Document ID: EPA-HQ-OW-2008-0667-0649
Agency: epa
Document Type: Supporting & Related Material
Title: 
Posted Date: 2011-04-20T04:00Z

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: 		September 30, 2010

SUBJECT:		Costs of Traveling Screen Versus Closed-Cycle Cooling at Power Plants on Rivers in the Midwest

During visits to power plants located on the Missouri and Mississippi rivers, EPA observed that a number of facilities were experiencing substantial equipment and operating problems due to high quantities of debris, silt, sand and other river conditions.  All of the plants utilized once-through cooling with traveling screens.  This analysis examines some of the problems and associated costs that would continue to occur at these facilities if the traveling screens were upgraded and the cooling system remained once-through.  Estimated costs for a closed-cycle retrofit are provided for comparison to see if the increased maintenance costs for the existing once-through system approach those of a closed-cycle retrofit.  The analysis suggests that for facilities with high debris loads or other issues, the additional costs of upgrading to closed-cycle cooling are unlikely to be offset unless the facility suffers from unscheduled outages or is forced to derate for an extended period.  However, a facility that does encounter such problems may quickly realize the benefits of converting to closed-cycle, as lost generation costs are substantial.  Unless specifically cited, the plant data provided here are taken from the Site Visit Reports listed in the reference section.

EPA Estimated Costs

When only the capital cost, equipment O&M costs, and energy penalty are considered, the difference in costs between a traveling screen upgrade and a retrofit with a closed-cycle cooling system can be quite substantial. Table 1 presents the estimated costs of replacing existing traveling screens with modified Ristroph Screens and a fish return, and the estimated costs of a closed-cycle cooling system retrofit for a typical 500 MW coal-fired power plant with traveling screens. These cost estimates are based on the EPA estimates for compliance costs for Module 1 (coarse-mesh Ristroph screens with fish return) and closed-cycle cooling. Baseline O&M costs are not deducted from the values shown. 

Assumed design parameters include:

   * Coal-fired plant with capacity of 500 MW
   * Design intake flow is 600 gpm/MW or 300,000 gpm
   * Capacity Utilization is 75%
   * Shoreline intake is 12 ft deep, with 50 ft screen wells with 1.4 fps screen velocity
   * Screen values were selected to produce a cost design equivalent to six 10-ft wide screens
   * Surface shoreline intake is on freshwater river
   * Discount Rate is 5% and service life of traveling screens and cooling towers are 20 and 30 years, respectively
   * Cost of lost power sales is $50/MWh
   * Cost of excess fuel use is $11/MWh
   * Energy and turbine penalty costs are assumed to be incurred as lost power 24% of the time and as excess fuel use 76% of the time
   * Turbine efficiency energy penalty is 1.5%
   * Downtime for Closed Cycle is a net of 4 weeks and is assessed as lost power at 80% of capacity, based on assumption that downtime will be scheduled during period of lower demand
   * Costs use a regional adjustment factor of 1.0 (national average) 

Table 1.  EPA Estimated Costs of Upgraded Traveling Screens and Closed-Cycle Retrofit at a Typical 500 MW Coal-fired Power Plant
                                       
                                 Capital Costs
                                   Downtime
                                 Fixed O&M
                              Variable O&M[1]
                      Energy Penalty - Pump & Fan[1]
                              Turbine Penalty[1]
                     Amortized Capital and Downtime Costs
                            Total Annualized Costs
                             Modified Ristroph TS
                                  $2,272,000
                                      $0
                                   $147,000
                                   $166,000
                               See Var. O&M
                                      $0
                                   $182,000
                                   $495,000
                              Closed Cycle (easy)
                                  $50,700,000
                                  $13,440,000
                                   $380,000
                                   $281,000
                                   $951,000
                                  $1,003,000
                                  $4,172,000
                                  $6,787,000
                            Closed Cycle (average)
                                  $78,900,000
                                  $13,440,000
                                   $380,000
                                   $281,000
                                   $951,000
                                  $1,003,000
                                  $6,007,000
                                  $8,622,000
                           Closed Cycle (difficult)
                                 $123,300,000
                                  $13,440,000
                                   $380,000
                                   $281,000
                                   $951,000
                                  $1,003,000
                                  $8,895,000
                                  $11,510,000
1 These costs are adjusted using the capacity utilization rate.

In order to allow comparison of long-term costs, capital and downtime costs are amortized over the estimated service life of the technology.  As can be seen, EPA's estimated total annualized compliance costs for closed-cycle cooling are more than an order of magnitude higher than the costs of upgraded traveling screens when only the direct technology costs are considered. 

It is important to note that the closed-cycle costs represent a somewhat conservative (high-end) cost estimate. The closed-cycle costs for pump/fan energy penalty assume the fans will operate year-round, even though they are often turned off during winter operation. The closed-cycle variable O&M costs assume treatment chemicals will be needed for optimized operation.  Thus, the closed-cycle costs are representative of a well-operated system where operational problems that could result in equipment failure and poor tower or condenser performance will be minimized. It is also assumed that the cost estimates include costs for towers that are designed and operated in a manner to prevent damage such as may occur due to ice formation in the winter or fouling due to solids and microbial growth build-up on the media.

The closed-cycle costs include the annual average turbine efficiency loss, which takes into consideration losses during periods when high wet bulb temperatures may reduce the turbine efficiency due to higher cold water temperatures compared to what would be available in a once-through system as well as any de-rate that may occur due to periods when the turbine back-pressure exceeds the maximum pressure allowed to prevent damage to the turbines.

The different capital costs are related to degree of difficulty encountered in retrofitting the technology.  As described later in this analysis, the closed-cycle cooling system capital costs reported by two facilities visited by EPA in the region appear to fall close to the "easy" end of the range of estimated costs.

The traveling screen upgrade costs in Table 1 are based on a typical system that is not experiencing any substantial problems such as episodes of high quantities of debris, silt, and sand in the source water, low source water levels, low source water flow, or high source water temperatures.  Such problems can result in higher maintenance costs for the screens and other equipment, greater system downtime (lost generation costs), and reduced capacity during peak demand. The costs in Table 1 do not include consideration of site-specific costs that may be encountered at facilities where the characteristics of the source water and intake location may present additional operational difficulties that have economic consequences.

The following sections provide an examination of some of the problems associated with traveling screen operation in certain environments. Some examples from visited facilities are presented, along with estimates of the economic impact when compared to an alternative closed-cycle cooling system.  While closed-cycle cooling will still require the use of intake technologies such as traveling screens for makeup water, the substantial reduction in intake flow volume should minimize or eliminate the problems described and the associated economic impact.
  
Debris, Silt, and Sand

Rivers with high levels of debris, silt, or sand can cause recurring problems for once-through systems that utilize traveling screens. Episodes of high concentrations of debris such as leaves and aquatic vegetation can rapidly blind traveling screens, resulting in an emergency shutdown of generating units or, under the worst-case situation, the collapse of the screen.   Silt and sand can also be abrasive on moving parts such as traveling screens and pump impellers, requiring more frequent rebuild and replacement.  Debris and silt can also coat and clog condenser tubing, resulting in reduced condenser performance and reduced generator output.

Meramec Power Station

The Meramec Power Station is a four-unit coal-fired power plant with a combined capacity of 835 MW and an average capacity utilization of 76%. The intake consists of eight dual-flow traveling screens with a single pump behind each screen (two for each generating unit).  The intake is located on the Mississippi River 20 miles south of St Louis, Missouri.  Meramec has had significant problems with debris in the past (especially with spring and fall leaf loads), including five unit shutdowns from 2000 to 2009.   Facility representatives noted that a major debris event typically leads to 4-5 screen panels being damaged.  
 
Nebraska City

Nebraska City is a single-unit 650-MW coal-fired power plant located on the Missouri River about 8 miles southeast of Nebraska City, Nebraska.  The intake consists of six conventional 3/8-in mesh traveling screens and three pumps with a capacity of 223 MGD each.  Two pumps are normally operated and, due to sedimentation problems in the intake bays, the screens are rotated continuously.  Wear on the traveling screens due to silt and sand has resulted in repeated screen rebuild and maintenance that totaled $2,481,282 over a 10-year period. Every six months, the traveling screens become silted in and sediment must be pumped out.   The costs of the screen rebuilds alone equal about $250,000 per year, or roughly 80% of the total EPA O&M cost for a similar number of screens as shown in Table 1. 

Fort Calhoun

Fort Calhoun is a single-unit 492-MW nuclear power plant about 5 miles northwest of the town of Fort Calhoun in eastern Nebraska on the Missouri River. The intake consists of six conventional 3/8-in mesh traveling screens and three pumps with a capacity of 173 MGD each.  The facility has had problems with gravel in the intake and as a result, during each refueling shutdown (occurring every 18 months), they have rebuilt each screen at a cost of $80,000 per screen and cleaned the condenser at a cost of $250,000. This is equivalent to an annual screen overhaul costs of $320,000 per year for six screens, which is 102% of the total EPA O&M cost for a similar number of screens as shown in Table 1.

Cooper Nuclear

The 836-MW Cooper Nuclear facility reported that in 2002 debris plugging problems in the condensers resulted in the need to perform 45 backwash cycles (nearly one per week) with a brief shutdown each time, resulting in an annual loss of 3,220 MWhs. This is roughly equivalent to about 0.2 days of lost generation per year.  Even with the backwashes, some of the debris remains until removed during the next scheduled maintenance shutdown. 

Increased Screen Maintenance Summary

The screen rebuild frequency for Nebraska City is about once every two years.  Three other plants located on the Missouri River -- the Hawthorne, Iatan, and Lake Road power plants -- also reported that traveling screens were rebuilt once every two years during scheduled maintenance downtime. The EPA O&M cost estimates for the proposed rule include routine operator labor, maintenance, and power requirements, in addition to screen rebuild costs.  By comparison, for the two plants that reported cost data, the screen rebuild costs alone were equivalent to 80% to 100% of the total EPA-estimated costs shown in Table 1.  This indicates that, for plants located on water bodies with high levels of debris, silt, and sand like the Missouri River, the actual O&M costs will likely be higher those estimated by EPA. 

A review of the EPA cost module component O&M costs for a 10-ft wide and 50-ft deep traveling screen shows that the split is roughly one-third each for labor, power, and materials.  It is reasonable to assume that a portion of the labor and materials costs in the EPA estimate includes the replacement of traveling screen parts, such as occurs in the Nebraska City and Fort Calhoun screen rebuilds.  If one assumes that roughly half of both of these costs are routine and the other half are rebuild-related, then the facility rebuild-related costs exceed the EPA-estimated rebuild component by 69% for Fort Calhoun and 49% for Nebraska City.  Thus, a reasonable estimate is to assume an increase of approximately 50% in total O&M for traveling screens at facilities with water body characteristics that result in excessive wear and tear on the screens.

Pumps

While no specific pump maintenance cost data were cited, the presence of sand in an intake can result in increased wear on pump impellers, resulting in reduced service life. Cavitation and air entrainment that result from operation at low water levels can also damage pump bearings and impellers.  However, such conditions are typically avoided by reducing the pump flow rate.  To examine the magnitude of the cost implications of such wear and tear on the pumps, it is assumed that the service life of the pump impeller is cut in half from 15 years to 7.5 years.  A project that involves upgrading a power plant's circulating water pumps with new impellers, diffusers, shrouds, and shafts results in a cost of $1,100,000 for a combined pump flow of 236,000 gpm (Flory 2005).  Using this data, the inflation-adjusted unit cost would be $5.6/gpm.   The equivalent $1,680,000 pump upgrade cost for a 300,000-gpm system amortized over 15 years and 7.5 years at 5% is $162,000 and $274,000, respectively. The difference of $112,000 represents the estimated increase in pump maintenance cost that results from reducing a pump impeller service life by half.

Condenser Performance

Condenser performance can suffer as the result of several problems. The water side of tube walls can become coated with sediment, scale or biological growth, reducing the heat transfer rate.  Individual tubes can develop leaks due to corrosion or erosion, requiring them to be plugged as an interim measure prior to tube replacement.  Debris too large to pass through the typical 7/8-in diameter can plug condenser tubes, reducing or eliminating flow through individual tubes.  

Traveling screens can contribute to this latter problem by allowing carryover of large debris to the back side, where the reverse-direction flow dislodges the debris which then plugs condenser tubes, resulting in reduced condenser performance and reduced turbine efficiency. Since the screen wash water is often withdrawn from the clean side, this debris may also plug screen wash water nozzles, increasing the potential for debris carryover in a spiraling cycle. The plugging of condenser tubes may require more frequent unit shutdowns to clean the condenser.  Downtime for cleaning may take from 3 to 5 days, depending on the amount of tube cleaning required and the amount of scale present (Spielmann 2002).  

While retrofit of the traveling screens with dual-flow or multi-disc screens may resolve this problem, there are often other problems associated with the existing intake design, such as concerns about changes in the distribution, direction and velocity of inlet and outlet flows that may make such retrofits difficult or require costly structural modifications.  Use of closed-cycle cooling would greatly reduce or eliminate the possibility of debris carryover because of the greatly reduced intake flow and the fact that the reduced flow volume may increase the opportunity to replace the existing traveling screens with screen designs that minimize carryover.

Condenser Ball Cleaning System

A condenser ball cleaning system is a technology where small foam balls that are slightly larger in diameter than the condenser tubes are continuously introduced upstream of the steam condenser tubes and then randomly pass through the tubes, scrubbing out any sediment/solid deposits and biological growth. The balls are then collected on a screen downstream and recirculated back through the system. These systems can maintain the condenser heat transfer efficiency close to the design clean levels. Such systems can increase generator output by 1% to 2% compared to uncleaned systems, and will often pay for themselves in a short period of time. Additional benefits include reduced condenser cleaning costs and increased service life of condenser tubes through reduction of microbe-induced corrosion. 

The initial capital costs and downtimes associated with installation of such systems often serves as an impediment to their installation, since installation requires replacing a portion of the condenser inlet and outlet piping with the ball release and collection equipment.  The retrofit of an existing once-through cooling system with a closed-cycle system presents an opportunity to save on installation and downtime costs, since piping is being replaced or modified already and the ball cleaning system can be installed during the retrofit downtime. As shown in Table 1, retrofit downtime costs can be substantial.  For the purpose of estimating savings associated with this technology, the value of the annual increase in power production is assumed to be equivalent to an average turbine efficiency increase of 1%. The actual increase is expected to be somewhat higher in most instances, and the difference is assumed to cover the cost of system O&M and the amortized capital costs.

Lost Generation Due to Inadequate River Flow or Lower River Levels

Seasonal variations, drought conditions, and/or changes to the water body can result in conditions where facilities may be forced to reduce power generation rates below full capacity (aka derate). This can require the utility to purchase power from another source at a cost that is much higher than the cost to generate power at the plant.  Closed-cycle cooling, which requires a much smaller intake volume, is an available alternative that can allow a facility to operate at full capacity regardless of river flow conditions. While there may be an energy penalty of up to several percent in output when compared to once-through operation under favorable river conditions, this reduction may be much smaller in magnitude compared to the size of the derate necessary to meet the restrictive conditions.

The inability of the cooling system to operate at full capacity generally results from situations where water body conditions limit pump operation or limit the ability of the water body to accommodate the full generating capacity or process cooling heat load.  In some cases, this is the result of the river surface elevation dropping below the level necessary to maintain the submergence depth required to prevent severe pump damage from cavitation and air entrainment. When this happens, the only immediate solution available is to reduce the circulating pump flow. The result is a reduction in the required pump submergence depth if the pump speed is reduced and/or an increase in water depth due to a reduction in the head loss across the screens. Low water conditions are often the result of drought and seasonal variations, but can also be exacerbated by changes in the normal surface level of the water body.  For example, the surface level of the lower Missouri River is dropping in several locations due to erosion of the river bed.
  
In many cases, physical characteristics of the water body (e.g., high temperatures and/or low flow) create conditions where 316(a) NPDES limitations for heat load and temperature increase would be exceeded unless the generating rate is reduced. One common solution employed in the past involves constructing cooling towers that operate in a helper mode. 

This lost generation due to limitations in the availability of cooling or the water body's ability to assimilate heat can result in substantial costs to the utility. Such costs include purchasing or generating replacement power at a much higher cost.  Also, since these problems often coincide with periods of peak power demand, replacement power costs will tend to be high and the unreliability will lead to the need for construction of additional generating units to increase peaking power capacity.

Nearman Creek

The Nearman Creek Power Station is a 235-MW single-unit coal-fired power plant in Wyandotte County in Kansas City, Kansas along the Missouri River. The plant's average capacity utilization rate is about 50%. The intake consists of four standard 3/8-in traveling screens serving two pumps with a total design intake flow of 230 MGD.  A minimum of one pump (108 MGD) is required to operate at full capacity during the winter (Domkowski and Arbesman, 2001).  

The plant has been experiencing problems associated with the reduction in river surface elevation due to the progressive degradation of the river bed. River flows tend to be lowest during the winter months and drought conditions during the summer of 2000 caused the river level to drop so low in December that the plant had to completely shut down. The situation was created as a result of an ice dam upstream and the clogging of the intake with ice.  The problem was temporarily solved by fixing barges just upstream to divert ice, which allowed for 25% capacity operation. But the river level was still 3 ft below the level needed to prevent cavitation of the pumps at full flow.  Next, the intake entrance was temporarily blocked by welding steel plates onto the bar racks such that the top was 3 ft above the required depth. Low head pumps capable of pumping the minimum flow needed for full capacity operation were rented and installed in front of the intake so that the discharge flowed directly onto the top of the water in the screen wells.  The pumps were subsequently purchased and, more recently, upgraded pump designs with additional capacity (144 MGD) were installed.  

To help resolve this problem, Nearman Creek installed a closed-cycle cooling system in 2006 that uses city water as a source of makeup water.  The closed-cycle cooling tower capital cost was $22,000,000 and included reinforcement of the existing condenser to support the higher pressure associated with CCRS operation.  

The normal production costs at Nearman Creek were about $11/MWh, but in December 2000 the utility was forced to purchase replacement power at rates of $50 to $130/MWh (Domkowski and Arbesman, 2001). During the emergency shutdown in December 2000, the average cost of purchased power was over $250,000 per day and the total cost of purchased power for the duration of the emergency was $2,500,000.  Dividing this per-day cost by the plant capacity results in an equivalent cost of $1,064/MW/day.  Attachment A presents river bottom and water elevation data, as well as photos and cost data for the emergency pumps used at Nearman Creek and at the nearby Quindaro Plant which experienced similar problems. The Quindaro plant has installed emergency pumps as well, but has no current plans to install closed-cycle cooling. 

Nearman operates the CCRS for only part of the year (from the spring to the fall), when cooling water requirements and river temperatures are the highest. The plant still operates in a once-through mode during the winter months and has purchased an emergency pump system at a cost of $1,200,000 to allow continued operation at full capacity when needed during low water-level conditions.

Lost Generation 

While various problems associated with the use of traveling screens can result in substantial increases in equipment maintenance or purchase costs, the greatest costs tend to be the result of lost generation. Lost generation can result from:

   * Reduction in turbine efficiency due to increase in steam condensing temperature as a result of reduced cooling water flow or condenser performance
   * Forced derate (reduction in power output) due to 316(a) limitations in receiving water
   * Generating unit shutdown due to limitations or failure of cooling water supply or equipment
   * Generating unit shutdown due to need to perform maintenance.
 
A maintenance shutdown is often performed in order to improve system performance; the decision to shut down will often involve weighing the tradeoff of short-term lost generation due to the shutdown versus long-term lost generation due to decreased system performance.  Costs are minimized if maintenance can be deferred until the next scheduled shutdown for routine maintenance.  However, if performance is reduced significantly, then a shutdown for maintenance may be the most economical solution.  If a plant's output is reduced by an average of 10% for two months, this is equivalent to losing 100% capacity for 6 days. 

The simplest way to express lost generation is in MWh per year or equivalent days of generation (at full capacity) per year.  Reduction in turbine efficiency is often expressed in percent reduction in generator output.  For a base-load plant, a 1% reduction in turbine efficiency is roughly equivalent to about 3 days of lost generation per year.

The Sioux City Power Plant reported in 2009 that, over the last 5 years, the facility had lost an average of one generating day per year to debris or icing.
 
Traveling Screen Replacement Capital Costs

Two plants reported that they recently replaced their traveling screens. The Labadie Power Plant replaced 8 screens at a cost of $2,800,000. The equivalent cost for 6 screens, which should be similar in size and scope to the example in Table 1, is $2,100,000.  The new screens at Labadie do not include fish buckets or a separate fish return trough, but are amenable to the addition of these features in the future. The higher cost in Table 1 may reflect such differences. These data indicate that the EPA cost estimates for Module 1 (upgrade to Ristroph traveling screens with fish return) are accurate for this facility.

Closed-Cycle Cooling Retrofit Capital Costs

Nearman Creek installed a closed-cycle cooling system in 2006 that allowed the cooling system to operate in both once-through and closed-cycle mode.  The cost cited was $22,000,000. This is comparable to the EPA estimate for an "easy" closed-cycle retrofit, which is $24,000,000 in 2006 dollars.  

Nebraska City is in the process of constructing a second new 650-MW coal-fired generating unit that will use an 18-cell back-to-back closed-cycle mechanical-draft cooling system. The capital costs are estimated to be $40,000,000 to $60,000,000 for the cooling system. The equivalent scaled-down costs for a 500-MW generation unit would be $31,000,000 to $46,000,000.  If additional costs associated with retrofitting an existing generating unit are factored in as well, these costs appear to fall closer to the "easy" retrofit range of the EPA capital cost estimates for a 500-MW plant shown in Table 1.

Summary of Costs 

Using the example 500-MW facility as the basis for comparison, Table 2 presents the estimated annualized technology costs from Table 1 and estimates of potential annual costs of some of the problems described above.  As can be seen, just one day of lost generation is equivalent to the estimated increase in costs associated with all of the traveling screen-related problems described here.  Thus, only in situations where the use of once-through cooling results in multiple days of lost generation does the difference in costs between closed-cycle and once-through cooling begin to converge. The break-even point is when the total once-through lost generation approaches 8 or 9 days when compared to the "easy" closed-cycle retrofit.  If the cooling towers are operated for only half of the year (as at Nearman Creek), then the reduction in tower variable O&M, pump and fan energy, and turbine penalty may reduce this time threshold by about 2 days (to 6 or 7 days).  The cost of generating equipment to replace lost power-generating capacity during peak demand periods is not included in this analysis, and may result in an even lower threshold.  

                                    Table 2
  Summary of Estimated Annualized Costs Associated with Once-through Cooling 
                                       
                      Total Annualized Costs From Table 1
                      Frequent Traveling Screen Rebuilds
                              Condenser Cleaning
                          Reduced Pump Impeller Life
                           One Day Lost Generation 
                            Condenser Ball Cleaning
                      Total with One Day Lost Generation
Modified Ristroph TS
                                   $495,000
                                   $156,500
                                                                      $250,000 
                                                                       $112,000
                                                                       $532,000
                                      N/A
                                                                     $1,545,500
Closed Cycle (easy)
                                  $6,787,000
                                      N/A
                                      N/A
                                      N/A
                                      N/A
                                                                    -$1,643,000
                                                                     $5,144,000
Closed Cycle (average)
                                  $8,622,000
                                      N/A
                                      N/A
                                      N/A
                                      N/A
                                                                    -$1,643,000
                                                                     $6,979,000
Closed Cycle (difficult)
                                  $11,510,000
                                      N/A
                                      N/A
                                      N/A
                                      N/A
                                                                    -$1,643,000
                                                                     $9,867,000

Cost for Selected Scenarios

As can be seen in Table 2, a cost comparison for even a theoretical plant will vary depending on the mix and degree of the associated problems.  The total values shown in the far-right-hand column present a sum of all values shown, but do not represent a specific scenario.  Table 3 presents the annualized estimated totals for the easy closed-cycle cooling and once-through conditions for the following scenarios:

   1. Water quality is poor with high sand and silt resulting in more frequent screen and pump maintenance, but little to no lost generation as a result (i.e., maintenance can be scheduled to minimize downtime)
   2. High sand, silt, and debris result in more frequent screen and pump maintenance, and an unscheduled 3-day condenser cleaning
   3. Water quality does not present a problem but low water levels and/or high temperatures result in an average derate of 10% for two months, resulting in an equivalent of six days lost generation
   4. Water quality does not present a problem but low water levels and/or high temperatures result in an average derate of 15% for two months, resulting in an equivalent of nine days lost generation. 

                                    Table 3
               Estimated Annualized Costs for Selected Scenarios
 
                                   Baseline
                                  Scenario 1
                                  Scenario 2
                                  Scenario 3
                                  Scenario 4

                      Typical Intake with no added costs
          Frequent screen/pump maintenance due to high sand and silt 
Frequent screen/pump maintenance & unscheduled 3- day condenser cleaning due to high sand, silt, and debris 
6 days/yr lost generation from average derate of 10% for 2 months due to low water/high temperature
9 days/yr lost generation from average derate of 15% for 2 months due to low water/high temperature
Once- through with Modified Ristroph TS
                                   $495,000
                                   $763,500
                                  $2,609,500
                                  $3,687,000
                                  $5,283,000
Easy Closed Cycle with Ball Cleaning
                                  $5,144,000
                                  $5,144,000
                                  $5,144,000
                                  $5,144,000
                                  $5,144,000
Easy Closed Cycle without Ball Cleaning
                                  $6,787,000
                                  $6,787,000
                                  $6,787,000
                                  $6,787,000
                                  $6,787,000
                                       
                                       
The comparable closed-cycle costs are shown with and without condenser ball cleaning savings, since this option may not be available or necessary in some instances. 

These estimates suggest that facilities with once-through cooling systems that encounter chronic problems involving a significant derate over a period of time or frequent and/or extended downtimes (especially during periods of peak power demand) may consider cooling towers as an economically viable solution.

References

Cassidy, Patrick J. Kansas City Board of Public Utilities. Missouri River Degradation At KCBPU. Presentation to MARC River Degradation Meeting North Kansas City, Missouri March 14, 2007.

Domkowski, Bob and Arbesman, Gary  -  Flygt US.  Winter Power Plant Outage Ended Thanks to Innovative Engineering Solution with Large Flygt Pumps. 2001.

EPA. Site Visit Report. Fort Calhoun Station. 2009a.

EPA. Site Visit Report. Nebraska City Power Plant. 2009b.

EPA. Site Visit Report. Sioux City Power Plant. 2009d.

EPA. Site Visit Report. Cooper Nuclear Power Plant. 2009e.

EPA. Site Visit Report. Nearman Creek Power Plant. 2009f.

EPA. Site Visit Report. Iatan  Power Plant. 2009g.

EPA. Site Visit Report. Meramec Power Plant. 2009h.

EPA. Site Visit Report. Power Plant. 2009i.

EPA. Site Visit Report. Quindaro Power Plant. 2009j.

EPA. Site Visit Report. Hawthorne Power Plant. 2009k.

EPA. Site Visit Report. Lake Road Power Plant. 2009l.

EPA. Site Visit Report. Labadie Power Plant. 2009m.

EPA. Site Visit Report. Sioux Power Plant. 2009n.

Flory, Alan. Austin Energy: Pumping System Improvement Project Saves Energy and Improves Performance at a Power Plant. June 2005. http://www1.eere.energy.gov/industry/bestpractices/pdfs/austinenergy.pdf

Shipilev, S.G. and Kataev, M.P. Improvement of Equipment for the Ball Cleaning of Steam Turbine Condensers. Thermal Engineering. Vol. 54 No 4. 2007.

Spielmann, Steve. Big Shot System Speeds Tube Cleaning. Power Engineering Magazine. 2002.
http://www.goodway.com/power_generation/bigshot_system_speeds.aspx
http://www.tubetech.com/case-studies/power-case-studies/dartt-removes-tenacious-mussels-from-condenser