Air cooling in a dry state5 November 2002
Two Reliant CCGT projects in Mississippi and Pennsylvania have been engineered for air cooling rather than water cooling, a decision that has speeded up the permitting process and helped to conserve water supplies. Roger Spears, Black & Veatch, Kansas City, Missouri, USA
More power generation facilities in the USA are installing and relying on air-cooled steam condensers, a decision often driven by water supply restrictions or circulating water discharge restraints. But making the decision is not straightforward - there is a balance of advantages and disadvantages that has to be analysed for each case.
Air-cooled condensers (ACCs) have the following advantages:
• minimisation of water make-up requirements;
• elimination of cooling tower blowdown disposal issues;
• elimination of tower vapour plume; and
• elimination of circulating water pollution restrictions.
The systems also have the following disadvantages:
• higher condenser operating pressure (resulting in lower cycle efficiency);
• higher initial cost;
• larger site requirements;
• higher noise level;
• higher operating costs.
Growth in water consumption for industrial, commercial, residential and power generation purposes has encouraged engineering solutions that minimise water use. The traditional once-through cooling method is more efficient, but uses enormous amounts of water. In addition, drought conditions or the danger of drought conditions have generated local, regional, and state regulations encouraging water conservation in power generation. The choice of ACCs can sometimes expedite the permitting process and accelerate power delivery to the market.
Recent combined cycle power generation projects for Reliant Resources, Choctaw County (Figure 1) and Hunterstown facilities, both employ ACCs and illustrate the commercial, design, and regulatory considerations governing selection of the condenser equipment.
The Hunterstown and Choctaw County plants both feature a 3-on-1 combined cycle design, consisting of GE 7FB gas turbine generators, Alstom Power triple pressure reheat cycle heat recovery steam generators (HRSGs), each equipped for supplemental duct firing, and a GE D11 reheat condensing steam turbine generator for a total nominal capacity of 800 MW. The two plants will feature the first application of GE 7FB gas turbines in a combined cycle application.
The combustion turbines are designed to fire natural gas and will be equipped with dry low NOx burners. Each HRSG is equipped with a selective catalytic reduction (SCR) system to control NOx emissions.
The air-cooled condensers have been supplied by GEA Power Cooling Systems, Inc (GEA - PCS) of San Diego, California.
Choctaw and Hunterstown
The Choctaw facility is located near French Camp, Mississippi. Its electrical output will be fed into a 500 kV substation for interconnection to the 500 kV backbone transmission line near the Entergy/TVA hinge point. The plant is an outdoor unit: its air cooled condenser uses standard fans with 200 hp (nominal) drives. The Choctaw County project is an EPC project being executed by a joint venture of Black & Veatch Corporation, Overland Park, Kansas, and Zachry Construction Corporation, of San Antonio, Texas.
Located near Hunterstown, Pennsylvania, the Hunterstown facility is being constructed as an EPC project by a joint venture of Black & Veatch Corporation, Overland Park, Kansas and Barton Malow Company, Southfield, Michigan under the BVBM name. The plant includes features for low noise emissions, and apart from the HRSGs is an indoor, fully enclosed unit. It will feed into a 500 kV GPU substation. The air-cooled condenser makes use of high volume, low speed (for reduced noise) fans with nominal 250 hp drives. The plant is being constructed by union labour under a project labour agreement.
The design considerations and specifications for the Choctaw County and the Hunterstown plants are quite similar, so the following description applies equally as an overview of the ACC system in each plant (Figures 2, 3).
The condensing system consists of a 50 cell/module ACC, condensate tank, condensate make-up de-aerator, air removal equipment and associated ducting/piping and valves. The ACC receives and condenses the turbine exhaust steam, turbine bypass steam and reclaimable drains. Each cell is a nominal forty feet square, yielding an overall area of about 192 feet by 400 feet, or 62 by 130 metres. The ACC modules are elevated, with the top of steel about 120 feet above ground level. Cooling air is drawn in from below and exits through top mounted tube bundles.
The steam turbine exhausts into the ACC steam duct and is conveyed by a system of ductwork to the condensing tube bundles. Steam turbine exhaust steam is conveyed through a 23 foot diameter steam duct to a distribution manifold at the ACC. The manifold conveys steam to 10 rows with five condensing cells each. Condenser tube bundles are installed on 'A-frame' assemblies above the fans. The first two and last two condensing cells in each row are loaded with condensing tube bundles or 'K' bundles. The centre or third cell in each of the 10 rows is loaded with dephlegmator bundles or 'D' bundles. The D bundles are connected to the condenser air extraction system for removal of air and non-condensable gases.
Each cell is equipped with a fan driven by a two-speed motor through a reduction gear drive. The steam is condensed in the tube bundles by the cool air passing over the condensing tubes. Recoverable steam and condensate from cycle drains, the gland condenser, and the low pressure and hot reheat steam bypasses are also routed to the condenser duct. Liquids are collected in the steam duct drip pot and are pumped to the condensate storage tank.
Condenser vacuum is initially developed by the mechanical hogging pumps, and maintained by the steam jet air ejectors in the condenser air extraction system.
The condenser steam duct includes three 100 per cent bypass flow connections for the hot reheat system and three 100 per cent by-pass flow connections for the low pressure steam (one per HRSG). The main steam bypasses to the cold reheat piping, which in turn is bypassed to the condenser duct after passing through the HRSG, maintaining reheat flow in the HRSGs during bypass operations. The bypass steam is desuperheated to an acceptable energy level prior to being discharged to the condenser duct.
The condensed steam and other returns are collected in the condensate tank which provides condensate storage at the saturation temperature corresponding to the vapour pressure in the condenser. The condensate storage tank level is maintained within limits that ensure that water is always available to the condensate pumps, and prevents flooding of the condensate and make-up de-aerator.
The make-up de-aerator is mounted on the condensate tank and receives make-up from the demineralised water storage tank in the cycle make-up and storage system. The function of the de-aerator is to remove air and noncondensable gases from the make-up water and the condensate return from the condenser modules.
The steam jet air ejector unit draws the non-condensables from the de-aerator. The make-up rate is controlled by a fill control valve to maintain a constant water level in the condenser hot well. When the hot well level is high, condensate is dumped to the plant wastewater sump through the condensate dump control valve. The condensate tank supplies condensate by gravity to the suction of the vertical, cantype, single-speed condensate pumps. The condensate tank is furnished with a ladder and platform for access to the deaerator and the deaerator steam jet air ejector unit. An access platform and manway are provided on one end of the condensate tank. There are two immersion heaters, provided to maintain a minimum water temperature, mounted in the condensate tank. There are three 20-inch pipe connections on the bottom of the tank for connection of the condensate pump suction lines.
A condenser curtain spray is located in the rectangular-to-round transition duct connection above the exhaust duct elbow. The curtain spray control valve is opened whenever the hot reheat steam bypass to the condenser or the LP steam bypass to the condenser is in service. The exhaust duct is then isolated from the steam turbine and the bypass flow migrates to the ACC in all bypass situations.
ACC system operations
Control of the ACC is provided through the plant distributed control system. Control is normally automatic, but manual control of several system components can be accomplished from the DCS operator stations in the control room.
The ACC supports the following three operating modes:
• Auto sequence fan control mode. In this mode, the fan speed sequence is adjusted as required to maintain a constant backpressure regardless of varying turbine load and ambient temperature, within the thermal capacity limits of the condenser. Fan speed may be modified/superseded by the freeze protection or fan protection functions.
• Manual sequence fan control mode. This mode allows the operator to step the air flow up or down for startup and transient conditions. The control system steps the fans through the speed sequence in support of operator requests.
• Direct fan control mode. During certain operating or testing conditions, deviation from the normal fan speed sequence may be necessary. To accomplish this, the control system includes a direct fan control mode. In this mode the fans may be running in a random combination of speeds as selected by the operator, because the selected speed combination may not correspond to a valid speed sequence number as defined in the sequence table.
Within these modes of operation, the ACC supports various forms of freeze protection by means of overrides.
To protect system equipment, automatic controls cut in if certain system components malfunction. Protective actions include the following:
• Overload and short-circuit protection - the ACC fan motors trip on motor overload or short circuit. The motors for motor-operated valves trip on motor overload or short circuit.
• Fan vibration protection - the ACC fan motors trip on fan high vibration.
Why select ACC?
Selecting the best condensing method for a plant involves many variables. Issues that may enter into the decision process include the time allocated for plant permitting, including the air permit, wastewater discharge permit, and sometimes added local permits; the availability of cooling water, and the quantity of water that can be allocated to the plant; the initial capital cost of the equipment, space constraints, and noise considerations.
The cooling method is a key decision in the plant layout and economic viability. In addition to the capital cost of the ACC, one must consider the space it takes up, the impact on performance owing to increased condenser back-pressure and higher auxiliary load (in this case, 50 fan drives), higher plant cooling water temperatures, and the effects of wind on ACC efficiency - all these will have an impact on the overall plant design and the price of associated plant equipment.
Reliant Energy determined that the plants would use ACCs in their initial plans for the plants. With no viable surface water supply at the selected locations for the two plants, make-up water had to come from ground water sources. Initial discussions with state permitting agencies established strict limits to the quantity of water that could be pumped on an annual basis, making air cooling an obvious choice.
An advantage realised by selecting air cooling was the expectation for expedited approval of the required permits for both plants. In addition, the air cooled plant's liquid discharge volume is reduced, improving the process of obtaining discharge permits for the plants. In short, the ACC is currently viewed as an attractive alternative by permitting agencies, and often by the general public.
In order to expedite approval for the plants and use the sites chosen based on availability of a natural gas supply and electrical interconnection, the use of ACC was determined to be the best alternative on the balance of advantages and disadvantages. In making this decision, Reliant considered initial capital costs, increased auxiliary power, increased maintenance costs over the life of the plant, lowered plant output owing to increased backpressure, and decreased potential scheduling impacts that would extend construction time and delay the commercial operation starting date of the plant.
Growing use of technology
Although the use of ACCs in the United States has historically been somewhat limited, current trends in permitting, design, and construction considerations show a growing use of the technology. The scarcity of water, water discharge limitations, and improved efficiencies, cost, and performance of these systems point to the possibility that more power generation facilities will be employing ACCs in the future.