In the mid-1990s, Malaysia was experiencing high load demand which required the addition of large amounts of baseload electricity generating capacity. At the same time, the government was also concerned about its dependence on natural gas which provided close to 80 per cent of its electricity. It therefore took the decision in 1996 to set up TNB Janamanjung, a wholly-owned subsidiary of state utility Tenaga Nasional Berhad (TNB) to develop a 2100 MW coal fired project on a build-own-operate basis. During the autumn of 2003, some seven years after the award of the contract, the plant began feeding power into the Malaysian grid.
Manjung was developed to help reduce Malaysia's dependence on natural gasClick here to enlarge image
Manjung was developed to help reduce Malaysia's dependence on natural gas
Project development
The plan to build the Manjung power project was announced in November 1996 and bids from all the major manufacturers were submitted in May 1997. At the time, the project was hailed as Asia's largest independent power producer (IPP) project.
Dennis Craig, Asia Pacific regional sales director for Alstom, the eventual winner of the contract recalls: "Alstom was called back for final bid clarification in early 1998 and received a letter of intent that summer, but the Asian crisis reduced demand and delayed the start of the project for a further year."
The currency crisis also affected how the plant would be financed. The plan was for the project to be funded through non-recourse financing but raising financing at this time proved difficult. The government therefore decided that most of the project cost – about Rm7.083 billion ($1.864 billion) would therefore be initially covered by TNB. In addition to the equity put forward by TNB, a buyer's credit was put forward by the UK credit agency, ECGD (the Export Credit Guarantee Department).
On June 29, 1999, an ECA loan (ECGD and France's Coface with support from the Norwegian agency, GIEK) was secured totalling the equivalent of Rm2800 million. Repayments of the loan were agreed to begin six months after project commissioning of unit two and will be repaid over a 12-year period.
 A 3 x 700 MW sub-critical scheme was selected for the project |
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When the Malaysian economy began its recovery the government decided that it would proceed with the project and the permit to proceed with the plant was issued in May 1999.
TNJB had already appointed PowerGen Projects Consultancy Ltd (PPC) as the Owner's Engineer for the project in 1997. The engineering, procurement and construction contract was awarded to a consortium of Alstom and Peremba Construction Sdn Bhd in June 1999. Alstom UK was the contractor for the offshore part of the contract and Peremba for the onshore portion. Craig explained: "You need a strong local partner and Peremba was selected as our local construction partner. They have a good track record in Malaysia and have strengths in civil works and EC&I."
Under the EPC contract Alstom had overall project responsibility and was responsible for the design and supply of the main power plant equipment and the associated erection and commissioning, along with training of the operation and maintenance team, the test run and performance guarantee tests. Peremba had specific responsibility for the civil works of the auxiliary buildings, the electrical and control equipment. The coal yard equipment was both designed and supplied by Koch.
 The boilers are two pass drum-type pulverized coal fired boilers |
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Plant description
The plant has been built on a reclaimed island called Teluk Penchalang in Manjung District, about 10 km south of the nearest town, Lumut, and about 288 km north of Kuala Lumpur. This location is in line with the government's desire to develop power in the coastal area and close to load centres. A new coal terminal, which is the deepest on the west coast of Malaysia, was also built to receive coal that is transported to the site by sea.
During the economic assessment of the plant, two options were considered to achieve the 2000 MW output: a 4 x 500 MW arrangement and a 3 x 700 MW arrangement. Both sub-critical and supercritical units were considered. After a detailed techno-economic review, the 3 x 700 MW scheme was selected because of the smaller land requirement; reduced staffing level and better overall project economics.
A further evaluation process also determined that despite the slightly higher efficiency of supercritical units, both schemes offered similar generating costs. However, the sub-critical scheme, because of its lower capital costs and thus lower financing requirements, was eventually selected. Craig said: "In December 1997, Alstom proposed a supercritical plant but the client decided that the extra [capital] cost couldn't be justified."
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The boilers of the three units are Alstom-designed two pass drum-type pulverized coal fired boilers. They are controlled circulation boilers with tangential firing. Each boiler is 110 m high and has economiser, superheater and reheater sections. Coal crushers are installed in the coal conveyor system before the boiler bunkers. There are seven vertical mills although only six mills are used in baseload operation. The boilers use low NOx burners which are designed to burn international imported coals from Indonesia, China as well as Australia. Light fuel oil is used on ignition and for sustaining the burner flame at low load.
Steam from the power plant's boilers is fed to three steam turbines which are of the axial flow design with the turbine and generator rotors directly coupled in tandem. The design is suitable for the range of steam temperatures and pressures delivered by the boiler during operation and startup. The turbines normally operate in baseload but are also capable of continuous two-shift operation. Each turbine consists of a high pressure (HP) turbine, an intermediate pressure (IP) turbine and two double flow low pressure (LP) turbines. Turbine casings, bearing housings and covers are split conventionally at the centre line horizontal half joints to facilitate maintenance. The steam turbine and generator and its associated auxiliary plant are housed in a building which has two permanent overhead cranes for lifting during maintenance.
The construction of the power blocks brought together an interesting mix of labour and expertise from around the world. Craig noted: "The boiler steel works were manufactured in Malaysia since the contract re-quired 40 per cent local manufacture. A quarter of this 40 per cent had to be Bumiputra (Malay) registered contractors. We doubled this Bumiputra content."
Seawater FGD
The export credit agencies were particularly interested in the environmental aspects of the Manjung project. The project was therefore designed to meet World Bank emission standards and the detailed Environmental Impact Assessment has now become a benchmark for other such projects in Malaysia.
A notable feature of the Manjung plant is the seawater scrubbing process used for flue gas desulphurization (FGD).
Craig explained: "FGD was not included in the basic scope of the project initially, but added in during the negotiation phase as it gives the client flexibility to use higher sulphur coal. The size of the site dictated the choice of the FGD. Seawater FGD was also the most economical."
Seawater is available in large amounts at the power plant as a cooling medium in the condensers. Because it is alkaline, it can be used to neutralize acids such as SO2. The absorbed sulphur dioxide is oxidized to harmless sulphate. Sulphate is a natural constituent of seawater and will completely dissolve to provide only a slight increase in the level of sulphate in the seawater.
The seawater FGD technology at the Manjung project is only the third such plant in the world. Alstom has other references at Shenzen in China and Paiton in Indonesia.
The FGD plant at Manjung is located downstream of the two ID fans. An FGD flue gas fan is designed to extract the correct amount of flue gas for desulphurization. Surplus flue gas bypasses the FGD and is used for reheat of the cleaned flue gas upstream of the stack. The SO2 is removed by absorption in seawater inside a packed column (the absorber).
The FGD system is designed to treat 65 per cent of the flue gas (total flow of 2783 kNm3/h at air heater outlet) when burning design coal at the boiler maximum continuous rating. At this rating, 35 per cent of of the flue gas bypasses the FGD to be mixed with the cleaned flue gas upstream of the stack.
The flue gas emissions at chimney (dry, six per cent O2) released into the atmosphere has a maximum concentration of 262 ppm SOx and 320 ppm NOx when burning design coal at the boiler maximum continuous rating.
The flue gas temperature at the stack outlet is greater or equal to 80°C for the boiler load range from 50 per cent to BMCR.
The flue gas duct from the outlet of each ID fan is merged into one duct, called the main duct. From here, up to 65 per cent of the flue gas can be routed through the FGD inlet damper by the FGD flue gas fan. The fan boosts the pressure in the flue gas sufficiently to overcome the pressure drop through the FGD system. Guide vane control is used to adjust for the correct flue gas flow through the FGD flue gas fan. Downstream of the fan, the gas enters the gas-gas heat exchanger (GGH). The untreated flue gas enters the GGH at thetop, and flows downward through the GGH to the absorber inlet.
 In emergencies that require shut-down, the FGD plant can be completely bypassed. In this situation, the main duct will transport all flue gas directly to the stack. |
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In emergency shut-downs, the FGD plant can be bypassed. Here, the main duct will transport all flue gas directly to the stack
In addition to seawater FGD there are also electrostatic precipitators (ESPs) to remove particulates. The ESPs are supplemented with SO3 injection to enhance ash collection capability. This allows the ESPs to be slightly smaller.
The plant has four emission monitoring stations and stack monitoring equipment to ensure the emissions do not exceed design levels. Moreover, the cooling water temperature outlet is monitored so that the cooling water is not fed back into the sea at a higher temperature than the specified limit (40°C). Dispersion modelling was also carried out to calculate the emission dispersion from the 200 m-high stack.
Construction
Although the plant will be a benchmark for future plants in Malaysia, construction was not without its challenges.
"The main challenge was that the island was continually settling as we carried out the project. This was because the plant was built on reclaimed land which was built up 4.5 m above mean sea level. The delay in the project gave it an extra year to settle but even now there is still some settlement taking place although at a much reduced rate which the design has taken into account," explained Craig.
During the construction phase of the project, according to Craig, the main task was to work out how settlement would occur. In addition, there were areas near the pump house where water was quite close to the surface. This called for good civil design and construction. "The most interesting part of the civil design was the pump house construction utilising a figure of eight temporary diaphragm walls which became part of the final structure," recalled Craig.
Piling began six months after the contract award and utilised board piles as opposed to the more normal driven piles. The width of the 245 ha site was also a constraint. "This determined the layout of the plant," said Craig.
 Each steam turbine delivers 760 MW gross |
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Despite the challenges, the plant was built in a relatively short timeframe – 42 months for Unit 1 with an additional four months for Unit 2 and a further four months for Unit 3. Unit 3 was taken over in September 2003.
With the hand over of Unit 3, Manjung is now going through its availability guarantee period and is expected to demonstrate the contractual availability without problem.
The availability of the plant will be crucial in supporting Malaysia's fast growing economy and the project will be a benchmark for other coal fired projects in the country to follow for years to come.
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