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Combined-cycle power plant.

The Combined Cycle Power Plants, developed by Combining Gas and Steam Turbines in one system, has much higher efficiency levels than conventional thermal power plants by virtue of exploiting exhaust heat from the gas turbines on a very large temperature range whilst retaining a simple arrangement of water/steam cycle. For this type of power plant, Siemens AG has developed power plant concepts which provide for the possibility of later constructing the steam turbine section of the power plant, a short construction and assembly period and low construction costs.

Utilization of Waste Heat from Gas Turbines

The temperature of the exhaust gas leaving the gas turbine is around 540 |degrees~ C at full load. The thermal energy in this exhaust gas, namely the so-called waste heat, can be exploited in various ways. Which of the many technical solutions is adopted depends upon the prevailing conditions and economic considerations.

Apart from exploitation of exhaust heat in Combined Cycle Power Plants, best known industrial & domestic uses for exhaust gas heat are:

* Space and district heating of private housing, offices, public building and trade premises by means of steam or hot water.

* Industrial-process heat in the form of steam (process steam) to industrial enterprises, e.g. sugar industry and kiln-drying of wood or paper.

* Distillation of drinking water and extraction of raw materials from sea water. These processes are of particular interest in coastal regions of arid countries with sparse fresh-water sources. Steam from the gas turbine power plant can be supplied to multistage desalination equipment, in which the sea water is evaporated and condensed to produce distilled water. The addition of chemicals renders this desalinated water suitable for either drinking or irrigation purposes. Furthermore, other substances, such as salt, magnesium, cement and calcium, can be obtained by additional precipitation or electrolytic processes with the aid of electric energy from the power plant.

Exploitation of Exhaust Heat in Combined Cycle Power Plants

In addition to being used for offsite application as already described, waste heat from gas turbines can be even more efficiently exploited in combined-cycle power plants which employ gas and steam power systems generating electrical energy.

Fully Fired Combined Cycle Power Plants

In this type of power plant, the gas turbine exhaust gas containing about 15% residual oxygen is fed as hot combustion air to the furnace of a boiler supplying steam to a conventional steam turboset generating electric power. The overall efficiency of such a plant can reach approximately 4.5% and the optimum output ratio of the gas to the steam turbine lies between roughly 1:3 and 1:4.

The overall efficiency can be enhanced by using three-pressure steam turbines, boiler with several reheat stages and feed water preheating systems. Higher total plant outputs are therefore advisable even by using other fuels like oil or coal for the fired steam boilers.

GUD(*) Unfired Combined-Cycle Power Plants

GUD(*) is the German acronym for "Gas Und Dampf" meaning "gas and steam". Such unfired combined-cycle installations employ heat exchangers, also referred to as unfired heat-recovery boilers, to extract heat from the gas to raise high-pressure steam. This steam drives a steam turboset to generate additional electric power.

Compared to conventional steam power plants, with efficiencies in the range of about 42 to 45%, and gas turbine power plants, with efficiencies between 33 and 36% the overall efficiency of a GUD(*) combined cycle power plant can be 52% and higher. The ratio of gas to steam turbine capacity lies around 60:40. GUD(*)

Normally steam turbines used with unfired boilers are two pressure turbines, the boilers can be single pressure. To enhance plant efficiency double or triple pressure boilers with reheating and feed water preheating can be used. The decision to do that depends on financial comparison of higher initial investment cost versus higher efficiency and power output/income during commercial operation.

To further optimize the investment cost versus running cost the mostly used configuration of two gas turbines providing steam to one steam turbine (2+1) through heat recovery steam boilers can be replaced by a 3 + 1 (3 Gas Turbines + 1 Steam Turbine) configuration thus saving cost in the area of civil construction and the steam/feed water/water treatment plant.

Gas Turbines for Power Generation

A gas turbine consists primarily of a compressor, combustion chambers and the turbine itself. The compressor takes in air from the surrounding atmosphere, compresses it to 10 to 16 bar and delivers it to the combustion chambers. The fuel, e.g. natural gas and/or oil, is injected through nozzles into the combustion chambers, where it is burnt after mixing with the compressed air. The resulting high-pressure combustion gas with a temperature of more than 1000 |degrees~ C flows from the combustion chambers into the turbine where it expands. This expansion work drives the turbine which inturn drives the compressor and the coupled generator. The useful electric power output is made available at the generator terminals.

The perspective drawing gives an impression of the machine construction. A cut away section (a 90 degree sector) of the outer casing reveals the rotating assembly (rotor)carrying the moving blades of the compressor (13) and of the turbine (10).

The common outer casing of the compressor and the turbine consists of three sections: the inlet casing (3), the center casing (6) and the exhaust casing (7). The center casing supports the stationary blade carriers (12). (The stationary binding produces the required change in the direction of the air or gas flow after each row of moving blades.) Control and protection equipment (15), as well as a hydraulic turning gear are located at the air-intake end.

The two combustion chambers (5) stand upright on both sides of the turbine and are attached to the casing by means of curved-elbow connections. Each combustion chamber is equipped with several burners (4). The internal surfaces the combustion chambers exposed to the highest temperature levels, i.e. the flame cylinders, are lined with refractory ceramic tiles. The hot gas enters the turbine proper through the inner casing (11).

The rotor is supported by two bearings (9, 14). The front bearing (14)is a combined thrust and journal bearing, i.e. it also accommodates axial loads. Both bearings, and hence the rotor, are centered and borne by radial ribs (2, 8) belonging to the outer casing. Intake air to the compressor and exhaust gas from the turbine flow over these hollow ribs which house the oil-supply pipes to the bearing housings. The generator is directly coupled to the shaft flange (16) at the compressor end.

The rotor consists of disks each carrying a row of moving blades, a hollow drum section and two end sections. All these elements are splined tightly together by.means of "Hirth teeth" or serration's on their outer-diameter mating faces and a pre stressed central through bolt. Torque is transmitted by the radial-tooth splines which do not restrain radial movement due to thermal expansion and centrifugal forces. This design offers the advantage of great rotor stiffness despite relatively low mass (no necessity for a mid-bearing) and permits internal cooling of the rotor.

The roots and profiles of the blades in the first rows of the turbine binding are also internally cooled. This is accomplished by diverting a small proportion of the compressed air through the central hollow drum section of the rotor to the blade roots and into passages within the hollow blade profiles. This cooling air finally exits through small apertures along the trailing edges of the blades into the hot-gas flow through the turbine.

The generator is designed to act also as a motor in order to be able to start up the gas turbine because the turbine can only deliver power to drive its compressor when a certain shaft speed has been attained. For this purpose state of the art static frequency converters are applied. If a gas turbine power plant is required to run in isolation (island operation), a diesel-engine generator is provided to produce the power to start up the gas turbine independently of any external electric power system.

Most modern gas turbine design reaches efficiency factors of 36% which yield to combined cycle efficiencies of up to 55%. This is obtained by increasing the inlet temperature to 1100 |degrees~ C and above, by increasing the compressor pressure and by optimizing the burner design.

Fuels for Gas Turbines

Although gas turbines are best run with natural gas, newer developments allow multifuel operation (gas, HSD or furnace oil). Higher investment costs are required if furnace oil is used and the plant efficiency is also reduced. This is mainly due to the additional systems which are required to remove sodium and potassium from the oil and to use inhibitor to protect the gas turbine from vanadium attacks.

The efficiency is reduced on furnace oil operation as the inlet temperature of the gas turbine has to be reduced due to some chemical processes which take place above certain temperature limits.

The integration of a coal-gasification process into a GUD(*) power plant offers the possibility of converting coal into electric energy with minimum environmental impact. This type of installation may therefore play an important role in curing air pollution in future.

Environmental Hazards and Design Features

The increasing environmental requirements to reduce pollution have; yielded to the design shown in Fig. 3 where in the 150 MW - model gas turbine, two offboared combustion chambers are provided, equipped with 8 burners each. Sufficient space is available in these chambers to allow complete combustion and to minimize NOx production. Under normal circumstances the exhaust gas is absolutely free of soot and thus invisible.

The fact that the exhaust gas is clear does not, however allow anything to be concluded about its NOx content because NO is completely invisible and N|O.sub.2~ can be seen as a brownish-yellow haze against a cloudy sky only when its concentration exceeds about 30 mg/|m.sup.3~. The legislation passed in many countries over the past few years to restrict NOx emissions requires the introduction of a new combustion control for gas turbines employing primary (preventive) measures in order to limit the thermal NOx production.

There are two different sources of NOx. The oxidation of organic nitrogen compounds bonded in the fuel, such as ammonia in gaseous fuels or notrogenous-hydrogen compounds in liquid fuels, is unavoidable. The thermal formation of NOx (NO and N|O.sub.2~) from the high temperature reaction between the nitrogen and the oxygen in the intake air is considerably more serious in quantitative terms because the compressor mass flow is more than 50 times the fuel consumption. The thermal NOx production can, however, be effectively reduced by lowering the flame temperature.

The Diffusion Burner

It is an established fact that the flame temperature can be lowered by injecting water or steam into the combustion zone. If, for example, steam is added in 1:1 proportion to fuel oil consumption, the NOx emissions at full load can be reduced by approximately four-fifths to about 110 mg/|m.sup.3~. (This mass concentration, like all the NOx values given below, refers to dry exhaust at standard conditions with 15% oxygen by volume). Even lower NOx emissions can be obtained with naturalgas firing. particularly if sufficient steam is mixed with the gas before it enters the combustion chambers.

The Premix Burner

The main disadvantage of wet NOx control is, of course, the large requirement for demineralized water. For this reason, Siemens developed a premix burner with which extremely stringent NOx emission requirements can be met with natural-gas firing without the necessity for water or steam injection (dry control). In premix burners, a highly homogeneous fuel/air mixture is produced in a promixing zone before it is combusted. Since the resultant flame exhibits a much more uniform temperature distribution at a greatly reduced temperature level, the NOx production values are extremely low.

Pure premix burners have the disadvantage that their stability range is very narrow. The operating range of such premix burners is considerably narrower than is required to operate a gas turbine over the entire range from no load to full load.

The Siemens Hybrid Burner

Siemens solved this problem by introducing a complex burner control system which, on load changes, would cut in or cut out the fuel supply to individual burners in order to maintain an excess air coefficient within the narrow allowable range at the burners still being supplied with gas.

Preference was given to a solution in which a pilot flame is used to stabilize each premixed flame, thus considerably extending its stability range.

It was on the basis of this principle that a burner was developed which can function with natural gas either as a diffusion burner or as a premix burner. It is consequently called a hybrid burner. It can be operated in the diffusion mode from start-up to 85% base load when it can be switched over to the premix mode to cover the upper load range. This avoids the necessity of switching off any burners. Fig. 4 illustrates the design of a burner of this type. It has three gas nozzle systems:

1. Diffusion-burner nozzles

2. Premix-burner nozzles

3. Pilot-burner nozzles (for premix operation)

Ball cocks outside the combustion chambers change over from one set of nozzles to the other. In order to permit the combustion of liquid fuels too, each burner is fitted with a central oil burner lance. By means of an additional nozzle system, which injects water or steam into the diffusion flames, the NOx emissions are restricted to a low level over the entire operating range with oil.

The operating range of the premix burners can be extended by reducing the combustion air flow in proportion to the fuel flow. For this purpose, a shutter ring is provided in the region of the dilution air ports in the flame cylinder of each combustion chamber. This ring can be turned to open or to close the dilution air ports, thus altering the ratio of combustion air to dilution air. It is, therefore, possible, within a certain load range, to maintain the NOx and CO values at a minimum level. This means that the changeover from the diffusion flame to premix flame mode can be made before 85% base load is reached.

A further extension of the premix flame operating mode range can be achieved if the compressor mass flow is altered by adjusting the variable-pitch initial guide vanes (IGV). By closing the IGV, the compressor mass flow can be reduced to 85% maximum flow. As a result, the machine output drops to 70% base load and the fuel flow to 83% without any change in turbine exhaust temperature which is particularly important for good combined cycle partial-load performance. In this load range, then, the required fuel mass flow changes almost proportionally with the compressor mass flow.

Commercial and Operational Aspects

A gas turbine power plant can deliver electric power to the grid within only a few minutes of being started up. This is its principal advantage over a steam turbine power plant which needs several hours to come on stream.

For this reason, gas turbine power plants are able to fulfil the special power generation task of supplying peak-load demand. Today's gas turbine power plants are also built especially for continuous duty in base-load operation. By comparison with other power plants they require lower capital investment and occupy less space.

If gas is available as fuel the GUD(*) plant is by far more cost effective, efficient and cheaper in investment as compared to the "conventional" thermal plant by guaranteeing low environmental pollution. The erection can be done in two steps with the gas turbine coming on line in less than 20 months and the steam turbine approximately 1 year later.

* Registered Trade Mark of Siemens AG for Combined Cycle Power Plants
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Title Annotation:featuring Siemens AG product
Author:Martin, H.D.
Publication:Economic Review
Date:Sep 1, 1993
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