Delta Electricity is a state-owned corporation producing electricity from several facilities using diverse energy sources, predominantly coal but also hydro and biomass. Most of its supply is generated by four power stations in New South Wales: Mt Piper and Wallerawang near Lithgow; and Vales Point and Munmorah on the Central Coast. These stations have a combined capacity of 4320 MW, which accounts for some 12% of the electricity purchased through the Australian National Electricity Market (covering all Australian states and territories except Western Australia and the Northern Territory).

The remainder of Delta’s production is renewable energy produced from: mini-hydro facilities at Mt Piper near Lithgow, Chichester Dam in the upper Hunter Valley and Dungog wastewater treatment plant; biomass co-firing at Vales Point and Wallerawang power stations; and two 30 MW cogeneration plants using waste from milling sugar cane at Condong and Broadwater sugar mills (supplying baseload renewable energy, the largest source of such energy in Australia).

However, to enable the company to meet growth in the electricity market a number of key objectives needed to be met. It must:

• Provide electricity at relatively short notice during periods of peak demand.

• Provide black-start capability to improve system security, stabilisation and emergency response.

• Meet future energy demands competitively, using best available technology, consistent with its current environmental objectives.

• Reduce environmental impacts by lowering greenhouse gas emissions.

Accordingly, in March 2007 a turnkey EPC (engineering, procurement and construction) contract was awarded to Alstom to build an open cycle power plant that would enable Delta to meet these key objectives. The new Colongra gas turbine facility is now under construction near the existing Munmorah power station on the Central Coast, 120 km north of Sydney.

Under the contract, Alstom will design, supply, install and commission the entire power plant with the turnkey delivery of:

• turbine island;

• step-up transformers;

• Alspa distributed control system; and

• balance-of-plant.

The project represents Alstom’s fifth contract in Australia for the supply of GT13E2 based power plants.

Australian power market

The Australian power market comprises a number of interconnected regional state markets. Interconnectors between each state facilitate power exchange. NSW accounts for more than 40 per cent of the installed generating capacity of the Australian National Electricity Market, which pools electricity production on Australia’s eastern seaboard to meet the market’s electricity demand.

NSW, which possesses significant coal resources, has a number of ageing coal fired power stations. But since the investment in coal based technology to meet demand in the 1980s and 1990s there has been little infrastructure development. Therefore the state is reliant on the continuing operation of these coal plants, with their relatively high emissions.

At the same time with increasing peak demands during summer and continuing growth of winter demand, new capacity is required to maintain reliability of supply and manage peak power prices in a competitive electricity market. In 2004, the NSW government released the Energy Directions green paper, which described current and future trends in energy demand in NSW. The green paper stated that the peak energy demand in NSW was growing at a faster rate than average demand. This diverging trend between base load and peak load demand profiles can be largely attributed to the sustained period of strong economic growth that Australia has enjoyed over the last 10-15 years.

This trend has resulted in an increasing demand for electricity across all sectors of the economy but in particular the residential sector, where increased prosperity is expected to continue to drive demand for electrical goods such as air conditioning units, which are one of the major contributors to the increasing peak demand load in summer.

Another report produced in 2004 by the National Electricity Market Management Company (NEMMCO) also included forecasts that the risk of a summer peak deficit or shortfall below the reserve condition for NSW by 2008/09 was increasingly likely, unless there was additional generation capacity to meet the deficit.

Transgrid, the NSW transmission authority, has assessed the potential system reliability issues during a severe system failure or blackout in the NSW transmission grid. The assessment determined that there was an opportunity for network restart or blackstart resources in the northern part of NSW to cater for such an event and concluded that the provision of a quick-start facility with blackstart capability at Colongra would provide a number of significant system security benefits in the event of a state-wide system shut-down.

Delta Electricity decided that a gas turbine peaking power plant of about 600 MW near the existing Munmorah power station site would be the best way of addressing the peak demand and system security issues. Munmorah is a coal fired power plant with four units – two of which have been decommissioned and two of which, unless refurbished with the latest emissions reduction technology, are likely to be decommissioned in the not too distant future.

At 660 MW, the new Colongra gas fired power station represents a large contribution to gas fired peaking capacity in New South Wales.

Selecting the right equipment

For an open cycle peaking power plant, selecting the right gas turbine is critical due to the stresses experienced by the machine as a result of the intermittent operation of the power plant and high number of stop-start operations compared to a baseload plant.

The Colongra power plant uses four GT13E2 dual fuel gas turbines in open cycle configuration.

The natural gas to fuel the turbines will be supplied via a new underground pipeline connecting the facility to the existing Sydney–Newcastle pipeline located about 8 km west of the power plant.

Natural gas will be the primary fuel, with distillate used primarily for backup in case of gas interruption. According to the approvals, the turbines cannot use distillate for more than a total of 75 hours in any 12-month period except to meet emergency market needs. Switchover between fuels will be automatic, which is particularly important during system emergency market conditions where the ability to deliver power to the grid is critical.

Each turbine has maximum power output of 167 MW when operating at nominal ambient conditions (35°C, power factor 0.85).

To improve the performance of the gas turbines during hot summer conditions, there is an evaporative cooler upstream of the GT compressor. This uses demineralised water to cool the air stream before it enters the gas turbine. This inlet air-cooling delivers an additional 6.7 MW per gas turbine at design ambient conditions.

The GT13E2 has a rotor welded from forged discs, which ensures high rotor stiffness with two-bearing support. The welded rotor design eliminates maintenance work such as restacking and disk replacement or factory rotor overhaul and thus eliminates the need for a ‘major overhaul’ of the engine.

The turbine features advanced aerodynamics and multi-convective cooling schemes, which contribute significantly to the engine’s efficiency.

The GT13E2 has a 5-stage turbine section. The design of the first turbine stage, combined with the thermal barrier coating (TBC) and conservative turbine inlet temperatures of 1100°C, allows extended inspection intervals of up to 36 000 EOH (equivalent operating hours). The use of Inconel 738 conventional cast turbine airfoils and heat shields ensure long parts life and allow for full cost-effective refurbishment.

The 21-stage subsonic compressor is equipped with a set of variable inlet guide vanes. The combustion airflow rate can be adjusted by changing the angular position of the vanes. Load control is managed by varying the amount of natural gas and combustion airflow. The result is increased part load efficiency and starting reliability.

The annular combustor contains 72 EV burners arranged in pairs. The burners operate on the principle of the lean pre-mix vortex breakdown to achieve low NOx values with dry combustion gas during gas operation.

The annular combustion chamber distributes the circumferential temperature evenly while avoiding problem zones such as cross-firing tubes or transition pieces. Unlike can-annular systems, the annular combustor does not need a combustion inspection, which means reduced maintenance and higher availability.

The gas turbine lubrication system also provides lubrication for the generators. Two 100% lube oil pumps on each gas turbine (plus one DC emergency pump) supply oil through the lube oil cooler to the bearings of the power train. When the GT is on turning gear, the GT/generator shafts are lifted by hydraulic jacking oil pumps.

Each gas turbine drives its own generator from the compressor end. The axial exhaust provides for easy adaptation for possible future installation of a heat recovery steam generator (HRSG).

The generators are of the high efficiency TOPAIR type, equipped with static excitation. They are air-cooled via four 25% air/water coolers by water from the CCW system.

Each generator is started by a synchronous motor with a variable frequency drive known as a static starting device (SSD). There is one SSD per GT. The GT is accelerated with the starting device until the turbine is ignited and self-sustaining speed is reached. The turbine start-up controller will take over and accelerate the GT set to synchronous speed. The generator is synchronised to the grid either through the generator circuit breaker or through the switchyard circuit breaker.

Power generated is distributed to the plant ancillaries and to the grid through step-up transformers, which were also under Alstom’s scope of supply. Four step-up transformers connect the four gas turbine-generators to the 330 kV switchyard. Each SC13E2 power train includes one 11/1.8/0.43 kV ‘unit auxiliary transformer’ and one 15/0.42 kV ‘excitation transformer’.

The GT unit auxiliary transformer feeds the SSD and GT auxiliaries. This transformer is a three winding type, oil isolating and air-cooled with fans.

Station transformers of 15/11 kV feed the plant ancillaries.

Power from the plant will be fed to the grid via a new dedicated bay being built next to the existing switchyard located northwest of the new plant. The existing overhead transmission lines will be used to export power from the power station.

Emissions reduction

The use of gas at Colongra is a part of the move away from the Australian power industry’s reliance on higher-emission power generation technologies. The new plant easily meets the World Bank limits. When running on natural gas, at each turbine stack discharge point NOx limits must not exceed 50 mg/m3 (15% O2). On distillate, emissions should not exceed 90 mg/m3.

The plant is designed to emit greenhouse gases at an average rate of 0.58 t of CO2 per MWh, which is significantly less than the NSW pool coefficient of 0.928 t/MWh in 2006 when the project was first proposed. This is of state-wide importance as it will help to reduce greenhouse gas emissions per unit of output in NSW and achieve the ultimate goal of 7.27 t of CO2 per capita by the year 2012 set by the NSW Greenhouse Gas Benchmark Scheme.

The desire for greater efficiency and the corresponding reduction in CO2 emissions will see increased pressure to convert the power plant to combined cycle power plant in the future.

The decision was taken not to opt for a baseload combined cycle power plant from the outset because of insufficient gas supplies at this site. The Colongra plant will take a gas feed off a distribution line between Sydney and Newcastle. A 9 km long, 1050 mm diameter lateral has been built for use as a storage pipeline off this supply. A compressor will compress and store up to 5 hours of gas in this storage pipeline for use during times of peak electricity demand. Recovery of this gas reserve is achieved within 24 hours.

Initiatives are underway to bring more gas to Sydney from Queensland. Should more gas be secured, the next step will be to consider the timing for conversion of the power plant to combined cycle operation.

At this stage, there may also be the addition of further emissions reduction equipment. Delta is currently engaged in a pilot carbon capture research project with CSIRO at the nearby coal fired Munmorah power station.

Showcase site

A great deal of effort gone into environmental protection at Colongra, including plant construction environmental management plans covering areas such as dust management, soil erosion protection, waste management and wastewater management.

For example, prior to the commencement of site preparation works, we were required to undertake acid sulphate soil testing for areas of the site to be disturbed during site preparation and construction. The potential impacts of any acid sulphate soils disturbed during site preparation or project construction were effectively addressed in accordance with an acid sulphate soil management plan.

Prior to the commencement of construction, it was also necessary to prepare and submit a water cycle management report detailing water conservation and re-use strategies. The report included a review of best practice water conservation and re-use initiatives and strategies with consideration given to their suitability for application on site.

We were also required to maximise the treatment, re-use and/or recycling on the site of any waste oil, excavated soil, slurries, dust and sludge associated with the project, to minimise the need for treatment or disposal of those materials outside the power station.

In addition the requirements of the Australian Dangerous Goods Code had to be met and various studies related to potential hazards pre-construction and pre-commissioning also had to be submitted.

Overall, in terms of environmental and safety performance, this is very much a showcase site.

All of the procedures and measures that have been put in place are being audited every two weeks. Further, twelve months after the start of operation of the plant, and every three years thereafter, an independent body will undertake a hazard audit. An environmental audit report is also required at the same time.

Plant operation and control

Delta Electricity requires that the plant be very flexible with reliable starting. During peak demand, power traders at Delta will need to be able to react immediately and have the plant up and running according to the size of the peak.

The plant is fully automated and remotely controlled. Traders are therefore able to start, dispatch and shut-down the plant remotely via a secure internet connection. This means the plant can respond very quickly to price developments in the market.

The plant is equipped with an overall plant process control system based on Alstom’s Alspa distributed control system (DCS). The DCS provides functions such as: signal conditioning, annunciation, recording; operation, monitoring and supervision; open and closed loop control, sequence logic, protection; and data communication and plant management applications.

The plant is basically unmanned, with just two or three operations staff on hand to ensure that the start-up and operation runs smoothly when the plant is started remotely. This is a fairly unusual for such a large power plant.

The gas turbine operation is a fully automated process with the various auxiliaries of the GT being switched on or off in a sequential manner. Operator intervention is only required for: pre-selection of gas turbine load target; command for start-up and shut-down of the gas turbine; pre-start conditioning for a later accelerated start-up procedure.

Any balance of plant system directly related to the operation of the gas turbines, such as fuel systems, are controlled directly by the DCS, while other BOP systems such as fuel unloading and service water require local operator attendance and are therefore be controlled from local control panels only.

The plant can be started by the operator giving a start instruction to each turbine in turn or by activating the plant master sequence start. The concept chosen for the plant allows normal start-up times, with a load-up time from start command to GT baseload of 30 minutes. The operator can also choose a fast start-up option, which reduces loading time to 13 minutes.

The plant master sequencer is used to start the complete plant. Here, the operator will be required to select the required plant load, the number of turbines to be started, the start-up type (standard or fast) and the fuel type for each GT before the plant start. The plant master sequencer will start each GT in turn and load the started units to the required level.

The plant operating regime will typically see one or possibly two starts per day during the peak summer period. At other times of the year, the plant will be on standby. The number of expected starts will largely depend on the electricity price developments in the market.

Although the facility could operate 24 hours per day, all year round (the environmental impact assessment has been based on continuous operation), the plant is likely to operate for about 500 hours per year. This is based on an approximate estimate of the projected annual cumulative peak power demand period. The power plant will also be required to respond to electrical system emergency and security situations, which would be in addition to the estimated annual cumulative peak power demand period.

The regular start-up regime is not expected to have any impact on the maintenance schedule of the plant.

Project development

The contract was awarded to Alstom in March 2007 and the project has moved quickly. Notice to proceed was given in July 2007, at which time engineering of equipment began. Site approvals were straightforward since the new plant is located next to part of the existing power station. The first project milestone was in October 2007 when access to site was given and site infrastructure work could begin.

Engineering, procurement and manufacturing took place in parallel with site infrastructure work such as earthworks and site levelling. At the time of writing, mechanical erection was 20% complete overall, ie, about 60% of the first unit and 30% of the second unit. The project is essentially being delivered in two stages or heavy shipment phases.

The first two gas turbine/generator sets were shipped in July/August 2008 and arrived on site in mid-September 2008. The second two were shipped at the end of November and arrived on site in January 2009. The units will be commissioned one at a time with a gap between units 1 and 2 being about two weeks.

The first target is first fire, which is expected to take place in the first half of 2009 when fuel gas becomes available. Units 1 and 2 have a provisional acceptance date during the summer 2009.

Units 3 and 4 will begin commissioning one month after units 1 and 2 and have a provisional acceptance date of the end of 2009.

The project has been divided into distinct stages, with civil work completed before the mechanical and electrical (M&E) work started.

All deliveries have been frontloaded to provide a margin of a couple of months between arrival of the equipment on site and the date when it was actually needed. This has allowed the erection contractors to plan their work around the most efficient installation method from a labour standpoint as opposed to planning work around deliveries. This means the work programme is dictated by efficiency instead of by deliveries.

The bigger picture

Power companies tend to take a holistic, big picture, approach to their investments in power generation, ie they look at the whole plant over its entire lifecycle. To align with this, Alstom has redefined the way it approaches power plant design, construction and maintenance. It calls itself a “Plant Integrator” – reflecting the company’s abilities to design and manufacture all the key components of a power plant and integrate them effectively together – and this has proved beneficial at Colongra.

Although Delta contracted Alstom to build a peaking plant, there is a possibility that the plant will be converted to a combined cycle plant at a later date. Using its Plant Integrator skills, Alstom has designed the civil works to be able to accommodate a heat recovery steam generator and air-cooled condenser at some point in the future.

Care has also been taken in provision of underground services to areas that are currently not occupied but might be needed by the steam turbine or other combined cycle plant equipment (although no other provisions, such as placing a diverter damper in the stack, have been made at this stage).

At Colongra, Alstom, as Plant Integrator, has also been able to increase project net present value by reducing lead times. Combining the EPC role with that of designer, manufacturer and supplier of all the major plant components means it possible to shift manufacturing slots to accelerate or delay the production of certain pieces of equipment in order to streamline the whole process.

Also, the bulk of the design is known before the contract is signed, further reducing lead time. In contrast architect engineers (A/Es) have to rely on external suppliers and therefore have to wait until the supplier is selected before they can engineer at the required level of detail.

Using an OEM with EPC and turnkey capabilities has proved a particular benefit to Delta at Colongra as it has allowed the company to focus its attention on the gas line project, which is being conducted in parallel with the power project, and has relieved it of the burden of power plant construction, which is being dealt with fully by Alstom.

The turbomachinery equipment and generators have been supplied as a standard package out of Switzerland, while the balance-of-plant components, engineering and arrangements for the later conversion into combined cycle, were handled by Alstom’s Malaysia office. Since Alstom’s scope of supply included the switchyard it will therefore also be responsible for interfaces with the grid company, Transgrid.

The Plant Integrator approach has benefited project execution. For example, if a separate EPC contractor had been used, activities such as civil works would have been much more complicated since information exchange is more difficult if third parties are involved.

With everything – manufacture, delivery and project engineering – under the control of one entity, which is able to prioritise, drive its own schedule and gain all necessary approvals from the relevant authorities, the project is ahead of schedule with all approvals already in place for first firing.