1

MEMORANDUM

Tetra Tech, Inc.

10306 Eaton Place, Suite 340

Fairfax, VA 22030

phone 703-385-6000

fax 703-385-6007

TO: Paul Shriner and Lisa Biddle, EPA

FROM: John Sunda, Tetra Tech

DATE: August 27, 2008 (revised May 13, 2014)

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

Reduction Technology for 316(b) and Costs

Introduction

At most existing power plants the intake cooling water pumps are fixed speed and are

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

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

(Gambica undated) Fixed speed pumps must constantly operate at the maximum flow rate 

regardless of the cooling water flow requirements, while the actual flow requirement will 

vary with the power generation rate and surface water temperature. The use of variable 

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

operators the flexibility to adjust the cooling water flow rate to better match the system’s 

cooling requirements.

A reduced flow volume will result in reduced O&M costs as a result of the reduction in

pump energy requirements. Depending on site-specific conditions this reduction can, in 

many cases, result in recovery of the capital cost of the technology over a period of time,

producing savings thereafter. In fact, VSPs are often employed in industrial systems 

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

volume has the added benefit of reducing impingement and entrainment (I&E) impacts.

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

but there are operational limitations and consequences associated with this flow reduction

technology. These limitations include:
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 National Pollution Discharge 

Elimination System (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 VSPs 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 reduction in 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 
3

disadvantage of increasing pumping head, which increases the pump energy

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 (i.e., the maximum power output and flow rate is reduced) 

or the motor will need to be replaced or rewound. Additionally, the pump itself may

require replacement or modification if the existing pump hydraulic characteristics are not 

compatible with variable speed operation and/or result in undesirable 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 may already be occurring but without the benefit of reduced 

pumping energy requirements. 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.
4

Using Variable Speed Pumps in Parallel with Single Speed Pumps

A potential costs saving measure would be to install a variable speed drive for only one 

pump of several pumps operating in parallel (i.e., discharge to a common pipe or header). 

Conceivably, this could cut costs by one-half or more while still providing considerable 

flow reduction flexibility. However, there are limitations that prevent this from being a 

practical option in many circumstances. Centrifugal pumps have operating curves where,

at any given speed, the flow volume varies with pumping head. Flow decreases as the 

pump head increases. A common rule for pumps is that all pumps operating in parallel 

should run to a similar characteristic which usually means identical pumps at identical 

speed (e.g., two VSPs can do this as long as the speeds are similar). If a fixed speed pump 

is operated in parallel with a variable speed of the same size, then the two curves will 

become different as the speed of one pumps is reduced. A point can be reached where the 

two curves do not intersect and flow in the slower speed pump will stop because it cannot 

produce sufficient head. This places limits on the operational flow range and the 

interaction of the pumps will create complexities in operation and control that are best 

avoided. It would be acceptable for a dedicated spare pump to remain fixed speed since 

all pumps could be operated at full speed under circumstances when the spare is needed. 

In developing cost estimates, it would be appropriate to assume that all pumps would be 

retrofitted with variable speed drives.

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. 

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 

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

reducing pump speed is 50% of maximum flow. (Mirant Delta 2007)

Another limitation is related to the desire to maintain a minimum average flow velocity in 

the condenser tubes. If the tube velocity drops below about 3 feet per second (fps), the 

pressure drop across the tubes becomes so low that the distribution of flow between tubes 

becomes less uniform reducing the predictability of condenser performance and 

increasing the potential for fouling. (Heat Exchange Institute 2006) Maximum 

recommended design tube velocities vary based on tube material, ranging from 6 fps for 

Admiralty steel to 8-10 fps for copper/nickel alloy and +30 fps for stainless steel.

(Janikowski 2003)
5

Another limitation is that at certain speeds pumps may suffer from excessive vibration 

when the frequency of the vibration caused by rotation matches the natural resonant 

frequency of the pump or of the support structure. While pumps may be safely

transitioned through these speeds, operation at these critical speeds for a prolonged 

period may cause serious damage to the pumps. VFD control systems can be 

programmed to transition through and avoid operating at selected ranges of pump speed.

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 from 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. The height of the 

inverted siphon is limited to prevent the formation of water vapor under the vacuum 

conditions that may form within the siphon. 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 savings in power usage. Thus, 

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

and system hydraulic characteristics must be carefully evaluated before deciding whether 

the benefits are worthwhile.

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 (delta T). Many 

plants have NPDES permit conditions that set a maximum limit for the delta 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 turbine exhaust pressure, resulting in a reduction in turbine efficiency. Thus, 

there is a competing economic incentive to maintain higher flow levels.
6

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

Unless existing intake velocities are relatively close to the 0.5 fps standard, 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 when 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 cooler. 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 a 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. Under very favorable conditions, the net operating 

savings may 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.

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

 Existing screen velocities can be reduced to below 0.5 fps.
7

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

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

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

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

 Traveling screens - Modules 1, 2, 2a, 31

 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. If existing screen velocities are 

already close to 0.5 fps, then compliance with impingement requirements may be 

possible using VSPs alone. For example, an intake with a screen velocity of 0.7 fps could 

meet the 0.5 limit with a consistent flow reduction of 30%.

Costs

Capital Costs

A VSP retrofit can involve installation/replacement of the following:

1. The variable frequency drive and associated instrumentation and controls

2. The pump motor

3. The pump and impeller

4. Power source modifications

5. Containment structure and HVAC modifications

The simplest retrofits will involve only item 1 but some projects could involve all five.

Since the power requirement is the primary cost driver for variable frequency drives, the 

costs are often expressed in terms of dollars per horsepower (Hp). However, since data 

concerning cooling water pump motor horsepower is generally not available to be used

for cost estimation, costs will be estimated using dollars per gallon per minute (gpm)

cooling water flow. Since the variable frequency drives will be working with the existing 

pumps, the design intake flow should serve as the basis. Table 1 below presents a 

summary of available variable speed pump total capital cost data for both installed 

projects and project estimates. One of the completed projects, the Pacheco Pumping 

Plant, is a water supply pump station with a very high pumping head of 241 feet (ft) and, 

thus, the dollar/gpm value does not compare well with power plants that operate at 

pumping heads closer to 50 to 60 ft. In order to provide comparable unit costs, the 

equivalent flow value for pumps with the same total motor power requirement with a

pumping head of 60 ft instead of 241 ft was calculated and used to derive $11.6/gpm unit 

 

1

See Chapter 8 of the Technical Development Document for a description of each of the technology 

modules.
8

shown.

2 All costs are adjusted for inflation to 2009 dollars. In general, variable frequency

drive costs in dollars/Hp have declined over time and therefore some of the older projects 

(Pittsburg, Contra Costa, Brayton Point) may be overestimated. The median value of 

$15/gpm should serve as a reasonable estimate for a typical VSP retrofit. 

Table 1.

Summary of Capital Costs for Variable Speed Pump Retrofits

Source

Capital 

Cost

Unit Cost

- Flow

Unit Cost

- Power

2009 

Dollars $/gpm $/Hp

Brayton Point Demonstration $1,250,000 $14.0 $971

Port Jefferson DT&C Estimate $5,337,000 $26.2 $1,451

Pittsburg CA Plant 1985 Estimate $5,749,000 $14.6

Contra Costa Units 1-5 $8,210,106 $21.6

Pacheco Pumping Plant (241 ft head) $14,000,000 $46.5 $583

Pacheco Pumping Plant Adj. to 60 ft 

heada$14,000,000 $11.6 $583

Carlsbad Desalination $8,500,000 $15.4

Medianb

$15 $971

a

See footnote 2

bExcludes Pacheco Pumping Plant at 241 ft head

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 decrease due to 

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

frequency drive (VFD) are low and only a slight amount of additional energy is required 

to run the VFD. While some additional periodic labor by a skilled electrician may be 

needed, 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 combined cost of 

variable frequency drive maintenance plus the energy penalty associated with reduced 

turbine efficiency (see discussion below). In other words, there would be no net gain or 

loss in annual O&M costs or total net power generation.

 

2 The costs of variable frequency drives and pump motors are more directly related to the energy 

requirements (e.g., Hp, MW) than to flow. At a constant pump Hp the pumping head will vary indirectly 

with flow (i.e., as pumping head increases flow will decrease). To compensate for this, the flow of pumps 

with same total HP but designed to operate at a lower head of 60 ft was calculated and used to drive the 

$/gpm value. 
9

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

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

be viewed as a low cost technology with respect to capital and net O&M costs. 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.

Energy Penalty

For any given steam load from the steam turbine, a reduction in cooling water flow will 

result in an increase in the temperature rise between the condenser inlet and outlet and a 

corresponding rise in the condensing temperature. This in turn increases the backpressure 

on the steam turbines resulting in a reduction of turbine energy output. Table 7-5 of the 

EPRI Technical Report “Closed-Cycle Cooling System Retrofit Study Capital and 

Performance Cost Estimates” presents turbine performance data for 13 different steam 

turbines of various designs ranging from lower to high pressure steam. The average 

calculated heat rate penalty from this table expressed as a percent of plant output is 

shown in Table 2. (EPRI 2011) The relationship between turbine backpressure (water 

vapor pressure) and condensing temperature is shown in Figure 1 along with an equation 

fitted to the data that allows the calculation of vapor pressure for any given water 

temperature. The heat rate penalty for any given increase in condensing temperature will 

increase with increasing initial temperature (i.e., marginal heat rate is higher at higher 

water temperatures). The increase in the slope of the line in Figure 1 as the water 

temperature rises is part of the reason for this. Table 2 also presents a rough estimate of 

the incremental rate of heat rate penalty increase for each increase in turbine 

backpressure. For example, as the condensing temperature increases from 93 degrees 

Fahrenheit (oF) to 102 oF the average increase in the heat rate penalty will be 0.03% per 

o

F.

Table 2.

Summary of Average Heat Rate Penalty 

Turbine Back 

Pressure

Condensing 

Temperature Heat Rate Penalty

Inches of 

mercury (in. Hg)

o

F

% per In. Hg 

Increasea

% per oF 

Increaseb

Total Penalty 

From 1.5 In Hg

1.5 93 0.6% 0.03% 0%

2 102 1.5% 0.09% 0.3%

3 114 2.1% 0.2% 1.8%

4 123 2.3% 0.3% 3.9%

5 130 - - 6.3%

a Average incremental rate per 1.0 In. Hg if temperature/back pressure is increased from this point.

b Average incremental rate per 1.0 o

F if temperature/back pressure is increased from this point.

Assuming that the condenser heat rejection rate (flow x temperature rise) remains 

constant, a flow reduction of 20% for a cooling system with a temperature rise of 15 oF 

would result in a temperature rise of 18.75 oF or an increase in the condenser outlet 

temperature of 3.75 oF. As a result, the condensing temperature inside the condenser will 
10

have a similar rise. At an initial condensing temperatures of 93 oF, the corresponding 

energy penalty would be approximately 0.11%. At an initial condensing temperature of 

102 oF, the corresponding energy penalty would be approximately 0.34%. The 

corresponding values for a larger flow reduction of 30% would be 0.2% and 0.6%, for 

initial condensing temperatures of 93 and 102 oF, respectively. The condensing 

temperature is the sum of the source water temperature, the condenser temperature 

increase (range), and the condenser total temperature difference (TTD) which is defined 

as the difference between the temperature of the hot water and the steam condensate 

exiting the condenser. The TTD typically ranges between 3-4 degrees Celsius (oC) (5.4 to 

7.2 oF) but can be higher for condensers designed to operate with a consistently cold 

water source. For a condenser with a TTD of 6 oF and a range of 15 oF, the cooling 

source water temperature corresponding to condensing temperatures of 93 oF and 102 oF

would be 72 oF and 81oF, respectively.

A typical cooling flow requirement for a once-through fossil-fuel cooling system with a 

range of 15 oF would be approximately 600 gpm/megawatt (MW). Assuming a pumping 

head of 60 ft and a pump efficiency of 75%, the corresponding pumping energy

requirement will be about 1% of plant output. If flow is reduced by 20%, the 

corresponding energy savings would be 0.2% of plant output. This pumping energy

savings is similar in value to the energy penalty when the source water temperature is 

around 80 oF in this example. During periods when the source water is cooler, for VSP 

installations with relatively low flow reduction values, in the 0 to 20% range, the 

pumping energy savings should be equal to or greater than any energy penalty. For higher 

flow reductions, especially during periods when source water is warmer,the energy

penalty may need to be factored into economic analyses.
11

Figure 1.

Relation of Condensing Temperature to Steam Pressure

Note: The equation calculates the vapor pressure for any given temperature in the range 

shown. In the equation y = water temperature in degrees F (Deg F) and x = vapor 

pressure in In Hg. R2 is the coefficient of determination of the equation with values close 

to 1.0 indicating a reliable data fit.

Examples

Millstone Nuclear Power Plant

The Millstone Nuclear Plant on Long Island Sound in Connecticut installed VFDs on the 

pumps. A report published prior to the planned operating start date of spring 2011 

indicated that the goal was to reduce impingement mortality and entrainment of winter 

flounder which are present during the period of April to May. The plant has agreed with 

the NPDES Permit authority to reduce their 2.2 billion gallons per day (bgd) intake flow 

by 40% during the period of increased biological activity. Flow reduction will be required 

from April 4 to June 5 or until the source water reaches 52 oF, whichever happens first. 

To continue operating normally, if the facility is required to reduce its intake flow, it will 

need to discharge water at a higher temperature. To facilitate this, the new NPDES permit 

allows for an increase in the discharge delta T limit for this period.3Table 3 below shows 

 

3 Note that this change in the discharge does not necessitate a modification of the receiving water 

temperature limitations. The presence of sufficient currents near the discharge enables the facility to 

continue meeting the existing thermal limit of no more than a 4 oF increase in receiving water temperature 

outside mixing zone even at the higher discharge temperature.

Water Vapor Pressure Curve

y = 0.0758e0.0322x

R

2

 = 0.9983

0

1

2

3

4

0 20 40 60 80 100 120 140

Water Temperature (Deg F)

V

a

p

o

r

P

re

s

s

u

r

e (In

H

g)

Vapor Pressure Expon. (Vapor Pressure)
12

the revisions in permit delta T limits and the associated flow reductions if the plant was 

operating at the limit. Table 2 shows that the increase in the delta T limit would result in 

flow reductions of 30% and 26% for units 2 and 3 respectively, if the units are operated

with delta T values close to the limits. To ground-truth the viability of the flow reduction

goal of 40% from April 4 to June 5, a review of NPDES discharge data, as reported in the 

Permit Compliance System (PCS) (EPA 2008) was conducted. This review indicates why 

the calculated reductions based on the delta T limits are lower than the proposed

reduction goal of 40%. PCS data indicate that the reported actual monthly maximum

delta T during a typical April to May period was typically 20-25 degrees, which is much 

lower than the limit. If it is assumed that the existing delta T is 23 oF during this period 

(selected from within the range of observed values), the corresponding flow reduction 

would be 44% if the operating discharge delta T was close to the limit of 41 oF. Since 

VFD control systems using real-time temperature sensors can be programmed to reliably 

control the pump flow such that the discharge temperature may be close to but not exceed 

the NPDES limitations, a 40% reduction appears to be achievable.

Table 3.

Millstone Nuclear Plant NPDES Temperature Limits

And Calculated Percent Flow Reductions

Millstone Nuclear

Normal 

Delta T 

Limit

Reported 

Spring 

Max 

Delta Ta

Seasonal 

VSP

Delta T 

Limit

Calculated 

Flow

Reduction 

Based on 

Change in 

Limitsb

Calculated 

Flow 

Reduction 

Based on 

Reported 

Max & 

Limitsc

o

F

o

F

o

F % %

Unit 2 Condenser Discharge 32 - 46 30% -

Unit 3 Condenser 28 - 38 26% -

Combined Discharge 

(Revised Limits) 32 23 41 22% 44%

Combined Discharge (Old 

Limits) 32 23 32 0% 28%

a Typical spring maximum delta T from PCS data.

b Calculated achievable flow reduction if operating delta T increases from Normal to Seasonal limit value.

c Calculated achievable flow reduction if operating delta T increases from Reported spring max to seasonal 

limit value.

For this base load plant, it appears that a reduction of about 25% could be achieved even 

without the modification to the discharge limits and that the modification increases the 

reduction to about 40%. However, the achievable reduction may be lower in warmer 

months (e.g., June – September) regardless of the delta T limit due to the need to 

maintain the discharge temperature below the maximum limit which in this case was 105 

o

F. PCS data suggests that during peak summer temperatures the delta T would need to be 

maintained below around 29 oF.

4 An increase in delta T from 23 o

F to 29 oF would result 

in a flow reduction of 20%.

 

4 The EPA PCS database showed that, at this facility for the period of 1999 to 2005, the reported maximum 

monthly intake temperature during the summer ranged from 73 to 76 oF. During 1998, the peak was 81 oF. 
13

This example shows that significant flow reduction can be achieved even at base load 

plants, especially during cooler months when high discharge temperature limits do not 

limit achievable reductions. However, flow reduction (especially during periods when the 

intake water is warmer) can result in a turbine efficiency loss which presumably is why

the permit flow reduction requirement for Millstone is limited to the optimal spawning 

season for winter flounder of April-May. The NPDES permit fact sheet mentions 

studying reductions at other times and, as suggested above, since they operate well below 

the maximum delta T for most of the year, there is an opportunity for substantial flow 

reduction even under less optimal conditions.

Indian Point

Unit 3 at the Indian Point Nuclear Plant uses VSPs. Table 4 presents the overall monthly

flow reductions attained from baseline that were presented in a technology evaluation 

report. (Enercon Services 2010) The recommended lower limit for tube velocity of 3 fps 

generally limits the flow reduction to around 50%.

Table 4.

Variable Speed Pump Flow Reduction Reported for Indian Point Unit 3

Month 

Baseline 

Flow

(mgd)

Historic 

Operating Flow

(mgd)

Average

Flow 

Reduction

January 1261.4 600.1 52.4%

February 1261.4 583.2 53.8%

March 1261.4 500.9 60.3%

April 1261.4 614.8 51.3%

May 1261.4 899.6 28.7%

June 1261.4 1199.1 4.9%

July 1261.4 1227.1 2.7%

August 1261.4 1217.4 3.5%

September 1261.4 1234.8 2.1%

October 1261.4 1170.1 7.2%

November 1261.4 806.5 36.1%

December 1261.4 715.2 43.3%

Average 

Annual

1261.4 899.0 28.7%

 mgd – Million gallons per day.

 Source: Enercon 2010. Table 3.2.

 

This example shows that flow reductions at facilities with variable speed pumps can have

considerable seasonal variations. The report notes that the design, efficiency, and 

operational requirements of the condensers and low pressure turbines affect the flow

levels but only specifically mentions the lower limit for condenser tube velocity which 

 

In order to meet the maximum limit of 105 oF when the peak intake temperature is 76 oF, the discharge 

delta T would need to be maintained below 29 oF and at an intake temperature of 81 oF it would need to be 

below 24 oF
14

limits the maximum reduction achievable if no other limitations are in effect. Although 

other operational limitations were not specified in this context, factors contributing to the 

smaller reductions during the warmer months may include: the limiting effect of NPDES 

temperature limitations similar to the Millstone example above; limits regarding the 

maximum allowable turbine back pressure which can effectively establish a maximum

condensing temperature; and self-imposed limit concerning the acceptable turbine 

efficiency penalty. The Unit 3 low vacuum alarm is set at no higher than approximately 4 

In Hg which is equal to a maximum condensing temperature of 123 oF based on data in 

Table 2. However, the NPDES maximum discharge temperature is 110 oF (93.2 oF 

between April 15 and June 30) which is much lower than 123 oF, indicating that the 

NPDES limits, and not the maximum turbine back pressure, are the limiting factors that 

determine the maximum achievable reductions during warmer months. The fairly low 

reduction of several percent that occur during the summer months suggest that the selfimposed limit concerning the acceptable turbine efficiency penalty may also be an 

important factor. As can be seen in Table 2, as the condensing temperature and 

corresponding turbine back pressure increase, the turbine efficiency penalty increases in 

an exponential manner and the resulting lost generation can have a significant economic 

and regional power supply impact that must be considered.
15

References

ASA Analysis & Communication, Inc. Design and Construction Technology Review

for the Port Jefferson Power Station. August 2007. DCN 12-6815.

Electric Power Research Institute (EPRI). Closed-Cycle Cooling System Retrofit Study

Capital and Performance Cost Estimates. Technical Report Number 1022491. 2011. DCN 

10-6951.

Enercon Services, Inc. Evaluation of Alternative Intake Technologies at Indian Point 

Units 2 & 3. February 12, 2010. DCN 10-6962.

EPA. Envirofacts PCS-ISIS Search. Data for NPDES CT0003263.

Accessed at: http://www.epa.gov/enviro/facts/pcs-icis/search.html

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

www.gambica.org.uk/pdfs/VSD_Pumps.pdf. DCN 12-6813

Heat Exchange Institute. Standards for Steam Surface Condensers. 10th Edition. 2006.

Janikowski, D. S. Plymouth Tube Co. Selecting Tubing Materials for Power Generation 

Heat Exchangers. Presented at the Southwest Chemistry Workshop (Irving, TX): July 28-

31, 2003. DCN 12-6818.

Lee&Ro Inc. “Project Description for Pacheco Pumping Plant” Accessed at 

http://www.lee-ro.com/Proj-Electrical.htm. DCN 12-6814.

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

DCN 12-6817.

PG&E National Energy Group. Brayton Point Station Permit Renewal Application

NPDES Permit No. MA0003654. 316(a) and (b) Demonstration. Volume 4 Section 3.5.3 

Variable Speed Drive Pumps. November 2001. DCN 12-6811.

Pacific Gas & Electric (PG&E). Reexamination of Alternatives to Reduce Losses of 

Striped Bass at the Contra Costa and Pittsburg Power Plants. December 9, 1985. 

Accessed at: http://www.calwater.ca.gov/Admin_Record/C-048529.pdf. DCN 12-6816.

Poseidon Resources for San Diego Regional Water Quality Control Board. Carlsbad 

Seawater Desalination Project – Flow Entrainment and Impingement Minimization Plan. 

Chapter 4. March 6, 2008. Accessed at: 

http://www.slc.ca.gov/Reports/Carlsbad_Desalination_Plant_Response.html. DCN 12-

6812.