- 1 - 

Emerging Issues and Needs 

in Power Plant Cooling Systems 

by 

Wayne C. Micheletti 

Wayne C. Micheletti, Inc. 

and 

John M. Burns, P.E. 

Burns Engineering Services, Inc. 

The majority of the electricity generated in the United States is produced by steamdriven turbine-generators. A very important step in this power generation process is the 

condensation of exhaust steam from the final, low-pressure turbine. When the steam 

condenses, the rapid decrease in vapor-to-liquid specific volumes creates a vacuum at 

the turbine outlet (monitored as turbine backpressure) that increases power generation 

efficiency. The conventional low-pressure steam turbine-generator can operate over a 

modest backpressure range (typically 1.0 to 5.0 or 5.5 in. Hga), but the design point for 

optimum efficiency is usually at the lower end of this range (2.0 to 3.5 in. Hga). 

Operating at backpressures greater than the design point reduces generation efficiency, 

and operating beyond a maximum backpressure limit is prohibited by warranty terms 

specified by the turbine manufacturer. Because lower turbine backpressures are 

achieved when the steam condensate temperatures are lower, designing and operating 

a cooling system that can consistently and continually remove the heat of condensation 

at those low temperatures is essential. Therefore, the cooling system should be 

considered an integral part of the power generation process that can have a major 

influence on the overall power plant performance and availability. 

The “waste” heat removed by the cooling system during the steam condensation step 

must ultimately be transferred to the surrounding environment. Having a high unit heat 

capacity, water has been the traditional transfer medium of choice because it has been 

readily available, relatively inexpensive and reusable up to a point. Wet cooling 

systems use water to absorb heat via indirect contact with steam in a condenser. The 

heated water is either discharged to a large surface water body such as a river or lake 

(once-through cooling) or passed through a cooling tower and recycled back to the 

condenser (recirculated cooling). In either case, heat absorbed in the condenser is 

released to the environment through a combination of evaporation and sensible heating 

of the surroundings. Prior to 1990, virtually all steam-electric power plants used wet 

cooling systems. 
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Many of the plants built during the last decade are based on the combined-cycle 

process for power generation. In the most common 2-on-1 arrangement, electricity is 

produced by two combustion turbine-generators with the hot exhaust gas from these 

turbines used to produce steam in a heat recovery steam generator (HRSG) for a single 

steam-driven turbine generator. Since the combustion turbines produce roughly twothirds of the overall electrical power and have no steam condensation step, a combinedcycle plant requires only about one-third the amount of cooling needed by a 

conventional steam-electric plant of equivalent capacity. As such, new combined-cycle 

power plants are seen as offering a greater degree of flexibility in the type of cooling 

system that can be used. Several recently built combined-cycle plants use an aircooled condenser (dry cooling) instead of the traditional condenser/wet cooling system. 

Still other plants have considered or have used combination wet/dry or hybrid cooling 

systems. 

Over this same period, a number of questions have been raised about the future of wet 

cooling systems for both existing and new power plants. In some instances, the 

questions focus on certain site-specific concerns. In other cases, the questions are 

more universal in nature and may have broader implications for the power industry at 

large. Nevertheless, for the first time in some time, power plant cooling system 

technology is being reevaluated in terms of a variety of rapidly evolving issues. The 

purpose of this paper is to examine those emerging issues (both perceived and real) 

and the corresponding needs for the electric power industry. 

The Perceived Issues

Wet Cooling. Since the advent of steam-electric generation, wet cooling systems have 

been a de facto component of the power production process. Initially, once-through 

cooling was the favored approach. The large size of the source water guarantees cold 

cooling water temperatures with almost no daily variation and usually very modest 

seasonal variation. However, in the early 1970’s, new steam-electric generation began 

using recirculated cooling. The primary reason for this trend (shown graphically in 

Figure 1) can be found in the Federal Water Pollution Control Act (FWPCA) enacted by 

Congress in 1972. Recognizing that industrial cooling, particularly for steam-electric 

power generation, used large volumes of water, Sections 316(a) and 316(b) were 

designed to address potential impacts on the aquatic environment. Section 316(a) 

regulates cooling system thermal discharges and Section 316(b) requires the use of 

best technology available for minimizing environmental impact in the location, design, 

construction and capacity of a cooling water intake. With lower makeup (intake) flows 

and lower discharge (cooling tower blowdown) flows, recirculated cooling systems were 

increasingly selected in direct response to Sections 316(a) and 316(b). 

Hence, environmental impacts became the first concern with wet cooling systems used 

in power plants. Subsequently, over the next three decades, the related themes of 

environment and health & safety have been at the center of an increasing number of 

regulations and factors affecting wet cooling systems, including: 
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Figure 1 

Growth of Once-through and Recirculated Cooling1 

• Possible pollutant discharges. Amendments to the FWPCA in 1977 (known as 

the Clean Water Act or CWA) and later promulgated through the National Pollutant 

Discharge Elimination (NPDES) permit process established specific effluent 

limitations for certain substances (including chlorine, chromium and zinc). 

Chromium, an additive used to protect cooling system equipment from corrosion, was 

ultimately banned entirely. Recent concerns about the presence of certain disinfection byproducts in potable water supplies (notably trihalomethanes or THMs) may 

eventually be reflected in greater limitations on the use of chlorine in cooling systems. 

• Atmospheric plume formation. Depending upon the temperature and humidity of 

the surrounding air, the saturated exhaust from a cooling tower can form a visible 

plume which may be unaesthetic or might impair visibility or cause icing on nearby 

roadways. 

• Drift consequences. Initial concerns with potential ground-level salt deposition 

may have been replaced in some locations with possible contributions to atmospheric 

particulate levels, measured and monitored in terms of PM10 and PM2.5. 

0

50000

100000

150000

200000

250000

1950 1960 1970 1980 1990

Year Commissioned

Cumulative Gross Generating Capacity (GW)

Once-through 

Cooling 

Recirculated 

Cooling 
- 4 - 

• Legionnaires’ disease. Legionella, the freshwater bacteria responsible for 

Legionnaires’ disease, is commonly found in U.S. surface waters, tends to thrive at 

temperatures typical in wet cooling systems (68-113 °F), and can be transported 

through the air via aerosols formed in cooling towers. Consequently, cooling towers 

are viewed as important sources for the potential exposure of workers or persons in 

the immediate surroundings. Similarly, the use of reclaimed water (treated municipal 

sewage effluent) has raised some concerns about possible dissemination and 

exposure to waterborne pathogens. 

However, with the construction of new power plants in recent years, perhaps the most 

prevalent concern with wet cooling systems has been water availability. Growing 

competition from municipal and agricultural users has decreased the amounts and 

increased the prices of good quality water resources available to industrial users. This 

competition is most apparent in the southwestern U.S. where the need for new electric 

power generation is significant, but regional surface water sources are minimal and 

groundwater sources are highly prized and may have designated use restrictions. But 

even in areas usually considered “water rich”, such as the northeastern U.S., the 

combination of environmental, safety & health, and resource availability concerns has 

resulted in an increasing interest in dry and hybrid cooling systems as alternatives to 

wet cooling systems. 

Dry and Hybrid Cooling. Three types of dry and hybrid cooling systems have received 

the most attention: 1) direct dry cooling (also referred to as an air-cooled condenser or 

ACC), 2) parallel wet/dry cooling (in which an ACC and a conventional wet recirculated 

cooling system are operated in combination), and 3) plume abatement cooling (in which 

the saturated exhaust from a conventional wet cooling tower is passed through an 

indirect dry cooling system located above it to prevent the atmospheric release of a 

visible plume). Plume abatement cooling serves a very special need and, assuming 

that evaporative cooling is not unacceptable for other reasons, this type of cooling will 

almost certainly be the preferred choice when visible plume abatement is a concern. 

For that reason, this type of cooling is not discussed further in this paper. 

Similarly, indirect dry cooling is not discussed in this paper. For new power plants in the 

U.S., indirect dry cooling has been dismissed by utilities and architect-engineers as 

impractical because of the extremely poor thermal performance relative to direct dry 

cooling. While indirect dry cooling would be more technically suitable than direct dry 

cooling as a retrofit to an existing wet cooling system, the practicality of such retrofits is 

questionable for a variety of reasons. The very poor thermal performance of indirect dry 

cooling systems will likely reduce the generating efficiency too much to justify such a 

retrofit, especially when combined with other site-specific factors (unit age and 

anticipated life, space constraints, etc.). An ongoing U.S. Department of Energy study 

is evaluating some of these retrofit implications and should provide valuable detailed 

information shortly. 
- 5 - 

On the other hand, direct dry and parallel wet/dry cooling systems address several of 

the concerns associated with wet cooling systems. Still, there are other factors that 

affect their widespread use in power plants. These include: 

• Size. By definition, dry cooling involves the transfer of heat to the atmosphere 

without the evaporative loss of water (i.e., by sensible heat transfer only). Because 

sensible heat transfer is less efficient than evaporative heat transfer, dry cooling 

systems must be larger than wet cooling systems. For example, to achieve a 

comparable heat rejection, one study estimates that a direct dry cooling system (ACC) 

will have a footprint about 2.2 times larger than a wet cooling tower and a height about 

1.9 times greater.2

• Operational control. Direct dry cooling and parallel wet/dry cooling systems 

require the transport of large volumes of steam from the turbine exhaust through ducts 

into headers for distribution into rows of small-diameter finned tubes grouped in cells. 

Maintaining the desired steam condensation temperature (turbine backpressure) 

requires balancing the steam flow into each cell (which can vary with unit load), 

continuous removal of any noncondensible gases, and elimination of any leaks to 

assure vacuum conditions throughout the entire network of ducts, headers and tubes. 

In a parallel wet/dry cooling system, operational control is further complicated by the 

need to balance steam flow between two separate cooling systems (wet and dry). 

• Plume recirculation. In a dry cooling system, forced-draft fans are used to control 

air flow across the finned tubes and enhance sensible heat transfer. However, forceddraft fans expand the inlet air stream to cover the large finned surface area, which 

lowers the warm air exit velocity. As a result, a large portion of the warm air plume 

exiting the top may be drawn back into the intake at the bottom instead of fresh 

ambient air. The potential for plume recirculation can be exacerbated by variations in 

wind patterns and the proximity of other structures (such as the turbine building) that 

could interfere with air flow patterns. In some cases, this problem can be mitigated by 

appropriately placed windwalls. 

• Maintenance. Both direct and indirect dry cooling systems, as well as hybrid 

cooling systems, are larger and mechanically more complex than corresponding wet 

cooling systems. In addition to the larger heat transfer surface area, dry and hybrid 

cooling systems will have more fans, meaning more electrical motors, gearboxes and 

drive shafts. As such, labor requirements for a large ACC can be substantial. At one 

site with a 60-cell ACC (three 20-cell bays for three separate steam turbines), the 

maintenance staff was increased by two people for such activities as cleaning fan 

blades and heat exchanger tube fins, monitoring lube-oil systems, and leak-checking 

the vacuum system.3

• Energy penalties. Because sensible heat transfer is directly related to the ambient 

dry-bulb temperature, a dry cooling system must have the flexibility to respond to 

typical daily temperatures variations of 20-25 °F. A dry system that maintains an 

optimum turbine backpressure at ambient dry-bulb temperatures of 90-95 °F, may not 
- 6 - 

be able to do so as the temperature increases, meaning a lower generating efficiency. 

From a design perspective, more surface area (i.e., a larger dry cooling system) can 

compensate for the decline in heat transfer at high ambient temperatures; but the 

greater size and associated operational control are also concerns, as previously 

discussed. 

To a great extent, most of these concerns are developmental in nature and reflect the 

U.S. utility industry’s lack of experience with the design and operation of dry and hybrid 

wet/dry cooling systems large enough for most power plants. Although some sources 

cite as many as 600 power plants using dry cooling systems worldwide, in the U.S. most 

dry cooling systems are at units that have generating capacities less than 100 MW. 

During the ten-year period 1990-1999, dry cooling was used at ten new U.S. power 

plants with a capacity greater than 50 MW; only one of these plants had a generating 

capacity greater than 200 MW. 

The Real Issues

None of the concerns described for wet, dry or parallel wet/dry cooling systems 

addresses the real issues. Instead, these concerns would be more correctly considered 

“constraints” rather than “issues”. They define the limits in which a cooling system must 

cost effectively operate. The real issues are economically based and are centered on 

reliable, cost-effective performance and unit availability. In the evolving deregulated 

utility industry, electric generating units that are unable to meet consumers’ demands for 

power at the lowest price will be slowly, but inevitably, excluded from the market. So 

the real issues for all power plant cooling systems are low-cost performance and 

availability within a set of defined constraints. 

Performance. For any cooling system, performance is determined by the system’s 

continuous and consistent ability to reject the heat load necessary to achieve the steam 

condensate temperature corresponding to the optimum turbine backpressure. In doing 

so, the cooling system must be designed not only to transfer the maximum heat load, 

but also to operate over a broad range of anticipated environmental conditions. Failure 

to meet either of these design considerations usually means higher steam condensate 

temperatures (higher turbine backpressures) and lower power generation efficiency. 

For wet cooling systems with a given condenser design (steam flow and cooling water 

flow), the temperature of the cold water entering the condenser will determine the steam 

condensate temperature. Therefore, the cold water temperature is a key design and 

operating parameter. For a once-through cooling system, plant operators have no 

control over inlet cold water temperatures. But with adequate historic source water 

data, once-through systems usually can be designed to provide cold water 

temperatures suitable for maintaining turbine operation at the optimum design point 

throughout the year. Assuming some typical values for condenser temperature rise (the 

increase in cooling water temperature entering and exiting the condenser) and a 

condenser terminal temperature difference or TTD (the temperature difference between 

the condensing steam and the hot water leaving the condenser), it is possible to 
- 7 - 

calculate the condensing steam temperature and the corresponding turbine 

backpressure as shown in Table 1. For this example, Atlanta, Georgia has been 

chosen as the power plant site. 

TABLE 1 

Steam Condensate Temperatures and Turbine Backpressures 

for Typical Cooling System Design Values

 Once-through

Wet Cooling 

Recirculated 

Wet Cooling 

Direct Dry 

Cooling (ACC) 

Surface water temperatureA 79 °F 

Condenser temperature rise 20 °F 

Ambient wet-bulb temperatureA 78 °F 

Ambient dry-bulb temperatureA 95 °F 

Correction for plume recirculation 2 °F 3 °F 

Approach to wet-bulb temperature 8 °F 

Cooling tower range 24 °F 

Condenser TTD 6 °F 6 °F 

Condenser ITDB 20 °F 

 

Steam condensate temperature 105 °F 118 ° F 118 °F 

Corresponding turbine backpressure 2.3 in. Hga 3.3 in. Hga 3.3 in. Hga 

A - Maxiumum surface water temperature and 1% ambient wet-bulb and dry-bulb data are for 

 Atlanta, GA. 

B - A 20 °F ITD was selected in order to achieve a steam condensate temperature comparable 

 to the recirculated system and ensure adequate performance at the 1% ambient dry-bulb 

 temperature; a more typical, cost-effective ITD would be in the 25-55 °F range. 

For a recirculated system, the cooling tower is designed to produce a specified cold 

water temperature based on the anticipated climatic conditions. Because evaporation is 

the dominant means of heat transfer in a cooling tower, the ambient air wet-bulb 

temperature is the controlling factor. The lower the inlet air wet-bulb temperature 

(indicating colder air and/or lower humidity), the colder a tower can make the cooling 

water going to the condenser. As a matter of physics, the cold water temperature can 

never be lower than the inlet air wet-bulb temperature. The difference in cold water and 

inlet air wet-bulb temperatures is known as the “cooling approach”. Most cooling towers 

are designed for an approach between 5 and 10 °F; for power plant cooling towers, the 

approach is generally 8 °F. 

To assure adequate cooling tower performance virtually all of the time, a “worst case” 

ambient wet-bulb temperature is selected for design purposes. Based on historic 

climatic data, the design value most frequently used is an ambient wet-bulb temperature 

that would not be exceeded for more than 29 hours during the months of June through 

September (approximately 1 percent of the total time for that period). Again, assuming 

some typical values for a power plant cooling tower range (the temperature difference 

between the hot water entering and the cold water leaving an evaporative cooling tower) 

and plume recirculation (the estimated increase in inlet air wet-bulb temperature due to 
- 8 - 

tower plume recirculation), it is possible to calculate the condensing steam temperature 

and the corresponding turbine backpressure as shown in Table 1. 

For dry cooling systems, sensible heat transfer is the only form of heat rejection, so 

performance depends upon the ambient air dry-bulb temperature instead of the wetbulb temperature. Because ambient dry-bulb temperatures are usually higher and tend 

to experience more dramatic daily and seasonal fluctuations than ambient wet-bulb 

temperatures, designing and operating dry cooling systems to obtain the consistent and 

continuous performance historically provided by wet cooling systems is possibly the 

greatest obstacle to the increased use of dry cooling in power plants. 

One way to overcome this obstacle is to increase the size of the air-cooled condenser 

(i.e., when the rate of sensible heat transfer declines due to an increase in the ambient 

dry-bulb temperature, a larger ACC will still have adequate heat transfer area to reject 

the design heat load). This can be accomplished in the design phase by specifying a 

smaller initial temperature difference or ITD (the temperature difference between the 

condensing steam and the ACC inlet air dry-bulb temperature). Assuming a fairly low 

design ITD (20 °F) and a typical plume recirculation (the estimated increase in inlet air 

dry-bulb temperature due to ACC plume recirculation), it is possible to calculate the 

condensing steam temperature and the corresponding turbine backpressure as shown 

in Table 1. 

The results shown in Table 1 indicate that all three types of cooling systems can be 

designed to provide acceptable performance (operating turbine backpressures in the 

range of 2.0-3.5 in. Hga) for environmental conditions that might occur approximately 

99.44% of the year. Therefore, performance need not be a limiting factor in the 

selection and/or use of any of these systems for power plant cooling. 

Availability and reliability. In order to be profitable, a commercial enterprise must 

operate; in the electric generation business that means producing power. If a cooling 

system cannot operate reliably on-demand, then it can interfere with the production of 

power for sale. Hence, a cooling system must guarantee suitable performance on a 

continuous and consistent basis. 

When operated and maintained properly, the availability and reliability of wet cooling 

systems have been excellent. Problems that might impede power production are rare 

and usually occur because of extremely unusual circumstances. For example, during 

infrequent periods of very high surface water temperatures, some once-through 

systems have needed to curtail flow or use helper towers to meet the maximum 

temperature limits required by site-specific discharge permits. Some recirculated 

systems have reported partial or complete cooling tower collapses due to ice formation 

during freezing temperatures or deterioration of the wooden support structure from 

fungal-based decay. As previously mentioned, the utility industry’s experience with dry 

cooling systems is limited. But potential problems that have been reported in other 

applications include fouling of the finned tubes from airborne contaminants, and freezing 

and rupturing of the finned tubes during periods of extremely low dry-bulb temperatures. 
- 9 - 

Yet, these problems are relatively rare and can usually be avoided with proper operating 

and maintenance practices. Therefore, availability and reliability should not be a limiting 

factor in the selection and/or use of any of these systems for power plant cooling. 

Costs. If performance, availability and reliability appear to be equal, then the single 

issue that will most likely govern the selection and use of a power plant cooling system 

is cost. Unfortunately, the economics of power plant cooling systems are complex, 

which means cost estimates are frequently mistaken, misunderstood or misrepresented. 

This complexity results from the complicated relationships of three key costs: installed 

equipment capital cost, annual operating and maintenance or O&M cost, and energy 

penalty cost. For most manufacturing processes, the first two costs can be fairly well 

defined and, to a certain extent, contractually guaranteed by the vendor/supplier. But 

the energy penalty cost is somewhat unique to power plant cooling systems because it 

reflects a direct performance link between the cooling system and the low-pressure 

turbine-generator. Consequently, the potential for and the magnitude of an energy 

penalty cost can dictate cooling system design and operating changes that directly 

affect the capital and O&M costs. So in a competitive market, generating power in the 

most cost-effective manner depends upon a company’s ability to balance all three key 

costs and optimize the overall life-cycle cost of the cooling system. 

For wet cooling systems, decades of experience have helped establish the optimum 

design and O&M practices. As a result, the relationships of the three key costs are well 

understood and documented. Ongoing innovations (such as the introduction of film fill 

about 15 years ago and the increasing replacement of wood by fiberglass) may cause 

some changes in capital and O&M costs. But these changes are not likely to influence 

the current design practice of specifying performance based on the maximum source 

water temperature (for once-through cooling) or the 1% ambient wet-bulb temperature 

(for recirculated cooling). The daily and seasonal variations in source water and wetbulb temperatures are too small to justify a lower performance that could produce a 

higher energy penalty cost. 

For dry cooling systems, the U.S. power plant experiential database is extremely small. 

Hence, the relationships between the three key costs are not well understood or 

documented. An important difference from wet cooling systems is the greater sensitivity 

of dry cooling system performance to ambient conditions. The larger daily and seasonal 

variations in ambient dry-bulb temperatures indicate that energy penalties for dry 

cooling systems are more likely to occur, particularly during the hottest times of the 

year. Because these times would typically coincide with periods of peak electricity 

consumption, a decline in power production could represent a serious difficulty in 

meeting customer demand and a potentially significant revenue loss. 

Determining reasonable energy penalty cost estimates is problematic due to the hourto-hour and day-to-day variations that occur in ambient dry-bulb temperatures and the 

market price of electrical power. Using daily averages for both of these parameters is 

an approach commonly suggested to simplify the energy penalty cost calculation. But 
- 10 - 

daily averages for dry-bulb temperatures cannot account for extreme energy penalties 

that might occur briefly during the hottest times of the day. Continuing with the example 

presented earlier in Table 1, Figure 2 shows the change in turbine backpressure as a 

function of ambient dry-bulb temperature for four different ITD design values. For an 

ITD of 40 °F and the average daily dry-bulb temperature for Atlanta during the summer, 

the turbine backpressure is within the typical operating range and well under the 

maximum operating limit. Consequently, the estimated energy penalty cost would be 

very low. But at the 1% dry-bulb design value, an ACC with an ITD of 40 °F will be 

unable to maintain the turbine backpressure below the maximum operating limit. Even 

though the 1% dry-bulb design value will definitely occur during the summer, the 

associated energy penalty cost, which could be substantial, would not be reflected in an 

estimate based on daily averages for summer dry-bulb temperatures. 

Figure 2 

Ambient Dry-Bulb Temperature vs Turbine Backpressure 

A misconception about the new generation of combined-cycle plants may also be 

contributing to incorrect energy penalty cost estimates for dry cooling systems. The 

confusion stems from an assumption that the cooling system can affect only the steam 

turbine-generator, which is not necessarily true. If a cooling system cannot provide 

adequate heat rejection, then steam flow from the HRSG through the turbine to the 

condenser may need to be reduced. Since the exhaust gases from the combustion 

turbines must pass through the HRSG, a limit on the boiler’s steam production could 

0

1

2

3

4

5

6

7

8

9

40 50 60 70 80 90 100 110

Ambient Dry-Bulb Temperature (F)

Turbine Backpressure (in. Hga)

ITD = 20 F

ITD = 30 F

ITD = 40 F

ITD = 50 F

Maximum Limit

Summer

Average

1% Design

Value
- 11 - 

also make it necessary to reduce the flow of exhaust gases by “trimming” operation of 

the combustion turbines. Through this domino affect, reduced cooling system 

performance could have energy penalty cost implications for both the steam and 

combustion turbines in a combined-cycle power plant. 

Several methods have been proposed to mitigate possible energy penalty costs when 

dry cooling is used at power plants. In addition to different cost implications, each 

method has certain characteristics that may be viewed as advantages or disadvantages 

depending upon site-specific constraints. Furthermore, although presented separately 

here, a combination of two or more of these methods could prove to be the most costeffective dry-cooling system design. 

• Larger ACC (smaller ITD). As shown in Table 1, an ACC with a large heat transfer 

surface area (low ITD) will provide adequate performance at the 1% ambient dry-bulb 

temperature (which is comparable to the performance standard typically required for 

wet cooling towers based on the 1% ambient wet-bulb temperature) to eliminate the 

energy penalty cost. Doing so, however, will appreciably increase both the installed 

equipment capital cost and the annual O&M cost. A larger ACC may also encounter 

site-specific space constraints and difficulties with operational control. 

• Turbine redesign. The maximum backpressure range of 5.0-5.5 in. Hga for 

conventional steam turbines could be extended to a higher value enabling more 

flexible operation over a wider range of backpressures. This could be done by 

modifications to existing turbine designs or by development of a new turbine. One 

modification that has been widely discussed includes removing the last row of blades 

or final stage and introducing steam downstream of the initial stage during periods of 

high ambient dry-bulb temperatures. Because these changes would reduce the 

efficiency of the turbine across the entire range of backpressures, enlargements in the 

steam flow area of both the high-pressure and intermediate-pressure turbines have 

been suggested to help compensate. 

A different modification would not remove the last row of blades, but would adjust the 

lengths and increase the structural strength of blades in the last several rows; no 

changes would be made to the high or intermediate-pressure turbines. As before, this 

redesign would reduce the efficiency of the turbine across the entire range of 

backpressures. 

A more radical approach would be the design of a completely new turbine. More than 

thirty years ago, one study suggested that by shortening the last-stage blades, 

strengthening all of the stages to pass more steam flow and extensively altering the 

exhaust structure, a turbine could be designed to operate at backpressures ranging 

from 2.0 to 14.0 in. Hga.4

 While such a design might be 10-12% less efficient than 

conventional low-pressure turbine (based on a comparison of heat rates), the 

efficiency would be relatively constant across the entire range of backpressures, 

making it desirable to operate at the higher end. Since that time, no serious efforts 

have been made to design such a high-backpressure turbine primarily because the 
- 12 - 

investment from manufacturers would be significant and the demand from utilities was 

not. 

• Water spray enhancement. The temporal nature of dry cooling energy penalties 

means that ACC heat transfer might be cost-effectively enhanced for limited, 

intermittent periods by evaporating water sprays directed on the hot surfaces of the 

finned tubes or into the hot ambient inlet air. Besides the practical difficulty of 

achieving a uniform spray to all sections of a large ACC, both techniques would 

consume some amount of water, which may be contrary to one or more of the 

constraints that originally made dry cooling an attractive option. Further, both 

techniques would need to use relatively pure water to prevent the formation of surface 

deposits on the ACC finned tubes that would interfere with heat transfer and further 

decrease system performance. Water sprayed into the inlet air could also leave 

surface deposits on the induced draft fans. Any water that falls to the ground would 

need to be collected and treated either for recycle to the spray enhancement 

equipment, reuse in other power plant processes or discharge/disposal. The 

additional equipment and pure water requirements will mean increased capital and 

O&M costs. But, a successful water spray enhancement technique could likely have 

both new and retrofit applications. 

• Parallel wet/dry cooling. The most highly promoted aspect of the parallel wet/dry 

cooling system is the design capability for distributing the overall heat rejection load 

between an ACC (at low ambient dry-bulb temperatures) and a conventional wet 

cooling tower (at high ambient dry-bulb temperatures). By using wet cooling to 

supplement dry cooling during periods of high ambient dry-bulb temperatures, this 

system attempts to limit the energy penalty costs. However, the operational control of 

this hybrid system is even more complex than either a direct or indirect dry cooling 

system. For example, a 37-MW unit reportedly uses automatic setpoint functions and 

a neural network to achieve a desired turbine backpressure by simultaneously 

monitoring and controlling the variable speed fans on the ACC and the cooling tower, 

as well as the recirculated cooling water flow.5

 In addition, the difficulty of 

constructing a large, low-pressure-drop, bifurcating ductwork from the turbine exhaust 

to both an ACC and a water-cooled condenser may limit this type of system to small 

power applications. For instance, a 400 MW turbine in a fossil plant would typically 

use a 20 ft. x 20 ft. exhaust. The capital costs for a parallel wet/dry system are 

reported to be about the same as for a direct dry system (ACC); the O&M costs are 

not well documented, but are suspected to be comparable or higher. 

Needs

Following decades of experience and refinement, wet systems (either once-through or 

recirculated) have become the standard for cost-effective, reliable cooling of steam 

turbine generators in electric power plants. Even as the number of constraints affecting 

the design and operation of these systems has grown over this time, wet cooling has 

continued to be the dominant choice in power plants. 
- 13 - 

Recently, federal regulatory activity under Section 316(b) of the Clean Water Act and 

widespread construction in the semi-arid southwestern U.S. have increased interest in 

dry and parallel wet/dry systems as alternatives. But the power industry’s lack of 

experience with dry and parallel wet/dry cooling may raise doubts about the costeffective, reliable performance of these systems. Until these doubts are addressed, the 

roles for dry and parallel wet/dry cooling in power plants will be ill defined, and the 

acceptance and use of these technologies will most likely be slow and erratic. 

Therefore, the following tasks need to be done: 

1. Develop methods for improving the performance of dry cooling at high ambient 

dry-bulb temperatures. 

2. Establish a procedure for estimating a representative energy penalty. When 

variations in important environmental factors are minor, a reasonable estimate 

can be determined using daily averages. This approach should be adequate for 

wet cooling systems because variations in hourly surface water temperatures 

(once-through cooling) and hourly ambient wet-bulb temperatures (recirculated 

cooling) are minor. However, due to the more significant variations in hourly 

ambient dry-bulb temperatures, for dry cooling a simple approach based on daily 

averages would substantially underestimate the energy penalty. Instead, an 

approach that uses hourly ambient dry-bulb temperature data with a 

corresponding series of system performance calculations should be used to 

estimate the energy penalty on an hour-by-hour basis. These values can then be 

summed for presentation as daily, monthly or annual energy penalties. Without 

this procedure, it will be difficult to measure the performance improvements 

achieved in Item 1 above or to estimate the true system cost discussed in Item 3 

below. 

3. Establish a protocol for optimizing a cooling system design based on site-specific 

constraints and data, and the three key costs (installed equipment capital cost, 

annual O&M cost and energy penalty cost). Such a protocol is critical if the utility 

industry is to make wise economic decisions in an unregulated, competitive 

market and to avoid unwarranted mistakes in selecting power plant cooling 

systems. 

References

1. COOLADD: A Database of Power Plant Cooling Water Systems and Generic 

Chemical Additives Usage, Electric Power Research Institute, Palo Alto, CA, 

December 1998. 

2. Burns, J.M. and W.C. Micheletti, “Comparison of Wet and Dry Cooling Systems for 

Combined Cycle Power Plants”, Utility Water Act Group, Washington, DC, 

November 4, 2000. 
- 14 - 

3. Makansi, Jason, “Matrix of Performance Challenges Met by Operating Plants”, 

Power, October 1993, pp. 17-26. 

4. Rossie, J.P. and E.A. Cecil, Research on Dry-Type Cooling Towers for Thermal

Electric Generation: Part I, Water Quality Office of the United States Environmental 

Protection Agency, Project # 16130 EES, Contract # 14-12-823, FWQA R&D Report 

#16130EES11/70, November 1970. 

5. Rusley, David, “Streeter Station Unit #7 Wet/Dry Cooling System”, presented at the 

AWMA Dry Cooling Symposium, San Diego, CA, May 31 - June 1, 2002.