System Design of Supercritical Thermal Power Plants-libre

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SYSTEM DESIGN OF SUPERCRITICAL THERMAL

POWER PLANT (800MW)

Submitted by:

NAVEEN KUMAR PODDAR (08ME1013) MRIDUL YADAV (08ME1004)

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CONTENTS

1. Introduction 3 1.1. What is Supercritical? 1.2. Why Supercritical?

2. History 6

3. Site Selection 7

4. Fuels and Combustion 8 4.1. Coal Classification 4.2. Analysis of Coal

5. Combustion mechanisms, Equipments and Firing methods 11 5.1. Preparation of coal 5.2. Firing Methods

6. Steam Generators 12 6.1. Sub-Crit ical Boiler Systems 6.2. Super-Critical Boiler Systems 6.3. Design for high steam temperature 6.4. Design features of once-through boilers 6.5. Boiler Operation and Boiler Material

7. Steam Turbines 21 7.1. Advances in Materials 7.2. Design Features

8. Condensers , Pumps and Circulating water systems 24 8.1. Condenser 8.2. Pumps 8.3. Cooling Tower

9. Pollution Handling Systems and Guidelines 26 9.1. Waste Characteristics 9.2. Emission Guidelines and Standards 9.3. Pollution Control Methods

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INTRODUCTION

Coal-based power generation is still a fundamental part of energy supply throughout the world. Reliability, security of supply, low fuel costs, and competitive cost of electricity make a good case for coal-fired steam power plants. Requests for sustainable use of existing resources and concerns about the effect of CO2 emissions on global warming have strengthen the focus of plant engineers and the power industry on more efficient energy conversion processes and systems.

Applying proven state-of-the-art technology while striving for cost-optimal efficiencies are key customer requirements in any new power plant project. Optimizing the combustion process, increasing the steam parameters, reducing the condenser pressure and improving the internal efficiency of the steam turbines are some of the well known levers for raising the overall plant efficiency. Due to the efficiency penalties associated with carbon capture and storage (CCS) such improvements are more than ever needed to ensure a sustainable generation of electricity based on coal.

Clean and cost-effective power generation is of paramount importance to cope with the challenges imposed by an increasing energy demand throughout the world. Investment cost and fuel costs are the main contributors to the cost of electricity. In recent years, costs associated with CO2 emissions have attracted more and more attention due to its political awareness.

The efficiency of the power plant as one key value affects both the fuel costs and the amount of CO2 emitted to the environment. As coal is more abundant in many parts of the world, coal prices are less volatile and more stable than natural gas prices. But larger CO2 emissions increase the need for more efficient coal-based power generation.

Supercritical steam power plants meet notably the requirements for high efficiencies to reduce both fuel costs and emissions as well as for a reliable supply of electric energy at low cost. Recent developments in steam turbine technology and high-temperature materials allowed for significant efficiency gains.

Introduction of the advanced technology has led to the current expansion of supercritical power plants worldwide. Therefore, In order to cope with the growing demand of power within India, a fundamental understanding of these power plants and implications are necessary.

The aim of this report is to provide an analysis of plant and operational features of a Super Critical Power Plant along with impact of coal quality on operational issues.

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WHAT IS SUPERCRITICAL?

"Supercritical" is a thermodynamic expression describing the state of a substance where there is no clear distinction between the liquid and the gaseous phase (i.e. they are a homogenous fluid). Water reaches this state at a pressure above 22.1 megapascals (MPa). Up to an operating pressure of around 19 MPa in the evaporator part of the boiler, the cycle is subcritical. This means, that there is a non-homogeneous mixture of water and steam in the evaporator part of the boiler. In this case, a drum-type boiler is used because the steam needs to be separated from water in the drum of the boiler before it is superheated and led into the turbine. Above an operating pressure of 22.1 MPa in the evaporator part of the boiler, the cycle is supercritical. The cycle medium is a single-phase fluid with homogeneous properties and there is no need to separate steam from water in a drum. Once-through boilers are therefore used in supercrit ical cycles.

Currently, for once-through boilers, operating pressures up to 30 MPa represent the state of the art. However, advanced steel types must be used for components such as the boiler and the live steam and hot reheat steam piping that are in direct contact with steam under elevated conditions. Therefore, a techno-economic evaluation is the basis for the selection of the appropriate cycle parameters.

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WHY SUPERCRITICAL?

Supercritical coal fired power plants permits efficiencies that exceed 45%, depending on cooling conditions. Options to increase the efficiency above 50 % in ultra-supercritical power plants rely on elevated steam conditions as well as on improved process and component quality.

Steam conditions up to 30 MPa/600C/620C are achie ved using steels with 12 % chromium content. Up to 31.5 MPa/620C/620C is achieved usi ng Austenite, which is a proven, but expensive, material. Nickel-based alloys, e.g. Inconel, would permit 35 MPa/700C/720C, yielding efficiencies up to 48%. Manufacturers and operators are cooperating in publicly sponsored R&D projects with the aim of constructing a demonstration power plant of this type.

Other improvements in the steam cycle and components can yield a further 3 percentage points rise in efficiency. Most of these technologies, like the double reheat concept where the steam expanding through the steam turbine is fed back to the boiler and reheated for a second time as well as heat extraction from flue gases have already been demonstrated.

There are no operational limitations due to once-through boilers compared to drum type boilers. In fact, once-through boilers are better suited to frequent load variations than drum type boilers, since the drum is a component with a high wall thickness, requiring controlled heating. This limits the load change rate to 3% per minute, while once-through boilers can step-up the load by 5% per minute. This makes once-through boilers more suitable for fast startup as well as for transient conditions.

Current designs of supercritical plants have installation costs that are only 2% higher than those of subcritical plants. Fuel costs are considerably lower due to the increased efficiency and operating costs are at the same level as subcritical plants. Specific installation cost i.e. the cost per megawatt (MW) decreases with increased plant size.

Benefits of advanced supercritical power plants include:

Reduced fuel costs due to improved plant efficiency. Significant reduction in CO2 emissions. Excellent availability, comparable with that of an existing sub-critical plant. Plant costs comparable with sub-critical technology and less than other clean coal

technologies. Much reduced NOx, SOx and particulate emissions. Compatible with biomass co-firing. Can be fully integrated with appropriate CO2 capture technology.

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HISTORY

Supercritical technology was first developed in the U.S. in the 1950s. The early units however experienced problems related to reliability and operational flexibility. The technology was adopted in Japan in the 1960s, has been refined by members of the related industries and is now utilized for all new large capacity boilers. The continuing development of high strength pressure parts materials to be used for high temperature- 2 -regions has enabled the technology to extend the steam temperatures to higher than 1100F (593C). Reflecting a strong desire of reduction in CO2 emission by achieving high efficiency, recently constructed large capacity boilers in Japan have employed this technology unexceptionally. The industries in most countries in Asia, Europe and Oceania have almost adopted the supercrit ical technology as a standard.

In 1954, the hunt for higher thermal efficiencies led to the construction of the Eddystone supercrit ical steam power plant. This search involved many of the major industrial companies of the time. A king-size supercritical project for Queensland; At 750 MWe, Kogan Creek will be about 300 MWe larger than Australia's five previous supercritical coal-fired units, and the biggest single-unit power plant in Australia. Huaneng Power International, Inc. (the "Company") announces that the first 1,000MW ultra-supercritical coal-fired generating unit (unit 1) at Huaneng Yuhuan Power Plant, NTPC has placed orders for steam generator packages for the 2x500 Mw Super Thermal Power Project each in Madhya Pradesh (Vindhyachal) and Uttar Pradesh (Rihand). NTPL has placed order for setting up 2x500 Mw thermal power plants in Tamil Nadu (Tuticorin).

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SITE SELECTION

For the conventional load based thermal power plant following factors should be considered:

1. Availability of cooling water(if cooling towers are used , the possibility of adequate make-up water)

2. Availability of fuel (water, rail or pipe connection to the fuel source and the cost of fuel transport)

3. Distance from the centre of gravity of load demand 4. Cost of land(including space for extension, maintenance workshop and storage yard) 5. Character of soil 6. Main wind direction and water currents in cooling water source (sea, lake or river in

order to minimize air and water pollution and other ecological considerations) 7. With coal fired stations, disposal of ash 8. Rail and road connections 9. Security considerations

TRANSPORT OF FUEL TO SITE AND STORAGE

Most thermal stations use coal as the main fuel. Raw coal is transported from coal mines to a power station site by trucks, barges, bulk cargo ships or railway cars. Generally, when shipped by railways, the coal cars are sent as a full train of cars. The coal received at site may be of different sizes. The railway cars are unloaded at site by rotary dumpers or side tilt dumpers to tip over onto conveyor belts below. The coal is generally conveyed to crushers which crush the coal to about inch (6 mm) size. The crushed coal is then sent by belt conveyors to a storage pile. Normally, the crushed coal is compacted by bulldozers, as compacting of highly volatile coal avoids spontaneous ignition.

The crushed coal is conveyed from the storage pile to silos or hoppers at the boilers by another belt conveyor system.

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FUELS AND COMBUSTION

COAL CLASSIFICATION

Coal is classified into three major types namely anthracite, bituminous, and lignite. However there is no clear demarcation between them and coal is also further classified as semi- anthracite, semi-bituminous, and sub-bituminous. Anthracite is the oldest coal from geological perspective. It is a hard coal composed mainly of carbon with little volatile content and practically no moisture. Lignite is the youngest coal from geological perspective. It is a soft coal composed mainly of volatile matter and moisture content with low fixed carbon. Fixed carbon refers to carbon in its free state, not combined with other elements. Volatile matter refers to those combustible constituents of coal that vaporize when coal is heated.

The common coals used in Indian industry are bituminous and sub-bituminous coal. The gradation of Indian coal based on its calorific value is as follows:

Grade Calorific Value Range(Kcal/ kg) A Exceeding 6200 B 5600-6200 C 4940-5600 D 4200-4940 E 3360-4200 F 2400-3360 G 1300-2400

Normally D, E and F coal grades are available to Indian Industry.

ANALYSIS OF COAL

There are two methods: ultimate analysis and proximate analysis. The ultimate analysis determines all coal component elements, solid or gaseous and the proximate analysis determines only the fixed carbon, volatile matter, and moisture and ash percentages.

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Significance of Various Parameters:

a) Fixed carbon: Fixed carbon is the solid fuel left in the furnace after volatile matter is distilled off. It consists mostly of carbon but also contains some hydrogen, oxygen, sulphur and nitrogen not driven off with the gases. Fixed carbon gives a rough estimate of heating value of coal

b) Volatile Matter: Volatile matters are the methane, hydrocarbons, hydrogen and carbon monoxide, and incombustible gases like carbon dioxide and nitrogen found in coal. Thus the volatile matter is an index of the gaseous fuels present. Typical range of volatile matter is 20 to 35%.

Volatile Matter Proportionately increases flame length, and helps in easier ignition of coal. Sets minimum limit on the furnace height and volume. Influences secondary air requirement and distribution aspects. Influences secondary oil support

c) Ash Content: Ash is an impurity that will not burn. Typical range is 5 to 40%.

Ash Reduces handling and burning capacity. Increases handling costs. Affects combustion efficiency and boiler efficiency Causes clinkering and slagging.

d) Moisture Content: Moisture in coal must be transported, handled and stored. Since it replaces combustible matter, it decreases the heat content per kg of coal. Typical range is 0.5 to 10%

Moisture Increases heat loss, due to evaporation and superheating of vapour Helps, to a limit, in binding fines. Aids radiation heat transfer.

e) Sulphur Content: Typical range is 0.5 to 0.8% normally.

Sulphur Affects clinkering and slagging tendencies Corrodes chimney and other equipment such as air heaters and economisers Limits exit flue gas temperature

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The ultimate analysis indicates the various elemental chemical constituents such as Carbon, Hydrogen, Oxygen, Sulphur, etc. It is useful in determining the quantity of air required for combustion and the volume and composition of the combustion gases. This information is required for the calculation of flame temperature and the flue duct design etc. Typical ultimate analyses of various coals are given in the Table:

Parameter Indian Coal (%) Australian Coal (%) Moisture 5.98 9.43

Mineral Matter(1.1* Ash) 38.3 13.99 Carbon 41.11 59.05 Hydrogen 2.76 4.16 Nitrogen 1.22 1.02 Sulphur 0.41 0.8 Oxygen 9.89 11.88

Proposed fuel composition 1. 70 % Domestic:

Indian Washed Coal from Talcher Coal fields of Mahanadi Coal fields Limited in Orissa state.

Avg. Calorific Value- 3070 Kcal/kg. Heat Rate -2450Kcal/KWH.

2. 30 % Imported: Imported Coal from Indonesia, South Africa, Australia, China, etc. Avg. Calorific Value- 5500Kcal/kg. Heat Rate-2500Kcal/KWH.

Net Calorific Value : 3800Kcal/kg Average ash content in coal (%-ARB) : 30.9% Maximum Sulphur content in coal : 0.35%

Water requirement : 245150m3/hr (including loss plus recovery)

Amount of coal required Wattage of Plant : 800 MW Efficiency : 37.5 % Thermal Energy Required : 800/0.375=2133.33MW Calorific Value of fuel : 3800Kcal/kg= 15960 KJ/kg Amount of Coal : (2133.33*10^6) / (15960*10^3) =133.6 kg/sec

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COMBUSTION MECHANISMS, EQUIPMENTS AND FIRING METHODS

PREPARATION OF COAL Sizing of coal: Proper coal sizing is one of the key measures to ensure efficient combustion. Proper coal sizing, with specific relevance to the type of firing system, helps towards even burning, reduced ash losses and better combustion efficiency. Coal is reduced in size by crushing and pulverizing. Pre-crushed coal can be economical for smaller units, especially those which are stoker fired. In a coal handling system, crushing is limited to a top size of 6 or 4mm. The devices most commonly used for crushing are the rotary breaker, the roll crusher and the hammer mill. It is necessary to screen the coal before crushing, so that only oversized coal is fed to the crusher. This helps to reduce power consumption in the crusher. Recommended practices in coal crushing are:

1. Incorporation of a screen to separate fines and small particles to avoid extra fine generation in crushing.

2. Incorporation of a magnetic separator to separate iron pieces in coal, which may damage the crusher. For pulverized fuel fired system the final coal size: 75% below 75 micron

FIRING METHODS Indirect firing or Storage System Direct firing system Semi direct firing system

Large steam generators are provided with one or more firing systems. This adds to the simplicity, greater safety, lower space requirements, lower capital and operating costs & great plant cleanliness. Proposed firing method : Direct firing System Pulverized coal burners It should satisfy following requirements:

It should prepare two individual flows, a coal dust air mixture and secondary air for ignition & active burning in the furnace space for creating turbulent environment for thorough mixing.

It should be able to control the flame shape and maintain a stable ignition of air-fuel mixture.

To prevent flashback into the burner.

In order to limit the NOx output, we use low NOx burners .NOx reducing parameters are met by reduction of secondary air quantity, diversion of secondary air injected through the auxiliary secondary air nozzles and injection of the remaining secondary air through pores above the top fuel nozzles on the original firing cycle. Proposed pulveriser

Beater Wheel Mills (Alstom)- 15 ton/h to 200 metric ton/h Bowl Mills (Alstom)- 5 metric ton/h to 150 metric ton/h ; Product fineness- 99% passing 45

microns.

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STEAM GENERATORS

SUB-CRITICAL BOILER SYSTEMS Water when heated at sub-critical pressure ( less than 22.1 MPa) increases in temperature until it starts to boil.While the water is boiling it exists as two phases, liquid and gas that have different mass densities, and remains at a constant temp. Known as the saturation temperature for the given pressure.Once all of the liquid has boiled off to steam (evaporated) the temperature of the steam will continue to rise, at constant pressure, and is then referred to as superheated steam. Sub-critical boilers typically have a means of separating the two phases, liquid and steam, to allow the process to be continuous.The separated liquid is recirculated through the evaporating section of the boiler and steam passes through to the superheating section. This separation typically occurs in the boiler drum, a heavy thick walled steel pressure vessel with a series of cyclones and baffles to separate liquid from steam. It is the mass of this boiler drum which limits the rate at which a sub-critical boiler can be brought on line and how well it responds to load changes which results in fuel being consumed for no energy compared with a more responsive boiler. Too great a firing rate will result in damaging thermal stresses in the heavy boiler drum.

SUPER-CRITICAL BOILER SYSTEMS When water is heated at a constant pressure above the critical pressure its temperature is never constant and no distinction between gas and liquid can be made, the mass density of the two phases is the same. Properties of the water in the super-critical boiler continuously change from liquid to gas (steam), for example:

Temperature rises steadily. Specific heat and rate of rise changes considerably.

Liquid in the super-critical boiler is assumed to have changed to steam after the critical temperature for the super-critical pressure, as the steam is heated further it continues to gain temperature in a superheated state. With the super-critical boiler there is no stage where the water exists as two phases and requires separation, so the boiler is constructed without a drum. Typically super-critical boilers are once through boilers where water pumped in at pressure by the Boiler Feed Pump passes progressively through the heating stages of the boiler and is delivered to the turbine at final temperature with no recirculation. The actual location of the transition from liquid to steam in a once through super-critical boiler is free to move with differing conditions. This means that for changing boiler loads and pressures the process is able to optimise the amounts of liquid and gas regions for efficient heat transfer keeping the high boiler efficiency over a wider range than sub-critical boilers with drums.

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Once-through Boiler Characteristics

The once through boiler has high load response characteristics due to the fact that it does not have a drum and has a much lower water inventory.

In the once through boiler, many times the load change response is dictated by the firing system and its controls rather than the boiler, per-say.

Once through boilers of super-critical pressure boilers have higher efficiency. However in the sub-critical range there is no difference in efficiency when compared to the drum type design.

Generally the power consumption is higher by 5 to 8 % for the same capacity boilers of drum type.

Once through boilers have a separate start-up loop along with all its controls. As the load demand is met by varying both fuel and feed water flow simultaneously,

the controls are more sophisticated and have to be more reliable. More redundancies are built in.

The water quality level is much more stringent than drum type boilers. Normally a condensate polishing unit is employed in once through units.

In once through boilers the superheater headers are subjected to both fatigue and creep when cyclic or two shift operations is resorted to. Hence these boilers are more preferred for base load operation. However, the load change rate that theses boilers can take is higher due to the absence of the drum.

A closer regime of operation is expected in once through boilers. The absence of the drum makes it possible to reduce the overall cycle time for the

once through boiler. However, the overall plant cycle time may not vary only marginally.

Once through boilers life time cost is expected to be more than the drum type units.

DESIGN FOR HIGH STEAM TEMPERATURE

1. Advanced high strength materials:

In order to achieve steam temperatures higher than 1100 deg. F while maintaining reliability,improved high strength ferritic and austenitic materials forhigh temperature use have been developed. The welding methods and materials have been established and proven for each of the developed materials. By application of these advanced materials, the thickness of pressure parts in the highest metal temperature regions can be reduced. For boiler tubes for high temperature steam application, materials such asA213TP310HCbN (HR3C in Japan) and A213UNS S30432 (Super 304 in Japan) have been developed and are commercially available. These materials have up to1.5 times higher strength at high temperatures than the traditional austenitic tubesteels such as Type 310H or Type 304H materials.

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2. Steam oxidation:

The formation of steam oxide scale in stainless steel tubing is an important issue to be taken into account in the design for high steam temperatures. The steam oxide scale formation rate increases with operating temperature, and as a result the potential for exfoliation of oxide scales can become very high. As a countermeasure against the once extensive scaling problems, austenitic stainless steel tubes have been internally shot blasted as part of the manufacturing process since the early 1980s. By appropriate internal shot blasting, the formation of steam oxide scale on the inside surface of shot-blasted tubes is negligible in the operating range of supercrit ical boilers. These techniques can be applied for tubes for service well above 1100F (593C).

3. Sulfidation:

Sulfidation is a process where hydrogen sulfide (H2S) created in the combustion process reacts with water wall tubes and leads to severe wastage. The key parameters that determine the levels of sulfidation are sulfur content in fuel, burner stoichiometry (the atmosphere around the burners), tube material compositions and metal temperature. While a lower stoichiometric ratio in the combustion zone is favorable to lower the amount of NOx produced, adversely it can result in higher levels of H2S production, and hence will promote sulfidation. Although the level of generated H2S depends on the sulphur content, the results show that a higher stoichiometric ratio can suppress the generation of H2S during combustion. The setting of appropriate burner stoichiometry is a significant factor in reducing the potential for sulfidation.

4. Liquid phase corrosion:

Liquid phase corrosion of stainless steel tubes at high temperature zones is a phenomenon that depends on the sulfur dioxide content in the combustion gas, the tube metal temperature, and the material composition.

The liquid phase corrosion (or simply high temperature corrosion) is strongly dependent on the SO2 content.The SO2 content in the flue gas is controlled by the sulfur content of the coal burned.

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Proposed boiler to be used: Spiral Wound Universal Pressure (SWUP) Boiler by Babcock & Wilcox.

Design features: A once-through boiler for supercrit ical applications, usually applied to systems with a capacity of 400 MW or larger; the design features a water-cooled dry-bottom furnace, superheater, reheater, economizer, and air heater components designed for both base load and full boiler variable pressure load cycling operation as well as on/off cycling operation. Capacity, steam output: From 2,000,000 lb/h (252 kg/s) to more than 10,000,000 lb/h (1260 kg/s). Operating pressure: Usually at 3500 psi (24.1 MPa) throttle pressure with 5% overpressure; higher pressures available. Superheater steam temperatures: As required, currently in the 1100F (595C) range. Fuel: Pulverized coal.

Our once through boiler, would consist of two reheaters each operating at a pressure ratio of close to 0.25.This means

The steam pressure entering the HP turbine will be 250 Bar. The steam pressure in the 1st reheater will be 65 Bar. The steam pressure in the 2nd reheater will be 15 Bar. The steam pressure in the condenser will be 0.04 Bar.

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DESIGN FEATURES OF THE ONCE THROUGH BOILER

1. Sliding pressure operation

By adopting the sliding pressure operation with lower boiler pressures at partial loads, the plant heat rate can be improved at partial loads due to improvement of high pressure (HP) turbine efficiency, reduced auxiliary power consumption by boiler feed pumps, and higher steam temperature at the HP turbine outlet. In addition to the plant efficiency advantages, there are other benefits such as reduction in start-up time, increase in ramp rate and reduced erosion of bypass valve.

2. Spiral Waterwall

For sliding pressure boilers, maintaining uniform fluid conditions during low load / low pressure operation becomes critical to reduce the potential of tube damage caused by high metal temperatures. The lower part of the boiler furnace is arranged in a spiral configuration such that the fluid path wraps around the boiler as it travels up the furnace. As a result of the uniform waterwall fluid temperature profile that is achieved across the full range of boiler loads, the spiral waterwall system does not require any flow adjusting devices to be installed at the furnace inlet. When steam is fed into the waterwall tubes, a large temperature gradient is obtained b/w the fireside & waterside of the tube.

3. Economizer

Economizer is a heat exchanger in which raises the temperature of the feed water leaving the highest pressure feedwater heater to about saturation temperature corresponding to boiler pressure. This is done by the hot flue gases exiting the last superheater or reheater at a temp. Varying from 370 C from 540 C. Economizer tubes are commonly 45-70 mm in outside dia. and are made in vertical coils, installed at a pitch of 45-50 mm spacing.

4. Superheater

Superheater is a heat exchanger in which heat is transferred to the saturated steam to increase its temp. The superheaters are classified as two types according to their heat source:

Convection type-These are located in the convective zone of the furnace usually ahead of economizer. They are often termed as primary superheater.

Radiant type-After convective superheater steam proceeds to the radiant superheater which is placed in the radiant zone of the furnace near the water wall to absorb heat by radiation.

Pendant superheater is a combined superheater in the sense that it receives heat partly by convection and partly by radiation. Radiant and combined superheater together is often termed as secondary superheater.

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5. Reheater

Reheaters are similar to superheater with almost same steam outlet temperature and with a steam temperature about 25 % of superheaters. Reheaters are usually located above the primary superheater in the convective zone. It consist of no. of vertical coils of horizontal tubes connected b/w two headers similar to the economizer and combined superheater.

In modern high pressure boilers, reheaters are normally in two sections. The primary section is placed in the convective zone of the back pass and the secondary section is placed just at the furnace exit hanging from the top known as pendant reheater.

6. Air preheater

Air Preheater is a general term to describe any device designed to heat air before another process (for example, combustion in boiler) with the primary objective of increasing the thermal efficiency of the process.

The purpose of the air preheater is to recover the heat from the boiler flue gas which increases the thermal efficiency of the boiler by reducing the useful heat lost in the flue gas. Air of the temperature range 150-420 C is needed for drying coal in the pulveriser. Air is also used for transporting pulverised coal to the furnace and burning it there. It is of two types-recuperative air preheater and regenerative air preheater. The most common type is rotary air preheater known as Ljungstrom air preheater which consists of a rotor, driven by a motor. They are compact heat exchanger with large heat transfer surface and can be accommodated in small volume.

7. Feedwater Heaters

A feedwater heater is a power plant component used to pre-heat water delivered to a steam generating boiler. Preheating the feedwater reduces the irreversibilities involved in steam generation and therefore improves the thermodynamic efficiency of the system.This reduces plant operating costs and also helps to avoid thermal shock to the boiler metal when the feedwater is introduced back into the steam cycle.

They are of two types: Open or Contact Feedwater Heater: Extracted steam is allowed to mix with the

feedwater and both leave the heater at a common temperature. Closed Feedwater Heater: Are shell-and-tube heat exchanger where the feedwater

flows through the tubes and the extracted steam condenses outside the tube in the shell.

Closed Heaters are costly and doesnt give as high feedwater temperature as open heaters. In most steam plants closed heaters are favoured but at least open heater is used for the purpose of deaeration.

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The number of heaters is fixed by energy balance of the whole plant when it is found that the cost of adding another heater does not justify the savings in the heat supply or the marginal increase in cycle efficiency. Increase in feedwater temperature reduces heat absorption from the outgoing flue gases in the economizer and may reduce boiler efficiency. For a general cycle 5-7 points of extraction are often used in practise.

In our cycle we use 5 feedwater heaters:

One Extraction from HP turbine at 100 Bar. Three Extractions from IP turbine at 40, 20 and 10 bar respectively. One extraction from LP turbine at 5 Bar.

8. Deaerators

A deaerator is a device that is widely used for the removal of air and other dissolved gases from the feedwater to steam-generating boilers. In particular, dissolved oxygen in boiler feedwaters will cause serious corrosion damage in steam systems by attaching to the walls of metal piping and other metallic equipment and forming oxides (rust). Water also combines with any dissolved carbon dioxide to form carbonic acid that causes further corrosion. Most deaerators are designed to remove oxygen down to levels of 7 ppb by weight (0.005 cm/L) or less. There are two basic types of deaerators:

The tray-type (also called the cascade-type) includes a vertical domed deaeration section mounted on top of a horizontal cylindrical vessel which serves as the deaerated boiler feedwater storage tank.

The spray-type consists only of a horizontal (or vertical) cylindrical vessel which serves as both the deaeration section and the boiler feedwater storage tank.

Proposed deaerator:

Manufactured by Parker Industries with specification

3,500 to 90,000 lbs/hr Oxygen Removal to .005 cc/1 CO2 removal to virtually 0.

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BOILER OPERATION

The boiler is sited in a boiler house with the pressure parts suspended within the boiler structure. The boiler house accommodates the coal bunkers, coal feeders, coal milling plant and the forced draught and primary air fans and air heaters.

The furnace dimensions are chosen to meet the requirements of low NOx emissions in the flue gases whilst maximising burnout to minimise the amounts of unburned carbon-in fly-ash for the given fuel fired.

In the combustion zone of the boiler, the membrane wall is spiral wound, utilising smooth-bore tubing. This inclined-tube arrangement reduces the number of parallel paths compared with a vertical-wall arrangement and therefore increases the mass flow of steam/water mixture through each smooth-bore tube. The high mass flow improves heat transfer between the tube metal and the fluid inside to maintain adequate cooling of the tube metal, despite the powerful radiant heat flux from the furnace fireball. In the upper furnace area, the heat flux is much lower and the transition is made from spiral wound to vertical tubing, via a transition header.

BOILER MATERIAL

The various components of the boiler are employed over a range of temperatures, pressures and corrosive atmospheres, and oxidation conditions, and the range of alloys necessary to best meet the design demands covers the simple carbon manganese (CMn) steels, low alloy steels, advanced low alloy steels, the 9-12Cr martensitic family and the austenitic range with chromium varying from 18% to in excess of 25%.

Simple carbon manganese steels are utilised at lower temperatures such as the reheater inlet but as component temperatures increase, it is necessary to move to low alloy steels such as SA213 T22 which, like the CMn steels, have been employed in boiler construction for decades.

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Moving to components at even higher temperatures and considering other manufacturing restrictions leads to the introduction of more modern steels that have been referred to as creep-strength enhanced ferritic (CSEF) steels 4, which exhibit very high creep strength by virtue of a fine dispersion of creep strengthening precipitates.

Two specific alloys within this family are T23 per ASME code case 2199 and T24 per ASTM A213. Both are based on the much used T22 or 2.25% chrome steel, but in the case of T23 modified by the addition of 1.6% tungsten and the reduction of molybdenum and carbon contents with the addition of small amounts of niobium, vanadium and boron. T24 also has reduced carbon but with additions of vanadium, titanium and boron.

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STEAM TURBINES

ADVANCES IN MATERIALS

Steam turbines for ASC steam conditions require application of advanced alloy steels for the HP and IP turbines and for the main and reheat steam admission valves.

The maximum metal temperatures in high temperature steam turbine components are limited by the applied stress and the requirement for a component lifetime of at least 200,000 hours. The principal material property determining the maximum temperature is the long-term creep rupture strength.

The most critical components at elevated temperatures are the valve chests and turbine casings (operating under high internal steam pressures) and the turbine rotors and blading (operating under high centrifugal load). With respect to pressure containment, the HP turbine casings tend to be the most limiting, whilst for the rotating components, the IP rotor, being of larger diameter and with longer blades, requires the more careful design in the high temperature regions. In contrast, the low pressure (LP) turbines can use the same technology as conventional steam turbines, because the steam conditions at inlet to the LP sections can be maintained at similar levels to subcritical steam generating plant.

Todays state-of-the-art steam turbines are based on the exploitation of advanced 9-12% Cr martensitic steels for rotors and casings,with nickel-based alloys or high-strength austenitic steels being required only for the early stages of blading. In both Europe and Japan, a first generation of advanced martensitic steels was developed in the mid-1980s and saw first commercial applications in plant entering service in the mid-1990s. These steels were based on optimised additions of Cr (9-10%), Mo (1-1.5%), W (~1%), V (~0.2%), Nb (~0.05%) and N (~0.05%), and they enabled steam temperatures to be increased to around 600C. A second generation of alloys has been developed based on additions of boron (~100ppm), in some cases with higher levels of W, and with additions of cobalt to ensure a fully martensitic microstructure. The greater creep strength of this second generation of alloys has enabled temperatures of 620C to be achieved.

DESIGN FEATURES

Modern HP and IP turbines for supercritical applications at moderate temperatures use single-piece rotor forgings. The application of welded rotor technology in these sections (with rotors made by welding together several forged sections to form a compact shaft with low body stresses) provides the capability to introduce 10% Cr steel sections for the hottest areas adjacent to the steam inlet zones of the HP and IP turbines, with conventional 1% Cr Mo V material for the outboard sections.

Distortion of turbine casings during thermal transients (e.g. in start-up or rapid load changes) can damage radials seals between the rotor and stationary parts, especially if the fixed blades are mounted directly into the casings. The cylindrical symmetry

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obtained from a shrink-ring closure system of the HP inner casing avoids the need for bolted joint flanges and ensures that thermal distortion of casings is minimised with a consequent improvement in operational flexibility.

Where applicable, temperature conditioning steam flows are introduced from within the HP and IP turbine cylinders to ensure that steady state metal temperatures in the hottest regions remain within acceptable limits, and to reduce the thermal impact of rapid load changes whilst retaining maximum performance advantage from the advanced steam conditions.

The blades of an ST are the components that receive the most attention. Significant efforts are invested to optimize blade design, which has a direct and powerful effect on HP and IP modules efficiency. It is customary to use a fully developed 3-D design, accounting for all blade profile losses, leakage losses, and other secondary effects. Because the blades are short, relatively large end-wall losses occur at the hub and the shroud. By modifying the conventional cylindrical design with a fully developed 3-D design, bent and twisted at the blade hub and tip, a stage efficiency improvement of approximately 2 percent is obtained. Another improvement for HP/ IP blading is the use of variable reaction for each stage in the blade path length instead of the constant 50 percent reaction.

The allowable tensile radial stress value represents the major limiting factor for blade length. Other limiting stresses include the bending stress resulting from steam forces in the blade root part and the tensile stress in the rotor caused by centrifugal forces.

New steam turbines (or retrofitted turbines) for ASC applications, in common with conventional steam turbines, must be able to support rapid load changes and have the capability to operate efficiently at part loads. Turbine internal efficiency improvements, discussed above for full load operation, also translate to similar improvements at part loads. Part load efficiency is largely a function of valve throttling loss. New HP turbine modules would therefore ideally be equipped with nozzle control capability to permit the unit to operate with up to 50% of the nozzle arcs closed at part load. This avoids the losses associated with throttling all the turbine governor valves simultaneously.

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Sealing Beyond the use of conventional non-contact labyrinth seals, new sealing technologies have been introduced in advanced ST designs, aiming to further reduce leakage losses. Several sealing methodologies used in gas turbines, such as abradable seals and brush seals, have found their way into ST applications.

Brush seals are becoming standard features in advanced STs, particularly for the HP and IP modules of SC and USC STs. Brush seals provide a curtain of metal bristles between adjacent areas of different pressures. The bristles are canted at an angle relative to the radial direction of the shaft, and the sealing process starts as soon as differential pressure is created, even though there is still a gap between the bristles and the rotor. In this type of application ,a 50 percent reduction of leakage flow is achieved compared with that of a conventional seal. The absence of any clearance between the brush and the surface of the part reduces the leakage considerably70% and moreand can improve turbine efficiency by 0.5 percent.

OPERATING CONDITIONS

Turbine Inlet Pressure Outlet Pressure High Pressure Turbine 250 Bar 65 Bar

Intermediate Pressure Turbine 65 Bar 15 Bar Low Pressure Turbine 15 Bar 0.04 Bar (25 C)

Proposed turbine:

STF 40 ( 250-700 mw) or STF 60 ( 500-900 mw) by Alstom Industries.

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CONDENSERS , PUMPS AND CIRCULATING WATER SYSTEMS

CONDENSERS

Condensers are heat exchangers which convert steam from its gaseous to its liquid state at a pressure below atmospheric pressure. A water-cooled shell and tube heat exchanger installed on the exhaust steam from a steam turbine in thermal power stations is called as surface condenser.

Need of a condenser To reduce the turbine exhaust pressure, so as to increase the specific output of the

turbine. To recover high quality feedwater in the form of condensate and feed it back to the

steam generator without any further treatment.

Modern Designs have steam lanes b/w tube banks to get max. steam flow with least pressure drop and uniform distribution of steam in the shell.In a two pass surface condenser steam enters a tube bundle in two separate sections from the top, sides and bottom, and flows towards the centre of the tube nest in each section.

Tube material: Cupronickel (70% Cu- 30% Ni), Aluminium Brass (76% Cu-22% Zn-2%Al), Muntz Metal (60%Cu-40%Zn)

Proposed condenser specification

Operating Pressure- 0.04 Bar Surface Condenser manufactured by : Alstom Industries Outside diameter of the tube is 22-23 mm and length varies from 9-15 m.

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PUMPS

A condensate pump is a specific type of pump used to pump the condensate (water) produced in an HVAC (heating or cooling), refrigeration, and condensing boiler furnace or steam system

In a steam power plant, the condensate pump is normally located adjacent to the main condenser hotwell often directly below it. This pump sends the water to a make-up tank closer to the steam generator or boiler. If the tank is also designed to remove dissolved oxygen from the condensate, it is known as a Deareating feed tank (DFT). The output of the DFT supplies the feed booster pump which, in turn, supplies the feed pump (feedwater pump) which returns the feedwater to the boiler so the cycle can start over. Two pumps in succession are used to provide sufficient Net Positive Suction Head to prevent cavitation and the subsequent damage associated with it.

Proposed pumps: Vertical Turbine Pumps (VTP): Alstom Saturne Pumps made by Alstom Industries 75000 m3/h.

COOLING TOWER A Cooling tower is equipment used to reduce the temperature of a water stream by extracting heat from water and emitting it to the atmosphere. They thus reduces the cooling water requirement in the power plant. Types of cooling towers

Natural Draft Cooling Tower- This makes use of the difference in temperature b/w the ambient air and hotter air inside the tower.

Mechanical Draft cooling Tower-These have large fans to force or draw air through circulated water.

Design considerations Cooling Range Wet Bulb Temperature of air Water Flow rate Size Air velocity

Other design characteristics to consider are fan horsepower, pump horsepower, make-up water source, fogging abatement, and drift eliminators.

Operation considerations

Water Make-up: Water losses include evaporation, drift (water entrained in discharge vapor), and blowdown (water released to discard solids). Drift losses are estimated to be between 0.1 and 0.2% of water supply.

Proposed cooling tower: Mechanical cross flow Cooling Tower by- BHEL.

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POLLUTION HANDLING SYSTEMS AND GUIDELINES

WASTE CHARACTERISTICS

The wastes generated by thermal power plants are typical of those from combustion processes. The exhaust gases from burning coal and oil contain primarily particulates (including heavy metals, if they are present in significant concentrations in the fuel), sulfur and nitrogen oxides (SOx and NOx,( and volatile organic compounds (VOCs). For example, a 500 MWe plant using coal with 2.5% sulfur (S), 16% ash, and 30,000 kilojoules per kilogram (kJ/kg) heat content will emit each day 200 metric tons of sulfur dioxide (SO2 ), 70 tons of nitrogen dioxide (NO2 ), and 500 tons of fly ash if no controls are present. In addition, the plant will generate about 500 tons of solid waste and about 17 gigawatt-hours (GWh) of thermal discharge.

The concentrations of these pollutants in the exhaust gases are a function of firing configuration, operating practices, and fuel composition. Ash residues and the dust removed from exhaust gases may contain significant levels of heavy metals and some organic compounds, in addition to inert materials. Fly ash removed from exhaust gases makes up 6085% of the coal ash residue in pulverized-coal boilers. Bottom ash includes slag and particles that are coarser and heavier than fly ash.

Steam turbines and other equipment may require large quantities of water for cooling, including steam condensation. Water is also required for auxiliary station equipment, ash handling, and FGD systems. The characteristics of the wastewaters generated depend on the ways in which the water has been used. Contamination arises from demineralizers, lubricating and auxiliary fuel oils, and chlorine, biocides, and other chemicals used to manage the quality of water in cooling systems. Once-through cooling systems increase the temperature of the receiving water.

EMISSION GUIDELINES

Particulate matter:

For all plants or units, PM emissions (all sizes) should not exceed 50 mg/Nm3 The EA should pay specific attention to particulates smaller than 10 m in aerodynamic diameter (PM10 ) in the airshed, since these are inhaled into the lungs and are associated with the most serious effects on human health. Where possible, ambient levels of fine particulates (less than 2.5 mm in diameter) should be measured

Sulfur dioxide:

Total sulfur dioxide emissions from the power plant or unit should be less than 0.20 metric tons per day (tpd) per MWe of capacity for the first 500 MWe, plus 0.10 tpd for each additional MWe of capacity over 500 MWe. In addition, the concentration of sulfur dioxide in flue gases should not exceed 2,000 mg/Nm3 (see note 4 for assumptions), with a maximum emissions level of 500 tpd. Construction of two or more separate plants in the same airshed to circumvent this cap is not acceptable.

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Nitrogen oxides:

The specific emissions limits for nitrogen oxides are 750 mg/Nm3 , or 260 nanograms per joule (ng/J), or 365 parts per million parts (ppm) for a coal-fired power plant, and up to 1,500 mg/Nm3 for plants using coal with volatile matter less than 10.

Guidelines for Liquid Effluents:

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POLLUTION CONTROL METHODS

Ash handling system

Fly ash handling systems may be generally categorized as dry or wet, even though the dry handling system involves wetting the ash to 1020% moisture to improve handling characteristics and to mitigate the dust generated during disposal. In wet systems, the ash is mixed with water to produce a liquid slurry containing 510% solids by weight.This is discharged to settling ponds, often with bottom ash and FGD sludges, as well. The ponds may be used as the final disposal site, or the settled solids may be dredged and removed for final disposal in a landfill. Wherever feasible, decanted water from ash disposal ponds should be recycled to formulate ash slurry. Where heavy metals are pre-sent in ash residues or FGD sludges, care must be taken to monitor and treat leachates and overflows from settling ponds, in addition to disposing of them in lined places to avoid contamination of water bodies. In some cases, ash residues are being used for building materials and in road construction. Gradual reclamation of ash ponds should be practiced.

Abatement of Particulate Matter

The options for removing particulates from exhaust gases are cyclones, baghouses (fabric filters), and ESPs. Cyclones may be adequate as precleaning devices; they have an overall removal efficiency of less than 90% for all particulate matter and considerably lower for PM10. Baghouses can achieve removal efficiencies of 99.9% or better for particulate matter of all sizes, and they have the potential to enhance the removal of sulfur oxides when sorbent injection, dry-scrubbing, or spray dryer absorption systems are used. ESPs are available in a broad range of sizes for power plants and can achieve removal efficiencies of 99.9% or better for particulate matter of all sizes.

The choice between a baghouse and an ESP will depend on fuel and ash characteristics, as well as on operating and environmental factors. ESPs can be less sensitive to plant upsets than fabric filters because their operating effectiveness is not as sensitive to maximum temperatures and they have a low pressure drop. However, ESP performance can be affected by fuel characteristics. Modern baghouses can be designed to achieve very high removal efficiencies for PM10 at a capital cost that is comparable to that for ESPs, but it is necessary to ensure appropriate training of operating and maintenance staff.

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Abatement of Sulfur Oxides

The range of options and removal efficiencies for SOx controls is wide. Pre-ESP sorbent injection can remove 3070% of sulfur oxides, at a cost of US$50$100 per kW. Post-ESP sorbent injection can achieve 7090% SOx removal, at a cost of US$80$170 per kW. Wet and semidry FGD units consisting of dedicated SOx absorbers can remove 7095%, at a cost of US$80$170 per kW (1997 prices). The operating costs of most FGDs are substantial because of the power consumed (of the order of 12% of the electricity generated), the chemicals used, and disposal of residues. Estimates by the International Energy Agency (IEA) suggest that the extra levelized annual cost for adding to a coal-fired power plant an FGD designed to remove 90% of sulfur oxides amounts to 1014% depending on capacity utilization.

An integrated pollution management approach should be adopted that does not involve switching from one form of pollution to another. For example, FGD scrubber wastes, when improperly managed, can lead to contamination of the water supply, and such SOx removal systems could result in greater emissions of particulate matter from materials handling and windblown dust. This suggests the need for careful benefit-cost analysis of the types and extent of SOx abatement.

Abatement of Nitrogen Oxides

The main options for controlling NOx emissions are combustion modifications: low-NOx burners with or without overfire air or reburning, water/steam injection, and selective catalytic or noncatalytic reduction (SCR/SNCR). Combustion modifications can remove 3070% of nitrogen oxides, at a capital cost of less than US$20 per kW and a small increase in operating costs. SNCR systems can remove 3070% of nitrogen oxides, at a capital cost of US$20$40 per kW and a moderate increase in operating cost. However, plugging of the preheater because of the formation of ammonium bisulphate may pose some problems. SCR units can remove 7090% of nitrogen oxides but involve a much larger capital cost of US$40$80 per kW and a significant increase in operating costs, especially for coal-fired plants. Moreover, SCR may require lowsulfur fuels (less than 1.5% sulfur content) because the catalyst elements are sensitive to the sulfur dioxide content in the flue gas.

System Design of Supercritical Thermal Power Plants-libre

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