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 m ost 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 m any industrial sy stem designers allow a contingency on the system head required

. (Gambica undated) F ixed speed pumps must constantly operate at the maximum flow rate regardless of the cooling water flow requirements , whi le the actual flow requirement will v ary with the power generation rate and surface water temperature

. The use of v ariable speed pumps (VSPs) instead of fixed speed pumps at cooling water intakes allow s plant operators the flexibility to adjust the cooling water flow rate to better match the sy stem ’ s cooling requirements

. A reduced flow volume will result in reduced O&M costs as a result of the reduc tion in pump energy requirements . D epending on site

- specific conditions this reduction can , in many cases , r esult 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 sy stems solely for their economic benefit

. In the case of power plant intakes, the reduction in flow volume has the added benefit of reduc ing 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 s ystem characteristics , may restrict pump operation to a specified flow range to prevent damage to the pump

. The sy st em h ydraulic characteris tics will also affect the amount of savings in pump energy

cost ;  L imits in flow reduction associated with National Pollution Discharge Elimination System (NPDES ) Permit heat limits , since a decrease in flow will result in an increase i n condenser outlet temperature;  Economic consequences of reduced plant generation output resulting from reduced turbine efficiency associated with higher c ondenser temperatures. The latter two limitations are m ore of a concern during periods when the source water is warmer , and will also tend to limit flow reduction during periods when the sy stem is operating at peak capacity

. **I&E Reduction from Flow Reduction** There is no question that the flow volume reduction associated with use of VSP s c an result in direct and proporti onal reduction in the impacts for both impingement and entrainment (I&E). F or 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 oth er words, a flow reduction of 2 0% is assumed to result in a reduction in both I&E of approximately 2 0%. This may actually be a conservative assumption ( i.e., an underestimate o f total reduction in impact) , as the reduction in the approach velocity for an i ntake 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 ty pical configuration for intake water pumps involve s use of one to two or more fixed speed pumps in parallel that are used to pump water though e ach 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 he ad . 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 sy stem. For fixed speed pumps , there are onl y two way s 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 increas e in the pumping head. Bo th 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 s ys tem 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 the3

disadvantage of increasing pumping head , which increases the pump energy requirements ; in addition, the amount of throttling is limited by the h ydraulic capabilities and characteristics of the sy stem. These limitations substantially restrict the opportunity for flow reduction for most fixed speed pump sy stems. **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 devic e that varies the pump motor speed b y varyi ng 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 ty pe of s ys tem. In such cases, the p ump 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 characteristic s 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 u se of VFDs allow s the flow through the pumps to be controlled over a range of flow volumes , thus allowing the flow volume to be tailo red to the plant operating conditions. With proper control , the effect on turbine efficiency can be minimized and the efflu ent temperature can be maintained within the NPDES permit temperature limits. This allows the facility

full flexibility

to effect both small and moderate flow volume re ductio ns when conditions allow. During the winter months, use of flow reduction can actuall y 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 sy ste m ’ s consumptio n 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 by pass a portion of the flow around the condensers and piping c onfigurations that can recirculate condenser outflow back to the pump inlet. Inthe latter case , some flow reduction may already be occurring but without the benefit of reduced pumping energy

requirements

. Th e control of subcooling , especiall y slight to mo derate 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 flexibili ty . 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 usuall y means identical pumps at identical speed ( e.g., two VSP s can do this as long as the speeds are simil ar). 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 spe ed 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 Limit ation**  **s** 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 sy stem’s static head, resulting in zero flow

. Continuous operation at s uch 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. Th e flow volume response to varying speed is uni que for every combination of pump and sy stem hydraulics , and thus the minimum safe speed must be calculated for each application to avoid operation at or even near the shutoff head

. Sy stem 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 a) have installed VSPs and the minimum flow that can be attaine d 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, rang ing 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 b y rotation matches th e 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 s ys tems can be p rogrammed to transition through and avoid operating at selected ranges of pump speed. One important sy stem characteristic that affects the performance of VSPs is whether the total pumping head is predominantly the result of losses from friction or from st atic head. Where the pumping head is predominantly from friction losses, the flow reduction capability of VSPs is greater and overall sy stem efficiency at reduced flows will be greater
. An example of a sy stem where friction losses are a large component of the pumping head would be a sy stem that uses an inverted siphon configuration. Inverted siphon configurations are often used in once - through sy stems 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 sy stems require vacuum pumps to remove the gases that collect in the high points. The height of the inverted siphon is limited t o prevent the formation of water vapor under the vacuum con ditions that may form within the siphon. I f the condenser elevation is above the maximum siphon height , then the siphon height is shortened by e xposing the downstream end to the air at an elevation above that of the source water in a structure called a seal pit. F acilities where the condensers are located well above the water surface will have higher static components of the pumping head even whe n inverted siphons are used. Thus, the condenser elevation and piping configuration will affect the performance o f VSPs. In s ys tems where the pumping head is predominantly static head , as the pump speed is reduced a point is soon reached where s mall changes in speed can result in large changes in flow rate , especiall y as the pumping head approaches the s ys tem static head as described above . Thus , the available range of flow reduction is much lower than in sy stems where the pumping head is mostly friction losses

. Also, in sy stems where the pumping head is predominantly static head, the pump efficiency drops substantially

with reduced speed. Such s ys tems will experience much less savings in power usage . Thus, use of VSPs in such sy stems is les s advantageous . In high static head sy stems , the pump and sy stem hydraulic characteristics must be carefully evaluated before deci ding whether the benefits are worthwhile

. When the turbine sy stem 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 incre ase 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. Th is effectively plac es 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 , especiall y 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. Ingeneral , 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 relativel y close to the 0.5 fps standard, f low 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 c oupled 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 cap able 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 technolog ies that may otherwis e 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 assume d , at a minimum , that a retrofit will include replacement of the pump motor s. 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) . Actu al savings will be highl y variable depending on the sy stem 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 tec hnol ogy will pay for itself )

. However, i f flow volume reduction is aggressively sought, then pump energy savings will be offset b y reduced plant output associated with a reduction in turbine efficiency

. VSPs will be most effective when:

 Facility capacity uti lization rates are not very high.
 Cooling pump head is predominantly from friction losses and not static head.
 They are c ombined with other I&E reduction technologies

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

The amount of f

low 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 bene fit from being paired with VSPs may include:

 Traveling screens

- M odules 1, 2, 2a , 3 1
 Fish barrier net

- M odule 5
 Velocity

cap - M odule 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 , particularl y those with high app roach 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 me e t the 0.5 limit with a consistent flow reduction of 30%

. **Costs** Capital Costs A V SP 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. P ower source modifications 5. Containment structure and HVAC modifications The simplest retrofits will involve only item 1 but some projects could involve all five. S ince the power requirement is the primary cost driver for variable frequency drive s, the costs are often e xpressed in terms of dollars per horsepower ( Hp )

. However, since data concerning cooling water pump motor horsepower is generall y 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 present s a summary of available variable speed pump total capital cost data for both installed projects and project estimates. One of the completed projects, the Pache c o 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. Inorder 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 mo dules.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, Bray ton Point) may

be overestimated. The median value of $15/gpm should serve as a reasonable estimate for a ty pical V SP retrofit. **Table 1 .**  **Summary of Capital Costs for Variable Speed Pump Retrofits**

**Source Cap**  **i tal**  **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 head a $14,000,000 $11.6 $583 Carlsbad Desalination $8,500,000 $15.4 **Me dian**  **b** $15 $971
a See footnote 2 b Excludes Pache c o Pum

ping 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 sy stem at lower speeds. M aintenance costs for the variable frequency drive (VFD) are low and onl y 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 s ys tem will likely be controlled by

personne l 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 sy stem 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 gener ation.

2 T he 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 decreas e). 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 fac ilities that do not require aggressive flow reduction to meet I&E reduction requirements and where site conditions are moderately favorable , this technology sh ould be viewed as a low c ost 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 technol o gies. **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 EPRITechnical 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 low er 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 backpres sure (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 temp erature
. 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 ( o F ) to 102 o F 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** 
**In ches of**  **mercury (in. Hg**  **) o**  **F %**  **per In. Hg**  **Increase a**  **% per**  **o F** 

**Increase b**  **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 pres s ure 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 temp erature rise) remains constant , a flow reduction of 20% for a cooling s ystem with a temperature rise of 15 o F would result in a temperature rise of 18.75 o F or an increase in the condenser outlet temperature of 3.75 o F . As a result, the condensing temperature inside the condenser will10

have a similar rise. At an initial condensing temperatures of 93 o F , the corresponding energy penalty would be approximately

0.11%

. At an initi al condensing temperature of 102 o F , 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 o F , respectivel y . 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 stea m condensate exiting the condenser . The TTD typicall y ranges between 3

- 4 degrees Celsius ( o C ) (5.4 to 7.2 o F) but can be higher for condensers designed to operate with a consistently cold water source . For a condenser with a TTD of 6 o F and a range of 15 o F, the cooling source water temperature corresponding to condensing temperature s of 93 o F and 102 o F would be 72 o F and 81 o F, respectivel y . A ty pical cooling flow requirement for a once - through fossil

- fuel cooling sy stem with a range of 15 o F 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 b y 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 o F 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 analy ses.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. Inthe 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 indicati ng a reliable data fit

. **Examples** Millstone Nuclear Power Plant The Millstone Nuclear Plant on L ong Island Sound in Connecticut install ed VFDs on the pumps . A report published prior to the planned operating start date of spring 2011 indicated that the goal wa s to reduce impingement mortality and entrainment of w inter f lounder 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 th e period of increased biological activity . Flow reduction will be required from April 4 to June 5 or until the source water reaches 52 o F , whichever happen s 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 th is period. 3 Table 3 below shows

3 Note that this change in the discharge does not necessitate a modification of the receivi ng water tem perature 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 o F increase in receiving water temperature outside mixing zone even at the high er discharge temperature.



### Wa **te r**  **Vapor Pressure**  **Curve**
y = 0 .0 758e 0. 0322x 

### R 2

### = 0 .9 983

0 1 2 3 4

0 20 40 60 80 100 120 140



### Wa **te r**  **Te mp**  **erat ure**  **(D eg**  **F) V** **a p** **o r** **P r** **e s** **s u** **r e** **( I** **n H** **g )** 

Va por P ressure Ex

pon. (Vapor P ressure)12

the revisions in p ermit delta T limits and the associated flow reductions if the plant was operating at the limit

. T able 2 shows that the increase in the delta T limit would result in flow reductions of 30 % and 26 % for units 2 and 3 respectivel y, if the units are operat ed 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 lo wer than the proposed reduction goal of 40%

. PCS data indicate that the reported actual monthly max imum delta T during a typical April to May period was ty picall y 20

- 25 degrees, which is much lower than the limit . If it is assume d that the existing delta T is 23 o F during this period (selected from within the range of observed values), the corresponding flo w reduction would be 4 4 % if the operating discharge delta T was close to the limit of 41 o F. Since VFD control sy stems using real

- time temperature sensors can be programmed to reliabl y 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 Ma**  **x Delta T**  **a Seasonal** 

**V SP**  **Delta T Limit**  **Calculated**

**Flow Reduction**  **Based on Change in**  **Limits b**  **Calculated**

**Flow Reduction**  **Based on Reported**  **Ma x &**  **Limits c**  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 Lim its) 32 23 32 0% 28% a Ty pical spring max imum 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 s easonal 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 increase s 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 o F

. 4 An increase in delta T from 23 o F to 29 o F would result in a flow reduction o f 20%.

4 The EPA PCS database showed that, at this facility for the period of 1999 to 2005, the reported maximum mo nthly intake temperature during the summer ranged from 73 to 76 o F. During 1998, the peak was 81 o F.13

This example shows that significant flow reduction can be achieved even at base load plants , e speciall y during cooler months when high discharge temperature limits do not limit achievable reductions. However, flow reduction ( especiall y 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 p ermit fact sheet mentions studying reductions at other times and , as suggested above, since they operat e 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 generall y limits the flow red uction to around 50%.

**Table 4 .**  **Variable Speed Pump Flow Reduction Reported for Indian Point Unit 3 Month**  **Baseline Flow**  **( mgd**  **) Historic** 

**Operating Flow (**  **mgd )**  **Av erage** 

**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 considerabl e seasonal variations. The report notes that the design, efficienc y , 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 o F w hen the peak intake temperature is 76 o F, the discharge delta T would need to be maintained below 29 o F and at an intake temperature of 81 o F it would need to be below 24 o F14

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; limit s regarding the maximum allowable turbine back pressure which can effective ly 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 o F based on data in Table 2. However, the N PDES maximum discharge temperature is 110 o F (93.2 o F between April 15 and June 30 ) which is much lower than 123 o F , 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 fairl y low reduction of several percent that occur during the summer months suggest that the self

imposed limit concerning the acceptable turbine efficiency penalty may also be an important facto r . 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 p ower supply impact that must be considered.15

**References** ASA Analy sis & 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 Sy stem 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

- IS IS 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. 10 th Edition. 2006

. Janikowski, D. S. Ply

mouth 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. Bray

ton 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. Access e d 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 Imping ement Minimization Plan. Chapter 4. March 6, 2008

. Accessed at: http://www.slc.ca.gov/Reports/Carlsbad_Desalination_Plant_Response.html

. DCN 12

- 6812.