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 hy

brid wet/dry

coo dry cooling 1 is employed (e.g., hybrid plume abatement).
 Closed cycle hy

brid wet/dry cooled condensers are used.
 Indirect dry

cooling alone.
 Direct air c ooled condensers Except where used in conjunction with wet cooling to be in use at any power plants in the US. I ndirect dry

cooling is however, used in numerous applications where it is combined with wet evapor wet/dry) . Such s ys tems are used for plume abatement and consumption. This memo focuses on sy stem

. Dry c ooling is described and evaluated as a cooling sys tem 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 w et/dry cooling systems use indirect dry cooling. 

### MEMORANDUM

10306 Eaton Place, Suite 340

Paul Shriner, EPA John Sunda (SAIC) and Kelly Meadows , 201 1 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 hy

brid wet/dry

coo ling 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. I ndirect dry

cooling is however, used in numerous applications where it is combined with wet evapor ative cooling ( aka . Such s ys tems 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 sys tem 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 w et/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. I ndirect dry

cooling is however, used in

aka hy brid for reduction of water

cooling
ooling is described and evaluated as a cooling sys tem 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 w et/dry cooling systems use indirect dryincrease air emissions due to the energy penalty, cost more than three times more, and would not significantl y 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.) Ano ther 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” (GA O 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 sy stem typ es . Italso states that certain important data (including cooling technology and use/consumption by

technology) is no longer being collec ted b y USGS or EIA. The report touch es 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 als o discusses energy

penalties. The recommendations in the report focus mostly on data collection. Spray Cooling of Inlet A ir for Reduced Energy Penalty Dry cooling sy stem performance can be enhanced by pre - cooling inlet air using a fine mist spray

of wat er. Cooler air passing though the heat exchanger will result in lower steam turbine backpressures with a corresponding increase in turbine efficiency

. Sy stem does result in some water consumption but would be used intermittently during periods of high air temperatures with a ty pical 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. Multip liers can vary widel y based on site

- specific conditions and can be as high as 10 times or more the cost of wet cooling

. A good anal ys is of wet versus dry cooling costs can be found in the 2002 EPRIreport “Comparison of Alternate Cooling Technologies for California Power Plants ” prepared for the California Energy Commission (EPRI2002). The following text is from the report ’ s a bstract: “This study

defines, explains, and documents the cost, performance, and environmental impacts of both wet and dry cooling sy stems. A survey of the cooling s ys tem literature is provided in an annotated bibliography and summarized in the body

of the report. Conceptual designs are developed for wet and dry cooling s ys tems as applied to a new, gas

- fired, combined

- cycle 500

- MW pl ant (170 MW produced b y 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 sy stems using mechanical

- draft wet cooling towerswith surface steam condens ers and from $18 to $47 million for dry s ys tems using air

- cooled condensers. Cooling sy stem power requirements for dry s ys tems are four to six times those for wet s ys tems. Dry

s ys tems, which are limited by the ambient dry

bulb temperature, cannot achieve as low a turbine back pressure as wet s ys tems, which are limited b y the ambient wet bulb. Therefore, heat rate penalties and capacity limitations are incurred at some sites depending on local meteorology .” (EPRI2002). Dry Cooling and California Califor nia 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 rec reation , raising the question of whether there i s 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 nearb y (http://www.energy .c a.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 , likel y contributing to the conclusion that dry cooling is the most appropriate technology

. It is widel y 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 b ottom line is that for new facilities, dry

cooling is technologicall y and economically competitive with wet cooling when factoring in environmental compliance issues

. Dry Cooling and New York In the past 10 ye ars , six power generation sy stems 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 b y 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 Key Span 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 s ys tem 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. Disadv antages of Dry

Cooling in a Retrofit 1. Cost effectiveness. Increasing flow reduction from 95% to 99% does not significantl y 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 s ys tems, the dry

bulb temperature is the governing variable as opposed to wet sy stems ( which depend o n wet bulb temperature ). Since dry bulb is alway s greater than wet bulb (can be equal at 100% saturation) and dry

s ys tems have a narrower cooling range, dry s ys tems will alway s have higher steam condensing temperatures than wet. 3. Configuration. There are two options in a dry s ys tem: air cooled condensers (ACC) and indirect. ACC operates like a car radiator in that the sy stem is a sealed loop that exhausts steam from the turbine directl y 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 s ys tem. The indirect dry s ys tem 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 maintain ed through the sealed loop. Indirect sy stems are the onl y plausible configuration for retrofits at power plants and many manufacturers since they already have a surface condenser in place. Retrof

itting to an ACC would require substantial modifications to the sy stem, 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 s ys tems (both direct and indirect cooling s ys tems) 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 suppli es indirect dry cooling sy stems

. Attachment A presents a list of direct air

- cooled condensers installations from 1968 to 2010 provided b y GEA Power Cooling, Inc. This list includes 61 installations in the US with 20 installed from 2000 to 20 09 . Only six (15%) of the 41 projects prior to 20 0 0 had generating capacities of 100MW or greater. Whereas 13 (65%) of the 20 f rom 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

- to
energy 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 20 09 based on the 79 installation s 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 In stalled from 1968 through 2010 by State Region State Number of Facilities Total Steam Capacity MW e Total Steam Capacity MW e 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 1 350 755

VA 2 325 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 Sy stems. 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 200 9 GAO

- 10

- 23 http://www.gao.gov/new.items/d1023.pdfEnvironmental 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 S ystems to Reduce I and E.” (in P2 Docket) Wurtz, W. SPX Cooling Technologies Inc. and Peltier, R. PhD PE . “Air

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

. http://www.powermag.com/water/Air

- cooled

- condensers

- eliminate

- plant

- water
use_1361.html Wolfe, J.R., Phd, PE, Limno

- Tech . “ Costlier, Scarcer Supplies Dictate Making Thermal Plants L ess Thirsty .” Power Magazine January 15, 2008

. http://www.powermag.com/issues/features/1 05.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_Zammi t.pdf

Attachment A GEA Air Cooled Condenser Installations

(See pdf Attachment)Attachment B Air Cooled Condenser Installations from EPRI Plant Capacity

2 MW e MW

e t/h NY SPX 1 Asto ria Energy Asto ri a 500 170 460 2006 WY GE A Black H ills Generat ion WyG en II/ Unit 4 80 80 2005 MN GE A FibroW att Fibrominn Biomas s ? 55 2004 AK GE A US Army Ft. Wa inwright CHP Plant 22. 5 3 x 5 2004 CA GE A Nores co 32nd St. N av al Station ? 5 2004 AZ GE A Pin nac le W es t Sn owfl ak e ? 3 2004 UT GE A Pac if iCorp Currant C reek 525 200 2004 NV Ham on 1 Genwes t L LC/ Silv erhawk Silv erhawk 570 170 2004 NY Hamon NYPA/GE/Sarge nt & L undy Poletti 450 150 2004 NV Hamon Rel iant /Sa rgent& L undy Big Horn 598 160 2003 NY Marley /BD T1 Ke y Sp an Rav ens wood 256 80 278 2002 WA Marley /BDT Pars ons Chehalis 520 170 490 2001 MA Hamon Sithe/Ray th eon Mystic 1600 500 2002 MA Hamon Sithe/Ray th eon Fore Ri ve r 750 250 2002 NV Marley /BDT Mir ant APEX 550 170 697 2001 CA GE A Calpine Ot ay Me sa 500 277 2001 MS GE A Reliant Choc taw C ount y 800 350 2001 NV GE A Nev ada Power Chuc k L enz ie 1200 400 2001 WY GE A Bla ck H ill Generat ion WyG en I/Unit 3 80 80 2001 PA GE A Reliant Hunt erst own 950 350 2001 CA Hamon Calpine/ Be ch te l Sut ter 500 170 2001 CO GE A Front Range Power Fr ont Range 500 150 2001 MA Marley /BDT ABB Bellingham 558 200 2 x 2 56 2001 WA GE A GoldendaleE nergy Goldendale 250 110 2000 NY GE A PG &E G enerat ing Ath ens 1058 360 2000 CT Marley /BDT ABB Lak e Road 840 275 3 x 2 56 2000 MA Marley /BDT ABB Blackstone 570 180 2 x 2 56 2000 TX Marley /BDT ABB Midlothian 1650 500 4 x 2 55 2000 TX Marley /BDT ABB Hay s 1100 300 2 x 2 56 2000 ME GE A Rum fo rd Power Associates Rumford 115 80 1999 NV GE A Se mpra Energy / Reliant En ergy El D orado 500 150 1999 RI GE A Ti ve rton Power Associates Ti ve rt on 265 80 1999 MA GE A Energy Ma ngement I nc
. Dight on 169 60 1998 CA Marley /BDT Bec ht el, Croc ke tt Croc ket t 240 80 275 1996 IL GE A Br owning Ferris Gas Ser

v. I nc. Mallard Lak e Landf ill 18 9 1996 MT Marley /BDT Billings Generation Ros ebud 42 42 210 1995 IA GE A Munic ipal Electric U ti lity Cedar Falls/Str eet er 50 40 1994 MA GE A Ogden Martin Sys. of H av erhi ll Hav

erhi ll Extension 46.9 46. 9 1994 MI GE A Br owning Ferris Gas Ser

v. I nc. Arbor Hi ll 9 9 1994 MN GE A Br owning Ferris Gas Ser

v. I nc. Pine Bend Landf ill 15 6 1994 NY GE A Mac Ar th er Res . Rec . Ag enc y Is lip ? 11 1994 NY GE A Dut ch ess Count y Dut ches s Co. Exte ns ion 10 10 1993 VA GE A Mission Energ y Gordons vi lle 240 100 1993 NY GE A Odgen Martin Sys. Onondaga County 39 39 1992 NY GE A Falc on Seaboard Sa ranac 240 80 1992 WY GE A Black H ills Power & Light Neil Simpson I I 80 80 1992 AK GE A Uni ve rsity of Ala ska Fairbank s ? 10 1991 MA Marley /BDT CRS Sirrine, Lowell Lowel l 27 27 73 1991 NJ GE A Odgen Martin Sys. Uni on County 44 44 1991 NY Hamon Ogden/Marin/ Hunt ingt on Hunt ington 25 25 1991 VA Huds on FPL Dos wel l 708 225 1991 NJ GE A Cogen Te chnologies I nc
. Linden 520 285 1990 NJ GE A Int erc ont inental Energy Sa yr ev ille 292 100 1990 NY Marley /BDT Indec k En ergy Silv er Springs 58 20 55 1990 PA GE A Falc on Seaboard Norc on-W elsh 20 20 1990 MA GE A Int erc ont inental Energy Bellingham 300 100 1990 WV GE A En ergy AmericaSo utheas t Nort h Br anc h 80 80 1990

Plant Capacity

2 MW e MW

e t/h
CT GE A Oxf ord Energy Exe te r 30 30 1989 TX Huds on TX U Sweet wat er 250 80 1989 WA GE A Wh eelabrator En vi ron. Sys. Spok ane 26 26 1989 NY GE A TB G Cogen Grumman ? 13 1988 MA GE A Ogden Martin Systems Hav erhill 47 47 1987 Ste am T urbine Capacity

3 Servi ce

Date Sta te Ve ndor Cu stomer Project/Site Ste am T urbine Capacity

3 Servi ce

Date Sta te Ve ndor* Cu stomer Project/Site

1990's

1980's