Tetra Tech, Inc.

10306 Eaton Place, Suite 340

Fairfax, VA 22030

phone 703-385-6000

fax 703-385-6007

TO: Paul Shriner, EPA

FROM: John Sunda (SAIC) and Kelly Meadows

DATE: March 11, 201

SUBJECT: Summary of Literature Review and New

Cooling Including Data for Dry Cooling Installations in the U.S.

Alternatives to once-through cooling at power plants and manufacturers can include:

 Closed cycle wet (evaporative) cooling

 Closed cycle hybrid wet/dry coo

dry cooling1is employed (e.g., hybrid plume abatement).

 Closed cycle hybrid wet/dry

cooled condensers are used.

 Indirect dry cooling alone.

 Direct air cooled condensers

Except where used in conjunction with wet cooling

to be in use at any power plants in the US. Indirect dry cooling is however, used in 

numerous applications where it is combined with wet evapor

wet/dry). Such systems are used for plume abatement and

consumption. This memo focuses on 

system. 

Dry cooling is described and evaluated as a cooling system alternative in Chapter 4: Dry

Cooling in the 316(b) Phase I Technical Development Document. The chapter concludes 

that dry cooling is not technically or economically feasible for all facilities subject

Phase I and does not represent BTA

 

1

Indirect dry cooling is where steam is first condensed using water or another fluid which is then piped to 

and passed through an air/fluid heat exchanger. Most hybrid wet/dry cooling systems use indirect dry 

cooling.

MEMORANDUM

10306 Eaton Place, Suite 340

Paul Shriner, EPA

John Sunda (SAIC) and Kelly Meadows

, 2011

Summary of Literature Review and New Developments Concerning Dry

Cooling Including Data for Dry Cooling Installations in the U.S.

through cooling at power plants and manufacturers can include:

Closed cycle wet (evaporative) cooling alone.

Closed cycle hybrid wet/dry cooling where both evaporative cooling and indirect 

is employed (e.g., hybrid plume abatement).

wet/dry cooling where both evaporative cooling and direct air 

cooled condensers are used.

alone.

ooled condensers alone.

Except where used in conjunction with wet cooling, indirect dry cooling does 

to be in use at any power plants in the US. Indirect dry cooling is however, used in 

numerous applications where it is combined with wet evaporative cooling (aka 

. Such systems are used for plume abatement and/or for reduction of water 

This memo focuses on the use of dry cooling as a stand-alone

ooling is described and evaluated as a cooling system alternative in Chapter 4: Dry

Cooling in the 316(b) Phase I Technical Development Document. The chapter concludes 

that dry cooling is not technically or economically feasible for all facilities subject

and does not represent BTA. Compared to wet cooling, dry cooling would 

 

Indirect dry cooling is where steam is first condensed using water or another fluid which is then piped to 

and passed through an air/fluid heat exchanger. Most hybrid wet/dry cooling systems use indirect dry 

Developments Concerning Dry

Cooling Including Data for Dry Cooling Installations in the U.S.

through cooling at power plants and manufacturers can include:

ling where both evaporative cooling and indirect 

where both evaporative cooling and direct air 

indirect dry cooling does not appear 

to be in use at any power plants in the US. Indirect dry cooling is however, used in 

aka hybrid 

for reduction of water 

cooling 

ooling is described and evaluated as a cooling system alternative in Chapter 4: Dry

Cooling in the 316(b) Phase I Technical Development Document. The chapter concludes 

that dry cooling is not technically or economically feasible for all facilities subject to 

dry cooling would 

Indirect dry cooling is where steam is first condensed using water or another fluid which is then piped to 

and passed through an air/fluid heat exchanger. Most hybrid wet/dry cooling systems use indirect dry 
increase air emissions due to the energy penalty, cost more than three times more, and 

would not significantly reduce impingement mortality or entrainment.

A review of government guidance for European power plants indicates that they have 

reached a similar conclusion: that dry cooling technologies should only be used where 

water is in extreme short supply (EU 2001. Environmental Agency UK 2010.) Another 

report noted that “[c]urrently, dry cooling is used, or viewed as an option of last resort, 

where water is very costly or limited in availability.” (Wolfe 2008). 

The GAO report “Energy-Water Nexus” (GAO 2009) does not focus on consumptive use 

as an issue for energy production but does include a table of relative withdrawal/ 

consumption rates for different cooling system types. It also states that certain important 

data (including cooling technology and use/consumption by technology) is no longer 

being collected by USGS or EIA. The report touches on regulatory compliance issues, as 

well as space, noise and suitability of technologies; it speaks of facilities balancing the 

positive and negative tradeoffs of using different power generation and cooling. It also 

discusses energy penalties. The recommendations in the report focus mostly on data 

collection.

Spray Cooling of Inlet Air for Reduced Energy Penalty

Dry cooling system performance can be enhanced by pre-cooling inlet air using a fine 

mist spray of water. Cooler air passing though the heat exchanger will result in lower 

steam turbine backpressures with a corresponding increase in turbine efficiency. System 

does result in some water consumption but would be used intermittently during periods of 

high air temperatures with a typical water consumption rate of about 25% of that for wet 

cooling (Maulbetsch et al 2008).

Comparison of Wet and Dry Cooling Cost

For new power facilities, dry cooling costs can average about 5 times the costs of wet 

cooling. Multipliers can vary widely based on site-specific conditions and can be as high 

as 10 times or more the cost of wet cooling. A good analysis of wet versus dry cooling 

costs can be found in the 2002 EPRI report “Comparison of Alternate Cooling 

Technologies for California Power Plants” prepared for the California Energy

Commission (EPRI 2002). The following text is from the report’s abstract:

“This study defines, explains, and documents the cost, performance, and 

environmental impacts of both wet and dry cooling systems. A survey of the 

cooling system literature is provided in an annotated bibliography and 

summarized in the body of the report. Conceptual designs are developed for wet 

and dry cooling systems as applied to a new, gas-fired, combined-cycle 500-

MW plant (170 MW produced by the steam turbine) at four sites chosen to be 

representative of conditions in California. The initial capital costs range from 

$2.7 to $4.1 million for wet systems using mechanical-draft wet cooling towers 
with surface steam condensers and from $18 to $47 million for dry systems 

using air-cooled condensers.

Cooling system power requirements for dry systems are four to six times those 

for wet systems. Dry systems, which are limited by the ambient dry bulb 

temperature, cannot achieve as low a turbine back pressure as wet systems, 

which are limited by the ambient wet bulb. Therefore, heat rate penalties and 

capacity limitations are incurred at some sites depending on local meteorology.” 

(EPRI 2002).

Dry Cooling and California

California doesn’t have an explicit requirement that requires dry cooling, but has several 

regulatory frameworks that make it the de facto policy. The State Water Board issued a 

policy in the 1970s directing any new power plant to investigate alternative cooling water 

sources and technologies before they could be permitted to use freshwater in once 

through cooling. The policy also has the effect of pushing industrial cooling down the 

priority scale compared to freshwater use, behind municipal, agriculture, and recreation, 

raising the question of whether there is enough water to satisfy all of these demands. For 

marine locations, the Coastal Act is applicable, which emphasizes maintaining and 

restoring coastal resources. Although it does make an exemption for “coastal dependent” 

industry, the Coastal Commission and the State Lands Commission have made it clear 

that they will not authorize any new once-through cooling facilities. 

The Gateway project in Antioch and the Willow Pass facility nearby 

(http://www.energy.ca.gov/sitingcases/willowpass/) are located in the Sacramento/San 

Joaquin Delta, where water use is a major issue. Both are new facilities. There are several 

threatened & endangered species present in the area, likely contributing to the conclusion 

that dry cooling is the most appropriate technology. 

It is widely recognized that dry cooling is the primary option for new facilities except in 

those locations where reclaimed water is available. Few facilities even attempt to apply

for new once-through or wet cooling permits anymore. The bottom line is that for new 

facilities, dry cooling is technologically and economically competitive with wet cooling 

when factoring in environmental compliance issues. 

Dry Cooling and New York

In the past 10 years, six power generation systems were installed with dry cooling in the 

state of New York. Outside of New York City, these include:

 The new 350 MW combined cycle Caithness Long Island Energy Center 

 The new 1,080 MW combined cycle Athens Power station. 

In the New York City area, air-cooled condensers are favored by siting authorities. New 

York City area facilities include:
 A 500 MW combined cycle plant constructed by Astoria Energy LLC adjacent to 

the existing Charles Poletti Plant came online in 2006. The Charles Poletti Plant 

was closed in January 2010.

 A second 500 MW combined cycle plant will be constructed adjacent to the 

existing Astoria Energy LLC facility is planned to come online in 2011.

 The Astoria Energy Center, a 500 MW combined cycle plant located one mile 

from the Charles Polleti Plant constructed on the site of an old oil terminal. 

 The KeySpan Corp’s 250-MW combined cycle expansion at the existing 2,160 

MW facility at Ravenswood completed in 2004 was space constrained requiring 

the dry cooling system to be located on the roof.

 The Astoria Repowering Project is a project currently under development that will 

replace 31 existing simple cycle turbines with a capacity of 600 MW with four 

new combined cycle units with a proposed capacity 1,040 MW.

Disadvantages of Dry Cooling in a Retrofit

1. Cost effectiveness. Increasing flow reduction from 95% to 99% does not 

significantly reduce impingement mortality or entrainment reduction in relation to wet 

cooling towers, especially when dry cooling costs many times more.

2. Efficiency. Total energy penalties can double for dry cooling versus wet cooling, 

although the gap may be less in colder climates. With dry systems, the dry bulb 

temperature is the governing variable as opposed to wet systems (which depend on wet 

bulb temperature). Since dry bulb is always greater than wet bulb (can be equal at 100% 

saturation) and dry systems have a narrower cooling range, dry systems will always have 

higher steam condensing temperatures than wet. 

3. Configuration. There are two options in a dry system: air cooled condensers 

(ACC) and indirect. ACC operates like a car radiator in that the system is a sealed loop 

that exhausts steam from the turbine directly to the radiator fins where it is condensed 

and returned to the boiler. The ACC configuration is limited because, ideally, the ACC is 

placed close to the turbine exhaust point in order to maintain the necessary pressure 

through the system. The indirect dry system places a heat exchanger between the turbine 

exhaust point and the cooling tower. Water or some other fluid circulates between the 

tower and the surface condenser. This is less efficient than an ACC and requires a larger 

tower, increasing the energy penalty. An indirect system is also limited in terms of 

distance (although not as much as an ACC) since pressure must be maintained through 

the sealed loop. Indirect systems are the only plausible configuration for retrofits at 

power plants and many manufacturers since they already have a surface condenser in 

place. Retrofitting to an ACC would require substantial modifications to the system, 

approaching the cost and complexity of a repower.

4. Unprecedented. There is no evidence that any facility has ever done a retrofit to 

dry cooling. Recognizing that technology options are different for new and existing 

facilities, it is difficult to make the case for dry cooling’s feasibility since there are no 

known case studies anywhere in the world.
Summary of Dry Cooling Installations in the US

Both GEA and SPX have been the main suppliers of large dry cooling systems (both 

direct and indirect cooling systems) in the US. However, when asked about indirect 

cooling installations in the US, a GEA representative said that that they are not aware of 

any installed in the US and that their Hungary office supplies indirect dry cooling 

systems.

Attachment A presents a list of direct air-cooled condensers installations from 1968 to 

2010 provided by GEA Power Cooling, Inc. This list includes 61 installations in the US 

with 20 installed from 2000 to 2009. Only six (15%) of the 41 projects prior to 2000 had 

generating capacities of 100MW or greater. Whereas 13 (65%) of the 20 from 2000 to 

2009 had generating capacities of 100MW or greater. Thirteen of the recent 20 were 

combined cycle plants, four were coal-fired and the remaining three were waste-toenergy and cogeneration plants. 

Attachment B presents a list of direct air-cooled condensers installations in the US from 

1968 through 2006 from all vendors provided to EPA by EPRI. This list includes 73 

facilities. When the six recent (2006 through 2009) facilities on the GEA list are added,

the total becomes 79 facilities.

Table 1 provides the distribution of dry cooling installations and total capacity by state 

and region from 2000 through 2009 based on the 79 installations from both the GEA and 

EPRI lists. Based on the combined data approximately 74% of the total steam capacity

was installed in the period from 2000 through 2009. As can be seen in Table 1, the 

greatest concentrations of dry cooling capacity are located in the northeastern and 

southwestern regions of the US.
Table 1

Number and Total Capacity of Dry Cooling Condenser Systems Installed from 1968

through 2010 by State

Region State

Number of 

Facilities

Total Steam Capacity 

MWe

Total Steam Capacity 

MWe

Northwestern 

States

AK 3 80

1,443 MT 1 42

WA 3 306

WY 6 1,015

North Central 

States

MN 2 61

120 MI 1 9

IL 2 10

IA 1 40

Northeastern 

States

CT 2 305

4,124

MA 11 1,485

ME 2 100

NJ 3 429

NY 13 1,288

PA 3 438

RI 1 80

Southwestern 

States

AZ 1 3

3,777

CA 7 558

CO 2 900

NM 1 148

NV 5 1,050

TX 3 880

UT 1 200

HI 1 38

Southeastern 

States

MS 1 350

VA 2 325 755

WV 1 80

Total 79 10,220 10,220

References

EU. European Commission. Integrated Pollution Prevention and Control (IPPC).

Reference Document on the application of Best Available Techniques to Industrial 

Cooling Systems. December 2001.

http://eippcb.jrc.es/reference/cv.html

GAO. Energy-Water Nexus: Improvements to Federal Water Use Data Would Increase 

Understanding of Trends in Power Plant Water Use October 2009

GAO-10-23

http://www.gao.gov/new.items/d1023.pdf
Environmental Agency UK. “Cooling Water Options for the New Generation of Nuclear 

Power Stations in the UK.” 2010.

Electric Power Research Institute. Comparison of Alternate Cooling Technologies for 

California Power Plants Economic, Environmental and Other Tradeoffs. Prepared For:

California Energy Commission. February 2002

500-02-079F

http://www.energy.ca.gov/reports/2002-07-09_500-02-079F.PDF

“Astoria Energy Project Queens, NY SCS Energy LLC. Taking Modularization To The 

Next Level.” Combined Cycle Journal, Fourth Quarter 2006.

http://www.scsenergyllc.com/ccjournal.pdf

Ravenswood Expansion

http://www.emersonprocess.com/home/library/articles/ccj/ccj03q4_ravenswood.pdf

Air Resources Group, LLC. Astoria Repowering - Draft Environmental Impact Statement 

EIA. April 16, 2010

http://www.nrgenergy.com/news-center/astoria/pdf/Binder%20I%20--

%20DEIS/01%20DEIS.pdf

Riverkeeper. “Comprehensive Survey and Investigation of Dry Cooling Systems to 

Reduce I and E.” (in P2 Docket)

Wurtz, W. SPX Cooling Technologies Inc. and Peltier, R. PhD PE. “Air-Cooled 

Condensers Eliminate Plant Water Use. Power Magazine. September 15, 2008. 

http://www.powermag.com/water/Air-cooled-condensers-eliminate-plant-wateruse_1361.html

Wolfe, J.R., Phd, PE, Limno-Tech. “Costlier, Scarcer Supplies Dictate Making Thermal 

Plants Less Thirsty.” Power Magazine January 15, 2008.

http://www.powermag.com/issues/features/105.html

Maulbetsch, J.S, DiFilippo M. N., Zammit K. D. “Spray Cooling for Performance 

Enhancement of Air-Cooled Condensers.” EPRI Advanced Cooling Workshop. August 9, 

2008.

http://mydocs.epri.com/docs/AdvancedCooling/PresentationsDay2/7_070908%20Spray%

20Enhance%20Presentation%20Day%202_Zammit.pdf

Attachment A

GEA Air Cooled Condenser Installations

(See pdf Attachment)
Attachment B 

Air Cooled Condenser Installations from EPRI

Plant Capacity2

MWe MWe t/h

NY SPX1 Astoria Energy Astoria 500 170 460 2006

WY GEA Black Hills Generation WyGen II/Unit 4 80 80 2005

MN GEA FibroWatt Fibrominn Biomass ? 55 2004

AK GEA US Army Ft. Wainwright CHP Plant 22.5 3 x 5 2004

CA GEA Noresco 32nd St. Naval Station ? 5 2004

AZ GEA Pinnacle West Snowflake ? 3 2004

UT GEA PacifiCorp Currant Creek 525 200 2004

NV Hamon1 Genwest LLC/Silverhawk Silverhawk 570 170 2004

NY Hamon NYPA/GE/Sargent & Lundy Poletti 450 150 2004

NV Hamon Reliant/Sargent & Lundy Big Horn 598 160 2003

NY Marley/BDT

1 Key Span Ravenswood 256 80 278 2002

WA Marley/BDT Parsons Chehalis 520 170 490 2001

MA Hamon Sithe/Raytheon Mystic 1600 500 2002

MA Hamon Sithe/Raytheon Fore River 750 250 2002

NV Marley/BDT Mirant APEX 550 170 697 2001

CA GEA Calpine Otay Mesa 500 277 2001

MS GEA Reliant Choctaw County 800 350 2001

NV GEA Nevada Power Chuck Lenzie 1200 400 2001

WY GEA Black Hill Generation WyGen I/Unit 3 80 80 2001

PA GEA Reliant Hunterstown 950 350 2001

CA Hamon Calpine/Bechtel Sutter 500 170 2001

CO GEA Front Range Power Front Range 500 150 2001

MA Marley/BDT ABB Bellingham 558 200 2 x 256 2001

WA GEA GoldendaleEnergy Goldendale 250 110 2000

NY GEA PG&E Generating Athens 1058 360 2000

CT Marley/BDT ABB Lake Road 840 275 3 x 256 2000

MA Marley/BDT ABB Blackstone 570 180 2 x 256 2000

TX Marley/BDT ABB Midlothian 1650 500 4 x 255 2000

TX Marley/BDT ABB Hays 1100 300 2 x 256 2000

ME GEA Rumford Power Associates Rumford 115 80 1999

NV GEA Sempra Energy / Reliant Energy El Dorado 500 150 1999

RI GEA Tiverton Power Associates Tiverton 265 80 1999

MA GEA Energy Mangement Inc. Dighton 169 60 1998

CA Marley/BDT Bechtel, Crockett Crockett 240 80 275 1996

IL GEA Browning Ferris Gas Serv. Inc. Mallard Lake Landfill 18 9 1996

MT Marley/BDT Billings Generation Rosebud 42 42 210 1995

IA GEA Municipal Electric Utility Cedar Falls/Streeter 50 40 1994

MA GEA Ogden Martin Sys. of Haverhill Haverhill Extension 46.9 46.9 1994

MI GEA Browning Ferris Gas Serv. Inc. Arbor Hill 9 9 1994

MN GEA Browning Ferris Gas Serv. Inc. Pine Bend Landfill 15 6 1994

NY GEA MacArther Res. Rec. Agency Islip ? 11 1994

NY GEA Dutchess County Dutchess Co. Extension 10 10 1993

VA GEA Mission Energy Gordonsville 240 100 1993

NY GEA Odgen Martin Sys. Onondaga County 39 39 1992

NY GEA Falcon Seaboard Saranac 240 80 1992

WY GEA Black Hills Power & Light Neil Simpson II 80 80 1992

AK GEA University of Alaska Fairbanks ? 10 1991

MA Marley/BDT CRS Sirrine, Lowell Lowell 27 27 73 1991

NJ GEA Odgen Martin Sys. Union County 44 44 1991

NY Hamon Ogden/Marin/Huntington Huntington 25 25 1991

VA Hudson FPL Doswell 708 225 1991

NJ GEA Cogen Technologies Inc. Linden 520 285 1990

NJ GEA Intercontinental Energy Sayreville 292 100 1990

NY Marley/BDT Indeck Energy Silver Springs 58 20 55 1990

PA GEA Falcon Seaboard Norcon-Welsh 20 20 1990

MA GEA Intercontinental Energy Bellingham 300 100 1990

WV GEA Energy America Southeast North Branch 80 80 1990

Plant Capacity2

MWe MWe t/h

CT GEA Oxford Energy Exeter 30 30 1989

TX Hudson TXU Sweetwater 250 80 1989

WA GEA Wheelabrator Environ. Sys. Spokane 26 26 1989

NY GEA TBG Cogen Grumman ? 13 1988

MA GEA Ogden Martin Systems Haverhill 47 47 1987

Steam Turbine

Capacity3 Service

Date

State Vendor Customer Project/Site

Steam Turbine

Capacity3 Service

Date

State Vendor* Customer Project/Site

1990's

1980's