High reliability is being achieved by the two GT26-based single shaft CCGT blocks at Besós, close to Barcelona
In parallel with privatisation, the Spanish government has made the diversification of fuels a priority for the power generation sector. This is part of its efforts to meet targets established in the Kyoto Protocol, while avoiding too much dependence on hydro, which is sensitive to the vagaries of weather conditions. The share of natural gas in electricity generation is expected to rise dramatically over the next few years, from around 10% in 2002 to some 25% in 2010.
The two GT26 based combined cycle plants at Besós, each 400 MWe, of the KA26-1, single shaft, configuration, can be seen as part of this shift towards natural gas.
Designated units 31 and 41 at Besós (where there were already two old oil/gas fired units), the new CCGTs are each owned by a different company. This demonstrates one potential consequence of the use of the single shaft configuration of combined cycle block: a plant with two units can, in reality, be two separate power stations run by two different companies. Thus it is at Besós in northern Spain, near Barcelona, where one block, unit 31, is owned and operated by Endesa and the other, unit 41, by Gas Natural.
With the reorganisation of the Spanish electricity supply system the generating companies were separated from the national grid and the regional distribution networks. Gas Natural, which supplies gas over the whole of Spain, saw the opportunity to generate electricity at its own power plants. So when in January 2000 the contracts were awarded for Besós and a similar plant at San Roque, 20 km northeast of Gibraltar, it was by a joint venture of Endesa and Gas Natural, each owning and operating a 400 MWe block at each site.
Under this arrangement each block is effectively a separate power station with its own control room and trading arrangements, compressor washing system, static frequency converter system for starting, etc. The only shared facility is the water treatment plant, which at San Roque is managed by Gas Natural, while at Besós it is managed by Endesa.
This dictates the maintenance arrangements. Endesa and Gas Natural each have operation and maintenance contracts with Alstom for the Besós and San Roque power plants.
Gas Natural also owns three more GT26 based CCGT units, in Cartagena, ordered in January 2004, with commercial operation due in 2006.
Since commercial operation was achieved at Besós, in August 2002, performance has been good, with unit 41 reporting an availability of around 97% in its second year of operation, while unit 31 has achieved reliability levels of 99.5% since the beginning of commercial operation, which was in summer 2002. Besós unit 41 also demonstrates the reliability of these units – having recorded continous operation for 163 days and still running at the time of writing.
In fact the five Alstom GT26 gas turbines (two at San Roque, two at Besós and one at Castejon) lead in terms of operating hours among all Spanish combined cycle plants, according to the Boletín Estadístico de Energía Eléctrica of October 2003, published by the Spanish Ministry of Economy and the transmission system operator Red Eléctrica de España.
This shows the huge progress that has been made in addressing the well known “introductory issues” associated with the GT26/GT24 technology. With these problems now firmly behind them the machines are demonstrating the positive features inherent in the sequential combustion concept. A further key step in the turnaround has been the recent award of an order for four new GT26 machines by a customer in Thailand.
Each Besós unit will be fitted with an upgraded compressor during planned hot gas path inspections in the course of 2005, the last of a series of modifications carried out by Alstom to overcome the model’s initial problems.
When the Besós contracts were placed four years ago, these problems, the first to be encountered being that associated with cooling of the low pressure turbine second stage, had not arisen. This only came to light with the commissioning of the first GT24B and GT26B engines, in early 2000.
Since then, various improvements were devised and tested on the GT26 engine at the Alstom test centre at Birr, Switzerland, and have been progressively introduced to all units in the fleet. Alstom took a conscious decision to make lasting improvements, which would not only solve the initial problems but result in a more powerful gas turbine than had originally been offered.
As well as reblading of the compressor to the upgrade configuration, which was done at Endesa’s San Roque plant in April 2003, further work planned for Gas Natural’s Besós 41 in 2005 will be final commissioning of the fuel oil system and installation of fogging. Both fuel oil and fogging are already implemented in the Endesa engines at Besós and San Roque.
The power train for each Besós block follows the standard Alstom single shaft arrangement, with one end of the generator directly coupled to the gas turbine and the other end connected to the steam turbine via SSS clutch.
The generator (type 50WT21H 120) is a 2-pole three phase synchronous machine, of H2 cooled design, with heat transferred to cooling water in heat exchangers located in the generator housing. It generates at 21 kV.
The generator is used as a synchronous starting motor fed by a static frequency converter. Power for start-up is provided by the HV grid across the generator step-up transformer, and start up without this is not possible.
The self shifting and synchronising SSS clutch permits the steam turbine to be accelerated and to be connected to the generator when it is already being driven by the gas turbine. The SSS clutch engages automatically as soon as the torque from the steam turbine shaft becomes positive, ie as soon as the speed of the steam turbine tends to overtake that of the generator and automatically disengages as soon as the steam turbine torque becomes negative (ie, as soon as the steam turbine tends to decelerate with respect to the generator), with no control device required.
The steam turbine, model DKYZ2-1N41BA, is of the two casing triple pressure reheat condensing type. The first casing contains the HP turbine and the second casing the IP/LP turbine. The steam turbine has one low pressure steam extraction. The LP steam turbine is of the single flow design. The turbine shafts are coupled rigidly together and the HP turbine shaft is coupled rigidly to the SSS clutch.
HP live steam enters the HP turbine through one stop and one control valve and is expanded to reheat pressure. The cold reheat steam is mixed with the IP steam before entering the HRSG in the LP reheater. The resulting reheated steam enters the IP steam turbine. The hot reheat steam is admitted to the IP turbine section via two IP turbine admissions both equipped with one flap and one intercept valve. The LP steam enters the LP turbine through one stop and one control flap. The outlet steam of the LP turbine is discharged to the horizontally arranged condenser.
HRSG and water/steam cycle
The HRSGs are of the vertical, natural circulation design. The supplier is CMI. Steam conditions are: HP, 118 bar, 566°C; IP, 27.5 bar, 568°C; and LP, 4.9 bar, 153°C.
The HP and the IP feedwater pumps feed the HRSG. The LP feedwater is extracted downstream of the first IP/LP economisers. The feedwater flows are preheated in the respective economisers and admitted via control valves into the HP, IP and LP drums. One start-up pump per pressure circuit supports the natural circulation during start-up and fast load changes. Saturated steam is generated at the HP, IP and LP evaporator.
The HP steam is led to the multi-stage HP superheater, the IP steam to the IP superheater and subsequently to the reheater. At the outlet of the HRSG, the HP and IP steam is attemperated with feedwater extracted from the HP economiser feedwater line and IP economiser respectively. The LP steam is directly led to the LP steam turbine.
Water is extracted for the fuel preheater from the IP economiser. A water extraction from the HP economiser feeds the once through coolers (OTCs) and in order to adjust the feedwater temperature upstream of the OTCs within a certain range, this is attemperated with an extraction from upstream of the first HP economiser.
The horizontally arranged single pass condenser is cooled directly with seawater, with the cooling water flowing straight through the tubes. To be able to operate the condenser with one half shut-down on the cooling water side, the water boxes are divided.
The non-condensable gases at the steam side are extracted at the point in each tube bundle with the lowest pressure, the so-called “air coolers”. The condensed steam flows into the hotwell, which provides condensate storage capacity.
The flash box is connected to the side of the condenser and collects the steam turbine internal drains. After separation steam is discharged to the condenser and condensate is discharged to the hotwell.
The 2×100% main condensate pumps are of the vertical type. During normal operation and start-up, one pump operates at full load; the other serves as standby unit. The standby pump is automatically switched on either by failure of the operating pump, or for steam turbine bypass operation at high load. The condensate pumps are equipped with mechanical seals.
The steam side evacuation system consists of one 100% single stage steam jet start-up ejector and two 100% two stage steam jet service ejectors with inter- and after condenser skid mounted.
The ejectors evacuate the steam side of the condenser during start-up and extract non-condensible gases during operation from the air coolers of the condenser.
The motive steam for the ejectors is taken from the cold reheat line and the extracted non-condensible gases are discharged to the atmosphere.
The condensed steam of the service ejector is returned to the flash box.
The start-up ejector provides a back-up, although at higher condenser pressure in case of a service ejector failure.
One feedwater storage tank (FWST)/deaerator provides feedwater storage for the heat recovery steam generator and preheats and deaerates the entering main condensate.
During normal operation, with fuel gas, feedwater preheating is ensured by steam extracted from the LP steam turbine. At low load operation or during fuel oil operation, preheating is done with pegging steam extracted from the cold reheat steam line. The condensate and the heating steam are physically mixed in the direct contact preheater. The separated gas is collected at the top of the deaerator, which is vented into the condenser.
The 2×100% HP and 2×100% IP feedwater pumps are of horizontal design with suction strainers and minimum flow check valves. With each pressure level one pump is in operation at full load and during start-up. The second pump serves as standby unit and is automatically switched on in case of failure of the operating pump.
The HP feedwater pump is equipped with a Voith turbo coupling which reduces the required power input during part load operation.
For any conditions at which the full amount of HP steam can not be admitted to the steam turbine, the HP bypass system guides the HP steam via the attemperation station and through the cold reheat line back to the HRSG. This ensures cooling of the HRSG reheater. The water used for attemperation is feedwater extracted downstream of the HP feedwater pumps.
The IP and LP bypasses lead the IP and LP steam flows into the main condenser via the respective desuperheating stations. For IP and LP bypasses, the water used for attemperation is main condensate extracted downstream of the main condensate pumps.
Each steam bypass is designed for 100% HRSG live steam mass flow at 100% live steam pressure.
The fuel gas is delivered to the plant via pipeline and due to the potentially wide range of supply pressures and quality, it has to be treated before it can be fed to the gas turbine fuel gas blocks.
The treatment system consists of a fuel gas slam shut down valve (100%), which is common to both units, and the following equipment for each unit: liquid and dust separator (2×100%) with condensate skid; dew point heater with gas heated hot water system (2×100%) to preheat gas prior to gas reducing station so that the gas temperature does not fall below the dew point temperature; gas compressor and in parallel 2×100% pressure reducing stations; gas metering station (2×100%) with online gas chromatograph; fuel gas fine filter (2×100%); and fuel gas preheater (for added efficiency).
When the gas pressure is higher than the required pressure for the gas turbine, it is adjusted by the pressure reducing station. When the gas pressure is lower than required the gas compressor is used.
The fuel oil supply system acts only as an occasional back-up system to the fuel gas system. It mainly consists of a fuel unloading station with pump, a fuel oil storage tank, and a fuel oil transfer pump, which forwards the fuel oil to the gas turbine fuel oil pump block. Each unit has its own fuel oil system.
Cooling and water supply
The Besós 31 and Besós 41 condensers use seawater cooling.
A new common seawater intake has been provided for the old (BBC) units (Besós 11 (recently dismantled) and Besós 21) and for the new units. The seawater comes in from the shore via three intake pipes of about 500 m in length.
After the seawater has passed a bar screen and a travelling screen (2×50% design), two 50% main cooling water pumps supply it via a debris filter to the condenser. From there the water flows via a discharge pipe to the seal pit where the main cooling water of unit 31 and unit 41 is brought together. From there the water flows to the Besós river which takes it back to the sea.
Each block has its own filling pump to fill the main cooling water system. As the filling pumps are connected to a small common filling header with isolation capabilities, in case of malfunction of the filling pump, the pump of the other block can be used to fill the main cooling water system.
The auxiliary cooling water system, which is in parallel to the condensers and supplies the CCW (closed cooling water) system intercoolers, is pumped from the two connection pipes upstream of the condenser and downstream of the debris filter and returns downstream of the condenser into the main discharge pipe. Due to the relatively low head loss of the single-flow-condenser, one of 2×100% auxiliary cooling water pumps produces the required head to pass the auxiliary water to the CCW coolers.
For each block a separate CCW system ensures the cooling of the generator, lube oil, and other consumers. Two 100% capacity circulating pumps are provided, with the heat picked up dissipated to the main cooling water system via two 100% capacity water to water heat exchangers.
Constant pressure and replacement of water losses are maintained via a head tank with demin water.
Each main condenser is equipped with a sponge ball cleaning system to avoid bio-fouling and scaling of the condenser tubes.
The main source of raw water is seawater, filtered through 2×100% sand filters and fed to the desalination plant. The desalinated water is collected in the storage tank serving the water treatment plant/demineralisation plant and also supplied to the fire fighting water storage tank.
In case of emergency potable water is taken from the local municipal supply system.
The desalination process is vapour compression distillation at ambient temperature in one operation.
The desalinated water will be treated to reach the required conductivity by means of two mixed resin beds. The demineralisation plant is based on a mixed bed ionic exchanger sized for continuous blowdown and oil operation.
From the demineralised water tank, for each unit one of two 100% forwarding pumps supplies the demineralised water to the consumers. Most is used to make up losses due to blow downs in the water steam cycle and occasionally closed cooling water system losses.
Additionally, each unit has a denox forwarding pump feeding the gas turbine during oil operation.
Each boiler is equipped with a trisodium phosphate dosing system including pumps for injecting the chemicals into the HRSG drums.
Each water/steam cycle is provided with an ammonia/oxygen scavenger dosing system including pumps injecting into the feedwater storage tank or condensate pump discharge line.
Each closed cooling water system is provided with separate sodium hydroxide/corrosion inhibitor dosing equipment for injecting chemicals into the closed cooling water system.
An electrochlorination plant produces chlorine from seawater and this is used to control biological fouling in the seawater intake as in the main cooling water system.
Electrical systems and control
Each unit has a two winding three phase core type step up transformer with on-load tap changer which connects the 21 kV generator with the 232 kV GIS (gas insulated switchgear) switchyard. The step-up transformer is filled with oil. It has its own cooling system.
The Besós substation will connect the Besós power plant with the 232 kV grid and the common auxiliary transformer to the 66 kV grid.
On the HV side (232 kV) each step-up transformer is connected via HV cable and the GIS switchyard to its corresponding transmission line.
An auxiliary infeed from a 66 kV cable line can supply back-up power via the GIS-switchyard and a common auxiliary 15 MVA transformer to the 6.6 kV medium voltage distribution system of the power plant.
The GIS switchyard contains three HV breakers, one for each independent line.
For each unit one three winding station service transformer provides power to the 6.6 kV station service board and to the 6.2 kV static starting device (SSD).
The station service board supplies power to the feedwater pumps, main cooling water pumps, fuel oil pumps, NOx water pumps, fuel gas compressor station, water treatment plant, fuel oil heater and to the auxiliary transformers.
The auxiliary transformers supply power to independent low voltage boards.
Auxiliary systems at the 6.6 kV level common to both units, such as the water treatment plant, are fed during normal operation by the station service transformers.
As already noted each gas turbine is equipped with a static frequency converter for starting the gas turbine from zero speed until the flame is stable enough to accelerate the rotor, with the generator operating as a synchronous motor.
Each unit also has its own static excitation system and an automatic voltage controller to control the generator voltage.
For emergency support the essential boards are fed by the auxiliary transformers. These boards supply the AC drives for safe shut down of the gas turbine, steam turbine and generator.
The following systems are connected: the 220V DC and 24 V DC battery chargers and, via DC/AC converters, the 230V AC UPS; essential drives; and essential lighting.
In case of power plant or HV grid black out, the standby diesel generator will ensure back-up power supply.
In case of an AC power supply failure, the batteries are the sole source of power, until the standby diesel has started and re-energised the essential board.
The digital control system for the plant employs Advant Power, hierarchically structured with a high degree of automation.
The operation of the common systems of both blocks can be done from all the operator stations in either one of the central control rooms.
The block to which the control of the common systems is assigned to, can be selected via the software.
Normally one owner (Endesa) runs the common balance of plant systems. In the other central control room displays relating to the common balance of plant systems are available.