Water is essential for thermoelectric power production. In fact, thermoelectric generation is one of the largest usages of water in the U.S. and around the world. However, most of this water is returned to the water body of origin (slightly warmer). Irrigation for agriculture results in the largest consumption of water, most of the water used in agriculture is not returned to the place of extraction. Converting heat (fossil fuel, biomass combustion, or nuclear reactions) to electricity is accomplished with the Rankine cycle (i.e., steam cycle). To provide an example of a steam cycle in thermoelectric power production, a typical pulverized coal-fired power plant and the associated water path is shown in Figure 1. Water is pressurized and boiled to produce high- temperature, high-pressure steam which is expanded over a turbine to spin a generator to produce electricity. The steam is condensed from a gas to a liquid at the turbine exit. This creates a vacuum that pulls the steam over the turbine. The water is constantly recirculated within this Rankine cycle and is repeatedly converted from gas to liquid and back again. The overall power plant efficiency is restricted by the temperature difference between the steam and condensate; the upper temperature limit is determined by steel properties and the lower temperature determined by the cooling water temperature. Much electricity-related water usage occurs in the steam condenser; ideally, the condensate will be a low temperature, the steam will be a high temperature, and the power plant efficiency can be maximized. If the condensate is not at a low temperature there will be a backpressure on the turbine, which decreases the efficiency of the power plant. If insufficient cooling is available, the plant will not be able to operate. Since water is most often responsible for cooling, it is clear that the relationship between water and electricity is a critical one. However, as water resources become more scarce, researchers and technology developers are employing different options to reduce water requirements.
FIGURE 1. Water balance for a 500-MW subcritical bituminous coal-fired power plant. Not shown leaving the flue gas stack is approximately 928 gpm of water vapor (19%). Note: 1000 gpm = 227 m3/hr
FIGURE 2. Water consumption by various thermoelectric power production options. Note: 1000 gal = 3.79 m3
WATER USE FOR DIFFERENT SOURCES OF ELECTRICITY
Figure 2 shows the average water requirements for several sources of electricity generation, all of which utilize the Rankine cycle described in Figure 1. Several options for coal-based power generation are included. Coal-fired power plant water requirements are generally higher than those for natural gas, but lower than the water usage required for nuclear-based power. Among the different types of coal-fired power plants there is still room for improvement; there are many water-saving technologies that can be employed to reduce overall water consumption. From Figure 2, it is clear that for all the different types of thermoelectric plants, the vast majority of the water requirements are related to cooling. This is a tremendously important focus area when developing water-saving technologies.
SOLUTIONS IN THE WATER/COAL ENERGY NEXUS
As noted, the relationship between water and electricity is a critical one. For coal-fired power plants, many potential improvements can be made to reduce water consumption; in the U.S. some of these improvements have been driven by regulation. With revisions to the U.S. Environmental Protection Agency (EPA) Clean Water Act 316(b), regulations on cooling water intake structures made withdrawing water for cooling more costly and advocated for the replacement of once-through cooling with cooling towers. As the regulations were revised, water permits for coal-fired power plants became more difficult to obtain. In addition, increased regulations on air emissions also resulted in increased water use for power plants; the control of air emissions often involved the use of technologies that transferred the emissions from the gas phase into water. To characterize the water usage by coal-fired power plants and explore potential solutions to water usage concerns, the National Energy Technology Laboratory (NETL) Strategic Center for Coal initiated a power plant water research program in 2001. The following sections in this article discuss general options for specific water-saving strategies explored under this research program.
Cooling and Emissions Control
As is shown in Figure 2, cooling is the largest user and consumer of water for coal-fired power plants. Emissions control, especially wet flue gas desulfurization (FGD), is also another significant consumer of water. Together, emissions control and cooling make up the majority of water usage for coal-fired power plants, although both can be accomplished with alternative technologies.
Once-through cooling is considered the traditional method of cooling coal-fired power plants. However, to meet EPA regulation requirements and to avoid discharging large quantities of water and potentially affecting the original water body, many power plants have opted for recirculation and cooling towers.
FIGURE 3. Fort Martin power plant in West Virginia. The water exiting the stack (foreground) and the cooling towers (diffuse cloud in the background) can easily be seen as the cold air condenses the water.
The recirculating water must be cooled, which is accomplished by evaporating water in the cooling tower; the latent heat of evaporation cools the water. Cooling towers result in less water being withdrawn, but more water being consumed (i.e., water is continually lost to evaporation). Figure 3 is a photograph of the Fort Martin power plant in West Virginia, U.S. The large plume of condensing water from the cooling towers, which is sometimes mistaken for pollution, is clearly visible and indicative of the amount of water being evaporated. Figure 4 illustrates the water balance at a subcritical plant that employs recirculating cooling: The plant loses 542 gal/MWh from the cooling tower and 88 gal/MWh for FGD makeup. Clearly cooling is responsible for the majority of this plant’s water consumption.
Dry cooling is another option that can be employed: Air, not water, is the cooling media. The power plant condensate is usually cooled inside a heat exchanger as ambient air is forced via large fans to flow around finned tubes, all of which is often referred to as an air-cooled condenser (ACC). Although no water is consumed for dry cooling, there are drawbacks. The power plant water temperature can only be lowered to a certain point (i.e., the ambient dry bulb temperature), which in the summer creates a large energy penalty, on the order of 10% of the power plant’s electricity output. This energy penalty results from backpressure on the power plant turbine. Dry cooling is also more capital intensive, as it requires a larger structure. However, dry cooling can be an important option for power plants in severely water-restricted areas.
Various novel improvements in cooling technology are also being studied;5 because the most significant opportunity for water savings is to employ dry cooling, therefore, alternative options for dry cooling are being investigated. For example, a liquid desiccant has been tested at the pilot scale as a heat-transfer medium between the condenser and the atmosphere. Water is used to condense the steam, and the warm water is cooled in a water-to-desiccant heat exchanger. The desiccant is then cooled with a direct-contact desiccant-to-air heat exchanger. The water in the desiccant does not evaporate; in fact, the desiccant absorbs additional water during the night, and this excess moisture evaporates during the day. This provides an additional cooling effect and allows the desiccant temperature to go below the dry bulb temperature, and therefore reduces the energy penalty of dry cooling. Preliminary cost estimates collected under the NETL power plant water program were 40% less than a traditional ACC and the parasitic power requirements were 35% lower. The annual costs for desiccant dry cooling were within ±10% of the comparable wet system.
Currently, wet FGD is the largest emission-control-related water requirement at coal-fired power plants. As is shown in Figure 4, the FGD make-up can require about 88 gal/MWh. There are also dry FGD technologies, although they can require injection of large amounts of dry sorbent. Whether wet or dry FGD is employed is a plant-by-plant decision.
FIGURE 4. Water balance on a subcritical, pulverized coal, 500-MW power plant with a cooling tower and wet FGD
Although CO2 capture and storage (CCS) is not yet commercially deployed, the water consumption of the process has been considered by NETL. The addition of carbon capture to an existing coal-fired power plant was analyzed using the most commercially viable option, an amine absorption process. Fluor’s Econamine technology was used as the basis for the analysis. This process requires a large amount of additional water, primarily due to the loss in efficiency from separating CO2 from the flue gas as well as the compression of the CO2. Figure 5 includes a water balance for a subcritical coal-fired power plant with recirculating cooling, FGD, and CCS. Notably, the cooling water makeup has increased from 524 gal/MWh (no CCS) to 1049 gal/MWh for a similar plant with CCS.
Using Waste Heat
NETL supports external research through competitive solicitations and, through this mechanism, has supported novel research to improve and reduce water use in coal-fired power plants. Utilization of power plant waste heat—for example, using hot air to dry coal—is one approach to reduce the amount of water needed for cooling. Drying coal prior to combustion increases the efficiency of the power plant. Based on lab-scale coal drying research, a fluidized bed dryer was designed; the fluidized bed dries the coal using air warmed by passing over the condenser and also using some heat from the flue gas. This concept was demonstrated with Clean Coal Power Initiative funding at Great River Energy’s Coal Creek Station.6 This project resulted in an estimated 2–4% efficiency improvement (or heat rate reduction). Part of the efficiency increase is due to improved performance of the coal pulverizers and induced draft fans. Notably, it was also estimated that the process would save 5–7% of the cooling water normally required.
FIGURE 5. Water balance on a subcritical, pulverized coal, 500-MW power plant with recirculating cooling, FGD, and amine absorption-based CCS4
Another possible use of waste heat is to reject the heat from the steam cycle to another Rankine cycle, such as ammonia or an organic chemical that boils at a lower temperature. This “bottoming cycle” would generate additional power from the waste heat. Although this concept has not been tested at a power plant to date, it is believed that it has merit. While a bottoming cycle may be capital intensive, an absorption chiller could be integrated into many processes. Another project funded by DOE investigated the use of ice produced in off-peak times to cool the inlet air of a gas turbine. This was calculated to have a net power gain up to 40% and a heat rate reduction as much as 7%. Water can also be recovered from the inlet air as it cools, thus being a water source. An absorption chiller run on waste heat could provide cold air to the turbine. Also, cold air could be used to offset energy penalties of dry cooling on a hot day or to reduce the overall size of an ACC.
Finding Alternative Sources of Water
Alternative sources of freshwater, rather than from the surface, have also been studied and several options exist.7 For example, mine pool water, which is water that has collected in underground voids left by mining, is used for cooling in the anthracite region of Pennsylvania and could also be used from the area under the mined Pittsburgh coal seam. Another example of an alternative water source is water produced during oil and natural gas production, although applications would be limited by transportation and treatment costs. While it has been shown that CCS technologies could result in increased water usage, there is also a chance to recover water during the process. If CO2 is stored in saline aquifers, it is possible that the CO2 storage could be enhanced by removing the aquifer water; then the water could be used for power plant cooling. Today, the most used alternative cooling water supply is treated municipal wastewater. This water source is fairly good quality and located next to nearly all U.S. power plants.
Water can be recovered from within the power plant, from water vapor leaving the cooling towers and/or the flue gas stack.8 For example, NETL funded research that led to the commercialization of the SPX ClearSky Plume Abatement Cooling Tower, which employs an air-to-air heat exchanger that uses ambient air to condense some of the water vapor in the evaporative cooling tower exhaust. The first prototype was tested at San Juan Generating Station (New Mexico, U.S.); a follow-up NETL project redesigned the heat exchanger to make it smaller. The tower condenses about 20% of the water leaving the cooling tower. It is estimated that the current model will pay for itself in water savings in about seven years. With further development and a larger heat exchanger, it is thought that this tower could condense 40–50% of the water from the cooling tower. Modularization of the heat exchangers could decrease the size and lower the cost.
Water could also be recovered from the flue gas. NETL has supported testing this opportunity in three ways: heat exchangers, desiccant absorption, and a ceramic membrane. All were found to be economically viable. Lehigh University tested the condensing heat exchangers in a flue gas slipstream at three coal-fired power plants. Cost–benefit studies of condensing heat exchangers for full scale suggest that placing them downstream of wet FGDs could be cost effective. Estimated annual benefits are $1.3 million versus costs of $0.8 million. In addition to the recovered water, latent heat from the condensing water is put back into the steam cycle for increased efficiency.
Along the same lines of capturing water from flue gas, a calcium chloride desiccant solution was successfully used to absorb water from pilot-scale flue gas using both natural gas and coal at the North Dakota Energy and Environmental Research Center (EERC). The Gas Technology Institute (GTI) tested their Transport Membrane Condenser (TMC) in a five-week slipstream of coal-fired boiler flue gas. The TMC is a ceramic membrane with nano-sized pores that condense water. High- purity water was recovered and some of the latent heat was put back into the steam cycle. This membrane was originally used in natural gas applications and there are ongoing discussions to further test it in coal-fired applications. GTI is also testing a smaller version in home furnaces to recover water from home heating systems and use it to humidify indoor air.10
Southern Company is testing waste heat integration into a solvent (amine)-based 25-MW CO2 capture project at Plant Barry.9 A waste heat recovery (High Efficiency System, HES) technology is a heat exchanger that extracts waste heat from flue gas exiting the power plant’s air preheater (flue gas cooler) and makes that heat available elsewhere in the power plant. In addition to other benefits, the flue gas cooler will reduce the amount of water used in FGD by about 30%. This flue gas cooler is already used in Japan to reheat scrubbed flue gas to eliminate visible plumes. Corrosion can be a problem, but tests in Japan have shown that if the ash/sulfur ratio is in the proper range, sulfur can be removed on the ash in an electrostatic precipitator.
Cooling towers require discharging salty or hard (mineral rich) water (blowdown) to keep the condenser tubes free of corrosion and buildup. In some cases it could be worthwhile to treat this blowdown stream so that it can be reused. NETL has supported experimentation on methods to remove contaminants in the cooling water: removing hard water ions by precipitation with an electrical pulse spark and mechanical filtration; precipitation with electrodeionization; and using various sorbents to filter out impurities. These methods could also be employed to utilize lower quality water instead of freshwater in cooling towers.
Some work was also done on managing the wastewater from coal-fired power plants.11 Several novel adsorbents were tested to remove various contaminants. Also wetlands were used to collect additional water and treat and clean wastewater. Management of water in wetlands was tested at the Hines Energy Complex in Florida and significant improvements in cycle efficiency were found by using wetlands in a cooling pond to reduce cooling water temperature.
CONTINUED EFFORTS
The projected growth in global population will continue to increase the pressure on water and energy resources. As the U.S. Department of Energy further investigates the close link between water and electricity, it is hoped that further research will lead to development and deployment of the options to reduce the water requirements associated with thermoelectric power production.
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