Tetra Tech, Inc.

10306 Eaton Place, Suite 340 Fairfax, VA 22030 phone 703 - 385 - 6000 fax 703 - 385 - 6007 TO : Paul Shriner and Jan Matuszko, EPA FROM : John Sunda (SAI C) and DATE: September 9, 2009 SUBJECT: Cooling Tower EPA request ed that Tetra Tech developing the 316(b) cooling tower compliance penalty of retrofit cooling towers. Task: C larify certain energy penalt y facilities would be higher than condenser replacement , where California once

- through cooling p Background The term “energy

penalty” can be used in various contexts. th e loss in energy

production facilities. Sometimes energy penalt y also includes and pumping
. For the purposes of estimating compliance costs, both interpretations are included. Energy penalty may also be expressed average energy

penalty data is useful in determining overall annual costs maximum energy

penalty is use of peak demand during the warmer mon estimate annual cost w ould significantl y overestimate the costs and using the average energy penalty to estimate the impacts on regional capacity w impact. 

### MEMORANDUM

10306 Eaton Place, Suite 340

Paul Shriner and Jan Matuszko, EPA John Sunda (SAI C) and Kelly Meadows September 9, 2009 Cooling Tower Energy

Penalties Tetra Tech and SAIC document design assumptions used in cooling tower compliance costs. Th is memo clarif ies penalty of retrofit cooling towers.

energy penalt y ass umptions, such as whether penalties at higher than at coal facilities and whether EPA’s costs include , where necessary . Review the assumptions used in the through cooling p olicy and compare them to EPA’s assumptions

can be used in various contexts. Sometimes it refers e loss in energy

production associated with lower turbine efficiency for retrofit facilities. Sometimes energy penalt y also includes parasitic power consumption for fans For the purposes of estimating compliance costs, both interpretations are Energy penalty may also be expressed as the annual average or a maximum. T average energy

penalty data is useful in determining overall annual costs , while maximum energy

penalty is use d to estimat e impact s on generating capacity of peak demand during the warmer mon ths. Using the maximum energy penalty to significantl y overestimate the costs and using the average energy penalty to estimate the impacts on regional capacity w ould underestimate the

1 and SAIC document design assumptions used in the energy penalties at nuclear facilities and whether EPA’s costs include Review the assumptions used in the DOE and assumptions
.
refers onl y to turbine efficiency

for retrofit parasitic power consumption for fans For the purposes of estimating compliance costs, both interpretations are
maximum. T he annual , while the on generating capacity for periods ths. Using the maximum energy penalty to significantl y overestimate the costs and using the average underestimate the2

E stimates of the energy

penalty are generally based on the methodology used in the EPRI cooling tower worksheet. This involves estimating the energy penalt y as two separate components: one for parasitic power consumption for fans and pumping expressed in MW ; and one for turbine efficienc y loss. A site

- specific parasitic loss is calculated for each facility

based on its flow; the national average is approximately 1.7 percent. Turbine effici ency varies by fuel ty pe; nuclear plants operate at a higher pressure and would experience a higher loss of efficiency . The overall balance between fossil and nuclear (2.0) is consistent with the value used in EPRI ’s cooling tower cost estimation tool. Table 1 presents a comparison of the EPA’s estimated energy penalt y for replacing once

through coolin g with closed

- cycle recirculating wet cooling towers along with values reported in other sources. Table 1 . Summary of Energy Penalty Data

Source Maximum

Total Energy Penalty (%) Annual Average Penalty

Net Pump and Fan (%) Turbine

Efficiency (%) Total

(%)
EPA/EPRI

– Fossil NA 1.7 1 1.5 3.2 EPA/EPRI

– Nuclear NA 1.7 1 2.5 4.2 200 2 Phase II proposed rule 1.4

– 2.0 NA NA 1.5

– 1.8 DOE Phase II 2 2.4

– 4.0 NA NA 0.8

– 1.5 DOE Nuclear 3 Up to 5.8 NA NA 2
- 3 California

– Gas 4 NA 1.0

– 2.0 0.8

– 1.3 2.0

– 3.2 California

– Nuclear4 NA 1.4

– 2.6 2.9

– 3.6 5.0
- 5.5

1 Fan and pumping energy i s based on cooling water flow
. The value of 1.7% shown in Table 1 for net fan and pump energy is a calculated average based on the average of the reported DIF flow divided by the steam capacity (707 gpm/MW). Estimated individual model facility

- specific percent values will vary above and below

this value. 2 Source (DOE 2002). Adopted by EPA in Final Phase II Rule. Developed for coal

- fired plants. Data is for condenser tempe rature range of 15 o F
. 3 DOE Study did not estimate nuclear penalty but cited a previous study of reported values (Veil 1992) with a range of 1% to 5.8% and estimated the annual average values would be in the 2% to 3% range. A subsequent DOE Study (DOE 200 6) estimated nuclear penalty by increasing the coal

- fired penalty by 25%. 4 From California cooling water policy. Penalty was calculated for each facility using facility

- supplied data. D ata shown is for several selected examples. The most recent estimates in Table 1 are from the technical and economic analy sis supporting the proposed California Power Plant Once

- Through Cooling Regulation. 1

1 California's Coastal Pow er Plants: Alternative Cooling System Analysis. February 2008.3

This study

include s a detailed estimation of the energy penalt y associated with cooling tower retrofit for each electric generating facility in California . These analy ses provide estimates for each facility and generating unit for the fan energy requirements, the net pumping energy

requirements, and turbine efficiency reductions ; all are expressed as a percent of power generation. Fan and pump energy values are conservative as they assume that fans and pumps will operate at full capacity ye ar round. The turbine efficiency loss was calculated on a monthly basis using reported and estimated changes in generating unit heat rates. Discussion: Pump and Fan Energy The California Report estimates for the pump and fan energy penalty component appear to be similar in magnitude to EPA ’s estimates and are based on basic eng ineering design principles. The DOE analy sis includes pump and fan energy requirements as well, and examination of several examples shows that the fan and pump energy penalty component was around 0.8% at a condenser temperature range of 15 o F . One important variable throughout these anal ys es is the condenser temperature rise (or range) which, for any given plant generating output, will affect the fan and pumping energy in relation to the generating capacity . This will affect the values shown in Table 1 wh ich may not necessarily

be based on the same design conditions. A lower condenser rise will result in higher recirculating flows and correspondingl y higher energy requirements for fan and pumping requirements. The EPA method is not affected b y this becau se it uses actual design intake flow values. The temperature ranges used in the California analy sis were around 18 to 20 o F
. Turbine Efficiency As noted above, a different turbine efficiency penalty is used for fossil and nuclear facilities, reflecting the differences in operating pressures in the generating turbines. EPRI ’s methodology

uses a 2% turbine efficiency loss for all facilities and is consistent with EPA’s approach ; the basis for EPRI’s assumption is not stated in the documentation, but (based on our BPJ) is likely to be representative of the maximum value. In California ’s anal ys is, average energy penalty estimates are also lower for the gas

- fired plants and higher for the nuclear plants. A review of the methodology shows that the California estimates are based on several conservative assumptions and data selections. The approach values selected ranged from 12 o F to 16 o F, with the 16 o F being for the nuclear plant with the highest turbine efficiency loss of 3.6%. These values are hi gher than the 10 o F value used by and EPRI . The DOE report stated that “the ty pical commercial design is based on an approach....of 8 degrees plus 1

- 3 degrees to account for an y plume recirculation.” All of the energy

penalt y methodologies presented in Tabl e 1 calculated the annual average turbine penalt y by averaging calculated monthly values. In the California4

anal ys es, each monthly

value is based on the maximum wet bulb temperature for the month. The DOE anal ys is used the monthly average wet bulb temper ature. The difference between the monthly maximum and average wet bulb temperature can be significant, and the use of monthly maximum val u es will skew the California numbers higher. Thus, it appears that the annual average turbine efficiency penalt y valu es from the California anal ys es are somewhat overestimated. Nuclear Facilities In a 2008 r eport, 2 DOE estimated nuclear penalt y values by assuming that nuclear penalties were 25% greater than those for fossil fuel plants. Similarly , a previous DOE s tudy (DOE 2006) based fossil

- fuel energy penalt y estimates on the values reported in the 2002 DOE study

and calculated the nuclear penalty by multiplying the coal

- fired penalty by 25%. The total average nuclear energy penalty of 4.2% used In EPA’s cost analysis is approximately

30% higher than the non

- nuclear penalty of 3.2% and thus is consistent with DOE estimates. EPA’s nuclear penalt y would still be lower than the California study estimates, but as noted above the California study estimates appear to be conservativel y overestimated with respect to the annual average penalty
. Condenser Modifications The California anal ys is assumed that condensers would require modification in the form of waterbox reinforcement and tube sheet bracing. This modification was included to account for the increase in water pressure associated with the need to pump water through the condenser to the top of the cooling towers. A conservative estimate of 5% of all direct costs was added to account for condenser modifications. The EPRIworksheet instructions state: “The approach to a closed

- cycle retrofit used in this analy sis is the following: The existing once

- through cooling s ys tem equipment is left intact to the exte nt possible; that is, the condenser, the circulating water pumps and the piping connections to the condenser inlet and exit waterboxes are kept the same.” The EPRImethodology

assumes that the retrofit configuration would be for the cooling tower water t o be pumped from the condenser effluent channel through the towers to the intake pumps inlet using an additional set of pumps. In this configuration, there is no change to the condenser h ydraulic conditions and thus no need to modify the condenser.

2 DOE. Electricity Reliability Impacts of a Mandatory Cooling Tower Rule for Existing Steam Generation Units. October 2008. Accessed at w ebsite: http://www.oe.energy.gov/Documents andMedia/Cooling_Tow er_Report.pdf