COMBINED CYCLE POWER PLANT
COMBINED CYCLE POWER PLANT
2.1 INTRODUCTION
In electric power generation combined cycle is an assembly of heat engines
that work in tandem off the same source of heat, converting it into mechanical
energy, which in turn usually drives electrical generators. The principle is that
the exhaust of one heat engine is used as the heat source for another, thus
extracting more useful energy from the heat, increasing the system's overall
efficiency. This works because heat engines are only able to use a portion of
the energy their fuel generates (usually less than 50%).
The remaining heat (e.g., hot exhaust fumes)
from combustion is generally wasted. Combining two or more thermodynamic cycles
results in improved overall efficiency, reducing fuel costs. In stationary
power plants, a successful, common combination is the Brayton cycle
(in the form of a turbine burning natural gas
or synthesis gas
from coal)
and the Rankine cycle (in the form of a steam power plant). Multiple
stage turbine or steam cylinders are also common.
Around two thirds of the electrical power
generated is produced by the gas turbine. a mixture of compressed air and fuel
is combusted. The hot gases that this process creates drive the turbine and,
with it, the generator that is coupled to it. The rest of the electrical power
generated, roughly a third, is produced by the steam turbine using the hot
exhaust gases leaving the gas turbine. In the heat recovery steam generator
(HRSG) the exhaust gases transfer their heat to the circulating water. the
pressurised water vaporises, causing the temperature in the system to rise. The
steam drives the steam turbine and, with it, the generator that is coupled to
it.
RANKINE CYCLE
3-4: Adiabatic compression in feed pump 4-5: Sensible
heat addition in economiser
5-6: Latent heat addition in evaporator 6-1:
Super heat adition in Super heater
BRATON CYCLE:
Braton cycle
1-2:
Adiabatic Compression 2-3: Constant
Pressure Heat Addition
3-4:
Adiabatic Expansion 4-5: Constant
Pressure Heat Rejection
2.2 BLOCK
DIAGRAM OF COMBINED CYCLE POWER PLANT
Typical combined cycle
Explanation
The term
combined cycle (CC) refers to a system that incorporates a gas turbine (GT), a
steam turbine (ST), a heat recovery steam generator (HRSG), where the heat of
the exhaust gases is used to produce steam and a generator. The shaft power
from the gas turbine and that developed by the steam turbine both run the
generator that produces electric power.
In most
combined cycle applications the gas turbine is the topping cycle and the steam turbine
is the bottoming cycle. The major components that make up a combined cycle are
the gas turbine, the HRSG and the steam turbine as shown in Figure .3 a typical
combined cycle power plant with a single pressure HRSG. Thermal efficiencies of
the combined cycles can reach as high as 60%. In the typical combination the
gas turbine produces about 60% of the power and the steam turbine about 40%.
The steam turbine utilizes the energy in the exhaust gas of the gas turbine as
its input energy. The energy transferred to the Heat Recovery Steam Generator
(HRSG) by the gas turbine is usually equivalent to about the rated output of the
gas turbine at design conditions. At off-design conditions the Inlet Guide
Vanes (IGV) are used
to regulate the air so as to maintain a high
temperature to the HRSG.
ENERGY DISTRIBUTION IN A COMBINED CYCLE POWER PLANT
Energy distribution of
CCPP
2.3 MAJOR GAS TURBINE COMPONENTS
The
primary modules in a gas turbine:
•
Compressor module
•
Combustion module
•
Turbine module
A gas turbine also has an inlet section/
module and an exhaust section/ module. Most advanced and large gas turbines
have compressors that are the axial design type. Some of the earlier, smaller
or deliberately compact gas turbines have centrifugal compressors. Each
compressor stage provides an opportunity for stepping up the overall compressor
pressure ratio (PR), so although an axial stage may not offer as much of a PR
as a centrifugal stage of the same
diameter, a multistage axial compressor offers far higher PR (and therefore
mass flow rates and resultant power) than a centrifugal design.
Air inlet section
A gas turbine takes in many multiples of
what an equivalent size reciprocating engine can. The air inlet is generally a
smooth, bell shaped, aluminium alloy duct. It leads air into the compressor
with minimized turbulence. Typically, struts brace the outer shell of the front
frame to minimize air flow vibration. An anti-icing system directs compressor
air (at discharge or some pressure higher than atmospheric) that is bled off an
appropriate compressor stage, into these struts. The temperature of this air
prevents ice formation. Ice ingestion can and has destroyed many gas turbine
engines.
Compressor module
The
compressor is made up of rotating blades on discs and stationary vanes that
direct the air to the next row of blades. The first stage compressor rotor
blades accelerate the air towards their trailing edges and towards the first
stage vanes. The first stage vanes slow the air down and direct it towards the
second stage compressor rotor blades, and so on through the compressor rotor
stages (each stage is one rotating stage and one stationary stage). The main
types of compressor design are centrifugal and axial flow. The
axial-centrifugal-flow compressor is a combination of both and operates with a
combination of their characteristics. It is a less common design.
Combustor:
The combustor module
contains the combustion chambers, igniter plugs, and fuel nozzles. The
combustor burns a fuel-air mixture and delivers the products of combustion to
the turbine at temperatures within design range. Fuel is injected at the
upstream end of the burner in a highly atomized spray. Fuel nozzles may be
simplex type (delivering gaseous fuel or liquid fuel) or they may be designed
to be dual fuel (delivering gas or liquid at different times in the operation).
Some gas turbines are “bi-fuel”. They may burn a mixture of gas and liquid fuel.
Combustion air, with the help of swirled vanes, flows in around the fuel nozzle
and mixes with the fuel.
Turbine module
The kinetic energy of the gases entering
the turbine is transformed into shaft horsepower which is then used to drive
the compressor and other support systems (via accessory system gears. Note that
this turbine, combustor and compressor modules form an assembly that is termed
the “gas generator”. In power generation applications, the entire gas turbine
is a gas generator that is then mechanically coupled either directly or via a
gear box, to the generator that in turn is coupled to the grid or power supply
system.
Exhaust module
The
gas turbine’s hot gases exit via the exhaust section or module. Structurally,
this section supports the power turbine and rear end of the rotor shaft. The
exhaust case typically has an inner and outer housing. Hollow struts locate its
position. The inner housing typically has a cone shape or cover that encloses a
chamber for cooling the thrust bearing at the end of the shaft.
2.4 CONFIGURATION OF CCGT PLANTS
The combined-cycle system includes single-shaft
and multi-shaft configurations. The single-shaft system consists of one gas
turbine, one steam turbine, one generator and one Heat Recovery Steam Generator
(HRSG), with the gas turbine and steam turbine coupled to the single generator
in a tandem arrangement on a single shaft. Key advantages of the single-shaft
arrangement are operating simplicity, smaller footprint, and lower start up
cost. Single-shaft arrangements, however, will tend to have less flexibility
and equivalent reliability than multi-shaft blocks. Additional operational
flexibility is provided with a steam turbine which can be disconnected, using a
synchronic-self-shifting (SSS) Clutch for start up or for simple cycle
operation of the gas turbine.
Multi-shaft systems have one or more gas
turbine-generators and HRSGs that supply steam through a common header to a
separate single steam turbine-generator. In terms of overall investment a
multi-shaft system is about 5% higher in costs.
Single- and
multiple-pressure non-reheat steam cycles are applied to combined-cycle systems
equipped with gas turbines having rating point exhaust gas temperatures of
approximately 540 °C or less. Selection of a single- or multiple-pressure
steam cycle for a specific application is determined by economic evaluation
which considers plant installed cost, fuel cost and quality, plant duty cycle,
and operating and maintenance cost. Multiple-pressure reheat steam cycles are
applied to combined-cycle systems with gas turbines having rating point exhaust
gas temperatures of approximately 600 °C.
The
most efficient power generation cycles are those with unfired HRSGs with
modular pre-engineered components. These unfired steam cycles are also the
lowest in cost. Supplementary-fired combined-cycle systems are provided for
specific application. The primary regions of interest for cogeneration
combined-cycle systems are those with unfired and supplementary fired steam
cycles. These systems provide a wide range of thermal energy to electric power
ratio and represent the range of thermal energy capability and power generation
covered by the product line for thermal energy and power systems.
2.5 FUEL FOR COMBINED CYCLE
POWER PLANTS
The turbines used in Combined Cycle Plants are
commonly fuelled with natural gas , which is found in abundant reserves on
every continent. Natural gas is becoming the fuel of choice for private
investors and consumers because it is more versatile than coal or oil and can
be used in 90% of energy applications.
Where the extension of a gas pipeline is
impractical or cannot be economically justified, electricity needs in remote
areas can be met with small scale Combined Cycle Plants, using renewable fuels.
Instead of natural gas, Combined Cycle Plants can be filled with biogas derived
from agricultural and forestry waste, which is often readily available in rural
areas.
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. Bio fuels
can also be used. Integrated solar combined cycle power stations combine the energy
harvested from solar radiation with another fuel to cut fuel costs and
environmental impact. 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.
Low-Grade Fuel for Turbines: Gas turbines burn mainly natural gas and light
oil. Crude oil, residual, and some distillates contain corrosive components and
as such require fuel treatment equipment. In addition, ash deposits from these
fuels result in gas turbine debating’s of up to 15 percent they may still be
economically attractive fuels however, particularly in combined-cycle plants.
Sodium and potassium are removed from residual,
crude and heavy distillates by a water washing procedure. A simpler and less
expensive purification system will do the same job for light crude and light
distillates. A magnesium additive system may also be needed to reduce the
corrosive effects if vanadium is present. Fuels requiring such treatment must have
a separate fuel-treatment plant and a system of accurate fuel monitoring to
assure reliable, low-maintenance operation of gas turbines.
2.6 GAS TURBINE
COMBINED-CYCLE FEATURES
The combination of the gas turbine Brayton Cycle
and the steam power system Rankine Cycle complement each other to form
efficient combined-cycles. The Brayton Cycle has high source temperature and
rejects heat at a temperature that is conveniently used as the energy source
for the Rankine Cycle. The most commonly used working fluids for combined
cycles are air and steam. Other working fluids (organic fluids, potassium
vapor, mercury vapor, and others) have been
applied on a limited scale. Combined-cycle systems that utilize steam and air-working fluids have
achieved widespread commercial application due to:
·
High thermal efficiency through application of two complementary
thermodynamic
cycles.
·
Heat rejection from the Brayton Cycle (gas turbine) at a temperature
that can be utilized in a simple and efficient manner.
·
Working fluids (water and air) that are readily available, inexpensive,
and nontoxic.
These
combined-cycle systems provide flexibility with features that include:
1. High Thermal Efficiency – Combined cycle thermal efficiency is higher than that of other
conventional power generation systems.
2. Low Installed Cost - Combined-cycle equipment is pre-engineered and
factorypackaged to minimize installation time and cost. All major equipment
(gas turbine generator, heat recovery steam generator [HRSG], and steam turbine
generator) is shipped to the field as assembled and tested components.
Auxiliary
equipment, such as condensers, can be shipped factory-tubed and hydrotested. This
greatly reduces the inventory of parts that must be managed in the field and
minimizes installation cost. Combined-cycle equipment cost is higher than that
for conventional steam plants due to pre-engineering; however, combined-cycle
plant installation costs are significantly lower, resulting from the reduced
installation cycle.
3. Fuel Flexibility - Combined-cycle plants operate efficiently by
burning a wide range of
fuels, ranging from clean natural gas and distillate oil fuels to ashbearing crude
oil and residual oil fuels. Operation with coal-derived gas fuels has been
applied in many commercial-size, combined-cycle systems.
4. Flexible Duty Cycle - Combined-cycle systems provide flexibility in
operation for both base load and mid-range duty with daily start up. Gas
turbines in multishaft, combined-cycle configuration can be started quickly,
bringing about two thirds of plant power on-line,
typically in less than 60
minutes. Combined-cycle plants also provide efficient operation at part load,
particularly for multiple gas turbine combined-cycle systems. This is
illustrated by the variation in plant output with variation in plant heat rate
curve shown for a General Electric STAG 209E system.
STAG 209E combined cycle part load performance
Modulating compressor inlet guide vanes are standard
features of many gas turbine models, enabling high efficiency operation at part
load through reduction in turbine airflow. This is accomplished at nearly
constant turbine exhaust temperature, so that design steam conditions and low
stack loss can be maintained to provide excellent part-load efficiency.
5. Short-Installation Cycle – Combined cycle plants can be installed and operated
in less time than that required for conventional steam plants. Again, this is
primarily due to the pre-engineering and packaging of major components in the factory. Phased installation of
the plant, when gas turbines are installed and operated in the simple-cycle
mode during the steam-cycle equipment installation, enables the user to
generate power and revenue in as little as a year from order date.
6. High Reliability/Availability – High reliability operation results from evolutionary
design development that improves parts and components, and quality
manufacturing programs that offer operational factory testing. High availability
is achieved through development of sound operation and maintenance practices,
which reside principally with the user. Manufacturer experience and
recommendations also contribute to this feature.
7. Low Operation and Maintenance Costs - Low operation and maintenance
costs are achieved
through quality design, prudent operation, and equipment design that allow
convenient access for component inspection.
8. High Efficiency in Small Capacity Increments - Gas turbine generators are designed and
manufactured in discrete frame sizes. For example, the General Electric
heavy-duty, gas turbine-packaged power plant product line includes the MS6001B
(50 Hz and 60 Hz), MS7001FA (60 Hz), MS7001B (60 Hz) and the MS9001FA (50 Hz)
units, which cover an output range of approximately 37 MW to 250 MW. Application
of these gas turbine models in combined-cycle systems as
single or multiple gas
turbine and HRSG installations can provide from about 50 MW to several thousand
megawatts of power generation at essentially constant plant
thermal efficiency.
2.7 EFFICIENCY OF CCGT
PLANTS
In general, Combined Cycle efficiencies are over
50 percent on lower heating value and Gross Output basis.
Most combined cycle units, especially the larger units, have peak, steady state
efficiency of 55 - 59%. Research aimed at 1370°C (2500°F) turbine inlet
temperature has led to even more efficient combined cycles and 60 percent
efficiency has been reached for at least one combined cycle unit, (e.g. the
combined cycle unit of Baglan Bay, a GE H-technology gas turbine with
a NEM 3 pressure reheat boiler. Utilising steam from the HRSG to cool the
turbine blades). Other GT manufacturers also claim to have broken the 60%
efficiency for combined cycle (e.g. Siemens).
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 condensers 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 actual efficiency achievable is a complex area.
The electric efficiency of a combined cycle
power station, calculated as electric energy produced as a percent of the lower heating value of the fuel consumed, may
be as high as 58 percent when operating new, ie un aged, and at continuous
output which are ideal conditions. As with single cycle thermal units, combined
cycle units may also deliver low temperature heat energy for industrial
processes, district heating and other uses. This is called
cogeneration and such power plants are often referred to as a Combined Heat and
Power (CHP) plant.
BOOSTING
EFFICIENCY
The efficiency of CCGT and GT can be boosted by
pre-cooling combustion air. This is practiced in hot climates and also has the
effect of increasing power output. This is achieved by evaporative cooling of
water using a moist matrix placed in front of the turbine, or by using Ice storage air conditioning. The latter
has the advantage of greater improvements due to the lower temperatures
available. Furthermore, ice storage can be used as a means of load control or
load shifting since ice can be made during periods of low power demand and,
potentially in the future the anticipated high availability of other resources
such as renewables during certain periods.
2.8 EMISSION CONTROL
As
with the combustion process, the exhaust from the gas turbine contains elements
that have been deemed as pollutants. The main emission products of the concern
are:
·
Nitrogen oxides(Nox)
·
Carbon monoxide (CO)
·
Volatile Hydrocarbon
Compounds(VHC)
·
Sulphur oxide(Sox)
·
Particulate Matter(PM)
FORMATION:
Nitrogen
oxides:
Nitrogen oxides (NOx =
NO + NO2) must be divided into two classes according to their mechanism of
formation. Nitrogen oxides formed from the oxidation of the free nitrogen in
the combustion air or fuel is called “thermal NOx.” They are mainly a function
of the stoichiometric adiabatic flame temperature of the fuel, which is the
temperature reached by burning a theoretically correct mixture of fuel and air
in an insulated vessel.
The
following is the relationship between combustor operating conditions and
thermal NOx production:
·
NOx increases strongly
with fuel-to-air ratio or with firing temperature
·
NOx increases
exponentially with combustor inlet air temperature
·
NOx increases with the
square root of the combustor inlet pressure
·
NOx increases with
increasing residence time in the flame zone
·
NOx decreases
exponentially with increasing water or steam injection or
increasing
specific humidity.
Emissions which are due to oxidation of
organically bound nitrogen in the fuel—fuel-bound nitrogen (FBN)—are called
“organic NOx.”Only a few parts per million of the available free nitrogen
(almost all from air) are oxidized to form nitrogen oxide, but the oxidation of
FBN to NOx is very efficient. It is important to note that the reduction of
flame temperatures to abate thermal NOx has little
effect on organic NOx. For liquid fuels, water and steam injection actually
increases organic NOx yields. Organic NOx formation is also affected by turbine
firing temperature. The contribution of organic NOx is important only for fuels
that contain significant amounts of FBN such as crude or residual oils. Low-Btu
gases generally have flame temperatures below 3500°F/1927°C and correspondingly
lower thermal NOx production.
Carbon Monoxide:
Because of the very short loading sequence of gas turbines, there are the chances for the emission of carbon monoxide (CO).
Variation of CO in gas
turbine exhaust along with firing temperature
As
firing temperature is reduced below about 1500°F/816°C the carbon monoxide
emissions increase quickly. This Figure characteristic curve is typical of all heavy-duty machine
series.
Unburned Hydrocarbons:
Unburned hydrocarbons (UHC), like carbon
monoxide, are associated with combustion inefficiency. At all but very low
loads, the UHC emission levels for No. 2 distillate and natural gas are less
than 7 ppmvw (parts per million by volume wet).
Variation of UHC in gas turbine exhaust along with firing temperature
The gas turbine itself does not generate
sulphur, which leads to sulphur oxides emissions. All sulphur emissions in the
gas turbine exhaust are caused by the combustion of sulphur introduced into the
turbine by the fuel, air, or injected steam or water. However, since most
ambient air and injected water or steam has little or no sulphur, the most
common source of sulphur in the gas turbine is through the fuel. Due to the
latest hot gas path coatings, the gas turbine will readily burn sulphur
contained in the fuel with little or no adverse effects as long as there are no
alkali metals present in the hot gas. The sulphur in the fuel is completely
converted to sulphur oxides. A nominal estimate of the sulphur oxides emissions
is calculated by assuming that all fuel sulphur is converted to SO2. However, sulphur
oxide emissions are in the form of both SO2 and SO3, reports show that 95% of
the sulphur into the turbine is converted to SO2 in the exhaust. The remaining sulphur
is converted into SO3. SO3 combines with water vapour in the exhaust to form sulphuric
acid. This is of concern in most heat recovery applications where the stack
exhaust temperature may be reduced to the acid dew point temperature.
Additionally, it is estimated that 10% by weight of the SOx generated is sulphur
mist. Control of sulphur oxides emissions has typically required limiting the sulphur
content of the fuel, either by lower sulphur fuel selection or fuel blending
with low sulphur fuel.
Particulates :
Gas turbine exhaust particulate emission
rates are influenced by the design of the combustion system, fuel properties
and combustor operating conditions. The principal components of the
particulates are smoke, ash, ambient noncombustibles, and erosion and corrosion
products.Two additional components that could be
considered
particulate matter in some localities are sulphuric acid and unburned
hydrocarbons that are liquid at standard conditions.
EMISSION REDUCTION TECHNIQUES:
Emission Reduction Techniques
The gas turbine, generally,
is a low emitter of exhaust pollutants because the fuel is burned with ample
excess air to ensure complete combustion at all but the minimum load conditions
or during start-up. The exhaust emissions of concern and the emission control
techniques can be divided into several categories as shown. Each pollutant emission
reduction technique will be discussed in the following sections.
Lean Head End (LHE) Combustion Liners:
Since the overall combustion system
equivalence ratio must be lean (to limit turbine inlet temperature and maximize
efficiency), the first efforts to lower NOx emissions were naturally directed
toward designing a combustor with a leaner reaction zone. Since most gas
turbines operate with a large amount of excess air, some of this air can be
diverted towards the flame end, which reduces the flame temperature.
LHE Combustion Liners
Leaning out the flame zone (reducing the flame
zone equivalence ratio) also reduces the flame length, and thus reduces the
residence time a gas molecule spends at NOx formation temperatures. Both these
mechanisms reduce Ox. The principle of a LHE liner design is shown in Figure
8. It quickly became apparent that the reduction in primary zone
equivalence ratio at full operating conditions was limited because of the large
turndown in fuel flow (40 to 1), air flow (30 to 1), and fuel/air ratio (5 to
1) in industrial gas turbines. Further, the flame in a gas turbine is a
diffusion flame since the fuel and air are injected directly into the reaction
zone. Combustion occurs at or near stoichiometric conditions, and there is
substantial recirculation within the reaction zone. These parameters essentially
limit the extent of LHE liner technology to a NOx reduction of 40% at most. One
disadvantage of leaning out the head end of the liner is that the CO emissions
increase.
Water/Steam Injection:
Another approach to reducing NOx
formation is to reduce the flame temperature by introducing a heat sink into
the flame zone. Both water and steam are very effective at achieving this goal.
A penalty in overall efficiency must be aid for the additional fuel required to
heat the water to combustor temperature. However, gas turbine output is
enhanced because of the additional mass flow through the turbine. By necessity,
the water must be of boiler feedwater quality to prevent deposits and corrosion
in the hot turbine gas path
area downstream of the combustor. Water injection is an extremely effective
means for reducing NOx formation; however, the combustor designer must observe
certain cautions when using this reduction technique. To maximize the
effectiveness of the water used, fuel nozzles have been designed with
additional passages to inject water into the combustor head end. The water is
thus effectively mixed with the incoming combustion air and reaches the flame
zone at its hottest point. Other machines have similar NOx abatement
performance with water injection. Steam injection for NOx reduction follows
essentially the same path into the combustor head end as water. However, steam
is not as effective as water in reducing thermal NOx. The high latent heat of
water acts as a strong thermal sink in reducing the flame temperature. In
general, for a given NOx reduction, approximately 1.6 times as much steam as
water on a mass basis is required for control. There are practical limits to
the amount of water or steam that can be injected into the combustor before
serious problems occur. This has been experimentally determined and must be
taken into account in all applications if the combustor designer is to ensure
long hardware life for the gas turbine user.
Carbon Monoxide Control:
There are no direct carbon
monoxide emission reduction control techniques available within the gas
turbine. Basically the carbon monoxide emissions within the gas turbine
combustor can be viewed as resulting from incomplete combustion. Since the
combustor design maximizes combustion efficiency, carbon monoxide emissions are
minimized across the gas turbine load range of firing temperatures. The carbon monoxide emission levels increase
at lower firing temperatures. In some applications where carbon monoxide
emissions become a concern at low loads (firing temperatures).
The increase in carbon monoxide can be lowered by:
·
reducing
the amount of water/steam
·
injection for NOx
control (if allowed)or
·
Closing the inlet guide vanes, this will
increase the firing temperature for the same load.
Unburned Hydrocarbons Control:
Similar
to carbon monoxide, there is also no direct UHC reduction control techniques
used within the gas turbine. UHCs are also viewed as incomplete combustion, and
the combustor is designed to minimize these emissions. The same indirect
emissions control techniques can be used for unburned hydrocarbons as for
carbon monoxide.
Particulate and Smoke Reduction:
Control
techniques for particulate emissions with the exception of smoke are limited to
control of the fuel composition. Although smoke can be influenced by fuel
composition, combustors can be designed which minimize emission of this
pollutant. Heavy fuels such as crude oil and residual oil have low hydrogen
levels and high carbon residue, which increase smoking tendencies. Crude and
residual fuel oil generally contain alkali metals (Na, K) in addition to
vanadium and lead, which cause hot corrosion of the turbine nozzles and buckets
at the elevated firing temperatures of today's gas turbine. If the fuel is
washed, water soluble compounds (alkali salts) containing the contaminants are
removed. Filtration, Centrifuging, or electrostatic precipitations are also
effective on reducing the solid contaminants in the combustion products.
Contaminants
that cannot be removed from the fuel (vanadium compounds) can be controlled
through the use of inhibitors. Magnesium is used to control vanadium corrosion
in its heavy-duty gas turbines. These magnesium additives always form ash
within the hot gas path components. This process generally requires control and
removal of added ash deposits from the turbine. The additional ash will
contribute to the exhaust particulate emissions. Generally, the expected
increase can be calculated from an analysis of the particular fuel being
burned. In some localities, condensable compounds such as SO3 and condensable hydrocarbons
are considered particulates. SO3, like SO2, can best be minimized by
controlling the amount of sulphur in the fuel. The major problem associated
with sulphur compounds in the exhaust comes from the difficulty of measurement.
Emissions of UHCs, which are a liquid or solid at room temperature, are very
low and only make a minor contribution to the exhaust particulate loading.
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