Tetra Tech, Inc.

10306 Eaton Place, Suite 340

Fairfax, VA 22030

phone 703-385-6000

fax 703-385-6007

TO: Paul Shriner and Jan Matuszko, EPA

FROM: John Sunda, SAIC

DATE: April 14, 2010

SUBJECT: Technology Analysis for the Discharge of Power Plant Combustion Flue 

Gas Through Natural Draft Cooling Towers 

Tetra Tech and SAIC were tasked by EPA with reviewing the conceptual design of an 

emerging technology for managing air emissions: t

combustion flue gas by injection into the plume of a natural draft cooling tower

design is an innovative technology

being introduced in the United States

dispersed into the atmosphere through the use of tall smoke stacks. 

natural draft cooling tower (NDCT) 

and dispersion of both the air pollutants contained in the flue gas and 

condensers. This technology is now a requirement for power plants in Germany

2010).

Background

In 2005, EPA issued the Clean Air Interstate Rule (CAIR) that requires reduction

sulfur dioxide (SO2) emissions 

2015. CAIR sets an emission reduction requirement for each State, based on

power plant emissions collectively at levels that EPA believes

achieve. SO2 annual caps are set at 

in 2015. NOx annual caps are set at 

MEMORANDUM

10306 Eaton Place, Suite 340

Paul Shriner and Jan Matuszko, EPA

John Sunda, SAIC and Kelly Meadows, Tetra Tech

April 14, 2010

Technology Analysis for the Discharge of Power Plant Combustion Flue 

Gas Through Natural Draft Cooling Towers 

Tetra Tech and SAIC were tasked by EPA with reviewing the conceptual design of an 

emerging technology for managing air emissions: the discharge of treated power plant 

combustion flue gas by injection into the plume of a natural draft cooling tower

ve technology, first introduced in 1981 in Europe that is just now 

in the United States. Normally, combustion flue gas is discharged and 

dispersed into the atmosphere through the use of tall smoke stacks. In this technology

(NDCT) serves the dual function of providing for 

the air pollutants contained in the flue gas and waste heat 

This technology is now a requirement for power plants in Germany

Clean Air Interstate Rule (CAIR) that requires reduction

) emissions and nitrogen oxides (NOx) in 28 eastern US states by

CAIR sets an emission reduction requirement for each State, based on

power plant emissions collectively at levels that EPA believes are highly cost

annual caps are set at 3.6 million tons in 2010 and drop to 2.5 million 

are set at 1.5 million tons in 2009 and 1.3 million 

Technology Analysis for the Discharge of Power Plant Combustion Flue 

Tetra Tech and SAIC were tasked by EPA with reviewing the conceptual design of an 

of treated power plant 

combustion flue gas by injection into the plume of a natural draft cooling tower. This 

is just now 

tion flue gas is discharged and 

In this technology, a

providing for discharge 

waste heat from the 

This technology is now a requirement for power plants in Germany (SPX 

Clean Air Interstate Rule (CAIR) that requires reductions in 

states by

CAIR sets an emission reduction requirement for each State, based on capping 

are highly cost-effective to 

2.5 million tons 

1.5 million tons in 2009 and 1.3 million tons in 
- 2 -

2015. CAIR was legally challenged and, on July 11, 2008, the US District Court of 

Appeals issued an opinion that remanded the rule, citing “more than several fatal flaws in 

the rule.” 

A subsequent December 23, 2008 ruling leaves CAIR and the CAIR Federal 

Implementation Plans (FIPs, including the CAIR trading programs) in place until EPA 

issues a new rule to replace CAIR in accordance with the July 11, 2008 decision. EPA 

informed the Court that development and finalization of a replacement rule could take 

about two years. The Court ruling did not modify any of the provisions in CAIR and the 

original deadlines are still effective. CAIR has increased the demand for the installation 

of equipment to remove SO2 from flue gas in coal-fired power plants, and wet flue gas 

desulphurization (FGD) is the preferred method (Kelly 2007).

First Installation in US

The Cardinal Station power plant is a three unit coal-fired power plant located along the 

Ohio River in Brilliant, OH and is owned by AEP. Units 1 and 2 have generating 

capacities of 615 MW each and came online in 1967. Both use once-through cooling,

withdrawing water from the Ohio River. Unit 3 has a generating capacity of 630 MW 

and first came online in 1977. Unit 3 uses a closed cycle cooling system with a 423 ft tall 

NDCT that was constructed as part of the original system. Recently, the plant has been 

required to upgrade its air pollution control equipment to include FGD on all three units, 

presumably in response to CAIR. An FGD upgrade has already been completed for Units 

1 and 2 in 2006, with the treated flue gas being discharged through a single new stack 

that is >1,000 ft tall and lined with fiberglass reinforced plastic (FRP). Recently, the 

SPX Corporation was awarded a contract to design and install the first NDCT flue gas 

disposal system in the US on Unit 3.

Total costs for the Unit 3 SPX contract are $47 million and include a fiberglass 

reinforced plastic conduit for transporting the flue gas from the new FGD to the existing 

NDCT and modifications to the tower associated with the retrofit.

1

 The SPX tower 

upgrade work was scheduled begin in late 2009 and the flue gas system installation is 

scheduled to be completed during the commissioning of a new FGD system in 2012. The 

following discussion examines the issues and benefits related to the use of NDCTs for the 

disposal of treated flue gas, especially as it relates to costs and cooling towers at power 

plants.

Technology Overview

Many of the flue gas treatment processes that are installed to meet more stringent air 

pollution discharge requirements (e.g., FGD) require that the flue gas be cooled in order 

 

1 Cardinal is also demolishing and rebuilding the tower fill assembly to improve tower performance and to 

extend its life, but this work was not a requirement for the flue gas disposal project (SPX 2010a). NDCT 

upgrade work also includes adding a lining to the interior and outer surface of the tower near the top with a 

corrosion-resistant coating. This was performed by AEP during a plant shut-down last year in anticipation 

of this project and is not included in the SPX contract total. 
- 3 -

to be processed, and many of these processes utilize wet scrubbing technology. In such 

processes, the flue gas is typically cooled to about 80 C (176 F) and becomes saturated 

with water vapor. The cooler flue gas introduces several problems within the air 

emissions control technology:

 It is saturated with water and still contains some SO3, chlorides, and fluorides 

which can condense out as an acid and can be very corrosive, requiring expensive 

corrosion-resistant materials in all of the air pollution control and downstream 

equipment (fans, heat exchangers, ducts, stacks). The stacks and equipment must 

be designed to prevent condensed acid droplets from being emitted out the top of 

the stack.

 The existing stacks are typically designed and sized to use the buoyancy of hot 

gas to draw the gases up through the stack. The cooler flue gas will require reheat 

equipment and/or additional fan energy to transport the flue gas through the stack,

both of which will require equipment with corrosion-resistant materials or linings.

 The reduced buoyancy changes the internal stack flue gas pressure from a 

negative to positive condition, increasing the likelihood that over time corrosive 

gases will pass through any cracks that may form in the stack liner and thus 

require the need for great care in design and installation of the flue liner.

 If not reheated, the colder flue gas plume exiting the stack will not rise as high,

reducing the effective stack height and resulting in less effective dispersion of the 

plume. Thus, a taller stack may possibly be required if the air pollution controls 

do not compensate for the effect on ground level concentrations locally

downwind.

The most common solution to these problems is to construct a new “wet” stack with a 

corrosion-resistant liner or lining. These stacks are designed with a lower gas velocity to 

minimize the emission of acid droplets out of the top of the stack. The use of the existing 

stack with modifications to resist corrosion plus the addition of gas reheat equipment is 

also an option. When installing a new FGD system, the use of an NDCT for flue gas 

disposal eliminates the costs of a new wet flue gas stack or the costs of modifying the 

existing stack system including reheat.

In the NDCT flue gas alternative, the cooled treated flue gas is piped from the air 

pollution control equipment and injected into the center of an NDCT well above the wet 

cooling section (at 49 meters height in one example). The cost of building a new 

smokestack system is replaced by the typically much lower cost of modifying the tower 

and installing the large diameter FRP conduit needed to transport the flue gas to the 

NDCT. Tower modifications include structural changes to accommodate the holes 

through the thin concrete shell needed for passage of the gases and measures required to 

deal with the presence of corrosive gases.

The introduction of the warmer (relative to water vapor from the cooling water stream) 

flue gas into the tower will provide additional buoyancy inside the tower, which in turn 

can increase tower air flow, providing some improvement to cooling tower performance. 

At the same time, the mixing and dispersion of the flue gas into the relatively large 
- 4 -

NDCT plume allows better dispersion of the air pollutants than would occur using a 

conventional stack under most circumstances. One study stated that this flue gas disposal 

method should be effective in reducing local ground-level concentrations, since NDCT 

plumes are typically very buoyant with a densimetric Froude number2below 1

(Schatzmanna et al 1987). The reverse is true only under high wind conditions when the 

NDCT plume may be subject to tower and building downwash. 

Benefits of the NDCT flue gas alternative include:

 Eliminated/reduced capital and O&M costs of treated flue gas discharge 

equipment downstream of the air pollution control equipment (stack, reheat

equipment, fans).

 Improved cooling tower performance due to an increase in the volume of air 

entering the tower and passing through the wet cooling section, resulting from the 

increased buoyancy of air inside the NDCT. This would produce slightly colder

cooling water leaving the tower, resulting in an improvement in turbine efficiency

and plant heat rate.

 Improved dispersion of stack gases downwind under most conditions.

This technology is limited to NDCTs and cannot be implemented for mechanical draft 

towers (MDCTs). Cooled flue gases are still too hot to be of any use in cooling the 

condenser water, and the injection of treated flue gas into the air outlet of an MDCT

would produce no benefit to the operation of the cooling tower. Such an application 

would result in unacceptable ground-level air pollution concentrations nearby, since 

MDCTs have a much lower discharge height and their plumes have a tendency to 

disperse near the ground and be recirculated.

Cost Considerations

EPA’s 316(b) rule compliance cost estimates are based on mechanical draft towers.

MDCTs have lower capital costs and higher O&M costs than NDCTs. According to a 

major cooling tower vendor, since NDCTs require a high capital investment, they are 

usually most economical when installed at large plants that operate frequently or 

continuously, such as a baseload coal or nuclear plant. When considering installation of 

a cooling tower, each individual facility would need to evaluate the balance between 

lower O&M costs of the NDCTs and their higher capital costs to determine the best

option. For many plants, the expected service life for the NDCT needs to be about 40 or 

more years to reach the break-even point (SPX 2010b). However, when cost adjustments

for components such as plume abatement are included in the comparison, or the savings 

of using an NDCT for treated flue gas versus installing a new wet stack are considered, 

then the break-even time frame can become much shorter.3

 

2 The Froude number is a unitless measure that quantifies the resistance of floating objects.

3 The degree to which the break-even point is reduced will vary depending on site-specific factors.
- 5 -

Brayton Point 

As an example, the Brayton Point Power Plant is installing two 500 ft NDCTs with a total 

design flow of 720,000 gpm to meet 316(a) and (b) requirements. Information from the 

facility indicates that the two NDCTs will cost about $500 million ($700 per gpm), which 

is roughly 1.8 times greater than the cost predicted by EPRI’s “difficult” retrofit costs 

estimate for a comparably sized conventional MDCT system ($280 million or $390 per 

gpm.

At first glance, the present value of the cost savings for O&M is $4 million4over 40 

years, which at a 5% discount rate is about $70 million; this is not comparable to the 

roughly $220 million capital cost difference between the NDCT system and a comparably

sized MDCT system. However, the EPRI “difficult” MDCT retrofit costs do not 

explicitly include plume abatement, which Brayton Point decided was necessary because 

of concerns about fog and icing on a nearby highway and bridge. Plume abatement 

towers cost between 2.5 and 3.5 times as much as conventional ones (SPX 2010a),

assuming the tower component of an MDCT costs about $75 per gpm. Assuming that the 

3.5x multiplier applies to saltwater systems, the plume abatement could add as much as 

about $260/gpm to the EPRI “difficult” MDCT retrofit cost. This additional $260/gpm is 

equivalent to $187 million, and the present value sum of all three costs ($280 + $187 + 

$70 million) is roughly $537 million for the MDCT option with plume abatement and 

including O&M. Thus, it appears that the need for plume abatement increased the cost of 

MDCTs to the point where the cost of each option was comparable. In addition, NDCTs

have other favorable traits, such as being more reliable at resolving the safety issues of 

fog and ice and of producing higher net generating capacity during peak demand periods.

Cost Savings of NDCTs

Probably the largest cost saving item for the NDCT flue gas disposal option is the 

elimination of the cost of a new stack or modifications to the existing stack. New stacks 

will be required for all new generating units with conventional flue gas systems. For 

repowered and existing plants being retrofitted with flue gas treatment technology, the 

existing stack may not be suitable for continued use. Factors affecting the associated 

costs and the decision to build a new stack or modify the existing stack include:

 The condition and expected service life of the existing stack;

 The compatibility of the new flue gas conditions with the design of the existing 

stack;

 The modifications to the stack required, particularly with respect to the prevention 

of corrosion;

 The need for flue gas reheat equipment, equipment O&M, and added equipment 

and fan energy requirements; and

 

4 One major difference between these two tower options is that the NDCTs do not require fans; O&M cost 

savings for fan energy requirement should be about $3 to $4 million per year.
- 6 -

 The location of the existing stack with respect to the new pollution control 

equipment. A poor location could result in the need for an excessive length of 

costly conduit or in insufficient available space for placement of the conduit. 

In many cases, retiring the old stack and building a new stack may be the selected option 

for a conventional flue gas system, as was the case for the original design at Units 1, 2, 

and 3 at Cardinal Station. In most cases, the option of using the existing stack has 

significant capital and much higher O&M costs and has generally been abandoned 

because of its high costs for little perceived benefit (Sargent & Lundy 2003).

A representative for a construction company that builds power plant stacks (who

requested anonymity) estimated that a new stack for Unit 3 at the Cardinal Station plant

would have cost about $10 to $15 million. This is equivalent to a unit cost of $15,400 to 

$23,100 per MW generating capacity for the 650 MW Unit 3. The reported new stack 

height for Units 1 and 2 is greater than 1,000 ft and it is assumed that the Unit 3 stack 

would have been comparable in height if that option had been chosen. The older original 

plant stacks for Units 2 and 3 are reported to be 826 ft and 895 ft, respectively. 

As a way to verify these costs, SAIC recently managed a project involving the upgrading 

of the air pollution control equipment at the Iowa Army Ammunition Plant that included 

replacing the stack for a small coal-fired industrial boiler. The construction costs for this 

150-ft tall stack were approximately $660,000, and the 257 MMBTU/hr boiler is 

estimated to be equivalent in energy output to a 27.8 MW coal-fired power plant based on 

an assumed heat rate of 9,300 BTU/hr. This is equivalent to a unit cost of about $24,000 

per MW generating capacity which is similar to the high end estimate for the Cardinal 

plant’s Unit 3. The fact that these two stacks of widely different heights have similar 

costs per MW is likely due to the fact that the economies of scale of the much greater flue 

gas volume (24X based on estimated equivalent generating capacity) are offset by the 

much greater height (6.7X) of the Cardinal Station power plant stack. 

Stack height is determined using air dispersion modeling to identify the minimum height 

needed to meet local air pollution regulations. EPA has also established a “good 

engineering practices” (GEP) stack height for any given site-specific application which 

takes into consideration the downwash effects of nearby structures. The GEP stack 

height is the maximum height that can be used in air dispersion modeling estimates even 

if the actual stack is taller, and is intended to prevent the use of taller stacks instead of air 

pollution control equipment to meet air standards. The average height for coal-fired 

boiler stacks built between 1971 and 1976 was 570 ft (Bellas 2008). The average stack 

height for all stacks at plants reporting a coal-fired steam flow in the 2006 EIA database 

was 445 ft with the tallest being 1103 ft. At nearly 1,000 ft, the Cardinal Station stack 

heights and estimated costs appear to represent the higher end of the range of stack 

heights and thus costs for similar plants throughout the US.

Another important cost item is the cost of the treated flue gas conduit. The comparative 

lengths of conduit for each of the two treated flue gas disposal options will factor into the 

decision of which method will be selected. If the distance from the air pollution control 
- 7 -

equipment to the location of the NDCT is much greater than the distance to the existing 

or proposed stack location, then high conduit costs may favor use of a stack. Since stacks 

have a relatively small footprint, there is much greater flexibility in selecting a site for a 

stack than for an NDCT and so the distance to a new stack may tend to be shorter. 

As a result of recent increases in the costs of corrosion-resistant metals, the trend has 

been to construct treated flue gas conduit using FRP, as will be the case for Cardinal 

Station Unit 3. One source estimated that installed FRP costs were about $100 to $150 

per sq ft (Kelly 2008). Using $125 per sq ft, the estimated costs of the 290-ft diameter 

liner that carried the Unit 1 flue gas inside the new 954 ft stack at Cardinal station would 

be approximately $11 million. This is equivalent to approximately $14,000 per MW for a 

1,000 ft length of flue gas conduit.

The case of Brayton Point provides additional perspective. While flue gas disposal may

not have been an issue at Brayton Point, if it had been, the location of the two new 

NDCTs appears to be rather far at around 1,500 to 2,000 ft from the generating units. 

The resulting estimated cost for a conduit to the NDCTs of $21,000 to $28,000 per MW 

appears to be similar in magnitude to the cost of building a nearby new stack at $24,000 

per MW. So in this case, had Brayton Point been required to upgrade their air pollution 

control equipment with FGD technology, the NDCT flue gas disposal option probably 

would not have resulted in any substantial cost savings. 

Potential Implications for 316(b) and Other Regulations

EPA raised the question of whether the flue gas disposal technology should be included 

in the 316(b) economic analyses. As noted above, the decision to use MDCTs or NDCTs 

as a flow reduction technology is site-specific. The incorporation of FGD wastes into an 

NDCT may influence a facility’s technology choice, but for the purposes of estimating 

national 316(b) compliance costs, MDCTs are the most appropriate technology given 

their versatility and the fact that they are the tower type that is most often utilized in 

cooling system retrofits and new construction. As noted above, for many plants, 

especially those with lower capacity utilization and shorter expected service life, using 

MDCTs may be the lower cost option as well. In some applications, MDCTs may be the 

more expensive option compared to NDCTs; in those cases, EPA’s selection of MDCTs 

for cost estimation represents a conservative costing approach, as the higher cost 

technology is assumed for those facilities. In summary, given the limited applicability of 

the technology, it would not be appropriate to include consideration of flue gas disposal 

in the 316(b) rule economic analysis. 

A second question would be whether a facility choosing to install NDCTs for compliance 

with 316(b) requirements should be included in any economic analyses for Clean Air Act 

(CAA) regulations. As stated above, the decision on which cooling tower technology to 

install incorporates a number of site-specific considerations that are not limited to solely

the CAA regulations. However, it is reasonable to expect that some facilities may select 

NDCTs as a technology option for compliance with either or both regulations. 

Additionally, it is possible that facilities with existing NDCTS (like Cardinal) will take 
- 8 -

advantage of the cost savings versus construction of a stack for the FGD. As such, it 

would likely be appropriate for EPA to consider flue gas disposal in the context of 

rulemakings under the Clean Air Act.

For existing plants, one issue that may limit the applicability of this technology is that the 

timeline for compliance with air pollution requirements such as CAIR has already been 

established and decisions to install air pollution control equipment to meet the 2010 SO2

caps have already been made. A facility may be able to amend its plans to incorporate an 

NDCT, but given the different time scales of CAA and 316(b) regulations, there may be 

minimal overlap in the decision-making criteria.

The technology may also be available to coal-fired generating units that will be newly 

constructed at an existing facility or for existing coal-fired generating units that are being 

repowered as coal-fired units, as long as the repowering requires major reconstruction or 

upgrade of the flue gas treatment and handling system. Repowered generating units that 

convert to cleaner burning fuels will tend to have less need for pollution control

equipment and may require shorter stack heights.

Conclusion

As discussed above, the discharge of FGD emissions via an NDCT is an emerging 

technology that may be evaluated as an additional option for a facility or new unit that 

must implement closed-cycle cooling. Additionally, there may be some opportunities for 

compliance cost reductions by combining technologies to meet multiple water rules and 

air emissions regulations. At the present time, however, there is not enough information 

to forecast adoption and use of the technology. 

 

References

M. Schatzmanna, M. Lohmeyerb, A. and Ortnerc G. “Flue gas discharge from cooling 

towers. Wind tunnel investigation of building downwash effects on ground-level 

concentrations.” Atmospheric Environment. Volume 21, Issue 8, Pages 1683-1875 

(1987).

SPX Cooling Technologies Inc. Marsten, Kent. Chief Technical Advisor - Evaporative 

Cooling. Personal communication with John Sunda, SAIC. January 15, 2010a.

SPX Cooling Technologies Inc. Marsten, Kent. Chief Technical Advisor - Evaporative 

Cooling. Personal communication with John Sunda, SAIC. February 26, 2010b.

Bellas, A.S. Largey, I “Did State Regulation of Power Plants Cause an Increase in 

Pollution Exportation?” U.S. Environmental Protection Agency Papers. 2008.

http://digitalcommons.unl.edu/cgi/viewcontent.cgi?article=1008&context=usepapapers

Kelly, Don. The Use of FRP in FGD Applications. Reinforced Pastics Volume 51, Issue 

1, January 2007, Pages 14-19.
- 9 -

Kelly Don. The Rapid Growth of Composites in Flue Gas Desulfurization (FGD) 

Processes 2008. 

http://www.derakane.com/downloadServlet?docPath=DPAPP1.asco.ashland.com%5CDa

ta%5Cascc%5Cecomdocsasc.nsf%5CEB2E55077DDFB4C3852574C8004B32A7%5C%

24FILE%5CCOAL-GEN_Paper_08_DHK.pdf

Sargent & Lundy LLC. Wet Flue Gas Desulfurization Technology Evaluation. Prepared 

for National Lime Association. January 2003. http://www.lime.org/Wet_FGD.pdf