Hybrid units at Map Ta Phut are first of a kind

In recent years Map Ta Phut (the location of which is shown in Figure 1) has grown into one of Thailand’s largest industrial areas. A key infrastructure provider to the area is the Cogeneration Company Ltd (COCO) – a company established in 1993 by Banpu Public Company Ltd and Nordic Power Invest (NPI). It went public in 1995, with Sithe Energies joining as a major shareholder in 1998. COCO builds, owns and operates the plants that meet the electricity, process steam, and water needs of industries in Map Ta Phut.

COCO’s Map Ta Phut plants consist of the following:

Phase I (central site) – boiler plant (gas/oil), 2 x 125 tonnes per hour, completed 1994.

Phase II (central site) – combined cycle/cogeneration plant (gas/oil), 2 x 150 MWe and 2 x 160 tonnes per hour, completed 1995/96.

Phase III (harbour site) – two conventional combustion turbine cogeneration units (gas/oil), 2 x 35 MWe and 2 x 85 tonnes per hour, completed 1997, and the two new Hybrid cogeneration units (coal + gas/oil), 2 x 233 MWe or 2 x 209 MWe and 2 x 100 tonnes per hour.

Similar to the Hybrid concept at Map Ta Phut is the multifuel technology being used at Avedøre in Denmark (see Modern Power Systems, January 2000), currently under construction. Map Ta Phut is the first operating plant in the world to use the concept. The differences between Map Ta Phut and Avedøre are discussed in the panel on page 37.

Why the hybrid?

The Hybrid concept as used at Map Ta Phut essentially aims to integrate a coal-fired plant with a gas-fired plant, the integrating unit being the heat recovery unit (HRU), in which the heat is transferred from the gas side to the coal side of the process, see Figure 2.

The objective is to obtain high cycle efficiency while lowering capital expenditure. By combining the two processes, it is possible to replace the feed water train and the boiler reheater of the conventional steam cycle as well as the heat recovery steam generator (HRSG) of the combined cycle with a simple gas-to-water/steam heat exchanger, the HRU. Furthermore, the two steam turbine generators of the separate cycles are combined into one larger and more efficient unit.

The Hybrid concept was chosen for Map Ta Phut for the following main reasons:

It can supply large quantities of high pressure (HP) process steam. Conventional reheat units are not suitable for supplying large quantities of HP process steam because when the unit is required to supply HP process steam, the flow through the reheater is reduced with the consequent risk of overheating the tube material – a situation that can only to a certain degree be compensated with spray desuperheating or other means of temperature control. The Hybrid therefore aims to separate the reheater from the main coal-fired boiler and to leave the boiler to its primary function, which is to generate high-pressure superheated steam.

Reduced capital expenditure. Where both gas and coal are being used to generate power, the Hybrid is a more cost effective way of adding generating capacity than building separate conventional coal-fired and gas-fired power plants. This is

because, in the Hybrid, the feed-water train and the reheater of the conventional steam cycle as well as the HRSG of the combined cycle have been replaced with the HRU. The HRU is not used to boil water, as in an HRSG, but is a very simple gas-to-water/steam heat exchanger with only three sections. Furthermore, the two steam turbine generators are combined into one large and more efficient unit with only two steam extractions. At Map Ta Phut capital cost savings of 12 per cent have been estimated relative to separate coal and gas-fired units.

Improved efficiency. Relative to separate units, the Hybrid is more efficient due to efficient heat transfer in the HRU and combination of the steam turbine generators into one large efficient unit. The heat transfer in the HRU takes place at very small temperature differences between the gas turbine exhaust gas and the water/steam side. When preheating is performed in the conventional way, by means of feed water heaters, the major part of the heat in the extracted steam will be transferred to the feed water at the saturation temperature, corresponding to the steam pressure in the preheater. However, there is a considerable difference between the temperature in the steam turbine extraction and the temperature at which it condenses in the feed-water heater. This means that when preheating is performed by extracted superheated steam, it is accompanied by considerable thermodynamic losses.

The overall, weighted fuel efficiency of a Frame-6B-based combined cycle gas turbine plus a separate coal plant in condensing mode is estimated to be 40.7 per cent, compared with the Hybrid’s efficiency of 43.0 per cent.

Figure 3 illustrates the basic argument for choosing the Hybrid solution in preference to separate coal-fired or gas-fired units. It shows the total cost of electricity as a function of the gas/coal price ratio. At the present ratio of approximately 2:1, the Hybrid has a cost advantage of about 9 per cent relative to separate units.

Hybrid at Map Ta Phut

A simplified flow diagram for each Hybrid unit of Map Ta Phut Phase III is shown in Figure 4. Each unit has a coal-fired circulating fluidised bed boiler, one steam turbine generator, two gas turbine generators and two HRUs (Figure 5), one per gas turbine.

At Map Ta Phut, as at Avedøre, SK Power Company, Denmark – now renamed and known as ENERGI E2 – has carried out the process design and acts as owner’s engineer responsible for project management, as well as supervision of engineering and construction.

The engineering, procurement and construction contractor is a consortium of Japan’s Marubeni and Black & Veatch of the UK.

The basic data for the Map Ta Phut Phase III Hybrid are shown in the table on page 33. The heat balance diagram is shown in Figure 6.

Circulating fluidised bed

To obtain the lowest fuel price and generate power as profitably as possible, the plant has to be able to deal with a wide range of fuel qualities and, at the same time, meet environmental requirements (see table above).

A pulverised coal boiler equipped with additional desulphurisation and NOx removal plants would have fulfilled the environmental requirements, but a more direct approach for this size of plant is to use a circulating fluidised bed (CFB) boiler where sulphur dioxide and oxides of nitrogen reduction takes place within the boiler. Furthermore, the CFB boiler has the advantage of superior fuel flexibility.

Foster Wheeler Energy International supplied the CFB boilers. They incorporate design features such as water-cooled cyclones and horizontal in-furnace superheater panels manufactured from T91 double-Omega tubes. The boilers have been designed for operation with feedwater temperatures ranging from 150°C to 275°C, depending on whether feed water heating is available from the gas turbine HRUs or not.

The boilers are of the natural circulation, non-reheat type and are designed for a maximum continuous rating of 120.6 kg per second main steam at a temperature of 568°C and a pressure of 183 bar. A 120 kg per second CFB boiler is well within the state-of-art of this technology.

Gas turbines

The exhaust gas temperature from numerous well-proven heavy-duty gas turbines falls within the range of 500°C to 560°C, making it sensible to match the coal-fired boiler with gas turbines in such a way that the exhaust heat reheats the steam before it enters the medium pressure section of the steam turbine.

In the Map Ta Phut Phase III Hybrids, each unit uses two GE Frame 6B gas turbines. A strong argument for selecting the GE Frame 6B was, of course, the fact that COCO already operates a total of eight similar GE gas turbines at Map Ta Phut in the earlier phases of the project.

Heat recovery units

As already mentioned, each Hybrid unit is equipped with two HRUs, one for each gas turbine (Figure 5). The main objective of the HRUs is to transfer the heat from the gas turbine exhaust to the steam and water in the steam cycle. Each HRU contains three tube bundles, one for each of its cycle components: the reheater; the feedwater economiser; and the condensate economiser. Each unit is designed to take the full mass flow of steam and water in case of operation with only one gas turbine.

Foster Wheeler Energia Oy, the Finland-based subsidiary of the company, designed and supplied the four HRUs. These receive exhaust gas at a temperature of 553°C and cool it down to about 100°C. The outlet reheat temperature from the units is up to 530°C.

The HRU system also includes an exhaust gas bypass damper and a stack, for use when the gas turbines operate without having the HRUs in service.

Steam turbine generator

The steam turbine island for the Hybrid system is less complex than that for a conventional plant. The turbine has only two bleed points, one for steam to the deaerator and one for the first low pressure heater, which is left to ensure that condensate enters the HRU at a temperature above the acid dew point of the flue gas.

The steam turbine generators were supplied by General Electric of the USA. The main steam is admitted to a separate high pressure turbine. From the HP turbine, exhaust, the steam flows through the reheater section of the HRU to the inlet of the combined single-flow intermediate and low pressure (IP/LP) turbine.

The reason for choosing a separate HP turbine instead of a combined HP/IP turbine has to do with the Hybrid concept. As the reheat temperature depends on the gas turbine load, situations with substantial temperature differences between main steam and hot reheat steam may occur.

In a combined HP/IP turbine, the main steam and the hot reheat steam are admitted in the central part of the HP/IP module. Large temperature differences between the two steam flows will increase the level of thermal stresses in this part of the turbine, which could lead to low cycle fatigue.

The two-part, single-pass titanium tubed condensers are designed for a cooling water temperature increase of 4.4°C in extraction mode and 5.6°C in pure condensing mode.

Emission control

As previously suggested, an advantage of the CFB technology is that the reduction in sulphur dioxide and NOx takes place within the boiler. Emission of SO2 is controlled by using pneumatic limestone injection into several locations in the furnace for in situ sulphur capture. NOx formation is limited through air staging and a relatively low combustion temperature and is further reduced through ammonia injection. The collection of fly ash takes place in a fabric filter before the stack.

NOx emission from the gas turbines is further controlled by water injection in the combustion chambers.

The table on page 35 shows a comparison between the contractually guaranteed emissions values for the Hybrids and the requirements established by the World Bank and the Thai Office of Environmental Policy and Planning. The guarantees apply to a sulphur content in the coal of up to 3 per cent.

Operating scenarios

Several specific operating scenarios with varying process steam and power demands have been anticipated.

In the first scenario, both the gas side and the coal side operate at matching loads, thereby maintaining the heat balance in the HRU. No special operating considerations are required in this situation.

If the gas turbine load is reduced while the CFB continues operation at high load, the temperature of reheated steam and feed water will drop. The CFB is designed to maintain full main-steam flow, even when the gas turbines are operating at a load as low as 60 per cent.

Operation without gas turbines is possible too. In this scenario, the feed water heating takes place in the feed water tank by means of pegging steam, while a portion of the main steam is bypassed to the hot reheat steam to maintain minimum required steam temperature. The steam turbine generator load will be limited to about 90 MWe net.

Alternatively, the gas turbines may be operated at full load, while the CFB load is reduced. In this situation, the exhaust gas heat from the gas turbines cannot be fully recovered as the flow of steam and feedwater decreases. The reheater will react by increasing the desuperheater spray water flow. The feedwater temperature is controlled by dumping some of the feed water to the condenser or by partly opening the exhaust gas bypass damper.

It is possible to start and operate the CFB in stand-alone operation and achieve sufficient pressure and temperature to supply process steam to the HP and MP steam systems.

The gas turbines can be operated in simple or open-cycle, exhausting through the exhaust gas bypass stacks.

Tables

Map Ta Phut Phase III Hybrid units - the basic data
Emission levels (mg/MJ)