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 (SAI C) and Kelly Meadows DATE: September 30, 2010 SUBJECT: Costs of Traveling Screen Versus

Rivers in the Midwest During visits to power plants located on the Missouri and Mississippi rivers, EPA observed that number of facilities were experiencing substantial equipment and operating problems due to hig quantities of debris, silt, sand and other river conditions. All of the plants utilized once cooling with traveling screens. 1 costs that would continue to occur the cooling s ys tem remained once provided for comparison to see if the sy stem approach those of a clo sed high debris loads or other issues, the additional costs of upgrading to closed unlikely to be offset unless the facility suffers from unscheduled outages or is forced to an extended period. However, a facility that does encounter such problems may quickl y realize the benefits of converting to closed specificall y cited, the plant data provided here are tak 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 close sy stem 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 s ys tem retrofit for a typical screens. These cost estimates are based on the EPA estimates for compliance costs for Module 1

1 One used dual
- flow screens and the rest used conventional flow 

### MEMORANDUM

Paul Shriner, EPA John Sunda (SAI C) and Kelly Meadows September 30, 2010 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

facilities were experiencing substantial equipment and operating problems due to hig quantities of debris, silt, sand and other river conditions. All of the plants utilized once This analy sis 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 s ys tem remained once
- through. Estimated costs for a closed
- cy cle retrofit are provided for comparison to see if the increased maintenance costs for the existing sed
- cycle retrofit. The anal ys is 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 an extended period. However, a facility that does encounter such problems may quickl y realize the benefits of converting to closed
- cycle, as lost generation costs are substantial. U specificall y cited, the plant data provided here are tak en from the Site Visit Reports listed in the
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 close sy stem 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 cycle cooling s ys tem 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

flow screens and the rest used conventional flow
- through screens. Cycle Cooling at Power Plants on During visits to power plants located on the Missouri and Mississippi rivers, EPA observed that a

facilities were experiencing substantial equipment and operating problems due to hig h quantities of debris, silt, sand and other river conditions. All of the plants utilized once
- through This analy sis examines some of the problems and associated

he traveling screens were upgraded and

cy cle retrofit are increased maintenance costs for the existing once - through

The anal ys is suggests that for facilities with 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 quickl y realize cycle, as lost generation costs are substantial. U nless

en from the Site Visit Reports listed in the
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 close d
- cycle cooling sy stem 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 fired power plant with traveling screens. These cost estimates are based on the EPA estimates for compliance costs for Module 1- 2 -

(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 y ears, respectivel y  Cost o f 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 Cy cle 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 A mortized

Capital and Downtime Costs Total

An nualized 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 onl y 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 ye ar - round, even though they are often turned off during winter operation. The closed
- cycle- 3 -

variable O&M costs assume treatment chemicals will be needed for optimized operation. Thus, the closed
- cyc le costs are representative of a well
- operated s ys tem 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 s ys tem 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 anal ys is, the closed
- cycle cooling s ystem capital costs reported b y two facilities visited by EPA in the region appear to fall close to the “eas y” end of the range of estimated costs. The traveling screen upgrade costs in Table 1 are based on a typical s y stem that is not experiencing an y 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 s ys tem 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 oper ation 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 s ys tem. 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, s ilt, or sand can cause recurring problems for once
- through sy stems 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 ge nerating 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.- 4 -

Mer ame c 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 utili zation 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 L ouis, 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 . Facilit y representatives noted that a major debris event t ypicall y 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 bay s, 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
- ye ar 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 roughl y 80% of the total EPA O&M cost for a similar numb er 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 s creen 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 f acility reported that in 2002 debris plugging problems in the condensers resulted in the need to perform 45 backwash cycles (nearl y one per week) with a brief shutdown each time, resulting in an annual loss of 3,220 MWhs. This i s roughl y equivalent to about 0.2 day s of lost generation per y ear. Even with the backwashes, some of the debris remains until removed during the next scheduled maintenance shutdown. In creased Screen Maintenance Summary The screen rebui ld frequency for Nebraska City

i s about once every

two y ears. Three other plants located on the Missouri River

—the Hawthorne, Iat an, and Lake Road power plants

— also reported that traveling screens were rebuilt once every two y ears during scheduled maintenance- 5 -

downtime. T he 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, f

or the two plants that reported cost data, the screen rebuild costs alone were equiva lent 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 b y 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 materi als 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 assume s that roughly half of both of these costs are routine and the other half are rebuild
- related, then the facilit y rebuild
- related costs exceed the EPA
- estimated rebuild component b y 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 faci lities 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 re duced service life. Cavitation and air entrainment that result from operation at low water levels can also damage pump bearin gs and impellers . However, such conditions are t ypicall y avoided b y 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 y ears. A project that involves upgrading a power plant’s circulating water pumps with new impellers, diffuse rs, shrouds, and shafts result s 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 sy stem amort ized over 15 ye ars and 7.5 y ears at 5% is $162,000 and $274,000, respectivel y. The difference of $112,000 represents the estimated increase in pump maintenance cost that results from reducing a pump impeller service life b y half. Condenser Performance Co ndenser 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, re quiring 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 t o 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 scree n 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- 6 -

condenser tubes may

require more frequent unit shutdowns to clean the condenser. Downtime for cleaning may

take from 3 to 5 day s, 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 costl y structur al modifications. Use of closed
- cycle cooling would greatl y reduce or eliminate the possibility of debris carryover because of the greatl y 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 Sy stem A condenser ball cleaning s ys tem 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 sy stem. These s ys tems can maintain the condenser heat transfer efficiency close to the design clean levels. Such sy stems can increase generator output by 1% to 2% compared to uncleaned sy stems, and will often pay for themselves in a short period of time. Additional benefits inclu de 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 sy stems 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 s ys tem with a closed
- cycle sy stem presents an opportuni ty to save on installation and downtime costs, since piping is being replaced or modified alread y and the ball cleaning s ys tem 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 sy stem 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 co nditions 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. Close d
- 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 whe n compared to once
- through operation under favorable river- 7 -

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 s ys tem to operate at full capacit y generall y results from situations where water body conditions limit pump operation or limit the ability of the water bod y to accommodate the full generating capacit y or process cooling heat lo ad. 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 sol ution available is to reduce the circulating pump flow. 2 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 condi tions are often the result of drought and seasonal variations, but can also be exacerbated b y 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 man y cases, phy sical 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 i s reduced. One common solution employed in the past involves constructing cooling towers that operate in a helper mode. This l ost generation due to limitations in the availability of cooling or the water body ’s abilit y to assimilate heat can result in su bstantial 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 unreliab ility

will lead to the need for construction of additional generating units to increase peaking power capacit y. 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 capacit y 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 oper ate 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 d uring 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 inta ke with ice. The problem was temporaril y 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 i ntake entrance was temporarily blocked by welding steel plates onto the bar racks such that the top was 3 ft above the required depth. L ow head pumps
2 This can be done by shutting off pumps, throttling pump output, or reducing pump speed if pumps are equipped for multiple or variable speed operation.- 8 -

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 capacit y (144 MGD) were installed. To help resolve this p roblem, Nearman Creek installed a closed
- cycle cooling s ys tem 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 em ergency 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 b y the plant capacity results in an equival ent 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 nearb y Quindaro Plant which experienced similar problems. The Quindaro plant h as installed emergency

pumps as well, but has no current plans to install closed
- cycle cooling. Nearman operates the CCRS for only part of the y ear (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 sy stem at a cost of $1,200,000 to allow continued operation at full capacity when needed during low water
- level conditions. 3 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 turbin e 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 limitatio ns or failure of cooling water supply or equipment  Generating unit shutdown due to need to perform maintenance.

3 Note that even if the existing traveling screens are upgraded, operation of the emergency pumps will likely not be compliant with the IM reduction requirements based on modified Ristroph screens in the proposed rule, since fish must first pass through the emer gency pumps before encountering the traveling screens. The emergency pump inlets, which appear to include bar screens only, would be difficult to retrofit with a compliant screening system. The best option to resolve this problem would be year
- round oper ation of the cooling tower. If that option were not available, such as is the current situation at the Quindaro Plant, then the intake would need to be rebuilt with deeper pum p wells and modified Ristroph screens or equivalent. Each of these alternatives w ould involve considerably mo re cost than a simple replacement and upgrade of the existing traveling screens.- 9 -

A maintenance shutdown is often performed in order to improve s ys tem 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 s ys tem performance. Costs are minimized if maintenance can be deferred until the next scheduled shutdown for routine maintenance. However, if performance is reduced significantl y, 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 y ear or equivalent day s of generation (at full capacity) per y ear. Reduction in tur bine efficiency

is often expressed in percent reduction in generator output. For a base
- load plant, a 1% reduction in turbine efficiency is roughl y equivalent to about 3 days of lost generation per year. The Sioux City

Power Plant reported in 2009 that, over the last 5 ye ars , the facility ha d lost an average of one generating day per y ear to debris or icing. Traveling Screen Replacement Capital Costs Two plants reported that they recently replaced their traveling screens. The L abadie Power Plant replac ed 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 a menable 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 fa cility
. Closed - Cycle Cooling Retrofit Capital Costs Nearman Creek installed a closed
- cycle cooling s ystem in 2006 that allowed the cooling s ys tem to operate in both once
- through and closed
- cycle mode. The cost cited was $22,000,000. This is comparable t o the EPA estimate for an “eas y” 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
- dr aft cooling sy stem. The capital costs are estimated to be $40,000,000 to $60,000,000 for the cooling s ys tem. 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 retrofittin g an existing generating unit are factored in as well, these costs appear to fall closer to the “eas y” retrofit range of the EPA capital cost estimates for a 500 - MW plant shown in Table 1. Summary of Cost s 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 ge neration is equivalent to the- 10 -

estimated increase in costs associated with all of the traveling screen
- related problems described here. Thus, onl y in situations where the use of once
- through cooling results in multiple day s of lost generation does the diff erence 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 day s when compared to the “eas y” closed
- cycle retrofit. If the cooling towers are operat ed for only half of the y ear ( as at Nearman Creek) , then the reduction in tower variable O&M, pump and fan energy , and turbine penalt y ma y reduce this time threshold by about 2 day s (to 6 or 7 day s). The cost of generating equipment to replace lost power
- generating capacit y during peak demand periods is not included in this analy sis, and may result in an even lower threshold. Table 2 Summary of Estimated Annualized Costs Associated with Once - through Cooling

Total An nualized 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 Scenario s 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 mainte nance, 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 no t 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 day s lost generation 4. Water quality

does not present a problem but low water levels and/or high temperatur es result in an average derate of 15% for two months, resulting in an equivalent of nine day s lost generation.- 11 - Table 3 Estimated Annualized Costs for Selected Scenarios Baseline Scenario 1 Scenario 2 Scenario 3 Scenario 4
Ty pical 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 /y r lost

generation from average derate of 10% for 2 months due to lo w water/high temperature 9 days /y r lost

generation from average derate o f 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 s ys tems that encounter chronic problems involving a significant derate over a period of time or frequent and/or extended downtimes (especiall y during periods of peak power demand) may consider cooling towers as an economicall y 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

– Fl ygt US. Winter Power Plant Outage Ended Thanks to Innovative Engineering Solution with L arge 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. C ooper Nuclear Power Plant. 2009e. EPA. Site Visit Report. Nearman Creek Power Plant. 2009f. EPA. Site Visit Report. I atan Power Plant. 2009g.- 12 -

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 S ys tem 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 Sy ste m Speeds Tube Cleaning . Power Engineering Magazine. 2002 . http://www.goodway .com/power_generation/bigshot_sy stem_speeds.aspx http://www.tubetech.com/case
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