The Västerås CHP plant consists of four units using oil and pulverised coal as fuel. The plant is now adding a fifth boiler to burn biomass, which is due to start operation in late 2000. Jan Westin, MälarEnergi, Västerås, Sweden, and Ilkka Venäläinen, Foster Wheeler Energia Oy, Varkaus, Finland.
The CHP plant at Västerås city is one of the largest and oldest CHP plants in Sweden. It consists of four existing units operated with oil and pulverised coal as fuel. Total capacity is 500 MWe and 900 MWth. Coal has been the main fuel, producing about 65 per cent of the heat production. Unit 4 was converted from oil to pulverised coal firing in 1983, with downrating of the unit capacity to 155 MWe/250 MWth.
The plant is now constructing a new boiler to burn biomass. This boiler will be connected to the existing turbine, steam, condensate and feed water systems of unit 4. The introduction of this boiler will allow the plant operators to replace 120 000 tonnes per year of coal with 1.1 million m3 per year of biomass, reducing CO2 emissions by 340 000 tonnes per year.
Foster Wheeler was selected as a turnkey supplier to construct the new boiler. The delivery includes a circulating fluidised bed (CFB) boiler. Start-up is scheduled for December 2000.
CFB boiler
Foster Wheeler’s Compact CFB design was selected for the new boiler. The key feature of this design is its solids separator, which is fabricated with straight panel walls. These straight panels are used in both the hot separator and in the solids return channels. The use of panel walls in the separator is based on its rectangular configuration as shown in Figure 1. Gas and solids flow into the separator from the combustion chamber through an inlet channel, and gas flows out of the separator through cylindrical vortex finders. The separated solids fall to the bottom of the device and are returned to the furnace.
The gas flow in the separator is a swirling vortex type, despite the rectangular cross section of the separator. Due to the centrifugal effect, solid particles are swept to the separator walls and continue to flow along the wall surface. In the corners of the separator, the particles form dense streams of solids. This promotes particle stream separation and helps the particles fall to the bottom of the separator for return to the furnace.
In the return channel, the gas seal system is made with a cooled membrane structure, which requires minimal space and in which the amount of refractory is minimised. This new design has many advantages, derived from the cooled panel wall structure used for the whole CFB system. The cooled structure of the separator and the solids return channel also minimises the different thermal expansions between combustion chamber and separator, minimising or eliminating the need for expansion joints.
Additionally, only thin refractory lining is needed, resulting in shorter start-up times, which are no longer limited by the refractory heating rate. Less and thinner refractory also means reduced maintenance.
INTREXTM heat exchanger
Foster Wheeler has developed an innovative heat exchanger design which can be used to produce steam in a CFB-based power plant.
The integrated heat exchanger (INTREX) uses hot solid material returned from the separator or solids taken from the furnace to the heat exchanger as shown in Figure 2. The integrated heat exchanger can replace in-furnace superheaters or be part of the evaporative surface with more efficient heat transfer surface. This arrangement allows the furnace size to be smaller and simplifies the arrangement of different surfaces such as superheaters and reheaters. The design of the integrated heat exchanger also provides means for heat transfer control, which allows control of furnace temperature to optimise emissions and combustion over a wide load range, or for a range of fuels with different calorific values.
Hot solid material is fluidised in the heat exchanger with air at low fluidising velocities. Fluidising gas is allowed to flow to the furnace from the top of the heat exchanger chamber. For the recirculated solid material from the separator, a simple gas seal is used between the separator and the chamber. The gas seal is constructed within the cooled vertical panel structure. Erosion, which is a risk in conventional bubbling bed boilers, is negligible due to much smaller particle sizes and the low but still effective fluidising velocity.
If the fuel contains harmful impurities, the return line of the solids separator decreases the concentration of impurities entering the region of the heat transfer surface, thus reducing potential for corrosion. The fact that the superheater tubes are inside the solids will significantly reduce the corrosion rate of the steel.
Various designs have been studied and the design parameters analysed, first in cold models and then in hot pilot units during several test run periods. The first commercial INTREX superheater was installed in the Nelson Industrial Steam Company Cogeneration Facility in Westlake, Louisiana. Six other commercial units with INTREX superheaters have been delivered to Denmark, Germany, Poland and Sweden.
INTREX has the following features:
Heat exchange from solid bed material to tube surface.
High heat transfer rate.
Smaller heat transfer area than in conventional gas to solid heat exchangers.
Heat transfer rate can be controlled.
Simple design.
No moving parts.
Resistant to erosion.
Low erosion rate due to low velocities.
Resistant to corrosion.
Tube corrosion rate reduced by environment.
In the Västerås boiler, both the high temperature superheater and reheater are INTREX heat exchangers, reducing the risk of chlorine-induced corrosion and fouling.
Fuels
The new CFB boiler (Figure 3) can fire a broad range of fuels (see table above) from different kinds of biomass to coal. The design is based on achieving full load with biomass fuels as well as when cofiring biomass and coal. With coal firing alone, 50 per cent load is achieved. There are provisions to increase coal-firing capacity to full load later if that becomes desirable.
Additionally, small amounts of recycled wood and fast growing biomass (eg, willow) will be used as supplementary fuels. Light fuel oil will be used as start-up fuel.
Emission control
The Swedish emission taxation regime for NOx and SO2 has made it necessary to strive for low emission levels. As a result, the new CFB boiler is designed to meet very low emission levels. NOx emission is controlled with ammonia injection into the particle separator. There is a small catalyst layer in the convective pass to reduce ammonia use and further reduce NOx emissions.
As the main fuel is various forms of low-sulphur biomass, limestone feeding for SO2 is not required. However, limestone-feeding equipment is provided as a provision for use with higher sulphur content fuels such as peat and coal.
Dust emissions are controlled with a fabric filter.
Flue gas condensing plant
A flue gas condensing plant is located after the boiler to further cool down the flue gases. In the first stage of the condensing plant, the flue gases are cooled by district heating water in a scrubber. After this stage, the flue gas temperature is approximately 65°C, and most of the water vapour is condensed.
In the second stage, the flue gases are further cooled with combustion air in a regenerative air heater. The heat is transferred from the flue gases by a rotating heat transfer surface, which heats and humidifies the combustion air up to 100 per cent relative humidity. Thereafter, combustion air is heated to 90°C to prevent water condensing in air ducts.
After the two-stage condensing plant, the flue gas temperature is approximately 35°C, and the water vapour is, a large extent, condensed. The heat input to the district heating water is 42.5 MW.
Connection with existing power plant
A unique feature of this project is connecting a once-through boiler and a natural circulation boiler, both with reheat, to a common turbine, see Figures 4 and 5. To address this challenge, the parallel operation of the two boilers was analysed in separate work groups formed by the owner and the supplier in an early stage of the project. The following main areas of concern were identified:
Water chemistry (oxygenated for boiler 4 versus alkali for boiler 5).
Connection of feed water pumps and HP feed water heaters.
Connecting main steam flows and reheat steam flows to the common turbine.
Dividing cold reheat steam flows to units 4 and 5.
Water chemistry
The existing boiler 4 has been operated with oxygenated feed water for a decade, and experience has been good. As a result, there was a requirement not to change water chemistry for boiler 4. However, operating the drum-type unit of boiler 5 with oxygenated feed water was unsuitable due to higher conductivity of boiler water and consequent corrosion risks. It was decided to change the location of the oxygen dosing to the inlet of the feed water pumps of boiler 4 to be able to continue operations with oxygenated feed water. However, the feed water tank, common to both boilers, will have deaeration, and boiler 5 will be fed with oxygen-free feed water.
Feed water pumps
Required feed water pressure for the two boilers is very different. Boiler 4 has a large pressure drop at full load due to the once-through boiler. The pressure drop across boiler 5 is much smaller, giving a lower required feed water pressure.
It was decided to provide a dedicated new feed water pump for boiler 5, designed for 100 per cent capacity. Thus both boilers have an independent source of feed water, making control of feed water flow easier and optimising the feed water pressure for each boiler.
High pressure feed water heaters
The existing HP heaters have two parallel lines designed for two x 60 per cent of the original capacity of boiler 4. Due to the different water chemistries of boilers 4 and 5, HP heater trails were separated so that one trail is used solely for boiler 4 and the other one for boiler 5. A new bypass line had to be added for HP heaters so that both trails have independent bypass lines.
Main steam connection
Main steam from boiler 5 is led to the existing turbine with one pipe, which then divides into two pipes close to the steam turbine and connected to both steam inlets of the HP turbine. A flow measurement is provided in the main steam line as well as a check valve to prevent back flow of steam.
Reheat steam connection
One of the biggest challenges of this project was to divide the cold reheat steam in correct proportions between boiler 4 and 5. Cold reheat steam from the HP turbine is delivered in two pipes and the reheat steam to boiler 5 is extracted from one of the two pipes. Steam flow measuring devices are installed in the new cold reheat pipe as well as in the existing two pipes for boiler 4. A new control valve was installed in both existing cold reheat pipes for boiler 4. A control valve for the cold reheat pipe to boiler 5 became unnecessary due to higher reheat pressure drop in boiler 5. The division of cold reheat steam flow is controlled in proportion to the measured main steam flows from boiler 4 and boiler 5.
There are alarms and interlocks for the reheat steam temperature after the first stage reheater. If the temperature exceeds given limits, the HP bypass will open and provide more steam through the reheater.
Sliding pressure operation
Boiler 4 has been operated with sliding main steam pressure, and the same principle will apply to boiler 5. The steam pressure of boiler 4 varies from 80-171 bar as a function of load. Operating a natural circulation boiler with such a wide pressure range is very rare. It was concluded that operating boiler 5 with a similar pressure range was not possible mainly due to evaporation in economiser and excessive spray water flow. Thus the steam pressure of boiler 5 is limited to 120 bar by a control valve in the main steam line.
Load changes
Boiler 5 is a base loaded boiler and fast load changes are not typically needed. In addition, the turbine is normally controlled according to the heat demand of the district heating net, which changes slowly. With the sliding pressure operation, the load change will also result in a change of the main steam pressure. This leads to variations in water level in the steam drum of boiler 5. The control valve in the main steam line is used to slow down the variations, particularly when load is reduced. Thus the allowed load changes for boiler 5 have been limited to 1-2 per cent of full load per minute.