POWER PLANT

A power plant is an industrial facility for the generation of electric power. Power plant is also used to refer to the engine in ships, aircraft and other large vehicles. Some prefer to use the term energy center because it more accurately describes what the plants do, which is the conversion of other forms of energy, like chemical energy, gravitational potential energy or heat energy into electrical energy.

At the center of nearly all power stations is a generator, a rotating machine that converts mechanical energy into electrical energy by creating relative motion between a magnetic field and a conductor. The energy source harnessed to turn the generator varies widely. It depends chiefly on what fuels are easily available and the types of technology that the power company has access to.

Classification:

By fuel Nuclear power plants use a nuclear reactor's heat to operate a steam turbine generator. Fossil fuelled power plants may also use a steam turbine generator or in the case of natural

gas fired plants may use a combustion turbine. Geothermal power plants use steam extracted from hot underground rocks. Renewable energy plants may be fuelled by waste from sugar cane, municipal solid waste,

landfill methane, or other forms of biomass. Waste heat from industrial processes is occasionally concentrated enough to use for power

generation, usually in a steam boiler and turbine.

By prime mover Steam turbine plants use the dynamic pressure generated by expanding steam to turn the

blades of a turbine. Almost all large non-hydro plants use this system.

Gas turbine plants use the dynamic pressure from flowing gases to directly operate the turbine. Natural-gas fuelled turbine plants can start rapidly and so are used to supply "peak" energy during periods of high demand, though at higher cost than base-loaded plants. These may be comparatively small units, and sometimes completely unmanned, being remotely operated.

Combined cycle plants have both a gas turbine fired by natural gas, and a steam boiler and steam turbine which use the exhaust gas from the gas turbine to produce electricity. This greatly increases the overall efficiency of the plant, and many new base load power plants are combined cycle plants fired by natural gas.

Internal combustion Reciprocating engines are used to provide power for isolated communities and are frequently used for small cogeneration plants. Hospitals, office buildings, industrial plants, and other critical facilities also use them to provide backup power in case of a power outage. These are usually fuelled by diesel oil, heavy oil, natural gas and landfill gas.

Microturbines, Stirling engine and internal combustion reciprocating engines are low cost solutions for using opportunity fuels, such as landfill gas, digester gas from water treatment plants and waste gas from oil production.

Out of the above mentioned power plants the P.P.C.L plant is a combined cycle power plant of 330 MW capacity and it is consist of two gas turbine units each of 104 MW capacity and one steam turbine unit of 122 MW generation capacity. The complete working of P.P.C.L plant will be discussed now.

COMBINED CYCLE POWER PLANT (CCPP)

Combined cycle: A combined cycle is characteristic of a power producing engine or plant that employs more than one thermodynamic cycle. Heat engines are only able to use a portion of the energy their fuel generates (usually less than 50%). The remaining heat from combustion is generally wasted. Combining two or more "cycles" such as the Brayton cycle and Rankine cycle results in improved overall efficiency.

The combined-cycle unit combines the Rankine (steam turbine) and Brayton (gas turbine) thermodynamic cycles by using heat recovery boilers to capture the energy in the gas turbine exhaust gases for steam production in HRSG (heat recovery steam generator) and supply this steam at high pressure to steam turbine which is also coupled with an steam turbine generator that generates electricity. Thus, both steam and gas turbine generate electricity.

Fig: working of combined cycle plant.

In a combined cycle power plant (CCPP), or combined cycle gas turbine (CCGT) plant, a gas turbine generator generates electricity and the waste heat is used to make steam, to generate additional electricity via a steam turbine; this last step enhances the efficiency of electricity generation. In a thermal power plant, high-temperature heat as input to the power plant, usually from burning of fuel, is converted to electricity as one of the outputs and low-temperature heat as another output. As a rule, in order to achieve high efficiency, the temperature difference between the input and output heat levels should be as high as possible. This is achieved by combining the Rankine (steam) and Brayton (gas) thermodynamic cycles.

In a thermal power station water is the working medium. High pressure steam requires strong, bulky components. High temperatures require expensive alloys made from nickel or cobalt, rather than inexpensive steel. These alloys limit practical steam temperatures to 655 °C while the lower temperature of a steam plant is fixed by the boiling point of water. With these limits, a steam plant has a fixed upper efficiency of 35 to 42%.

An open circuit gas turbine cycle has a compressor, a combustor and a turbine. For gas turbines the amount of metal that must withstand the high temperatures and pressures is small, and lower quantities of expensive materials can be used. In this type of cycle, the input temperature to the turbine (the firing temperature), is relatively high (900 to 1,400 °C). The output temperature of the flue gas is also high (450 to 650 °C). This is therefore high enough to provide heat for a second cycle which uses steam as the working fluid; (a Rankine cycle).

In a combined cycle power plant, the heat of the gas turbine's exhaust is used to generate steam by passing it through a heat recovery steam generator (HRSG) with a live steam temperature between 420 and 580 °C. The condenser of the Rankine cycle is usually cooled by water from a lake, river, sea or cooling towers. This temperature can be as low as 15 °C.

Fig: simplified view of combined cycle power plants

Efficiency of Combined cycle plants:

By combining both gas and steam cycles, high input temperatures and low output temperatures can be achieved. The efficiency of the cycles add, because they are powered by the same fuel source. So, a combined cycle plant has a thermodynamic cycle that operates between the gas-turbine's high firing temperature and the waste heat temperature from the condensors of the steam cycle. This large range means that the Carnot efficiency of the cycle is high. The actual efficiency, while lower than this is still higher than that of either plant on its own.

The thermal efficiency of a combined cycle power plant is the net power output of the plant divided by the heating value of the fuel. If the plant produces only electricity, efficiencies of up to 60% can be achieved. In the case of combined heat and power generation, the overall efficiency can increase to 85%.

Fuel for combined cycle power plants:

Combined cycle plants are usually powered by natural gas, although fuel oil, synthesis gas or other fuels can be used. The supplementary fuel may be natural gas, fuel oil, or coal. Next generation nuclear power plants are also on the drawing board which will take advantage of the higher temperature range made available by the Brayton top cycle, as well as the increase in thermal

efficiency offered by a Rankine bottoming cycle. The P.P.C.L power plant utilize natural gas as a fuel for running gas turbines, the natural gas is supplied by GAIL (Gas Authority Of India Ltd.) through a direct pipeline.

Natural gas is a gaseous fossil fuel consisting primarily of methane but including significant quantities of ethane, propane, butane, and pentane—heavier hydrocarbons removed prior to use as a consumer fuel —as well as carbon dioxide, nitrogen, helium and hydrogen sulfide. It is found in oil fields (associated) either dissolved or isolated in natural gas fields (non associated), and in coal beds (as coalbed methane). When methane-rich gases are produced by the anaerobic decay of non-fossil organic material, these are referred to as biogas. Sources of biogas include swamps, marshes, and landfills (see landfill gas), as well as sewage sludge and manure by way of anaerobic digesters, in addition to enteric fermentation particularly in cattle.

Since natural gas is not a pure product, when non associated gas is extracted from a field under supercritical (pressure/temperature) conditions, it may partially condense upon isothermic depressurizing--an effect called retrograde condensation. The liquids thus formed may get trapped by depositing in the pores of the gas reservoir. One method to deal with this problem is to reinject dried gas free of condensate to maintain the underground pressure and to allow reevaporation and extraction of condensates.

Natural gas is often informally referred to as simply gas, especially when compared to other energy sources such as electricity. Before natural gas can be used as a fuel, it must undergo extensive processing to remove almost all materials other than methane. The by-products of that processing include ethane, propane, butanes, pentanes and higher molecular weight hydrocarbons, elemental sulfur, and sometimes helium and nitrogen.

In power sector natural gas is a major source of electricity generation through the use of gas turbines and steam turbines. Particularly high efficiencies can be achieved through combining gas turbines with a steam turbine in combined cycle mode. Natural gas burns cleaner than other fossil fuels, such as oil and coal, and produces less carbon dioxide per unit energy released. For an equivalent amount of heat, burning natural gas produces about 30% less carbon dioxide than burning petroleum and about 45% less than burning coal. Combined cycle power generation using natural gas is thus the cleanest source of power available using fossil fuels, and this technology is widely used wherever gas can be obtained at a reasonable cost. Fuel cell technology may eventually provide cleaner options for converting natural gas into electricity, but as yet it is not price-competitive.

ELEMENTS OF A COMBINED CYCLE POWER PLANT

GAS TURBINE

A gas turbine is a rotary machine, which consists of three main components - a compressor, a combustion chamber and a turbine. The air after being compressed into the compressor is heated either by directly burning fuel in it or by burning fuel externally in a heat exchanger. The heated air with or without products of combustion is expanded in a turbine resulting in work output, a substantial part, about two-thirds, of which is used to drive the compressor. The rest, about one-third, is available as useful work output. A gas turbine extracts energy from a flow of hot gas produced by combustion of gas or fuel oil in a stream of compressed air. It has an upstream air compressor (radial or axial flow) mechanically coupled to a downstream turbine and a combustion chamber in between. "Gas turbine" may also refer to just the turbine element.

Energy is released when compressed air is mixed with fuel and ignited in the combustor. The resulting gases are directed over the turbine's blades, spinning the turbine, and mechanically powering the compressor. Finally, the gases are passed through a nozzle, generating additional thrust by accelerating the hot exhaust gases by expansion back to atmospheric pressure. Energy is extracted in the form of shaft power, compressed air and thrust, in any combination, and used to power aircraft, trains, ships, electrical generators, and even tanks.

The gas turbine at P.P.C.L is of B.H.E.L model MS 9000, is a simple cycle, single shaft gas turbine with a 14 combustion chambers, reverse flow combustion system. The turbine assembly is consist of following six major sections or groups :

Air inlet section. Compressor section.

Combustion system.

Turbine section.

Exhaust section.

Support systems.

Fig: Main components of a gas turbine

Theory of operation:

Gas turbines are described thermodynamically by the Brayton cycle, in which air is compressed isentropically, combustion occurs at constant pressure, and expansion over the turbine occurs isentropically back to the starting pressure.

In practice, friction, and turbulence cause:

1. Non-isentropic compression: for a given overall pressure ratio, the compressor delivery temperature is higher than ideal.

2. Non-isentropic expansion: although the turbine temperature drop necessary to drive the compressor is unaffected, the associated pressure ratio is greater, which decreases the expansion available to provide useful work.

3. Pressure losses in the air intake, combustor and exhaust: reduces the expansion available to provide useful work.

As with all cyclic heat engines, higher combustion temperature means greater efficiency. The limiting factor is the ability of the steel, nickel, ceramic, or other materials that make up the engine to withstand heat and pressure. Considerable engineering goes into keeping the turbine parts cool. Most turbines also try to recover exhaust heat, which otherwise is wasted energy. Recuperators are heat exchangers that pass exhaust heat to the compressed air, prior to combustion. Combined cycle designs pass waste heat to steam turbine systems. And combined heat and power (co-generation) uses waste heat for hot water production. Mechanically, gas turbines can be considerably less complex than internal combustion piston engines. Simple turbines might have one moving part: the shaft/compressor/turbine/alternative-rotor assembly (see image above), not counting the fuel system.

More sophisticated turbines (such as those found in modern jet engines) may have multiple shafts (spools), hundreds of turbine blades, movable stator blades, and a vast system of complex piping, combustors and heat exchangers. As a general rule, the smaller the engine the higher the rotation rate of the shaft(s) needs to be to maintain tip speed. Turbine blade tip speed determines the maximum pressure that can be gained, independent of the size of the engine. Jet engines operate around 10,000 rpm and micro turbines around 100,000 rpm. Thrust bearings and journal bearings are a critical part of design. Traditionally, they have been hydrodynamic oil bearings, or oil-cooled ball bearings. This is giving way to foil bearings, which have been successfully used in micro turbines and auxiliary power units.

Brayton cycle:

The 'Brayton cycle' is a constant-pressure cycle that describes the workings of the gas turbines, basis of the jet engine and others. It is also sometimes known as the Joule cycle. The Ericsson cycle is also similar but uses external heat and incorporates the use of a regenerator.

A Brayton-type engine consists of three components:

A gas compressor A mixing chamber An expander

In the original 19th-century Brayton engine, ambient air is drawn into a piston compressor, where it is compressed; ideally an isentropic process. The compressed air then runs through a mixing chamber where fuel is added, a constant-pressure isobaric process. The heated (by compression), pressurized air and fuel mixture is then ignited in an expansion cylinder and energy is released, causing the heated air and combustion products to expand through a piston/cylinder; another theoretically isentropic process. Some of the work extracted by the piston/cylinder is used to drive the compressor through a crankshaft arrangement.

The term Brayton cycle has more recently been applied to the gas turbines. This also has three components:

A gas compressor A burner (or combustion chamber) An expansion turbine

Ideal Brayton cycle:

Isentropic process (1-2) - Ambient air is drawn into the compressor, where it is pressurized. Isobaric process (2-3) - The compressed air then runs through a combustion chamber, where

fuel is burned, heating that air—a constant-pressure process, since the chamber is open to flow in and out.

Isentropic process (3-4) - The heated, pressurized air then gives up its energy, expanding through a turbine (or series of turbines). Some of the work extracted by the turbine is used to drive the compressor.

Isobaric process (4-1) - Heat Rejection (in the atmosphere).

Actual Brayton cycle:

Since there are always some heat and other losses, so as a result the actual cycle differs from ideal cycle. In the actual brayton cycle the various processes are:

Adiabatic process (1-2) - Compression. Isobaric process (2-3) - Heat Addition. Adiabatic process (3-4) - Expansion. Isobaric process (4-1) - Heat Rejection.

Since neither the compression nor the expansion can be truly isentropic, losses through the compressor and the expander represent sources of inescapable working inefficiencies. In general, increasing the compression ratio is the most direct way to increase the overall power output of a Brayton system.

Methods to increase power:

The power output of a Brayton engine can be improved in the following manners:

Reheat, wherein the working fluid—in most cases air—expands through a series of turbines, then is passed through a second combustion chamber before expanding to ambient pressure through a final set of turbines. This has the advantage of increasing the power output possible for a given compression ratio without exceeding any metallurgical constraints (typically about 1000°C). The use of an afterburner for jet aircraft engines can also be referred to as reheat, it is a different process in that the reheated air is expanded through a thrust nozzle rather than a turbine. The metallurgical constraints are somewhat alleviated enabling much higher reheat temperatures (about 2000°C). The use of reheat is most often used to improve the specific power (per through put of air) and is usually associated with a reduction in efficiency, this is most pronounced with the use of after burners due to the extreme amounts of extra fuel used.

Methods to improve efficiency:

The efficiency of a Brayton engine can be improved in the following manners:

Intercooling, wherein the working fluid passes through a first stage of compressors, then a cooler, then a second stage of compressors before entering the combustion chamber. While this requires an increase in the fuel consumption of the combustion chamber, this allows for a reduction in the specific volume of the fluid entering the second stage of compressors, with an attendant decrease in the amount of work needed for the compression stage overall. There is also an increase in the maximum feasible pressure ratio due to reduced compressor discharge temperature for a given amount of compression, improving overall efficiency.

Regeneration, wherein the still-warm post-turbine fluid is passed through a heat exchanger to pre-heat the fluid just entering the combustion chamber. This directly offsets fuel consumption for the same operating conditions improving efficiency. It allows also results in less power lost as waste heat.

A Brayton engine also forms half of the combined cycle system, which combines with a Rankine engine to further increase overall efficiency.

Cogeneration systems make use of the waste heat from Brayton engines, typically for hot water production or space heating.

Gas path description:

When the turbine starting system is actuated and the clutch is engaged, ambient air is drawn through the air inlet plenum assembly, filtered and compressed in the 17 stage axial flow compressor. For pulsation protection during startup, the eleventh stage extraction valves are open and the variable inlet guide vanes are in closed position. At high speed, the eleventh stage extraction bleed valve closes automatically and the variable inlet guide vane actuator energizes to open the inlet guide vanes to the normal turbine operating position. Compressed air from the compressor flows into the annular space surrounding the 14 combustion chambers. From there, it flows into the combustion liners and enters the combustion zone through metering holes in each of the combustion liners for proper fuel combustion. Fuel from an off base source is provided to 14 equal flow lines, each

terminating at a fuel nozzle centered in the end plate of a separate combustion chamber. Prior to being distributed to the nozzles, the fuel is accurately controlled to provide an equal flow into the nozzle feed lines at a rate consistent with the speed and load requirement of the gas turbine. The nozzle introduces the fuel in to the combustion chambers where it mixes with the combustion air and is ignited by one or both of spark plugs.

At the instant when fuel is ignited in one combustion chamber, flame is propagated through the connecting crossfire tubes to all, other combustion chambers. After the turbine rotor approximates operating speed combustion chamber pressure causes the spark plugs to retract to remove their electrodes from the hot flame zone. The hot gases from the combustion chamber expands into 14 separate transition pieces attached to the aft end (turbine end) of the combustion chamber liners and flow from there to the three stage turbine section of the machine. Each stage consists of a row of fixed nozzles followed by a row of routable turbine buckets.

In each nozzle row, the kinetic energy of the jet is increased, with an associated pressure drop and in each following row of moving buckets a portion of the kinetic energy of the jet turns the turbine rotor, resultant rotation is used to turn the generator rotor and generate electrical power.

After passing through the third stage buckets the gases are directed into the exhaust hood and diffuser which contains a series of turning vanes to turn the gases from an axial direction to a radial direction thereby minimizing exhaust hood losses. The gases then pass into the exhaust plenum and are introduced to atmosphere through the exhaust stack.

Constructional features:

Fig: A simplified representation of gas turbine

A gas turbine can be broadly divided into three parts i.e. compressor section, combustion system and turbine section these are discussed below:

1) Compressor Section:

The compressor is that section of the turbine assembly that draws in atmospheric air, compresses it and supplies it at high pressure to the combustion system. It is made up of rotating and stationary vane assemblies, the gas turbine at P.P.C.L has 17 stages of rotor and stator blading. The first stage compressor rotor blades accelerate the air rearward into the first stage vane assemblies. The first stage vane assemblies slow the air down and direct it into the second stage compressor rotor blades. The second stage compressor rotor blades accelerate the air rearward into the second stage vane assemblies, and so on. The compressor rotor may be thought of as an air pump the volume of air pumped by the compressor rotor is basically proportional to the rotor rpm. However, air density, the weight of a given volume of air, also varies this proportional relationship. The weight

per unit volume of air is affected by temperature, compressor air inlet pressure, humidity and free stream air pressure provided by the forward motion of the engine and if compressor air inlet temperature is increased, air density is reduced. If compressor air inlet pressure is increased, air density is increased. If humidity increases, air density is decreased. Humidity, by comparison with temperature, and pressure changes, has a very small effect on density. With increased forward speed, free stream air pressure provided by the forward motion of the engine increases and air temperature and pressure increase.

The compressors can be classified as:

1) Radial/centrifugal flow compressor.2) Axial flow compressors.

Radial/centrifugal compressor:

The basic components of a centrifugal-flow compressor are rotor, stator, and compressor manifold.

Fig: Typical Single-stage Centrifugal Compressor

As the impeller (rotor) revolves at high speed, air is drawn into the blades near the center. Centrifugal force accelerates this air and causes it to move outward from the axis of rotation toward the rim of the rotor where it is forced through the diffuser section at high velocity and high kinetic energy. The pressure rise is produced by reducing the velocity of the air in the diffuser, thereby converting velocity energy to pressure energy. The centrifugal compressor is capable of a relatively high compression ratio per stage. This compressor is not used on larger engines because of size and weight.

Because of the high tip speed problem in this design, the centrifugal compressor finds its greatest use on the smaller engines where simplicity, flexibility of operation, and ruggedness are the principal requirements rather than small frontal area and ability to handle high airflows and pressures with low loss of efficiency.

Axial flow compressor:

The air is compressed, as the name implies, in a direction parallel to the axis of the engine. The compressor is made of a series of rotating airfoils called rotor blades, and a stationary set of airfoils called stator vanes. A stage consists of two rows of blades, one rotating and one stationary. The entire compressor is made up of a series of alternating rotor and stator vane stages.

The turbine at P.P.C.L has a axial flow compressor. The above fig shows the rotor, stator and their assembly from left to right respectively. Axial flow compressors have the advantage of being capable of very high compression ratios with relatively high efficiencies, Because of the small frontal area created by this type of compressor, it is ideal for installation on high-speed aircraft. Unfortunately, the delicate blading and close tolerances, especially toward the rear of the compressor where the blades are smaller and more numerous per stage, make this compressor highly susceptible to foreign-object damage. Because of the close fits required for efficient air-pumping and higher compression ratios, this type of compressor is very complex and very expensive to manufacture. For these reasons the axial-flow design finds its greatest application where required efficiency and

output override the considerations of cost, simplicity, and flexibility of operation. To ensure maximum efficiency and allow for flexibility, compressor can be split into HP & LP sections also inlet vanes/nozzle angles can be varied to control air flow. The air inside the compressor section can be divided into three parts:

• 1) Primary Air (30%) - Passes directly to combustor for combustion process.• 2) Secondary Air (65%) - Passes through holes in perforated inner shell & mixes with

combustion gases

• 3) Film Cooling Air (5%) - Insulates/cools turbine blades

2) Combustion system:

In combustion system high pressure air from the compressor is mixed with fuel and the combustible mixture is ignited by spark plugs. The combustion system contains the combustion chambers, igniter plugs, and fuel nozzle or fuel injectors. It is designed to burn a fuel-air mixture and

to deliver combusted gases to the turbine at a temperature not exceeding the allowable limit at the turbine inlet. Theoretically, the compressor delivers 100 percent of its air by volume to the combustion chamber. However, the fuel-air mixture has a ratio of l5 parts air to 1 part fuel by weight. Approximately 25 percent of this air is used to attain the desired fuel-air ratio. The remaining 75 percent is used to form an air blanket around the burning gases and to dilute the temperature, which may reach as high as 3500º F, by approximately one-half. This ensures that the turbine section will not be destroyed by excessive heat.

The air used for burning is known as primary air; that used for cording is secondary air. Secondary air is controlled and directed by holes and louvers in the combustion chamber liner. Igniter plugs function during starting only; they are shut off manually or automatically. Combustion is continuous and self-supporting. After engine shutdown or failure to start, a pressure-actuated valve automatically drains any remaining unburned fuel from the combustion chamber.

The primary function of the combustion system is to burn the fuel-air mixture, thereby adding heat energy to the air. To do this efficiently, the combustion chamber must--

Provide the means for mixing the fuel and air to ensure good combustion. Bum this mixture efficiently. Cool the hot combustion products to a temperature which the turbine blades can withstand

under operating conditions. Deliver the hot gases to the turbine section. The location of the combustion section is directly between the compressor and turbine

sections. The combustion chambers are always arranged coaxially with the compressor and turbine, regardless of type, since the chambers must be in a through-flow position to function efficiently.

All combustion chambers contain the same basic elements:

A casing A perforated inner liner. A fuel injection system. Some means for initial ignition. A fuel drainage system to drain off unburned fuel after engine shutdown. There are currently three basic types of combustion chambers, varying in detail only:

The multiple-chamber or can type. The annular or basket type. The can-annular type.

Following are some common types of combustion chambers out of these the can annular type combustion chamber is used in the turbines at P.P.C.L:

1) Annular Type:

The annular-type combustion chamber is used in engines of the axial-centrifugal-flow compressor design. The annular combustion chamber permits building an engine of a small and compact design. Instead of individual combustion chambers, the primary compressed air is

introduced into an annular space formed by a chamber liner around the turbine assembly. A space is left between the outer liner wall and the combustion chamber housing to permit the flow of secondary cooling air from the compressor. Primary air is mixed with the fuel for combustion. Secondary (cooling) air reduces the temperature of the hot gases entering the turbine to the proper level by forming a blanket of cool air around these hot gases.

1. ANNULAR TYPE COMBUSTION CHAMBER LINER2. COMBUSTION CHAMBER HOUSING ASSEMBLY

Fig: Annular-type Combustion Chamber.

The annular combustion chamber offers the advantages of a larger combustion volume per unit of exposed area and material weight, a smaller exposed area resulting in lower pressure losses through the unit, and less weight and complete pressure equalization.

2) Can-Type:

The can-type combustion chamber is one made up of individual combustion chambers. This type of combustion chamber is so arranged that air from the compressor enters each individual chamber through the adapter. Each individual chamber is composed of two cylindrical tubes, the combustion chamber liner and the outer combustion chamber, shown in figure 1.19. Combustion takes place within the liner. Airflow into the combustion area is controlled by small louvers located in the inner dome, and by round holes and elongated louvers along the length of the liner. Airflow into the combustion area is controlled by small louvers located in the inner dome, and by round holes elongated louvers along the length of the liner.

Through these openings flows the air that is used in combustion and cooling. This air also prevents carbon deposits from forming on the inside of the liner. This is important, because carbon deposits can block critical air passages and disrupt airflow along the liner walls causing high metal temperatures and short burner life.Ignition is accomplished during the starting cycle. The igniter plug is located in the combustion liner adjacent to the start fuel nozzle. Each can-type combustion

chamber consists of an outer case or housing with a perforated stainless steel (highly heat-resistant) combustion chamber liner or inner liner . The outer case is divided for ease of liner replacement. The larger section or chamber body encases the liner at the exit end; the Smaller chamber cover encases the front or inlet end of the liner.

The interconnector (flame propagation) tubes area necessary part of can-type combustion chambers. Since each can is a separate burner operating independently of the others, there must be some way to spread combustion during the initial starting operation. This is done by interconnecting all the chambers. The flame is started by the spark igniter plugs in two of the lower chambers; it passes through the tubes and ignites the combustible mixture in the adjacent chamber. This continues until all chambers are burning. The flame tubes will vary in construction details from one engine to another although the basic components are almost identical. The chambers be interconnected by an outer tube (in this case, a ferrule), but there must also be a slightly longer tube inside the outer one to interconnect the chamber liners where the flame is located The outer tubes or jackets around the interconnecting flame tubes not only afford airflow between the chambers but also fulfill an insulating function around the hot flame tubes. The spark igniters are normally two in number. They are located in two of the can-type combustion chambers.

Another very important requirement in the construction of combustion chambers is providing the means for draining unburned fuel. This drainage prevents gum deposits in the fuel manifold, nozzles, and combustion chambers. These deposits are caused by the residue left when fuel evaporates. If fuel is allowed to accumulate after shutdown there is the danger of after fire.

If the fuel is not drained, a great possibility exists that at the next starting attempt excess fuel in the combustion chamber will ignite and tailpipe temperature will go beyond safe operating limits. The liners of can-type combustors have perforations of various sizes and shapes, each hole having a specific purpose and effect on flame propagation in the liner. Air entering the combustion chamber is divided by holes, louvers, and slots into two main streams -- primary and secondary air. Primary

(combustion) air is directed inside the liner at the front end where it mixes with the fuel and bums. Secondary (cooling) air passes between the outer casing and the liner and joins the combustion gases through larger holes toward the rear of the liner, cooling the combustion gases from about 3500º F to near 1500º F. Holes around the fuel nozzle in the dome or inlet end of the can-type combustor liner aid in atomization of the fuel. Louvers are also provided along the axial length of the liners to direct a cooling layer of air along the inside wall of the liner. This layer of air also tends to control the flame pattern by keeping it centered in the liner, preventing burning of the liner walls.

3) Can-Annular type:

This combustion chamber uses characteristics of both annular and can-type combustion chambers. The can-annular combustion chamber consists of an outer shell, with a number of individual cylindrical liners mounted about the engine axis. There are 14 combustion chambers and all of them are completely surrounded by the airflow that enters the liners through various holes and louvers.

Fig: Can-Annular Combustion Chamber

This air is mixed with fuel which has been sprayed under pressure from the fuel nozzles. The fuel-air mixture is ignited by igniter plugs, and the flame is then carried through the crossover tubes to the remaining liners. The inner casing assembly is both a support and a heat shield; also, oil lines run through it.

3) Turbine section:

In the turbine section of the gas turbine the hot gases at high velocity and pressure expand through the 14 separate transition pieces attached to the aft end (turbine end) of the combustion chamber liners and flow from there to the three stage turbine section of the machine. Each stage consists of a row of fixed nozzles followed by a row of routable turbine buckets.

Turbines, like compressors, consist of stator and rotor elements. Stators prepare the mass flow for harnessing of power through the turbine rotor. The nozzles take the high pressure, high-

energy mixture and draw the kinetic energy for driving the rotor. In each nozzle row, the kinetic energy of the jet is increased, with an associated pressure drop and in each following row of moving buckets a portion of the kinetic energy of the jet turns the turbine rotor, resultant rotation is used to turn the generator rotor and generate electrical power.

The turbine section consists of two basic elements: the stator or nozzle and the rotor. The  rotor element  of  the  turbine  consists  of a  shaft  and  bladed  wheel(s).  The wheel(s)  are attached to the main power transmitting shaft of the gas turbine. The  jets  of  combustion gas  leaving  the vanes  of  the  stator  element  act upon  the  turbine  blades  and  cause  the  turbine wheel to rotate in a speed range of 3,600 to 42,000 rpm,  

Fig: Stator of turbine section

depending upon the type of engine. The high rotational speed imposes severe centrifugal loads on the turbine wheel. At the same time, the high temperature (1050° to 2300  °F)  results  in  a lowering of   the   strength   of   the   material. Consequently, the engine speed and temperature must be controlled to keep turbine operation within safe limits.

Fig: Rotor of turbine section

 The operating life of the turbine blading usually determines the life of the gas turbine engine. The turbine wheel is a dynamically balanced unit consisting of blades attached to a rotating disk.  The disk,  in  turn,  is  attached  to  the  rotor shaft  of  the  engine.  The high-velocity exhaust gases leaving the turbine nozzle vanes act on the blades of the turbine wheel.  This causes the assembly to rotate at a high rate of speed. This turbine rotation, in turn, causes the compressor to rotate.

Turbine buckets or blades:

The turbine blades or buckets are one of the important element of gas turbines, they are the primary elements that transfer the energy from the combustion exhaust gases to the shaft of the turbine, which results in high speed rotation and development of power. The blades must be able to withstand high impacts and temperatures, corrosion, metal fatigue and they must be inspected regularly because the overall efficiency of the gas turbine depends upon the efficient operation of the blades. The blades or buckets are attached to the rotor by means of dovetail joints and can be easily detached. The material for blades varies with stages, for ex. The first stage blading which are subjected to highest temperatures are generally made of cobalt based alloys and for the latter stages nickel based alloys may be used. To protect the blades from corrosion, oxidation, mechanical property degradation the blades are sometimes coated with platinum alumunide.

Auxiliary components of gas turbine:

Gas turbine starter – The gas turbine requires a starting mechanism to spin the main shaft initially, and once the turbine reaches its rated speed this mechanism detaches automatically. This starting process normally uses an electric motor to spin the main turbine shaft. The motor is bolted to the outside of the engine and uses a shaft and gears to connect to the main shaft. The electric motor spins the main shaft until there is enough air blowing through the compressor and the combustion chamber to light the turbine. Fuel starts flowing and an igniter similar to a spark plug ignites the fuel. Then fuel flow is increased to spin the engine up to its operating speed.

Inlet air filters – The air supplied to the gas turbine must be cleaned and conditioned thoroughly and no impurities, dust and corrosive chemicals should be present in it. For this purpose the atmospheric air is passed through air filter house that contains a number of small cylindrical filters.

Air filters Air filter house

After this the air is passed through fin fan air coolers and air washer system for controlling the temperature and than to the turbine.

Fin-fan air coolers – Gas turbines operate with a constant volume of air flow, but the power they generate is determined by the mass flow of air. As a result, the denser the air is when it flows through the turbine, the greater that the output power will be. Warm air is less dense than cold air, and therefore gives a lower power output. In addition, warm air is harder to compress than cold air, thus requiring greater work from the compressor, leaving less net available shaft energy.

A fin fan cooler

The power boost that can be achieved at a typically hot and dry site through air inlet cooling can be as much as 15 per cent. Cooling the inlet air to the gas turbine enables greater mass to be delivered by the compressor, and hence enable the turbine to provide a greater power output. For a typical gas turbine, an increase of inlet air temperature from 59°F to 100°F decreases power output to about 73 percent of its rated capacity. If the inlet air is cooled to 42°F, the power generation capacity of the gas turbine will be increased to 110 per cent of the rated capacity. Thus, if the inlet air is cooled from 100°F to 42°F, the power output of a gas turbine would be increased from 73 per cent to 110 per cent of the rated capacity, a boost of about 50per cent. In a fin fan air cooler there are fans that create flow of cool air around the pipes carrying hot air and thus take away the hotness of the air.

BENEFITS OF TURBINE AIR INLET COOLING:

When the ambient temperature of air is above 59°F, the benefits of turbine inlet air cooling include the following:

1) Increased power output.

2) Reduced capital cost per unit of power plant output capacity.

3) Increased fuel efficiency.

4) Increased steam output in cogeneration.

5) Increased power output of steam turbine in combined cycle plant.

STEAM TURBINE

Introduction:

A steam turbine is a mechanical device that extracts thermal energy from pressurized steam, and converts it into useful mechanical work. The available heat energy of the steam first is converted into kinetic energy by the expansion of the steam in suitably shaped passage, or nozzle, form which it issues as a jet, at a proper angle, against curved blades mounted on a revolving disk or cylinder and by the reaction of the jet itself as it leaves the curved passage. The pressure on the blades, causing rotary motion, is solely due to the change of momentum of the steam jet during its passage through these blades.

The steam energy is converted mechanical work by expansion through the turbine.   The expansion takes place through a series of fixed blades (nozzles) and moving blades each row of fixed blades and moving blades is called a stage. The moving blades rotate on the central turbine rotor and the fixed blades are concentrically arranged within the circular turbine casing which is substantially designed to withstand the steam pressure. On large output turbines the duty too large for one turbine and a number of turbine casing/rotor units are combined to achieve the duty.  These are generally

arranged on a common centre line (tandem mounted) but parallel systems can be used called cross compound systems.

Energy in the steam after it leaves the boiler is converted into rotational energy as it passes through the turbine. The turbine normally consists of several stages with each stage consisting of a stationary blade (or nozzle) and a rotating blade. Stationary blades convert the potential energy of the steam (temperature and pressure) into kinetic energy (velocity) and direct the flow onto the rotating blades. The rotating blades convert the kinetic energy into forces, caused by pressure drop, which results in the rotation of the turbine shaft. The turbine shaft is connected to a generator, which produces the electrical energy. The rotational speed is near to 3000 rpm for generating electricity at 50 Hz.

Working cycle:

The steam turbine works on rankine cycle, the Rankine cycle is a thermodynamic cycle which converts heat into work. The heat is supplied externally to a closed loop, which usually uses steam as the working fluid. A Rankine cycle describes a model of the operation of steam heat engines most commonly found in power generation plants. Common heat sources for power plants using the Rankine cycle are coal, natural gas, oil, and nuclear.

The Rankine cycle is sometimes referred to as a practical Carnot cycle as, when an efficient turbine is used, the TS diagram will begin to resemble the Carnot cycle. The main difference is that a pump is used to pressurize liquid instead of gas. This requires about 100 times less energy than that compressing a gas in a compressor (as in the Carnot cycle).

The efficiency of a Rankine cycle is usually limited by the working fluid. Without the pressure going super critical the temperature range the cycle can operate over is quite small, turbine entry temperatures are typically 565°C (the creep limit of stainless steel) and condenser temperatures are around 30°C. This gives a theoretical Carnot efficiency of around 63% compared with an actual efficiency of 42% for a modern coal-fired power station. This low turbine entry temperature (compared with a gas turbine) is why the Rankine cycle is often used as a bottoming cycle in combined cycle gas turbine power stations.

The working fluid in a Rankine cycle follows a closed loop and is re-used constantly. The water vapor often seen billowing from power stations is generated by the cooling systems (not from the closed loop Rankine power cycle) and represents the waste heat that could not be converted to useful work. Note that steam is invisible until it comes in contact with cool, saturated air, at which point it condenses and forms the white billowy clouds, seen leaving cooling towers. While many substances could be used in the Rankine cycle, water is usually the fluid of choice due to its favorable properties, such as nontoxic and unreactive chemistry, abundance, and low cost, as well as its thermodynamic properties.

One of the principal advantages it holds over other cycles is that during the compression stage relatively little work is required to drive the pump, due to the working fluid being in its liquid phase at this point. By condensing the fluid to liquid, the work required by the pump will only consume approximately 1% to 3% of the turbine power and so give a much higher efficiency for a real cycle. The benefit of this is lost somewhat due to the lower heat addition temperature. Gas turbines, for instance, have turbine entry temperatures approaching 1500°C. Nonetheless, the efficiencies of steam cycles and gas turbines are fairly well matched.

Processes in rankine cycle:

Fig: Ts diagram of a typical Rankine cycle operating between pressures of 0.06bar and 50bar

There are four processes in the Rankine cycle, each changing the state of the working fluid. These states are identified by number in the diagram to the right.

Process 1-2: The working fluid is pumped from low to high pressure, as the fluid is a liquid at this stage the pump requires little input energy.

Process 2-3: The high pressure liquid enters a boiler where it is heated at constant pressure by an external heat source to become a dry saturated vapor.

Process 3-4: The dry saturated vapor expands through a turbine, generating power. This decreases the temperature and pressure of the vapor, and some condensation may occur.

Process 4-1: The wet vapor then enters a condenser where it is cooled at a constant pressure and temperature to become a saturated liquid. The pressure and temperature of the condenser is fixed by the temperature of the cooling coils as the fluid is undergoing a phase-change.

In an ideal Rankine cycle the pump and turbine would be isentropic, i.e., the pump and turbine would generate no entropy and hence maximize the net work output. Processes 1-2 and 3-4 would be represented by vertical lines on the Ts diagram and more closely resemble that of the Carnot cycle. The Rankine cycle shown here prevents the vapor ending up in the superheat region after the expansion in the turbine, which reduces the energy removed by the condensers.

Constructional features:

The steam turbine at P.P.C.L has a tandem compound shaft arrangement with H.P and L.P sections. The H.P section is a single flow turbine where as the L.P section is double flow. The individual turbine rotors and generator rotors are connected by rigid couplings. The H.P turbine has been constructed for throttle control governing. The initial steam is admitted before the blading by two combined main steam stop and control valves.

The steam from H.P turbine exhaust is led to the L.P turbine through cross around pipes. Additional steam from L.P stage of waste heat recovery steam generator is passed to the L.P turbine via two combined L.P stop and control valve. Following are some important components and systems of the steam turbine:

1) H.P turbine:

The H.P turbine is of single flow, double shell construction with horizontally split casings allowance is made for thermal movement of the inner casing within the outer casing. The main steam enters the inner casing from top and bottom.

2) L.P turbine:

The casing of the double flow L.P turbine is of three shell design. The shells are of horizontally split welded construction. The inner casing which carries the first rows of stationary blades is supported on the outer casing so as to allow for thermal expansion.

3) Blading:

The entire turbine is provided with reaction blading. The moving blades of H.P turbine and the initial rows of L.P turbine with inverted T roots and integral shrouding are machined from solid rectangular bars. The last stages of the L.P turbine consists of twisted, drop forged moving blades with roots inserted in corresponding grooves of the rotor.

4) Bearings:

A thrust bearing A tilting pad journal bearing

The H.P rotor is supported on two bearings a combined journal and thrust bearing at its front and a journal bearing close to the coupling with L.P motor. The L.P rotor has a journal bearing at its end. The combined journal and thrust bearing takes up residual thrust from both directions. The rotor of every turbine must be positioned radially and axially by bearings. Radial bearings carry and support the weight of the rotor and maintain the correct radial clearance between the rotor and casing. Axial (thrust) bearings limit the fore-and-aft travel of the rotor. Thrust bearings take care of any axial thrust, which may develop on a turbine rotor and hold the turbine rotor within definite axial positions. All main turbines and most auxiliary units have a bearing at each end of the rotor

5) Shaft gland and interstage sealing:

The shaft gland seals the steam inside the cylinders against atmosphere and the interstage seals restrict leakage at blade tip. Shaft packing glands prevent the leaking of steam out of or air into

the turbine casing where the turbine rotor shaft extends through the turbine casing. Labyrinth and carbon rings are two types of packing. They are used either separately or in combination.

Labyrinth packing consists of rows of metallic strips or fins. The strips fasten to the gland liner so there is a small space between the strips and the shaft. As the steam from the turbine casing leaks through the small space between the packing strips and the shaft, steam pressure gradually reduces.

Fig: Carbon packing gland.

Carbon packing rings restrict the passage of steam along the shaft in much the same manner as labyrinth packing strips. Carbon packing rings mount around the shaft and are held in place by springs. Three or four carbon rings are usually used in each gland. Each ring fits into a separate compartment of the gland housing and consists of two, three, or four segments that are butt-jointed to each other. A garter spring is used to hold these segments together. The use of keepers (lugs or stop pins) prevents the rotation of the carbon rings when the shaft rotates. The outer carbon ring compartment connects to a drain line.

6) Valves:

Steam enters the turbine from the HRSG into a series of valves. These valves are controlled by the governor with regulates the amount of steam passing through the turbine in order to maintain the constant speed required to generate power at 50 cycles per second.

The H.P turbine is fitted with two main stop and control valves. One main stop and control valve with stems arranged at right angles to each other are combined in a common body. These valves combinations are located at both sides of the H.P turbine and are connected to the H.P cylinder at the top and bottom by two steam admission pipes. The valves are operated by individual hydraulic valve actuators. The main stop valves are spring action single seat valves, the control valves are also of single seat design, and have diffusers to reduce pressure losses.

The L.P turbine has two induction steams stop and control valves. These valves combinations are also located in an easily accessible position at both sides of the L.P turbine, are operated by hydraulic valve actuators.

7) Turbine governing system:

The turbine has an electro-hydraulic governing system backed up with a hydraulic governing system. An electric system measures and controls speed, output and operate the control valves hydraulically in conjunction with an electro-hydraulic converter. The electro-hydraulic governing system permits run-up control of the turbine up to the rated speed.

8) Turbine monitoring system:

In addition to the measuring instruments and instruments indicating pressures, temperatures, valves positions and speed, the monitoring system also includes measuring instruments and indicators for the following values:

Differential expansion between the shafting and turbine casing. Bearing pedestal vibrations, measured at all turbine bearings.

Relative shaft vibrations measured at all bearings.

Technical specification:

H.P turbine : Single flow with 28 reaction stages.

L.P turbine : Double flow with 8 reaction stages.

Main stop and control valves : 2

L.P stop and control valves : 2

Speed:-

Rated Speed : 50.0/s

Max. Speed no time limitation : 51.5/s

Min speed no time limitation : 47.5/s

Steam pressure table:

Steam pressure at Rated (bar) Long time operation (bar)

Short time operation (bar)

Initial steam 71.38 83.5 97.25

Ahead of first H.P drum stage

66.9 77.6 77.6

At first cylinder exhaust

5.23 6.2 6.2

At inlet to induction steam valve

5.31 6.2 1.2

At inlet to second cylinder

5.14 6.16 6.16

At second cylinder exhaust

0.099 0.3 0.3

Steam temperature table:

Steam temperature at Rated value (deg. c) Long time value (deg. c)

Initial steam 518.3 526.2

At inlet to L.P steam valve 198.6 206.6

At first cylinder exhaust 187.2 214.2

At second cylinder inlet 188.6 216.2

At second cylinder exhaust 45.6 70

Vibrations table:

vibrations Absolute bearing housing vibration

Absolute shaft vibration

Standard alarm setting 35μm 30μm

Maximum alarm setting 35μm 120μm

Limit values for tripping 45μm 200μm

HEAT RECOVERY STEAM GENERATOR (HRSG)

A heat recovery steam generator or HRSG is a heat exchanger that recovers heat from a hot gas stream. It produces steam that can be used in a process or used to drive a steam turbine. A common application for an HRSG is in a combined-cycle power station, where hot exhaust from a gas turbine is fed to an HRSG to generate steam which in turn drives a steam turbine. This combination produces electricity more efficiently than either the gas turbine or steam turbine alone. Another application for an HRSG is in diesel engine combined cycle power plants, where hot exhaust from a diesel engine is fed to an HRSG to generate steam which in turn drives a steam turbine. The HRSG is also an important component in cogeneration plants. Cogeneration plants typically have a higher overall efficiency in comparison to a combined cycle plant. This is due to the loss of energy associated with the steam turbine.

HRSG is consist of three major components. They are the Evaporator, Superheater, and Economizer. The different components are put together to meet the operating requirements of the unit. Based on the flow of exhaust gases, HRSGs are categorized into vertical and horizontal types. In vertical type HRSGs, exhaust gas flows horizontally over vertical tubes whereas in horizontal type HRSGs, exhaust gas flow vertically over horizontal tubes. Based on pressure levels, HRSGs can be categorized into single pressure and multi pressure. Single pressure HRSGs have only one steam drum and steam is generated at single pressure level whereas multi pressure HRSGs employ two (double pressure) or three (triple pressure) steam drums. As such triple pressure HRSGs consist of three sections: an LP (low pressure) section, a reheat/IP (intermediate pressure) section, and an HP (high pressure) section. Each section has a steam drum and an evaporator section where water is converted to steam. This steam then passes through superheaters to raise the temperature and pressure past the saturation point.

The heat recovery steam generator at P.P.C.L is a horizontal, natural circulation, single drum, dual pressure, unfired water tube boiler. It is designed to generate steam quantities as furnished in operating parameters at main steam stop valve under specified modes of operation. Feed water temperature is 151.7˚c for H.P section and 150.1˚c for L.P section at the design point. It is consist of the following main components:

1) H.P superheater and components:

A superheater is a device in a HRSG that heats the steam generated again, increasing its thermal energy and decreasing the likelihood that it will condense inside the steam turbine. Superheaters increase the efficiency of the whole system, and are widely adopted. Steam which has been superheated is logically known as superheated steam; non-superheated steam is called saturated steam or wet steam. H.P superheater is the first heat transfer surface arranged in the direction of gas flow. H.P superheater is constructed of modules consisting of finned tubes welded to the top and bottom headers two rows maximum per module. The H.P superheater is designed for single pass flow on the gas side and on the tube side. Interconnection of modules will be by multiple 180 degrees bent tubes of similar material as header. The H.P superheater modules are equipped with low point 1 inches drain for a fully drainable design. The H.P superheater outlet is equipped with a vent for start up.

2) H.P evaporator:

An evaporator changes liquids into gaseous state. For instance, water is heated and changed into steam. Therefore, it is the opposite of a condenser. H.P evaporator is the second heat transfer surface arranged in the direction of the gas flow. In the circulation system, the heated feed water from H.P economizer goes to the steam drum. The boiler water from the steam drum flows to the common feed headers through large down corners and is distributed to the bottom headers of the evaporator through the individual feeders. Steam water mixture generated in the evaporator tubes due to the heat transfer from the gas turbine exhaust, flows back to the drum through the riser tubes. The saturated steam is separated by centrifugal separator and final scrubbers placed inside the drum.

3) H.P economizer:

Economizers are mechanical devices intended to reduce energy consumption, or to perform another useful function like preheating a fluid. The term economizer is used for other purposes as well. Boiler, power plant, and heating, ventilating, and air-conditioning (HVAC) uses are discussed in this article. In simple terms, an economizer is a heat exchanger.

H.P economizer 2 is the third and H.P economizer 1 is the sixth heat transfer surface. The H.P economizer is constructed of modules, consisting of spiral finned tubes welded to the top and bottom headers, two rows per module. The H.P economizer is designed for single pass flow on the gas side and multipass flow on the tube side.

4) L.P superheater:

L.P superheater is the fourth heat transfer surface arranged in the direction of the gas flow. L.P superheater is constructed of a module consisting of finned tubes, welded to top and bottom headers single row module. The L.P superheater is designed for single pass flow on the gas side and on the tube side.

5) L.P evaporator:

It is fifth heat transfer surface, in the circulation system, the heated feed goes to the steam drum. The boiler water from the steam drum flow to the common feed headers through the individual feeders steam water mixture generated in the evaporator due to heat transfer from the gas turbine exhaust flows back to the drum through the riser tubes.

6) Condensate preheater:

It is the seventh and the final heat transfer surface arranged in the gas flow. Condensate preheater is constructed of modules consisting of spiral finned tubes welded to the top and bottom headers two rows maximum per module. Condensate preheater is designed for single pass flow of the gas side and multipass flow on the tube side.

7) Attemperator:

Attemperator reduces steam temperature by bringing superheated steam into direct contact with water. The steam is cooled through the evaporation of the water. Attemperators can be mounted either horizontally or vertically and are normally used for relatively steady load conditions where pressure losses must be minimized. These desuperheaters are a modification of the venturi-type unit, without the venturi tail, and offer increased turndown when mounted vertically up.

Water enters the attemperator and is preheated in the circulatory chamber around the water diffuser tube. It is then introduced in many small jets to assist final atomization by the steam flow through the center of the throat. After leaving the throat, the mixture of steam and water enters the main steam flow in a fog-like condition where final heat transfer is achieved without contacting the sidewalls-providing maximum desuperheating effectiveness with minimum of pipe wear. Water pressure into the attemperator should equal steam line pressure. Spray attemperator is utilised to control the H.P steam temperature to 520˚C. For this application interstage attemperator is used after the H.P superheater.

8) Expansion joints:

A part of expansion joint Positions of expansion joints

One expansion joint at HRSG inlet and one more expansion joint at chimney or stack inlet are provided to take care of expansions.

9) Chimney or Stacks:

The gas turbine exhaust gases after passing through all the heat transfer surfaces are discharged into the atmosphere at safe height through a 70 m high steel chimney or stack. On each HRSG there are two stacks one main stack and other bypass stack. When enough steam is produced in the HRSG than the gas turbine exhaust gases are diverted to bypass stack by closing a gate valve and hence the gases does not pass through HRSG and hence no steam is produced.

Specification:

HRSG Type : Natural circulation, dual pressure, horizontal unfired, water tube, Single drum, HV type HRSG.

HRSG Fuel : Unfired.

HRSG Source : Gas turbine exhaust gases.

Heat transfer surface details:H.P section Type Tube size Area (sq. m)

Superheater Solid 38.1×3.6 7220

Evaporator Serrated 51.0×4.5 41865

Economizer Serrated 38.1×4.5 29910

L.P section Type Tube size Area (sq. m)

Superheater Solid 51.0×3.6 945

Evaporator Serrated 51.0×3.6 30440

Condensate preheater Serrated 38.1×3.6 20805

GENERATOR

A steam turbine generator

In electricity generation, an electrical generator is a device that converts mechanical energy to electrical energy, generally using electromagnetic induction. The reverse conversion of electrical energy into mechanical energy is done by a motor, and motors and generators have many similarities. A generator forces electric charges to move through an external electrical circuit, but it does not create electricity or charge, which is already present in the wire of its windings. It is somewhat analogous to a water pump, which creates a flow of water but does not create the water inside. The source of mechanical energy may be a reciprocating engine, a steam or gas turbine, water falling through a turbine or waterwheel, an internal combustion engine, a wind turbine, a hand crank, the sun or solar energy, compressed air or any other source of mechanical energy. At P.P.C.L there are 3 electrical generators, each coupled with two gas turbines and one steam turbine.The two main parts of a generator or motor can be described in either mechanical or electrical terms:

Mechanical:

Rotor:

The rotor is the non-stationary part of a rotary electric motor or a A.C generator, which rotates because the wires and magnetic field of the motor are arranged so that a torque is developed about the rotor's axis. In some designs, the rotor can act to serve as the motor's armature, across which the input voltage is supplied. The stationary part of an electric motor is the stator.

Stator:

The stationary part of an alternator, generator, dynamo or motor is called stator. The non-stationary part on an electric motor is the rotor.

Depending on the configuration of a spinning electromotive device the stator may act as the field magnet, interacting with the armature to create motion, or it may act as the armature, receiving its influence from moving field coils on the rotor.

Electrical:

Armature: The power-producing component of an alternator, generator, dynamo or motor. In a generator, alternator, or dynamo the armature windings generate the electrical current. The armature can be on either the rotor or the stator.

Field: The magnetic field component of an alternator, generator, dynamo or motor. The magnetic field of the dynamo or alternator can be provided by either electromagnets or permanent magnets mounted on either the rotor or the stator.

Because power transferred into the field circuit is much less than in the armature circuit, AC generators nearly always have the field winding on the rotor and the stator as the armature winding. Only a small amount of field current must be transferred to the moving rotor, using slip rings. Direct current machines necessarily have the commutator on the rotating shaft, so the armature winding is on the rotor of the machine.

EXITATION:

An electric generator or electric motor that uses field coils rather than permanent magnets will require a current flow to be present in the field coils for the device to be able to work. If the field coils are not powered, the rotor in a generator can spin without producing any usable electrical energy, while the rotor of a motor may not spin at all. Very large power station generators often utilize a separate smaller generator to excite the field coils of the larger. The generators at P.P.C.L also use an exiter. In the event of a severe widespread power outage where islanding of power stations has occurred, the stations may need to perform a black start to excite the fields of their largest generators, in order to restore customer power service.

WORKING PRINCIPLE:

The electrical generator works on faraday’s law of electromagnetic induction. Faraday's law of induction describes an important basic law of electromagnetism, which is involved in the working of transformers, inductors, and many forms of electrical generators. The law states:

“The induced electromotive force or EMF in any closed circuit is equal to the time rate of change of the magnetic flux through the circuit.”

The law was discovered by Michael Faraday in 1831 and independently at the same time by Joseph Henry.

Quantitatively, the law takes the following form:

.

Where

is the electromotive force (EMF) in volts ΦB is the magnetic flux through the circuit (in webers).

The direction of the electromotive force (the negative sign in the above formula) is given by Lenz's law. The meaning of "flux through the circuit" is elaborated upon in the examples below.

Traditionally, two different ways of changing the flux through a circuit are recognized. In the case of transformer EMF the idea is to alter the field itself, for example by changing the current originating the field (as in a transformer), or by sweeping a magnet past a loop of wire. In the case of motional EMF, the idea is to move all or part of the circuit through the magnetic field, for example, as in a homopolar generator.

When the magnetic field around a conductor changes, a current is induced in the conductor. Typically, a rotating magnet called the rotor turns within a stationary set of conductors wound in coils on an iron core, called the stator. The field cuts across the conductors, generating an electrical current, as the mechanical input causes the rotor to turn. The rotating magnetic field induces a AC voltage in the stator windings. Often there are three sets of stator windings, physically offset so that the rotating magnetic field produces three phase currents, displaced by one-third of a period with respect to each other.

The rotor magnetic field may be produced by induction (in a "brushless" alternator), by permanent magnets (in very small machines), or by a rotor winding energized with direct current through slip rings and brushes. The rotor magnetic field may even be provided by stationary field winding, with moving poles in the rotor. Automotive alternators invariably use a rotor winding, which allows control of the alternator generated voltage by varying the current in the rotor field winding. Permanent magnet machines avoid the loss due to magnetizing current in the rotor, but are restricted in size, owing to the cost of the magnet material. Since the permanent magnet field is constant, the terminal voltage varies directly with the speed of the generator. Brushless AC generators are usually larger machines like those in power plants than those used in automotive applications.

DEAERATOR

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). It 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 (0.0005 cm³/L) or less.

The removal of dissolved gases from boiler feedwater is an essential process in a steam system. The presence of dissolved oxygen in feedwater causes rapid localized corrosion in boiler tubes. Carbon dioxide will dissolve in water, resulting in low pH levels and the production of corrosive carbonic acid. Low pH levels in feedwater causes severe acid attack throughout the boiler system. While dissolved gases and low pH levels in the feedwater can be controlled or removed by the addition of chemicals, it is more economical and thermally efficient to remove these gases mechanically. This mechanical process is known as deaeration and will increase the life of a steam system dramatically.

The purposes of deaeration are:

1. To remove oxygen, carbon dioxide and other non-condensable gases from feed water.2. To heat the incoming makeup water and return condensate to an optimum temperature for:

a. Minimizing solubility of the undesirable gases

b. Providing the highest temperature water for injection to the boiler

Deaerators are typically elevated in boiler rooms to help create head pressure on pumps located lower. This allows hotter water to be pumped without vapor locking should some steam get into the pump.

The most common source of corrosion in boiler systems is dissolved gas: oxygen, carbon dioxide and ammonia. Of these, oxygen is the most aggressive. The importance of eliminating oxygen as a source of pitting and iron deposition cannot be over-emphasized. Even small concentrations of this gas can cause serious corrosion problems.

Makeup water introduces appreciable amounts of oxygen into the system. Oxygen can also enter the feed water system from the condensate return system. Possible return line sources are direct air-leakage on the suction side of pumps, systems under vacuum, the breathing action of closed condensate receiving tanks, open condensate receiving tanks and leakage of non-deaerated water used for condensate pump seal and/or quench water. With all of these sources, good housekeeping is an essential part of the preventive program.

One of the most serious aspects of oxygen corrosion is that it occurs as pitting. This type of corrosion can produce failures even though only a relatively small amount of metal has been lost and the overall corrosion rate is relatively low. The degree of oxygen attack depends on the concentration of dissolved oxygen, the pH and the temperature of the water.

The influence of temperature on the corrosivity of dissolved oxygen is particularly important in closed heaters and economizers where the water temperature increases rapidly. Elevated temperature in itself does not cause corrosion. Small concentrations of oxygen at elevated temperatures do cause severe problems. This temperature rise provides the driving force that accelerates the reaction so that even small quantities of dissolved oxygen can cause serious corrosion.

Operating Principle:

Deaeration is based on two scientific principles. The first principle can be described by Henry's Law. Henry's Law asserts that gas solubility in a solution decreases as the gas partial pressure above the solution decreases. The second scientific principle that governs deaeration is the relationship between gas solubility and temperature. Easily explained, gas solubility in a solution decreases as the temperature of the solution rises and approaches saturation temperature. A deaerator utilizes both of these natural processes to remove dissolved oxygen, carbon dioxide, and other non-condensable gases from boiler feedwater. The feedwater is sprayed in thin films into a steam atmosphere allowing it to become quickly heated to saturation. Spraying feedwater in thin films increases the surface area of the liquid in contact with the steam, which, in turn, provides more rapid oxygen removal and lower gas concentrations. This process reduces the solubility of all dissolved gases and removes it from the feedwater. The liberated gases are then vented from the deaerator. Deaerators use steam to heat the water to the full saturation temperature corresponding to the steam pressure in the deaerator and to carry away dissolved gases. The deaeration system consists of deaeration tank, a storage tank and a vent. In the deaeration tank, water is heated and agitated by steam bubbling through the water. Steam is cooled by the incoming water and condensed at the vent condenser. Non-condensable gases and some steam are released through the vent. Steam provided to the deaerator provides physical stripping action and heats the mixture of returned condensate and boiler feedwater make-up to saturation temperature. While most of the steam condenses, a small percentage of steam (5-14%) must be vented to accommodate the stripping requirements.

There are two basic types of deaerators, the tray-type and the spray-type:

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.

Types of deaerators:

There are many different horizontal and vertical designs available from a number of manufacturers, and the actual construction details will vary from one manufacturer to another. The deaerator at P.P.C.L is a Tray type deaerator. The two types of deaerator are described below:

Tray-type deaerator:

Figure: A schematic diagram of a typical tray-type deaerator.

The typical horizontal tray-type deaerator has a vertical domed deaeration section mounted above a horizontal boiler feedwater storage vessel. Boiler feedwater enters the vertical dearation section above the perforated trays and flows downward through the perforations. Low-pressure dearation steam enters the below the perforated trays and flows upward through the perforations. Some designs use various types of packing material, rather than perforated trays, to provide good contact and mixing between the steam and the boiler feed water.

The steam strips the dissolved gas from the boiler feedwater and exits via the vent at the top of the domed section. Some designs may include a vent condenser to trap and recover any water entrained in the vented gas. The vent line usually includes a valve and just enough steam is allowed to escape with the vented gases to provide a small and visible telltale plume of steam.

The deaerated waster flows down into the horizontal storage vessel from where it is pumped to the steam generating boiler system. Low-pressure heating steam, which enters the horizontal vessel

through a sparger pipe in the bottom of the vessel, is provided to keep the stored boiler feedwater warm. External insulation of the vessel is typically provided to minimize heat loss.

Spray-type deaerator:

Figure: A schematic diagram of a typical spray-type deaerator.

As shown in Figure, the typical spray-type deaerator is a horizontal vessel which has a preheating section (E) and a deaeration section (F). The two sections are separated by a baffle(C). Low-pressure steam enters the vessel through a sparger in the bottom of the vessel.

The boiler feedwater is sprayed into section (E) where it is preheated by the rising steam from the sparger. The purpose of the feedwater spray nozzle (A) and the preheat section is to heat the boiler feedwater to its saturation temperature to facilitate stripping out the dissolved gases in the following deaeration section.

The preheated feedwater then flows into the dearation section (F), where it is deaerated by the steam rising from the sparger system. The gases stripped out of the water exit via the vent at the top of the vessel. Again, some designs may include a vent condenser to trap and recover any water entrained in the vented gas. Also again, the vent line usually includes a valve and just enough steam is allowed to escape with the vented gases to provide a small and visible telltale plume of steam

The deaerated boiler feedwater is pumped from the bottom of the vessel to the steam generating boiler system.

Deaeration steam:

The deaerators in the steam generating systems of most power plants use low pressure steam obtained from an extraction point in their steam turbine system. However, the steam generators in many large industrial facilities such as petroleum refineries may use whatever low-pressure steam that is available.

Oxygen scavengers:

Oxygen scavenging chemicals are very often added to the deaerated boiler feedwater to remove any last traces of oxygen that were not removed by the deaerator. The most commonly used oxygen scavenger is sodium sulfite (Na2SO3). It is very effective and rapidly reacts with traces of oxygen to form sodium sulfate (Na2SO4) which is non-scaling.

Limitations:

Inlet water should be virtually free of suspended solids that could clog spray valves and ports of the inlet distributor and the deaerator trays. In addition, spray valves, ports and deaerator trays may become plugged with scale that forms when the water being deaerated has high hardness and alkalinity levels. In this case, routine cleaning and inspection of the deaerator is very important.

COOLING TOWER

An induced draft cooling tower

Cooling towers are heat removal devices used to transfer process waste heat to the atmosphere. Cooling towers may either use the evaporation of water to remove process heat and cool the working fluid to near the wet-bulb air temperature or rely solely on air to cool the working fluid to near the dry-bulb air temperature. Common applications include cooling the circulating water used in oil refineries, chemical plants, power plants and building cooling. The towers vary in size from small roof-top units to very large hyperboloid structures that can be up to 200 metres tall and 100 metres in diameter, or rectangular structures that can be over 40 metres tall and 80 metres long. Smaller towers are normally factory-built, while larger ones are constructed on site.

In a combined cycle power plant the steam after doing useful work in steam turbine is condensed by means of a cooling tower, the steam after passing through steam turbine goes into the condenser, the condenser is consist of a number of coils in which cold water from cooling tower runs, the steam passes over from these coils and thus the heat is absorbed from the steam and it condenses in to water, this water is again sent to the HRSG after mixing it with pre-treated makeup water. The water after absorbing heat becomes hot, so it is again sent to the cooling tower where it again cools and is re-circulated. If cooling tower is not present in a plant than water requirement of the plant will become very large. The primary task of a cooling tower is to reject heat into the atmosphere. This heat rejection is accomplished through the natural process of evaporation that takes place when air and water are brought into direct contact in the cooling tower. The evaporation is most efficient when the maximum water surface area is exposed to the maximum flow of air, for the longest possible period of time.

Cooling towers are designed in two different configurations, counter flow and cross flow. The specific configuration indicates the direction of air flow through the tower relative to the direction of the water flow. Cooling tower water and air distribution systems are designed in concert, with each playing an equally important role in determining the efficiency and proper application of the cooling tower.

The overall efficiency of a cooling tower is directly related to the design of the tower's hot water distribution system. The primary consideration in selecting the type of hot water distribution system for a specific application is pump head. The pump head imposed by a cooling tower consists of the static lift (related to the height of the inlet) plus the pressure necessary to move the water through the distribution system and over the fill. The pump head varies according to the cooling tower configuration. The cooling tower at P.P.C.L is a induced draught cross flow cooling tower, the cooling towers can be classified as:

Air flow generation methods:

With respect to drawing air through the tower, there are three types of cooling towers:

Natural draft, which utilizes buoyancy via a tall chimney. Warm, moist air naturally rises due to the density differential to the dry, cooler outside air. Warm moist air is less dense than drier air at the same temperature and pressure. This moist air buoyancy produces a current of air through the tower.

Mechanical draft, which uses power driven fan, motors to force or draw air through the tower.

o Induced draft: A mechanical draft tower with a fan at the discharge which pulls air through tower. The hot water falls down from top of the cooling tower through nozzles; the fan is situated at top of these nozzles. The interaction of air and water results in absorption of heat from the hot water.

A cooling tower fan

The fan produces low entering and high exiting air velocities, reducing the possibility of recirculation in which discharged air flows back into the air intake. This fan/fill arrangement is also known as draw-through.

o Forced draft: A mechanical draft tower with a blower type fan at the intake. The fan forces air into the tower, creating high entering and low exiting air velocities. The low exiting velocity is much more susceptible to recirculation. With the fan on the air intake, the fan is more susceptible to complications due to freezing conditions. Another disadvantage is that a forced draft design typically requires more motor horsepower than an equivalent induced draft design. The forced draft benefit is its ability to work with high static pressure. They can be installed in more confined spaces and even in some indoor situations. This fan/fill geometry is also known as blow-through.

Fan assisted natural draft. A hybrid type that appears like a natural draft though airflow is assisted by a fan.

Categorization by air-to-water flow:

Crossflow:

Crossflow is a design in which the air flow is directed perpendicular to the water flow). Air flow enters one or more vertical faces of the cooling tower to meet the fill material. Water flows (perpendicular to the air) through the fill by gravity. The air continues through the fill and thus past the water flow into an open plenum area. A distribution or hot water basin consisting of a deep pan with holes or nozzles in the bottom is utilized in a crossflow tower. Gravity distributes the water through the nozzles uniformly across the fill material. Cross flow towers utilize a distinctly different type of water distribution system. Hot water is distributed to the fill by gravity through metering orifices in the floor of the inlet basin. There is no pressure spray distribution system. The air movement is horizontally through the fill, across the downward fall of the water. In cross flow towers, the internal pressure component of pump head is insignificant because maximum flow is achieved by gravity.

Advantages of cross flow cooling towers due to their gravity flow hot water distributionsystem:

1) Low pumping head. 2) Lower first cost pumping systems. 3) Lower annual energy consumption and operating costs. 4) Accepts larger variation in water flow without adverse effect on the water distribution pattern

(flat plate heat exchanger operation in winter). 5) Easy maintenance access to distribution nozzles.

Advantages of cross flow cooling towers due to their horizontal air distribution system:

1) Low static pressure drop. 2) Reduced drift. 3) Reduced recirculation. 4) More air per fan horsepower. 5) Larger diameter fans can be used so that fewer cells are required for a given capacity. 6) Lower energy and operating costs.

Disadvantages of cross flow cooling towers due to their gravity flow hot water distribution system:

1) Low pressure head on the distribution pan may encourage orifice clogging and less water break-up at spray nozzle.

2) Exposure to air in the hot water basin may accelerate algae growth. Larger footprint.

Disadvantage of cross flow cooling towers due to their horizontal air distribution system:

1) Larger louver surface area makes icing more difficult to control.

Counterflow:

In a counterflow design the air flow is directly opposite of the water flow. Air flow first enters an open area beneath the fill media and is then drawn up vertically. The water is sprayed through pressurized nozzles and flows downward through the fill, opposite to the air flow. Counter flow towers use a high pressure spray nozzle hot water distribution system to achieve water coverage of the fill. The nozzle spray pattern is sensitive to changes in water flow, and consequent change in nozzle pressure. The air movement is vertically upward through the fill, counter to the downward fall of the water. Counter flow towers typically have a smaller footprint than cross flow towers, but require additional height, static lift, and dynamic head to achieve the same cooling effect.

Common to both designs:

The interaction of the air and water flow allows a partial equalization and evaporation of water.

The air, now saturated with water vapor, is discharged from the cooling tower.

A collection or cold water basin is used to contain the water after its interaction with the air flow.

Both crossflow and counterflow designs can be used in natural draft and mechanical draft cooling towers.

Advantages of counter flow cooling towers due to their pressurized spray water distribution system:

·         Increased tower height accommodates longer ranges and closer approaches.

·         More efficient use of air due to finer droplet size from pressure sprays. 

Advantages of counter flow cooling towers due to their vertical air distribution system:

← The vertical air movement across the fill allows the coldest water to be in contact with the driest air maximizing tower performance. 

Disadvantages of counter flow cooling towers due to their pressurized spray water distribution system:

·         Increased system pumping head requirements.

·         Increased energy consumption and operating costs.

·         Distribution nozzles difficult to inspect and clean.

·         Requires individual risers for each cell, increasing external piping costs.

Disadvantages of counter flow cooling towers due to their vertical air distribution system:

The resistance to upward air travel against the falling water results in higher static pressure loss and a greater fan horsepower than in cross flow towers.

The restricted louver area at the base with high velocity of inlet air increases the fan horsepower.

Tendency for uneven distribution of air through the fill with very little movement near the walls and center of the tower.

High inlet velocities are liable to suck airborne trash and dirt into the tower.

WATER TREATMENT

Water circulation in various components

Water treatment is an important part of any combined cycle power plant, if a clean source of water is not available and the water is procured from sewage or any other source which is not clean. The water required for production of steam must be clean and free from harmful chemicals, suspended particles, sludge, gases etc. If the water is not thoroughly cleaned, it may clog the paths through which it travels over the time or may cause corrosion of turbine blades, HRSG tubes and many other severe problems, so an efficient water treatment system is required by every combined cycle power plant. At P.P.C.L raw water requirement is met through Sewage treated water being drawn from Sen Nursing Home and Delhi Gate Sewage Treatment Plant. The demineralized water requirement for steam generation is met up through sewage treated water by treating this through RODM (reverse osmosis de-mineralized) process. The production of cooling water requirement for condenser and other equipment is also met through sewage treated water after processing through Lime softening system. The plant effluent is discharged to river Yamuna after naturalizing and thus the effluent discharge is better than sewage water. Infact cleaner water is being discharged to Yamuna River, making the plant more eco-friendly. The water treatment process at P.P.C.L can be divided in to following three sections:

1) Sewage treatment plant 3) Reverse osmosis and demineralization plant.

2) Effluent treatment plant.

Sewage treatment plant:

The sewage treatment plant is designed for sewage generated from main plant as well as the balance plant. The total quantity is around 25 cubic meter per day. It is consist of the following processes:

1) Bar screening:

Sewage from main and balance plant are collected in two sewage pits no. 2 and no. 1 respectively after passing through a bar screen of 20mm size to remove flowing matters. The sewage is collected in the pits and is passed once again through bar screens for further removal of floating particles.

2) Grit chamber:

Grit particles in sewage are removed in this chamber. Grit removal is necessary to protect the moving mechanical equipments and to avoid settling in the aeration tank which will affect the biological treatment.

3) Parshall flume:

Parshall flume is required at the down stream of grit chamber. It is an open constructed channel which can be used both as a velocity control device.

4) Aeration tank:

The organic matter present in the sewage is removed by using biological treatment. In this process, the sewage containing waste organic matter is aerated in the aeration tank in which micro organisms metabolizes the soluble and suspended organic matter. Part of the organic matter is synthesized into new cells and part is oxidized to carbon dioxide and water to derive the energy. The clear water will be transferred to chlorination tank for further treatment.

5) Chlorination system:

This system is provided as a tertiary sewage will remove all the bacteria present in the effluent. It will also take care of further contamination.

6) Sludge drying beds:

Sludge dewatering is adopted for reducing the volume or increase the solid concentration. The digested sludge is deposited on well drained beds of sand and gravel.

Effluent treatment plant:

This plant is designed for total flow of 318 cubic meters per day and the treatment scheme is based on the inlet characteristics of water. It is consist of the following:

1) Oil removal: The effluent is pumped from gas turbine generator and boiler feed pump area, steam turbine generator and auxiliary TFR area, boiler operating pump area, transformer effluent are

pumped into central oil separator for oil water separation. The floating oil is removed using oil skimmer. After removal of oil the effluent passes into the tilted plate interceptor(TPI) and the removed free oil is collected in the slop oil collection tank. In the tilted plate separator the residual oil free effluent passes in to central monitoring basin. The removed free oil from TPI is collected in the slop oil collection tank.

2) Neutralization:

The oil free effluent from tilted plate separator and other wastewater from other areas are collected in central monitoring basin. The function of central monitoring basin is to neutralize the characteristics of the wastewater. The chemical dosing system such as lime and acid dosing is carried out depending on the ph of combined effluent. The basin is provided with an aeration grid connected with air blowers to ensure proper mixing using online instruments like turbidity, temperature conductivity and ph of the effluent can be measured.

3) Common sludge dewatering system:

The common sludge dewatering system is designed for a flow of 57 cubic meters per hour and the treatment scheme is consist of the following processes:

a) Flash mixing cum flocculation and clarification:

The sludge is pumped from the filter backwash sump, HRSG area waste water sump sludge from TPI, sludge from CT basin, waste service water sump, HSD area, oil water separator sludge and sludge from central oil water separator sludge are pumped into flash mixer cum flocculation tank. Flash mixing by which the coagulants and coagulant aids are rapidly and uniformly dispersed throughout the volume of water to create homogeneous system. In the flocculation which results in the formation of large and readily setteleable flocs by bringing the finely divided matter into contact with the micro flocs formed during rapid mixing.

Fig: A mechanical clarifier

These can be subsequently removed in the lamella clarifier. The sludge collected from the bottom of the lamella clarifier is collected in sludge sump for further dewatering process. The clarified water from lamella clarifier is collected in filter water sump and they are pumped to central monitoring basin for further treatment. Water clarification is the process of removing suspended solids from

water. Most of the suspended matter in water would settle, given enough time, but in most cases the amount of time required would not be practical. The time required for settling is dependent on many factors, including:  weight of the particle, shape of the particle, size of the particle, and viscosity and/or frictional resistance of the water, which is a function of temperature. The process of clarification generally involves the addition of coagulation chemicals to a water supply, mixing under heavy agitation to cause the particles to cling together and grow larger, and mechanically removing them from the water. Clarification is commonly used for large boilers that consume large volumes of water from surface water sources. Clarification is commonly used in combination with filtration for total removal of solids.

b) Sludge thickening:

The sludge collected from lamella clarifier is pumped to thickener. The sludge sump is provided with an aeration grid connected with air blowers to ensure proper mixing and solids in suspension. The function of thickener is for increasing the solids concentration to centrifuge. The thickened sludge collected from thickener is pumped by means of screw pumps to centrifuge for sludge dewatering purpose. The solid cakes formed centrifuge is collected and disposed off. The supernatant is sent and is collected in flash mixer followed by flocculator and lamella clarifier for further reduction of suspended solids in the system.

c) Chemical dosing system:

Chemicals such as alum and polymer of desired strength are prepared in solution tanks and are fed to the flash mixer by chemical dosing pumps.

d) Lime sludge treatment:

The lime sludge treatment is designed for a flow of 1320cubic meters per day. The sludge collected from lime softening plant is pumped to thickener. The function of thickener is for increasing the solids concentration to centrifuge. The thickened sludge collected from thickener is pumped by means of screw pumps to centrifuge for sludge dewatering purpose. The solid cakes formed from centrifuge is collected and disposed off in the area allotted for it. The supernatant is diverted to stilling chamber of lime softening plant.

Reverse osmosis and demineralization plant:

Reverse osmosis:

A reverse osmosis plant

The reverse osmosis and demineralization is the last stage of water treatment after this the water is pumped to the HRSG for steam generation. Reverse osmosis (RO) is a separation process that uses pressure to force a solution through a membrane that retains the solute on one side and allows the pure solvent to pass to the other side. More formally, it is the process of forcing a solvent from a region of high solute concentration through a membrane to a region of low solute concentration by applying a pressure in excess of the osmotic pressure. This is the reverse of the normal osmosis process, which is the natural movement of solvent from an area of low solute concentration, through a membrane, to an area of high solute concentration when no external pressure is applied. The membrane here is semipermeable, meaning it allows the passage of solvent but not of solute.

The membranes used for reverse osmosis have a dense barrier layer in the polymer matrix where most separation occurs. In most cases the membrane is designed to allow only water to pass through this dense layer while preventing the passage of solutes (such as salt ions). This process requires that a high pressure be exerted on the high concentration side of the membrane, usually 2–17 bar (30–250 psi) for fresh and brackish water, and 40–70 bar (600–1000 psi) for seawater, which has around 24 bar (350 psi) natural osmotic pressure which must be overcome.

This process is best known for its use in desalination (removing the salt from sea water to get fresh water), but it has also been used to purify fresh water for medical, industrial and domestic applications since the early 1970s.

When two solutions with different concentrations of a solute are mixed, the total amount of solutes in the two solutions will be equally distributed in the total amount of solvent from the two solutions.

Instead of mixing the two solutions together, they can be put in two compartments where they are separated from each other by a semipermeable membrane. The semipermeable membrane does not allow the solutes to move from one compartment to the other, but allows the solvent to move. Since equilibrium cannot be achieved by the movement of solutes from the compartment with high solute concentration to the one with low solute concentration, it is instead achieved by the movement of the solvent from areas of low solute concentration to areas of high solute concentration. When the solvent moves away from low concentration areas, it causes these areas to become more concentrated. On the other side, when the solvent moves into areas of high concentration, solute concentration will decrease. This process is termed osmosis. The tendency for solvent to flow through the membrane can be expressed as "osmotic pressure", since it is analogous to flow caused by a pressure differential.

In reverse osmosis, in a similar setup as that in osmosis, pressure is applied to the compartment with high concentration. In this case, there are two forces influencing the movement of water: the pressure caused by the difference in solute concentration between the two compartments (the osmotic pressure) and the externally applied pressure.

Principles of Operation:

Reverse osmosis is a membrane separation process for removing solvent from a solution. When a semi permeable membrane separates a dilute solution from a concentrated solution, solvent crosses from the dilute to the concentrated side of the membrane in an attempt to equalize concentrations. The flow of solvent can be prevented by applying an opposing hydrostatic pressure to the concentrated solution.

The magnitude of the pressure required to completely impede the flow of solvent is defined as the "osmotic pressure". If the applied hydrostatic pressure exceeds the osmotic pressure (see figure below), flow of solvent will be reversed, that is, solvent will flow from the concentrated to the dilute solution. This phenomenon is referred to as Reverse Osmosis. The figure illustrates the concepts of osmosis, osmotic pressure and reverse osmosis schematically.

Fig: Overview of osmosis and reverse osmosis

In order to use reverse osmosis as a water purification process, the feed water is pressurized on one side of a semi permeable membrane. The pressure must be high enough to exceed the osmotic pressure to cause reverse osmotic flow of water.

If the membrane is highly permeable to water, but essentially impermeable to dissolved solutes, pure water crosses the membrane and is known as product water. As product water crosses the membrane, the concentration of dissolved impurities increases in the remaining feed water (a condition known as concentration polarization) and, as a consequence, the osmotic pressure increases.

A point is reached at which the applied pressure is no longer able to overcome the osmotic pressure and no further flow of product water occurs. Moreover, if the applied pressure is increased in an attempt to gain more product water, a point is reached at which the membrane becomes fouled by precipitated salts and other un-dissolved material from the water.

Therefore, there is a limit to the fraction of feed water which can be recovered as pure water and reverse osmosis units are operated in a configuration where only a portion of the feed water passes through the membrane with the remainder being directed to drain (cross-flow configuration).

The water flowing to drain contains concentrated solutes and other insoluble materials, such as bacteria, endotoxin and particles, and is referred to as the reject stream. The product water to feed water ratio can range from 10% 50% for purification of water depending on the characteristics of the incoming water as well as other conditions.

Types of Reverse Osmosis Membranes:

A reverse osmosis membrane must be freely permeable to water, highly impermeable to solutes, and able to withstand high operating pressures. It should ideally be tolerant of wide ranges of pH and temperature and should be resistant to attack by chemicals like free chlorine and by bacteria.

Ideally, it should also be resistant to scaling and fouling by contaminants in the feed water. There are three major types of reverse osmosis membranes: cellulosic, fully aromatic polyamide and thin film composite.

Demineralization:

A mixed bed demineralization plant

Demineralization (D.M.) is concerned with the removal of all mineral matter from the Boiler Feed Water (BFW) in order to maintain high heat-transfer efficiency in the boiler by preventing deposition of precipitated scale and preventing corrosion or deterioration of surfaces in contact with water. Moreover when production of steam is related to power generation through a steam turbine, a higher water quality is mandatory to meet requirements of the turbine manufacturer. The demineralization plant at P.P.C.L is a mixed bed type plant. D.M. plants consist of cation unit and anion unit placed one after other in series. The cation unit is charged with strong acid cation resin & anion unit is charged with strong base unit. D. M. plants remove all the anions & cations from the water. Conductivity of the treated water is in the range of 0 to 40 ms per cm. The cation resin is regenerated with Hydrochloric acid & anion resin with Caustic solution. Then the cation unit is rinsed with feed water and anion unit with decationised water till the acceptable water quality is achieved. Demineralization can be accomplished through the following processes that could be placed in sequence to guarantee the highest water quality:

DOUBLE STEP DEMINERALISATION:

Demineralization refers to the removal of all mineral matter from the raw water.The most common arrangement is a sequence of cation exchangers and anion exchangers in which cation resins in the hydrogen form and anion resins in the hydroxide form are filled-in respectively.Water passes first through the cation exchanger where cations (mainly calcium, magnesium, sodium etc) are exchanged with hydrogen ions. In the anionic exchanger negative ions (mainly chloride, sulfate, hydro carbonates) are exchanged with hydroxide ions. Hydrogen ions produced in the first stage react with hydroxide ions to give water.The regeneration of the ion exchange resins takes place when the resins are exhausted. The regeneration is performed with diluted solution of hydrochloric or sulphuric acid and caustic soda.

MIXED BED DEMINERALIZATION UNITS:

Industrial Mixed Bed Deionizers are designed to produce high purity treated water required by the pharmaceuticals and electronic industries. These deionizers can be used as polishing units after two bed deionizers or directly to obtain high purity water. Mixed Bed Deionizers are single column units, filled with strongly acidic cation and strongly basic anion exchange resins mixed together evenly. Dissolved solids in the water are thus removed, producing water of very high quality - confirming to IP specifications of purified water. The treated water, however is not free from bacteria and pyrogen.

Working principle:

There are four distinct stages in the operation of an industrial mixed-bed deionizer:

1) Service/exhaustion

2) Backwashing

3) Regeneration

4) Rinse/remix

Service/exhaustion:

Backwashing:

Once the resins are exhausted, the bed is backwashed. Backwashing is initiated by introducing a uniform upward flow of water through the resin bed. The backwash step serves two important functions:Firstly, it expands the resin bed releasing any entrapped particulate matter and resin fines. Secondly, the backwash flow separates the denser cation resin from the lighter anion resin, forming two distinct layers in the vessel.

Regeneration:

The first stage in the process of regeneration involves passing a dilute solution of acid, usually hydrochloric, through the cation bed. After the cation resin has been regenerated, the anion resin is regenerated by passing a dilute solution of caustic (sodium hydroxide) through the anion resin bed. As a result, the cation resin is reconverted to the hydrogen form and the anion resin to the hydroxyl form.

Rinse\Remix:

The final stage of regeneration is to rinse the resins of excess regenerant and then remix with air.

Rinse/remix

About the company

Brief history of power supply in Delhi:

Generation of electricity in Delhi started with a 2 MW diesel set in 1903. After independence Rajghat Power House ‘A’ was installed in 1951 with 5 MW capacity. Delhi Electric Supply Undertaking (DESU) came into existence in 1958 and two Units of 9.6 MW capacity each were installed as Rajghat Power House ‘B’. In the second five year plan, three diesel generating sets totaling 20 MW were installed at different locations in Delhi. As a first major step towards making Delhi self sufficient in power, first unit of 36.6 MW was installed in 1963 at Indraprastha Power Station. A 15 mw unit was installed at Rajghat in 1966 followed by three units of 67.5MW each in 1967-68 at Indraprastha Power Station. Delhi Electric Supply Undertaking was restructured and Delhi Vidyut Board was formed in 1997.

Indraprastha Power Generation Co. Ltd. came into existence on 1st July, 2002 after unbundling of Delhi Vidyut Board into six entities. The main function of IPGCL is generation of electricity with an installed capacity of 994.5 MW and 2750 MW capacity addition in pipeline.

With the unbundling of D.V.B. on 01.07.2002, two companies came into existence under Genco:

Indraprastha Power Generation Co. Ltd. (IPGCL) Pragati Power Corporation Ltd. (PPCL)

The Power demand in the Capital City is increasing with the growth of population as well as living standard and commercialization. The unrestricted power demand in the summer of year 2000 was 3000 MW and increasing every year @ 6 to 7%. In 2005-2006, it is expected to be 4078 MW and by 2009-10 it will reach 5075 MW.

Erstwhile DVB's own generation from RPH, I.P. Station and Gas Turbine Power Station had been around 350-400 MW and Badarpur has been supplying 600-700 MW and the balance was met from the Northern Grid and other sources. To bridge the gap between demand and supply and to give reliable supply to the Capital City, Delhi Govt. had set up 330 MW Pragati Power Project on fast track basis. To cut down the project cycle duration, turnkey contract was awarded to M/s BHEL in May 2000 based on similar project executed by BHEL at Kayamkulam (owned by NTPC). To further ensure reliable and smooth operation of the plant, experience of NTPC was utilized by retaining them as engineering consultant and specification of the Kayamkulam Project were adopted.

PRAGATI POWER CORPORATION LTD.

Pragati Power Station:

Pragati Power Station (330 MW) was dedicated to citizens of Delhi by Hon’ble Chief Minister Of Delhi on 6 June 2003.To bridge the gap between demand and supply and to have reliable supply to the Capital City, a 330 MW combined cycle Gas Turbine Power Project was set up on fast track basis. This plant consists of 2 x 104 MW Frame 9-E Gas Turbine Units commissioned in 2002 – 03 and 1 x 122 MW STG Unit commissioned in 2003 – 04. Gas supply has been tied up with GAIL through HBJ Pipeline. The station is performing satisfactorily meeting the targets set by DERC and CEA.

Salient Featuresi. Due to paucity of water this plant was designed to operate on treated sewage water which is

being supplied from Sen Nursing Home & Delhi Gate sewage treatment plant. ii. Emission of oxides of nitrogen (Nox) has been limited to 35 PPM, lowest in the country, for

which special technology is used by installing Dry Low Nox Combustors.

With the commissioning of Pragati Power Station, total capacity of IPGCL & PPCL is 994.5MW and all our efforts are made to maximize the generation.

 

Brief history: A contract was signed with M/s BHEL for installation of 330MW gas based power plant in the vicinity of 220V, I.P. Extension, Switchyard on 05.05.2003. The station is comprised of 2x104MW gas turbines of GT Frame-9E and 1x122MW steam turbine. The Waste Heat emanating from gas turbines is being utilized to generate 122MW power through steam turbine. The hot gases of 560o centigrade with a mass flow of approx. 14000 metric ton per hour is passed through 02 Nos. waste heat recovery boilers of generate steam. The environmental friendly quality power generation through this station is pumped to 220kV Sub Station of Delhi Transco Limited and the entire power is being utilized by citizen of Delhi.

Fuel: The primary fuel for gas turbine is natural gas being supplied by M/s GAIL through HBJ pipe line. The gas is received at GAIL Terminal installed in the vicinity of the power station. M/s GAIL is committed to supply 1.75 MCMD of gas on daily basis. The caloric value of natural gas being received for power generation is in the band of 8200-8500 kilocalories. The secondary fuel for gas turbine is HSD/Naphtha, which is to be used only in case no gas supply is available. Demineralized water is injected to control Nox. While machine is operated on Liquid fuel i.e. HSD/Naphtha.

Raw water: Raw water requirement is met through Sewage treated water being drawn from Sen Nursing Home and Delhi Gate Sewage Treatment Plant. The demineralized water requirement for steam generation is met up through sewage treated water by treating this through RODM (reverse osmosis de-mineralized) process. The production of cooling water requirement for condenser and other equipment is also met through STW after processing through Lime softening system. The plant effluent is discharged to river Yamuna after naturalizing and thus the effluent discharge is better than

sewage water.Infact cleaner water is being discharged to Yamuna River, making the project more eco-friendly.

Emission control: In order to make control on flue gas emission specifically Nox. & CO2 a special emphasizes being given. To control Nox & CO2, State of art, Dry Low Nox. (DLN) Burners have been installed on gas turbine while on natural gas. While the machine is to run on HSD/Naphtha water injection arrangement has been provided to control the Nox. & CO2. at present the value of Nox. & CO2 is in order on 17-18 PPM and 4.22% respectively on base load while O2 is 15%. The allowable limit of Nox. approved by DPCC (Delhi Pollution Control Committee) is 35 PPM, however, there is no cap on CO2 emission.

This is the first plant in India with a facility to control Nox. emission and is an eco-friendly power station.

Also a thick belt of plantation has been grown on periphery of the power plant and small plantation in side the power plant to make it environment friendly.

Funding:The total value of installation the power plant is approx. Rs. 1077.30 crore, which is met by drawing loan from Power Finance Corporation Ltd. and equity of 30% from Delhi Govt.

Load factor: The plant is now fully stabilized and average plant load factor is 90+ during the month of August and September 2003.

Landmarks:

1905First Diesel Power Station established in Delhi.

1911 Steam Generating Station set up in Delhi.1932 Management of Central Power House handed over to NDMC.1939 DCEPA Ltd. established.1947 DESTC taken over by DCEPA Ltd.1951 Delhi State Electricity Board formed.1955 Purchase of Power From Nangal.1958 Delhi Electric Supply Undertaking came into existence.1959 Certain NDMC area taken over by DESU for electric supply.1962 U.J.V.E. Supply Co. taken over by DESU.1963 MES&T Corpn. Taken over by DESU.1963 Unit # 1 of I.P. Station commissioned (36.6 MW).1966 15 MW set installed at RPH.1967 One Unit of 62.5 MW commissioned under I.P. Station extension project1967 First 220KV S/Stn. Set up at I.P. Station.1967 Pool operation of DESU & Bhakra System at 220KV Grid Station at I.P. Station started.1968 All the three units (62.5MW each) at I.P. Station Extension project put on commercial

use.1971 Fifth unit of 60 MW commissioned at I.P. Station, 220 KV S/Stn. Set up at Narela.1986 Six G.T. units of 30MW each at GTPS commissioned.1989 Replacement units of 267.5MW at RPH commissioned.1995 Three WHRUs of 34 MW each at GTPS commissioned.

24.02.1997 Delhi Vidyut Board came into existence.10.06.2000 Foundation stone for 330 MW CCGT Pragati Power Project laid.30.06.2002 Delhi Vidyut Board split in 6 companies namely :

(1) BSES Rajdhani Power Ltd. (2) North Delhi Power Ltd.(3) BSES Yamuna Power Ltd. (4) Delhi Transco Ltd.(5) Indraprastha Power Generation Co. Ltd. (6) Delhi Power Co.

01.07.2002 Indraprastha Power Generation Co. Ltd. And Pragati Power Corporation started working independentely under Govt. of NCT Delhi.

02.07.2002GT No. 1(104MW) of Pragati Power Project on commercial operation.

03.12.2002 GT No. 2(104 MW) of Pragati Power Project put on commercial operation.16.05.2003 STG of Pragati Power Project (122MW ) put on Commercial Operation.06.06.2003 Pragati Power Station (330 MW) was dedicated to citizens of Delhi by Hon’ble Chief

Minister Of Delhi.2007 MOEF has accorded environmental clearance for enhanced capacity of 1600 MW (Max.)

Pragati-III Gas Based Combined Cycle Power Project at Bawana , North-West Delhi.

IPGCL / PPCL STATIONS AT A GLANCE

UNDER IPGCL 3 POWER STATIONS ARE IN OPERATION : Indraprastha

Power Station Rajghat Power

Station

Station Indraprastha Power Station

Rajghat Power Station

Gas Turbine Power Station

Pragati Power Station

Station Cpacity (MW)

247.5 135 282 330(Total 994.5

MW)

Units 3x62.5+60

2x67.5 6x30 (GT)+

3x34 (WHRU)

2x104 (GT)+

1x122 (WHRU)

Year of Commissioning

1967-71 1989-90 1986 & 1996

2002 -03

Coal Fields/Gas NCL, BINA NCL, BINA

GAIL HBJ Pipeline

GAIL HBJ Pipeline

Water Sources River Yamuna River Yamuna

River Yamuna

Treated water from

Sen Nursing Home

and Delhi Gate Sewage

Treatment Plants

Beneficiary Areas

VIP- South & Central Delhi

Central & North Delhi

NDMC-VVIP, DMRC

NDMC, South Delhi

Gas Turbine Power Station

 

The Delhi Vidyut Board (DVB) was a State Electricity Board set up in 1997 under the Electricity (Supply) Act, 1948, succeeding the Delhi Electricity Supply Undertaking (DESU) which has existed since 1957 as a wing of the Municipal Corporation of Delhi. It was an integrated utility with generation, transmission and distribution functions serving all of Delhi except the NDMC and MES (Cantonment) areas to which it supplied power in bulk.

The creation of DVB, replacing DESU, is 1997 proved to be merely a change in the legal status of the organization and was not followed by any real change in its structure, functioning and work culture. Its reputation continued to deteriorate and its poor commercial performance, the best known thing about DVB perhaps being its high Transmission and Distribution (T&D) losses made it a drain on the public exchequer. Further, failure in raising the resources necessary for improvement of its services made matters critical. There were unprecedented, widespread expressions of public discontent during the difficult summer of 1998.

Delhi Electricity Board Regulatory Commission (DERC) was constituted in May 1999 whose prime responsibility was to look into the entire gamut of existing activity and search for various ways of power sector reforms. The DERC is even today a fully functional body which has since issued tariff orders for annual revenue requirement.Delhi Electricity Reform Ordinance, 2000 was a body which was promulgated in October 2000 and notified in the form of an Act in March 2001. It mainly provides for the constitution of an Electricity Regulatory Commission, unbundling of DVB into separate generation, transmission and distribution companies and increasing avenues for participation of private sector.

The Government of India on July 1, 2002, implemented the reforms by unbundling DVB into six companies, one holding company, one generation company (GENCO), one transmission company (TRANSCO) and three distribution companies (DISCOMS). The government handed over the management of the business of electricity distributions to there private companies since July 1, 2002 with 51% equity with the private sector.

For augmentation in generation capacity, the first gas turbine 140 MW of 330 MW Pragati Combined Cycle Gas based power project was put no commissioned operator in July 2002. It was the first power generating project in Delhi after a gap of 14 years. The second gas Turbine unit of 104 MW and waste heart recovery unit of 122 MW were operational by the end of December 2002 and may 2003.

IPGCL (GENCO) generated 2940 MUs during the year 2002 against the target of 2940 MU s fixed by Center Electricity Authority. The expected generation for 2002-2003 is 2960 MUs.

Fly ash brick plant near IP Station is being installed which has started manufacturing 3.00 lakhs ash bricks per day from March 01, 2003. Two mini fly ash plants at Rajghat power Station are expected to double their production from 32,000 bricks per day to 64,000 bricks per day. This will not utilized the fly-ash but will be environment friendly also.

As a result of the power sector reforms in Delhi, the National Capital is now being served by two of the best electric utilities in India, BSES and TATA Power. They will take some time to achieve desired objectives. However, one thing is certain. With economic viability the power situation in Delhi will only get better with every passing year, thus reversing the legacy of deteriorating service that we had seen in past.

ABOUT IPGCL 3 POWER STATIONS:

1. I.P. STATION

247.5 MW coal based power station was installed and commissioned in 1968. While according to the environmental clearance by Ministry of environment and Forest (MOEF) to the Pragati Power Project, they imposed a condition that I.P. Station should be decommissioned with six months from the date of commissioning of Pragati Power Project.

However, Considering the fast rise of power requirement of Delhi. DPCC has now allowed to run I.P. Station units subject to maintaining stack emission below 50 mg/NM3 and zero discharge from ash ponds for which action has been initiated.

2. RAJGHAT POWER HOUSE

It has installed capacity of 2x67.5=135 MW. Both the units are performing well. Additional ESPs are being fitted to bring down the SPM level from 150 mg/NM3 to 50 mg/NM3.

3. GAS TRIBUNE POWER STATION

It has installed capacity of 282 MW. Due to gas restriction only 4 gas turbines and 2 steam turbines are generally in operation. Two gas turbines along with one steam turbine are kept on liquid fuel to meet any emergency.

UNDER PPCL ONE POWER STATION IS IN OPERATION :

PRAGATI POWER STATION

a) Gas Turbines 2x104 MW (open cycle)b) Steam Turbine of 1x122MW (combined cycle)

OBJECTIVE To maximize generation from available capacity. To plan & implement new generation capacity in Delhi.

Competitive pricing of our own generation. To set ever so high standards of environment Protection. To develop competent human resources for managing the company with good standards.

Clients BSES Yamuna Power Limited. BSES Rajdhani Power Limited. North Delhi Power Limited.

Type of Services Being Provided• Electricity Generation by using coal and natural gas as fuel.• Present installed capacity of power generation is 382.5 MW from coal and 612 MW from gas.• Plan and implement new generation plants and augment capacity.• All matters relating to power generation of GNCTD.

Commitments towards citizens• To generate maximum power from existing capacity.• Cost of generation be economical & cheapest.• To augment generation capacity to meet the ever increasing demand of power.• To contain the pollution level from the generating units within the admissible standards.