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DOE/FE’s Power Plant Water Management R&D Program Summary, July 2005 

 

Department of Energy/Office of Fossil Energy’s 

Power Plant Water Management R&D Program 

Thomas J. Feeley, III1, Lindsay Green2, James T. Murphy2, 

Jeffrey Hoffmann1

, and Barbara A. Carney1 

1. U.S. Department of Energy, National Energy Technology Laboratory 

2. Science Applications International Corporation 

INTRODUCTION 

Coal-fired power plants utilize significant quantities of both coal and water for generating 

electrical energy. For example, a 500 MW power plant burns approximately 250 tons per 

hour of coal while using over 12 million gallons per hour of water for cooling and other 

process requirementsa

. The United States Geological Survey (USGS) estimates that 

thermoelectric generationb

 accounts for approximately 136,000 million gallons per day 

(MGD) of freshwater withdrawalsc

, ranking only slightly behind agricultural irrigation as 

the largest source of freshwater withdrawals in the United States.1

 As U.S. population and 

associated economic development continues to expand, the demand for electricity will 

increase. The Energy Information Administration’s (EIA) latest forecast estimates U.S. 

coal-fired generating capacity will grow from approximately 305 GW in 2003 to 389 GW 

in 2025.2

 As such, coal-fired power plants may increasingly compete for freshwater with 

other sectors such as domestic, commercial, agricultural, industrial, and in-stream use – 

particularly in regions of the country with limited freshwater supplies. In addition, current 

and future water-related environmental regulations and requirements will also challenge 

the operation of existing power plants and the permitting of new thermoelectric 

generation projects. 

In response to these challenges to national energy sustainability and security, the 

Department of Energy/Office of Fossil Energy’s National Energy Technology Laboratory 

(DOE/NETL) has initiated an integrated research and development (R&D) effort under 

its Innovations for Existing Plants (IEP) program directed at technologies and concepts to 

reduce the amount of freshwater used by power plants and to minimize any potential 

impacts of plant operations on water quality. This paper provides background information 

on the relationship between water and thermoelectric power generation and describes the 

R&D activities currently being sponsored by DOE/NETL’s IEP program to address 

current and future water-energy issues. 

a

 Actual cooling water flow rate requirements for a particular plant will vary depending on type of cooling 

water system and design parameters. 

b

 Thermoelectric generation includes coal, oil, natural gas and nuclear power generation. Coal-based 

generation represents approximately 58% of total U.S. thermoelectric generation based on EIA AEO 2005 

estimates. 

c

 This includes both surface and ground water withdrawals. 
BACKGROUND 

Water Use for Thermoelectric Power Generation 

Thermoelectric generation represents the largest segment of U.S. electricity production 

and coal-based power plants alone generate more than half of the nation’s electricity 

supply. According to USGS water use survey data, 346 billion gallons of freshwater per 

day (BGD) was used in the United States in 2000. Figure 1 presents the percentage of 

total U.S. freshwater withdrawal by source category. Thermoelectric generation 

accounted for 39% (136 BGD) of all freshwater withdrawals in the nation in 2000, 

second only to irrigation. Each kWh of thermoelectric generation requires approximately 

25 gallons of waterd

, primarily used for cooling purposes – a 500 MW power plant would 

use approximately 300 million gallons of water per day. However, power plants also use 

water for operation of pollution control devices such as flue gas desulfurization (FGD)

technology as well as for ash handling, wastewater treatment, and wash water. When 

discussing water and thermoelectric generation, it is important to distinguish between 

water use and water consumption. Water use represents the total water withdrawal from a

source and water consumption represents the amount of that withdrawal that is not 

returned to the source. Although thermoelectric generation is the second largest user of 

water on a withdrawal basis, it was only responsible for about 3% of the total of 100 

BGD freshwater consumed in 1995 compared to 81% for irrigation as shown in Figure 

2.3

 

Figure 1 – U.S. Freshwater Withdrawal (2000 ) Figure 2 – U.S. Freshwater Consumption (1995)

 Freshwater Withdrawal by Sector

Thermoelectric

39%

Public Supply

13%

Aquaculture

1%

Industrial

5%

Mining

1%

Livestock

1%

Irrigation

40%

Domestic

1%

Freshwater Consumption by Sector

Commercial

1%

Domestic

7%

Irrigation

81%

Livestock

3%

Thermoelectric

3% Mining

1% Industrial

3%

As discussed above, large quantities of cooling water are required for thermoelectric 

power plants to support the generation of electricity. Thermoelectric generation relies on 

a fuel source (fossil or nuclear) to heat water to steam that is used to drive a turbinegenerator. Steam exhausted from the turbine is condensed and recycled to the steam 

 

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DOE/FE’s Power Plant Water Management R&D Program Summary, July 2005 

d

 This number is a weighted average that captures total thermoelectric water withdrawals and generation for 

both once-through and recirculating cooling systems. 
generator or boiler. The steam condensation typically occurs in a shell-and-tube heat 

exchanger known as a condenser. The steam is condensed on the shell side by the flow 

of cooling water through tube bundles located within the condenser. Cooling water mass

flow rates of greater than 25 times the steam mass flow rate are necessary depending on 

the allowable temperature rise of the cooling water – typically 15-25oF. There are 

basically two types of cooling water system designs – once-through (open loop) or

recirculating (closed loop). In once-through systems the cooling water is withdrawn from 

a local water body such as a lake, river, or ocean and the warm cooling water is 

subsequently discharged back to the same water body after passing through the 

condenser. As a result, plants equipped with once-through cooling water systems have 

relatively high water use, but low water consumption. The most common type of 

recirculating system uses wet cooling towers to dissipate the heat from the cooling water

to the atmosphere. In wet recirculating systems the warm cooling water is typically 

pumped from the condenser to a cooling tower where the heat is dissipated directly to 

ambient air by evaporation of the water and heating the air. The cooling water is then 

recycled back to the condenser. In addition to cooling towers, cooling ponds or lakes can 

also be used to accomplish evaporation in recirculating systems. 

Because of evaporative losses, a portion of the cooling water needs to be discharged from 

the system – known as blowdown − to prevent the buildup of minerals and sediment in 

the water that could adversely affect performance. For a wet recirculating system, only 

makeup water needs to be withdrawn from the local water body to replace water lost 

through evaporation and blowdown. As a result, plants equipped with wet recirculating 

systems have relatively low water use, but high water consumption, compared to oncethrough systems. Typical wet recirculating cooling water system flow rates for a 650 MW

coal-fired plant are shown in Figure 3. 

Figure 3 - Process Flow Schematic for Wet Recirculating Cooling Water System 

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DOE/FE’s Power Plant Water Management R&D Program Summary, July 2005 

Boiler 

Feedwater

Boiler

Steam

Evaporation 

& Drift 

5,035,000 lb/hr 

6,500 gpm 

650 MW

Generator Turbine

Cooling 

Tower 260,000 gpm 

Condensate

Warm Water 20 oF Rise 

Steam

Cool Water Condenser

10,000 gpm 

Make-up Water Blowdown 

7,000 gpm 500 gpm 
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DOE/FE’s Power Plant Water Management R&D Program Summary, July 2005 

Wet cooling towers are available in two basic designs – mechanical draft and natural 

draft. Mechanical draft towers utilize a fan to move ambient air through the tower, while 

natural draft towers rely on the difference in air density between the warm air in the 

tower and the cooler ambient air outside the tower to draw the air up through the tower. 

In both designs the warm cooling water is discharged into the tower for direct contact 

with the ambient air. 

A second type of recirculating cooling system is known as dry cooling. Dry recirculating 

cooling systems use either direct or indirect air-cooled steam condensers. In a direct aircooled steam condenser the turbine exhaust steam flows through air condenser tubes that 

are cooled directly by conductive heat transfer using a high flow rate of ambient air that 

is blown by fans across the outside surface of the tubes. Therefore, cooling water is not 

used in the direct air-cooled system. In an indirect air-cooled steam condenser system a 

conventional water-cooled surface condenser is used to condense the steam, but an aircooled closed heat exchanger is used to conductively transfer the heat from the water to 

the ambient air. As a result, there is no evaporative loss of cooling water with an indirectair dry recirculating cooling system and both water use and consumption are minimal. 

Due to relatively higher capital and operating costs and lower performance, dry 

recirculating cooling systems are not as prevalent as the wet recirculating cooling 

systems. 

Of the 136 BGD of freshwater use by thermoelectric generators in 2000, USGS estimated 

approximately 88% was used at plants with once-through cooling systems. Table 1 

presents an estimate of average water use and consumption for once-through and 

recirculating systems based on year 2000 data from EIA’s Form 767 report.4

 Oncethrough systems have very high water use requirements, but since nearly all of the water 

is returned to the source body, consumptive losses are low on a percentage basis. 

Recirculating wet systems have lower water use requirements, but consumptive losses 

through direct evaporation can be relatively high on a percentage basis. In 2001, 

approximately 31% of thermoelectric generating units were equipped with wet cooling 

towers, representing approximately 38% of installed generating capacity. 

Table 1 – Average Cooling System Water Use and Consumption 

Average gal/kWh Type of Cooling Water 

System Water Use Water 

Consumption 

Once-through 37.7 0.1 

Recirculating wet 1.2 1.1 

It is difficult to estimate future freshwater use and consumption by thermoelectric 

generation due to changes in the type of generation, method of cooling, and source of 

water. Based on EIA projections of thermoelectric generation in 2025, DOE/NETL 

estimates that daily freshwater withdrawals could decrease to 113 BGD or increase to 

138 BGD, and that daily freshwater consumption could remain at 3.3 BGD or increase to 

8.7 BGD.5

 
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DOE/FE’s Power Plant Water Management R&D Program Summary, July 2005 

Impact of Water Availability on Thermoelectric Power Generation 

Freshwater availability is a critical limiting factor in economic development and 

sustainability and directly impacts electric-power supply. A 2003 study conducted by the 

Congressional General Accounting Office indicates that 36 states anticipate water 

shortages in the next ten years under normal water conditions, and 46 states expect water 

shortages under drought conditions.6

 Water supply and demand estimates by EPRI for the 

years 1995 and 2025 also indicate a high likelihood of local and regional water shortages 

in the United States.7

 The area that is expected to face the most serious water constraints 

is the arid southwestern United States. 

In any event, the demand for water for thermoelectric generation will increasingly 

compete with demands from other sectors of the economy such as agriculture, domestic, 

commercial, industrial, mining, and in-stream use. EPRI projects the potential for future 

constraints on thermoelectric power in 2025 for Arizona, Utah, Texas, Louisiana, 

Georgia, Alabama, Florida, and all of the Pacific Coast states. Competition over water in 

the western United States, including water needed for power plants, led to a 2003 

Department of Interior initiative to predict, prevent, and alleviate water-supply conflicts.8

 

Other areas of the United States are also susceptible to freshwater shortages as a result of 

drought conditions, growing populations, and increasing demand. 

Concern about water supply expressed by state regulators, local decision-makers, and the 

general public is already impacting power projects across the United States. For 

example, Arizona recently rejected permitting for a proposed power plant because of 

concerns about how much water it would withdraw from a local aquifer.9

 An existing 

Entergy plant located in New York is being required to install a closed-cycle cooling 

water system to prevent fish deaths resulting from operation of its once-through cooling 

water system.10 Water availability has also been identified by several Southern States 

Energy Board member states as a key factor in the permitting process for new merchant 

power plants.11 In early 2005, Governor Mike Rounds of South Dakota called for a 

summit to discuss drought-induced low flows on the Missouri River and the impacts on 

irrigation, drinking-water systems, and power plants.12 Also, residents of Washoe 

County, Nevada expressed opposition to a proposed coal-fired power plant in light of 

concerns about how much water the plant would use.13 Another coal-fired power plant to 

be built in Wisconsin on Lake Michigan has been under attack from environmental 

groups because of potential effects of the facility’s cooling-water-intake structures on the 

Lake’s aquatic life.14

Such events point towards a likely future of increased conflicts and competition for the 

water the power industry will need to operate their thermoelectric generation capacity. 

These conflicts will be national in scope, but regionally driven. It is likely that power 

plants in the west will be confronted with issues related to water rights, that is, who owns 

the water and the impacts of chronic and sporadic drought. In the east, current and future 

environmental requirements, such as the Clean Water Act’s intake structure regulation, 

could be the most significant impediment to securing sufficient water, although local 

drought conditions can also impact water availability. Key environmental regulations 

that can potentially impact power plants are summarized below. 
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DOE/FE’s Power Plant Water Management R&D Program Summary, July 2005 

Environmental Regulations Affecting Thermoelectric Power Generation Water Use 

The U.S. Environmental Protection Agency (EPA) has been charged with maintaining 

and improving the Nation's water resources for uses including but not limited to 

agricultural, industrial, nutritional, ecological, and recreational. To accomplish this goal, 

EPA has issued several regulations under the Clean Water Act and the Safe Drinking 

Water Act that directly impact the discharge of pollutants from power plants to receiving 

waters as well as the intake of water for cooling and other power plant needs. The 

following is a summary of regulations that affect power plant water use. 

The Clean Water Act 

The Clean Water Act (CWA) provides for the regulation of discharges to the Nation's 

surface waters. The CWA calls for a federal-state partnership in which the federal 

government sets the standards for pollution discharge and states are responsible for the 

implementation and enforcement. Initial emphasis was placed on "point source" 

pollutant discharge, but 1987 amendments authorized measures to address "non-point 

source" discharges, including stormwater runoff from industrial facilities. Permits are 

issued under the National Pollutant Discharge Elimination System (NPDES), which 

designates the highest level of water pollution or lowest acceptable standards for water 

discharges. With EPA approval, the states may implement standards more stringent than 

federal water quality standards but they may not be less stringent. Certain sections of the 

CWA are particularly applicable to water issues related to power generation and are 

described below in more detail. 

• CWA §303 Water Quality Standards and Implementation Plans - Section 303 of 

the CWA, the Total Maximum Daily Load (TMDL) program, requires states to 

develop lists of impaired waters—water bodies that do not meet water quality 

standards (WQS) that the states have set, even after the installation of the 

minimum required levels of pollution control technology. States must then 

establish priority rankings for waters that do not meet the WQS and develop 

TMDLs for these water bodies. A TMDL specifies the maximum amount of a 

pollutant that an impaired water body can receive and still meet WQS. While 

states are responsible for establishing the TMDL, the CWA requires EPA to 

approve or disapprove the impaired water lists and TMDLs established by the 

states. After establishing a TMDL, states have 10 years to develop 

implementation plans for improving the quality of the affected waters. 

• CWA §316(a) Water Thermal Discharge – Section 316(a) requires the regulation 

of water thermal discharge from cooling water systems in order to protect 

shellfish, fish, and other aquatic wildlife. 

• CWA §316(b) Cooling Water Intake Structures – Section 316(b) is arguably the 

most urgent water-related issue facing thermoelectric power generation in the near 

term. This section requires that the location, design, construction and capacity of 

cooling water intake structures reflect the best technology available for 

minimizing adverse environmental impact, such as impingement or entrainment 

of aquatic organisms due to the operation of cooling water intake structures. 
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DOE/FE’s Power Plant Water Management R&D Program Summary, July 2005 

•

•

•

•

Regulations to implement Section 316(b) are being issued in three phases that 

cover different facility categories. The Phase I rule was issued in December 2001 

and effectively requires all new thermoelectric power generation plants to install 

closed-cycle cooling systems due to standards for water intake capacity and 

velocity. The Phase II rule, issued in July 2004, applies to existing thermoelectric 

power generation plants that withdraw more than 50 MGD of water and use at 

least 25 percent of the water withdrawn for cooling purposes only. Although the 

Phase II rule requires significant percentage reductions in both impingement and 

entrainment losses from uncontrolled levels, it also provides flexible compliance 

alternatives so that conversions of open-cycle to closed-cycle cooling water 

systems are not mandated. Regulations for Phase III were proposed in November 

2004 and will apply to other industrial sources and new offshore and coastal oil 

and gas extraction facilities. 

The Safe Drinking Water Act – The Safe Drinking Water Act (SDWA) serves to protect 

humans from contaminants in the Nation’s public drinking water supply. Amended in 

1986 and 1997, the law requires many actions to protect drinking water and its sources. 

The SDWA requires EPA to set national drinking water standards and create a joint 

federal-state system to ensure compliance. While the provisions of the SDWA apply 

directly to public water systems in each state, the Act is relevant to thermoelectric power 

generation because waste streams may contain detectable levels of elements or 

compounds that have established drinking water standards. Under the SDWA, regulations 

that would require additional limits on mercury, arsenic, and other trace metals could also 

affect how power plants dispose of coal by-products. 

INNOVATIONS FOR EXISTING PLANTS PROGRAM 

DOE/NETL’s IEP Program is a comprehensive R&D effort directed at the development 

of advanced technologies and knowledge products that can enhance the environmental 

performance of the existing fleet of coal-fired power plants. In response to the growing 

recognition of the inter-dependence between freshwater availability and quality and 

electricity production, the IEP program was broadened in 2003 to include research 

directed at coal-fired power plant related water management issues.15 The overall goal of 

this effort is to reduce the amount of freshwater needed for power plant operations and to 

minimize potential impacts on water quality. The research encompasses laboratory and 

bench-scale activities through pilot- and full-scale demonstrations and is performed in 

partnership and collaboration with industry, academia, technology developers, and other 

government organizations. The program is built around four specific areas of research: 

Non-Traditional Sources of Process and Cooling Water 

Innovative Water Reuse and Recovery 

Advanced Cooling Technology 

Advanced Water Treatment and Detection Technology 

The following is a brief summary of several recently completed and on-going R&D 

projects in these four research areas. Several water-related projects funded under the 
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DOE/FE’s Power Plant Water Management R&D Program Summary, July 2005 

University Coal Research and the Clean Coal Power Initiative programs are also 

discussed. 

Non-Traditional Sources of Process and Cooling Water 

Research and analysis are being conducted to evaluate and develop cost-effective 

approaches to using non-traditional sources of water to supplement or replace freshwater 

for cooling and other power plant needs. Water quality requirements for cooling systems 

can be less restrictive than many other applications such as drinking water supplies or 

agricultural applications, so opportunities exist for the utilization of lower-quality, nontraditional water sources. Examples include surface and underground mine pool water16, 

geological carbon sequestration and coal-bed methane produced waters, and industrial 

and/or municipal wastewater. 

Strategies for Cooling Electric Generating Facilities Utilizing Mine Water: Technical 

and Economic Feasibility 

West Virginia University’s Water Research Institute conducted a study to evaluate the 

technical and economic feasibility of using water from abandoned underground coal 

mines in the northern West Virginia and southwestern Pennsylvania region to supply 

cooling water to power plants.17 The amount of mine water available, the quality of the 

water, and the types of water treatment needed are all factors that were analyzed during 

this study. Non-traditional water sources such as coal mine discharges not only have the 

potential to reduce freshwater power plant cooling requirements, they also can improve 

the efficiency of the cooling process due to the lower water temperatures associated with 

deep mine pools. 

The study included identification of available mine water reserves in the region with 

sufficient capacity to support power plant cooling water requirements under two 

scenarios. The first scenario was to provide the makeup water requirements for a 600 

MW plant equipped with a closed-loop recirculating cooling water system. The second 

scenario was to provide the entire cooling water requirement for a 600 MW plant 

equipped with a closed-loop recirculating cooling water system utilizing a flooded 

underground mine as a heat sink. If feasible, the second scenario would eliminate the 

need for a wet cooling tower to dissipate the heat to the atmosphere. 

The study identified eight potential sites under the first scenario where underground mine 

water is available in sufficient quantity to support the 4,400 gallons per minute (gpm) 

makeup water requirements for a closed-loop 600 MW plant. Three of these sites were 

further evaluated for preliminary design and cost analysis of mine pool water collection, 

treatment, and delivery to a power plant. One site was selected for each of three mine 

pool water chemistry categories based on “net alkalinity” as measured in mg/L equivalent 

concentration of CaCO3 − net acidic (<-50 mg/L), neutral (-50 to +50 mg/L), and net 

alkaline (>+50 mg/L). The net alkalinity of the mine pool water determines the water 

treatment requirements. The mine pool water treatment process includes pre- and postaeration, neutralization with hydrated-lime, and clarification. A water treatment option 
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DOE/FE’s Power Plant Water Management R&D Program Summary, July 2005 

using hydrogen peroxide for neutralization was also evaluated. The cost analysis 

concluded that depending on site conditions and water treatment requirements that 

utilization of mine pool water as a source of cooling water makeup can be cost 

competitive with freshwater makeup systems. Table 2 provides a summary of the capital 

and operating cost estimates for mine pool water collection and treatment systems at the 

three sites. 

Table 2 – Cost Estimate for Mine Pool Water Collection and Treatment System 

Cost Flaggy Meadows 

(net-acidic) 

Irwin 

(near-neutral) 

Uniontown 

(net-alkaline) 

Total Capital Cost, $ 5,740,000 3,770,000 3,464,000 

Operating Cost, $/yr 1,367,000 363,000 433,000 

Annualized Cost, $/1000 gallons 0.79 0.26 0.29 

 

Based on fluid and heat flow modeling of the second scenario, it was determined that 

interconnection of two adjoining mines would be necessary to provide sufficient heat 

transfer residence time to adequately cool the recirculating water flow. As a result, the 

study identified only one potential site for a closed-loop recirculating cooling water 

system utilizing a flooded underground mine as a heat sink. Furthermore, that site would 

be limited to the cooling water requirements of a 217 MW unit. This project was 

completed in January 2005. 

Use of Produced Water in Recirculated Cooling Systems at Power Generation Facilities 

The Electric Power Research Institute (EPRI) evaluated the feasibility of using produced 

waters, a by-product of natural gas and oil extraction, to meet up to 10 percent of the 

approximately 20 MGD of make-up cooling water demand for the mechanical draft 

cooling towers at Public Service of New Mexico’s 1,800 MW San Juan Generating 

Station (SJGS) located near Farmington, New Mexico.18 Two major issues are associated 

with this use of produced water: 1) collection and transportation of the produced water to 

the plant and 2) treatment of the produced water to lower the total dissolved solids (TDS) 

concentration. 

Providing cost-effective collection and transportation of produced water from the 

wellhead or disposal facility to the power plant is a significant issue. There are over 

18,000 oil and gas wells in the San Juan Basin in New Mexico, where SJGS is located, 

that generate more than 2 MGD of produced water. Most of the produced water in the 

region is collected in tanks at the wellhead and transported by truck to local saltwater 

disposal facilities. The SJGS evaluated a two-phased approach for transportation of 

produced water to the plant site (Figure 3). In the first phase, an 11-mile pipeline would 

be built to gather and convey close-in production. Existing unused gas and oil pipelines 

would be converted to transport produced water in the second phase. 
Figure 3 – Pipeline System for Transportation of Produced Water to San Juan Generating Station

Water quality is an issue when using produced water to supplement plant cooling water 

requirements due to high TDS concentrations. Cooling water currently used at the SJGS 

is withdrawn from the San Juan River and contains only 360 mg/L of TDS compared to 

produced water with a TDS concentration ranging from 5,440 to 60,000 mg/L. For 

comparison, sea water contains 26,000 mg/L. Therefore, the produced water would have 

to be treated prior to use at the plant in order to reduce TDS to an acceptable level. 

In addition to cooling tower make-up, produced water was also evaluated for use as 

bottom ash sluice water, fly ash wetting water, and FGD absorber make-up. It was 

determined that FGD absorber make-up would be the least costly use for treated 

produced water. The most economical treatment method identified was high efficiency 

reverse osmosis with a brine concentrator distillation unit that would process 

approximately 1,100 gpm of produced water. Based on this equipment arrangement, the 

cost for produced water treatment would include an initial capital cost of $14.1 million 

and operating costs of $2.98 million per year that includes approximately 2 MW for

auxiliary power. The total project capital cost including collection, transportation, and 

treatment facilities is $43.1 million. This study was completed in April 2005. 

Innovative Water Reuse and Recovery 

Research is currently underway to develop advanced technologies to reuse power plant 

cooling water and associated waste heat and investigate methods to recover water from 

coal and power plant flue gas. Such advances have the potential to reduce fossil fuel 

power plant water withdrawal and consumption. 

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DOE/FE’s Power Plant Water Management R&D Program Summary, July 2005 
Water Extraction from Coal-Fired Power Plant Flue Gas 

The University of North Dakota’s Energy & Environmental Research Center 

(UNDEERC) is developing a technology to extract water vapor from coal-fired power

plant flue gases in order to reduce makeup water requirements for the plant’s cooling

water system.19 The flue gas contains large amounts of water vapor produced from the 

coal combustion process. Coal contains in-situ water and the combustion of the hydrogen 

within the coal matrix also releases additional water. The amount of water potentially 

available for recovery from the flue gas is sufficient to substantially reduce the need for 

plant makeup water withdrawals. 

This project has two objectives. The first objective is to develop a cost-effective liquid 

desiccant-based dehumidification technology to recover a large fraction of the water 

present in the plant flue gas. The second objective is to perform an engineering 

evaluation to determine how such a technology can be integrated to recover water, 

improve efficiency, and reduce stack emissions of acid gases and carbon dioxide. 

The liquid desiccant-based dehumidification system utilizes low-grade heating and 

cooling sources available at the power plant. A conceptual schematic of the proposed 

prototype system is shown in Figure 4. The flue gas is cooled and then subjected to a 

liquid desiccant absorption process that removes water from the flue gas. By stripping 

off the absorbed water, the weak desiccant solution is regenerated back to the strong 

desiccant solution. The water vapor that is produced during the regeneration process is 

condensed and made available for plant makeup water. 

Figure 4 - Conceptual Design of Liquid Desiccant Process 

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DOE/FE’s Power Plant Water Management R&D Program Summary, July 2005 
To date, a desiccant selection and characterization evaluation has been conducted by 

ranking the merits of potential desiccants based on physical and chemical data along with 

laboratory testing. One of the desiccants was selected for initial pilot-scale testing. Data 

from the pilot-scale testing show that the performance of the system was better than

predicted by chemical process models. Based on pH and chemistry, extracted water 

quality is good and off-gas of undesirable species, such as SO2 and NOx, from the 

solution was minimal. Prospects for commercial development of the process are 

encouraging. This project will be complete in September 2005. 

Use of Coal Drying to Reduce Water Consumed in Pulverized Coal Power Plants

Lehigh University is conducting laboratory-scale testing to evaluate the performance and 

economic feasibility of using low-grade power plant waste heat to partially dry low-rank 

coals prior to combustion in the boiler.20 The project will be completed in December 

2005. While bituminous coals have minimal moisture content (less than 10%), low-rank 

coals have significant moisture content – subbituminous and lignite coals range from 15-

30% and 25-40% moisture, respectively. In this process heat from condenser return 

cooling water is extracted upstream of the cooling tower to warm ambient air that is then 

used to dry the coal. Lowering the temperature of the return cooling water reduces

evaporative loss in the tower, thus reducing overall water consumption. 

In addition, drying the coal prior to combustion can improve the plant heat rate, and in 

return reduce overall air emissions. Figure 5 shows a schematic of the plant layout with 

the air heater and coal dryer. Variations of this approach are also being evaluated that 

include using heat from combustion flue gas to supplement the condenser return cooling 

water to dry the coal. Information from this project is being used to design a full-scale 

coal drying system at Great River Energy’s 546 MW lignite-fired Coal Creek Power

Station located near Underwood, North Dakota. The Coal Creek project is being funded 

under DOE/NETL’s Clean Coal Power Initiative. 

Figure 5 - Schematic of Lehigh Coal Drying Process 

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DOE/FE’s Power Plant Water Management R&D Program Summary, July 2005 
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DOE/FE’s Power Plant Water Management R&D Program Summary, July 2005 

An Innovative Fresh Water Production Process for Fossil Fired Power Plants Using 

Energy Stored in Main Condenser Cooling Water 

The University of Florida is investigating an innovative diffusion-driven desalination 

process that would allow a power plant that uses saline water for cooling to become a net 

producer of freshwater.21 Hot water from the condenser provides the thermal energy to 

drive the desalination process. Saline water cools and condenses the low pressure steam 

and the warmed water then passes through a diffusion tower to produce humidified air. 

The humidified air then goes to a direct contact condenser where fresh water is 

condensed out. This process is more advantageous than conventional desalination 

technology in that it may be driven by low-temperature waste heat. Cool air, a byproduct of this process, can also be used to cool nearby buildings. 

To date, a diffusion driven desalination facility has been designed that can produce 1.03 

MGD of fresh water from the waste heat of a 100 MW plant. The only energy cost to use 

this process is the energy used to power the pumps and fans. An economic simulation of 

the system has been performed and shows that production cost is competitive with the 

costs associated with reverse osmosis or flash-evaporation technologies. This project will 

be completed in 2005.

Advanced Cooling Technology 

This component of the program is focused on research to develop technologies that 

improve performance and reduce costs associated with wet cooling, dry cooling, and 

hybrid cooling technologies. In addition, the research area covers innovative methods to 

control bio-fouling of cooling water intake structures as well as advances in intake 

structure systems. 

Development of Hybrid Cooling Water System 

In conjunction with the produced water feasibility study being conducted at the San Juan 

Generating Station, EPRI will also conduct pilot-scale testing of a hybrid cooling 

technology. The Wet Surface Air Cooler (WSAC) is a closed-loop cooling system 

coupled with open-loop evaporative cooling. Warm water from the steam condenser 

flows through tubes that are externally drenched with spray water. Heat is removed 

through the evaporative effect of the spray water. The tubes are always covered in water, 

hence the name “wet surface”. The WSAC is capable of operating in a saturated mineral 

regime because of its spray cooling configuration. A high spray rate is used to ensure 

that the tubes are constantly flooded and helps the spray nozzles from becoming plugged. 

Co-current flow of air and spray water eliminates dry spots on the underside of the tubes 

where fouling often occurs. The tubes have no fins and are spaced far enough apart that 

solids or precipitates from the poor quality water are washed into the basin. 

At SJGS this system will be used as auxiliary cooling for condenser cooling water. The 

spray water will be blowdown water from the existing cooling towers. The testing will 

determine to what extent the WSAC can concentrate untreated cooling tower blowdown 
before thermal performance is compromised. It will be used as a pre-concentrating

device for the cooling tower blowdown that is typically evaporated in a brine 

concentrator or evaporation pond at this zero discharge facility. The pilot test unit will be

skid mounted and will consist of three separate tube bundles. Each bundle will be 

constructed of a different metal to evaluate the corrosion potential of the degraded water.

The pilot unit will be instrumented to monitor thermal performance, conductivity of the

spray water, and corrosion. 

Environmentally-Safe Control of Zebra Mussel Fouling 

Zebra mussels are small, fingernail-sized bivalves that can live in rivers and lakes in 

enormous densities. Native to Europe, these mussels were first discovered in Lake St. 

Clair, near Detroit, in 1988 and have since spread as far south as Louisiana and as far 

west as Oklahoma. Figure 6 shows the distribution of zebra mussels in North America. 

Zebra mussels can attach to almost any hard surface and their colonization on cooling

water intake structures can restrict water intake and lead to significant plant outages. 

There is a need for economical and environmentally safe methods for zebra mussel 

control where this invasive species has become problematic. Researchers with the New 

York State Education Department are conducting a three-year study to evaluate a 

particular strain of naturally occurring bacteria, Pseudomonas fluorescens, that has shown 

to be selectively lethal to zebra mussels but benign to non-target organisms.22 Testing is 

being conducted on the service water treatment system for Rochester Gas and Electric 

Corporation’s Russell Station that withdraws 4 to 5 MGD from Lake Ontario. 

Figure 6 - North America Distribution of Zebra Mussels 

To date, research suggests that that this method for zebra mussel control will pose less of 

an environmental risk than the current use of biocides like chlorine. However, if this

method is to be widely adopted, it must also be cost competitive. Laboratory experiments

to define key nutrients required to produce more toxin per bacterial cell are underway. 

This is a long-term experiment and an accurate measurement of this increase in cell 

toxicity will not be available until design of the entire chemically-defined culture medium 

and culturing protocol is finalized in 2005. 

14 

DOE/FE’s Power Plant Water Management R&D Program Summary, July 2005 
15 

DOE/FE’s Power Plant Water Management R&D Program Summary, July 2005 

Enhanced Performance Carbon Foam Heat Exchanger for Power Plant Cooling 

Ceramic Composites, Inc. has partnered with SPX Corporation to develop high thermal 

conductivity foam to be used in an air-cooled steam condenser for power plants that 

could significantly decrease energy consumption associated with conventional dry 

cooling systems.23 In addition, the availability of a more efficient dry cooling technology 

would offer an alternative to power plants for minimizing adverse impacts such as 

organism intake, warm water discharge, and evaporative water loss associated with wet 

or wet-dry hybrid cooling technology. This project will be complete in July 2006. 

Advanced Water Treatment and Detection Technology 

Future controls on the emission of mercury and possibly other trace elements have raised 

concerns about the ultimate fate of these contaminants once they are removed from the 

flue gas. Preventing these “air pollutants” from being transferred to surface or ground 

waters will be critical. In addition, ammonia from selective catalytic reduction systems 

used to control nitrogen oxide emissions can appear in a power plant’s wastewater 

streams such as ash sluice water. Research is needed for advanced technologies to detect 

and remove mercury, arsenic, selenium and other components from the aqueous streams 

of coal-based power plants should effluent standards be tightened in the future. 

Fate of As, Se, and Hg in a Passive Integrated System for Treatment of Fossil Plant 

Waste Water 

Tennessee Valley Authority (TVA) and EPRI are conducting a three-year study of a 

passive treatment technology to remove trace levels of arsenic, mercury, and selenium, as 

well as ammonia and nitrate from fossil power plant wastewater. An extraction trench 

containing zero-valent iron for removal of trace contaminants is included in the study in 

order to evaluate an integrated passive treatment system for removal of these trace 

compounds. This project will be complete in 2006. 

Demonstrating a Market-Based Approach to the Reclamation of Mined Lands in West 

Virginia 

EPRI is demonstrating a market-based approach to abandoned mine land (AML) 

reclamation by creating marketable water quality and carbon emission credits. The 

project involves the reclamation of thirty acres of AML in West Virginia through (1) the 

installation of a passive system to treat acid mine drainage, (2) application of fly ash as a 

mine soil amendment, and (3) reforestation for the capture and sequestration of 

atmospheric carbon dioxide (CO2). Water quality and CO2 uptake will be measured and 

the costs and environmental benefits of the remedial treatments will be developed. 

Potential eco-credits include water quality credits due to decreased acid mine drainage 

and other benefits resulting from the soil amendment, as well as potential credits for CO2 

sequestration due to more than 36,000 seedlings to be planted at the site. This project 

will be completed in 2005. 
16 

DOE/FE’s Power Plant Water Management R&D Program Summary, July 2005 

Novel Anionic Clay Adsorbents for Boiler-Blow Down Waters Reclaim and Reuse 

The University of Southern California is conducting a feasibility study of using novel 

anionic clay sorbents for treating and reusing power plant boiler blowdown water that can 

contain metals such as arsenic and selenium.24 Currently, it is difficult to economically 

and effectively clean this waste stream as flow rates are high and the metals 

concentrations are at trace levels. The goal of this project is to develop an inexpensive 

clay-based adsorbent that can be used to treat the high-volume, low-concentration 

wastewater stream. This project will be complete in August 2005. 

Specifically Designed Constructed Wetlands: A Novel Treatment Approach for Scrubber 

Wastewater 

Clemson University will evaluate pilot-scale constructed wetland treatment systems for 

treatment of trace elements in coal-fired power plant FGD wastewater. The overall goal 

of this project is to decrease arsenic, mercury, and selenium concentrations in FGD 

wastewater to achieve applicable discharge limitations. Specific objectives are to: 1) 

measure trace element removal performance; 2) determine wetland treatment system 

biogeochemical reactions and rates; and 3) measure changes in the bioavailability of the 

trace elements (e.g. toxicity of sediments in constructed wetlands and toxicity of outflow 

waters from the treatment system). The pilot-scale constructed wetland treatment system 

consists of a 6,800 liter (L) upstream equalization basin followed by three parallel 

treatment trains. Each of the treatment trains includes four 378-L cells – two wetland 

cells planted with bulrush, a gravel manganese oxidation cell, and a wetland cell planted 

with cattails. Both simulated and actual FGD wastewater samples will be included in the 

evaluation. This project will be complete in August 2005. 

SUMMARY 

Freshwater resources and reliable and secure electrical energy are inextricably linked. 

Thermoelectric generation requires a sustainable, abundant, and predictable source of 

water and is second only to irrigation as the largest user of freshwater in the United 

States. As the demand for electricity increases, so will the need for water for power 

generation. However, thermoelectric power plants will increasingly compete with 

demands for freshwater by the domestic, commercial, agricultural, industrial, and instream use sectors. In addition, current and future water-related environmental 

regulations and requirements will continue to challenge power plant operations. As such, 

there will be increasing pressure to retire existing plants and deny permits for new power 

plants due to water availability and quality issues. 

In response to this challenge to national energy sustainability and security, DOE’s Office 

of Fossil Energy/NETL is carrying out an R&D program focused on the development and 

application of advanced technologies and concept to better manage how power plant use 

and impact freshwater. Research is currently underway to assess and develop nontraditional sources of cooling and process water, advanced cooling water technologies, 

innovative water reuse and recovery technologies, and advanced wastewater treatment 
17 

DOE/FE’s Power Plant Water Management R&D Program Summary, July 2005 

and detection technologies. It is anticipated that this research will help to alleviate 

potential conflicts between growing demands for electricity and increasing pressures on 

the Nation’s freshwater resources. For more information on NETL’s power plant water 

R&D activities, please visit: http://www.netl.doe.gov/coal/E&WR/water/index.html. 

DISCLAIMER 

Reference in this article to any specific commercial product or service is to facilitate 

understanding and does not imply endorsement by the U.S. Department of Energy. 

 

REFERENCES 

 

1

 U.S. Geological Survey. Estimated Use of Water in the United States in 2000; USGS Circular 1268; 

March 2004. 

2

 Energy Information Administration. Annual Energy Outlook 2005, EIA Report No. DOE/EIA0383(2005); February 2005. 

3

 U.S. Geological Survey. Estimated Use of Water in the United States in 2000; USGS Circular 1268; 

March 2004. 

4

 SAIC. Water-Energy RD&D Scoping Study; Final Report to the U.S. Department of Energy, NETL; 

September 2003. 

5

 U.S. Department of Energy, NETL; Estimated Freshwater Needed to Meet 2025 Electricity Demand 

Projections; Draft Internal Report; March 2004. 6

 United States General Accounting Office. Freshwater Supply, States’Views of How Federal Agencies 

Could Help Them Meet the Challenges of Expected Shortages; GAO Report No. GAO-03-514; July 2003. 7

 Electric Power Research Institute. A Survey of Water Use and Sustainability in the United States With a 

Focus on Power Generation; EPRI Report No. 1005474; November 2003. 8

 U.S. Department of the Interior. Water 2025 – Preventing Crises and Conflict in the West; May 2003. 9

 Land Letter. Western Power Plants Come Under Scrutiny as Demand and Drought Besiege Supplies;

March 4, 2004; http://www.eenews.net/Landletter.htm 10 Greenwire. State Orders N.Y.’s Indian Point to Take Steps to Protect Fish; November 13, 2003; 

http://www.eenews.net/Greenwire.htm 11 Clean Air Task Force. Wounded Waters – The Hidden Side of Power Plant Pollution; February 2004. 12 Billingsgazette.com. South Dakota Governor Seeks Summit on Missouri River, February 2005. 13 Reno-Gazette Journal. Nevada Residents Wary of Sempra Water Rights Purchases, February 22, 2005. 14 Milwaukee Journal Sentinel. Wisconsin Energy Just Can’t Stay Out of the News with Their Intake 

Structures, February 18, 2005. 15 Feeley, III, T.J. and Ramezan, M., Electric Utilities and Water: Emerging Issues and R&D Needs, Water 

Environment Federation, 9th Annual Industrial Wastes Technical and Regulatory Conference, San Antonio, 

TX , April 13-16, 2003 

16 Veil, J.A., Kupar, J.M., Puder, M.G., and Feeley, III, T.J., Beneficial Use of Mine Pool Water for Power 

Generation, Ground Water Protection Council Annual Forum, Niagara Falls, NY, September 13-17, 2003. 17 Strategies for Cooling Electric Generating Facilities Utilizing Mine Water: Technical and Economic 

Feasibility Project. Final Report to the U.S. Department of Energy under Cooperative Agreement No. DEPS26-03NT41719; West Virginia Water Research Institute – West Virginia Univeristy, September 30, 

2004. 

18 Use of Produced Water in Recirculating Cooling Systems at Power Generating Facilities. Semi-Annual 

Technical Progress Reports to the U.S. Department of Energy under Cooperative Agreement No. DEFC26-03NT41906; Electric Power Research Institute, August-December 2004. 19 Water Extraction from Coal-Fired Power Plant Flue Gas. Quarterly Progress Report to the U.S. 

Department of Energy under Cooperative Agreement No. DE-FC26-03NT41907; Energy & Environmental 

Research Center - University of North Dakota, September 2004. 
18 

DOE/FE’s Power Plant Water Management R&D Program Summary, July 2005 

 20 Use of Coal Drying to Reduce Water Consumed in Pulverized Coal Power Plants. Quarterly Report to 

the U.S. Department of Energy under Cooperative Agreement No. DE-FC26-03NT41729; Energy Research 

Center - Lehigh University, October 2004. 

21 Innovative Fresh Water Production Process for Fossil Fuel Plants. Annual Report to the U.S. 

Department of Energy under Cooperative Agreement No. DE-FG26-02NT41537; University of Florida, 

September 2004. 

22 U.S. Department of Energy, NETL: Environmentally Safe Control of Zebra Mussel Fouling Fact Sheet; 

September 2004. 

23 SPX Cooling Technologies and Services and Ceramic Composites to Test Carbon Foam Heat 

Exchangers for Power Plant Cooling. SPX Corporation News Release. October 13, 2004. 24 Novel Anionic Clay Adsorbents for Boiler-Blow Down Waters Reclaim and Reuse. Proposal to the U.S. 

Department of Energy under Cooperative Agreement No. DE-PS26-04NT41898-11; University of 

Southern California, December 2003.