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: August 27, 2008 (updated March 8, 2011)

SUBJECT: Application of Variable Speed Cooling Water Pump Technology as a 

Flow Reduction Technology for 316(b)

Introduction

At most existing power plants 

sized to handle the maximum flow required

many industrial system designers allow a contingency on the system head required

Fixed speed pumps must constantly

cooling water flow requirements

power generation rate and surface water temperature

(VSPs) instead of fixed speed pumps 

flexibility to adjust the cooling water flow rate to 

requirements. 

A reduced flow volume will result in reduced

pump energy requirements. D

many cases, result in recovery of

producing savings thereafter. 

solely for their economic benefit

flow volume has the added benefit of 

impacts. 

VSPs can be used to reduce flow volume even during 

but there are operational limitations 

technology. These limitations 

MEMORANDUM

10306 Eaton Place, Suite 340

Paul Shriner, EPA

John Sunda (SAIC) and Kelly Meadows

August 27, 2008 (updated March 8, 2011)

of Variable Speed Cooling Water Pump Technology as a 

Flow Reduction Technology for 316(b)

power plants the intake cooling water pumps are fixed speed 

sized to handle the maximum flow required. These pumps may even be oversized

system designers allow a contingency on the system head required

constantly operate at the maximum flow rate regardless of 

cooling water flow requirements, while the actual flow requirement will vary

and surface water temperature. The use of variable speed pumps 

(VSPs) instead of fixed speed pumps at cooling water intakes allows plant operators 

the cooling water flow rate to better match the system’s cooling 

will result in reduced O&M costs as a result of the reduc

. Depending on site-specific conditions this reduction can

result in recovery of the capital cost of the technology over a period of

. In fact, VSPs are often employed in industrial systems 

solely for their economic benefit. In the case of power plant intakes, the reduction in 

benefit of reducing impingement and entrainment 

VSPs can be used to reduce flow volume even during periods of peak power generation, 

limitations and consequences associated with this flow reduction

hese limitations include:

of Variable Speed Cooling Water Pump Technology as a 

fixed speed and are

oversized, as 

system designers allow a contingency on the system head required1. 

regardless of the 

y with the

ariable speed pumps 

plant operators the 

s cooling 

eduction in

this reduction can, in 

technology over a period of time,

in industrial systems 

he reduction in 

impingement and entrainment (I&E) 

peak power generation, 

flow reduction
- 2 -

 Inherent limits of the technology that, based on system characteristics, may 

restrict pump operation to a specified flow range to prevent damage to the pump. 

The system hydraulic characteristics will also affect the amount of savings in 

pump energy cost; 

 Limits in flow reduction associated with NPDES Permit heat limits, since a

decrease in flow will result in an increase in condenser outlet temperature;

 Economic consequences of reduced plant generation output resulting from 

reduced turbine efficiency associated with higher condenser temperatures.

The latter two limitations are more of a concern during periods when the source water is 

warmer, and will also tend to limit flow reduction during periods when the system is 

operating at peak capacity.

I&E Reduction from Flow Reduction 

There is no question that the flow volume reduction associated with use of variable speed 

pumps can result in direct and proportional reduction in the impacts for both 

impingement and entrainment (I&E). For the purposes of compliance and benefits 

assessment, EPA has assumed that there is a direct one-to-one relationship between flow 

reduction and the reduction in I&E impacts. In other words, a flow reduction of 20% is 

assumed to result in a reduction in both I&E of approximately 20%. This may actually be 

a conservative assumption (i.e., an underestimate of total impact), as the reduction in the 

approach velocity for an intake may allow an even greater proportion of actively

swimming fish to avoid the intake and escape impingement and entrainment. Also, the 

reduction in through-screen velocity may reduce injury to impinged organisms that are 

returned via fish return, by reducing the force holding them against the screen.

Flow Reduction Using Existing Fixed Speed Pumps

The typical configuration for intake water pumps involves use of one to two or more 

fixed speed pumps in parallel that are used to pump water though each steam condenser. 

There may also be a spare pump that does not operate during normal conditions. Fixed

speed pumps will produce a constant volume of flow for any given set of hydraulic 

conditions, with flow volume being affected mostly by the pumping head. The pumping 

head is a measure of the energy delivered to the water by the pump and is often expressed 

in “feet.” The pumping head is the sum of the height the water is raised plus the friction 

losses as water is forced through the system. 

For fixed speed pumps, there are only two ways to reduce the flow volume: one is to turn 

off one or more pumps if there are several operating in parallel; and the other is to throttle 

the flow downstream of the pump, resulting in an increase in the pumping head. Both 

approaches have disadvantages and limitations. Turning off a pump can only be done 

when two or more pumps are operating in parallel and when the system conditions allow 

for a substantial flow reduction, like when the generators are operating well below 

capacity and/or when source water temperatures are very low. Throttling the flow has the 

disadvantage of increasing pumping head, which increases the pump energy
- 3 -

requirements; in addition, the amount of throttling is limited by the hydraulic capabilities 

and characteristics of the system. These limitations substantially restrict the opportunity

for flow reduction for most fixed speed pump systems.

VSP Retrofit

A VSP retrofit involves replacing fixed speed intake pumps with variable speed pumps. 

At a minimum, this involves the installation of a variable frequency drive (VFD) and 

replacement of the pump motor, switches, and controller. In many cases, this may be all 

that is needed. A variable frequency drive is an electronic device that varies the pump 

motor speed by varying the electrical frequency of the AC power delivered to the pump 

motor. In some cases, the existing motor may not be designed to handle the added 

harmonic electric currents associated with this type of system. In such cases, the pump 

motor may need to be derated (the maximum power output and flow rate is reduced) or 

the motor will need to be replaced. Additionally, the pump itself may require replacement 

if the existing pump hydraulic characteristics place too many limitations on the amount of 

flow reduction that can be obtained. If multiple pumps are operated simultaneously and in 

parallel, it is best to retrofit all of the pumps.

The use of VFDs allows the flow through the pumps to be controlled over a range of flow 

volumes, thus allowing the flow volume to be tailored to the plant operating conditions. 

With proper control, the effect on turbine efficiency can be minimized and the effluent 

temperature can be maintained within the NPDES permit temperature limits. This allows 

the facility full flexibility to effect both small and moderate flow volume reductions when 

conditions allow. 

During the winter months, use of flow reduction can actually result in an increase in 

turbine efficiency by eliminating subcooling in the condensers. Subcooling occurs when 

the steam condensate in the condenser is cooled excessively, resulting in the system’s 

consumption of additional heat to bring the condensate back up to the boiling temperature 

when it is recycled back to the boilers. Excessive subcooling can also result in the 

formation of condensed water droplets within the last stage of the turbine, which can 

damage the turbine blades. Measures to control excessive subcooling include the flow 

reduction methods described above for fixed speed pumps, as well as piping 

configurations that can bypass a portion of the flow around the condensers and piping 

configurations that can recirculate condenser outflow back to the pump inlet. In the latter 

case, some flow reduction is already occurring but pumping energy requirements are not 

reduced. The control of subcooling, especially slight to moderate subcooling that might 

otherwise be tolerated, provides another economic benefit for VSP retrofits through 

increased plant power output.

Operational Limitations

There are technical limitations to the amount of volume reduction that can be achieved

with VSPs. For any pump, as the speed is reduced, there is a point reached where the 

pump’s output head is equal to the system’s static head, resulting in zero flow. 
- 4 -

Continuous operation at such a condition must be avoided because the impeller will 

continue to spin and the water will recirculate within the pump casing, resulting in 

damage to the pump. The flow volume response to varying speed is unique for every

combination of pump and system hydraulics, and thus the minimum safe speed must be 

calculated for each application to avoid operation at or even near the shutoff head. 

System controls are set such that the minimum pump speed will be well above that which 

produces zero flow conditions. Two power plants in California (Pittsburg and Contra 

Cost) have installed VSPs and the minimum flow that can be attained at these plants by

reducing pump speed is 50% of maximum flow2.

One important system characteristic that affects the performance of VSPs is whether the 

total pumping head is predominantly the result of losses from friction or to static head. 

Where the pumping head is predominantly from friction losses, the flow reduction 

capability of VSPs is greater and overall system efficiency at reduced flows will be 

greater. An example of a system where friction losses are a large component of the 

pumping head would be a system that uses an inverted siphon configuration. Inverted 

siphon configurations are often used in once-through systems where the condenser 

elevation is close to the water surface, because they are well worth the savings in pump 

energy requirements associated with the siphon configuration. Such systems require 

vacuum pumps to remove the gases that collect in the high points. To prevent water 

vapor from forming under the vacuum conditions that form within the siphon, the height 

of the inverted siphon is limited. If the condenser elevation is above the maximum siphon 

height, then the siphon height is shortened by exposing the downstream end to the air at 

an elevation above that of the source water in a structure called a seal pit. Facilities 

where the condensers are located well above the water surface will have higher static 

components of the pumping head even when inverted siphons are used. Thus, the 

condenser elevation and piping configuration will affect the performance of VSPs.

In systems where the pumping head is predominantly static head, as the pump speed is 

reduced a point is soon reached where small changes in speed can result in large changes 

in flow rate, especially as the pumping head approaches the system static head as 

described above. Thus, the available range of flow reduction is much lower than in 

systems where the pumping head is mostly friction losses. Also, in systems where the 

pumping head is predominantly static head, the pump efficiency drops substantially with 

reduced speed. Such systems will experience much less power usage savings. Thus, use 

of VSPs in such systems is less advantageous. In these high static head systems, the 

pump and system hydraulic characteristics must be carefully evaluated before deciding

whether the available benefits outweigh the costs.

When the turbine system is operating at a given generation rate (i.e., a constant steam 

load), a reduction of the cooling water flow volume will result in a proportional increase 

in the condenser temperatures. This will result in an increase in the difference in cooling 

water temperature between the condenser inlet and the condenser outlet (∆T). Many 

plants have NPDES permit conditions that set a maximum limit for the ∆T value. This 

effectively places a practical limit on the amount of flow reduction that can be achieved.

During warmer months, the increase in condenser temperature will also result in a higher 
- 5 -

turbine exhaust pressure, resulting in a reduction in turbine efficiency. Thus, there is a

competing economic incentive to maintain higher flow levels.

Many plants have NPDES permit conditions that set a maximum effluent temperature,

which may put additional limitations on the availability of flow reduction through 

variable speed pumping, especially during summer months, regardless of the economic 

considerations. In fact, under extreme summer conditions, some plants may be required 

to maintain the cooling water flow at full capacity while having to reduce power output 

(derate) in order to meet temperature limits.

As described above, the amount of flow reduction that can be achieved has both 

operational and seasonal limitations. In general, opportunities for flow reduction are 

greater during cooler months and thus the benefits of I&E reductions may be enhanced or 

reduced depending on the timing of the seasonal variations in the presence and behavior 

of the various life stages of the affected aquatic organisms. 

Applicability

Flow reduction through the use of VSPs alone may not be sufficient to result in 

compliance with 316(b) I&E reduction standards. The technology, however, should be 

effective in producing partial reductions and, coupled with other technologies, may help 

ensure compliance. Because of the economic benefit associated with reduced pumping 

energy requirements, VSPs may be useful even when the other technologies are fully

capable of meeting the I&E requirements by themselves and when the presence of 

sensitive organisms coincides with the period when the source water is warmest. Given 

their limitations, EPA should not consider VSPs as a stand-alone technology option but,

rather, one that should be applied in conjunction with other technologies. VSPs should be

considered as a technology option that can provide moderate I&E reductions that 

complement other technologies that may otherwise be unable or only marginally able to 

meet the I&E reduction requirements.

The capital costs of VSP retrofit will be dependent on which components of the pumps 

need to be replaced; it should be assumed, at a minimum, that a retrofit will include 

replacement of the pump motors. Given the savings in pump energy costs associated 

with VSPs, the net operating costs should be negative in most applications (i.e., savings 

in pump energy costs will exceed any maintenance costs). Actual savings will be highly 

variable depending on the system hydraulic conditions, the plant operating schedule, and 

the degree of flow reduction attained. If conditions are favorable, the net operating 

savings will offset capital costs (i.e., the technology will pay for itself). However, if flow 

volume reduction is aggressively sought, then pump energy savings will be offset by 

reduced plant output associated with a reduction in turbine efficiency.

VSPs will be most effective when:

 Facility capacity utilization rates are not very high.

 Cooling pump head is predominantly from friction losses and not static head.
- 6 -

 They are combined with other I&E reduction technologies.

The amount of flow reduction that can be achieved at any given moment will vary from 

0% to as high as 50%. Given this variability, the overall flow reduction will lie 

somewhere in between and will be dependant on the factors described above. 

Technologies that could benefit from being paired with VSPs may include:

 Traveling screens - Modules 1, 2, 2a, 3

 Fish barrier net - Module 5

 Velocity cap - Module 8

Since reduced flow volume will result in a reduction in the approach and through-screen 

velocities, VSPs will likely result in improved performance of velocity caps and traveling 

screens, particularly those with high approach velocities.

Costs

Capital Costs

A review of the 316(b) Phase I Technical Development Document (TDD) shows that the 

VSP costs shown in Table 2-21, Table 2-22 and Chart 2-10 are comparative costs for new 

construction alternatives and do not include such costs as equipment removal,

installation, controls and instrumentation, housing for the VFD, and other indirect costs.

Any cost derived using the Phase I data must also include costs for these additional 

components.

O&M Costs

Operating costs of VSPs will consist of pump energy and equipment maintenance. 

Maintenance for the pump and motor should not change and, in fact, may drop due to less 

mechanical stress on the system at lower speeds. Maintenance costs for the variable 

frequency drive are low and only a slight amount of additional energy is required to run 

the VFD. While operation may require more frequent oversight, the system will likely be 

controlled by personnel in the main control room. Thus, the only significant change in 

O&M costs will be the reduction in pump energy requirements (i.e., negative net O&M).

Assuming the goal is to maximize flow reduction, it is reasonable to assume that an 

aggressive flow reduction may be sought and, at times, will result in reduced turbine 

efficiency, especially during the summer. The simplest O&M cost approach would be to 

assume that the system will be operated such that the annual reduction in pumping energy

will be roughly equal to the energy penalty associated with reduced turbine efficiency. In 

other words, there would be no net gain or loss in annual total power generation.

For facilities that do not require aggressive flow reduction to meet I&E reduction 

requirements and where site conditions are moderately favorable, this technology could 

be assumed to be a low- to no-cost technology with respect to capital and net O&M costs. 
- 7 -

As such, it is an available low-cost technology option that could be used to improve and 

supplement the performance of other onsite I&E reduction technologies.

Estimated VSP Costs for a Typical facility

Costs to install VSPs at a “typical” power plant (with a DIF of 800 mgd) are presented in 

the table below. Two scenarios are provided: one where the facility has two circulating 

pumps per intake and a second where the facility has three circulating pumps per intake. 

By adding VSPs, the facility could tailor withdrawals to best meet cooling needs. This 

analysis assumes a cost of $15 per gpm, with no incremental O&M costs.

Typical 

Plant DIF 

Total

Proportion 

Add VSP Cost Flow Cost Flow

Unit Cost 

VSP Total Cost

MGD % MGD gpm $/gpm

2009 

Dollars

Assume 1 

in 3 pumps 

get VFD 800 33% 264 183,333 15 $2,750,000

Assume 1 

in 2 pumps 

get VFD 800 50% 400 277,778 15 $4,170,000

References

1Gambica Association Ltd. Variable Speed Drive Pumps – Best Practice Guide. 

www.gambica.org.uk/pdfs/VSD_Pumps.pdf

2MIRANT DELTA, LLC – DRAFT. Mirant Proposed BDCP Covered Activities. 2007.

Accessed at: 

www.resources.ca.gov/bdcp/docs/5.4.2007_HO_Mirant_BDCP_Covered_Activities_(2)_

.pdf

3

“Variable speed pumping for submersible wastewater pumping systems.” World Pumps. 

Volume 2003. Issue 439. April 2003. Pages 29-31. 

http://www.sciencedirect.com/science?_ob=ArticleURL&_udi=B6VJK-49KRN29-

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