                                       

                                  MEMORANDUM



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 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[1].  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:

             *       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 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. 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 flow[2].

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 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.
 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.   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

[1]Gambica Association Ltd. Variable Speed Drive Pumps  -  Best Practice Guide. 
www.gambica.org.uk/pdfs/VSD_Pumps.pdf

[2]MIRANT 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-X&_user=5099374&_rdoc=1&_fmt=&_orig=search&_sort=d&view=c&_acct=C000066306&_version=1&_urlVersion=0&_userid=5099374&md5=38f92d2724bc5ab6359cbbdbb92bfb89

