the energy demand patterns. In such cases, one may think of developing afacility that caters to several user-groups with varying demand patterns that can becomplimentary. In the building sector, for instance, offices are active during the daytime

High PressureHigh Pressure Vapour

Vapour Refrigerant Refrigerant

Heat

Mechanical InputHeat

Power/Electricity ExchangerVapour

Compressor

Low Pressure Low PressureVapour Refrigerant Vapour Refrigerant

(i) Vapour Compression Chiller (ii) Vapour Absorption Chiller

Condenser Condenser Generator

Evaporator Evaporator Absorber


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whereas hotels may have high loads at nights. When the two loads are combined, a uniformcomposite curve may be obtained with very small amplitude.

Besides, there are a number of justifications for grouping together several buildings andindustries in order to meet their different energy services, such as:

- larger cogeneration system and the economies of scale associated with it;

- system expansion to users for whom individual facility cannot be justified;

- improvement in the overall generation efficiency;

- increased reliability and availability of utility services;

- pooling of maintenance personnel and reduction in manpower cost;

- saving of mechanical room space in the user buildings;

- purchase of fuel at more competitive rate;

- better negotiation power for power purchase/sale to the electric utility, etc.

There are, however, a few drawbacks to district heating/cooling, the most important amongthem being the high initial investment on the system. The cost of steam/hot water and chilledwater transportation and distribution can also be high. Because of the down-sizing of thedifferent components installed at the central plant, capital investment cost can in fact bereduced by 10 to 20 per cent as compared to those which would have been required in theindividual buildings. This takes into account the piping distribution network cost that is notrequired in conventional decentralized systems. For instance, a district cooling network isinstalled in Paris which includes three chiller plants with a total of 25,500 RT to supply to amuseum, shopping complex, exhibition centre and offices having a total equivalent areaexceeding one million m2. Decentralized plants would have required a total capacity ofapproximately 34,100 RT to be installed. The district-cooling network has thus helped toachieve an investment saving of over US$ 8 million for the reduced installed cooling capacity.2

2.8 Evolution of Package Cogeneration

Cogeneration systems traditionally constituted various components which were ordered andassembled at the site according to the clients requirements, mostly matching the thermalenergy needs. The minimum power generation capacity was of the order of a few MW due tothe limited products available in the market, some of the reasons being:

1) Investment cost per kWe is considerably higher for smaller units;

2) Limited financing capabilities of small and medium scale enterprises;

3) Additional investment needed by smaller units to cope with environmental regulations;

4) Unavailability of guarantee for the overall system.

2 R. Caillaud, District cooling with thermal storage for shifting power loads in south-east Asia, APECDemand-side Management Inter-Utility Liaison Group Meeting, Chiang Mai, 26-29 March 1996.


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However, trends have changed considerably with the introduction of modular concept whichconsists of cogeneration units packaged as of-the-shelf" products and whoseperformances, both electrical and thermal, are guaranteed by suppliers who act as the soleresponsible for the design of the overall system and all its interfaces. This has led towidespread propagation of cogeneration plants with power generating capacities less than aMW. Many of these adopted by enterprises that are located at the end of electric networksand are faced with the problem of getting reliable and uninterrupted power. Moreover, theexpansion of the natural gas network has made it possible to employ gas engines of smallercapacities in urban areas without violating the environmental regulations. For example, over2,500 units have been installed in the Netherlands alone in the range between 100 and 300kW, the main clients being hospitals, community buildings, sports centres, teachingestablishments, commercial buildings, small and medium enterprises, etc.

A typical module of less than one MWe capacity presents itself as a mono-bloc, compact andsoundproofed packaged unit, consisting of the following:

engine for mechanical energy generation;

alternator for electrical output;

heat recovery unit for thermal energy generation;

component for evacuation of combustion products;

control system, electrical protection and low voltage connection box;

soundproofing insulation.

These modules are designed for being installed within a few days with very little structural orengineering work at the site. Moreover, as the components are well matched, high efficiencyis guaranteed for the overall system. Some of these cogeneration facilities are designed fortrigeneration at sites with process or space cooling needs.

The strength of the package units lies with their high overall efficiency and system availability.Manufacturers propose cogeneration systems whose overall efficiency can be between 84and 92 per cent (with a mechanical efficiency between 30 and 35 per cent) and 95 per centavailability. Variations in their performances are a function of the type of prime mover, thelevel at which heat is required, and the quality of heat recovery devices.

The package cogeneration plants are well suited for intermittent operations and variable

loads. The nominal power can be delivered within a few seconds after starting (typically 90seconds) and the loading can be modulated between 50 and 100 per cent without muchreduction in the efficiency. When supplied in soundproof casing, the unit may limit the noiselevel to only 65 dB at a metre.

The supplier defines a well-defined maintenance schedule to guarantee long-term operationwithout unscheduled breakdowns. Use of the same core prime mover for numerousapplications allows to have improved availability of the spare parts at a lower cost. A wellmaintained package cogeneration unit can have a life span of over 60,000 hours. Themaintenance cost on small size engine-based units still remains relatively high comparedwith units with capacities exceeding 600 kW.


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2.9 Innovation in Exhaust Gas Heat Recovery

Sites requiring more thermal energy than that is available at the exhaust of reciprocating

engine or gas turbine have the option of adopting post-combustion of oxygen-rich exhaustgases. For this, either the fuel required by the prime mover or an alternate cheaper fuel maybe employed. New types of burners have been designed in the recent years that can beoperated efficiently to provide the varying thermal energy demand of the site.

The GRC Induct type of burners has been specially designed by EGCI Pillard forcombustion of either liquid or gaseous fuels, by making use of the gas turbine exhaust gas(leaving at around 500C and 13 per cent of O2 content) as the oxidizing air. Located at theinlet of the heat recovery boiler, it helps to increase the temperature of the gas turbineexhaust gas, and thus the overall efficiency of the cogeneration installation. In case the gasturbine is out of operation, these burners can assure steam generation by making use of coldinlet air from the surrounding. The heat output per burner can range from 4 to 50 MW.

These burners function equally well on natural gas as well as liquid fuels (light or heavy fueloil, residual fuel) or in simultaneous mixed mode. Steam or compressed air assurespulverization of the liquid fuel. The design based on the GRC LONOxFLAM technology,assures perfect flame stability, a low-pressure drop and an excellent combustion with lowemissions of unburnts and NOx, thus well within the environmental pollution thresholds set bythe regulation. When there is a combustion zone in the boiler, it is possible to reduce theoxygen level in the exhaust gas to around three to four per cent for further increasing theefficiency, while still maintaining the emission of pollutants lower than the norms.3

For its operation with cold ambient air, the control flaps close a part of the recovery section.While using heavy fuel oil, a suitable adaptation is necessary for limiting emissions. One of

the main features of the system is the mechanism for quick dismantling which allows tochange the burners during operation by opening the whole frame laterally within 15 minutes.

2.10 Research and Development on Cogeneration Technologies

There has been a steady rise in the efficiency of gas turbines and diesel engines. The inlettemperature of a large size gas turbine has risen to 1,350C and can be expected to reach1,500C in the near future. The thermal efficiency of gas engines has been increasing thanksto an increase in compression ratio, and the application of pre-chamber lean burntechnologies. These improvements have been made possible mainly due to the progressesmade in cooling, heat-resist materials, turbo machinery and combustion technologies.

Various projects are ongoing to achieve rapid efficiency improvements by the year 2000.4

These include development of ceramic gas engine and gas turbine that require advancedtechnology related to ceramic science. To prove the concept, the Miller cycle gas enginesystem is being developed which has a unique intake and exhaust timing mechanism thatallows to power generation efficiency exceeding 35 per cent.

In a ceramic gas engine, ceramic is used as the materials of the combustion chamber toallow an advanced combustion. Similar to a thermos structure, air gap is provided andgaskets with low thermal conductivity are placed between the ceramic and metallic parts to

3 Energie Plus, Lumires et ombres sur la cognration, No.197, pp. 6, 15 December 1997.4 M. Motokawa, R&D efforts for cogeneration technologies with high efficiency, Proceedings of theConference on Natural Gas Technologies: A Driving Force for Market Development, International EnergyAgency, pp. 627-636, Berlin, 1-4 September 1996.


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enhance the effect of insulation. The wall temperature of the combustion chamber ismaintained above 1,000C, which helps to reduce the heat transfer from the combustion gasto the wall. Such a structure eliminates the need for a cooling system and renders the enginevery compact. High efficiency is achieved by both diesel cycle combustion and the energyrecovery unit where exhaust energy from the heat insulation is recovered and converted intoelectricity by a turbo compound system, an ultra high speed generator, and a highly efficientconverter. As for the ceramic gas turbine, the target is to develop units having efficiencies of42 per cent or more.

The thermal efficiency of an Otto cycle engine is a function of the difference between themaximum combustion temperature and the exhaust gas temperature. The maximumcombustion temperature in an engine increases with a higher compression ratio while theexhaust gas temperature decreases with a lower expansion ratio. But the compression andexpansion ratios of an Otto cycle engine are the same and the engine is adjusted for a lowercompression ratio to avoid knocking. In a Miller cycle, the expansion ratio can be set largerthan the compression ratio by adjusting the intake timing, and this results in an improved

efficiency as well as improved durability due to the lower exhaust temperature.

The gas injection diesel engine can now attain an electrical efficiency of 45 per cent, which isthe highest among commercialized gas engines. The engine no longer requires pilot oil andglow plugs be used to ignite natural gas ignited into the cylinder at 25 MPa.

R&D efforts are also on going to develop solid oxide fuel cells to exploit the excellentproperties of ceramic materials and achieve efficiencies in the range of 50 per cent. Oncethese technologies are commercialized, cogeneration promotion can get a further boost asan energy saving and environmentally sound technology.

2.11 Cogeneration and the Environment

The high efficiency of cogeneration and efficient use of fuel guarantee a significant reductionof CO2 emission. However, cogeneration can have environmental implications in the form ofCO, SO2 and NOx emissions to the atmosphere. The quantity of each of the pollutantgenerated depends largely on the type of fuel used and the characteristics of thecogeneration technology adopted.

CO is a poisonous gas produced due to incomplete combustion and can be reduced tonegligible levels by assuring satisfactory air-fuel ratio control. SO2 is an acidic gas producedwhen sulphur-containing fuels such as oil or coal are burned. Its emissions cause acid rain.Sulphur-containing exhaust gases are the main cause of corrosion of heat recovery devices

when the SO2 in the gas is cooled below its condensation temperature. NOx is a mixture ofnitrogen oxides produced due to the combustion of a fuel with air, and its formation is afunction of the combustion condition, characterized by the air-fuel ratio, combustiontemperature, and residence time. It also causes acid rain and can result in ozone and smogafter undergoing several chemical reactions in the atmosphere.

Technologies which have undergone rapid development are those based on spark andcompression ignition engines and gas turbines, primarily using natural gas as the fuel.Natural gas is considered the cleanest among the fossil fuels as it does not practicallycontain any sulphur, nitrogen and is free of dust particles. However, the emission of NOx isgreater, particularly for the prime movers operating at high temperatures.


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Appropriate designing of the combustion chambers and control of the flame characteristichelp to reduce NOx formation in engines and turbines. Engine design alone cannot eliminateNOx formation. Moreover, efforts to reduce NOx emission can lead to increase in COemissions while adversely affecting the power output and efficiency. Therefore, end-pipe NO xabatement technologies such as those based on catalytic reduction systems must beapplied to assure very low emission.

2.11.1Gas engine

Technical options adopted to minimize emissions from gas engines are optimal combustionprocess and flue gas cleaning. Lean-burn techniques are used for self-igniting engines usingnatural gas as fuel. With high load pressure and excess air (typically, 35 to 60 per cent), NOxemission can be reduced to 200 mg/m3, below the standards set by many industrializedcountries.

Flue gas can be cleaned with a 3-way catalyst; as its name implies, NOx, CO andhydrocarbon emissions are reduced. In order for it to function efficiently, a constant NO x-CO

ratio needs to be maintained by proper control of air-fuel ratio and ignition.

2.11.2Gas turbine

Three commonly employed methods for eliminating NOx emissions from gas turbines arewater or steam injection, use of dry low NOx burners, and selective catalytic reduction.

Water or steam injection are well established techniques which boost the power output dueto increased mass flow rate in the turbine. These also help to lower the flame temperatureand the partial pressure of oxygen, thus inhibiting NOx formation. There is an upper limit toNOx reduction by this method without affecting gas turbine performance. Beyond a certaininjection rate of water or steam, there is greater flame instability that leads to formation of CO

and emission of unburned hydrocarbons.

More modern gas turbines make use of dry low-NO x systems instead of water or steaminjection in order to avoid the costs of treating and pressurizing water or producing highquality steam. The fuel is mixed with combustion air to a homogeneous mixture in a mixingchamber before being sprayed into the flame; this reduces the peak flame temperature andassures less NOx generation. Such systems are effective at high loads but perform poorly atpartial loads. Where the cogeneration system is required to have a wide range of operatingconditions, a hybrid design of low NOx burners is employed which incorporates a smalldiffusion pilot flame for stabilizing flame at low loads.

At sites where stringent environmental standards are applied, selective catalytic converterscan be adopted as an end-of-pipe technique. A reducing agent, normally ammonia, is used toconvert NOx to nitrogen and water in the presence of a catalyst, the most common beingvanadium oxide.

2.11.3Steam turbine

In steam turbine cogeneration systems, sulphur and nitrogen oxide emissions are importantin oil-fired boilers whereas particulate and nitrogen oxides have to be considered in wood-fired boilers.

As far as the boilers are concerned, technologically advanced equipment has beendeveloped to meet increasingly stringent environmental requirements. A significant

development is the use of a secondary combustion chamber where complete combustion ofthe unburned gases occurs. Better monitoring of combustion parameters through adequateinstrumentation has allowed the operator to better regulate the combustion.


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Four types of emission control devices widely used in boiler systems are electrostaticprecipitation, fabric filters, multi-tube cyclones and wet scrubbers. Chemical agents such aslime, magnesium oxide, etc., are used for flue gas desulphurization. Commonly usedtechniques employed for NOx emission abatement in steam turbine cycles include low NO xburners, selective catalytic reduction, flue gas recirculation, ammonia injection, etc.


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Economic and financial aspects of cogeneration 27

CHAPTER 3: ECONOMIC AND FINANCIAL ASPECTS OF COGENERATION

3.1 Introduction

Cogeneration is a proven technology that saves fuel resources, but it does not necessarilyimply any assurance of economic benefits. Irrespective of all its technical merits, theadoption of cogeneration would principally depend on its economic viability, which is verymuch site-specific. The equipment used in cogeneration projects and their costs are fairlystandard, but the same cannot be said about the financial environment that variesconsiderably from one site and/or country to another. The best way to assess theattractiveness of a cogeneration project is to conduct a detailed financial analysis andcompare the returns with the market rates for investments in projects presenting similarrisks.

Well-conceived cogeneration facilities should incorporate technical and economic featuresthat can be optimized to meet both heat and power demands of a specific site. Acomprehensive knowledge of the various energy requirements as well as characteristics ofthe cogeneration plant is essential to derive an optimal solution. As a first step, thecompatibility of the existing thermal system with the proposed cogeneration facility should bedetermined. Important user characteristics which need to be considered include electricaland thermal energy demand profiles, prevalent costs of conventional utilities (fossil fuels,electricity) and physical constraints of the site. A factor that should not be overlooked at thisstage is the need for reliable energy supply as some industrial processes and commercialsites are extremely sensitive to any disruption of energy supply that may lead to productionlosses.

To fully exploit the cogeneration installation throughout the year, potential candidates forcogeneration should have the following characteristics:

a. adequate thermal energy needs, matching with the electrical demand;

b. reasonably high electrical load factor and/or annual operating hours;

c. fairly constant and matching electrical and thermal energy demand profiles.

These are essential for full exploitation of the cogeneration installation; moreover, part-loadoperation of the plant can be avoided, which would otherwise have affected the economicviability of the project.

3.2 Some Points to Consider for Cogeneration Project Development

Cogeneration project is the same as any other commercial project requiring high investment,relatively longer period, and presenting certain financial risks. Therefore the steps whichshould be followed in developing a cogeneration facility would be quite the same as thoseemployed for any investment project (see Figure 3.1). Projects will obviously vary from one toanother on the basis of factors such as who is the project developer, what is the size of theproject, who is financing the project, etc.

Prior to undertaking any economic analysis to assist the commercial benefit of a

cogeneration project, technical parameters which need to be considered first have beendiscussed in Chapter 1 and are summarized below:


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- heat-to-power ratio;

- quality of thermal energy needed;

- electrical and thermal energy demand patterns;

- fuel availability;- Required system reliability;

- Local environmental regulations;

- dependency on the local power grid;

- option for exporting excess electricity to the grid or a third party, etc.

Some of these concerns are further elaborated below.

Figure 3.1 Typical steps for cogeneration project development

A cogeneration system may be sized to meet either the electricity or the heat demand of the

site. When the local power utility allows selling excess electricity generated at the site, oneshould make sure that the buy-back rate is attractive enough before over-sizing thecogeneration plant.

As the electrical and thermal loads of the site tend to vary with time, the cogeneration systemmay require that any shortfall in the electricity supply be met by the purchase of electricityfrom the grid. Likewise, any shortfall of thermal energy should be met by either post-combustion of exhaust gases in the case of gas turbines or reciprocating engines, or from anauxiliary source such as a stand-by boiler. These solutions will certainly have consequenceson the annual average efficiency and the economics of the project. The ideal operation wouldthus consist of the use of the maximum electricity on site, while assuring continuousoperation of the processes at nominal conditions and avoiding the generation of excess

thermal energy.

If the thermal load is negligible or if it is required to produce only low-pressure steam or toheat a fluid at low temperature, gas engine may be preferred because of its higher efficiency.

1-Technical Analysis 2-Economic Study

3-Selection of Best Solution

4-Financial Arrangement5-DECISION

6-Execution

7-Starting off8-Technical &Financial

Result


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When opting for gas turbine, it is advisable to first verify gas supply pressure. If the pressureof gas in the pipeline is low, it will necessitate additional investment on the gas compressionstation. Moreover, some amount of electricity generated would be diverted for running thecompressor, and the operation and maintenance costs will be higher.

The availability of fuel, its price and guarantee of its long-term supply are the major factorsdetermining the choice of the prime movers. As prime movers can operate with differenttypes of fuels, the option for fuel switching should be taken into consideration.

Designing of the cogeneration facility at the initial stage should incorporate the possibleevolution of future energy demand. This would help in the appropriate choice of equipmentand in planning the schedule for expanding capacity according to the changes in need.

Modern cogeneration plants are highly reliable and have a high load factor; one cannothowever ignore the occurrence of stoppages for scheduled maintenance or unscheduledbreakdown. There may be a need for back-up power to assure continuous operation of

activities at the site. One solution would be to provide stand-by generation capacity at thesite, which will increase the investment further. Alternatively, a stand-by contract may besigned with the power utility so that electricity can be tapped from the grid up to the maximumcontracted demand whenever the cogeneration plant stops operating.

3.3 Key Parameters for Cogeneration Economic Analysis

Cogeneration may be considered economical only if the different forms of energy producedhave a higher value than the investment and operating costs incurred on the cogenerationfacility. In some cases, the revenue generated from the sale of excess electricity and heat orthe cost of availing stand-by connection must be included. More difficult to quantify are theindirect benefits that may accrue from the project, such as avoidance of economic lossesassociated with the disruption in grid power, and improvement in productivity and productquality.

Following are the major factors that need to be taken into consideration for economicevaluation of a cogeneration project:

1. initial investment;

2. operating and maintenance costs;

3. fuel price;

4. price of energy purchased and sold.

Initial investment is the key variable that includes many items in addition to the cost of thecogeneration equipment. To start with, one should consider the cost of pre-engineering andplanning. Barring a few exceptional cases, the cogenerator would normally hire a consultingfirm to carry out the technical feasibility of the project before identifying suitable alternativesthat may be retained for economic analysis. If the cogeneration equipment needs to beimported, one should add the prevailing taxes and duties to the equipment cost. If one plansto purchase cogeneration components from different suppliers and assemble them on site,one should take into account the cost of preparing the site, civil, mechanical and electricalworks, acquiring of all auxiliary items such as electrical connections, piping of hot and coldutilities, condensers, cooling towers, instrumentation and control, etc. Table 3.1 provides anexample of the breakdown of typical costs for a 20 MWe gas turbine cogeneration plant.


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Table 3.1 Cost breakdown (US$) of a 20 MWe gas turbine cogeneration plant1

If cogeneration is being adopted as a retrofit at an existing site, the cost items will dependgreatly on the existing facilities, some of which may be retained while others are discarded,replaced or upgraded.

The cost of land may be a crucial factor at some sites where cogeneration facility iscommissioned, particularly in the case of urban buildings or when additional space isrequired for storage and handling of fuel.

Integration of the cogeneration plant into the existing set-up may lead to some economic

losses to the cogenerator (e.g. production downtime). Costs associated with such lossesshould be included in the total project cost.

The operating and maintenance (O&M) cost should include all direct and indirect costs ofoperating the new cogeneration facility, such as servicing, equipment overhauls, replacementof parts, etc. The cost of employing additional personnel as well as their training needed foroperating the new facility must also be taken into account. Present technology allowscomplete automation of small pre-packaged and pre-engineered units, helping to reduce theO&M costs considerably.

1 Gas Turbine World, The 1990 Handbook, Pequot Publishing.

G a s t u r b i n e p l a n t e q u i p m e n t

- G a s t u r b i n e g e n - s e t p a c k a g e ( F O B )

- A u x i l i a r y s y st e m s- Fu e l g a s c o m p r e ss o r / s k i d

- B a c k - u p d i s t i l l a t e s t o r a g e

S t e a m e q u i p m e n t

- H e a t r e c o v e r y b o i l e r w i t h a u x i l i a r y f i r i n g

- W a t e r t r e a t m e n t s y s t e m

- C o n d e n s e r , f e e d w a t e r p u m p s

E l e c t r i c a l e q u i p m e n t

- Su b s t a t i o n t r a n sf o r m e r s

- Sw i t c h g e a r a n d c o n t r o l s

- U t i l i t y i n t e r c o n n e c t i o n s

S e r v i c e s a n d I n s t a l l a t i o n

- E n g i n e e r i n g d e si g n

- C i v i l w o r k s

- C o n t r o l a n d m a i n t e n a n c e b u i l d i n g

- El e c t r i c a l f i e l d w o r k

- M e c h a n i c a l f i e l d w o r k

- F r e i g h t a n d h a n d l i n g

8 , 1 0 0 , 0 0 0

3 7 0 , 0 0 04 2 0 , 0 0 0

1 1 0 , 0 0 0

1 , 8 4 0 , 0 0 0

3 2 0 , 0 0 0

4 2 0 , 0 0 0

3 2 0 , 0 0 0

1 1 0 , 0 0 0

4 2 0 , 0 0 0

1 , 1 0 0 , 0 0 0

6 3 0 , 0 0 0

3 2 0 , 0 0 0

8 4 0 , 0 0 0

1 , 4 7 0 , 0 0 0

3 2 0 , 0 0 0

9 , 0 0 0 , 0 0 0

2 , 5 8 0 , 0 0 0

8 5 0 , 0 0 0

4 , 6 8 0 , 0 0 0

To t a l p l a n t c o s t

- E q u i p m e n t , d e si g n a n d i n st a l l a t i o n

- C o n t i n g e n c y ( a p p r o x i m a t e l y 1 0 % )

1 7 , 1 1 0 , 0 0 0

1 , 7 0 0 , 0 0 0

1 8 , 8 1 0 , 0 0 0


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Annual costs incurred due to the cogeneration plant, such as the insurance fees and propertytaxes should be included in the analysis. These are often calculated as a fixed percentage ofthe initial investment.

Fuel costs may form the largest component of the operating expenditures. If cogeneration isadded to an existing plant, only the fuel cost in excess of that used earlier for heat and powergeneration may be considered. Since the cogeneration plant is expected to operate for a longtime period, escalation of the fuel price over time should be included in a realistic manner.

The price of energy purchased and sold is a decisive parameter. This includes the net valueof electricity or thermal energy that is displaced as well as any excess electricity or thermalenergy sold to the grid or a third party. A good understanding of the electric utilitys tariffstructure is important, which may include energy charge and capacity charge, time-of-usetariff, stand-by charges, electricity buy-back rates, etc. As for the fuel, there should beprovision to account for electricity price escalation with time. This is particularly true wherepower utilities depend heavily on fuel in their power generation-mix.

3.4 Source of Financing of Cogeneration Projects

Cogeneration systems are capital intensive projects and the sources of capital financing canbe an important consideration in the investment analysis in which different sources may beused. It is important, therefore, to know the rate of return for each alternative. The sources ofcapital financing could be one of the following:

1. self financing: capital generated from cogenerators own activities;

2. borrowing: requiring certain equity and guarantee;

3. leasing: ownership maintained by the leasing company;

4. third-party financing: undertaken by an energy service company; and

5. facility management: reduction of energy bill for user with zero capital risk.

Self-financing can be in various forms, such as equity capital, depreciation fund and retainedprofit. Equity capital is supplied and used by its owner in the expectation that a profit, of aminimum acceptable level, will be earned. In equity financing, however, the owner has noassurance that a profit will actually be made or that even the equity capital invested will berecovered.

When the funds that are set aside out of the revenue as the cost of depreciation are a part of

the net cash flow, these can be retained and used for capital financing of expansion projectslike cogeneration. The equipment may continue to be used after its original value has beenrecovered through normal depreciation procedures. Hence the accumulated funds may beavailable for use until the original equipment is actually replaced. Also, if the depreciationprocedures used in accounting are such that they provide large recoveries of the first costsduring the first few years of equipment life, there will usually be funds available before theequipment must be replaced. Thus, the depreciation funds may provide a revolvinginvestment fund that will become a source of capital for new ventures like cogeneration.Obviously, the management of these funds must ensure the availability of required capitalwhen the time does come for replacement of essential equipment.

Existing enterprises have an important source of capital financing for expansion of activities,

like setting up cogeneration power plants, through retained profits. Normally a part of the profitearned by an enterprise is retained after payment of adequate dividend to the shareholders,and this capital is then re-invested for a further increase in profits.


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In reality, the enterprise concerned may prefer to save the capital for financing its mainactivity that may present a smaller risk and can be a source of greater financial profitability.As an alternative, borrowed financing may seem more attractive because the suppliers ofdebt capital do not get a share of the profits accrued from the use of their capital. Here, afixed rate of profit, or value of money, must be paid to the supplier of the capital and therepayment of the borrowed funds is negotiated on the basis of the amount borrowed,duration, and the interest rates. Normally, the terms of the borrowed financing (loan) mayplace some restrictions on the uses to which the funds may be put. Moreover, any amountborrowed will require a certain percentage of equity investment and guarantees may berequired in the forms of mortgages or securities.

Leasing is only one of the several ways of obtaining working capital and a decision to lease,rather than purchase, should be based upon the cost of capital financing by other possiblemethods, some of which have been described above. The leasing company guarantees fullfinancing of the cogeneration plant, which remains its owner till the user buys it backaccording to the conditions of the contract. Most leases cannot be cancelled, or cancelled by

incurring costly penalties, whereas borrowed financing works on some fixed obligations andmay provide better terms.

Some indirect costs, which are difficult to determine in most cases, are associated with theownership that may not apply to the equipment under lease. In many cases, leasing turns outto be cheaper than owning, but the actual comparative costs and all other factors must beconsidered before a decision is taken.

An Energy Service Company (ESCO) often does third party financing which, after preliminaryanalysis of the requirement of the client and feasibility study of the cogeneration project,implements the project in agreement with the client. When the ESCO covers the whole costof financing the project, it is repaid by sharing the actual savings realized according to a

predetermined contract. Accurate measurement of the actual monetary saving is essential toassure fairness to the ESCO as well as the client. Here, the client does not have toinvestment in the cogeneration project and starts getting benefits from the day thecogeneration plant is in operation.

The concept of facility management is not very different from third party financing, except thatthe facility manager does more than an ESCO in meeting practically all the requirements ofthe site which are not directly involved with the main line of activity of the client. For example,a facility management firm can assure the supply of all utilities including electricity, steam,compressed air, water, etc., to the client, while also handling the wastes or effluentsgenerated from the production process. This firm signs a contract with the client to meet thepresent and future requirements of the site and invests in the development of infrastructure

and undertakes to operate and maintain it. By adopting innovative schemes such ascogeneration, sizing the components appropriately, operating the facility reliably andmaintaining it efficiently, the facility management firm manages to reduce the overall costconsiderably. Moreover, a part of the benefits accrued is shared with the client in the form ofreduced bill.

Facility management is normally feasible for bigger clients or where one firm can cater to theneeds of several clients in the same locality. Then it becomes economical to makeinvestment on a bigger facility and employing a limited number of personnel who can dealwith several clients at the same time.

3.5 Tools for Financial Analysis of Cogeneration Projects

Regardless of whether the cogeneration project is a totally new facility or a retrofit of anexisting operation, the project will materialize only if it is financially attractive. There are a


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number of financial indicators to measure the attractiveness of a project. Some indicators areused to compare several projects to decide which one is the best alternative.

The sizing of the cogeneration system is sometimes carried out by financial analysis in griddependent cases where there is an option for importing electricity instead of self-generationof all the electricity. In such circumstances, the optimum size of cogeneration wouldcorrespond to a system that has the minimum annual total cost (or maximum annual netprofit).

Commonly employed financial indicators for cogeneration feasibility study are the paybackperiod (PBP), net present value (NPV), and internal rate of return (IRR).

The easiest and basic measure of the fi

overview of cogeneration and its status in asia

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