United States Office of Water EPA 821-R-02-003
Environmental Protection (4303) April 2002
Agency
&ERA Technical Development
Document for the
Proposed Section 316(b)
Phase II Existing Facilities
Rule
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Technical Development Document for the Proposed
Section 316(b) Phase II Existing Facilities Rule
U.S. Environmental Protection Agency
Office of Science and Technology
Engineering and Analysis Division
Washington, DC 20460
April 9, 2002
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Section 316(b) Phase II TDD Table of Contents
Table of Contents
Chapter 1: Industry Profile
Introduction 1-1
1-1 Industry Overview 1-1
1-2 Domestic Production 1-4
1-3 Existing Plants with CWIS and NPDES Permits 1-6
Glossary 1-23
References 1-26
Chapter 2: Costing Methodology for Model Plants
Introduction 2-1
2-1 Cooling Water Intake Structure Costs 2-1
2-2 Outline of Cooling System Conversion Costing Methodology 2-16
2-3 Recurring Annual Costs of Post-Compliance Monitoring 2-26
2-4 One-Time Costs for Comprehensive Demonstration Studies 2-26
2-5 Regional Cost Factors 2-27
2-6 Retrofit Cost Factor 2-28
2-7 Examples of Model Plant Cost Estimates 2-29
2-8 Repowering Facilities and Model Plant Costs 2-35
2-9 Capacity Utilization Rate Cut-Off 2-37
References 2-40
Chapter 3: Efficacy of Cooling Water Intake Structure Technologies
Introduction 3-1
3-1 Scope of Data Collection Efforts 3-1
3-2 Data Limitations 3-1
3-3 Conventional Traveling Screens 3-2
3-4 Closed-Cycle Wet Cooing System Performance 3-3
3-5 Alternative Technologies 3-3
3-6 Intake Location 3-15
3-7 Summary 3-17
References 3-20
Attachment A Cooling Water Intake Structure Technology Fact Sheets
Chapter 4: Cooling System Conversions at Existing Facilities
Introduction 4-1
4-1 Example Cases of Cooling System Conversions 4-1
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Section 316(b) Phase II TDD Table of Contents
4-2 Plant Outages for Cooling System Conversions 4-6
4-3 Summary of Flow-Reduction Options Considered 4-9
References 4-12
Chapter 5: Energy Penalties of Cooling Towers
Introduction 5-1
5-1 Energy Penalty Estimates for Cooling 5-2
5-2 Introduction to Energy Penalty Estimates 5-4
5-3 Turbine Efficiency Energy Penalty 5-7
5-4 Energy Penalty Associated with Cooling System Energy Requirements 5-21
5-5 Analysis of Cooling System Energy Requirements 5-25
5-6 Other Sources of Energy Penalty Estimates 5-31
References 5-35
Attachment A Heat Diagram for Steam Power Plant
Attachment B Exhaust Pressure Correction Factors
Attachment C Design Approach Data for Recent Cooling Tower Projects
Attachment D Tower Size Factor Plot
Attachment E Cooling Tower Wet Bulb Versus Cold Water Temperature Typical Performance Curve
Chapter 6: Non-Water Quality Impacts
Introduction 6-1
6-1 Air Emissions Increases 6-1
6-2 Vapor Plumes 6-5
6-3 Displacement of Wetlands or Other Land Habitats 6-8
6-4 Salt or Mineral Drift 6-8
6-5 Noise 6-9
6-6 Solid Waste Generation 6-9
6-7 Evaporative Consumption of Water 6-9
References 6-11
Appendix A: Compliance Cost Estimates for the Proposed Rule
Appendix B: Technology Cost Curves
Appendix C: Cost Estimate Report for a Hypothetical Cooling System Conversion
Appendix D: Dry Cooling
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§ 316(b) Phase II TDD Industry Profile
Chapter 1: Industry Profile
INTRODUCTION
This profile presents data for the electric power generating industry important for understanding the context of the analyses
presented in this document. The majority of this profile is excerpted from Chapter A3 of the Economic and Benefits Analysis
for the Proposed Section 316(b) Phase II Existing Facilities Rule (the "EBA"). For more information on aspects of the
industry that may influence the nature and magnitude of economic impacts of the Proposed Section 316(b) Phase II Existing
Facilities Rule, see Chapter A3 of the EBA.
The electric power industry is one of the most extensively studied industries. The Energy Information Administration (EIA),
among others, publishes a multitude of reports, documents, and studies on an annual basis. This profile is not intended to
duplicate those efforts. Rather, this profile compiles, summarizes, and presents those industry data that are important in the
context of the proposed Phase II rule. For more information on general concepts, trends, and developments in the electric power
industry, the last section of this profile, "References," presents a select list of other publications on the industry.
The remainder of this profile is organized as follows:
*• Section 1-1 provides a brief overview of the industry, including descriptions of major industry sectors and types
of generating facilities.
> Section 1-2 provides data on industry production and capacity.
> Section 1-3 focuses on the in-scope section 316(b) facilities. This section provides information on the
geographical, physical, and cooling water characteristics of the in-scope phase II facilities.
1-1 INDUSTRY OVERVIEW
This section provides a brief overview of the industry, including descriptions of major industry sectors and types of generating
facilities.
1-1.1 Industry Sectors
The electricity industry is made up of three major functional service components or sectors: generation, transmission, and
distribution. Each of these terms are defined as follows (Beamon, 1998; Joskow, 1997):1
*• The generation sector includes the power plants that produce, or "generate," electricity.2 Electric energy is
produced using a specific generating technology, for example, internal combustion engines and turbines.
Turbines can be driven by wind, moving water (hydroelectric), or steam from fossil fuel-fired boilers or nuclear
reactions. Other methods of power generation include geothermal or photovoltaic (solar) technologies.
Terms highlighted in bold and italic font are defined in the glossary at the end of this chapter.
The terms "plant" and "facility" are used interchangeably throughout this profile and document.
1-1
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§ 316(b) Phase II TDD Industry Profile
> The transmission sector can be thought of as the interstate highway system of the business - the large,
high-voltage power lines that deliver electricity from power plants to local areas. Electricity transmission
involves the "transportation" of electricity from power plants to distribution centers using a complex system.
Transmission requires: interconnecting and integrating a number of generating facilities into a stable,
synchronized, alternating current (AC) network; scheduling and dispatching all connected plants to balance the
demand and supply of electricity in real time; and managing the system for equipment failures, network
constraints, and interaction with other transmission networks.
> The distribution sector can be thought of as the local delivery system - the relatively low-voltage power lines
that bring power to homes and businesses. Electricity distribution relies on a system of wires and transformers
along streets and underground to provide electricity to residential, commercial, and industrial consumers. The
distribution system involves both the provision of the hardware (for example, lines, poles, transformers) and
a set of retailing functions, such as metering, billing, and various demand management services.
Of the three industry sectors, only electricity generation uses cooling water and is subject to section 316(b). The remainder of
this profile will focus on the generation sector of the industry.
1-1.2 Prime Movers
Electric power plants use a variety of prime movers to generate electricity. The type of prime mover used at a given plant
is determined based on the type of load the plant is designed to serve, the availability of fuels, and energy requirements. Most
prime movers use fossil fuels (coal, petroleum, and natural gas) as an energy source and employ some type of turbine to produce
electricity. The six most common prime movers are (U.S. DOE, 2000a):
> Steam Turbine: Steam turbine, or "steam electric" units require a fuel source to boil water and produce
steam that drives the turbine. Either the burning of fossil fuels or a nuclear reaction can be used to produce
the heat and steam necessary to generate electricity. These units are generally baseload units that are run
continuously to serve the minimum load required by the system. Steam electric units generate the majority of
electricity produced at power plants in the U.S.
> Gas Combustion Turbine: Gas turbine units burn a combination of natural gas and distillate oil in a high
pressure chamber to produce hot gases that are passed directly through the turbine. Units with this prime
mover are generally less than 100 megawatts in size, less efficient than steam turbines, and used for peakload
operation serving the highest daily, weekly, or seasonal loads. Gas turbine units have quick startup times and
can be installed at a variety of site locations, making them ideal for peak, emergency, and reserve-power
requirements.
> Combined-Cycle Turbine: Combined-cycle units utilize both steam and gas turbine prime mover
technologies to increase the efficiency of the gas turbine system. After combusting natural gas in gas turbine
units, the hot gases from the turbines are transported to a waste-heat recovery steam boiler where water is
heated to produce steam for a second steam turbine. The steam may be produced solely by recovery of gas
turbine exhaust or with additional fuel input to the steam boiler. Combined-cycle generating units are generally
used for intermediate loads
> Internal Combustion Engines: Internal combustion engines contain one or more cylinders in which fuel
1-2
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§ 316(b) Phase II TDD
Industry Profile
is combusted to drive a generator. These units are generally about 5 megawatts in size, can be installed on
short notice, and can begin producing electricity almost instantaneously. Like gas turbines, internal combustion
units are generally used only for peak loads.
> Water Turbine: Units with water turbines, or "hydroelectric units," use either falling water or the force of
a natural river current to spin turbines and produce electricity. These units are used for all types of loads.
> Other Prime Movers: Other methods of power generation include geothermal, solar, wind, and biomass
prime movers. The contribution of these prime movers is small relative to total power production in the U.S.,
but the role of these prime movers may expand in the future because recent legislation includes incentives for
their use.
Table 1-1 provides data on the number of existing utility and nonutility power plants by prime mover. This table includes all
plants that have at least one non-retired unit and that submitted Forms EIA-860A (Annual Electric Generator Report - Utilities)
or EIA-860B (Annual Electric Generator Report - Nonutilities) in 1999.3 For the purpose of this analysis, plants were classified
as "steam turbine" or "combined-cycle" if they have at least one generating unit of that type. Plants that do not have any steam
electric units, were classified under the prime mover type that accounts for the largest share of the plant's total electricity
generation.
Table 1-1: Number of Existing
Prime Mover
Steam Turbine
Combined-Cycle
Gas Turbine
Internal Combustion
Hydroelectric
Other
Total
Plants by Prime Mover, 1999
Number of Plants
1,624
260
707
887
1,713
139
5,330
Source: U.S. DOE, 1999a; U.S. DOE, 1999b; U.S. DOE, 1999c.
Only prime movers with a steam electric generating cycle use substantial amounts of cooling water (for the condensing of steam
exiting the steam turbines). These generators include steam turbines and combined-cycle technologies. As a result, the analysis
in support of the proposed Phase II rule focuses on generating plants with a steam electric prime mover. This profile will,
therefore, differentiate between steam electric and other prime movers.
At the time of publication of this document, 1999 was the most recent year for which complete EIA data were
available for existing utility and nonutility plants. As of March 2002, EIA 860B data were not available for year 2000. As
such, this profile is based on 1999 data.
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§ 316(b) Phase II TDD Industry Profile
1-2 DOMESTIC PRODUCTION
This section presents an overview of U.S. generating capacity and electricity generation. Subsection 1-2.1 provides data on
capacity, and Subsection 1-2.2 provides data on generation. Subsection 1-2.3 presents an overview of the geographic
distribution of generation plants and capacity.
1-2.1 Generating Capacity4
The rating of a generating unit is a measure of its ability to produce electricity. Generator ratings are expressed in megawatts
(MW). Capacity and capability are the two common measures (U.S. DOE, 2000a):
Nameplate capacity is the full-load continuous output rating of the generating unit under specified conditions, as designated
by the manufacturer.
Net capability is the steady hourly output that the generating unit is expected to supply to the system load, as demonstrated
by test procedures. The capability of the generating unit in the summer is generally less than in the winter due to high
ambient-air and cooling-water temperatures, which cause generating units to be less efficient. The nameplate capacity of a
generating unit is generally greater than its net capability.
Figure 1-2 shows the total US generating capacity from 1991 to 1999.5
The numbers presented in this section are capability for utility facilities and capacity for nonutilities. For
convenience purposes, this section will refer to both measures as"capacity."
analysis.
1-4
More accurate data were available starting in 1991, therefore, 1991 was selected as the initial year for trends
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§ 316(b) Phase II TDD
Industry Profile
Figure 1-2: Generating Capability & Capacity,
1991 to 1999°
800 -|
700 -
600 -
500 -
400 -
300 -
200 -
100 -
/
/
/
/
/
/
/
e=
1
^
5
^
5
i
i
i
i
.c
1
1991 1992 1993 1994 1995 1996 1997 1998
^
1
1999
• Utility
Capability
• Nonutility
Capacity
Source: U.S. DOE, 2000c; U.S. DOE,1996b.
1-2.2 Electricity Generation
Total net electricity generation in the U.S. for 1999
was 3,723 billion kWh. Total net generation has
increased by 21 percent over the nine-year period from
1991 to 1999.
Table 1-2 shows the change in net generation between
1991 and 1999 by fuel source for utilities and
nonutilities.
MEASURES OF GENERATION
The production of electricity is referred to as generation and is measured
in kilowatthours (kWh). Generation can be measured as:
Gross generation: The total amount of power produced by an electric
power plant.
Net generation: Power available to the transmission system beyond that
needed to operate plant equipment. For example, around 7% of electricity
generated by steam electric units is used to operate equipment.
Electricity available to consumers: Power available for sale to
customers. Approximately 8 to 9 percent of net generation is lost during
the transmission and distribution process.
U.S. DOE, 2000a
Table 1-2
Sourc
Energy
Source
!: Net Generation by Energy
z. 1991 to 1999 (6Wh)
Total
1991 i 1999 i % Change
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§ 316(b) Phase II TDD
Industry Profile
Coal
Hydropower
Nuclear
Petroleum
Gas
Renewablesb
Total
1,591
286
613
119
392
67
3,067
1,893
315
734
108
592
80
3,723
19%
10%
20%
-9%
51%
19%
21% |
a Nonutility generation was converted from gross to net generation based on prime mover-specific
conversion factors (U.S. DOE, 2000c). As a result of this conversion, the total net generation
estimates differ slightly from EIA published totals by fuel type.
b Renewables include solar, wind, wood, biomass, and geothermal energy sources.
Source: U.S. DOE, 2000b;U.S. DOE, 2000c; U.S. DOE, 1995a; U.S. DOE,1995b.
Figure 1 -3 shows total net generation for the U. S. by primary fuel source. Electricity generation from coal-fired plants accounts
for 47 percent of total 1999 generation. The second largest source of electricity generation is nuclear power plants, accounting
for 20 percent of total generation. Another significant source of electricity generation is gas-fired power plants, which account
for 16 percent of total generation.
Figure 1-3: Percent of Electricity Generation by Primary Fuel Source, 1999
iNbn-Utility
D Utility
ff ^ ^ <$ CT N^
J * / /
^
^
Source: U.S. DOE,2000b; U.S. DOE,2000c.
Regulatory options cosidered for proposed Phase II rule affect facilities differently based on the fuel sources and prime movers
used to generate electricity. As mentioned in Section 1-1.2 above, only prime movers with a steam electric generating cycle use
substantial amounts of cooling water.
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§ 316(b) Phase II TDD
Industry Profile
1-3 EXISTINS PLANTS WITH CWIS AND NPDES PERMITS
Section 316(b) of the Clean Water Act applies to a point source facility that uses or proposes to use a cooling water intake
structure water that directly withdraws cooling water from a water of the United States. Among power plants, only those
facilities employing a steam electric generating technology require cooling water and are therefore of interest to this analysis.
Steam electric generating technologies include units with steam electric turbines and combined-cycle units with a steam
component.
The following sections describe existing power plants that would be subject to the proposed Phase II rule. The Proposed Section
316(b) Phase II Existing Facilities Rule applies to existing steam electric power generating facilities that meet all of the
following conditions:
They meet the definition of an existing steam electric power generating facility as specified in § 125.93 of this
rule;
They use a cooling water intake structure or structures, or obtain cooling water by any sort of contract or
arrangement with an independent supplier who has a cooling water intake structure;
Their cooling water intake structure(s) withdraw(s)
cooling water from waters of the U.S., and at least
twenty-five (25) percent of the water withdrawn is
used for contact or non-contact cooling purposes;
* They have an NPDES permit or are required to
obtain one; and
> They have a design intake flow of 50 MGD or
greater.
The proposed Phase II rule also covers substantial additions or
modifications to operations undertaken at such facilities. While all
facilities that meet these criteria are subject to the regulation, this
document focuses on 539 steam electric power generating facilities
identified in EPA's 2000 Section 316(b) Industry Survey as being
"in-scope" of this proposed rule. These 539 facilities represent 550
facilities nation-wide.6 The remainder of this chapter will refer to
these facilities as "existing section 316(b) plants."
Utilities and nonutilities are discussed in separate subsections because
the data sources, definitions, and potential factors influencing the
magnitude of impacts are different for the two sectors. Each
subsection presents the following information:
*• Plant size: This section discusses the existing
section 316(b) facilities by the size of their
generation capacity. The size of a plant is important
WATER USE BY STEAM ELECTRIC
POWER PLANTS
Steam electric generating plants are the single
largest industrial users of water in the United States.
In 1995:
»• steam electric plants withdrew an estimated
190 billion gallons per day, accounting for 39
percent of freshwater use and 47 percent of
combined fresh and saline water withdrawals
for offstream uses (uses that temporarily or
permanently remove water from its source);
> fossil-fuel steam plants accounted for 71
percent of the total water use by the power
industry;
»• nuclear steam plants and geothermal plants
accounted for 29 percent and less than 1
percent, respectively;
> surface water was the source for more than 99
percent of total power industry withdrawals;
> approximately 69 percent of water intake by
the power industry was from freshwater
sources, 31 percent was from saline sources.
USGS, 1995
EPA applied sample weights to the 539 facilities to account for non-sampled facilities and facilities that did not
respond to the survey. For more information on EPA's 2000 Section 316(b) Industry Survey, please refer to the Information
Collection Request (U.S. EPA 2000).
1-7
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§ 316(b) Phase II TDD Industry Profile
because it partly determines its need for cooling water.
> Geographic distribution: This section discusses plants by NERC region. The geographic distribution of
facilities is important because a high concentration of facilities with costs under a regulation could lead to
impacts on a regional level. Everything else being equal, the higher the share of plants with costs, the higher
the likelihood that there may be economic and/or system reliability impacts as a result of the regulation.
> Water body and cooling system type: This section presents information on the type of water body from which
existing section 316(b) facilities draw their cooling water and the type of cooling system they operate. Cooling
systems can be either once-through or recirculating systems.7 Plants with once-through cooling water systems
withdraw between 70 and 98 percent more water than those with recirculating systems.
Once-through cooling systems withdraw water from the water body, run the water through condensers, and
discharge the water after a single use. Recirculating systems, on the other hand, reuse water withdrawn from the source.
These systems take new water into the system only to replenish losses from evaporation or other processes during the cooling
process. Recirculating systems use cooling towers or ponds to cool water before passing it through condensers again.
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§ 316(b) Phase II TDD
Industry Profile
1-3.1 Existing Section 316(b) Utility Plants
EPA identified steam electric prime movers that require cooling water using information from the EIA data collection U.S. DOE,
1999a.8 These prime movers include:
Atmospheric Fluidized Bed Combustion (AB)
Combined-Cycle Steam Turbine with Supplementary Firing (CA)
Combined Cycle - Total Unit (CC)
Steam Turbine - Common Header (CH)
Combined-Cycle - Single Shaft (CS)
Combined-Cycle Steam Turbine - Waste Heat Boiler Only (CW)
Steam Turbine - Geothermal (GE)
Integrated Coal Gasification Combined-Cycle (IG)
Steam Turbine - Boiling Water Nuclear Reactor (NB)
Steam Turbine - Graphite Nuclear Reactor (NG)
Steam Turbine - High Temperature Gas-Cooled Nuclear Reactor (NH)
Steam Turbine - Pressurized Water Nuclear Reactor (NP)
Steam Turbine - Solar (SS)
Steam Turbine - Boiler (ST)
Using this list of steam electric prime movers, and U.S. DOE, 1999a information on the reported operating status of units, EPA
identified 862 facilities that have at least one generating unit with a steam electric prime mover. Additional information from
the section 316(b) Industry Surveys was used to determine that 416 of the 862 facilities operate a CWIS and hold an NPDES
permit. Table 1-4 provides information on the number of utilities, utility plants, and generating units, and the generating
capacity in 1999. The table provides information for the industry as a whole, for the steam electric part of the industry, and
for the part of the industry potentially affected by the proposed Phase II rule.
Table 1-4: Number of Existing Utilities, Utility Plants, Units, and Capacity, 1999
Utilities
Plants
Units
Nameplate Capacity (MW)
Total3
891
3,125
10,460
702,624
Steam Electric"
Number % of Total
315 35%
862 28%
2,226 21%
533,503 76%
Steam Electric with CWIS
and NPDES Permit0
Number % of Total
148 17%
416 13%
1,220 12%
344,849 49%
Includes only generating capacity not permanently shut down or sold to nonutilities.
Utilities and plants are listed as steam electric if they have at least one steam electric unit.
The number of plants, units, and capacity was sample weighted to account for survey non-
respondents.
U.S. DOE, 1999a (Annual Electric Generator Report) collects data used to create an annual inventory of utilities.
The data collected includes: type of prime mover; nameplate rating; energy source; year of initial commercial operation;
operating status; cooling water source, and NERC region.
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§ 316(b) Phase II TDD
Industry Profile
Source: U.S. EPA, 2000; U.S. DOE, 1999a; U.S. DOE, 1999c.
Table 1-4 shows that the while the 862 steam electric plants account for only 28 percent of all plants, these plants account for
76 percent of all capacity. The 416 in-scope plants represent 13 percent of all plants, are owned by 17 percent of all utilities,
and account for approximately 49 percent of reported utility generation capacity. The remainder of this section will focus on
the 416 utility plants.
a. Plant size
EPA analyzed the utility steam electric facilities with a CWIS and an NPDES permit with respect to their generating capacity.
Figure 1-4 presents the distribution of existing utility plants with a CWIS and an NPDES permit by plant size. Of the 416
plants, 189 (45 percent) have a total nameplate capacity of 500 megawatts or less, and 280 (67 percent) have a total capacity
of 1,000 megawatts or less.
Figure 1-4: Number of Existing Phase II Facilities by Plant Size (in MW). 1999
a,b
200
180-
160-
140
120-
100-
80-
60-
40
20-I
0
FT
ui
61
QI
10
f=n
U)
4 20
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§ 316(b) Phase II TDD
Industry Profile
facilities, followed by the East Central Area Reliability Coordination Agreement (ECAR) with 90 facilities, or 22 percent of
all facilities.
Table 1-5: Existing Utility Plants by NERC Region
NERC Region
ASCC
ECAR
ERCOT
FRCC
HI
MAAC
MAIN
MAPP
NPCC
SERC
SPP
WSCC
Unknown
Total
Total Number of
Plants
168
301
107
62
16
93
207
406
394
333
262
773
3
3,125
Plants with CWIS
Number
1
90
52
29
3
3
33
43
17
94
32
18
0
416
. 1999
and NPDES Permit3"
% of Total
1%
30%
49%
47%
19%
3%
16%
11%
4%
28%
12%
2%
0%
13%
a Numbers may not add up to totals due to independent rounding.
b The number of plants was sample weighted to account for survey non-respondents.
Source: U.S. EPA, 2000; U.S. DOE, 1999a; U.S. DOE, 1999c.
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§ 316(b) Phase II TDD
Industry Profile
c. Water body and cooling system type
Table 1 -6 shows that most of the existing utility plants with a CWIS and an NPDES permit draw water from a freshwater river
(204, or 49 percent). The next most frequent water body types are lakes or reservoirs with 138 plants (3 3 percent) and estuaries
or tidal rivers with 47 plants (11 percent). The table also shows that most of these plants, 314 or 75 percent, employ a once-
through cooling system. Of the plants that withdraw from an estuary, the most sensitive type of water body, only nine percent
use a recirculating system while 85 percent have a once-through system.
Table 1-6: Number of Existing Utility Plants by Water Body Type and Cooling System Type"
Water Body
Type
Estuary/
Tidal River
Ocean
Lake/
Reservoir
Freshwater
River
Multiple
Freshwater
Other/
Unknown
Total
Cooling System Type
Recirculating
No.
4
0
29
36
0
1
70
%of
Total
9%
0%
21%
18%
0%
50%
17%
Once-Through
No.
40
15
103
149
6
1
314
%of
Total
85%
100%
75%
73%
60%
50%
75%
Combination
No.
1
0
4
8
3
0
16
%of
Total
2%
0%
3%
4%
30%
0%
4%
Other
No.
2
0
2
10
1
0
15
%of
Total
4%
0%
1%
5%
10%
0%
4%
Unknown
No.
0
0
0
I
0
0
1
%of
Total
0%
0%
0%
0%
0%
0%
0%
Total "
47
15
138
204
10
2
416
a The number of plants was sample weighted to account for survey non-respondents.
b Numbers may not add up to totals due to independent rounding.
Source: U.S. EPA, 2000; U.S. DOE, 1999a; U.S. DOE, 1999c.
1-3.2 Existing Section 316(b) Nonutility Plants
EPA identified nonutility steam electric prime movers that require cooling water using information from the EIA data collection
Forms EIA-860B9 and the section 316(b) Industry Survey. These prime movers include:
*• Geothermal Binary (GB)
*• Steam Turbine - Fluidized Bed Combustion (SF)
Solar - Photovoltaic (SO)
U.S. DOE, 1998b (Annual Nonutility Electric Generator Report) is the equivalent of U.S. DOE, 1998a for utilities.
It is the annual inventory of nonutility plants and collects data on the type of prime mover, nameplate rating, energy source,
year of initial commercial operation, and operating status.
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§ 316(b) Phase II TDD
Industry Profile
> Steam Turbine (ST)
In addition, prime movers that are part of a combined-cycle unit were classified as steam electric.
U.S. DOE, 1998b includes two types of nonutilities: facilities whose primary business activity is the generation of electricity,
and manufacturing facilities that operate industrial boilers in addition to their primary manufacturing processes. The discussion
of existing section 316(b) nonutilities focuses on those nonutility facilities that generate electricity as their primary line of
business.
Using the identified list of steam electric prime movers, and U.S. DOE, 1999b information on the reported operating status of
generating units, EPA identified 559 facilities that have at least one generating unit with a steam electric prime mover.
Additional information from the section 316(b) Industry Survey determined that 134 of the 559 facilities operate a CWIS and
hold an NPDES permit. Table 1 -7 provides information on the number of parent entities, nonutility plants, and generating units,
and their generating capacity in 1999. The table provides information for the industry as a whole, for the steam electric part
of the industry, and for the "section 316(b)" part of the industry.
Table 1-7: Number of Nonutilities, Nonutility Plants, Units, and Capacity, 1999
Parent Entities
Nonutility Plants
Nonutility Units
Nameplate Capacity (MW)
Total
1,509
2,205
5,958
206,500
Total Steam
Electric
Nonutilities a
441
559
1,255
153,032
Nonutilities with CWIS and NPDES
Permit3"
Number % of Steam Electric
47 11%
134 24%
343 27%
107,054 70%
a Includes only nonutility plants generating electricity as their primary line of business.
b The number of plants, units, and capacity was sample weighted to account for survey non-respondents.
Source: U.S. EPA, 2000; U.S. DOE, 1999a; U.S. DOE, 1999b; U.S. DOE, 1999c.
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§ 316(b) Phase II TDD
Industry Profile
a. Plant size
EPA analyzed the steam electric nonutilities with a CWIS and an NPDES permit with respect to their generating capacity.
Figure 1-5 shows that the original nonutility plants are much smaller than the former utility plants. Of the 14 original utility
plants, 3 (25 percent) have a total nameplate capacity of 50 MW or less, and 8 (58 percent) have a capacity of 100 MW or less.
No original nonutility plant has a capacity of more than 500 MW. In contrast, only 18(15 percent) former utility plants are
smaller than 250 MW while 83 (69 percent) are larger than 500 MW and 44 (37 percent) are larger than 1,000 MW.
Figure 1-5: Number of Existing Nonutility Plants with CWIS and
NPDES Permit by Generating Capacity (in MW). 1998"b
a Numbers may not add up to totals due to independent rounding.
a The number of plants was sample weighted to account for survey non-
respondents.
Source: U.S. EPA, 2000; U.S. DOE, 1999a; U.S. DOE, 1999b; U.S. DOE, 1999c.
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§ 316(b) Phase II TDD
Industry Profile
b. Geographic distribution
Table 1-8 shows the distribution of existing section 316(b) nonutility plants by NERC region. The table shows that the
Northeast Power Coordinating Council (NPCC) has the highest absolute number of existing section 316(b) nonutility plants
with 45 (9 percent) of the 134 plants with a CWIS and an NPDES permit, followed by the Mid-Atlantic Area Council (MAAC)
with 41 plants. MAAC also has the largest percentage of plants with a CWIS and an NPDES permit compared to all nonutility
plants within the region, at 26 percent.10
Table 1-8: Nonutility Plants by NERC Region,
NERC Region
ASCC
ECAR
ERCOT
FRCC
HI
MAAC
MAIN
MAPP
NPCC
SERC
SPP
WSCC
Not Available
Total
Total Number
of Plants
26
139
75
57
11
155
136
70
531
279
43
613
70
2,205
1998
Plants with CWIS & NPDES Permit3"
Number
0
10
0
1
0
41
18
1
45
1
0
16
0
134
% of Total
0%
7%
0%
2%
0%
26%
13%
2%
9%
0%
0%
3%
0%
6%
a Numbers may not add up to totals due to independent rounding.
b The number of plants was sample weighted to account for survey non-respondents.
Source: U.S. EPA, 2000; U.S. DOE, 1999a; U.S. DOE, 1999b; U.S. DOE, 1999c.
10
The total number of plants includes industrial boilers while the number of plants with a CWIS and an NPDES
permit does not. Therefore, the percentages are likely higher than presented.
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§ 316(b) Phase II TDD
Industry Profile
c. Water body and cooling system type
Table 1-9 shows the distribution of existing section 316(b) nonutility plants by type of water body and cooling system. The
table shows that a majority of plants with a CWIS and an NPDES permit draw water from either a freshwater river, or an
estuary or tidal river.
The table also shows that most of the nonutilities employ a once-through system: 114 out of 13 3 nonutility plants. Of the plants
that withdraw from an estuary/tidal river, the most sensitive type of waterbody, only two use a recirculating system, while 56
operate a once-through system.
Table 1-9: Number of Nonutility Plants by Water Body Type and Cooling System Type"
Water Body
Type
Estuary/
Tidal River
Ocean
Lake/
Reservoir
Freshwater
River
Other/
Unknown
Total
Cooling System Type
Recirculating
!VT % °f
N°- Total
2 3%
0 0%
2 17%
13 25%
0 0%
17 13%
Once-Through
!VT % °f
N°- Total
56 95%
9 100%
9 74%
39 75%
1 100%
114 86%
Combination
!VT % °f
N°- Total
1 2%
0 0%
1 9%
0 0%
0 0%
2 2%
Other
!VT % °f
N°- Total
0 0%
0 0%
0 0%
1 2%
0 0%
1 1%
Total "
59
9
12
52
1
133
a The number of plants was sample weighted to account for survey non-respondents.
b Numbers may not add up to totals due to independent rounding.
Source: U.S. EPA, 2000; U.S. DOE, 1999a; U.S. DOE, 1999b; U.S. DOE, 1999c.
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§ 316(b) Phase II TDD Industry Profile
1-3.3 Cooling Water Intake Structure Data
A primary source of information used to prepare the analyses of this document is the 316(b) survey. The 316(b) survey was
a two phase process. The results from the second phase of this process ~ the distribution of questionnaires to utility and
nonutility power producers ~ is of specific interest to the analyses in this document. The results from following questionnaires
are of interest to this proposed rule: (1) Detailed Industry Questionnaire: Phase II Cooling Water Intake Structures -Traditional
Steam Electric Utilities, (2) Short Technical Industry Questionnaire: Phase II Cooling Water Intake Structures - Traditional
Steam Electric Utilities, (3) Detailed Industry Questionnaire: Phase II Cooling Water Intake Structures - Steam Electric
Nonutility Power Producers, and (4) Short Technical Industry Questionnaire: Phase II Cooling Water Intake Structures - Steam
Electric Nonutility Power Producers. For the purposes of this document, the results of the detailed industry questionnaires for
both utilities and nonutilities are addressed as simply the detailed questionnaire (the "DQ") results. Similarly, this document
refers to the results from the short technical industry questionnaire for both utilities and nonutilities as simply the short technical
questionnaire (the "STQ") results. Specific details about the questions may be found in EPA's Information Collection Request
(DCN 3-3084-R2 in Docket W-00-03) and in the questionnaires (see DCN 3-0030 and 3-0031 in Docket W-00-03 and Docket
for today's proposal); these documents are also available on EPA's web site (http://www.epa.gOv/waterscience/316b/question/).
All utilities and a sample of nonutility facilities (those identified as in-scope by the results of a screener questionnaire) were
sent either a STQ or a DQ. A total of 878 utility facilities and 343 nonutility facilities received one of the two questionnaires.
EPA selected a random sample of these eligible facilities to receive a DQ. The sample included 282 utility facilities and 181
nonutility facilities. Those facilities not selected to receive a DQ were sent a STQ. More detail is provided in a report,
Statistical Summary for Cooling Water Intakes Structures Surveys (See DCN 3-3077 in Docket W-00-03). Of the 282 utility
facilities and 181 nonutility facilities receiving a DQ, the Agency determined that 225 of the respondents would fall within the
scope of this rule. Of the STQ respondents, the Agency found that 314 would be in-scope.
The Agency compiled facility level, cooling system, and intake structure data for the 225 in-scope Detailed Questionnaire (DQ)
respondents and, to the extent possible, for the 314 Short Technical Questionnaire (STQ) respondents. The Agency then used
this tabulation of data to make determinations on the types of cooling systems and intake structures in-place at the in-scope
facilities. The Agency utilized questions about intake systems common to both the DQ and STQ in order to make determinations
about costing decisions that hinged on the intake structures in-place. Other pieces of information from the STQ provided insight
into the types of intake structures in-place at the STQ facilities, when compared to more detailed information for the DQ
respondents.
Using both the DQ and STQ responses, the Agency studied the intake structure characteristics for all 539 facilities and/or the
225 DQ facilities. The Agency focused on questions about intake screen structure types common to both the DQ and STQ.
The Agency then examined the DQ respondents within the context of these questions to discern patterns and statistics for use
in making decisions relating to costing of the proposed option based on intake systems currently in-place for both the DQ and
STQ facilities. Tables 1-10 through 1-19 summarize this data analysis. For discussion and descriptions of the types of cooling
water intake technologies presented in the tables, see Chapter 3 of this document.
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§ 316(b) Phase II TDD
Industry Profile
Table 1-10 presents information for the in-scope, DQ respondents relating to the general configuration of their cooling water
intake system, water body from which they withdraw cooling water, and cooling system type. The table also shows that the
median intake velocity for all in-scope, DQ intakes is 1.5 feet per second. Of interest is the fact that of all in-scope DQ
respondents, 89 percent of the intakes operate traveling screens and 25 percent report some form of impingement or entrainment
reducing configuration.
Table 1-10 Statistics for all Detailed Questionnaire, In-scope Facilities
Percent
22
36
10
30
38
14
95
97
25
5
6
32
89
Percent
76
12
11
1
Percent
14
Percent
22
5
49
19
5
Cooling Water Intake Technology
cooling tower (recirculating or helper)
intake canal or channel
embayment/bay/cove
submerged shoreline intake
surface shoreline intake
submerged offshore intake
trash racks
intake screen
impingement / entrainment technology
passive intake
fish diversion or avoidance
fish handling and/or return
traveling screens
Cooling System Type
once-through
recirculating cooling
combination cooling
other cooling type
Intake Velocity (median intake velocity =1.5 ft/sec)
velocity < or = 0.5 fps
Waterbody Type
Estuary/Tidal River
Ocean
Freshwater Stream/River
Lake/Reservoir
Great Lake
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§ 316(b) Phase II TDD
Industry Profile
Table 1-11 shows similar information as in Table 1-10, however, the data is specific to the in-scope respondents to the DQ that
reported impingement/ entrainment technologies. The cooling water intake technology information in the first portion of Table
1-11 resembles that of Table 1-10. However, the percentage of intakes with fish handling / fish return technologies is
considerably higher for those reporting impingement / entrainment technologies compared to all in-scope DQ intakes. The
distribution of cooling system types are similar for Tables 1-10 and 1-11, as is the median velocity.
Table 1-11
Percent
22
34
7
34
37
5
94
98
8
2
59
Percent
80
14
5
1
Percent
18
Percent
41
4
35
19
2
Statistics for DQ Intakes with Impingement / Entrainment Technologies
Cooling Water Intake Technology
cooling tower (recirculating or helper)
intake canal or channel
embayment/bay/cove
submerged shoreline intake
surface shoreline intake
submerged offshore intake
trash racks
intake screen
passive intake
fish diversion or avoidance
fish handling and/or return
Cooling System Type
once-through
recirculating cooling
combination cooling
other cooling type
Intake Velocity (median intake velocity =1.4 ft/sec)
velocity < or = 0.5 fps
Waterbody Type
Estuary/Tidal River
Ocean
Freshwater Stream/River
Lake/Reservoir
Great Lake
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§ 316(b) Phase II TDD
Industry Profile
Table 1-12 presents the number and capacity of the intakes for the in-scope DQ respondents. Key statistics, in the Agency's
view, are the number of intakes per facility (less than two), the distribution of the number of intakes at in-scope DQ respondent
facilities (64 percent with only one intake and only 11 percent of facilities with three or more intakes), and the average percent
of intake flow used for cooling (86 percent).
Table 1-12. Number and Capacity of Intakes for In-Scope Detailed Questionnaire Facilities
Characteristic
Value
median design capacity per intake (gpd) for all intakes 219,000,000
median design capacity per facility (gpd) for all facilities 374,000,000
median capacity per intake (gpd) for facilities at or below median facility flow 100,800,000
median capacity per intake (gpd) for facilities above median facility flow 408,400,000
average number of intakes per facility for all facilities 1.6
Facilities with only 1 intake 64 %
Facilities with 2 or more intakes 36 %
Facilities with 3 or more intakes 11 %
Facilities at or below median facility flow with 2 or more intakes 26 %
Facilities above median facility flow with 2 or more intakes 46 %
Facilities at or below median facility flow with 3 or more intakes 4 %
Facilities above median facility flow with 3 or more intakes 17 %
Facilities at or below median facility flow with 4 or more intakes 1 %
Facilities above median facility flow with 4 or more intakes 8 %
Facilities with four or more intakes 4 %
Average number of intakes per facility at or below median facility flow 1.3
Average number of intakes per facility above median facility flow 1.8
Average percent of intake used for cooling per intake (all facilities) 86 %
Average percent of intake used for cooling for facilities at or below median flow 86 %
Average percent of intake used for cooling for facilities above median facility flow 87 %
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§ 316(b) Phase II TDD
Industry Profile
Table 1-13 gives a breakdown of the type offish handling / return systems at in-scope DQ facilities. Table 1-14 presents the
same information, but only for the in-scope DQ respondents that reported both fish handling / fish return systems and
impingement/ entrainment reducing configurations. Clearly, the most prevalent form offish handling / return system is the
conveyance system. See Chapter 3 of this document for descriptions of the types offish handling / return systems.
Table 1-13. Statistics for DQ Facilities Reporting Fish Handling/Return Systems
Percent Characteristic
8 fish pump
94 fish conveyance system
4 fish elevator/lift baskets
3 fish bypass
1 fish holding tank
3 other handling/return system
10 more than one of the above
Table 1-14. Statistics for Facilities Reporting Fish Handling / Returns
AND Impingement / Entrainment Systems in Detailed Quetionnaire
Percent Characteristic
14 fish pump
86 fish conveyance system
8 fish elevator/lift baskets
6 fish bypass
2 fish holding tank
6 other handling/return system
18 more than one of the above
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§ 316(b) Phase II TDD
Industry Profile
Table 1-15 presents information for the in-scope DQ respondents that reported shoreline intakes (either surface or submerged
intakes). Interestingly, the median surface water depth for surface and submerged shoreline intakes is very similar
(approximately 18 feet). The percentage of in-scope DQ respondents with shoreline intakes is split, roughly equally, between
submerged and surface configurations. The majority (77 percent) of all shoreline intakes are flush with the shore and only 8
percent protrude offshore.
Table 1-15. Statistics for Detailed Questionnaire Shoreline Intakes
characteristic
value
median surface water depth for both submerged and surface intakes (ft) 18
median surface water depth for surface intakes (ft) 17
median surface water depth for submerged intakes (ft) 18
median distance from top of intake to surface for all shoreline intakes (ft) 9
median distance from intake bottom to surface for all shoreline intakes (ft) 18
Percent of all shoreline intakes submerged 45
Percent of all shoreline intakes surface 55
Percent of all shoreline intakes flush with shore 77
Percent of all shoreline intakes recessed 15
Percent of all shoreline intakes protruding offshore 8
Percent of all shoreline intakes with skimmer/curtain/baffle wall 45
Tables 1-16 and 1-17 present basic information from the in-scope DQ respondents on the percent of fine-mesh screens and
passive intakes in-place at these facilities. In addition, Table 1-16 includes the Agency's projection of the total number of fine-
mesh screens at STQ respondents (note: the STQ did not collect information of sufficient detail to distinguish fine-mesh from
coarse-mesh screens).
Table 1-16. Statistics for Fine Mesh Screens
Characteristic
Value
Detailed Questionnaire Intakes with Fine Mesh in-place 1.3 %
Detailed Questionniare Estuarine Intakes with Fine Mesh in-place 4.3%
Projected Number of Short Technical Questionnaire Intakes with Fine Mesh in-place 6
Table 1-17. Statistics for Passive Intake
Percent
Characteristic
5.4
5.3
Percent of All Intakes reported as Passive Intakes
Percent of Estuarine Intakes reported as Passive
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§ 316(b) Phase II TDD
Industry Profile
Table 1-18 presents detailed information from the in-scope DQ respondents with offshore intakes. The percentage of
impingement / entrainment technologies on offshore intakes is very low (2 percent). The median distance from shore is 450 feet
and the median surface water depth is 30 feet at the intake. As expected, ocean intakes show the highest percentage of offshore
configurations.
Table 1-18. Statistics for Intakes Reported as Offshore in the
Characteristic
all DQ intakes Offshore
% of intakes reporting I/E Offshore
Median distance to shore for Offshore intakes (feet)
Median surface water depth at Offshore intake (feet)
Percent of estuarine intakes Offshore
Percent of ocean intakes Offshore
Percent of lake / Reservoir intakes Offshore
Percent of freshwater stream / river intakes Offshore
Percent of Great Lake intakes Offshore
Detailed Questionnaire
Value
10
2
450
30
5
41
16
11
35
Table 1-19 presents information for in-scope DQ intakes reporting canal or channel configurations. The median canal/channel
length from mouth to pumps is 1000 feet. The cross-sectional water level ranges from 470 ft (median of reported low-water
levels) to 620 ft (median of reported mean-water levels).
Table 1-19. Statistics for DQ Intakes Reporting Canal/Channel
Characteristic
Value
Median Length Canal Mouth to Pumps (ft) 1000
Median Intake X-Section-Low Water (ft) 472
Median Intake X-Section-Mean Water (ft) 617
Median Distance curtain/baffle from canal mouth (ft) 650
Median intake bay depth (ft) 17
Percent of canal/channel intakes with submerged shoreline Intakes 9 %
Percent of canal/channel intakes with surface shoreline intakes 19 %
Percent of canal/channel intakes with flush intakes 20 %
Percent of canal/channel intakes with recessed intakes 6 %
Percent of canal/channel intakes with protruding intakes 2 %
7-23
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§ 316(b) Phase II TDD Industry Profile
GLOSSARY
Baseload: A baseload generating unit is normally used to satisfy all or part of the minimum or base load of the system
and, as a consequence, produces electricity at an essentially constant rate and runs continuously. Baseload units are
generally the newest, largest, and most efficient of the three types of units.
(http://www.eia.doe.gov/cneaf/electricity/page/prim2/chapter2.html)
Combined-Cycle Turbine: An electric generating technology in which electricity is produced from otherwise lost waste
heat exiting from one or more gas (combustion) turbines. The exiting heat is routed to a conventional boiler or to heat
recovery steam generator for utilization by a steam turbine in the production of electricity. This process increases the
efficiency of the electric generating unit.
Distribution: The portion of an electric system that is dedicated to delivering electric energy to an end user.
Electricity Available to Consumers: Power available for sale to customers. Approximately 8 to 9 percent of net
generation is lost during the transmission and distribution process.
Energy Policy Act (EPACT): In 1992 the EPACT removed constraints on ownership of electric generation facilities
and encouraged increased competition on the wholesale electric power business.
Gas Combustion Turbine: A gas turbine typically consisting of an axial-flow air compressor and one or more
combustion chambers, where liquid or gaseous fuel is burned and the hot gases are passed to the turbine. The hot gases
expand to drive the generator and are then used to run the compressor.
Generation: The process of producing electric energy by transforming other forms of energy. Generation is also the
amount of electric energy produced, expressed in watthours (Wh).
Gross Generation: The total amount of electric energy produced by the generating units at a generating station or
stations, measured at the generator terminals.
Intermediate load: Intermediate-load generating units meet system requirements that are greater than baseload but less
than peakload. Intermediate-load units are used during the transition between baseload and peak load requirements.
(http://www.eia.doe.gov/cneaf/electricity/page/prim2/chapter2.html)
Internal Combustion Engine: An internal combustion engine has one or more cylinders in which the process of
combustion takes place, converting energy released from the rapid burning of a fuel-air mixture into mechanical energy.
Diesel or gas-fired engines are the principal fuel types used in these generators.
Kilowatthours (kWh): One thousand watthours (Wh)
Nameplate Capacity: The amount of electric power delivered or required for which a generator, turbine, transformer,
transmission circuit, station, or system is rated by the manufacturer.
Net Capacity: The amount of electric power delivered or required for which a generator, turbine, transformer,
transmission circuit, station, or system is rated by the manufacturer, exclusive of station use, and unspecified conditions for
1-24
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§ 316(b) Phase II TDD Industry Profile
a given time interval.
Net Generation: Gross generation minus plant use from all plants owned by the same utility.
Nonutility: A corporation, person, agency, authority, or other legal entity or instrumentality that owns electric generating
capacity and is not an electric utility. Nonutility power producers include qualifying cogenerators, qualifying small power
producers, and other nonutility generators (including independent power producers) without a designated franchised service
area that do not file forms listed in the Code of Federal Regulations, Title 18, Part 141.
(http://www.eia.doe.gov/emeu/iea/glossary.html)
Other Prime Movers: Methods of power generation other than steam turbine, combined-cycle, gas
combustion turbine, internal combustion engine, and water turbine Other prime movers include: geothermal,
solar, wind, and biomass.
Peakload: A peakload generating unit, normally the least efficient of the three unit types, is used to meet requirements
during the periods of greatest, or peak, load on the system.
(http://www.eia.doe.gov/cneaf/electricity/page/prim2/chapter2.html)
Power Marketers: Business entities engaged in buying, selling, and marketing electricity. Power marketers do not
usually own generating or transmission facilities. Power marketers, as opposed to brokers, take ownership of the electricity
and are involved in interstate trade. These entities file with the Federal Energy Regulatory Commission for status as a
power marketer, (http://www.eia.doe.gov/cneaf/electricity/epavl/glossary.html)
Power Brokers: An entity that arranges the sale and purchase of electric energy, transmission, and other services
between buyers and sellers, but does not take title to any of the power sold.
(http://www.eia.doe.gov/cneaf/electricity/epavl/glossary.html)
Prime Movers: The engine, turbine, water wheel or similar machine that drives an electric generator. Also, for reporting
purposes, a device that directly converts energy to electricity, e.g., photovoltaic, solar, and fuel cell(s).
Public Utility Regulatory Policies Act (PURPA): In 1978 PURPA opened up competition in the electricity
generation market by creating a class of nonutility electricity-generating companies referred to as "qualifying facilities."
Reliability: Electric system reliability has two components: adequacy and security. Adequacy is the ability of the electric
system to supply customers at all times, taking into account scheduled and unscheduled outages of system facilities.
Security is the ability of the electric system to withstand sudden disturbances, such as electric short circuits or unanticipated
loss of system facilities, (http://www.eia.doe.gov/cneaf/electricity/epavl/glossary.html)
Steam Turbine: A generating unit in which the prime mover is a steam turbine. The turbines convert thermal energy
(steam or hot water) produced by generators or boilers to mechanical energy or shaft torque. This mechanical energy is
used to power electric generators, including combined-cycle electric generating units, that convert the mechanical energy to
electricity.
Transmission: The movement or transfer of electric energy over an interconnected group of lines and associated
equipment between points of supply and points at which it is transformed for delivery to consumers, or is delivered to other
7-25
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§ 316(b) Phase II TDD Industry Profile
electric systems. Transmission is considered to end when the energy is transformed for distribution to the consumer.
Utility: A corporation, person, agency, authority, or other legal entity or instrumentality that owns and/or operates
facilities within the United States, its territories, or Puerto Rico for the generation, transmission, distribution, or sale of
electric energy primarily for use by the public and files forms listed in the Code of Federal Regulations, Title 18, Part 141.
Facilities that qualify as cogenerators or small power producers under the Public Utility Regulatory Policies Act (PURPA)
are not considered electric utilities, (http://www.eia.doe.gov/emeu/iea/glossary.html)
Water Turbine: A unit in which the turbine generator is driven by falling water.
Watt: The electrical unit of power. The rate of energy transfer equivalent to 1 ampere flowing under the pressure of 1 volt
at unity power factor. (Does not appear in text)
Watthour (Wh): An electrical energy unit of measure equal to 1 watt of power supplied to, or take from, an electric
circuit steadily for 1 hour. (Does not appear in text)
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§ 316(b) Phase II TDD Industry Profile
REFERENCES
U.S. Department of Energy (U.S. DOE). 2002. Energy Information Administration (EIA). Status of State Electric Industry
Restructuring Activity as of March 2002. At: http://www.eia.doe.gov/cneaf/electricity/chg_str/regmap.html
U.S. Department of Energy (U.S. DOE). 2001. Energy Information Administration (EIA). Annual Energy Outlook 2002 With
Projections to 2020. DOE/EIA-0383(2002). December 2001.
U.S. Department of Energy (U.S. DOE). 2000a. Energy Information Administration (EIA). Electric Power Industry
Overview. At: http://www.eia.doe.gov/cneaf/electricity/page/prim2/toc2.html.
U.S. Department of Energy (U. S. DOE). 2000b. Energy Information Administration (EIA). Electric Power Annual 1999
Volume I. DOE/EIA-0348(99)/1.
U.S. Department of Energy (U. S. DOE). 2000c. Energy Information Administration (EIA). Electric Power Annual 1999
Volume II. DOE/EIA-0348(99)/2.
U.S. Department of Energy (U.S. DOE). 1999a. Form EIA-860A (1999). Annual Electric Generator Report - Utility.
U.S. Department of Energy (U.S. DOE). 1999b. Form EIA-860B (1999). Annual Electric Generator Report - Nonutility.
U.S. Department of Energy (U.S. DOE). 1999c. Form EIA-861 (1999). Annual Electric Utility Data.
U.S. Department of Energy (U.S. DOE). 1999d. Form EIA-759 (1999). Monthly Power Plant Report.
U.S. Department of Energy (U.S. DOE). 1998a. Energy Information Administration (EIA). Electric Power Annual 1997
Volume I. DOE/EIA-0348(97/1).
U.S. Department of Energy (U.S. DOE). 1998b. Energy Information Administration (EIA). Electric Power Annual 1997
Volume II. DOE/EIA-0348(97/1).
U.S. Department of Energy (U.S. DOE). 1998c. Form EIA-861 (1998). Annual Electric Utility Data.
U.S. Department of Energy (U.S. DOE). 1996a. Energy Information Administration (EIA). Electric Power Annual 1995
Volume I. DOE/EIA-0348(95)/1.
U.S. Department of Energy (U.S. DOE). 1996b. Energy Information Administration (EIA). Electric Power Annual 1995
Volume II. DOE/EIA-0348(95)/2.
U.S. Department of Energy (U. S. DOE). 1996c. Energy Information Administration (EIA). Impacts of Electric Power
Industry Restructuring on the Coal Industry. At: http://www.eia.doe.gov/cneaf/electricity/chg_str_fuel/html/chapterl.html.
U.S. Department of Energy (U.S. DOE). 1995a. Energy Information Administration (EIA). Electric Power Annual 1994
Volume I. DOE/EIA-0348(94/1).
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§ 316(b) Phase II TDD Industry Profile
U.S. Department of Energy (U.S. DOE). 1995b. Energy Information Administration (EIA). Electric Power Annual 1994
Volume II. DOE/EIA-0348(94/1).
U.S. Environmental Protection Agency (U.S. EPA). 2000. Section 316(b) Industry Survey. Detailed Industry Questionnaire:
Phase II Cooling Water Intake Structures and Industry Short Technical Questionnaire: Phase II Cooling Water Intake
Structures, January, 2000 (OMB Control Number 2040-0213). Industry Screener Questionnaire: Phase I Cooling Water
Intake Structures, January, 1999 (OMB Control Number 2040-0203).
U.S. Geological Survey (USGS). 1995. Estimated Use of Water in the United States in 1995.
At: http://water.usgs.gov/watuse/pdfl 995/html/.
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§ 316(b) Phase II TDD Costing Methodology
Chapter 2: Costing Methodology for
Model Plants
INTRODUCTION
This chapter presents the methodologies used by the Agency to develop cost estimates at the model plant level for the
proposed rule and regulatory options considered. The Agency costs for 539 model plants and these were then used in
the economic analysis to scale to the total universe of in-scope facilities. For the model-plant specific projected
compliance costs of the proposed rule, see Appendix A of this document. Under the proposed rule, facilities have the
option of conducting a cost test against the compliance costs developed by the Agency for support of the regulatory
requirements of the rule. The costs presented in Appendix A, and developed based on the methodology presented in
this chapter, would form the basis of the "significantly greater" cost test in the proposed rule.
The term model plant is used frequently throughout this document. The Agency notes that model plants are not actual
existing facilities. Model Plants are statistical representations of existing facilities (or fractions of existing facilities).
Therefore, the cost estimates developed for the rule should not be considered to reflect those exactly of a particular
existing facility. However, in the Agency's view, the national estimates of benefits, compliance costs, and economic
impacts are representative of those expected from the industry as a whole.
2.1 COOLINS WATER INTAKE STRUCTURE COSTS
EPA developed distinct sets of intake structure and conduit system costs for existing source model plants expected to
(1) upgrade screen systems only, (2) upgrade cooling systems and intake structures, and (3) upgrade cooling systems
only.
For those plants projected to incur costs of cooling water intake structure upgrades (but not flow-reducing cooling
system conversions), the Agency estimates that intake fanning/expansion would be necessary for the majority of plants
projected to install entrainment reducing fine-mesh screens. Therefore, the Agency developed capital costs for these
scenarios that incorporate the costs of expanding/fanning or adding an additional bay to an existing intake structure in
order to upgrade to fine-mesh screens. Because fine-mesh screens have reduced open cross-sectional area when
compared to coarse-mesh screens, the Agency considers the intake expansion/fanning costs to be appropriate in these
cases. Even though there is not a set of velocity-based requirements for this proposal, the Agency projects that the
model plants expected to upgrade their intake screens from coarse to fine-mesh would reduce their through-screen
velocity from the median facility value of 1.5 feet/second to 1.0 feet/second as a result of this technology change. In
part, in the Agency's view, the reduced velocity would adopted for the operational requirements of the screens and to
balance the impingement reduction benefits of lower velocities with the physical constraints of velocity reduction for
existing intake structures. The Agency utilized costs developed for fine-mesh screens with a through-screen velocity
of 1.0 feet/second to size the intake for the full design, once-through intake flow. The operation and maintenance
(O&M) costs of these screens are calculated based on the same principle. These capital and O&M costs for fine-mesh
screens were developed for the New Facility 316(b) rule and are utilized for existing facilities with some modifications.
The Agency applies a capital cost construction inflation factor (in addition to a "retrofit" factor discussed in section
2.1
-------
§ 316(b) Phase II TDD
Costing Methodology
2.6) to account for the expansion/fanning of the intake structure, but does not estimate further O&M costs for this one-
time activity. Those plants that additionally would install fish handling/return systems to the upgraded screens incur
capital and operation and maintenance costs developed based on the size of the larger size screens. See Sections 2.1.1
and 2.1.2 for the development of the cost estimates for capital and O&M costs for fine-mesh screens.
The Agency developed existing facility construction factors (used in addition to "retrofit" factors discussed in Section
2.6) based on the average ratio of intake modification construction costs to costs derived from CWIS equations
developed for New Facility projects. Thus the differences reflect differences in construction costs for nuclear and non-
nuclear and differences in CWIS installation capital costs. Table 2-1 presents the construction factors for a variety of
compliance technologies used as the basis for the costs estimated for this proposal and regulatory options.
Table 2-1 CWIS Technology Flow Sizing and Construction Factors for Existing Facilities
Compliance Cooling
System Type Plant Type
Flow Used to size
Cooling Water Intake
Technology
Compliance Cooling Construction
Water Intake Factor for
Technology Scenario
Non-Cooling Tower
Non-Cooling Tower
Non-Cooling Tower
Non-Cooling Tower
Non-Cooling Tower
Non-Cooling Tower
Non-nuclear
Non-nuclear
Non-nuclear
Nuclear
Nuclear
Nuclear
100% of Once-through
Baseline Design Intake
100% of Once-through
Baseline Design Intake
100% of Once-through
Baseline Design Intake
100% of Once-through
Baseline Design Intake
100% of Once-through
Baseline Design Intake
100% of Once-through
Baseline Design Intake
Fish Handling
Fine Mesh Screens
Fine Mesh Screens
w/ Fish Handling
Fish Handling
Fine Mesh Screens
Fine Mesh Screens
w/ Fish Handling
None
30%*
15%*
None
65%*
30%*
* Existing facility construction factors based on average ratio of intake modification construction costs to costs derived
from CWIS equations developed for New Facility projects. Thus the differences reflect differences in construction
costs for nuclear and non-nuclear and differences in CWIS installation capital costs.
** For cooling sizing of cooling towers and appropriate flow for determining the costs of retrofitted cooling water
systems, see Section 2.2.
Intake modification construction costs are based on the following general framework:
• An increase in screen area of 50% due to conversion from coarse-mesh to fine-mesh.
• Screen size increase will involve demolition of one side of intake and extension in that direction.
• Installation/removal of sheet piling.
• Concrete demolition of one column and one side (cost doubled for nuclear*).
2.2
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§ 316(b) Phase II TDD Costing Methodology
• Excavation (cost doubled for nuclear*).
• Additional concrete foundation.
• Additional concrete side and back wall.
• Additional concrete column.
* EPA doubled costs to account for concerns that use of blasting and high-impact equipment may be limited at nuclear
facilities.
Modification construction costs were then increased by the following cost factors:
Item Factor
Mobilization/Demobilization 3 %
Engineering 10 %
Site Work 5 %
Electrical 10 %
Controls 3 %
Contingency 10 %
Allowance 5 %
For those model plants projected to only incur costs of installing fish handling/return systems to existing screens, the
Agency developed costs by estimating the size of coarse mesh, 1.5 feet/sec screens. The through-screen velocity of 1.5
feet/sec is the median velocity for all 316b survey respondents. The Agency determined that use of this metric to size
the fish handling/return systems was appropriate for the variety of plants projected to incur their capital and operation
and maintenance costs as a result of this proposal. The capital cost estimates used here for installation of the fish
handling/return systems to existing screens were those developed for new facilities, with an additional inflation (or
"retrofit") factor to account for the issues discussed in Section 2.6 below. Section 2.1.1 presents the cost estimates
developed for new facilities for fish handling/return systems.
For the those plants projected to incur costs of cooling system conversions and entrainment-reducing fine-mesh screens,
the Agency considered the existing intake structures to be of a size too large for a realistic screen retrofit. Therefore,
in these cases, the Agency estimated that one-half of the intake bay(s) would be blocked/closed and the retrofitted fine-
mesh intake screens would apply to only one-half of the size of the original intake. The Agency considers this a
reasonable approach to estimating realistic scenarios where the average plant (as demonstrated in Table 1-12) utilizes
multiple intake bays. In the Agency's view, the plant, when presented an equal opportunity option, would utilize the
potential cost savings option of installing the fine-mesh screens on only the maximum intake area necessary. For those
plants also projected to incur costs of the addition offish handling/return systems, the Agency estimates the system size
based on this concept of closure/blockage of one-half of the existing intake. The operation and maintenance costs are
also developed using this size of an intake. Therefore, for the case of each of these retrofit activities, the installed
capital costs and operation and maintenance costs of the intake screens and fish handling/return systems are
approximately one-half of those for a full size screen replacement.
2.3
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§ 316(b) Phase II TDD Costing Methodology
For those model plants converting their cooling systems from once-through to recirculating systems but not incurring
costs of entrainment-reducing intake screens, the existing intake structures are considered to be operational without
significant modification (as was the case in the example of the conversions discussed in Chapter 4). In turn, the plants
would incur no additional operation and maintenance costs.
The Agency notes that in addition to the intake structure capital costs described above, the capital costs are inflated by
the "retrofit" capital cost factor of 30 percent described in section 2.6, below. Therefore, the Agency views the retrofit
capital costs developed for upgrading intake screens and structures to be appropriate for existing model plants.
2.1.1 Capital and O&M Costs of Intake Structures and Conduit Systems
Installation of traveling screens with fish baskets for New Facilities
Single-entry, single-exit vertical traveling screens (conventional traveling screens) contain a series of wire mesh screen
panels that are mounted end to end on a band to form a vertical loop. As water flows through the panels, debris and
fish that are larger than the screen openings are caught on the screen or at the base of each panel in a basket. As the
screen rotates around, each panel in turn reaches a top area where a high-pressure jet spray wash pushes debris and
fish from the basket into a trash trough for disposal. As the screen rotates over time, the clean panels move down, back
into the water to screen the intake flow.
Conventional traveling screens can be operated continuously or intermittently. However, when these screens are fitted
with fish baskets (also called modified conventional traveling screens or Ristroph screens), the screens must be operated
continuously so that fish that are collected in the fish baskets can be released to a bypass/return using a low pressure
spray wash when the basket reaches the top of the screen. Once the fish have been removed, a high pressure jet spray
wash is typically used to remove debris from the screen. In recent years, the design of fish baskets has been refined
(e.g., deeper baskets, smoother mesh, better balance) to decrease chances of injury and mortality and to better retain
fish (i.e., prevent them from flopping out and potentially being injured). Methods used to protect fish include the
Stabilized Integral Marine Protective Lifting Environment (S.I.M.P.L.E.) developed by Brackett Green and the
Modified Ristroph design by U.S. Filter.
U.S. Filter's conventional (through flow) traveling screens are typically manufactured in widths ranging from two feet
to at least 14 feet, for channel depths of up to 100 feet, although custom design is possible to fit other dimensions.
Flow
To calculate the flow through a screen panel, the width of the screen panel is multiplied by the water depth and, using
the desired flow velocities (1 foot per second and 0.5 foot per second), is converted to gallons per minute assuming a
screen efficiency of 50 percent. The calculated flows for selected screen widths, water depths, and well depths are
presented in Tables 2-30 and 2-31. For flows greater than this, a facility would generally install multiple screens or
use a custom design.
Well depth includes the height of the structure above the water line. The well depth can be more than the water depth
by a few to tens of feet. The flow velocities used are representative of a flow speed that is generally considered to be
fish friendly particularly for sensitive species (0.5 fps), and a flow speed that may be more practical for some facilities
2.4
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§ 316(b) Phase II TDD
Costing Methodology
to achieve but typically provides less fish protection. The water depths and well depths are approximate and may vary
based on actual site conditions.
Table 2-2. Average
Flow Through A Traveling Water Screen (gpm) 1
for a Flow Velocity of 1.0 fps
Well Depth
(ft)
10
25
50
75
100
Water Depth
(ft)
8
20
30
50
65
Basket
2
4000
9000
13,000
22,000
29,000
Panel Screening
Width (ft)
5 10
9000
22,000
34,000
56,000
73,000
18,000
45,000
67,000
112,000
146,000
14 |
25,000
63,000
94,000
157,000
204,00o|
Table 2-3. Average Flow Through A Traveling Water Screen (gpm) for a Flow
Velocity of 0.5 fps |
Well Depth
(ft)
10
25
50
75
100
Water Depth
(ft)
8
20
30
50
65
Basket
2
2000
4000
7000
11,000
15,000
Screening
5
4000
11,000
17,000
28,000
36,000
Panel Width (ft)
10
9000
22,000
34,000
56,000
73,000
14 |
13,000|
31,000
47,000
79,000
102,00o|
Capital Costs
Equipment Cost
Basic costs for screens with flows comparable to those shown in the above tables are presented in Tables 2-4 and 2-5.
Table 2-4 contains estimated costs for basic traveling screens without fish handling features, that have a carbon steel
structure coated with epoxy paint. The costs presented in Table 2-33 are for traveling screens with fish handling
features including a spray system, a fish trough, housings and transitions, continuous operating features, a drive unit,
frame seals, and engineering. Installation costs and spray pump costs are presented separately below.
2.5
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§ 316(b) Phase II TDD
Costing Methodology
Table 2-4. Estimated Equipment Cost for Traveling Water Screens Without Fish Handling
Features1 (1999 Dollars)
Well Depth
(ft)
Basket Screening Panel Width (ft)
5 10
$30,000
$35,000
$55,000
$75,000
$115,000
$35,000
$45,000
$70,000
$100,000
$130,000
$45,000
$60,000
$105,000
$130,000
$155,000
$65,00
$105,00
$145,00
$175,00
$200,00
1) Cost includes carbon steel structure coated with epoxy paint and non-metallic trash baskets with
Tyrje 304 stainless mesh and intermittent operation comrjonents
Source: Vendor estimates.
Table 2-5. Estimated Equipment Cost for Traveling Water Screens With Fish Handling
Features1 (1999 Dollars)
Well depth
(ft)
Basket Screening Panel Width (ft)
5 10
14
10
25
50
75
100
$63,500
$81,250
$122,500
$163,750
$225,000
$73,500
$97,500
$152,000
$210,000
$267,500
$94,000
$133,000
$218,000
$283,000
$348,000
$135,500
$214,000
$319,500
$414,500
$504,500
1) Cost includes carbon steel screen structure coated with epoxy paint and non-metallic fish
handling panels, spray systems, fish trough, housings and transitions, continuous operating
features, drive unit, frame seals, and engineering (averaged over 5 units). Costs do not include
differential control system, installation, and spray wash pumps.
Source: Vendor estimates.
2.6
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§ 316(b) Phase II TDD Costing Methodology
Installation Cost
Installation costs of traveling screens for New Facilities are based on the following assumptions of a typical average
installation requirement for a hypothetical scenario. Site preparation and earth work are calculated based on the
following assumptions:
• Clearing and grubbing: Clearing light to medium brush up to 4" diameter with a bulldozer.
• Earthwork: Excavation of heavy soils. Quantity is based on the assumption that earthwork increases with
screen width.
• Paving and surfacing: Using concrete 8" thick and assuming that the cost of pavement attributed to screen
installation is 6x3 yards for the smallest screen and 25x6 yards for the largest screen.
• Structural concrete: The structural concrete work attributed to screen installation is four 12"xl2" reinforced
concrete columns with depths varying between 1.5 yards and 3 yards. There is more structural concrete work
for a water intake structure, however, for new source screens and retrofit screens, only a portion of the intake
structural cost can be justifiably attributed to the screen costs. For new screens, most of the concrete structure
work is for developing the site to make it accessible for equipment and protect it from hydraulic elements,
which are necessary for constructing the intake itself. For retrofits, some of the structural concrete will already
exist and some of it will not be needed since the intake is already in place and only the screen needs to be
installed. All unit costs used in calculating on-shore site preparation were obtained from Heavy Construction
Cost Data 1998 (R. S. Means, 1997b).
Table 2-6 presents site preparation installation costs that apply to traveling screens both with and without fish handling
features. The total onshore construction costs are for a screen to be installed in a 10-foot well depth. Screens to be
installed in deeper water are assumed to require additional site preparation work. Hence for costing purposes it is
assumed that site preparation costs increase at a rate of an additional 25 percent per depth factor (calculated as the ratio
of the well depth to the base well depth of 10 feet) for well depths greater than 10 feet. Table 2-7 presents the estimated
costs of site preparation for four sizes of screen widths and various well depths.
2.7
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§ 316(b) Phase II TDD
Costing Methodology
Table 2-6. Estimated Installation (Site Preparation) Costs for Traveling Water
Screens Installed at a 10-foot Well Depth (1999 Dollars)
Screen Clearing Clearing Earth
Width and Cost1 Work
(ft) Grabbing (cy)
(acre)
Earth
Work
Cost1
Paving and Paving Structura Structural Total
Surfacing Cost1 1 Cost Onshore
Using Concrete Construction |
Concrete (cy) Costs
(sy)
2
5
10
14
0.1
0.35
0.7
1
$250
$875
$1,750
$2,500
200 $17,400
500 $43,500
1000 $87,000
1400 $121,800
$250
$560
$1,050
$2,100
$680
$790
$900
$1,350
$19,OOC
$46,OOC
$91,OOC
$128,OOC
ft = feet, cy=cubic yard, sy=square yard
1) Clearing cost @ $2,500/acre, earth work cost @ $87/cubic yard, paving cost @ $14/square yard, structural cost @
$l,250/cubicyard.
Source of unit costs: Heavy Construction Cost Data 1998 (R.S. Means, 1997b).
Table 2-7. Estimated Installation (Site Preparation, Construction, and Onshore Installation) Costs for
Traveling Water Screens of Various Well Depths (1999 Dollars)
Well Depth
(ft)
Screen Panel Width (ft)
5 10
$19,000
$31,000
$43,000
$55,000
$67.000
$46,000
$75,000
$104,000
$132,000
$161,000
$91,000
$148,000
$205,000
$262,000
$319,000
$128,000
$208,000
$288,000
$368,000
$448,000
Source: R.S. Means (1997b) and vendor estimates.
EPA developed a hypothetical scenario of a typical underwater installation to estimate an average cost for underwater
installation costs. EPA estimated costs of personnel and equipment per day, as well as mobilization and demobilization.
Personnel and equipment costs would increase proportionately based on the number of days of a project, however
mobilization and demobilization costs would be relatively constant regardless of the number of days of a project since
the cost of transporting personnel and equipment is largely independent of the length of a project. The hypothetical
project scenario and estimated costs are presented in Box 2-1. Hypothetical scenario was used to develop installation
cost estimates as function of screen width/well depth. Installation costs were then included with total cost equations.
To cost facilities, EPA selected appropriate screen width based on flow.
As shown in the hypothetical scenario in Box 2-1, the estimated cost for a one-day installation project would be $8,000
($4,500 for personnel and equipment, plus $3,500 for mobilization and demobilization). Using this one-day cost
estimate as a basis, EPA generated estimated installation costs for various sizes of screens under different scenarios.
These costs are presented in Table 2-7. The baseline costs for underwater installation include the costs of a crew of
divers and equipment including mobilization and demobilization, divers, a barge, and a crane. The number of days
needed is based on a minimum of one day for a screen of less than 5 feet in width and up to 10 feet in well depth. Using
best professional judgement (BPJ), EPA estimated the costs for larger jobs assuming an increase of two days for every
2.8
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§ 316(b) Phase II TDD Costing Methodology
imfease in well depth size ana ot one day tor every increase in screen width size.
Box 2-1. Example Scenario for Underwater Installation of an Intake
Screen System
This project involves the installation of 12, t-24 passive intake screens onto a manifold inlet
system. Site conditions include a 20-foot water depth, zero to one-foot underwater
visibility, 60-70 °F water temperature, and fresh water at an inland. The installation is
assumed to be 75 yards offshore and requires the use of a barge or vessel with 4-point
anchor capability and crane.
Job Description:
Position and connect water intake screens to inlet flange via 16 bolt/nut connectors. Lift,
lower, and position intake screens via crane anchored to barge or vessel. Between 4 and 6
screens of the smallest size can be installed per day per dive team, depending on favorable
environmental conditions.
Estimated Personnel Costs:
Each dive team consists of 5 people (1 supervisor, 2 surface tenders, and 2 divers), the
assumed minimum number of personnel needed to operate safely and efficiently. The labor
rates are based on a 12-hour work day. The day rate for the supervisor is $600. The day
rate for each diver is $400. The day rate for each surface tender is $200. Total base day
rate per dive team is $1,800.
Estimated Equipment Costs:
Use of hydraulic lifts, underwater impact tools, and other support equipment is $450 per
day. Shallow water air packs and hoses cost $100 per day. The use of a crane sufficient to
lift the 375 Ib t-24 intakes is $300 per day. A barge or vessel with 4-point anchor capability
can be provided by either a local contractor or the dive company for $1,800 per day (cost
generally ranges from $1,500-$2,000 per day). This price includes barge/vessel personnel
(captain, crew, etc) but the barge/vessel price does not include any land/waterway
transportation needed to move barge/vessel to inland locations. Using land-based crane and
dive operations can eliminate the barge/vessel costs. Thus total equipment cost is $2,650
per day.
Estimated Mobilization and Demobilization Expenses:
This includes transportation of all personnel and equipment to the job site via means
necessary (air, land, sea), all hotels, meals, and ground transportation. An accurate estimate
on travel can vary wildly depending on job location and travel mode. For this hypothetical
scenario, costs are estimated for transportation with airfare, and boarding and freight and
would be $3,500 for the team (costs generally range between $3,000 and $4,000 for a
team).
-------
§ 316(b) Phase II TDD
Costing Methodology
Table 2-8. Estimated Underwater Installation Costs
for Various Screen Widths and Well Depths1 (1999 Dollars)
Well Depth
(ft)
Basket Screening Panel Width (ft)
5 10
14
10
25
50
75
100
$8,000
$17,000
$26,000
$35,000
$44,000
$12,500
$21,500
$30,500
$39,500
$48,500
$17,000
$26,000
$35,000
$44,000
$53,000
1) Based on hypothetical scenario of crew and equipment costs of $4,500 per day and
mobilization and demobilization costs of $3,500 (see Box 2-1).
$21,500|
$30,500|
$39,50C
$48,50C
$57,5001
Table 2-9 presents total estimated installation costs for traveling screens. Installation costs for traveling screens with
fish handling features and those without fish handling features are assumed to be similar.
Table 2-9. Estimated Total Installation Costs for Traveling Water Screens1 (1999
Dollars)
Well Depth
(ft)
Basket Screening Panel Width (ft)
5 10
14
10
25
50
75
100
$27,000
$48,000
$69,000
$90,000
$111,000
$58,500
$96,500
$134,500
$171,500
$209,500
$108,000
$174,000
$240,000
$306,000
$372,000
$149,50C
$238,50C
$327,500
$416,500
$505,50C
1) Includes site preparation, and onshore and underwater construction and installation
costs.
Total Estimated Capital Costs for New Facilities
The installation costs in Table 2-9 were added to the equipment costs in Tables 2-4 and 2-5 to derive total equipment
and installation costs for traveling screens with and without fish handling features. These estimated costs are presented
in Tables 2-10 and 2-11. The flow volume corresponding to each screen width and well depth combination varies based
on the through screen flow velocity. These flow volumes were presented in Tables 2-12 and 2-13 for flow velocities
of 1.0 fps and 0.5 fps, respectively.
2.10
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§ 316(b) Phase II TDD
Costing Methodology
Table 2-10. Estimated Total Capital Costs for Traveling Screens Without Fish
Features (Equipment and Installation)1 (1999 Dollars)
Well Depth
(ft)
10
25
50
75
100
Handling
Screening Basket Panel Width (ft)
2
$57,000
$83,000
$124,000
$165,000
$226,000
5
$93,500
$141,500
$204,500
$271,500
$339,500
10
$153,000
$234,000
$345,000
$436,000
$527,000
14
$214,500
$343,500
$472,500
$591,500
$705,500
1) Costs include carbon steel structure coated with an epoxy paint, non-metallic trash baskets with Type
304 stainless mesh, and intermittent operation components and installation.
Table 2-11. Estimated Total Capital Costs for Traveling Screens With Fish Handling Features)
(Equipment and Installation)1 (1999 Dollars)
Well Depth
(ft)
10
25
50
75
100
Screening Basket Panel Width (ft)
2
$90,500
$129,250
$191,500
$253,750
$336,000
5
$132,000
$194,000
$287,000
$381,500
$477,000
10
$202,000
$307,000
$458,000
$589,000
$720,000
14
$285,000
$453,000
$647,000
$831,000
$1,010,000
1) Costs include non-metallic fish handling panels, spray systems, fish trough, housings and transitions,
continuous operating features, drive unit, frame seals, engineering (averaged over 5 units), and
installation. Costs do not include differential control system and spray wash pumps.
Tables 2-12 and 2-13 present equations that can be used to estimate costs for traveling screens at 0.5 fps and 1.0 fps,
respectively. See the Appendix B for cost curves and equations.
Table 2-12. Capital Cost Equations for Traveling Screens for Velocity of 0.5 fps 1
Traveling Screens with Fish Handling
Screen
Width
(ft)
2
5
10
14
Equipment
Equation1
y=6E-08x3-0.0014x2 +
28.994x + 36372
y = lE-09x3 - 8E-05x2 +
12.223x + 80790
y = 5E-10x3 - 9E-05x2 +
12.726x + 88302
y = 6E-10x3-0.0001x2 +
15. 874x + 91207
Correlation
Coefficient
R2 = 0.9992
R2 = 0.994
R2 = 0.9931
R2 = 0.995
Traveling Screens without Fish Handling I
Equipment
Equation1
y=5E-08x3-0.0013x2 +
20.892x + 18772
y = 2E-09x3- 0.000 Ix2 +
9.7773x + 54004
y = 5E-03x3 - 9E-05x2 + 10.143x
+ 63746
y=5E-10x3-0.0001x2 +
12.467x + 65934
Correlation 1
Coefficient 1
R2 = 0.9991 1
R2 = 0.9995
R2 = 0.9928
R2 = 0.9961
2.11
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§ 316(b) Phase II TDD
Costing Methodology
1) x is the flow in gpm y is the capital cost in dollars
Table 2-13. Capital Cost Equations for Traveling Screens for Velocity of 1 fps 1
Screen
Width
(ft)
Traveling Screens with Fish Handling
Equipment
Correlation
Equation1 Coefficient
Traveling Screens without Fish Handling 1
Equipment 1
Correlation 1
Equation1 Coefficient |
2 y = 8E-09x3 - 0.0004x2 + 15.03x R2 = 0.9909 y = 8E-09x3 - 0.0004x2 +
+ 33044 10.917x+16321
R2 = 0.9911
5 y = 2E-10x3-3E-05x2 + 6.921x R2 = 0.9948 y = 3E-10x3 - 4E-05x2 + 5.481x R2 = 0.9962
+ 68688 + 44997
10 y=5E-llx3-2E-05x2 + 6.2849x R2 = 0.9906 y = 5E-llx3 - 2E-05x2 + 5.0073x R2 = 0.9902
+ 88783 +64193
14 y=5E-llx3-2E-05x2 + 7.1477x R2 = 0.9942 y = 5E-llx3 - 2E-05x2 + 5.6762x R2 = 0.9952
+ 113116 +81695
1) x is the flow in gpm y is the capital cost in dollars.
Operation and Maintenance (O&M) Costs for Traveling Screens
O&M costs for traveling screens vary by type, size, and mode of operation of the screen. Based on discussions with
industry representatives, EPA estimated annual O&M cost as a percentage of total capital cost. The O&M cost factor
ranges between 8 percent of total capital cost for the smallest size traveling screens with and without fish handling
equipment and 5 percent for the largest traveling screen since O&M costs do not increase proportionately with screen
size. Estimated annual O&M costs for traveling screens with and without fish handling features are presented in Tables
2-4 and 2-5, respectively. As noted earlier, the flow volume corresponding to each screen width and well depth
combination varies based on the through screen flow velocity. These flow volumes were presented in Tables 2-14 and
2-15 for flow velocities of 1.0 fps and 0.5 fps, respectively.
Table 2-14. Estimated Annual O&M Costs for Traveling Water Screens
Without Fish Handling Features
(Carbon Steel - Standard Design)1 (1999 Dollars)
Screen Panel Width (ft)
Well Depth
(ft)
10
25
50
75
100
2
$4560
$5810
$8680
$11,550
$13,560
5
$6545
$9905
$12,270
$16,290
$16,975
10
$7650
$14,040
$17,250
$21,800
$26,350
14
$12,870
$17,175
$23,625
$29,575
$35,275
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§ 316(b) Phase II TDD
Costing Methodology
ll) Annual O&M costs range between 8 percent of total capital cost for the smallest size traveling
(screens with and without fish handling equipment and 5 percent for the largest traveling screen.
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§ 316(b) Phase II TDD
Costing Methodology
Table 2-15. Estimated Annual O&M Costs for Traveling Water Screens
With Fish Handling Features (Carbon Steel Structure, Non-Metallic Fish Handling Screening
Panel)1 (1999 Dollars)
Well Depth
(ft)
Screen Panel Width (ft)
5 10
14
10
25
50
75
100
$7240
$9048
$13,405
$17,763
$20,160
$9240
$13,580
$17,220
$22,890
$23,850
$10,100
$18,420
$22,900
$29,450
$36,000
$17,100
$22,650
$32,350
$41,550
$50,500
1) Annual O&M costs range between 8 percent of total capital cost for the smallest size traveling
screens with and without fish handling equipment and 5 percent for the largest traveling screen.
The tables below present O&M cost equations generated from the above tables for various screen sizes and water
depths at velocities of 0.5 fps and 1 fps, respectively. The "x" value of the equation is the flow and the "y" value is
the O&M cost in dollars.
Table 2-16: Annual O&M Cost Equations for Traveling Screens Velocity 0.5 fps
Traveling Screens with Fish Handling
Screen Equipment
Width Correlation
(ft) Equation1 Coefficient
Traveling Screens without Fish Handling
Equipment
Correlation
Equation1 Coefficient
R2 = 0.9943 y=-2E-05x2+1.0121x+ R2 = 0.9965
2392.4
R2 = 0.9943 y = -7E-06x2 + 0.6204x + R2 = 0.9956
4045.7
R2 = 0.9907 y = 9E-1 lx3 - lE-05x2 + R2 = 0.9997
0.8216x+1319.5
R2 = 0.9912 y = 8E-12x3 - 2E-06x2 + R2 = 0.9922
0.3899x +7836.7
1) x is the flow in gpm and y is the annual O&M cost in dollars.
2 y=-3E-05x2+1.6179x
3739.1
5 y = -lE-05x2 + 0.8563x
5686.3
10 y = -2E-06x2 + 0.5703x -
5864.4
14 y = 5E-12x3 - lE-06x2 +
0.4835x+10593
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§ 316(b) Phase II TDD
Costing Methodology
Table 2-17. Annual O&M Cost Equations for Traveling Screens Velocity 1 fps
Traveling Screens without Fish Handling
Equipment
Correlation
Coefficient
Correlation
Coefficient
y = -8E-06x2 + 0.806x + 3646.7 R2 = 0.982
R2 = 0.9954
y = -4E-06x2 + 0.5035x + 2334 R2 = 0.9853
y=-2E-06x2 + 0.3312x
3621.1
y = -3E-06x2 + 0.4585x
5080.7
R2 = 0.9915
R2 = 0.9903
1) x is the flow in gpm and y is the annual O&M cost in dollars.
y = -6E-07x2
5705.3
y= !E-llx3-3E-06x2
0.4047x+ 1359.4
y = -3E-13x3 - 4E-08x2
0.2081x+11485
y = 4E-13x3 - 3E-07x2
0.1715x +8472.1
Screen
Width
(ft)
Traveling Screens with Fish Handling
Equipment
Adding fish baskets to existing traveling screens
Capital Costs
Table 2-17 presents estimated costs offish handling equipment without installation costs. These estimated costs
represent the difference between costs for equipment with fish handling features (Table 2-33) and costs for equipment
without fish handling features (Table 2-4), plus a 20 percent add-on for upgrading existing equipment (mainly to
convert traveling screens from intermittent operation to continuous operation).: These costs would be used to estimate
equipment capital costs for upgrading an existing traveling water screen to add fish protection and fish return
equipment.
Table 2-18.
Well Depth
(ft)
10
25
50
75
100
Source: Vendor estimates.
Estimated Capital
2
$40,200
$55,500
$81,000
$106,500
$132,000
Costs of Fish Handling
Basket Screening
5
$46,200
$63,000
$99,000
$132,000
$165,000
Equipment (1999
Panel Width (ft)
10
$58,800
$87,600
$135,600
$183,600
$231,600
Dollars) |
14
$84,600
$131,400
$209,400
$287,400
$365,400
is 20 percent additional cost for upgrades to existing equipment was included based on
recommendations from one of the equipment vendors supplying cost data for this research effort.
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§ 316(b) Phase II TDD
Costing Methodology
Installation of Fish Handling Features to Existing Traveling Screens
As stated earlier, the basic equipment cost offish handling features (presented in Table 2-18) is calculated based on
the difference in cost between screens with and without fish handling equipment, plus a cost factor of 20 percent for
upgrading the existing system from intermittent to continuous operation. Although retrofitting existing screens with
fish handling equipment will require upgrading some mechanical equipment, installing fish handling equipment generally
will not require the use of a costly barge that is equipped with a crane and requires a minimum number of crew to
operate it. EPA assumed that costs are 75 percent of the underwater installation cost (Table 2-8) for a traveling screen
(based on BP J). Table 2-19 shows total estimated costs (equipment and installation) for adding fish handling equipment
to an existing traveling screen.
Table 2-19. Estimated
Well Depth
(ft)
10
25
50
75
100
Capital Costs of Fish
2
$46,200
$68,250
$100,500
$132,750
$165,000
Handling Equipment
Basket Screening
5
$55,575
$79,125
$121,875
$161,625
$201,375
and Installation1 (1999
Panel Width (ft)
10
$71,550
$107,100
$161,850
$216,600
$271,350
Dollars) 1
14 |
$100,725
$154,275
$239,025
$323,775
$408,525
1) Installation portion of the costs estimated as 75 percent of the underwater installation cost for installing a traveling 1
water screen. 1
The additional O&M costs due to the installation offish baskets on existing traveling screens can be calculated by
subtracting the O&M costs for basic traveling screens from the O&M costs for traveling screens with fish baskets.
See the Appendix B for cost curves and equations.
Other CWIS Technologies
Fine mesh traveling screens and traveling screens with fish handling are but two means by which facilities may comply
with the impingement and/or entrainment reduction requirements of the proposed rule. The Agency based its cost
estimates on the technologies outlined here, in part due to their prevalence, their applicability to the primary types of
intake structures at existing facilities within the scope of the rule, and for their conservative costs (that is, fine mesh
traveling screens tend to have higher costs, in the Agencies estimation than other similar technologies). As such, the
Agency notes that there are many ways by which facilities may comply with the requirements of this rule and that the
costs will be comparable to those developed here and presented in Appendix A. In that regard, the Agency has prepared
cost estimates for other comparable screening systems to those presented here and gave the majority of this information
in the Technical Development Document for the Final Regulations Addressing Cooling Water Intake Structures for New
Facilities (EPA-821 -R-01-036), hereinafter referred to as the New Facility TDD. The Agency refers the reader to the
New Facility TDD for information on the development of cost for other technologies that facilities may consider for
meeting the proposed impingement and entrainment requirements. In addition, Appendix B of this document contains
additional cost curves for technologies the Agency analyzed for the development of this rule and the New Facility rule.
In addition, Chapter 3 presents a detailed analysis of the types and performance of technologies that facilities may use
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§ 316(b) Phase II TDD Costing Methodology
to comply with the proposed existing facility rule.
2.2 OUTLINE OF COOLING SYSTEM CONVERSION COSTING METHODOLOSY
Under certain regulatory options considered (those described in Chapter 4.3), existing facilities are projected to install
recirculating wet cooling systems. The Agency developed a methodology for estimating the costs of converting model-
facility cooling systems from once-through to recirculating operation in the effort of reproducing the costs and
engineering characteristics of the example cooling system conversion cases presented in Chapter 4. The methodology
for estimating costs of these cooling system conversions is based on the principles observed in the empirical cases and
in historical proposals for cooling system conversions (see Chapter 4 for more discussion). The commonalities and/or
principles are as follows:
recirculating systems can be connected to the existing condensers and operated successfully under a variety
of conditions (but not all);
condenser flows generally do not change due to the conversions;
significant portions of the condenser conduit systems can be used for the recirculating tower systems;
existing cooling water pumps generally would be replaced with new circulating water pumps or booster
pumps would be installed to increase pumping energy of the circulating system;
the existing intake structures can be used for supplying make-up water to the recirculating towers (though
demolition and replacement of the intake pumps may be necessary);
pumping distances from tower systems to condensers can be significant, but existing piping runs can, in
some cases, be utilized to reduce the amount of new circulating piping installed;
tower structures can be constructed on-site before connection to the existing conduit system; and
modification and branching of circulating piping is necessary for connecting the recirculating system to
the existing conduits and for providing make-up water to the towers.
Based on these principles, the Agency developed cost estimates for cooling system conversions utilizing those developed
for new, "greenfield" facilities and inflated these costs by a "retrofit" factor to account for activities outside the scope
of the "greenfield" cost estimates. See sections 2.1 and 2.2 for the cost estimates for "greenfield" cooling tower systems
and intake structures. See section 2.6 for a discussion of the "retrofit" factor.
Condenser Refurbishments for Cooling System Conversions
The Agency includes costs for condenser refurbishments at a subset of facilities expected to comply with flow reduction
requirements in the regulatory options considered. The Agency projects premature condenser refurbishments, in part,
to alleviate potential condenser tube failures, such as that experienced at the Palisades plant. The Agency researched
the materials of construction of surface condensers for the model plants under certain regulatory options and for the
example cases described in Chapter 4. The Agency also consulted with condenser manufacturing representatives for
advice on probable causes for condenser failures due to cooling system conversions, motivations for condenser
replacements or refurbishments, useful lives of condensers, and appropriate tube materials for recirculating cooling
systems for a variety of water types. Of the four example cases in Chapter 4, only the Palisades plant experienced
condenser failure potentially related to the cooling system conversion. Plant personnel were not able to confirm the
condenser tube material at the time of the failure, nor were they able to positively confirm the cause of the failure as
relating to the recirculating system. Hence, the Agency could not isolate the specific cause of the Palisades failure and,
therefore, relied on additional information to determine which plants would likely replace condensers in order to upgrade
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§ 316(b) Phase II TDD Costing Methodology
the cooling system under certain regulatory options. The Agency learned from condenser vendors that plants would
elect to upgrade condenser tube materials to increase the efficiency of the recirculating cooling system. In addition,
based on the circumstantial evidence that the Palisades failure happened, at least in part, due to the chemical addition
necessary for the recirculating system and the fact that many of the plants projected to upgrade their cooling systems
under certain regulatory options utilize brackish or saline cooling water, the Agency judged that the material of the tubes
would need to withstand corrosive effects of chemical addition and increased salt content of the cooling water (due to
concentration in a recirculating system). Hence, the Agency concluded that meeting a baseline standard of condenser
tube material would determine which model plants would most likely upgrade condenser tube materials. See section
3.2.4 for further information on condenser refurbishments.
Condenser Flows for Cooling System Conversions
Based on the example cases of cooling system conversions in Chapter 4, the Agency determined that condenser
flows would not change as a result of cooling system upgrades. The cooling water flow through these tube bundles
would be the same as for the once-through systems due to the fact that each of the example cases utilized the original,
once-through designed, cooling water flow. In addition to the empirical example cases, the Agency researched
condenser flow to MW ratios to determine if cooling system type influenced the flow rate to capacity ratio. Published
condenser flows and generating capacity data from the Nuclear Regulatory Commission (DCN 4-2521)) for all nuclear
units in the US demonstrates that recirculating cooling systems have lower condenser flow to MW ratios than once-
through systems, regardless of age or other characteristics. After considering this information, EPA chose a
conservative approach and used the design cooling water intake flow of the baseline once-through system intake to
estimate the size of the recirculating cooling tower and associated conduit system for its model facilities. EPA notes
that design flows are significantly higher than operating flows in some cases. As such, the approach of the Agency is
additionally conservative, in that facilities considering cooling system conversions could optimize the design of the
circulating flow levels appropriate for the facilities operating flows if sufficient unused design intake capacity exists.
Reuse of Existing Intake Structures for Supplying Make-up Water to Cooling Towers
As demonstrated by the example cases in Chapter 4, conversions from once-through to recirculating cooling
systems do not require construction of new intake structures to provide make-up water to the cooling tower systems.
Installation of a fully recirculating cooling system reduces intake flow by upwards of approximately 92 percent as
compared to a once-through system. In turn the intake structure designed for a once-through cooling system is oversized
for moving flows reduced to this level. For the case of the Palisades plant, the original intake structure withdrew water
from a submerged offshore intake. The plant continued to utilize this intake structure (a velocity cap) and the associated
submerged piping system (3300 ft) after the conversion. A branch from the onshore portion of the original intake
conduit system provided make-up flow to the cooling tower via a separate pump system. The Agency includes capital
costs for the conduit system required to bring make-up water to the cooling tower and basin. See Example 1 of this
chapter for a discussion of the makeup and blowdown piping associated with the Agency's cooling system conversion
estimates. The Agency includes these costs to account for conversion cases in which significant distances may exist
between intake locations and cooling tower sites. The Agency notes, as described in Example 1, that these piping
capital costs are further inflated by the "retrofit" factor to account for construction techniques and situations outside
the scope of a typical "greenfield" cost estimate. In turn, the Agency views the inclusion of these cost estimates as
conservative and appropriate for cooling system conversions.
Cooling Tower Construction and Conduit Connections
The actual process of adjoining the cooling tower system to the existing condenser conduit system is reported
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§ 316(b) Phase II TDD Costing Methodology
to have not disrupted service significantly for two of the example cases presented in Chapter 4. However, for the
Palisades plant, Consumers Energy report that the outage lasted approximately 10 months for connection and start-up
of the cooling tower system (see Chapter 4). The Agency estimates for the flow-reduction regulatory options considered
that the typical process of adjoining the recirculating system to the existing condenser unit and the refurbishment of the
existing condenser (when necessary) would last approximately two months. Because the Agency analyzed flexible
compliance dates (extended over a five-year compliance period), the Agency estimated that plants under the flow-
reduction regulatory options could plan the cooling system conversion to coincide with periodic scheduled outages, as
was the case for the example cases. For the case of nuclear units, these outages can coincide with periodic inspections
(ISIs) and refueling. For the case of fossil-fuel and combined-cycle units, the conversion can be planned to coincide
with periodic maintenance. Even though ISIs for nuclear units last typically 2 to 4 months, which would extend equal
to or beyond the time required to connect the converted system, the Agency estimates for all model plants one month
of interrupted service due to the cooling system conversion. For further information see Chapter 4 of this document
and the EBA.
Connections of circulating systems to existing once-through conduits, in the Agency's view, would occur
through either demolition and/or removal of the connecting piping and/or through branching (and plugging) of the
existing conduit system outside the condenser buildings. The Agency estimates that the primary activities fall within
the scope of types of construction projects accounted for by the "retrofit" capital cost inflation factor (see Section 2.6
below). Note that the Agency applies the "retrofit" factor to each capital cost outlay for the entire project. Therefore,
the branching/connection of the cooling system conduit system could be accounted for in the inflation of a variety of
cost components.
2.2.1 Capital Costs of Wet Towers
As described in section 2.2, above, in order to develop cooling system conversion costs for existing facilities, the Agency
modified the capital cost estimates for wet cooling tower systems that it developed for new, "greenfield" facilities in
the 316b Phase I Rule for New Facilities by applying a "retrofit" factor. The description of the Agency' s cost estimates
for cooling tower systems at new facilities is presented below:
For cooling towers, EPA developed cost estimates for use at a range of different total recirculating flow volumes. The
cost for flow reduction technologies depends on many factors, including site-specific conditions. The Agency
determined that the factor that is most relevant is the total flow. Therefore, EPA selected total flow as the factor on
which to base unit costs and thus use for basic cost comparisons.
The maximum cooling flow value used to develop the wet tower cost equations (both Capital and O&M) was 204,000
gpm. If the model facility flow value exceeded this maximum by 10 percent (i.e., > 225,000 gpm), EPA costed multiple
parallel wet tower units.
Recirculating the cooling water in a system vastly reduces the amount of cooling water needed. The method most
frequently used to cool the water in a recirculating system is putting the cooling water through a cooling tower.
Therefore, EPA chose to cost cooling towers as the technology used to switch a once-through cooling system to a
recirculating system.
The factors that generally have the greatest impact on cost are the flow, approach (the difference between cold water
temperature and ambient wet bulb temperature), tower type, and environmental considerations. Physical site conditions
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§ 316(b) Phase II TDD Costing Methodology
(e.g., topographic conditions, soils and underground conditions, water quality) affect cost, but in most situations are
secondary to the primary cost factors. Relative capital and operation cost estimates for various types of cooling towers
are estimated in literature (Mirsky et al. (1992), Mirsky and Bauthier (1997), and Mirsky (2000))2.
Other characteristics of cooling towers include:
• Airflow: Mechanical draft towers use fans to induce air flow, while natural draft (i.e., hyperbolic) towers
induce natural air flow by the chimney effect produced by the height and shape of the tower. For towers of
similar capacity, natural draft towers typically require significantly less land area and have lower power costs
(i.e., fans to induce air flow are not needed) but have higher initial costs (particularly because they need to be
taller) than mechanical draft towers. Both mechanical draft and natural draft towers can be designed for air
to flow through the fill material using either a crossflow (air flows horizontally) or counterflow (air flows
vertically upward) design, while the water flows vertically downward. Counterflow towers tend to be more
efficient at achieving heat reduction but are generally more expensive to build and operate because clearance
needed at the bottom of the tower means the tower needs to be taller.
• Mode of operation: Cooling towers can be either recirculating (water is returned to the condenser for reuse)
or non-recirculating (tower effluent is discharged to a receiving waterbody and not reused). Facilities using
non-recirculating types (i.e., "helper" towers) draw large flows for cooling and therefore do not provide fish
protection for §316(b) purposes, so the information in this chapter is not intended to address non-recirculating
towers.
• Construction materials: Towers can be made from concrete, steel, wood, and/or fiberglass.
Capital Cost of Cooling Towers (New Facility Cost Development)
The volume of water needed for cooling depends on the following critical parameters: water temperature, make of
equipment to be used (e.g, G.E turbine vs. ABB turbine, turbine with heat recovery system and turbine without heat
recovery system), discharge permit limits, water quality (particularly for wet cooling towers), and type of wet cooling
tower (i.e., whether it is a natural draft or a mechanical draft).
Two cooling tower industry managers with extensive experience in selling and installing cooling towers to power plants
and other industries provided information on how they estimate budget capital costs associated with a wet cooling tower.
The rule of thumb they use is $30/gpm for an approach of 10 degrees and $50/gpm for an approach of 5 degrees.3 This
In developing cost estimates for hybrid-wet/dry cooling towers included in Charts 2-1 through 2-6 of the
attachments to this chapter, the Agency computed the capital costs of the hybrid tower unit according to the factors
referenced here. The Agency then applied an inflation factor to account for the auxiliary components of installation
of a cooling tower system. However, this may overstate the costs of hybrid towers in comparison to wet (only)
systems, for the fact that hybrid and wet (only) towers would have roughly identical installation costs (see Appendix
C of this document for a discussion of the installation costs of hybrid towers and Chapter 6 for a discussion of the
relative costs of plume abatement (that is, hybrid towers) versus wet (only) cooling towers).
3The approach is the difference between the cold water (tower effluent) temperature and the tower wet
bulb temperature. This is also referred to as the design approach. For example, at design conditions with
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§ 316(b) Phase II TDD Costing Methodology
cost is for a "small" tower (flow less than 10,000 gpm) and equipment associated with the "basic" tower, and does not
include installation. Important auxiliary costs are included in the installation factor estimate listed below. Above
10,000 gpm, to account for economy of scale, the unit cost was lowered by $5/gpm over the flow range up to 204,000
gpm. For flows greater than 204,000 gpm, a facility may need to use multiple towers or a custom design. Combining
this with the variability in cost among various cooling tower types, costs for various tower types and features were
calculated for the flows used.
To estimate costs specifically for installing and operating a particular cooling tower, important factors include:
• Condenser heat load and wet bulb temperature (or approach to wet bulb temperature): Largely determine
the size needed. Size is also affected by climate conditions.
• Plant fuel type and age/efficiency: Condenser discharge heat load per Megawatt varies greatly by plant type
(nuclear thermal efficiency is about 33 percent to 35 percent, while newer oil-fired plants can have nearly 40
percent thermal efficiency, and newer coal-fired plants can have nearly 38 percent thermal efficiency).4 Older
plants typically have lower thermal efficiency than new plants.
• Topography: May affect tower height and/or shape, and may increase construction costs due to subsurface
conditions. For example, sites requiring significant blasting, use of piles, or a remote tower location will
typically have greater installation/construction cost.
• Material used for tower construction: Wood towers tend to be the least expensive, followed by fiberglass
reinforced plastic, steel, and concrete. However, some industry sources claim that Redwood capital costs might
be much higher compared to other wood cooling towers, particularly in the Northwest U.S., because Redwood
trees are a protected species. Factors that affect the material used include chemical and mineral composition
of the cooling water, cost, aesthetics, and local/regional availability of materials.
Capital costs for the recirculating wet tower include costs for all installation components, such as site preparation and
clearing, support foundation, electrical wiring and controls, basin and sump, cicrulating piping, blowdown water
treatment system, and recirculating pump and housing costs. Wet tower costs are based on cost data for redwood
towers with splash fill and an approach of 10 °F taken from Chart 2-3 in the attachments to this chapter. This tower
equation does not include make-up and blowdown piping, intake pumps, intake structure and screening technologies.
In order to account for the important auxiliary costs of installing the cooling tower system, the Agency obtained
estimates from industry representatives for installation costs as an inflation percentage of the installed cooling tower
unit costs. The factor that EPA obtained is 80 percent, which experienced industry representatives described as the
average installation inflation factor. The Agency used this factor to inflate the rule of thumb described above for 10
a delta or design approach of 5 degrees, the tower effluent and blowdown would be 5 degrees warmer than
the wet bulb temperature. A smaller delta (or lower tower effluent temperature) requires a larger cooling
tower and thus is more expensive.
4 With a 33 percent efficiency, one-third of the heat is converted to electric energy and two-thirds goes to
waste heat in the cooling water.
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§ 316(b) Phase II TDD Costing Methodology
degree F approach towers (from approximately $307 gpm to $54 / gpm for the total project cost of a small douglas fir
tower and from $25 / gpm to $ 45 / gpm for large fir towers). The Agency chose the median design approach of 10
degrees F based on empirical data from recently installed cooling towers at a variety of geographic locations and plant
sizes (See Attachment C to Chapter 5). Applying the factors provided in literature for converting from douglas fir
material to other types of cooling towers, the Agency derived capital cost equations for basic cooling towers of douglas
fir, redwood, concrete, steel, and fiberglass reinforced plastic. For example, using the Agency's methodology for new
facilities, the installed cost of a basic 205,000 gpm fiberglass tower would be expressed as follows: $25 * 1.8 * 110
/ 100 * 205,000 = $10,147,500 (in 1999 $). To accommodate the relatively standard application of splash fill the
Agency additionally multiplied by the factor for splash fill from the literature tower factors. For example, using the
new facility methodology for the installation of a 205,000 gpm redwood tower with splash fill would be expressed as
follows: $25 * 1.8 * 120 /100 * 112 /100 * 205,000 = $12,398,400 (in 1999 $). The Agency developed a series of
these calculations for each type of tower using the literature factors and fitted curves to the results. These curve fits
are presented in Appendix B of this document as Figures 2-1 through 2-6. The Agency determined that the median cost
material was redwood, which is just slightly more expensive than fiberglass reinforced plastic. The Agency learned
from cooling tower vendors that fiberglass has become relatively standard for new facility installations, and therefore
chose to use the median costs of the redwood because they slightly exceeded those of fiberglass. As such, the Agency
primarily developed installed cooling tower costs for the new facility rule using the equation for redwood towers with
splash fill. The equation for an installed redwood mechanical-draft cooling tower unit with 10 degree F design
approach and splash fill is as follows:
y = -5E-5 xA2 + 70.721 x + 25393 , (in 1999 $)
where x = flow in gallons per minute, valid up to 225,000 gpm.
For existing facility estimates of cooling tower conversions at non-nuclear facilities, this equation is the starting
point for assessing the conversion project costs. In addition to the retrofit factor described in Section 2.6 below, the
Agency also added additional makeup and discharge piping capital costs according to the methodology presented in
Example 2, which demonstrates how the Agency estimated cooling tower conversion costs for certain regulatory
options considered for this proposal.
Similarly, the Agency developed the following equation for the installation capital costs of mechanical-draft
concrete cooling tower systems with splash fill:
y = -6E-5 xA2 + 87.845 x + 31674 , (in 1999 $)
where x = flow in gallons per minute, valid up to 225,000 gpm.
This equation was used as the starting point for assessing cooling tower conversion project capital costs for nuclear
facilities for certain regulatory options of this proposed rule. See Example 2 for a demonstration of the
incorporation of regional cost factors, the retrofit factor, and makeup and discharge piping costs with the above
capital cost equation.
EPA obtained data for 20 cooling tower construction projects: nine Douglas fir towers, eight fiberglass towers, one
redwood tower, and two towers for which the construction material was unknown (for purposes of comparison,
EPA compared these last two towers to predicted costs for redwood towers). In some cases, the project costs did
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§ 316(b) Phase II TDD Costing Methodology
not include certain components such as pumps or basins. Where this was the case, EPA adjusted the project costs
as follows:
• where project costs did not include pumps, EPA added $10/gpm to the project costs to account for pumps.
where project costs did not include pumps and basins, EPA doubled the project costs to account for pumps
and basins.
Chart 2-7 in the attachments to this chapter compares actual, total capital costs for wet cooling tower projects
against predicted costs from EPA's cooling tower capital cost curves, with 25 percent error bars around the cost
curve predicted values. This chart shows that, in almost all cases, EPA's cost curves provide conservative cost
estimates (erring on the high side) and are within 25 percent or less of actual project costs. In those few cases
where the cost curve predictions are not within 25 percent of the actual costs, the difference can generally be
attributed to the fact that the constructed cooling towers were designed for temperature approaches different than
the 10 °F used for EPA's cost curves.
For the existing facility regulatory options based on flow reduction, the Agency first compared the validity of the
redwood cost curve against empirical turn key costs from cooling tower projects at existing facilities. The Agency
obtained four sets of total installed cooling tower costs for helper towers and expansions at existing facilities. The
Agency attempted to discern if construction costs at existing facilities were inherently different from its empirically
verified cost equations for new facilities. The results of this analysis showed that the median $ per gpm predictions
of the redwood equation were nearly identical to those of the four existing facility projects (DCN 4522). However,
the Agency determined that additional inflation of the new facility costs was necessary to compensate for the
probable additional costs that would be associated with cooling system conversions. In turn, the Agency estimated
a retrofit factor of 20 percent additional installed capital cost would be necessary for an average retrofit project.
As described in Chapter 4, the Agency obtained two empirical, total project costs for cooling tower conversion
projects. The Agency calculated estimated project costs based on the methodology presented in Example 2 below
and determined that for the case of the Palisades conversion that the Agency's methodology was very accurate. For
the case of Pittsburg Unit 7, the Agency methodology for assessing conversion costs at non-nuclear plants may
have understated total project capital costs (as reported by Pittsburg) by approximately 18 percent. In part, the
Agency estimates that exclusion of makeup water pumps may have contributed to the difference (see Example 2).
For more information on the on the cooling system example cases see Chapter 4 .
2.2.2 Operation and Maintenance Costs of Wet Towers
The Agency estimates that operation and maintenance costs of wet cooling tower systems for conversion projects
would be the same as those developed for new, "greenfield" facilities during the 316b Phase I Rule for New
Facilities. The Agency notes that recirculating pumping costs included in these operation and maintenance costs
should be deducted from annual costs of cooling system conversion projects. In EPA's view, this methodology
presents a realistic estimate of the actual operation and maintenance costs of cooling tower conversion projects.
Even though the Agency did not include capital costs for make-up water pumps for the cooling system conversions
(see Example 2, below), the Agency includes operation and maintenance costs for delivering make-up water to the
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§ 316(b) Phase II TDD Costing Methodology
cooling towers.
Cooling towers may require replacement of equipment during the financing period that is necessary for the upkeep
of the cooling tower. These costs tend to increase over the useful life of the tower and constitute an O&M
expenditure that needs to be accounted for. Therefore, EPA factored these periodic equipment replacement costs
into the O&M cost estimates presented herein. However, EPA has not included the replacement costs for other
equipment because the life expectancy is generally expected to last over the financial life of the facility.
EPA has included the following variables in estimating O&M costs for cooling towers:
• Size of the cooling tower,
• Material from which the cooling tower is built,
• Various features that the cooling tower may include,
• Source of make-up water,
• How blowdown water is disposed, and
• Increase in maintenance costs as the tower useful life diminishes.
For example, if make-up water is obtained from a lesser quality source, additional treatment may be required to
prevent biofouling in the tower.
The estimated annual O&M costs presented below are for cooling towers designed at a delta of 10 degrees. To
calculate annual O&M costs for various types of cooling towers, EPA made the following assumptions:
• For small cooling towers, the annual O&M costs for chemical costs and routine preventive maintenance is
estimated at 5 percent of capital costs. To account for economy of scale in these components of the O&M
cost, that percentage is gradually decreased to 2 percent for the largest size cooling tower. EPA notes that,
while there appear to be economies of scale for these components of O&M costs, chemical and routine
preventive maintenance costs represent a small percentage of the total O&M costs and EPA does not
believe there to be significant economies of scale in the total O&M costs.
• 2 percent of the tower flow is lost to evaporation and/or blowdown.
• To account for the costs of makeup water and disposal of blowdown water, EPA based the estimate on the
facility using surface water sources for makeup water and disposing of blowdown water either to a pond or
back to the surface water source at a combined cost of $0.5/1000 gallons.
• Based on discussions with industry representatives, the largest component of total O&M costs is the
requirement for major maintenance of the tower that occurs after years of tower service, such as around the
10th year and 20th years of service. These major overhauls include repairs to mechanical equipment and
replacement of 100 percent of fill material and eliminators.
To account for the variation in maintenance costs among cooling tower types, a scaling factor is used. Douglas Fir
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§ 316(b) Phase II TDD Costing Methodology
is the type with the greatest maintenance cost, followed by Redwood, steel, concrete, and fiberglass. For additional
cooling tower features, a scaling factor was used to account for the variations in maintenance (e.g., splash fill and
non-fouling film fill are the features with the lowest maintenance costs).
Using the operation cost comparison information published by Mirsky et al. (1992) and maintenance cost
assumptions set out above, EPA calculated estimated costs of O&M for various types of cooling towers with and
without additional features. EPA then developed cost equations from the generated cost data points. The O&M
equations are shown in Charts 2-8 and 2-9 for redwood and concrete towers with various features. The following
equations present the O&M costs for 10 degree F design approach redwood and concrete towers with splash fill:
y = -4E-6 xA2 + 11.617 x + 2055.2 , (in 1999 $ for with Splash Fill)
where x = flow in gallons per minute, valid up to 225,000 gpm.
y = -3E-6 xA2 + 10.305 x + 1837.2 , (in 1999 $ for Concrete with Splash Fill)
where x = flow in gallons per minute, valid up to 225,000 gpm.
Note that these cost estimates and equations are for total O&M costs. Stone and Webster (1992) presents a value
for additional annual O&M costs equal to approximately 0.7 percent of the capital costs for a retrofit project.
Stone and Webster's estimate is for the amount O&M costs are expected to increase when plants with once-
through cooling systems are retrofit with cooling towers to become recirculating systems, and therefore do not
represent total O&M costs of cooling tower systems.
2.2.3 Operation and Maintenance Costs of Baseline, Once-Through Systems
The Agency also utilizes estimates of operation and maintenance costs of once-through cooling based on a similar
methodology to the costs developed for the 316b Phase I Rule for New Facilities. However, the Agency has
concluded that the price of electricity used to estimate once-through system pumping costs plus ancillary
operational and maintenance costs of operating the existing intake structure and other process activities is not
appropriate in the context of existing facility O&M costs. The electricity price used by the Agency to reflect only
the dedicated operational pumping costs of the once-through system is a realistic $0.03/kWh. Therefore, when
subtracted from the overall cooling tower operation and maintenance estimates, the once-through pumping costs
would approximately represent the original pumping costs of the reused cooling water pump. If the Agency had not
subtracted this element from the recurring annual costs of the cooling system conversion, the pumping costs, as
compared to the baseline operating costs of the once-through system, would be miscounted. See Example 2 for a
demonstration of the Agency's estimates of once-through O&M costs.
2.2.4 Capital Costs of Surface Condenser Refurbishments
As described in section 2.2, above, the Agency projects premature condenser refurbishments for a portion of the
plants expected to incur costs of cooling tower conversions under certain regulatory options considered for this
proposal. The Agency concluded that meeting a baseline standard of condenser tube material would determine
which model plants would most likely upgrade condenser tube materials. In part, the Agency based this
methodology based on a reference developing cost estimates for modular condenser tube replacements (Burns and
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§ 316(b) Phase II TDD Costing Methodology
Tsou, 2001). The Agency judged that the minimum standard material would be copper-nickel alloy (of any
mixture) for brackish water and stainless steel (of any type) for saline water. The Agency then consulted the 1994
UDI database (Power Statistics Unit Design Data File Part B) - the only data source the Agency is aware of with
condenser tube material statistics - to determine the condenser tube material for the plants. For the units at each
plant with condenser tube materials of a quality judged below that of the minimum standards mentioned above, the
Agency estimates that the plant would refurbish the condenser (thereby changing out the condenser tubes) as a
result of the cooling system conversion. The Agency projected that tube material for the upgrades would be
stainless steel for all model plants receiving upgrade refurbishments. At some plants, EPA projects that only a
portion of design intake flow serves units that would require condenser refurbishment or replacement.
As noted in the discussion above, condenser manufacturing representatives advised the Agency that plants would be
motivated to upgrade condenser materials to maximize the energy efficiency of the recirculating cooling system. By
upgrading the condensers for those plants utilizing less than the adjudged minimum standard (copper-nickel alloy
for brackish waters and stainless steel for saline waters), the Agency determines that the turbine energy penalties
derived for new, "greenfield" plants would be more applicable to the upgraded recirculating cooling systems at
existing plants. See Chapter 5 of this document for the Agency's energy penalty analysis. In addition, the Agency
determines that by accounting for condenser upgrades for those model plants with materials below the minimum
standard that it has addressed potential condenser failures due to cooling system upgrades. See Table 2-20 for
statistics on condenser materials at recirculating cooling facilities (compiled from the 1994 UDI database for all
generating units in the database with cooling towers in-place).
Table 2-20. Condenser Tubes for Units with Cooling Tower (from all Units in 1994 UDI database)
Percent of Cooling Tower Units with Condenser Material
17% Titanium
3% Stainless Steel (any type)
27% Brass or Admir. Brass
35% Copper-Nickel Alloy (any type)
12% AL6X
2% Others
5% Unknown
The Agency contacted condenser vendors to obtain cost estimates for refurbishing of existing condensers and for full
condenser replacements. The Agency developed cost estimates (on a flow basis) for several types of condenser tube
materials - copper-nickel alloy, stainless steel, and titanium. The capital cost estimates for condenser refurbishing were
lower than those for full replacements, and the Agency determined that, given equal opportunity, facilities would make
the economical decision to refurbish existing condensers rather than replace the waterboxes and the tube bundles. The
condenser refurbishing costs developed by the Agency account for the tube materials, full labor, overhead, and potential
bracing of the shell due to buoyancy changes (related to changes in tube material and, hence, densities). See Example
2 below for the condenser tube replacement and upgrade capital cost equations.
Power plants will refurbish or replace condensers on a periodic basis. Condenser vendors estimated the average useful
life of condenser tubes as 20 years. In order to determine remaining useful life of the condensers at the 59 model plants,
the Agency calculated a condenser replacement/refurbishing schedule based on the 20-year useful life estimate and the
age of the generating units at the plants. The average useful life remaining for a condenser at the 59 model plants is
approximately 9-1/2 years (in 2001). The Agency rounded this to 10 years and used this figure to represent lost
operating years as a result of premature condenser refurbishments. The Agency estimates the baseline condenser
material for any plant upgrading a condenser would be copper-nickel alloy. Therefore, plants upgrading condensers
in order to install recirculating cooling would incur the costs of the full condenser refurbishment/upgrade to stainless
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§ 316(b) Phase II TDD Costing Methodology
steel, less the 10 years of useful life already expended, on average, in a condenser made of a lesser material (e.g.,
copper-nickel alloy). The economic analysis then uses these capital cost estimates in the calculation of net annualized
costs. See the EBA. As explained in the EBA, the full capital cost value of the replacement is reduced to represent lost
operating years of the existing condenser.
2.3 RECURRING ANNUAL COSTS OF POST-COMPLIANCE MONITORINS
Existing facilities that fall within the scope of this proposed rule would be required to perform biological monitoring
of impingement and entrainment, and visual or remote inspections of the cooling water intake structure and any
additional technologies, on an on-going basis. Additional ambient water quality monitoring may also be required of
facilities depending on the specifications of their NPDES permits. Facilities would be expected to analyze the results
from their monitoring efforts and provide these results in an annual status report to the permitting authority. In addition,
facilities would be required to maintain records of all submitted documents, supporting materials, and monitoring results
for at least three years. (Note that the Director may require that records be kept for a longer period to coincide with
the life of the NPDES permit.)
EPA expects that facility managers, biologists, biological technicians, statisticians, and clerical staff will devote time
toward gathering, preparing, submitting and maintaining records of the post-compliance monitoring information that
is required by the proposed rule. To develop representative profiles of each employee's relative contribution, EPA
assumed burden estimates that reflect the staffing and expertise typically found in power generating plants. In doing
this, EPA considered the time and qualifications necessary to complete a variety of tasks: collecting, preparing, and
analyzing samples; enumerating organisms; performing statistical analyses; performing visual or remote inspections
of installed technologies; compiling and submitting yearly status reports; and maintaining records of monitoring results.
For each activity burden assumption, EPA selected time estimates to reflect the expected effort necessary to carry out
these activities under normal conditions and reasonable labor efficiency.
The costs to the respondent facilities associated with these time commitments can be estimated by multiplying the time
spent in each labor category by an appropriately loaded hourly wage rate. All base wage rates used for facility labor
categories were derived from the Bureau of Labor Statistics (BLS) Occupational Handbook 2002-2003 (BLS, 2002).
Additional detail on the development of cost estimates for annual post-compliance monitoring can be found in the Draft
Information Collection Request for Cooling Water Intake Structures Phase II Existing Facilities Proposed Rule.
EPA estimated the annual cost of post-compliance monitoring to be approximately $62,650 for freshwater facilities
(i.e., facilities withdrawing cooling water from freshwater rivers and streams; or lakes and reservoirs), and
approximately $78,300 for marine facilities (i.e., facilities withdrawing cooling water from estuaries and tidal rivers;
or oceans) and Great Lakes facilities.
2.4 ONE-TIME COSTS FOR TRACK II DEMONSTRATION STUDIES
Under the proposed rule, all facilities would submit a comprehensive demonstration study to characterize the source
water baseline in the vicinity of the intake, characterize the operation of the intake, and confirm that the technology(ies),
operational measures and restoration measures proposed and/or implemented at the intake meet the applicable
performance standards. EPA developed burden and cost estimates for the comprehensive demonstration study in a
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§ 316(b) Phase II TDD
Costing Methodology
manner similar to that described in section 1.4 above (i.e., by building up the estimated burdens and corresponding costs
associated with the various activities being performed).
The burden estimates include: developing a proposal for collecting information to support the study; developing a
description of the proposed and/or implemented technologies, operational measures and restoration measures to be
evaluated and their efficacies; performing biological sampling; assessing the source waterbody; estimating the
magnitude of impingement mortality and entrainment; calculating the reduction in impingement mortality and
entrainment that would be achieved by the technologies and operational measures selected; demonstrating that the
location, design, construction and capacity of the intake reflects the best technology available for minimizing adverse
environmental impact (BTA); and reporting the results. The burden also includes developing a verification monitoring
plan to verify the full-scale performance of the proposed or implemented technologies and operational measures. In
addition, the burden includes performing a site-specific evaluation of the suitability of the technology(ies) and/or
operational measures based on representative studies and/or site-specific technology prototype studies.
The costs to the respondent facilities associated with these time commitments can be estimated by multiplying the time
spent in each labor category by an appropriately loaded hourly wage rate. Additional detail on the development of cost
estimates for annual post-compliance monitoring can be found in the Draft Information Collection Request for Cooling
Water Intake Structures Phase II Existing Facilities Proposed Rule.
EPA estimated the one-time costs for comprehensive demonstration studies to be approximately $827,000 for facilities
withdrawing cooling water from freshwater rivers and streams, $739,000 for facilities withdrawing cooling water from
lakes, $864,000 for facilities withdrawing cooling water from the Great Lakes, and $1,015,000 for facilities
withdrawing cooling water from estuaries/tidal rivers or oceans.
2.5 RESIGNAL COST FACTORS
As described in sections 2.1 and 2.2 above, the Agency developed technology-specific cost estimates for construction
projects at new, "greenfield" projects on a national average basis. However, the capital construction costs can vary
significantly for different locations within the United States. Therefore, to account for these regional variations, EPA
adjusted the capital cost estimates for the existing model plants using state-specific cost factors, which ranged from
0.739 for South Carolina to 1.245 for Alaska. The applicable state cost factors were multiplied by the facility model
cost estimates to obtain the facility location-specific capital costs used in the impact analysis.
The Agency derived the state-specific capital cost factors shown in Table 2-21 below from the "location cost factor
database" in RS Means Cost Works 2001. The Agency used the weighted-average factor category for total costs
(including material and installation). The RS Means database provides cost factors (by 3-digit Zip code) for numerous
locations within each state. The Agency selected the median of the cost factors for all locations reported within each
state as the state-specific capital cost factor.
Table 2-21. State-Specific Capital Cost Factors
State
Alaska
Alabama
Arkansas
State
Code
AK
AL
AR
Median
Weighted
Cost Factor
1.245
0.81
0.7815
State
North Carolina
North Dakota
Nebraska
State
Code
NC
ND
NE
Median
Weighted
Cost Factor
0.752
0.827
0.828
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Costing Methodology
State
Arizona
California
Colorado
Connecticut
DC
Delaware
Florida
Georgia
Hawaii
Iowa
Idaho
Illinois
Indiana
Kansas
Kentucky
Louisiana
Massachusetts
Maryland
Maine
Michigan
Minnesota
Missouri
Mississippi
Montana
State
Code
AZ
CA
CO
CT
DC
DE
FL
GA
HI
IA
ID
IL
IN
KS
KY
LA
MA
MD
ME
MI
MN
MO
MS
MT
Median
Weighted
Cost Factor
0.864
1.081
0.915
1.052
0.948
1.009
0.832
0.812
1.225
0.886
0.932
0.994
0.922
0.84
0.847
0.819
1.064
0.89
0.829
0.966
1.046
0.925
0.7425
0.954
State
New Hampshire
New Jersey
New Mexico
Nevada
New York
Ohio
Oklahoma
Oregon
Pennsylvania
Rhode Island
South Carolina
South Dakota
Tennessee
Texas
Utah
Virginia
Vermont
Washington
Wisconsin
West Virginia
Wyoming
Minimum
Maximum
State
Code
NH
NJ
NM
NV
NY
OH
OK
OR
PA
RI
SC
SD
TN
TX
UT
VA
VT
WA
WI
WV
WY
SC
AK
Median
Weighted
Cost Factor
0.913
1.099
0.912
0.997
1.0235
0.955
0.82
1.059
0.9765
1.039
0.7385
0.789
0.803
0.797
0.8975
0.822
0.743
1.028
0.97
0.943
0.787
0.739
1.245
2.6 RETROFIT COST FACTOR
In order to account for capital cost expenditures specific to construction at existing power plants, the Agency applies
a capital cost inflation factor to the cost estimates described in sections 2.1 and 2.2 above. This capital cost inflation
factor, referred to hereinafter as a "retrofit factor" accounts for activities outside the scope of the costs estimates
described in sections 1.2 and 1.3. These activities relate to the "retrofit," or upgrade, of existing cooling water and
intake structure systems. The Agency generally developed the cost estimates summarized in sections 2.1 through 2.2
specifically for construction projects at new, "greenfield" projects (with the exception of those for surface condenser
refurbishing, which the Agency developed to inherently include retrofit activities). These projects and, therefore, the
costs equations described in sections 2.1 and 2.2 generally do not include retrofit activities such as (but not limited to)
branching or diversion of cooling water delivery systems, reinforcement of retrofitted conduit system connections,
partial or full demolition of conduit systems and/or intake structures, additional excavation activities, temporary delays
in construction schedules, expedited construction schedules, potential small land acquisitions, hiring of additional
(beyond those typical for the "greenfield" cost estimates) equipment and personnel for subsurface construction,
administrative and construction related safety precautions, and potential additional cooling water (recirculating or make-
up) delivery needs.
The Agency estimates that a capital cost inflation factor of 20 or 30 percent applied to the costs developed for new,
"greenfield" projects accounts for the retrofit activities described above. The retrofit activities represented by the factor
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§ 316(b) Phase II TDD
Costing Methodology
do not relate to uncertainty of the construction project, and therefore are not considered "contingencies." Rather, the
retrofit activities are site-specific, may vary between sites, but on average, in the Agency's view, will approach 20
percent for activity necessary to convert cooling systems and approach 30 percent for upgrading of cooling water intake
structures and screens.
2.7 EXAMPLES OF MODEL PLANT COST ESTIMATES
EXAMPLE 1: IMPINGEMENT AND ENTRAINMENT UPGRADE FOR ONCE-THROUGH INTAKE
Source Water: Freshwater
Steam Plant Type: Nuclear
Baseline Cooling System: Once-through
Baseline Intake Type: Trash Racks and Coarse-Mesh Screens
Baseline Design Intake Capacity: 600 million gallons per day (416,667 gpm)
Compliance Intake Type: Fine-mesh Travelling Screens with Fish Handling/Returns
Regional Capital Cost Factor: 1.00
Cooling Water Intake Technology Retrofitted Capital Cost:
• Utilized intake technology capital cost curves derived for New Facility Rule.
• Multiplied by additional retrofit cost equal to 30% of installed costs.
• Multiplied by regional capital cost factor.
• Utilized flow for sizing and construction factors as follows:
Table EX-1 CWIS Technology Retrofit Flow Sizing and Construction Factors
Flow Used to size Compliance Cooling Construction
Compliance Cooling Cooling Water Intake Water Intake Factor for
System Type Plant Type Technology Technology Scenario
Cooling Tower **
Non-Cooling Tower
Non-Cooling Tower
Non-Cooling Tower
Non-Cooling Tower
All
Non-nuclear
Non-nuclear
Non-nuclear
Nuclear
50% of Once-through,
Baseline Design Intake
100% of Once-through
Baseline Design Intake
100% of Once-through
Baseline Design Intake
100% of Once-through
Baseline Design Intake
100% of Once-through
All
Fish Handling
Fine Mesh Screens
Fine Mesh Screens w/
Fish Handling
Fish Handling
None
None
30%*
15%*
None
Baseline Design Intake
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§ 316(b) Phase II TDD Costing Methodology
Table EX-1 CWIS Technology Retrofit Flow Sizing and Construction Factors
Flow Used to size Compliance Cooling Construction
Compliance Cooling Cooling Water Intake Water Intake Factor for
System Type Plant Type Technology Technology Scenario
Non-Cooling Tower Nuclear 100% of Once-through Fine Mesh Screens 65%*
Baseline Design Intake
Non-Cooling Tower Nuclear 100% of Once-through Fine Mesh Screens w/ 30%*
Baseline Design Intake Fish Handling
* Existing facility construction factors based on average ratio of intake modification construction costs to costs derived
from CWIS equations developed for New Facility projects. Thus the differences reflect differences in construction
costs for nuclear and non-nuclear and differences in CWIS installation capital costs.
** For cooling sizing of cooling towers and appropriate flow for determining the costs of retrofitted cooling water
systems, see Section 2.2.
Intake modification construction costs are based on the following general framework:
• An increase in screen area of 50% due to conversion from coarse-mesh to fine-mesh.
• Screen size increase will involve demolition of one side of intake and extension in that direction.
• Installation/removal of sheet piling.
• Concrete demolition of one column and one side (cost doubled for nuclear*).
• Excavation (cost doubled for nuclear*).
• Additional concrete foundation.
• Additional concrete side and back wall.
• Additional concrete column.
* EPA doubled costs to account for concerns that use of blasting and high-impact equipment may be limited
at nuclear facilities.
Modification construction costs were then increased by the following cost factors:
Item Factor
Mobilization/Demobilization 3 %
Engineering 10 %
Site Work 5 %
Electrical 10 %
Controls 3 %
Contingency 10 %
Allowance 5 %
Fine-mesh travelling screens with fish handling/return capital cost equation:
(5 E-l 1 * x3 - 2 E-5 * x2 + 7.1477 * x + 113116) * (1.05* 1.30) * regional factor * construction factor
where x = appropriate flow for sizing
Total Capital Cost of Intake Structure Technology Modification for this example: $5.742.300
(addition of fine-mesh travelling screens with fish handling/return to the existing intake).
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§ 316(b) Phase II TDD Costing Methodology
Total Capital Cost of Intake Upgrade: $5.742.300.
Cooling Water Intake Technology O&M Costs:
Based on outreach with industry representatives, EPA estimated annual O&M cost as a percentage of total
capital cost (that is, those costs developed for new facility projects, not including retrofit factors). The O&M
cost factor ranges between 8 percent of total capital cost for the smallest size traveling screens with and without
fish handling equipment and 5 percent for the largest traveling screen since O&M costs do not increase
proportionately with screen size. The screen O&M costs are based on the size of the screen, which are based
on the initial sizing flow. For this example, the Agency uses the sizing flow of full, baseline once-through flow.
O&M Equation for Fine-mesh Travelling Screens with Fish Handling/Return:
-3E-13 * x3 - 4 E-8*x2 +0.2081 *x+ 11485
Cooling Water Intake Technology O&M Costs for This Example: $69.548
Total Annual O&M Costs for this Example: $69.548
EXAMPLE 2: COOLING SYSTEM CONVERSION
Source Water: Estuary / Tidal River
Steam Plant Type: Fossil
Baseline Cooling System: Once-through
Baseline Intake Type: Trash Racks and Coarse-Mesh Screens
Baseline Design Intake Capacity: 600 million gallons per day (416,667 gpm)
Converted Cooling System: Mechanical-Draft Wet Cooling Towers
Compliance Intake Type: Fine-mesh Travelling Screens with Fish Handling/Returns
Reduced Intake Capacity: 33,333 gpm (416,667 gpm * 0.08)
Regional Capital Cost Factor: 1.08
Recirculating Wet Cooling Tower Cost Development:
Cooling Tower Material of Construction: Redwood
Number of Cooling Tower Units: 2
Cooling Flow for Each Tower Unit: 208,334 gpm
Basic Redwood Tower with Splash Fill Capital Cost Equation:
n * (-5E-5 * x2+ 70.271 * x + 25393) * regional factor,
where x = cooling flow per unit
n = number of cooling units
Items included in the installed tower capital cost equation:
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§ 316(b) Phase II TDD Costing Methodology
- Wet tower, furnished & erected
includes internal tower piping, risers, and valves
includes splash fill
includes fans and motors
includes electrical service and housing
- Site preparation, clearing, grading
- Excavation for basins and piping
- Circulating water piping, valves, and fittings to and from condenser
- Access roads
- Full circulating pumps and housing
- Installed concrete basins, sumps, and footings
- Electrical wiring, controls, and transformers
- Blowdown-water treatment facility
- Acceptance testing
- Installation
Factors included in the installed tower capital cost equation (i.e., these factors inflate the direct capital costs):
Construction management, mobilization and demobilization
Design engineering and architectural fees
Contractor overhead and profit
Turnkey Fee
Contingencies
Additional Cooling Tower Retrofit Scaling Factor: 20 percent.
Regional Capital Cost Factor: 1.08
Total Capital Cost of Installed Cooling Tower (2 unit tower system): $44,550,000 (new facility project cost)
+ $8,910,000 (retrofit cost factor) = $53.550.000
Intake and Discharge Piping Modification Capital Costs:
Pipe modification costs are based on the following assumptions:5
• Piping material and installation cost is $12 per in-diameter per ft-length.
5 The Agency excluded makeup water pump costs from its derived equations for cooling system
conversions. In doing so, the Agency attempted to compensate for the situations where existing pumps
can be reused in the converted recirculating system, as was the case for the Jefferies Steam Plant
conversion (see Chapter 4 for futher discussion of cooling tower conversion example cases). However, the
Agency recognized that the probability of existing circulating water pumps being reused for retrofitted
tower systems was low. Therefore, because the Agency was able to confirm the reuse of existing intake
structures for three of the example cases, the Agency considered the cost of the makeup pump to offset the
possible savings of pump reuse such as the Jefferies plant to be appropriate. The Agency estimates that
the installed cost of intake pumps, such as for the model plant cost example above, would be a very small
fraction of the total cost of the installed cooling tower system (less than 0.25 percent). For the final rule's
analyses, the Agency will consider the costs of new intake pumps at a portion, or all cooling system
conversions.
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§ 316(b) Phase II TDD Costing Methodology
• Additional retrofit cost equal to 30% of material and installation.
• Note: EPA inadvertently excluded excavation, backfill, and other civil costs from the intake piping
modifications. This could represent a significant cost increase. The Agency intends to rectify this
error for the final rule's analysis.
• Additional cost factors as follows:
Item Factor
Mobilization/Demobilization 3%
Engineering 10%
Site Work 5%
Controls 3%
Contingency 10%
Allowance 5 %
• Pipe characteristics as follows:
Table EX-2
Compliance Intake
302^_(SE!SL____
1,000
5,000
10,000
50,000
100,000
350,000
PipeCharacterisdcsforlnts^^
Pipe Diameter
(in)
8
16
20
42
60
60 (3 pipes)
PjipmgModiflcadoMforCtrolin
Pipe Velocity
(fp_s)
6.4
8.0
10
12
11
13
LS^^E^E—————
Pipe Length
(ft)
2,000
2,000
2,000
3,000
4,000
4,000
Cost equation (incorporating retrofit factor and all other factors) derived is as follows:
(-0.00002*FlowA2 + 48.801*Flow + 350292) * regional factor
Total Capital Cost of Intake/Discharge Piping Modification for this example: $1.955,000
Cooling Water Intake Technology Retrofit Capital Cost:
• Utilized intake technology capital cost curves derived for New Facility Rule.
• Multiplied by additional retrofit cost equal to 30% of installed costs.
• Multiplied by regional capital cost factor.
• Utilized flow for sizing and construction factors as described in Table EX-1 above:
Fine-mesh travelling screens with fish handling/return capital cost equation:
(5 E-l 1 * x3 - 2 E-5 * x2 + 7.1477 * x + 113116) * (1.05* 1.30) * regional factor * construction factor
where x = appropriate flow for sizing (which is 50 % of baseline, once-through flow for this example)
2.34
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§ 316(b) Phase II TDD Costing Methodology
Total Capital Cost of Intake Structure Technology Modification for this example: $1.748.800 (this includes
addition of fine mesh travelling screens with fish handling/return to the existing intake).
Total Capital Cost of Cooling System Conversion and Intake Upgrade: $57.414.400.
Condenser Upgrade Capital Costs:
EPA estimates that some condensers would require upgrades premature to the end of their useful lives due to
the cooling system conversion. For this example case, the condenser baseline tube material is Copper/Nickel
Alloy. The Agency determined that the tubes would be upgraded to 304 Stainless Steel for a cooling tower
using brackish cooling water. This upgrade would occur when the existing condenser had 10 years of useful
life remaining. Therefore, EPA developed cost estimates for the tube upgrade and the tube replacement.
The Capital Cost equation for CuNi replacement is as follows:
Number of Cooling Tower Units * (18.046 * Unit Cooling Flow - 13134) * Regional Factor.
Accounts for cost of materials
Accounts for vibration/stability analysis
Accounts for labor, overhead, etc.
EPA utilizes a 1.58 factor for safety at nuclear plants
Replacement tubing includes non-corroding internal tubing liner
Does not include an additional retrofit or allowance, due to the fact that the cost estimates forming the
basis of the curves were for actual tube replacement projects.
Capital Cost of Existing Material Condenser Tube Replacement: $8.029.400
Capital Cost of Condenser Tube Upgrade: $8.774.600
The economic analysis calculates the net capital cost to the facility for the premature replacement of
the condenser tube sheets. The analysis accounts for the upgraded material and deducts the useful life
of the replacement. See the Economic and Benefits Analysis for more information.
Operation and Maintenance Costs of Baseline Intake Pumping (once-through):
Pumping head estimated at 50 ft for all systems.
Pump and motor efficiency estimated at 70 percent.
Annual hours of operation estimated at 7860 (i.e., 90 percent of 8760).
Energy cost estimated at $0.03/KWh. This value is set near the average wholesale cost of electricity.
To be conservative, this estimation of the unit energy cost is intended to account for the pumping
electricity costs and does not account for such O&M costs as pump maintenance.
Baseline Intake Pumping Annual Cost Equation: - (50 * Flow * 8.33 * 0.746 * 7860 * 0.03) / (33,000
*0.7)
Baseline Intake Annual Pumping Cost in this Example: $1.321.500
Wet Cooling Tower Operation and Maintenance:
Includes periodic equipment replacement and maintenance costs (i.e., 10th and 20th year overhauls).
2.35
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§ 316(b) Phase II TDD Costing Methodology
Includes pumping and fanning O&M requirements.
Includes blowdown-water treatment and disposal.
Accounts for increase in equipment replacement costs as tower useful life diminishes.
Includes chemical addition.
Does not include turbine efficiency penalty, which is factored into the economic analysis through lost
revenue.
Redwood Wet Tower O&M Equation: n * (-4E-6 * x2 +11.617 * x + 2055.2)
Where x = cooling flow per unit
n = number of cooling units
Wet Cooling Tower O&M Cost Estimate for this Example: $4.497.300
Intake Pumping O&M Costs:
Developed in a manner very similar to the once-through, baseline intake pumping costs. However, the
compliance intake flow is used in place of the baseline, once-through flow.
Wet Tower Compliance Intake Pumping O&M Cost Estimate for this Example: $105.700
Cooling Water Intake Technology O&M Costs:
Based on outreach with industry representatives, EPA estimated annual O&M cost as a percentage
of total capital cost (that is, those costs developed for new facility projects, not including retrofit
factors). The O&M cost factor ranges between 8 percent of total capital cost for the smallest size
traveling screens with and without fish handling equipment and 5 percent for the largest traveling
screen since O&M costs do not increase proportionately with screen size. The screen O&M costs are
based on the size of the screen, which are based on the initial sizing flow. For this example, the
Agency uses the sizing flow of !/2 of the baseline once-through flow.
O&M Equation for Fine-mesh Travelling Screens with Fish Handling/Return:
-3E-13 * x3 - 4 E-8*x2 +0.2081 *x+ 11485
Cooling Water Intake Technology O&M Costs for This Example: $50.390
Total Annual O&M Costs for this Example: $3.331.900
2.9 REPOWERINS FACILITIES AND MODEL PLANT COSTS
Under this proposed rule certain forms of repowering could be undertaken by an existing power generating facility that
uses a cooling water intake structure and it would remain subject to regulation as a Phase II existing facility. For
example, the following scenarios would be existing facilities under the proposed rule:
- An existing power generating facility undergoes a modification of its process
short of total replacement of the process and concurrently increases the design
capacity of its existing cooling water intake structures;
- An existing power generating facility builds a new process for purposes of the
2.36
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§ 316(b) Phase II TDD Costing Methodology
same industrial operation and concurrently increases the design capacity of its
existing cooling water intake structures;
- An existing power generating facility completely rebuilds its process but uses the
existing cooling water intake structure with no increase in design capacity.
Thus, in most situations, repowering an existing power generating facility would be
addressed under this proposed rule.
As discussed in Section III.B of the preamble, the section 316(b) Survey acquired technological and economic
information from facilities for the years 1998 and 1999. With this information, the Agency established a subset of
facilities potentially subject to this rule. Since 1999, some existing facilities have proposed and/or enacted changes to
their facilities in the form of repowering that could potentially affect the applicability of this proposal or a facility's
compliance costs. The Agency therefore conducted research into repowering facilities for the section 316(b) existing
facility rule and any information available on proposed changes to their cooling water intake structures. The Agency
used two separate databases to assemble available information for the repowering facilities: RDFs NEWGen Database,
November 2001 version and the Section 316(b) Survey.
In January 2000, EPA conducted a survey of the technological and economic characteristics of 961 steam-electric
generating plants. Only the detailed questionnaire, filled out by 283 utility plants and 50 nonutility plants, contains
information on planned changes to the facilities' cooling systems (Part 2, Section E). Of the respondents to the detailed
questionnaire, only six facilities (three utility plants and three nonutility plants) indicated that their future plans would
lead to changes in the operation of their cooling water intake structures
The NEWGen database is a compilation of detailed information on new electric generating capacity proposed over the
next several years. The database differentiates between proposed capacity at new (greenfield) facilities and
additions/modifications to existing facilities. To identify repowering facilities of interest, the Agency screened the 1,530
facilities in the NEWGen database with respect to the following criteria: facility status, country, and steam electric
additions. The Agency then identified 124 NEWGen facilities as potential repowering facilities.
Because the NEWGen database provides more information on repowering than the section 316(b) survey, the Agency
used it as the starting point for the analysis of repowering facilities. Of the 124 NEWGen facilities identified as
repowering facilities, 85 responded to the section 316(b) survey. Of these 85 facilities, 65 are in-scope and 20 are out
of scope of this proposal. For each of the 65 in scope facilities, the NEWGen database provided an estimation of the
type and extent of the capacity additions. The Agency found that 36 of the 65 facilities would be combined-cycle
facilities after the repowering changes. Of these, 34 facilities are projected to decrease their cooling water intake after
repowering (through the conversion from a simple steam cycle to a combined-cycle plant). The other 31 facilities within
the scope of the rule would increase their cooling water intake. The Agency examined the characteristics of these
facilities projected to undergo repowering and determined the waterbody type from which they withdraw cooling water.
The results of this analysis are presented in Table 2-22.
Table 2-22 - In-scope Existing Facilities Projected to Enact Repowering Changes
2.37
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§ 316(b) Phase II TDD Costing Methodology
Waterbody Type Repowering Facilities Projected to Repowering Facilities Projected to
Increase Cooling Water Decrease or Maintain Cooling Water
Withdrawals Withdrawals
Ocean N/A N/A
Estuary/Tidal River 3 17
Freshwater River/Stream 14 10
Freshwater Lake/Reservoir 10 1
Great Lake 0 1
Of the 65 in scope facilities identified as repowering facilities in the NEWGen database, 24 received the detailed
questionnaire, which requested information about planned cooling water intake structures and changes to capacity.
Nineteen of these 24 facilities are utilities and the remaining five are nonutilities. The Agency analyzed the section
316(b) detailed questionnaire data for these 24 facilities to identify facilities that indicated planned modifications to their
cooling systems which will change the capacity of intake water collected for the plant and the estimated cost to comply
with today's proposal. Four such facilities were identified, two utilities and two nonutilities. Both utilities responded
that the planned modifications will decrease their cooling water intake capacity and that they do not have any planned
cooling water intake structures that will directly withdraw cooling water from surface water. The two nonutilities, on
the other hand, indicated that the planned modifications will increase their cooling water intake capacity and that they
do have planned cooling water intake structures that will directly withdraw cooling water from surface water.
Using the NEWGen and section 316(b) detailed questionnaire information on repowering facilities, the Agency
examined the extent to which planned and/or enacted repowering changes would effect cooling water withdrawals and,
therefore, the potential costs of compliance with this proposal. Because the Agency developed a cost estimating
methodology that primarily utilizes design intake flow as the independent variable, the Agency examined the extent to
which compliance costs would change if the repowering data summarized above were incorporated into the cost analysis
of this rule. The Agency determined that projected compliance costs for facilities withdrawing from estuaries could be
lower after incorporating the repowering changes. The primary reason for this is the fact that the majority of estuary
repowering facilities would change from a steam cycle to a combined-cycle, thereby maintaining or decreasing their
cooling water withdrawals (note that a combined-cycle facility generally will withdraw one-third of the cooling water
of a comparably sized full-steam facility). Therefore, the portion of compliance costs for regulatory options that
included flow reduction requirements or technologies could significantly decrease if the Agency incorporated repowering
changes into the analysis. As shown in Table 2-22 the majority of facilities projected to increase cooling water
withdrawals due to the repowering changes use freshwater sources. In turn, the compliance costs for these facilities
would increase if the Agency incorporated repowering for this proposal.
2.9 CAPACITY UTILIZATION RATE CUT-OFF
The Agency is proposing standards for reducing impingement mortality but not entrainment when a facility operates
at a capacity utilization rate of less than 15 percent over the course of several years (see § 125.94 (b)(2) of the proposed
rule). Capacity utilization rate means the ratio between the average annual net generation of the facility (in MWh) and
the total net capability of the facility (in MW) multiplied by the number of available hours during a year. The average
annual generation is to be measured over a five year period (if available) of representative operating conditions.
Incorporation of capacity utilization into the level of control was found to be the most economically practicable given
2.38
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§ 316(b) Phase II TDD Costing Methodology
these facilities' reduced operating levels. Fifteen percent capacity utilization corresponds to facility operation for
roughly 55 days in a year (that is, less than two months). The Agency refers to this differentiation between facilities
based on their operating time as a capacity utilization cut-off. Facilities operating at capacity utilization rates of less
than 15 percent are generally facilities of significant age, including the oldest facilities within the scope of the rule.
Frequently, entities will refer to these facilities as peaker plants, though the definition extends to a broader range of
facilities. These peaker plants are less efficient and more costly to operate than other facilities. Therefore, operating
companies generally utilize them only when demand is highest and, therefore, economic conditions are favorable.
Because these facilities operate only a fraction of the time compared to other facilities, such as base-load plants, the
peaking plants achieve sizable flow reductions over their maximum design annual intake flows. The lower the intake
flow at a site, the lesser the potential for entraining of organisms. Therefore, the concept of an entrainment reduction
requirement for such facilities does not appear necessary. Additionally, the plants typically operate during two specific
periods: the extreme winter and the extreme summer demand periods. Each of these periods can, in some cases,
coincide with periods of abundant aquatic concentrations and/or sensitive spawning events. However, it is generally
accepted that peak winter and summer periods will not be the most crucial for aquatic organism communities on a
national basis.
Based on an analysis of data collected through the detailed industry questionnaire and the short technical questionnaire,
EPA believes that today' s proposed rule would apply to 5 3 9 existing steam electric power generating facilities. Of these,
53 facilities operate at less than 15 percent capacity utilization and would potentially only comply with impingement
controls, with 34 of these estimated to actually require such controls. (The remaining 19 facilities have existing
impingement controls).
Of the facilities exceeding the capacity utilization cut-off, the median and average capacity utilization is 50 percent.
As a general rule, steam plants operate cyclically between 100 percent load and standby. In turn, the intake flow rate
of a typical steam plant cycles between flows approaching the full design rate and standby (that is, near-zero intake
flow). Facilities operating with an average capacity utilization of 5 0 percent would generally withdraw more than three
times as much water over the course of time than a facility with a capacity utilization of less than 15. Therefore, the
capacity utilization cut-off coincides with an approximate flow reduction, and hence entrainment reduction, of roughly
70 percent as compared to the average facility above the cut-off. This level of reduction is within the range of
performance standards for entrainment reduction. Were the Agency to establish the cut-off at less than 20 percent
capacity utilization, an additional 18 facilities would be subject to the reduced requirements and the comparable flow
reduction would be roughly 60 percent. The operating period would extend to approximately 75 days (that is, 2.5
months) for the hypothetical 20 percent cut-off. Were the Agency to establish the cut-off at less than 25 percent
capacity, 108 of the 539 facilities would be subject to the reduced standards, and the comparable entrainment reduction
would be roughly 54 percent. For a hypothetical 25 percent capacity utilization cut-off, the operating period would
extend to approximately three months.
The median age of generating units with capacity utilization factors less than 15 percent is 48 years in 2002. The
median age of generating units with capacity utilization factors of less than 25 percent and equal to or greater than 15
percent is 43 years. The age of generating units shows a continued trend upwards as capacity utilization rate increases.
This trend agrees with the theory that existing peaking plants generally are aged facilities only dispatched when
economic conditions are favorable and/or demand is highest.
The Agency examined the cooling water use of all plants for trends associated with or related to capacity utilization.
As the analysis of unit age described above shows, most plants with low capacity utilization rates are very old. These
plants generally utilize once-through cooling systems. For some plants, not all generating units may be available or
capable of operating during extended periods, and the plant may staggered operation of generating units may be
employed. However, as discussed above, the Agency believes that these aged units generally operate at or near peak
capacity when they are dispatched. Therefore, the intake pumps will operate at near design intake capacity when
functioning. Because a peaker plant will only operate for limited times during the year, its overall use of water (that
2.39
-------
§ 316(b) Phase II TDD Costing Methodology
is, the average annual intake) would be significantly below its design maximum intake rate. The Agency calculated a ratio of actual annual intake (for 1998)
to maximum-design annual intake for the plants within the scope of this rule and compared this to capacity utilization. Though the data shows a significant
degree of scatter, the Agency concludes that the data plotted in Figure 2-1 (actual-to-design intake ratio versus capacity utilization rate for all model plants
within scope of this proposed rule) shows that generally, the lower the capacity utilization of a plant, the lower the intake flow as a percent of the maximum
design intake capability.
2.40
-------
§ 316(b) Phase II TDD Costing Methodology
REFERENCES
Fi£ie2-1. fctual-toDesigi Intake versus Capacity Utilization for Pt\ Model Plants
100%
90%-
TCP/o-
2 60%-|
I 55%-!
.2> 50%-
in
2 4ffi
15 4056-1
£
30%-
25%-
20%-
15%-
10%-
5%
CP/O
4 *•*•
v < /•;/*"•*
n
* \* SA*** I *4^i WV A* f/ ^ *
••; v\^>??^ • •
»*%* »X^ i* • '*
t «* *« » » * »
• v »*-: **
:4v;.V v • Y • •
*A*fA^^***A * *
*4A TT . ^ . . . A
>f.» ,»^ .
-------
§ 316(b) Phase II TDD Costing Methodology
Dayton, OH and Faysal Bekdash, SAIC.
Antaya, Bill. 1999. Personal communication between Bill Antaya, The Coon-De Visser Company and Faysal Bekdash,
SAIC.
Boles, D.E., et al. 1973. Technical and Economic Evaluations of Cooling Systems Slowdown Control Techniques.
Burns, J.M., and Micheletti, W.C. Comparison of Wet and Dry Cooling Systems for Combined Cycle Power Plants.
November 4, 2000.
Burns, J.M. and Tsou, J.L., 2001. Modular Steam Condenser Replacements Using Corrosion Resistant High
Performance Stainless Steel Tubing. Proceedings from a conference of the American Society of Mechanical Engineers.
Campbell, Thomas A. 2001. Correspondence from Thomas A. Campbell, Managing Partner, Campbell, George &
Strong, LLP, to the Cooling Water Intake Structure (New Facilities) Proposed Rule Comment Docket Clerk, Water
Docket, EPA. Subject: Submission of Comments Regarding May 25, 2001 Federal Register Notice of Data
Availability; National Pollutant Discharge Elimination System-Regulations Addressing Cooling Water Intake
Structures for New Facilities. June 25, 2001.
Coss, Tim. 2000. Personal communication (February, and March) between Tim Coss, the Boulder Trenchless Group
and Faysal Bekdash, SAIC.
U.S. Department of Energy (DOE). 1994. Environmental Mitigation at Hydroelectric Projects: Volume II. Benefits
and Costs of Fish Passage and Protection. Francfort, J.E., Cada, G.F., Dauble, D.D., Hunt, R.T., Jones, D.W.,
Rinehart, B.N., Sommers, G.L. Costello, R.J. Idaho National Engineering Laboratory.
U.S. EPA. Economic and Engineering Analyses of the Proposed §316(b) New Facility Rule. Office of Water.
August 2000. EPA
U.S. EPA (EPA). (1996). Technology Transfer Handbook - Management of Water Treatment Plant Residuals,
EPA/625/R-95/008, April 1996.
Edison Electric Institute (EEI). Environmental Directory of U.S. Power Plants. 1996.
Electric Power Research Institute (EPRI). 1995. Proceedings: Cooling Tower and Advanced Cooling Systems
Conference. Summary of Report TR-104867, obtained from EPRI's Web site at http://www.epri.com on 12/1/99.
EPRI. 1986a. Performance of'a Capacitive Cooling System for Dry Cooling. Summary of Report CS-4322, obtained
from EPRI's Web site at http://www.epri.com on 12/1/99.
EPRI. 1986b. Wet-Dry Cooling Demonstration: Test Results. Summary of Report CS-4321, obtained from EPRI's
Web site at http://www.epri.com on 12/1/99.
Federal Energy Regulatory Commission (FERC). 1995. Preliminary Assessment of Fish Entrainment atHydropower
Projects, A Report on Studies and Protective Measures, Volume 1. Office of Hydropower Licensing, Washington, DC.
Paper No. DPR-10.
Flory, A. FlowServe Pump Division. Telephone Contact with John Sunda, SAIC. Regarding equipment costs for intake
pumps and variable frequency drives. May 14, 2001.
Ganas, Michael. Assembling underwater concrete pipelines. Published article provided by Price Brothers (no date or
2.42
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§ 316(b) Phase II TDD Costing Methodology
journal name).
GEA Power Cooling Systems, Inc. (GEA). Undated. Direct Air Cooled Condenser Installations. Brochure. R-227.
Gerwick, B.C. Jr. 2000. Construction of Marine And offshore structures. 2nd edition. CRC Press.
Gunderboom, Inc. System Specification: Gunderboom Marine/Aquatic Life Exclusion System, obtained from the
Gunderboom, Inc. Web site at http://www.gunderboom.com/specs/MLES/MLESTl.htm.
Hensley, J.C. Undated. Cooling Tower Fundamentals. 2nd Edition. The Marley Cooling Tower Company (Mission,
Kansas). 1985.
Huber, Gary. 2000. Personal communication (February, and March) between Gary Huber, Permalok and Faysal
Bekdash, SAIC.
Kaplan, Charles. Memo to Martha Segall. April 18, 2000. Subject: Flow Reduction. (Water Docket #1-1073-TC).
Mirsky, G.R., etal. 1992. TheLatest Worldwide Technology in Environmentally Designed Cooling Towers. Cooling
Tower Institute 1992 Annual Meeting Technical Paper Number TP92-02.
Mirsky, G. and Bautier, J. 1997. Designs for Cooling Towers and Air Cooled Steam Conensers that Meet Today's
Stringent Environmental Requirements. Presented at the EPRI 1997 Cooling Tower Conference (St. Petersburg,
Florida) and ASME 1997 Joint Power Conference (Denver, Colorado).
Mirsky, G. 2000. Personal communication between Gary Mirsky, Hamon Cooling Towers and Faysal Bekdash, SAIC.
Email dated 3/27/00.
Montdardon, S. 2000. Personal communication (February, and March) between Stephan Montdardon, Torch Inc. and
Faysal Bekdash, SAIC.
Nicholson, J.M. (Stone & Webster Engineering Corp.) 1993. Preliminary Engineering Evaluation. Public Service
Electric and Gas Company Salem Generating Station, NJPDES Permit No. NJ0005622, Public Hearing.
Congress of the United States, Office of Technology Assessment (OTA). 1995. Fish Passage Technologies: Protection
at Hydropower Facilities. OTA-ENV-641.
Paroby, Rich. 1999. Personal communication between Rich Paroby, District Sales Manager, Water Process Group
and Deborah Nagle, U.S. EPA. E-mail dated May 12, 1999.
Power Plant Research Program (PPRP) for Maryland. 1999. Cumulative Environmental Impact Report (CEIR), 10th
Annual. Obtained from Maryland's PPRP Web site at http://www.dnr.md.us/bay/pprp/ on 11/18/99.
R.S. Means Company, Inc. (R.S. Means). 1997a. Plumbing Cost Data 1998. 21st Annual Edition.
R.S. Means. 1997b. Heavy Construction Cost Data 1998. 12th Annual Edition.
R.S. Means. 1997c. Environmental Remediation Cost Data 1998.
Science Applications International Corporation (SAIC). 1994. Background Paper Number 3: Cooling Water Intake
Technologies. Prepared by SAIC for U.S. EPA. Washington, DC.
2.43
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§ 316(b) Phase II TDD Costing Methodology
SAIC. 1996. Supplement to Background Paper 3: Cooling Water Intake Technologies. Prepared by SAIC for U.S.
EPA. Washington, DC.
SAIC. 2000. Cost Research and Analysis of Cooling Water Technologies for 316(b) Regulatory Options, Prepared
by SAIC for Tetra Tech, for U.S. EPA. Washington, DC.
Stone & Webster Engineering Corporation. 1992. Evaluation of the Potential Costs and Environmental Impacts of
Retrofitting Cooling Towers on Existing Steam Electric Power Plants that Have Obtained Variances Under Section
316(a) of the Clean Water Act. Prepared by Stone & Webster for the Edison Electric Institute (EEI).
Tallon, B. GEA Power Systems Inc. Telephone Contact with John Sunda, SAIC. Regarding Air Cooled Condenser
Fans. October 22, 2001.
Tatar, G. El Dorado Energy. Telephone Contact with John Sunda, SAIC. Regarding operation of the air cooled
condenser fans. October 19, 2001.
Taylor, S. Bechtel. Telephone Contact with John Sunda, SAIC. Regarding cooling water pumping and condenser
operation. May 11, 2001.
US Filter/Johnson Screens (US Filter). 1998. Surface Water Intake Screen Technical Data. Brochure.
Utility Data Institute (UDI). 1995. EEI Power Statistics Database. Prepared by UDI for EEI. Washington, DC.
The Utility Water Action Group (UWAG). 1978. Thermal Control Cost Factors. Chapter 2 - Report on the Capital
Costs of Closed-Cycle Cooling Systems. Prepared by Stone & Webster Engineering Corporation for UWAG.
Additional References Used for General Information But Not Specifically Cited
Envirex Inc. 1973. Traveling screens to protect fish in water intake systems. Bulletin No. 316-300.
Gathright, Trent. 1999. Personal communication between Trent Gathright, Marketing Manager, Brackett Green
and Faysal Bekdash, SAIC. Letter dated November 16, 1999.
GEA. Undated. PAC System™: The Parallel Condensing System. Brochure.
Geiger. Undated. GeigerFipro -Fimat. Efficient, modern fish protection systems. Fish repelling plants of the
new generation. Brochure.
Norell, Bob. 1999. Personal communication between Bob Norell, US Filter/Johnson Screens and Tracy Scriba,
SAIC.
Puder, M.G. and J.A. Veil. 1999. Summary Data on Cooling Water Use at Utilities andNonutilities. Prepared
by Puder and Veil, Argonne National Laboratory for U.S. DOE.
Swanekamp, Robert, PE. 1998. Parallel condensing combines best of all-wet, all-dry methods. Power.
July/August 1998 issue.
U.S. Filter. 1999. Raw Water Screening Intake Systems. Brochure.
2.44
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§ 316(b) Phase II TDD Costing Methodology
List of Cost Curves and Equations in Appendix B
Chart 2-1. Capital Costs of Basic Cooling Towers with Various Building Material (Delta 10 Degrees)
Chart 2-2. Douglas Fir Cooling Tower Capital Costs with Various Features (Delta 10 Degrees)
Chart 2-3. Red Wood Cooling Tower Capital Costs with Various Features (Delta 10 Degrees)
Chart 2-4. Concrete Cooling Tower Capital Costs with Various Features (Delta 10 Degrees)
Chart 2-5. Steel Cooling Tower Capital Costs with Various Features (Delta 10 Degrees)
Chart 2-6. Fiberglass Cooling Tower Capital Costs with Various Features (Delta 10 Degrees)
Chart 2-7. Actual Capital Costs for Wet Cooling Tower Projects and Comparable Costs from EPA Cost
Curves
Chart 2-8. Total O&M Red Wood Tower Annual Costs - 1st Scenario
Chart 2-9. Total O&M Concrete Tower Annual Costs - 1st Scenario
Chart 2-10. Variable Speed Pump Capital Costs
Chart 2-11. Municipal Water Use Costs
Chart 2-12. Gray Water Use Costs
Chart 2-13. Capital Costs of Passive Screens Based on Well Depth
Chart 2-14. Capital Costs of Passive Screens for a Flow Velocity 0.5 ft/sec
Chart 2-15. Capital Costs of Passive Screens for a Flow Velocity 1 ft/sec
Chart 2-16. Velocity Cap Total Capital Costs
Chart 2-17. Concrete Fittings for Intake Flow Velocity Reduction
Chart 2-18. Steel Fittings for Intake Flow Velocity Reduction
Chart 2-19. Traveling Screens Capital Cost Without Fish Handling Features Flow Velocity 0.5 ft/sec
Chart 2-20. Traveling Screens Capital Cost With Fish Handling Features Flow Velocity 0.5 ft/sec
Chart 2-21. Traveling Screens Capital Cost Without Fish Handling Features Flow Velocity 1 ft/sec
Chart 2-22. Traveling Screens Capital Cost With Fish Handling Features Flow Velocity 1 ft/sec
Chart 2-23. Fish Spray Pumps Capital Costs
Chart 2-24. O&M Costs for Traveling Screens Without Fish Handling Features Flow Velocity 0.5 ft/sec
Chart 2-25. O&M Costs for Traveling Screens With Fish Handling Features Flow Velocity 0.5 ft/sec
Chart 2-26. O&M Costs for Traveling Screens Without Fish Handling Features Flow Velocity 1 ft/sec
Chart 2-27. O&M Costs for Traveling Screens With Fish Handling Features Flow Velocity 1 ft/sec
Chart 2-28. Capital Cost of Fish Handling Equipment Screen Flow Velocity 0.5 ft/sec
Chart 2-29. O&M for Fish Handling Features Flow Velocity 0.5 ft/sec
Chart 2-30. Gunderboom Capital and O&M Costs for Simple Floating Structure
2.45
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§ 316(b) Phase II TOO
Costing Methodology
Chart 2-10. Variable Speed Pump Capital Cost
$900,000
$800,000
$700,000
$600,000
o $500,000
o
ra$400,000
Pump, Motor & VFD
y = 3.1667x + 16667
R2=1
VFD
y=1.803x-6E-11
R2=1
Pump & Motor
y=1.6859x +13369
R2 = 0.9998
50,000
100,000 150,000
FlowGPM
200,000
* Pump, Motor and Varible Freq. Drive • Pump and Motor A Variable Frequency Drive
250,000
70
-------
§ 316(b) Phase II TOO
Costing Methodology
Chart 2-11. Municipal Water Use Costs
$10,000,000
$9,000,000
$8,000,000
$7,000,000
$6,000,000
«
o
o
re $5,000,000
c
c
<
$4,000,000
$3,000,000
$2,000,000
$1,000,000
$0
500
y = 2102.4x
R2=1
1000 1500
2000 2500
FlowGPM
3000 3500 4000 4500
-------
§ 316(b) Phase II TDD
Costing Methodology
Chart 2-12. Gray Water Use Costs
$7,000,000
$6,000,000
$5,000,000
•5; $4,000,000
o
o
"re
c
< $3,000,000
$2,000,000
$1,000,000
-------
§ 316(b) Phse II TOO
Costing Methodology
Chart 2-13. Capital Costs of Passive Screens Based on Well Depth
$160,000
$140,000
$120,000
$40,000
$20,000
$0
y = 3240x + 59400
R2=1
20
y = 0.088x3 - 11.406x2 + 1406.4x + 20961
R2 = 0.9999
2277x +34350
R2=1
40
60
Well Depth Feet
80
100
* Screen width 2 feet Screen width 5 feet Screen width 10 feet * Screen width 14 feet
120
-------
§ 316(b) Phase II TOO
Costing Methodology
Chart 2-14. Capital Costs of Passive Screens - Flow Velocity 0.5 ft/sec
$160,000
$140,000
0.0002x'+1.5923x +47041
E-08x3 - 0.0008X2 + 12.535x + 11263
5000
10000
15000
20000
FlowGPM
Screen width 2 ft Water depth 8-65 ft
Screen width 10 ft water depth 8-20 ft
Screen width 5 ft water depth 8-30 ft
Screen width 14 ft water depth 8 ft
25000
-------
§ 316(b) Phase II TOO
Costing Methodology
Chart 2-15. Capital Costs of Passive Screens - Flow Velocity 1 ft/sec
$160,000
$140,000
$120,000
$100,000
$40,000
$20,000
$0
s4E-05x + 1.0565x + 43564
y\5E-09x3 - 0.0002X2 + 6.5501x + 9792.6
R =0.9911
5000 10000 15000 20000 25000 30000 35000 40000 45000 50000
Flow in gpm
Screen width 2 ft Water depth 8-65 ft
Screen width 10 ft water depth 8-20 ft
Screen width 5 ft water depth 8-30 ft
Screen width 14 ft water depth 8 ft
-------
§ 316(b) Phase II TOO
Costing Methodology
Chart 2-16. Velocity Caps Total Capital Costs
y = 0.071 x - 9.865x + 775.03x + 66088
-9.865x' + 775.03x + 49213
R2 = 0.9962
w $60,000 -
-= $50,000
10
20
30 40
Water Depth in feet
50
60
70
«18000gpmflow>70000 (23 VC)
•35000>flow>18000(9VC)
*157000gpm(35VC)
A 70000>flow>35000 (15 VC)
• 204000 gpm (46 VC)
-------
§ 316(b) Phase II TOO
Costing Methodology
Chart 2-17. Concrete Fittings for Intake Flow Velocity Reduction
$80,000
$70,000
$60,000
$50,000
o
o
re $40,000
Q.
re
O
$30,000
$20,000 -
$10,000
$0
= -4E-06x2 + 0.5395x + 2719.6
R2 = 0.9881
y = -2E-05x2 + 4.0765X - 148706
R2=1
20000
40000
60000
Flow GPM
80000
100000
120000
-------
§ 316(b) Phase II TOO
Costing Methodology
Chart 2-18. Steel Fittings for Intake Flow Velocity Reduction
$180,000
$160,000
$140,000
$120,000
g $100,000
o
re" $80,000
y = 5E-08x2 + 0.5222X + 1250.3
R2 = 0.9998
50000
100000
150000 200000
Flow GPM
250000
300000
350000
-------
§ 316(b) Phase II TOO
Costing Methodology
$800,000
$700,000
$600,000
$500,000
in
o
O
a.
re
O
re $400,000
$300,000
$200,000
$100,000
$0
Ft = 0.9961
Chart 2-19. Travel Screens Capital Cost Without Fish Handling Features
Flow Velocity 0.5ft/sec - Costs for New Facilities
v = 5E-10x3 - 0.0001X2 + 12.467X + 65934
y = 5E-10x3 - 9E-05X2 + 10.143x + 63746
R2 = 0.9928
y = 2E-09x3 - O.OOOIx2 + 9.7773x + 54004
Ft = 0.9955
y = 5E-08x3 - 0.0013x2 + 20.892x + 18772
R2 = 0.9991
20000
40000
60000
FlowGPM
80000
100000
120000
» width 2 feet
I width 5 feet
width 10 feet
* width 14 feet
-------
§ 316(b) Phase II TOO
Costing Methodology
$1,200,000
$1,000,000
$800,000
(A
O
O
re $600,000
a.
re
O
$400,000
$200,000
Chart 2-20. Travel Screens Capital Cost With Fish Handling Features
Flow Velocity 0.5ft/sec - Costs for New Facilities
y = 6E-10x3 - O.OOOIx2 + 15.874x + 91207
Ft = 0.995
y = 5E-10x3 - 9E-05x2 + 12.726x + 88302
R2 = 0.9931
y = 1 E-09x3 - 8E-05x2 + 12.223x + 80790
R2 = 0.994
y = 6E-08x3 - 0.0014x2 + 28.994x + 36372
R2 = 0.9992
20000
40000
60000
FlowGPM
80000
100000
120000
* width 2 feet
I width 5 feet
width 10 feet
* width 14 feet
-------
§ 316(b) Phase II TOO
Costing Methodology
$800,000
$700,000
$600,000
$500,000
in
o
O
a.
re
O
re $400,000
$300,000
$200,000
$100,000
$0
Chart 2-21. Travel Screens Capital Cost Without Fish Handling Features
Flow Velocity 1 ft/sec - Costs for New Facilities
y = 5E-11x3 - 2E-05x2 + 5.6762x + 81695
y = 5E-11x3 - 2E-05X2 + 5.0073x + 64193
R = 0.9902
\
y = 3E-10x3 - 4E-05x2 + 5.481x + 44997
R2 = 0.9962
y = 8E-09x3 - 0.0004x2 + 10.917x + 16321
R2 = 0.9911
50000 100000 150000
FlowGPM
200000
250000
» width 2 feet
I width 5 feet
width 10 feet
* width 14 feet
-------
§ 316(b) Phse II TOO
Costing Methodology
1200000
1000000
800000
in
o
O
Q.
re
O
600000
400000
200000
Chart 2-22. Travel Screens Capital Cost With Fish Handling Features
Flow Velocity 1 ft/sec - Costs for New Facilities
y = 5E-11x3 - 2E-05x2 + 7.1477x + 113116
FT = 0.9942
y = 5E-11x3 - 2E-05X2 + 6.2849x + 88783
R = 0.9906
y = 2E-10x3 - 3E-05x2 + 6.921x + 68688
R = 0.9948
y = 8E-09x3 - 0.0004x2 + 15.03x + 33044
R2 = 0.9909
50000
100000
150000
200000
250000
FlowGPM
* width 2 feet
'width 5 feet
width 10 feet
* width 14 feet
-------
§ 316(b) Phase II TOO
Costing Methodology
$10,000
$9,000
$8,000
$7,000
$3,000
$2,000
$1,000
$0
Chart 2-23. Fish Spray Pumps Capital Costs - Costs for New Facilities
y = 2E-06x3 - 0.0035X2 + 3.8696x + 2446.8
R -1
y = -0.2394x^ + 47.9x + 364.04
P2 - n QQfV7
500
1000 1500
FlowGPM
2000
2500
* Spray pumps flow in GPM
-------
§ 316(b) Phase II TOO
Costing Methodology
$40,000
$35,000
$30,000
$25,000
(A
•4-i
(A
O
0 $20,000
08
O
$15,000
$10,000
$5,000
$0
Chart 2-24. O&M Cost for Traveling Screens Without Fish Handling Features
Flow Velocity 0.5ft/sec
y = -7E-06x + 0.6204x + 4045.7
R2 = 0.9956
y = -2E-05x2 + 1.0121x + 2392.4
R2 = 0.9965
y = 8E-12x3 - 2E-06x2 + 0.3899x + 7836.7
R = 0.9922
'9E-11x3- 1 E-05x2 +0.8216x+ 1319.5
R2 = 0.9997
20000
40000
60000
FlowGPM
80000
100000
120000
1 Screen width 2 feet
Screen width 5 feet
1 Screen width 10 feet
Screen width 14 feet
-------
§ 316(b) Phase II TOO
Costing Methodology
42
"55
o
08
O
$60,000
$50,000
$40,000
$30,000
$20,000
$10,000
$0
Chart 2-25. O&M Cost for Traveling Screens With Fish Handling Features
Flow Velocity 0.5ft/sec
y = 5E-12x3 - 1E-06x2 + 0.4835x + 10593
R2 = 0.9912
y = -2E-06x2 + 0.5703X + 5864.4
R2 = 0.9907
-1E-05x2 + 0.8563x +5686.3
R2 = 0.9943
!-05x2+1.6179x +3739.1
R2 = 0.9943
20000
40000
60000
Flow GPM
80000
i Screen Width 2 ft
A Screen Width 5 ft
i Screen Width 10ft
100000
120000
Screen Width 14ft
-------
§ 316(b) Phase II TOO
Costing Methodology
$40,000
$35,000
$30,000
$25,000
(A
•4-i
(A
O
0 $20,000
08
O
$15,000
$10,000
$5,000
$0
Chart 2-26. O&M Cost for Traveling Screens Without Fish Handling Features
Flow Velocity 1 ft/sec
y = -2E-06x + 0.3312x + 3621.1
R2 = 0.9963
y = 4E-13x3- 3E-07x2 + 0.1715x + 8472.1
R =0.9913
y = 1E-11x3 - 3E-06x2 + 0.4047x + 1359.4
R2=1
y = -4E-06x^ + 0.5035X + 2334
R2 = 0.9853
50000
100000 150000
FlowGPM
200000
250000
• Screen width 2 feet
Screen width 5 feet
I Screen width 10 feet
* Screen width 14 feet
-------
§ 316(b) Phase II TOO
Costing Methodology
(A
•4-i
(A
O
O
08
O
$60,000
$50,000
$40,000
$30,000
$20,000
$10,000
$0
Chart 2-27. O&M Cost for Traveling Screens With Fish Handling Features
Flow Velocity 1 ft/sec
y = -3E-13x3 - 4E-08x2 + 0.2081 x + 11485
R2 = 0.9903
\
y = -6E-07x2 + 0.2895X + 5705.3
R2 = 0.9915
y = -3E-06x2 + 0.4585X + 5080.7
R2 = 0.9954
y = -8E-06x2 + 0.806x + 3646.7
R2 = 0.982
50000
100000
150000
200000
Flow GPM
i Screen Width 2 ft
A Screen Width 5 ft
i Screen Width 10ft
Screen Width 14ft
250000
-------
§ 316(b) Phase II TOO
Costing Methodology
$400,000
$350,000
$300,000
$250,000
in
o
O
a.
re
O
re $200,000
$150,000
$100,000
$50,000
$0
Chart 2-28. Capital Cost of Fish Handling Equipment Screen
Flow Velocity 0.5 ft/sec - Costs for New Facilities
y = 7E-11x3 - 2E-05x2 + 4.0881x + 30327
y = -8E-10x3 + 5E-05X2 + 2.9353x + 32144
R = 0.9896
\
y = 4E-09x3 - 0.0002X2 + 9.7217x + 21120
R2 = 0.9994
R = 0.9924
y = 3E-11x3 - 7E-06x2 + 3.0998x + 29468
R = 0.9939
20000
40000
60000
FlowGPM
80000
100000
120000
* width 2 feet
I width 5 feet
width 10 feet
* width 14 feet
-------
§ 316(b) Phase II TOO
Costing Methodology
$16,000
$14,000
$12,000
$10,000
(A
•4-i
(A
O
0 $8,000
08
O
$6,000
$4,000
$2,000
$0
Chart 2-29. O&M Cost for Fish Handling Features
Flow Velocity 0.5ft/sec
y = -3E-12x3 + 5E-07x2 + 0.0936x + 2755.8
Ft = 0.989
y = -3E-07x + 0.1315X + 1425.7
R2 = 0.9954
y = -2E-06x2 + 0.2359x + 1640.6
R2 = 0.9869
y = -2E-05x + 0.6059x + 1346.7
R2 = 0.9866
20000
40000
60000
FlowGPM
80000
100000
120000
I Screen Width 2 ft
A Screen Width 5 ft
» Screen Width 10ft
Screen Width 14ft
-------
§ 316(b)PhaseIITDC)
Costing Methodology
in
+j
(/)
O
o
$9,000,000
$8,000,000
$7,000,000
$6,000,000
$2,000,000
$1,000,000
$0
Chart 2-30. Gunderboom Capital and O&M Costs
For Simple Floating Structure
Gunderboom Maximum Capital
y = 8E-06x2 + 18.249x + 516725
R2 = 1
Gunderboom Average Capital
y = 7E-06x2 + 15.664x + 442638
R2=1
Gunderboom Average O&M
y = 4E-06x2 - 0.1661 x + 201282
R2 =
50,000 100,000 150,000 200,000 250,000 300,000 350,000 400,000
FlowGPM
Gunderboom Average Capital •Gunderboom O&M Gunderboom Maximum Capital
-------
Section 316(b) Phase II TDD Efficacy of Cooling Water Intake Structure Technologies
Chapter 3: Efficacy of Cooling Water
Intake Structure Technologies
INTRODUCTION
To support the Section 316(b) proposed rule for existing facilities, the Agency compiled data on the performance of
the range of technologies currently used to minimize impingement and entrainment (I&E) at power plants nationwide.
The goal of this data collection and analysis effort has been to determine whether specific technologies can be
demonstrated to provide a consistent level of proven performance. This information was used to compare specific
regulatory options and their associated costs and benefits. It provides the supporting information for the proposed rule
and alternative regulatory options considered. Throughout this chapter, baseline technology performance refers to the
performance of conventional, wide mesh traveling screens that are not intended to prevent I&E. Alternative
technologies generally refer to those technologies, other than closed-cycle cooling systems that can be used to minimize
I&E. Overall, the Agency has found that performance and applicability vary to some degree based on site-specific
conditions. However, the Agency has also determined that alternative technologies can be used effectively on a
widespread basis with proper design, operation, and maintenance.
3.1 SCOPE OF DATA COLLECTION EFFORTS
Since 1992, the Agency has been evaluating regulatory alternatives under Section 316(b) of the Clean Water Act. As
part of these efforts, the Agency has compiled readily available information on the nationwide performance of I&E
reduction technologies. This information has been obtained through:
• Literature searches and associated collection of relevant documents on facility-specific performance.
• Contacts with governmental (e.g., TVA) and non-governmental entities (e.g., EPRI) that have undertaken
national or regional data collection efforts/performance studies
• Meetings with and visits to the offices of EPA Regional and State agency staff as well as site visits to
operating power plants.
It is important to recognize that the Agency did not undertake a systematic approach to data collection, i.e., the Agency
did not obtain all of the facility performance data that are available nor did it obtain the same level of information for
each facility. The Agency is not aware of such an evaluation ever being performed nationally. The most recent national
data compilation was undertaken by the Electric Power Research Institute (EPRI) in 2000, see Fish Protection at
Cooling Water Intakes, Status Report. The findings of this report are cited extensively in the following subsections.
However, EPRI's analysis was primarily a literature collection and review effort and was not intended to be an
exhaustive compilation and analysis of all data.
3.2 DATA LIMITATIONS
Because the Agency did not undertake a systematic data collection effort with consistent data collection procedures,
3-1
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Section 316(b) Phase II TDD Efficacy of Cooling Water Intake Structure Technologies
there is significant variability in the information available from different data sources. This leads to the following data
limitations:
• Some facility data include all of the major species and associated life stages present at an individual facility.
Other facilities only include data for selected species and/or life stages.
• Much of the data were collected in the 1970s and early 1980s when existing facilities were required to complete
their initial 316(b) demonstrations.
• Some facility data includes only initial survival results, while other facilities have 48 to 96-hour survival data.
These data are relevant because some technologies can exhibit significant latent mortality after initial survival.
• The Agency did not review data collection procedures, including quality assurance/quality control protocols.
• Some data come from laboratory and pilot-scale testing rather than full-scale evaluations.
The Agency recognizes that the practicality or effectiveness of alternative technologies may not be uniform under all
conditions. The chemical and physical nature of the waterbody, the facility intake requirements, climatic conditions,
and biology of the area all effect feasibility and performance. However, despite the above limitations, the Agency has
concluded that significant general performance expectations can be implied for the range of technologies and that one
or more technologies (or groups of technologies) can provide significant I&E protection at most sites. In addition, in
the Agency's view many of the technologies have the potential for even greater applicability and higher performance
when facilities optimize their use.
The remainder of this chapter is organized by groups of technologies. A brief description of conventional, once-through
traveling screens is provided for comparison purposes. Fact sheets describing each technology, available performance
data, and design requirements and limitations are provided in Attachment A. It is important to note that this chapter
does not provide descriptions of all potential CWIS technologies. (ASCE 1982 generally provides such an all-inclusive
discussion). Instead, the Agency has focused on those technologies that have shown significant promise at the
laboratory, pilot-scale, and/or full-scale levels in consistently minimizing impingement and/or entrainment. In addition,
this chapter does not identify every facility where alternative technologies have been used but rather only those where
some measure of performance in comparison to conventional screens has been made. The chapter concludes with a brief
discussion of how the location of intakes (as well as the timing of water withdrawals) could also be used to limit
potential I&E effects.
Habitat restoration projects are an additional means to comply with this proposed rule. Such projects have not had
widespread application at existing facilities. Because the nature, feasibility, and likely effectiveness of such projects
would be highly site-specific, the Agency has not attempted to quantify their expected performance level herein.
3.3 CONVENTIONAL TRAVELINS SCREENS
For impingement control technologies, performance is compared to conventional traveling screens as a baseline
technology. These screens are the most commonly used intakes at older existing facilities and their operational
performance is well established. In general, these technologies are designed to prevent debris from entering the cooling
water system, not to minimize I&E. The most common intake designs include front-end trash racks (usually consisting
of fixed bars) to prevent large debris from entering system. They are equipped with screen panels mounted on an
endless belt that rotates through the water vertically. Most conventional screens have 3/8-inch mesh that prevents
smaller debris from clogging the condenser tubes. The screen wash is typically high pressure (80 to 120 pounds per
square inch (psi)). Screens are rotated and washed intermittently and fish that are impinged often die because they are
trapped on the stationary screens for extended periods. The high-pressure wash also frequently kills fish or they are
3-2
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Section 316(b) Phase II TDD Efficacy of Cooling Water Intake Structure Technologies
re-impinged on the screens. Conventional traveling screens are used by approximately 89 percent of all existing
facilities within the scope of this rule, (see Chapter 1.3.3 of this document).
3.4 CLOSED-CYCLE WET COOLING SYSTEM PERFORMANCE
Although flow reduction serves the purpose of reducing both impingement and entrainment, these requirements function
foremost as a reliable entrainment reduction technology. Throughout this chapter, the Agency compares performance
of entrainment reducing technologies to that of recirculating wet cooling towers. To evaluate the feasibility of
regulatory options with flow reduction requirements and to allow comparison of costs/benefits of alternatives, the
Agency determined the likely range in flow reductions between wet, closed-cycle cooling systems compared to once-
through systems. In closed-cycle systems, certain chemicals will concentrate as they continue to be recirculated through
the tower. Excess buildup of such chemicals, especially total dissolved solids, affects the tower performance.
Therefore, some water (blowdown) must be discharged and make-up water added periodically to the system.
An additional question that the Agency has considered is the feasibility of constructing salt-water make-up cooling
towers. Certain regulatory options considered for this proposal would have required flow reduction commensurate with
closed-cycle wet cooling at a significant number of estuarine and ocean facilities. For the development of the New
Facility 316(b) rule, the Agency contacted Marley Cooling Tower (Marley), which is one of the largest cooling tower
manufacturers in the world. Marley provided a list of facilities (Marley, 2001) that have installed cooling towers with
marine or otherwise high total dissolved solids/brackish make-up water. It is important to recognize that this represents
only a selected group of facilities constructed by Marley worldwide; there are also facilities constructed by other cooling
tower manufacturers. For example, Florida Power and Light's (FPL) Crystal River Units 4 and 5 (about 1500 MW)
use estuarine water make-up. The Agency also consulted the 1994 UDI Power Statistics Database (EEI, 1994) to
examine additional demonstrations of cooling towers using brackish and saline waters.
3.5 ALTERNATIVE TECHNOLOGIES
3.5.1 Modified Traveling Screens and Fish Handling and Return Systems
Technology Overview
Conventional traveling screens can be modified so that fish, which are impinged on the screens, can be removed with
minimal stress and mortality. "Ristroph Screens" have water-filled lifting buckets which collect the impinged organisms
and transport them to a fish return system. The buckets are designed such that they will hold approximately 2 inches
of water once they have cleared the surface of the water during the normal rotation of the traveling screens. The fish
bucket holds the fish in water until the screen rises to a point where the fish are spilled onto a bypass, trough, or other
protected area (Mussalli, Taft, and Hoffman, 1978). Fish baskets are also a modification of a conventional traveling
screen and may be used in conjunction with fish buckets. Fish baskets are separate framed screen panels that are
attached to vertical traveling screens. An essential feature of modified traveling screens is continuous operation during
periods where fish are being impinged. Conventional traveling screens typically operate on an intermittent basis. (EPRI,
2000 and 1989; Fritz, 1980). Removed fish are typically returned to the source water body by sluiceway or pipeline.
ASCE 1982 provides guidance on the design and operation offish return systems.
Technology Performance
Modified screens and fish handling and return systems have been used to minimize impingement mortality at a wide
range of facilities nationwide. In recent years, some researchers, primarily Fletcher 1996, have evaluated the factors
3-3
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Section 316(b) Phase II TDD Efficacy of Cooling Water Intake Structure Technologies
that effect the success of these systems and described how they can be optimized for specific applications. Fletcher
cited the following as key design factors:
Shaping fish buckets/baskets to minimize hydrodynamic turbulence within the bucket/basket
Using smooth woven screen mesh to minimize fish descaling
Using fish rails to keep fish from escaping the buckets/baskets
Performing fish removal prior to high pressure wash for debris removal
Optimizing the location of spray systems to provide gentler fish transfer to sloughs
Ensuring proper sizing and design of return troughs, sluiceways, and pipes to minimize harm.
In 1993 and 1994, the Salem Generating Station specifically considered Fletcher's work in the modification oftheir fish
handling system. In 1996, the facility subsequently reported an increase in juvenile weakfish impingement survival
from 5 8 percent to 79 percent with an overall weakfish reduction in impingement losses of 51 percent. 1997 and 1998
test data for Units 1 and 2 showed: white perch had 93 to 98 percent survival, bay anchovy had 20 to 72 percent
survival, Atlantic croaker had 58 to 98 percent survival, spot had 93 percent survival, herring had 78 to 82 percent
survival, and weakfish had 18 to 88 percent survival.
Additional performance results for modified screens and fish return systems include:
• 1988 studies at the Diablo Canyon and Moss Landing Power Plants in California found that overall
impingement mortality could be reduced by as much as 75 percent with modified traveling screens and fish
return sluiceways.
• Impingement data collected during the 1970s from Dominion Power' s Surry Station (Virginia) indicated a 93.8
percent survival rate of all fish impinged. Bay anchovies had the lowest survival 83 percent. The facility has
modified Ristroph screens with low pressure wash and fish return systems.
• In 1986, the operator of the Indian Point Station (New York) redesigned fish troughs on the Unit 2 intake to
enhance survival. Impingement injuries and mortality were reduced from 53 to 9 percent for striped bass, 64
to!4 percent for white perch, 80 to 17 percent for Atlantic tomcod, and 47 to 7 percent for pumpkinseed.
• 1996 data for Brayton Point Units 1-3 showed 62 percent impingement survival for continuously rotated
conventional traveling screens with a fish return system.
• In the 1970s, a fish pump and return system was added to the traveling screens at the Monroe Power Plant in
Michigan. Initial studies showed 70 to 80 percent survival for adult and young-of-year gizzard shad and yellow
perch.
• At the Hanford Generating Plant on the Columbia River, late 1970s studies of modified screens with a fish return
system showed 79 to 95 percent latent survival of impinged Chinook salmon fry.
• The Kintigh Generating Station in New Jersey has modified traveling screens with low pressure sprays and
a fish return system. After enhancements to the system in 1989, survivals of generally greater than 80 percent
have been observed for rainbow smelt, rock bass, spottail shiner, white bass, white perch, and yellow perch.
Gizzard shad survivals have been 54 to 65 percent and alewife survivals have been 15 to 44 percent.
• The Calvert Cliffs Station in Maryland has 12 traveling screens that are rotated for 10 minutes every hour or
3-4
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Section 316(b) Phase II TDD Efficacy of Cooling Water Intake Structure Technologies
when pressure sensors show pressure differences. The screens were originally conventional and are now dual
flow. A high pressure wash and return system leads back to the Chesapeake Bay. Twenty-one years of
impingement monitoring show total fish survival of 73 percent.
• At the Arthur Kill Station in New York, 2 of 8 screens are modified Ristroph type; the remaining six screens
are conventional type. The modified screens have fish collection troughs, low pressure spray washes, fish flap
seals, and separate fish collection sluices. 24-hour survival for the unmodified screens averages 15 percent,
while the two modified screens have 79 and 92 percent average survival rates, respectively.
In summary, performance data for modified screens and fish returns are somewhat variable due to site conditions and
variations in unit design and operation. However, the above results generally show that at least 70-80 percent
reductions in impingement can be achieved over conventional traveling screens.
3.5.2 Cylindrical Wcdgcwirc Screens
Technology Overview
Wedgewire screens are designed to reduce entrainment by physical exclusion and by exploiting hydrodynamics.
Physical exclusion occurs when the mesh size of the screen is smaller than the organisms susceptible to entrainment.
The screen mesh ranges from 0.5 to 10 mm. Hydrodynamic exclusion results from maintenance of a low through-slot
velocity, which, because of the screen's cylindrical configuration, is quickly dissipated, thereby allowing organisms to
escape the flow field (Weisberd et al, 1984). Adequate countercurrent flow is needed to transport organisms away from
the screens. The name of these screens arises from the triangular or "wedge" cross section of the wire that makes up
the screen. The screen is composed of wedge-wire loops welded at the apex of their triangular cross section to
supporting axial rods presenting the base of the cross section to the incoming flow (Pagano et al, 1977). Wedgewire
screens may also be referred to as profile screens or Johnson screens.
Technology Performance
Wide mesh wedgewire screens have been used at 2 "high flow" power plants: J.H. Campbell Unit 3 (770 MW) and
Eddystone Units 1 and 2 (approximately 700 MW combined). At Campbell, Unit 3 withdraws 400 million gallons per
day (mgd) of water from Lake Michigan approximately 1,000 feet from shore. Unit 3 impingement of gizzard shad,
smelt, yellow perch, alewife, and shiner species is significantly lower than Units 1 and 2 that do not have wedgewire
screens. Entrainment is not a major concern at the site because of the deep water, offshore location of the Unit 3 intake.
Eddystone Units 1 and 2 withdraw over 500 mgd of water from the Delaware River. The cooling water intakes for these
units were retrofitted with wedgewire screens because over 3 million fish were reportedly impinged over a 20-month
period. The wedgewire screens have generally eliminated impingement at Eddystone. Both the Campbell and
Eddystone wedgewire screens require periodic cleaning but have operated with minimal operational difficulties.
Other plants with lower intake flows have installed wedgewire screens but there are limited biological performance data
for these facilities. The Logan Generating Station in New Jersey withdraws 19 MGD from the Delaware River through
a 1-mm wedgewire screen. Entrainment data show 90 percent less entrainment of larvae and eggs then conventional
screens. No impingement data are available. Unit 1 at the Cope Generating Station in South Carolina is a closed cycle
unit that withdraws about 6 MGD through a 2-mm wedgewire screen, however, no biological data are available.
Performance data are also unavailable for the Jeffrey Energy Center, which withdraws about 5 6 MGD through a 10-mm
screen from the Kansas River in Kansas. The system at the Jeffrey Plant has operated since 1982 with no operational
difficulties. Finally, the American Electric Power Corporation has installed wedgewire screens at the Big Sandy (2
MGD) and Mountaineer (22 MGD) Power Plants, which withdraw water from the Big Sandy and Ohio Rivers,
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respectively. Again, no biological test data are available for these facilities.
Wedgewire screens have been considered/tested for several other large facilities. In situ testing of 1 and 2-mm
wedgewire screens was performed in the St. John River for the Seminole Generating Station Units 1 and 2 in Florida
in the late 1970s. This testing showed virtually no impingement and 99 and 62 percent reductions in larvae entrainment
for the 1-mm and 2-mm screens, respectively, over conventional screen (9.5 mm) systems. The State of Maryland
conducted testing in 1982 and 1983 of 1, 2, and 3-mm wedgewire screens at the Chalk Point Generating Station, which
withdraws water from the Patuxent River in Maryland. The 1 -mm wedgewire screens were found to reduce entrainment
by 80 percent. No impingement data were available. Some biofouling and clogging was observed during the tests.
In the late 1970s, Delmarva Power and Light conducted laboratory testing of fine mesh wedgewire screens for the
proposed 1540 MW Summit Power Plant. This testing showed that entrainment offish eggs (including striped bass)
could effectively be prevented with slot widths of 1 mm or less, while impingement mortality was expected to be less
than 5 percent. Actual field testing in the brackish water of the proposed intake canal required the screens to be
removed and cleaned as often as once every three weeks.
As shown by the above data, it is clear that wedgewire screen technology has not been widely applied in the steam
electric industry to date. It has only been installed at a handful of power plant facilities nationwide. However, the
limited data for Eddystone and Campbell indicate that wide mesh screens, in particular, can be used to minimize
impingement. Successful use of the wedgewire screens at Eddystone as well as Logan in the Delaware River (high
debris flows) suggests that the screens can have widespread applicability. This is especially true for facilities that have
relatively low intake flow requirements (i.e., closed-cycle systems). Yet, the lack of more representative full-scale plant
data makes it impossible to conclusively say that wedgewire screens can be used in all environmental conditions. There
are no full-scale data specifically for marine environments where biofouling and clogging are significant concerns. In
addition, it is important to recognize that there must be sufficient crosscurrent (or low intake velocities) in the waterbody
to allow organisms to move or be carried away from the screens.
Fine mesh wedgewire screens (0.5 - 1 mm) also have the potential for use to control both I&E. The Agency is not
aware of any fine-mesh wedgewire screens that have been installed at power plants with high intake flows (> 100 MGD).
However, they have been used at some power plants with lower intake flow requirements (25-50 MGD) that would be
comparable to a very large power plant with a closed-cycle cooling system. With the exception of Logan, the Agency
has not identified any full-scale performance data for these systems. They could be even more susceptible to clogging
than wide-mesh wedgewire screens (especially in marine environments). It is unclear whether this simply would
necessitate more intensive maintenance or preclude their day-to-day use at many sites. Their successful application at
Logan and Cope and the historic test data from Florida, Maryland, and Delaware at least suggests promise for
addressing both fish impingement and entrainment of eggs and larvae. However, based on the fine-mesh screen
experience at Big Bend Units 3 and 4, it is clear that frequent maintenance would be required. Therefore, relatively
deep water sufficient to accommodate the large number of screen units, would preferably be close to shore (i.e., be
readily accessible). Manual cleaning needs might be reduced or eliminated through use of an automated flushing (e.g.,
microburst) system.
3.5.3 Fine-Mesh Screens
Technology Overview
Fine-mesh screens are typically mounted on conventional traveling screens and are used to exclude eggs, larvae, and
juvenile forms offish from intakes. These screens rely on gentle impingement of organisms on the screen surface.
Successful use of fine-mesh screens is contingent on the application of satisfactory handling and return systems to allow
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the safe return of impinged organisms to the aquatic environment (Pagano et al, 1977; Sharma, 1978). Fine mesh
screens generally include those with mesh sizes of 5 mm or less.
Technology Performance
Similar to fine-mesh wedgewire screens, fine-mesh traveling screens with fish return systems show promise for both
I&E control. However, they have not been installed, maintained, and optimized at many facilities. The most significant
example of long-term fine-mesh screen use has been at the Big Bend Power Plant in the Tampa Bay area. The facility
has an intake canal with 0.5-mm mesh Ristroph screens that are used seasonally on the intakes for Units 3 and 4.
During the mid-1980s when the screens were initially installed, their efficiency in reducing I&E mortality was highly
variable. The operator, Florida Power & Light (FPL) evaluated different approach velocities and screen rotational
speeds. In addition, FPL recognized that frequent maintenance (manual cleaning) was necessary to avoid biofouling.
By 1988, system performance had improved greatly. The system's efficiency in screening fish eggs (primarily drums
and bay anchovy) exceeded 95 percent with 80 percent latent survival for drum and 93 percent for bay anchovy. For
larvae (primarily drums, bay anchovies, blennies, and gobies), screening efficiency was 86 percent with 65 percent
latent survival for drum and 66 percent for bay anchovy. (Note that latent survival in control samples was also
approximately 60 percent). Although more recent data are generally not available, the screens continue to operate
successfully at Big Bend in an estuarine environment with proper maintenance. While egg and larvae entrainment
performance are not available, fine mesh (0.5 mm) Passavant screens (single entry/double exit) have been used
successfully in a marine environment at the Barney Davis Station in Corpus Christi, Texas. Impingement data for this
facility show overall 86 percent initial survivals for bay anchovy, menhaden, Atlantic croaker, killfish, spot, silverside,
and shrimp.
Additional full-scale performance data for fine mesh screens at large power stations are generally not available.
However, some data are available from limited use/study at several sites and from laboratory and pilot-scale tests.
Seasonal use of fine mesh on two of four screens at the Brunswick Power Plant in North Carolina has shown 84 percent
reduction in entrainment compared to the conventional screen systems. Similar results were obtained during pilot testing
of 1-mm screens at the Chalk Point Generating Station in Maryland, and, at the Kintigh Generating Station in New
Jersey, pilot testing indicated 1-mm screens provided 2 to 35 times reductions in entrainment over conventional 9.5-mm
screens. Finally, Tennessee Valley Authority (TVA) pilot-scale studies performed in the 1970s showed reductions in
striped bass larvae entrainment up to 99 percent using a 0.5-mm screen and 75 and 70 percent for 0.97-mm and 1.3-mm
screens, respectively. A full-scale test by TVA at the John Sevier Plant showed less than half as many larvae entrained
with a 0.5-mm screen than 1.0 and 2.0-mm screens combined.
Despite the lack of full-scale data, the experiences at Big Bend (as well as Brunswick) show that fine-mesh screens can
reduce entrainment by 80 percent or more. This is contingent on optimized operation and intensive maintenance to
avoid biofouling and clogging, especially in marine environments. It also may be appropriate to have removable fine
mesh that is only used during periods of egg and larval abundance, thereby reduced the potential for clogging and wear
and tear on the systems.
3.5.4 Fish Net Barriers
Technology Overview
Fish net barriers are wide-mesh nets, which are placed in front of the entrance to intake structures. The size of the mesh
needed is a function of the species that are present at a particular site and vary from 4 mm to 32 mm (EPRI, 2000).
The mesh must be sized to prevent fish from passing through the net causing them to become gilled. Relatively low
velocities are maintained because the area through which the water can flow is usually large. Fish net barriers have
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been used at numerous facilities and lend themselves to intakes where the seasonal migration offish and other organisms
require fish diversion facilities for only specific times of the year.
Technology Performance
Barrier nets can provide a high degree of impingement reduction. Because of typically wide openings, they do not
reduce entrainment of eggs and larvae. A number of barrier net systems have been used/studied at large power plants.
Specific examples include:
• At the J.P. Pulliam Station (Wisconsin), the operator installed 100 and 260-foot barrier nets across the two
intake canals, which withdraw water from the Fox River prior to flowing into Lake Michigan. The barrier nets
have been shown to reduce impingement by 90 percent over conventional traveling screens without the barrier
nets. The facility has the barrier nets in place when the water temperature is greater than 37°F or April 1
through December 1.
• The Ludington Storage Plant (Michigan) provides water from Lake Michigan to a number of power plant
facilities. The plant has a 2.5-mile long barrier net that has successfully reduced I&E. The overall net
effectiveness for target species (five salmonids, yellow perch, rainbow smelt, alewife, and chub) has been over
80 percent since 1991 and 96 percent since 1995. The net is deployed from mid-April to mid-October, with
storms and icing preventing use during the remainder of the year.
• At the Chalk Point Generating Station (Maryland), a barrier net system has been used since 1981, primarily
to reduce crab impingement from the Patuxent River. Eventually, the system was redesigned to include two
nets: a 1,200-foot wide outer net prevents debris flows and a 1,000-foot inner net prevents organism flow into
the intake. Crab impingement has been reduced by 84 percent. The Agency did not obtain specific fish
impingement performance data for other species, but the nets have reduced overall impingement liability for
all species from over $2 million to less than $140,000. Net panels are changed twice per week to control
biofouling and clogging.
• The Bowline Point Station (New York) has an approximately 150-foot barrier net in a v-shape around the
intake structure. Testing during 1976 through 1985 showed that the net effectively reduces white perch and
striped bass impingement by 91 percent. Based on tests of a "fine" mesh net (3.0 mm) in 1993 and 1994,
researchers found that it could be used to generally prevent entrainment. Unfortunately, species' abundances
were too low to determine the specific biological effectiveness.
• In 1980, a barrier net was installed at the J.R. Whiting Plant (Michigan) to protect Maumee Bay. Prior to net
installation, 17,378,518 fish were impinged on conventional traveling screens. With the net, sampling in 1983
and 84 showed 421,978 fish impinged (97 percent effective), sampling in 1987 showed 82,872 fish impinged
(99 percent effective), and sampling in 1991 showed 316,575 fish impinged (98 percent effective).
Barrier nets have clearly proven effective for controlling impingement (i.e., 80+ percent reductions over conventional
screens without nets) in areas with limited debris flows. Experience has shown that high debris flows can cause
significant damage to net systems. Biofouling concerns can also be a concern but this can be addressed through
frequent maintenance. Barrier nets are also often only used seasonally, where the source waterbody is subject to
freezing. Fine-mesh barrier nets show some promise for entrainment control but would likely require even more
intensive maintenance. In some cases, the use of barrier nets may be further limited by the physical constraints and
other uses of the waterbody.
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3.5.5 Aquatic Microfiltration Barriers
Technology Overview
Aquatic microfiltration barrier systems are barriers that employ a filter fabric designed to allow for passage of water
into a cooling water intake structure, but exclude aquatic organisms. These systems are designed to be placed some
distance from the cooling water intake structure within the source waterbody and act as a filter for the water that enters
into the cooling water system. These systems may be floating, flexible, or fixed. Since these systems generally have
such a large surface area, the velocities that are maintained at the face of the permeable curtain are very low. One
company, Gunderboom, Inc., has a patented full-water-depth filter curtain comprised of polyethylene or polypropylene
fabric that is suspended by flotation billets at the surface of the water and anchored to the substrate below. The curtain
fabric is manufactured as a matting of minute unwoven fibers with an apparent opening size of 20 microns.
Gunderboom systems also employ an automated "air burst" system to periodically shake the material and pass air
bubbles through the curtain system to clean it of sediment buildup and release any other material back into the water
column.
Technology Performance
The Agency has determined that microfiltration barriers, including the Gunderboom, show significant promise for
minimizing entrainment. However, the Agency acknowledges that Gunderboom technology is currently "experimental
in nature." At this juncture, the only power plant where the Gunderboom has been used at a "full-scale" level is the
Lovett Generating Station along the Hudson River in New York, where pilot testing began in the mid-1990s. Initial
testing at this facility showed significant potential for reducing entrainment. Entrainment reductions up to 82 percent
were observed for eggs and larvae and these levels have been maintained for extended month-to-month periods during
1999 through 2001. At Lovett, there have been some operational difficulties that have affected long-term performance.
These difficulties, including tearing, overtopping, and plugging/clogging, have been addressed, to a large extent, through
subsequent design modifications. Gunderboom, Inc. specifically has designed and installed a "microburst" cleaning
system to remove particulates. Each of the challenges encountered at Lovett could be significantly greater concern at
marine sites with higher wave action and debris flows. Gunderboom systems have been otherwise deployed in marine
conditions to prevent migration of particulates and bacteria. They have been used successfully in areas with waves up
to five feet. The Gunderboom system is currently being tested for potential use at the Contra Costa Plant along the San
Joaquin River in Northern California.
An additional question related to the utility of the Gunderboom and other microfiltration systems is sizing and the
physical limitations and other uses of the source waterbody. With a 20-micron mesh, 100,000 and 200,000 gallon per
minute intakes would require filter systems 500 and 1,000 feet long (assuming 20 foot depth). In some locations, this
may preclude its successful deployment due space limitations and/or conflicts with other waterbody uses.
3.5.6 Louver Systems
Technology Overview
Louver systems consist of series of vertical panels placed at 90 degree angles to the direction of water flow
(Hadderingh, 1979). The placement of the louver panels provides both changes in the flow direction and velocity, which
fish tend to avoid. The angles and flow velocities of the louvers create a current parallel to the face of the louvers which
carries fish away from the intake and into a fish bypass system for return to the source waterbody.
Technology Performance
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Louver systems can reduce impingement losses based on fishes' abilities to recognize and swim away from the barriers.
Their performance, i.e., guidance efficiency, is highly dependant on the length and swimming abilities of the resident
species. Since eggs and early stages of larvae cannot "swim away," they are not affected by the diversions and there
is no associated reduction in entrainment.
While louver systems have been tested at a number of laboratory and pilot-scale facilities, they have not been used at
many full-scale facilities. The only large power plant facility where a louver system has been used is San Onofre Units
2 and 3 (2,200 MW combined) in Southern California. The operator initially tested both louver and wide mesh, angled
traveling screens during the 1970s. Louvers were subsequently selected for full-scale use at the intakes for the two units.
In 1984, a total of 196,978 fish entered the louver system with 188,5 83 returned to the waterbody and 8,395 impinged.
In 1985, 407,755 entered the louver system with 306,200 returned and 101,555 impinged. Therefore, the guidance
efficiencies in 1984 and 1985 were 96 and 75 percent, respectively. However, 96-hour survival rates for some species,
i.e., anchovies and croakers, were 50 percent or less. The facility also has encountered some difficulties with predator
species congregating in the vicinity of the outlet from the fish return system. Louvers were originally considered for use
at San Onofre because of 1970s pilot testing at the Redondo Beach Station in California where maximum guidance
efficiencies of 96-100 percent were observed.
EPRI2000 indicated that louver systems could provide 80-95 percent diversion efficiency for a wide variety of species
under a range of site conditions. This is generally consistent with the American Society of Civil Engineers' (ASCE)
findings from the late 1970s which showed almost all systems had diversion efficiencies exceeding 60 percent with many
more than 90 percent. As indicated above, much of the EPRI and ASCE data come from pilot/laboratory tests and
hydroelectric facilities where louver use has been more widespread than at steam electric facilities. Louvers were
specifically tested by the Northeast Utilities Service Company in the Holyoke Canal on the Connecticut River for
juvenile clupeids (American shad and blueback herring). Overall guidance efficiency was found to be 75-90 percent.
In the 1970s, Alden Research Laboratory observed similar results for Hudson River species (including alewife and
smelt). At the Tracy Fish Collection Facility located along the San Joaquin River in California, testing was performed
from 1993 and 1995 to determine the guidance efficiency of a system with primary and secondary louvers. The results
for green and white sturgeon, American shad, splittail, white catfish, delta smelt, Chinook salmon, and striped bass
showed mean diversion efficiencies ranging from 63 (splittail) to 89 percent (white catfish). Also in the 1990s, an
experimental louver bypass system was tested at the USGS' Conte Anadromous Fish Research Center in
Massachusetts. This testing showed guidance efficiencies for Connecticut River species of 97 percent for a "wide
array" of louvers and 100 percent for a "narrow array." Finally, at the T.W. Sullivan Hydroelectric Plant along the
Williamette River in Oregon, the louver system is estimated to be 92 percent effective in diverting spring Chinook, 82
percent for all Chinook, and 85 percent for steelhead. The system has been optimized to reduce fish injuries such that
the average injury occurrence is only 0.44 percent.
Overall, the above data indicate that louvers can be highly effective (70+ percent) in diverting fish from potential
impingement. Latent mortality is a concern, especially where fragile species are present. Similar to modified screens
with fish return systems, operators must optimize louver system design to minimize fish injury and mortality
3.5.7 Angled and Modular Inclined Screens
Technology Overview
Angled traveling screens use standard through-flow traveling screens where the screens are set at an angle to the
incoming flow. Angling the screens improves the fish protection effectiveness since the fish tend to avoid the screen
face and move toward the end of the screen line, assisted by a component of the inflow velocity. A fish bypass facility
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with independently induced flow must be provided (Richards 1977). Modular inclined screens (MISs) are a specific
variation on angled traveling screens, where each module in the intake consists of trash racks, dewatering stop logs, an
inclined screen set at a 10 to 20 degree angle to the flow, and a fish bypass (EPRI 1999).
Technology Performance
Angled traveling screens with fish bypass and return systems work similarly to louver systems. They also only provide
potential reductions in impingement mortality since eggs and larvae will not generally detect the factors that influence
diversion. Similar to louver systems, they were tested extensively at the laboratory and pilot scales, especially during
the 1970s and early 1980s. Testing of angled screens (45 degrees to the flow) in the 1970s at San Onofre showed poor
to good guidance (0-70 percent) for northern anchovies with moderate to good guidance (60-90 percent) for other
species. Latent survival varied by species with fragile species only having 25 percent survival, while hardy species
showed greater than 65 percent survival. The intake for Unit 6 at the Oswego Steam plant along Lake Ontario in New
York has traveling screens angled to 25 degrees. Testing during 1981 through 1984 showed a combined diversion
efficiency of 78 percent for all species; ranging from 53 percent for mottled sculpin to 95 percent for gizzard shad.
Latent survival testing results ranged from 22 percent for alewife to nearly 94 percent for mottled sculpin.
Additional testing of angled traveling screens was performed in the late 1970s and early 19 80s for power plants on Lake
Ontario and along the Hudson River. This testing showed that a screen angled at 25 degrees was 100 percent effective
in diverting 1 to 6 inch long Lake Ontario fish. Similar results were observed for Hudson River species (striped bass,
white perch, and Atlantic tomcod). One-week mortality tests for these species showed 96 percent survival. Angled
traveling screens with a fish return system have been used on the intake from Brayton Point Unit 4. Studies from 1984
through 1986 that evaluated the angled screens showed a diversion efficiency of 76 percent with latent survival of 63
percent. Much higher results were observed excluding bay anchovy. Finally, 1981 full-scale studies of an angled screen
system at the Danskammer Station along the Hudson River in New York showed diversion efficiencies of 95 to 100
percent with a mean of 99 percent. Diversion efficiency combined with latent survival yielded a total effectiveness of
84 percent. Species included bay anchovy, blueback herring, white perch, spottail shiner, alewife, Atlantic tomcod,
pumpkinseed, and American shad.
During the late 1970s and early 1980s, Alden Research Laboratories (Alden) conducted a range of tests on a variety
of angled screen designs. Alden specifically performed screen diversion tests for three northeastern utilities. In initial
studies for Niagara Mohawk, diversion efficiencies were found to be nearly 100 percent for alewife and smolt. Follow-
up tests for Niagara Mohawk confirmed 100 percent diversion efficiency for alewife with mortalities only four percent
higher than control samples. Subsequent tests by Alden for Consolidated Edison, Inc. using striped bass, white perch,
and tomcod also found nearly 100 percent diversion efficiency with a 25 degree angled screen. The one-week mean
mortality was only 3 percent.
Alden further performed tests during 1978-1990 to determine the effectiveness of fine-mesh, angled screens. In 1978,
tests were performed with striped bass larvae using both 1.5 and 2.5-mm mesh and different screen materials and
approach velocity. Diversion efficiency was found to clearly be a function of larvae length. Synthetic materials were
also found to be more effective than metal screens. Subsequent testing using only synthetic materials found that 1.0
mm screens can provide post larvae diversion efficiencies of greater than 80 percent. However, the tests found that
latent mortality for diverted species was also high.
Finally, EPRI tested modular inclined screens (MIS) in a laboratory in the early 1990s. Most fish had diversion
efficiencies of 47 to 88 percent. Diversion efficiencies of greater than 98 percent were observed for channel catfish,
golden shiner, brown trout, Coho and Chinook salmon, trout fry and juveniles, and Atlantic salmon smolts. Lower
diversion efficiency and higher mortality were found for American shad and blueback herring but comparable to control
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mortalities. Based on the laboratory data, a MIS system was pilot-tested at a Niagara Mohawk hydroelectric facility
on the Hudson River. This testing showed diversion efficiencies and survival rates approaching 100 percent for golden
shiners and rainbow trout. High diversion and survival was also observed for largemouth and smallmouth bass, yellow
perch, and bluegill. Lower diversion efficiency and survival was found for herring.
Similar to louvers, angled screens show potential to minimize impingement by greater than 80 to 90 percent. More
widespread full-scale use is necessary to determine optimal design specifications and verify that they can be used on
a widespread basis.
3.5.8 Velocity Caps
Technology Description
A velocity cap is a device that is placed over vertical inlets at offshore intakes. This cover converts vertical flow into
horizontal flow at the entrance into the intake. The device works on the premise that fish will avoid rapid changes in
horizontal flow. In general, velocity caps have been installed at many offshore intakes and have been successful in
minimizing impingement.
Technology Performance
Velocity caps can reduce fish drawn into intakes based on the concept that they tend to avoid horizontal flow. They
do not provide reductions in entrainment of eggs and larvae, which cannot distinguish flow characteristics. As noted
in ASCE 1981, velocity caps are often used in conjunction with other fish protection devices. Therefore, there are
somewhat limited data on their performance when used alone. Facilities that have velocity caps include:
• Oswego Steam Units 5 and 6 in New York (combined with angled screens on Unit 6).
• San Onofre Units 2 and 3 in California (combined with louver system).
• El Segundo Station in California
• Huntington Beach Station in California
• Edgewater Power Plant Unit 5 in Wisconsin (combined with 9.5 mm wedgewire screen)
• Nanticoke Power Plant in Ontario, Canada
• Nine Mile Point in New York
• Redondo Beach Station in California
• Kintigh Generation Station in New York (combined with modified traveling screens)
• Seabrook Power Plant in New Hampshire
• St. Lucie Power Plant in Florida.
• Palisades Nuclear Plant in Michigan
At the Huntington Beach and Segundo Stations in California, velocity caps have been found to provide 80 to 90 percent
reductions in fish entrapment. At Seabrook, the velocity cap on the offshore intake has minimized the number of pelagic
fish entrained except for pollock. Finally, two facilities in England have velocity caps on one of each's two intakes.
At the Sizewell Power Station, intake B has a velocity cap, which reduces impingement about 50 percent compared to
intake A. Similarly, at the Dungeness Power Station, intake B has a velocity cap, which reduces impingement about
62 percent compared to intake A.
3.5.9 Porous Dikes and Leaky Dams
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Technology Overview
Porous dikes, also known as leaky dams or dikes, are filters resembling a breakwater surrounding a cooling water
intake. The core of the dike consists of cobble or gravel that permits free passage of water. The dike acts both as a
physical and behavioral barrier to aquatic organisms. Tests conducted to date have indicated that the technology is
effective in excluding juvenile and adult fish. The major problems associated with porous dikes come from clogging
by debris and silt, ice build-up, and by colonization offish and plant life.
Technology Performance
Porous dike technologies work on the premise that aquatic organisms will not pass through physical barriers in front
of an intake. They also operate with low approach velocity further increasing the potential for avoidance. However,
they will not prevent entrainment by non-motile larvae and eggs. Much of the research on porous dikes and leaky dams
was performed in the 1970s. This work was generally performed in a laboratory or on a pilot level, i.e., the Agency
is not aware of any full-scale porous dike or leaky dam systems currently used at power plants in the U.S. Examples
of early study results include:
• Studies of porous dike and leaky dam systems by Wisconsin Electric Power at Lake Michigan plants showed
generally lower I&E rates than other nearby onshore intakes.
• Laboratory work by Ketschke showed that porous dikes could be a physical barrier to juvenile and adult fish
and a physical or behavioral barrier to some larvae. All larvae except winter flounder showed some avoidance
of the rock dike.
• Testing at the Brayton Point Power Plant showed that densities of bay anchovy larvae downstream of the dam
were reduced by 94 to 99 percent. For winter flounder, downstream densities were lower by 23 to 87 percent.
Entrainment avoidance for juvenile and adult fmfish was observed to be nearly 100 percent.
As indicated in the above examples, porous dikes and leaky dams show potential for use in limiting passage of adult
and juvenile fish, and, to some degree, motile larvae. However, the lack of more recent, full-scale performance data
makes it difficult to predict their widespread applicability and specific levels of performance.
3.5.10 Behavioral Systems
Technology Overview
Behavioral devices are designed to enhance fish avoidance of intake structures and/or promote attraction to fish
diversion or bypass systems. Specific technologies that have been considered include:
• Light Barriers: Light barriers consist of controlled application of strobe lights or mercury vapor lights to lure
fish away from the cooling water intake structure or deflect natural migration patterns. This technology is
based on research that shows that some fish avoid light, however it is also known that some species are
attracted by light.
• Sound Barriers: Sound barriers are non-contact barriers that rely on mechanical or electronic equipment that
generates various sound patterns to elicit avoidance responses in fish. Acoustic barriers are used to deter fish
from entering cooling water intake structures. The most widely used acoustical barrier is a pneumatic air gun
or "popper."
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• Air bubble barriers: Air bubble barriers consist of an air header with jets arranged to provide a continuous
curtain of air bubbles over a cross section area. The general purpose of air bubble barriers is to repel fish that
may attempt to approach the face of a CWIS.
Technology Performance
Many studies have been conducted and reports prepared on the application of behavioral devices to control I&E, see
EPRI 2000. For the most part, these studies have either been inconclusive or shown no tangible reduction in
impingement or entrainment. As a result, the full-scale application of behavioral devices has been limited. Where data
are available, performance appears to be highly dependent on the types and sizes of species and environmental
conditions. One exception may be the use of sound systems to divert alewife. In tests at the Pickering Station in
Ontario, poppers were found to be effective in reducing alewife I&E by 73 percent in 1985 and 76 percent in 1986.
No benefits were observed for rainbow smelt and gizzard shad. 1993 testing of sound systems at the James A.
Fitzpatrick Station in New York showed similar results, i.e., 85 percent reductions in alewife I&E through use of a high
frequency sound system. At the Arthur Kill Station, pilot- and full-scale, high frequency sound tests showed
comparable results for alewife to Fitzpatrick and Pickering. Impingement of gizzard shad was also three times less than
without the system. No deterrence was observed for American shad or bay anchovy using the full-scale system. In
contrast, sound provided little or no deterrence for any species at the Roseton Station in New York. Overall, the Agency
expects that behavioral systems would be used in conjunction with other technologies to reduce I&E and perhaps
targeted towards an individual species (e.g., alewife).
3.5.11 Other Technology Alternatives
The proposed new facility rule does not specify the individual technology (or group of technologies) to be used to meet
the impingement and/or entrainment requirements. In addition to the above technologies, there are other approaches
that may be used on a site-by-site basis. For example:
• Use of variable speed pumps can provide for greater system efficiency and reduced flow requirements (and
associated entrainment) by 10-30 percent. EPA Region 4 estimated that use of variable speed pumps at the
Canaveral and Indian River Stations in the Indian River estuary would reduce entrainment by 20 percent.
Presumably, such pumps could be used in conjunction with other technologies to meet proposed requirements.
• Perforated pipes draw water through perforations or elongated slots in a cylindrical section placed in the
waterway. Early designs of this technology were not efficient, velocity distribution was poor, and they were
specifically designed to screen out detritus (i.e., not used for fish protection) (ASCE, 1982). Inner sleeves were
subsequently added to perforated pipes to equalize the velocities entering the outer perforations. These systems
have historically been used at locations requiring small amounts of make-up water. Experience at steam
electric plants is very limited (Sharma, 1978). Perforated pipes are used on the intakes for the Amos and
Mountaineer Stations along the Ohio River. However, I&E performance data for these facilities are
unavailable. In general, EPA projects that perforated pipe system performance should be comparable to wide-
mesh wedgewire screens (e.g., at Eddystone Units 1 and 2 and Campbell Unit 3).
• At the Pittsburg Plant in California, impingement survival was studied for continuously rotated screens versus
intermittent rotation. Ninety-six-hour survival for young-of-year white perch was 19 to 32 percent for
intermittent screen rotation versus 26 to 56 percent for continuous rotation. Striped bass latent survival
increased from 26 to 62 percent when continuous rotation was used. Similar studies were also performed at
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Section 316(b) Phase II TDD Efficacy of Cooling Water Intake Structure Technologies
Moss Landing Units 6 and 7, where no increased survival was observed for hardy and very fragile species,
however, there was a substantial increase in impingement survival for surfperch and rockfish.
• Facilities may be able to use recycled cooling water to reduce intake flow needs. The Brayton Point Station
has a "piggyback" system where the entire intake requirements for Unit 4 can be met by recycled cooling water
from Units 1 through 3. The system has been used sporadically since 1993 and reduces the make-up water
needs (and thereby entrainment) by 29 percent.
3.6 INTAKE LOCATION
Beyond design alternatives for CWISs, an operator may able to relocate CWISs offshore or otherwise in areas that
minimize I&E (compared to conventional onshore locations), though the ability of existing facilities to do so may be
quite limited. As such, this discussion is of limited applicability to the majority of existing facilities, but is included
to complete the discussion. It is well known that there are certain areas within every waterbody with increased
biological productivity, and therefore where the potential for I&E of organisms is higher.
In large lakes and reservoirs, the littoral zone (i.e., shorezone areas where light penetrates to the bottom) of
lakes/reservoirs serves as the principal spawning and nursery area for most species of freshwater fish and is considered
one of the most productive areas of the waterbody. Fish of this zone typically follow a spawning strategy wherein eggs
are deposited in prepared nests, on the bottom, and/or are attached to submerged substrates where they incubate and
hatch. As the larvae mature, some species disperse to the open water regions, whereas many others complete their life
cycle in the littoral zone. Clearly, the impact potential for intakes located in the littoral zone of lakes and reservoirs
is high. The profundal zone of lakes/reservoirs is the deeper, colder area of the waterbody. Rooted plants are absent
because of insufficient light, and for the same reason, primary productivity is minimal. A well-oxygenated profundal
zone can support benthic macroinvertebrates and cold-water fish; however, most of the fish species seek shallower areas
to spawn (either in littoral areas or in adjacent streams/rivers). Use of the deepest open water region of a lake and
reservoir (e.g., within the profundal zone) as a source of cooling water typically offers lower I&E impact potential (than
use of littoral zone waters).
As with lakes/reservoirs, rivers are managed for numerous benefits, which include sustainable and robust fisheries.
Unlike lakes and reservoirs, the hydrodynamics of rivers typically result in a mixed water column and (overall)
unidirectional flow. There are many similarities in the reproductive strategies of shoreline fish populations in rivers
and the reproductive strategies offish within the littoral zone of lakes/reservoirs. Planktonic movement of eggs, larvae,
post larvae, and early juvenile organisms along the shorezone are generally limited to relatively short distances. As a
result, the shorezone placement of CWISs in rivers may potentially impact local spawning populations offish. The
impact potential associated with entrainment may be diminished if the main source of cooling water is recruited from
near the bottom strata of the open water channel region of the river. With such an intake configuration, entrainment
of shorezone eggs and larvae, as well as the near surface drift community of ichthyoplankton, is minimized. Impacts
could also be minimized by the control of the timing and frequency of withdrawals from rivers. In temperate regions,
the number of entrainable/impingeable organisms of rivers increases during spring and summer (when many riverine
fishes reproduce). The number of eggs and larvae peak at that time, whereas entrainment potential during the remainder
of the year may be minimal.
In estuaries, species distribution and abundance are determined by a number of physical and chemical attributes
including: geographic location, estuary origin (or type), salinity, temperature, oxygen, circulation (currents), and
substrate. These factors, in conjunction with the degree of vertical and horizontal stratification (mixing) in the estuary,
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Section 316(b) Phase II TDD Efficacy of Cooling Water Intake Structure Technologies
help dictate the spatial distribution and movement of estuarine organisms. However, with local knowledge of these
characteristics, the entrainment effects of a CWIS could be minimized by adjusting the intake design to areas (e.g.,
depths) least likely to impact upon concentrated numbers and species of organisms.
In oceans, nearshore coastal waters are generally the most biologically productive areas. The euphotic zone (zone of
photosynthetic available light) typically does not extend beyond the first 100 meters (328 feet) of depth. Therefore,
inshore waters are generally more productive due to photosynthetic activity, and due to the input from estuaries and
runoff of nutrients from land.
There are limited published data quantifying the locational differences in I&E rates at individual power plants.
However, some information is available for selected sites. For example,
• For the St. Lucie plant in Florida, EPA Region 4 permitted the use of a once through cooling system instead
of closed-cycle cooling by locating the outfall 1,200 offshore (with a velocity cap) in the Atlantic Ocean. This
avoided impacts on the biologically sensitive Indian River estuary.
• In Entrainment of Fish Larvae and Eggs on the Great Lakes, with Special Reference to the D.C. Cook
Nuclear Plant, Southeastern Lake Michigan (1976), researchers noted that larval abundance is greatest within
about the 12.2-m (40 ft) contour to shore in Lake Michigan and that the abundance of larvae tends to decrease
as one proceeds deeper and farther offshore. This led to the suggestion of locating CWISs in deep waters.
• During biological studies near the Fort Calhoun Power Station along the Missouri River, results of transect
studies indicated significantly higher fish larvae densities along the cutting bank of the river, adjacent to the
Station's intake structure. Densities were generally were lowest in the middle of the channel.
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Section 316(b) Phase II TDD Efficacy of Cooling Water Intake Structure Technologies
3.7 SUMMARY
Tables 3-1 and 3 -2 summarize I&E performance data for selected, existing facilities. The Agency recognizes that these
data are somewhat variable, in part depending on site-specific conditions. This is also because there generally have not
been uniform performance standards for specific technologies. However, during the past 30 years, significant
experience has been gained in optimizing the design and maintenance of CWIS technologies under various site and
environmental conditions. Through this experience and the performance requirements under Track II of the proposed
new facility rule, the Agency is confident that technology applicability and performance will continue to be improved
The Agency has concluded that the data indicate that several technologies, i.e., wide-mesh wedgewire screens and
barrier systems, will generally minimize impingement to levels comparable to wet, closed-cycle cooling systems. Other
technologies, such as modified traveling screens with fish handling and return systems, and fish diversion systems, are
likely to be viable at some sites (especially those with hardy species present). In addition, these technologies may be
used in groups, e.g., barrier nets and modified screens, depending on site-specific conditions.
Demonstrating that alternative design technologies achieve comparable entrainment performance to the proposed
entrainment reduction requirements (specific to a subset of regulated facilities) is more problematic largely because
there are relatively few fully successful examples of full-scale systems being deployed and tested. However, the Agency
has determined that fine-mesh traveling screens with fish return systems, fine-mesh wedgewire screens and
microfiltration barriers (e.g., gunderbooms) are all promising technologies that could provide a level of protection
reasonably consistent with the I&E protection afforded by wet, closed-cycle cooling. In addition, the Agency is also
confident that on a site-by-site basis, many facilities will be able to further minimize entrainment (and impingement)
by optimizing the timing and, to a lesser degree for existing facilities, the location of cooling water withdrawals.
Similarly, habitat restoration could also be used, as appropriate as needed, in conjunction with CWIS technologies
and/or locational requirements.
3-17
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Section 316(b) Phase II TDD
Efficacy of Cooling Water Intake Structure Technologies
Site
Diablo Canyon/Moss
Landing
Brayton Point
Danskammer
Monroe
Holyoke Canal
Tracy Fish Collection
Salem
Redondo Beach
San Onofre
Dominion Power Surry
Barney Davis
Kintigh
Calvert Cliffs
Arthur Kill
J.H. Campbell
Eddystone
Lovett
J.P. Pulliam
Ludington Storage
Chalk Point
Bowline
J.R. Whiting
D.C. Cook
Oswego Steam
j Location
| California
| Massachusetts
| New York
| Michigan
| Connecticut
| California
| New Jersey
| California
| California
| Virginia
| Texas
| New York
| Maryland
| New York
| Michigan
| Pennsylvania
| New York
| Wisconsin
| Michigan
| Maryland
| New York
| New York
| Michigan
• New York
Table
• Name/Type of
j Waterbody
| Pacific Ocean
j Mt. Hope Bay (Estuary)
| Tidal River (Hudson)
| River/Great Lake
| Connecticut River Basin
| San Joaquin River
| Tidal River (Delaware)
| Pacific Ocean
| Pacific Ocean
| Estuary (James River)
| Estuary (coastal lagoon)
| Great Lake
| Bay/estuary
| Estuary
| Great Lake
| Estuary (Delaware)
| Tidal River (Hudson)
| River/Great Lake
| Great Lake
| Bay/Estuary
| Tidal River (Hudson)
| Great Lake
| Great Lake
• Great Lake
5-1: Impingement Performance
j Technology
| Modified traveling/fish return
• Angled screens/fish return
• Angled screens/fish return
| Fish pump/return (screenwell)
| Louvers
| Louvers
| Ristroph screens
| Louvers
| Louvers
| Modified Fish/fish return
| Passavant screens (1.5 mm)
| Modified with fish return
| Dual flow, cont. rot., return
| Ristroph screens
| Wide mesh wedgewire
| Wide mesh wedgewire
| Gunderboom
| Barrier net
| Barrier net
| Barrier net
| Barrier net
| Barrier net
| Barrier net
• Velocity cap
Impingement
75
76
99
70-80
85-90
63-89
18-98
96-100
75-96
94
86
>80
73
79-92
99+
99+
99
90
96
90+
91
97-99
80
78
Entrainment
0
0
0
0
0
0
0
0
0
0
NA
50-97
0
0
0
0
82
0
0
0
0
0
0
0
j Notes
j 63% latent
j 84% latent
| Raisin River trib to L. Erie
| Test results
| Species specific (no avg.)
| Test for San Onofre
| Includes survival
| Entrainment data Not Avail
| Except shad 54-65, alewife 15-44
| Includes survival
| Only when above 37 degrees C
| Based on liability reduced 93%
| Estimated by U. of Michigan
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Section 316(b) Phase II TDD
Efficacy of Cooling Water Intake Structure Technologies
Table 5-2: Entrainment Performance
Site : : Name/Type of :
: Location : Waterbody : Technology
Big Bend : Florida : Tampa Bay : Fine mesh traveling
Seminole : Florida : River/Estuary : Fine mesh wedgewire
Logan : New Jersey : River/Estuary : Fine mesh wedgewire
TVA (studies) : Various : Fresh Water : Fine mesh traveling
Lovett : New York : River/Tidal : Gunderboom
Brunswick : North Carolina : River/Estuary : Fine mesh traveling
Chalk Point : Maryland : Bay/Estuary : Fine mesh wedgewire
Kintigh : New York : Great Lake : Fine mesh traveling
Summit : Delaware : Bay/Estuary : Fine mesh wedgewire
Impingement
NA
NA
NA
NA
99
NA
NA
>80
NA
Entrainment
86-95
99
90
99
82
84
80
50-97
90+
Notes
66-93% survival
Testing, not full-scale
19mgd
lab testing, striped bass larvae
only
used only when less than 84 deg F
Testing, not full-scale
"impingement eliminated"
3-19
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Section 316(b) Phase II TDD Efficacy of Cooling Water Intake Structure Technologies
REFERENCES
American Electric Power Corporation. March, 1980. Philip Sporn Plant 316(b) Demonstration Document.
American Society of Civil Engineers. 1982. Design of Water Intake Structures for Fish
Protection. Task Committee on Fish-Handling Capability of Intake Structures of the
Committee on Hydraulic Structures of the Hydraulic Division of the American Society of
Civil Engineers.
Bailey et. al. Undated. Studies of Cooling Water Intake Structure Effects at PEPCO Generating Stations.
CK Environmental. June, 2000. Letter from Charles Kaplan, CK Environmental, to Martha Segall, Tetra Tech,
Inc. June 26, 2000.
Duke Energy, Inc. April, 2000. Moss Landing Power Plant Modernization Project. 316(b) Resource Assessment.
Ecological Analysts, Inc. 1979. Evaluation of the Effectiveness of a Continuously Operating Fine Mesh Traveling
Screen for Reducing Ichthvoplankton Entrainment at the Indian Point Generating Station. Prepared for
Consolidated Edison, Inc.
Edison Electric Institute (EEI). 1993. EEI Power Statistics Database. Prepared by the
Utility Data Institute for the Edison Electric Institute.
Ehrler, C. and Raifsnider, C. April, 1999. "Evaluation of the Effectiveness of Intake Wedgewire Screens."
Presented at EPRI Power Generation Impacts on Aquatic Resources Conference.
Electric Power Research Institute (EPRI). 1999. Fish Protection at Cooling Water Intakes: Status Report.
EPRI. March, 1989. Intake Technologies: Research Status. Publication GS-6293.
EPRI. 1985. Intake Research Facilities Manual.
ESS A Technologies, Ltd. June, 2000. Review of Portions of NJPDES Renewal Application for the PSE&G
Salem Generating Station.
Fletcher, I. 1990. Flow Dynamics and Fish Recovery Experiments: Water Intake Systems.
Florida Power and Light. August, 1995. Assessment of the Impacts of the St. Lucie Nuclear Generating Plant on
Sea Turtle Species Found in the Inshore Waters of Florida.
Fritz, E.S. 1980. Cooling Water Intake Screening Devices Used to Reduce Entrainment
and Impingement. Topical Briefs: Fish and Wildlife Resources and Electric Power
Generation, No. 9.
Hadderingh, R.H. 1979. "Fish Intake Mortality at Power Stations, the Problem and its
Remedy." In: Hydrological Bulletin, 13(2-3).
Hutchison, J.B., and Matousek, J.A. Undated. Evaluation of a Barrier Net Used to Mitigate Fish Impingement at a
Hudson River Power Pant Intake. American Fisheries Society Monograph.
Jude, D.J. 1976. "Entrainment of Fish Larvae and Eggs on the Great Lakes, with Special Reference to the D.C.
3-20
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Section 316(b) Phase II TDD Efficacy of Cooling Water Intake Structure Technologies
Cook Nuclear Plant, Southeastern Lake Michigan." In: Jensen, L.D. (Ed.), Third National Workshop on
Entrainment & Impingement: Section 316(b) - Research and Compliance.
Ketschke, B.A. 1981. "Field and Laboratory Evaluation of the Screening Ability of a Porous Dike." In: P.B.
Dorn and Johnson (Eds.). Advanced Intake Technology for Power Plant Cooling Water Systems.
King, R.G. 1977. "Entrainment of Missouri River Fish Larvae through Fort Calhoun Station." In: Jensen, L.D.
(Ed.), Fourth National Workshop on Entrainment and Impingement.
Lifton, W.S. Undated. Biological Aspects of Screen Testing on the St. John's River. Palatka. Florida.
Marley Cooling Tower. August 2001. Electronic Mail from Robert Fleming, Marley Cooling Tower to Ron
Rimelman, Tetra Tech, Inc. August 9, 2001.
Micheletti, W. September, 1987. "Fish Protection at Cooling Water Intake Systems." In: EPRI Journal.
Mussalli, Y.G., Taft, E.P., and Hofmann, P. February, 1978. "Biological and Engineering Considerations in the
Fine Screening of Small Organisms from Cooling Water Intakes." In: Proceedings of the Workshop on Larval
Exclusion Systems for Power Plant Cooling Water Intakes, Sponsored by Argonne National Laboratory (ANL
Publication No. ANL/ES-66).
Mussalli, Y.G., Taft, E.P, and Larsen, J. November, 1980. "Offshore Water Intakes
Designated to Protect Fish." In: Journal of the Hydraulics Division, Proceedings of the
America Society of Civil Engineers. Vol. 106, No HY11.
Northeast Utilities Service Company. January, 1993. Feasibility Study of Cooling Water System Alternatives to
Reduce Winter Flounder Entrainment at Millstone Units 1-3.
Orange and Rockland Utilities and Southern Energy Corp. 2000. Lovett Generating Station Gunderboom
Evaluation Program. 1999.
PG&E. March 2000. Diablo Canyon Power Plant. 316(b) Demonstration Report.
Pagano, R. and Smith, W.H.B. November, 1977. Recent Developments in Techniques to
Protect Aquatic Organisms at the Intakes Steam-Electric Power Plants.
Pisces Conservation, Ltd. 2001. Technical Evaluation of USEPA's Proposed Cooling Water Intake Regulations for
New Facilities. November 2000.
Richards, R.T. December, 1977. "Present Engineering Limitations to the Protection of Fish
at Water Intakes". In: Fourth National Workshop on Entrainment and Impingement.
Ringger, T.J. April, 1999. "Baltimore Gas and Electric, Investigations of Impingement of Aquatic Organisms at
the Calvert Cliffs Nuclear Power Plant, 1975-1999." Presented at EPRI Power Generation Impacts on Aquatic
Resources Conference.
Sharma, R.K. February, 1978. "A Synthesis of Views Presented at the Workshop." In:
Larval Exclusion Systems For Power Plant Cooling Water Intakes.
Taft, E.P. April, 1999. "Alden Research Laboratory, Fish Protection Technologies: A Status Report." Presented
at EPRI Power Generation Impacts on Aquatic Resources Conference.
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Section 316(b) Phase II TDD Efficacy of Cooling Water Intake Structure Technologies
Taft, E.P. March, 1999. PSE&G Renewal Application. Appendix F. Salem Generation Station.
Taft, E.P. et. al. 1981. "Laboratory Evaluation of the Larval Fish Impingement and Diversion Systems." In:
Proceedings of Advanced Intake Technology.
Tennessee Valley Authority (TVA). 1976. A State of the Art Report on Intake Technologies.
U.S. Environmental Protection Agency (EPA), Region 4. May, 1983. 316a and 316b Finding for Cape
Canaveral/Orlando Utilities Plants at Canaveral Pool.
EPA, Region 4. September, 1979. Brunswick Nuclear Steam Electric Generating Plant. Historical Summary and
Review of Section 316(b) Issues.
University of Michigan. 1985. Impingement Losses at the D.C. Cook Nuclear Power Plant During 1975-1982
with a Discussion of Factors Responsible and Possible Impact on Local Populations.
Versar, Inc. April, 1990. Evaluation of the Section 316 Status of Delaware Facilities with Cooling Water
Discharges. Prepared for State of Delaware Department of Natural Resources.
Weisberg, S.B., Jacobs, F., Burton, W.H., and Ross, R.N. 1983. Report on Preliminary
Studies Using the Wedge Wire Screen Model Intake Facility. Prepared for State of
Maryland, Power Plant Siting Program.
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Section 316(b) Phase II TDD Efficacy of Cooling Water Intake Structure Technologies
3-23
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§ 316(b) Phase II TDD Attachment A to Chapter 3
Attachment A to Chapter 3
COOLINS WATER INTAKE STRUCTURE TECHNOLOSY FACT SHEETS
-------
§ 316(b) Phase II TDD Attachment A to Chapter 3
Intake Screening Systems
Fact Sheet No. 1: Single-Entry, Single-Exit
Vertical Traveling Screens (Conventional
Traveling Screens)
Description:
The single-entry, single-exit vertical traveling screens (conventional traveling screens) consist
of screen panels mounted on an endless belt; the belt rotates through the water vertically. The
screen mechanism consists of the screen, the drive mechanism, and the spray cleaning system.
Most of the conventional traveling screens are fitted with 3/8-inch mesh and are designed to
screen out and prevent debris from clogging the pump and the condenser tubes. The screen mesh
is usually supplied in individual removable panels referred to as " baskets" or "trays".
The screen washing system consists of a line of spray nozzles operating at a relatively high
pressure of 80 to 120 pounds per square inch (psi). The screens are usually designed to rotate
at a single speed. The screens are rotated either at predetermined intervals or when a
predetermined differential pressure is reached across the screens based on the amount of debris
in the intake waters.
Because of this intermittent operation of the conventional traveling screens, fish can become
impinged against the screens during the extended period of time while the screens are stationary
and eventually die. When the screens are rotated the fish are removed from the water and then
subjected to a high pressure spray; the fish may fall back into the water and become re-
impinged or they may be damaged (EPA, 1976, Pagano et al, 1977).
Testing Facilities and/or Facilities Using the Technology:
• The conventional traveling screens are the most common screening device presently
used at steam electric power plants. Sixty percent of all the facilities use this
technology at their intake structure (EEI, 1993).
Research/Operation Findings:
• The conventional single-entry single screen is the most common device resulting in
impacts from entrainment and impingement (Fritz, 1980).
Design Considerations:
• The screens are usually designed structurally to withstand a differential pressure across
their face of 4 to 8 feet of water.
• The recommended normal maximum water velocity through the screen is about 2.5 feet
per second (ft/sec). This recommended velocity is where fish protection is not a factor
to consider.
• The screens normally travel at one speed (10 to 12 feet per minute) or two speeds (2.5
A-2
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§ 316(b) Phase II TDD
Attachment A to Chapter 3
Intake Screening Systems
Fact Sheet No. 1: Single-Entry, Single-Exit
Vertical Traveling Screens (Conventional
Traveling Screens)
Advantages:
Limitations:
to 3 feet per minute and 10 to 12 feet per minute). These speeds can be increased to
handle heavy debris load.
Conventional traveling screens are a proven "off-the-shelf technology that is readily
available.
Impingement and entrainment are both major problems in this unmodified standard
screen installation, which is designed for debris removal not fish protection.
References:
ASCE. Design of Water Intake Structures for Fish Protection. Task Committee on Fish-Handling
Capability of Intake Structures of the Committee on Hydraulic Structures of the Hydraulic Division of
the American Society of Civil Engineers, New York, NY. 1982.
EEI Power Statistics Database. Prepared by the Utility Data Institute for the Edison Electric Institute.
Washington, D.C., 1993.
Fritz, E.S. Cooling Water Intake Screening Devices Used to Reduce Entrainment and Impingement.
Topical Briefs: Fish and Wildlife Resources and Electric Power Generation, No. 9. 1980.
PaganoR. andW.H.B. Smith. Recent Developments in Techniques to Protect Aquatic Organisms at the
Intakes of Steam-Electric Power Plants. MITRE Corporation Technical Report 7671. November 1977.
U.S. EPA. Development Document for Best Technology Available for the Location. Design.
Construction, and Capacity of Cooling Water Intake Structures for Minimizing Adverse Environmental
Impact. U.S. Environmental Protection Agency, Effluent Guidelines Division, Office of Water and
Hazardous Materials. EPA 440/1-76/015-a. April 1976.
A-3
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§ 316(b) Phase II TDD Attachment A to Chapter 3
Intake Screening Systems
Fact Sheet No. 2: Modified Vertical
Traveling Screens
Description:
Modified vertical traveling screens are conventional traveling screens fitted with a collection
"bucket" beneath the screen panel. This intake screening system is also called a bucket screen,
Ristroph screen, or a Surry Type screen. The screens are modified to achieve maximum
recovery of impinged fish by maintaining them in water while they are lifted to a release point.
The buckets run along the entire width of the screen panels and retain water while in upward
motion. At the uppermost point of travel, water drains from the bucket but impinged organisms
and debris are retained in the screen panel by a deflector plate. Two material removal systems
are often provided instead of the usual single high pressure one. The first uses low-pressure
spray that gently washes fish into a recovery trough. The second system uses the typical high-
pressure spray that blasts debris into a second trough. Typically, an essential feature of this
screening device is continuous operation which keeps impingement times relatively short
(Richards, 1977; Mussalli, 1977; Pagano et al, 1977; EPA , 1976).
Testing Facilities and/or Facilities Using the Technology:
Facilities which have tested the screens include: the Surry Power Station in Virginia (White et
al, 1976) (the screens have been in operation since 1974), the Madgett Generating Station in
, Wisconsin, the Indian Point Nuclear Generating Station Unit 2 in New York, the Kintigh
(formerly Somerset) Generating Station in New Jersey, the Bowline Point Generating Station
(King et al, 1977), the Roseton Generating Station in New York, the Danskammer Generating
Station in New York (King et al, 1977), the Hanford Generating Plant on the Columbia River
in Washington (Page et al, 1975; Fritz, 1980), the Salem Genereating on the Delaware River
in New Jersey, and the Monroe Power Plant on the Raisin River in Michigan.
Research/Operation Findings:
Modified traveling screens have been shown to have good potential for alleviating impingement
mortality. Some information is available on initial and long-term survival of impinged fish
(EPRI, 1999; ASCE, 1982; Fritz, 1980). Specific research and operation findings are listed
below:
• In 1986, the operator of the Indian Point Station redesigned fish troughs on the Unit 2
intake to enhance survival. Impingement injuries and mortality were reduced from 53
to 9 percent for striped bass, 64 to!4 percent for white perch, 80 to 17 percent for
Atlantic tomcod, and 47 to 7 percent for pumpkinseed (EPRI, 1999).
• The Kintigh Generating Station has modified traveling screens with low pressure
sprays and a fish return system. After enhancements to the system in 1989, survivals
of generally greater than 80 percent have been observed for rainbow smelt, rock bass,
spottail shiner, white bass, white perch, and yellow perch. Gizzard shad survivals have
been 54 to 65 percent and alewife survivals have been 15 to 44 percent (EPRI, 1999).
A-4
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§ 316(b) Phase II TDD Attachment A to Chapter 3
Intake Screening Systems
Fact Sheet No. 2: Modified Vertical
Traveling Screens
Long-term survival testing was conducted at the Hanford Generating Plant on the
Columbia River (Page et al, 1975; Fritz, 1980). In this study, 79 to 95 percent of the
impinged and collected Chinook salmon fry survived for over 96 hours.
Impingement data collected during the 1970s from Dominion Power's Surry Station
indicated a 93.8 percent survival rate of all fish impinged. Bay anchovies had the lowest
survival rate of 83 percent. The facility has modified Ristroph screens with low
pressure wash and fish return systems (EPRI 1999).
At the Arthur Kill Station, 2 of 8 screens are modified Ristroph type; the remaining six
screens are conventional type. The modified screens have fish collection troughs, low
pressure spray washes, fish flap seals, and separate fish collection sluices. 24-hour
survival for the unmodified screens averages 15 percent, while the two modified screens
have 79 and 92 percent average survival rates (EPRI 1999).
Design Considerations:
Advantages:
The same design considerations as for Fact Sheet No. 1: Conventional Vertical
Traveling Screens apply (ASCE, 1982).
Traveling screens are a proven "off-the-shelf technology that is readily available. An
essential feature of such screens is continuous operation during periods where fish are
being impinged compared to conventional traveling screens which operate on an
intermittent basis
Limitations:
• The continuous operation can result in undesirable maintenance problems (Mussalli,
1977).
• Velocity distribution across the face of the screen is generally very poor.
Latent mortality can be high, especially where fragile species are present.
References:
ASCE. Design of Water Intake Structures for Fish Protection. Task Committee on Fish-Handling
Capability of Intake Structures of the Committee on Hydraulic Structures of the Hydraulic
Division of the American Society of Civil Engineers, New York, NY. 1982.
Electric Power Research Institute (EPRI). Fish Protection at Cooling Water Intakes: Status Report.
1999.
A-5
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§ 316(b) Phase II TDD Attachment A to Chapter 3
Intake Screening Systems
Fact Sheet No. 2: Modified Vertical
Traveling Screens
EPRI. Intake Technologies: Research Status. Electric Power Research Institute GS-6293. March 1989.
U.S. EPA. Development Document for Best Technology Available for the Location, design.
Construction, and Capacity of Cooling Water Intake Structures for Minimizing Adverse
Environmental Impact. Environmental Protection Agency, Effluent Guidelines Division, Office
of Water and Hazardous Materials, EPA 440/1-76/015-a. April 1976.
Fritz, E.S. Cooling Water Intake Screening Devices Used to Reduce Entrainment and Impingement.
Topical Briefs: Fish and Wildlife Resources and Electric Power Generation, No. 9, 1980.
King, L.R., J.B. Hutchinson, Jr. and T.G. Huggins. "Impingement Survival Studies on White Perch,
Striped Bass, and Atlantic Tomcod at Three Hudson Power Plants". In Fourth National
Workshop on Entrainment and Impingement. L.D. Jensen (Editor) Ecological Analysts, Inc.,
Melville, NY. Chicago, December 1977.
Mussalli, Y.G., "Engineering Implications of New Fish Screening Concepts". In Fourth National
Workshop on Entrainment and Impingement. L.D. Jensen (Editor). Ecological Analysts, Inc.,
Melville, N.Y. Chicago, December 1977, pp 367-376.
Pagano, R. and W.H.B. Smith. Recent Developments in Techniques to Protect Aquatic Organisms at
the Intakes Steam-Electric Power Plants. MITRE Technical Report 7671. November 1977.
Richards, R.T. "Present Engineering Limitations to the Protection of Fish at Water Intakes". In Fourth
National Workshop on Entrainment and Impingement, pp 415-424. L.D. Jensen (Editor).
Ecological Analysts, Inc., Melville, N.Y. Chicago, December 1977.
White, J.C. and M.L. Brehmer. "Eighteen-Month Evaluation of the Ristroph Traveling Fish Screens".
In Third National Workshop on Entrainment and Impingement. L.D. Jensen (Editor). Ecological
Analysts, Inc., Melville, N.Y. 1976.
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§ 316(b) Phase II TDD Attachment A to Chapter 3
Intake Screening Systems
Sheet No. 3: Inclined Single-Entry, Single-
Exit Traveling Screens (Angled
Screens)
Description:
Inclined traveling screens utilize standard through-flow traveling screens where the screens are
set at an angle to the incoming flow as shown in the figure below. Angling the screens improves
the fish protection effectiveness of the flush mounted vertical screens since the fish tend to avoid
the screen face and move toward the end of the screen line, assisted by a component of the
inflow velocity. A fish bypass facility with independently induced flow must be provided. The
fish have to be lifted by fish pump, elevator, or conveyor and discharged to a point of safety
away from the main water intake (Richards, 1977).
Testing Facilities and/or Facilities Using the Technology:
Angled screens have been tested/used at the following facilities: the Brayton Point Station Unit
4 in Massachusetts; the San Onofre Station in California; and at power plants on Lake Ontario
and the Hudson River (ASCE, 1982; EPRI, 1999).
Research/operation Findings:
• Angled traveling screens with a fish return system have been used on the intake for
Brayton Point Unit 4. Studies from 1984 through 1986 that evaluated the angled
screens showed a diversion efficiency of 76 percent with latent survival of 63 percent.
Much higher results were observed excluding bay anchovy. Survival efficiency for the
major taxa exhibited an extremely wide range, from 0.1 percent for bay anchovy to 97
percent for tautog. Generally, the taxa fell into two groups: a hardy group with
efficiency greater than 65 percent and a sensitive group with efficiency less than 25
percent (EPRI, 1999).
• Southern California Edison at its San Onofre steam power plant had more success with
angled louvers than with angled screens. The angled screen was rejected for full-scale
use because of the large bypass flow required to yield good guidance efficiencies in the
test facility.
Design Considerations:
Many variables influence the performance of angled screens. The following recommended
preliminary design criteria were developed in the studies for the Lake Ontario and Hudson River
intakes (ASCE, 1982):
• Angle of screen to the waterway: 25 degrees
• Average velocity of approach in the waterway upstream of the screens: 1 foot per
second
A-7
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§ 316(b) Phase II TDD
Attachment A to Chapter 3
Intake Screening Systems
Sheet No. 3: Inclined Single-Entry, Single-
Exit Traveling Screens (Angled
Screens)
Advantages:
Limitations:
Ratio of screen velocity to bypass velocity: 1:1
Minimum width of bypass opening: 6 inches
The fish are guided instead of being impinged.
The fish remain in water and are not subject to high pressure rinsing.
Higher cost than the conventional traveling screen
Angled screens need a stable water elevation.
Angled screens require fish handling devices with independently induced flow
(Richards, 1977).
References:
ASCE. Design of Water Intake Structures for Fish Protection. Task Committee on Fish-Handling
Capability of Intake Structures of the Committee on Hydraulic Structures of the Hydraulic Division
of the American Society of Civil Engineers, New York, NY. 1982.
Electric Power Research Institute (EPRI). Fish Protection at Cooling Water Intakes: Status Report.
1999.
U.S. EPA. Development Document for Best Technology Available for the Location. Design,
Construction, and Capacity of Cooling Water Intake Structures for Minimizing Adverse Environmental
Impact. U.S. Environmental Protection Agency, Effluent Guidelines Division, Office of Water and
Hazardous Materials. EPA 440/1-76/015-a. April 1976.
Richards, R.T. "Present Engineering Limitations to the Protection of Fish at Water Intakes". In Fourth
National Workshop on Entrainment and Impingement. L.D. Jensen (Editor). Ecological Analysts, Inc.,
Melville, N.Y. Chicago. December 1977. pp 415-424.
A-8
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§ 316(b) Phase II TDD
Attachment A to Chapter 3
Intake Screening Systems
Fact Sheet No.4: Fine Mesh Screens
Mounted on Traveling Screens
Description:
Fine mesh screens are used for screening eggs, larvae, and juvenile fish from cooling water
intake systems. The concept of using fine mesh screens for exclusion of larvae relies on gentle
impingement on the screen surface or retention of larvae within the screening basket, washing
of screen panels or baskets to transfer organisms into a sluiceway, and then sluicing the
organisms back to the source waterbody (Sharma, 1978). Fine mesh with openings as small
as 0.5 millimeters (mm) has been used depending on the size of the organisms to be protected.
Fine mesh screens have been used on conventional traveling screens and single-entry, double-
exit screens. The ultimate success of an installation using fine mesh screens is contingent on the
application of satisfactory handling and recovery facilities to allow the safe return of impinged
organisms to the aquatic environment (Pagano et al, 1977).
Testing Facilities and/or Facilities Using the Technology:
The Big Bend Power Plant along Tampa Bay area has an intake canal with 0.5-mm mesh
Ristroph screens that are used seasonally on the intakes for Units 3 and 4. At the Brunswick
Power Plant in North Carolina, fine mesh used seasonally on two of four screens has shown 84
percent reduction in entrainment compared to the conventional screen systems.
Research/Operation Findings:
During the mid-1980s when the screens were initially installed at Big Bend, their
efficiency in reducing impingement and entrainment mortality was highly variable.
The operator evaluated different approach velocities and screen rotational speeds.
In addition, the operator recognized that frequent maintenance (manual cleaning)
was necessary to avoid biofouling. By 1988, system performance had improved
greatly. The system's efficiency in screening fish eggs (primarily drums and bay
anchovy) exceeded 95 percent with 80 percent latent survival for drum and 93
percent for bay anchovy. For larvae (primarily drums, bay anchovies, blennies, and
gobies), screening efficiency was 86 percent with 65 percent latent survival for
drum and 66 percent for bay anchovy. Note that latent survival in control samples
was also approximately 60 percent (EPRI, 1999).
At the Brunswick Power Plant in North Carolina, fine mesh screen has led to 84
percent reduction in entrainment compared to the conventional screen systems.
Similar results were obtained during pilot testing of 1-mm screens at the Chalk Point
Generating Station in Maryland. At the Kintigh Generating Station in New Jersey,
pilot testing indicated 1-mm screens provided 2 to 35 times reductions in
entrainment over conventional 9.5-mm screens (EPRI, 1999).
Tennessee Valley Authority (TVA) pilot-scale studies performed in the 1970s
showed reductions in striped bass larvae entrainment up to 99 percent using a 0.5-
A-9
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§ 316(b) Phase II TDD
Attachment A to Chapter 3
Intake Screening Systems
Fact Sheet No.4: Fine Mesh Screens
Mounted on Traveling Screens
mm screen and 75 and 70 percent for 0.97-mm and 1.3-mm screens. A full-scale
test by TVA at the John Sevier Plant showed less than half as many larvae entrained
with a 0.5-mm screen than 1.0 and 2.0-mm screens combined (TVA, 1976).
• Preliminary results from a study initiated in 1987 by the Central Hudson and Gas
Electric Corporation indicated that the fine mesh screens collect smaller fish
compared to conventional screens; mortality for the smaller fish was relatively high,
with similar survival between screens for fish in the same length category (EPRI,
1989).
Design Considerations:
Biological effectiveness for the whole cycle, from impingement to survival in the source
water body, should be investigated thoroughly prior to implementation of this option. This
includes:
• The intake velocity should be low so that if there is any impingement of larvae on
the screens, it is gentle enough not to result in damage or mortality.
• The wash spray for the screen panels or the baskets should be low-pressure so as not
to result in mortality.
• The sluiceway should provide smooth flow so that there are no areas of high
turbulence; enough flow should be maintained so that the sluiceway is not dry at any
time.
• The species life stage, size and body shape and the ability of the organisms to
withstand impingement should be considered with time and flow velocities.
• The type of screen mesh material used is important. For instance, synthetic meshes
may be smooth and have a low coefficient of friction, features that might help to
minimize abrasion of small organisms. However, they also may be more susceptible
to puncture than metallic meshes (Mussalli, 1977).
Advantages:
Limitations:
There are indications that fine mesh screens reduce entrainment.
Fine mesh screens may increase the impingement offish, i.e., they need to be used in
conjunction with properly designed and operated fish collection and return systems.
Due to the small screen openings, these screens will clog much faster than those with
conventional 3/8-inch mesh. Frequent maintenance is required, especially in marine
A-10
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§ 316(b) Phase II TDD
Attachment A to Chapter 3
Intake Screening Systems
Fact Sheet No.4: Fine Mesh Screens
Mounted on Traveling Screens
environments.
References:
Bruggemeyer, V., D. Condrick, K. Durrel, S. Mahadevan, and D. Brizck. "Full Scale Operational
Demonstration of Fine Mesh Screens at Power Plant Intakes". In Fish Protection at Steam and
Hydroelectric Power Plants. EPRI CS/EA/AP-5664-SR, March 1988, pp 251-265.
Electric Power Research Institute (EPRI). Fish Protection at Cooling Water Intakes: Status Report.
1999.
EPRI. Intake Technologies: Research Status. Electrical Power Research Institute, EPRI GS-6293.
March 1989.
Pagano, R., andW.H.B. Smith. Recent Developments in Techniques to Protect Aquatic Organisms
at the Intakes Steam-Electric Power Plants. MITRE Corporation Technical Report 7671. November
1977.
Mussalli, Y.G., E.P. Taft, and P. Hofmann. "Engineering Implications of New Fish Screening
Concepts". In Fourth Workshop on Larval Exclusion Systems For Power Plant Cooling Water
Intakes. San-Diego, California, February 1978, pp 367-376.
Sharma, R.K., "A Synthesis of Views Presented at the Workshop". In Larval Exclusion Systems
For Power Plant Cooling Water Intakes. San-Diego, California, February 1978, pp 235-237.
Tennessee Valley Authority (TVA). A State of the Art Report on Intake Technologies. 1976.
A-ll
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§ 316(b) Phase II TDD Attachment A to Chapter 3
Passive Intake Systems Fact Sheet No. 5: Wedgewire Screens
Description:
Wedgewire screens are designed to reduce entrainment by physical exclusion and by exploiting
hydrodynamics. Physical exclusion occurs when the mesh size of the screen is smaller than the
organisms susceptible to entrainment. Hydrodynamic exclusion results from maintenance of a
low through-slot velocity, which, because of the screen's cylindrical configuration, is quickly
dissipated, thereby allowing organisms to escape the flow field (Weisberd et al, 1984). The
screens can be fine or wide mesh. The name of these screens arise from the triangular or
"wedge" cross section of the wire that makes up the screen. The screen is composed of
wedgewire loops welded at the apex of their triangular cross section to supporting axial rods
presenting the base of the cross section to the incoming flow (Pagano et al, 1977). A cylindrical
wedgewire screen is shown in the figure below. Wedgewire screens are also called profile
screens or Johnson screens.
Testing Facilities and/or Facilities Using the Technology:
Wide mesh wedgewire screens are used at two large power plants, Eddystone and Campbell.
Smaller facilities with wedgewire screens include Logan and Cope with fine mesh and Jeffrey
with wide mesh (EPPJ 1999).
Research/Operation Findings:
• In-situ observations have shown that impingement is virtually eliminated when
wedgewire screens are used (Hanson, 1977; Weisberg et al, 1984).
• At Campbell Unit 3, impingement of gizzard shad, smelt, yellow perch, alewife, and
shiner species is significantly lower than Units 1 and 2 that do not have wedgewire
screens (EPPJ, 1999).
• The cooling water intakes for Eddystone Units 1 and 2 were retrofitted with wedgewire
screens because over 3 million fish were reportedly impinged over a 20-month period.
The wedgewire screens have generally eliminated impingement at Eddystone (EPPJ,
1999).
• Laboratory studies (Heuer and Tomljanovitch, 1978) and prototype field studies
(Lifton, 1979; Delmarva Power and Light, 1982; Weisberg et al, 1983) have shown
that fine mesh wedgewire screens reduce entrainment.
• One study (Hanson, 1977) found that entrainment offish eggs (striped bass), ranging
in diameter from 1.8 mm to 3.2 mm, could be eliminated with a cylindrical wedgewire
screen incorporating 0.5 mm slot openings. However, striped bass larvae, measuring
5.2 mm to 9.2 mm were generally entrained through a 1 mm slot at a level exceeding
A-12
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§ 316(b) Phase II TDD
Attachment A to Chapter 3
Passive Intake Systems
Fact Sheet No. 5: Wedgewire Screens
75 percent within one minute of release in the test flume.
At the Logan Generating Station in New Jersey, monitoring shows shows 90 percent
less entrainment of larvae and eggs through the 1 mm wedgewire screen then
conventional screens. In situ testing ofl and 2-mm wedgewire screens was performed
in the St. John River for the Seminole Generating Station Units 1 and 2 in Florida in the
late 1970s. This testing showed virtually no impingement and 99 and 62 percent
reductions in larvae entrainment for the 1-mm and 2-mm screens, respectively, over
conventional screen (9.5 mm) systems (EPRI, 1999).
Design Considerations:
Advantages:
Limitations:
To minimize clogging, the screen should be located in an ambient current of at least 1
feet per second (ft/sec).
A uniform velocity distribution along the screen face is required to minimize the
entrapment of motile organisms and to minimize the need of debris backflushing.
In northern latitudes, provisions for the prevention of frazil ice formation on the screens
must be considered.
Allowance should be provided below the screens for silt accumulation to avoid
blockage of the water flow (Mussalli et al, 1980).
Wedgewire screens have been demonstrated to reduce impingement and entrainment in
laboratory and prototype field studies.
The physical size of the screening device is limiting in most passive systems, thus,
requiring the clustering of a number of screening units. Siltation, biofouling and frazil
ice also limit areas where passive screens such as wedgewire can be utilized.
Because of these limitations, wedgewire screens may be more suitable for closed-cycle
make-up intakes than once-through systems. Closed-cycle systems require less flow and
fewer screens than once-through intakes; back-up conventional screens can therefore
be used during maintenance work on the wedge-wire screens (Mussalli et al, 1980).
References:
Delmarva Ecological Laboratory. Ecological Studies of the Nanticoke River and Nearby Area. Vol
II. Profile Wire Studies. Report to Delmarva Power and Light Company. 1980.
A-13
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§ 316(b) Phase II TDD Attachment A to Chapter 3
Passive Intake Systems Fact Sheet No. 5: Wedgewire Screens
EEI Power Statistics Database. Prepared by the Utility Data Institute for the Edison Electric
Institute. Washington, D.C., 1993.
Electric Power Research Institute (EPRI). Fish Protection at Cooling Water Intakes: Status Report.
1999.
Hanson, B.N., W.H. Bason, B.E. Beitz and K.E. Charles. "A Practical Intake Screen which
Substantially Reduces the Entrainment and Impingement of Early Life stages of Fish". In Fourth
National Workshop on Entrainment and Impingement. L.D. Jensen (Editor). Ecological Analysts,
Inc., Melville, NY. Chicago, December 1977, pp 393-407.
Heuer, J.H. and D.A. Tomljanovitch. "A Study on the Protection of Fish Larvae at Water Intakes
Using Wedge-Wire Screening". In Larval Exclusion Systems For Power Plant Cooling Water
Intakes. R.K. Sharmer and J.B. Palmer, eds, Argonne National Lab., Argonne, IL. February 1978,
pp 169-194.
Lifton, W.S. "Biological Aspects of Screen Testing on the St. Johns River, Palatka, Florida". In
Passive Screen Intake Workshop. Johnson Division UOP Inc., St. Paul, MN. 1979.
Mussalli, Y.G., E.P. Taft III, and J. Larsen. "Offshore Water Intakes Designated to Protect Fish".
Journal of the Hydraulics Division. Proceedings of the America Society of Civil Engineers. Vol. 106,
No HY11, November 1980, pp 1885-1901.
Pagano R. and W.H.B. Smith. Recent Developments in Techniques to Protect Aquatic Organisms at
the Intakes Steam-Electric Power Plants. MITRE Corporation Technical Report 7671. November
1977.
Weisberg, S.B., F. Jacobs, W.H. Burton, and R.N. Ross. Report on Preliminary Studies Using the
Wedge Wire Screen Model Intake Facility. Prepared for State of Maryland, Power Plant Siting
Program. Prepared by Martin Marietta Environmental Center, Baltimore, MD. 1983.
Weisberg, S.B., W.H. Burton, E.A., Ross, and F. Jacobs. The effects od Screen Slot Size. Screen
Diameter, and Through-Slot Velocity on Entrainment of Estuarine Ichthvoplankton Through Wedge-
Wire Screens. Martin Marrietta Environmental Studies, Columbia MD. August 1984.
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§ 316(b) Phase II TDD Attachment A to Chapter 3
Passive Intake Systems || Fact Sheet No. 6: Perforated Pipes
Description:
Perforated pipes draw water through perforations or slots in a cylindrical section placed in the
waterway. The term "perforated" is applied to round perforations and elongated slots as shown in
the figure below. The early technology was not efficient: velocity distribution was poor, it served
specifically to screen out detritus, and was not used for fish protection (ASCE, 1982). Inner sleeves
have been added to perforated pipes to equalize the velocities entering the outer perforations. Water
entering a single perforated pipe intake without an internal sleeve will have a wide range of entrance
velocities and the highest will be concentrated at the supply pipe end. These systems have been used
at locations requiring small amounts of water such as make-up water. However, experience at steam
electric plants is very limited (Sharma, 1978).
Testing Facilities And/or Facilities Using the Technology:
Nine steam electric units in the U.S. use perforated pipes. Each of these units uses closed-cycle
cooling systems with relatively low make-up intake flow ranging from 7 to 36 MGD (EEI,
1993).
Research/Operation Findings:
• Maintenance of perforated pipe systems requires control of biofouling and removal of
debris from clogged screens.
• For withdrawal of relatively small quantities of water, up to 50,000 gpm, the perforated
pipe inlet with an internal perforated sleeve offers substantial protection for fish. This
particular design serves the Washington Public Power Supply System on the Columbia
River (Richards, 1977).
• No information is available on the fate of the organisms impinged at the face of such
screens.
Design Considerations:
The design of these systems is fairly well established for various water intakes (ASCE, 1982).
Advantages:
The primary advantage is the absence of a confined channel in which fish might become trapped.
Limitations:
Clogging, frazil ice formation, biofouling and removal of debris limit this technology to small
flow withdrawals.
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§ 316(b) Phase II TDD Attachment A to Chapter 3
Passive Intake Systems || Fact Sheet No. 6: Perforated Pipes
REFERENCES:
American Society of Civil Engineers. Task Committee on Fish-handling of Intake Structures of the
Committee of Hydraulic Structures. Design of Water Intake Structures for Fish Protection. ASCE, New
York, N.Y. 1982.
EEI Power Statistics Database. Prepared by the Utility Data Institute for the Edison Electric Institute.
Washington, D.C., 1993.
Richards, R.T. 1977. "Present Engineering Limitations to the Protection of Fish at Water Intakes". In
Fourth National Workshop on Entrainment and Impingement. L.D. Jensen Editor, Chicago, December
1977, pp 415-424.
Sharma, R.K. "A Synthesis of Views Presented at the Workshop". In Larval Exclusion Systems For
Power Plant Cooling Water Intakes. San-Diego, California, February 1978, pp 235-237.
A-16
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§ 316(b) Phase II TDD Attachment A to Chapter 3
Passive intake Systems
Fact Sheet No. 7: Porous Dikes/Leaky
Dams
Description:
Porous dikes, also known as leaky dams or leaky dikes, are filters resembling a breakwater
surrounding a cooling water intake. The core of the dike consists of cobble or gravel, which
permits free passage of water. The dike acts both as a physical and a behavioral barrier to
aquatic organisms and is depicted in the figure below. The filtering mechanism includes a
breakwater or some other type of barrier and the filtering core (Fritz, 1980). Tests conducted
to date have indicated that the technology is effective in excluding juvenile and adult fish.
However, its effectiveness in screening fish eggs and larvae is not established (ASCE, 1982).
Testing Facilities and/or Facilities Using the Technology:
• Two facilities which are both testing facilities and have used the technology are: the
Point Beach Nuclear Plant in Wisconsin and the Baily Generating Station in Indiana
(EPRI, 1985). The Brayton Point Generating Station in Massachusetts has also tested
the technology.
Research/Operation Findings:
Schrader and Ketschke (1978) studied a porous dike system at the Lakeside Plant on
Lake Michigan and found that numerous fish penetrated large void spaces, but for most
fish accessibility was limited.
The biological effectiveness of screening of fish larvae and the engineering
practicability have not been established (ASCE, 1982).
The size of the pores in the dike dictates the degree of maintenance due to biofouling
and clogging by debris.
Ice build-up and frazil ice may create problems as evidenced at the Point Beach
Nuclear Plant (EPRI, 1985).
Design Considerations:
The presence of currents past the dike is an important factor which may probably
increase biological effectiveness.
The size of pores in the dike determines the extent of biofouling and clogging by debris
(Sharma, 1978).
Filtering material must be of a size that permits free passage of water but still prevents
entrainment and impingement.
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§ 316(b) Phase II TDD
Attachment A to Chapter 3
Passive intake Systems
Fact Sheet No. 7: Porous Dikes/Leaky
Dams
Advantages:
• Dikes can be used at marine, fresh water, and estuarine locations.
Limitations:
• The maj or problem with porous dikes comes from clogging by debris and silt, and from
fouling by colonization offish and plant life.
• Backflushing, which is often used by other systems for debris removal, is not feasible
at a dike installation.
• Predation of organisms screened at these dikes may offset any biological effectiveness
(Sharma, 1978).
REFERENCES:
American Society of Civil Engineers. Task Committee on Fish-handling of Intake Structures of the
Committee of Hydraulic Structures. Design of Water Intake Structures for Fish Protection. ASCE, New
York, N.Y. 1982.
EPPJ. Intake Research Facilities Manual. Prepared by Lawler, Matusky & Skelly Engineers, Pearl
River, New York for Electric Power Research Institute. EPRI CS-3976. May 1985.
Fritz, E.S. Cooling Water Intake Screening Devices Used to Reduce Entrainment and Impingement. Fish
and Wildlife Service, Topical Briefs: Fish and Wildlife Resources and Electric Power Generation, No
9. July 1980.
Schrader, B.P. and B.A. Ketschke. "Biological Aspects of Porous-Dike Intake Structures". In Larval
Exclusion Systems For Power Plant Cooling Water Intakes, San-Diego, California, August 1978, pp
51-63.
Sharma, R.K. "A Synthesis of Views Presented at the Workshop". In Larval Exclusion Systems For
Power Plant Cooling Water Intakes. San-Diego, California, February 1978, pp 235-237.
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§ 316(b) Phase II TDD Attachment A to Chapter 3
Fish Diversion or Avoidance Systems || Fact Sheet No. 8: Louver Systems
Description:
Louver systems are comprised of a series of vertical panels placed at an angle to the direction of the
flow (typically 15 to 20 degrees). Each panel is placed at an angle of 90 degrees to the direction of
the flow (Hadderingh, 1979). The louver panels provide an abrupt change in both the flow direction
and velocity (see figure below). This creates a barrier, which fish can immediately sense and will
avoid. Once the change in flow/velocity is sensed by fish, they typically align with the direction of
the current and move away laterally from the turbulence. This behavior further guides fish into a
current created by the system, which is parallel to the face of the louvers. This current pulls the fish
along the line of the louvers until they enter a fish bypass or other fish handling device at the end of
the louver line. The louvers may be either fixed or rotated similar to a traveling screen. Flow
straighteners are frequently placed behind the louver systems.
These types of barriers have been very successful and have been installed at numerous irrigation
intakes, water diversion projects, and steam electric and hydroelectric facilities. It appears that this
technology has, in general, become accepted as a viable option to divert juvenile and adult fish.
Testing Facilities and/or Facilities Using the Technology:
Louver barrier devices have been tested and/or are in use at the following facilities: the California
Department of Water Resource's Tracy Pumping Plant; the California Department of Fish and
Game's Delta Fish Protective Facility in Bryon; the Conte Anadromous Fish Research Center in
Massachusetts, and the San Onofre Nuclear Generating Station in California (EPA, 1976; EPRI,
1985; EPRI, 1999). In addition, three other plants also have louvers at their facilities: the Ruth
Falls Power Plant in Nova Scotia, the Nine Mile Point Nuclear Power Station on Lake Erie, and
T.W. Sullivan Hydroelectric Plant in Oregon. Louvers have also been tested at the Ontario Hydro
Laboratories in Ontario, Canada (Ray et al, 1976).
Research/Operation Findings:
Research has shown the following generalizations to be true regarding louver barriers:
1) the fish separation performance of the louver barrier decreases with an increase in the velocity
of the flow through the barrier; 2) efficiency increases with fish size (EPA, 1976; Hadderingh,
1979); 3) individual louver misalignment has a beneficial effect on the efficiency of the barrier; 4)
the use of center walls provides the fish with a guide wall to swim along thereby improving
efficiency (EPA, 1976); and 5) the most effective slat spacing and array angle to flow depends upon
the size, species and ability of the fish to be diverted (Ray et al, 1976).
In addition, the following conclusions were drawn during specific studies:
• Testing of louvered intake structures offshore was performed at a New York facility. The
louvers were spaced 10 inches apart to minimize clogging. The array was angled at 11.5
percent to the flow. Center walls were provided for fish guidance to the bypass. Test
species included alewife and rainbow smelt. The mean efficiency predicted was between
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§ 316(b) Phase II TDD Attachment A to Chapter 3
Fish Diversion or Avoidance Systems || Fact Sheet No. 8: Louver Systems
22 and 48 percent (Mussalli 1980).
During testing at the Delta Facility's intake in Byron California, the design flow was 6,000
cubic feet per second (cfs), the approach velocity was 1.5 to 3.5 feet per second (ft/sec), and
the bypass velocities were 1.2 to 1.6 times the approach velocity. Efficiencies were found
to drop with an increase in velocity through the louvers. For example, at 1.5 to 2 ft/sec the
efficiency was 61 percent for 15 millimeter long fish and 95 percent for 40 millimeter fish.
At 3.5 ft/sec, the efficiencies were 35 and 70 percent (Ray et al. 1976).
The efficiency of a louver device is highly dependent upon the length and swimming
performance of a fish. Efficiencies of lower than 80 percent have been seen at facilities
where fish were less than 1 to 1.6 inches in length (Mussalli, 1980).
In the 1990s, an experimental louver bypass system was tested at the USGS' Conte
Anadromous Fish Research Center in Massachusetts. This testing showed guidance
efficiencies for Connecticut River species of 97 percent for a "wide array" of louvers and
100 percent for a "narrow array" (EPRI, 1999).
At the Tracy Fish Collection Facility located along the San Joaquin River in California,
testing was performed from 1993 and 1995 to determine the guidance efficiency of a system
with primary and secondary louvers. The results for green and white sturgeon, American
shad, splittail, white catfish, delta smelt, Chinook salmon, and striped bass showed mean
diversion efficiencies ranging from 63 (splittail) to 89 percent (white catfish) (EPRI, 1999).
In 1984 at the San Onofre Station, a total of 196,978 fish entered the louver system with
188,583 returned to the waterbody and 8,395 impinged. In 1985, 407,755 entered the
louver system with 306,200 returned and 101,555 impinged. Therefore, the guidance
efficiencies in 1984 and 1985 were 96 and 75 percent, respectively. However, 96-hour
survival rates for some species, i.e., anchovies and croakers, were 50 percent or less.
Louvers were originally considered for use at San Onofre because of 1970s pilot testing at
the Redondo Beach Station in California where maximum guidance efficiencies of 96-100
percent were observed. (EPRI, 1999)
At the Maxwell Irrigation Canal in Oregon, louver spacing was 5.0 cm with a 98 percent
efficiency of deflecting immature steelhead and above 90 percent efficiency for the same
species with a louver spacing of 10.8 cm.
At the Ruth Falls Power Plant in Nova Scotia, the results of a five-year evaluation for
guiding salmon smelts showed that the optimum spacing was to have wide bar spacing at
the widest part of the louver with a gradual reduction in the spacing approaching the
bypass. The site used a bypass:approach velocity ratio of 1.0 : 1.5 (Ray et al, 1976).
Coastal species in California were deflected optimally (Schuler and Larson, 1974 in Ray
et al, 1976) with 2.5 cm spacing of the louvers, 20 degree louver array to the direction of
flow and approach velocities of 0.6 cm per second.
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§ 316(b) Phase II TDD Attachment A to Chapter 3
Fish Diversion or Avoidance Systems || Fact Sheet No. 8: Louver Systems
• At the T.W. Sullivan Hydroelectric Plant along the Williamette River in Oregon, the louver
system is estimated to be 92 percent effective in diverting spring Chinook, 82 percent for
all Chinook, and 85 percent for steelhead. The system has been optimized to reduce fish
injuries such that the average injury occurrence is only 0.44 percent (EPRI, 1999).
Design Considerations:
The most important parameters of the design of louver barriers include the following:
• The angle of the louver vanes in relation to the channel velocity ,
• The spacing between the louvers which is related to the size of the fish,
• Ratio of bypass velocity to channel velocity,
• Shape of guide walls,
• Louver array angles, and
• Approach velocities.
Site-specific modeling may be needed to take into account species-specific considerations and
optimize the design efficiency (EPA, 1976; O'Keefe, 1978).
Advantages:
• Louver designs have been shown to be very effective in diverting fish (EPA, 1976).
Limitations:
• The costs of installing intakes with louvers may be substantially higher than other
technologies due to design costs and the precision required during construction.
• Extensive species-specific field testing may be required.
• The shallow angles required for the efficient design of a louver system require a long line
of louvers increasing the cost as compared to other systems (Ray et al, 1976).
A-21
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§ 316(b) Phase II TDD Attachment A to Chapter 3
Fish Diversion or Avoidance Systems || Fact Sheet No. 8: Louver Systems
• Water level changes must be kept to a minimum to maintain the most efficient flow velocity.
• Fish handling devices are needed to take fish away from the louver barrier.
• Louver barriers may, or may not, require additional screening devices for removing solids
from the intake waters. If such devices are required, they may add a substantial cost to the
system (EPA, 1976).
• Louvers may not be appropriate for offshore intakes (Mussalli, 1980).
References:
Chow, W., I.P. Murarka, R.W. Broksen. "Entrainment and Impingement in Power Plant Cooling Systems."
Literature Review. Journal Water Pollution Control Federation. 53 (6)(1981):965-973.
U.S. EPA. Development Document for Best Technology Available for the Location. Design. Construction.
and Capacity of Cooling Water Intake Structures for Minimizing Adverse Environmental Impact. U.S.
Environmental Protection Agency, Effluent Guidelines Division, Office of Water and Hazardous Materials.
April 1976.
Electric Power Research Institute (EPRI). Fish Protection at Cooling Water Intakes: Status Report. 1999.
EPRI. Intake Research Facilities Manual. Prepared by Lawler, Matusky & Skelly Engineers, Pearl River,
New York for Electric Power Research Institute. EPRI CS-3976. May 1985.
Hadderingh, R.H. "Fish Intake Mortality at Power Stations, the Problem and its Remedy." N.V. Kema,
Arnheem, Netherlands. Hydrological Bulletin 13(2-3) (1979): 83-93.
Mussalli, Y.G., E.P. Taft, and P. Hoffman. "Engineering Implications of New Fish Screening Concepts,"
In Fourth National Workshop on Entrainment and impingement. L.D. Jensen (Ed.), Ecological Analysts, Inc.
Melville, NY. Chicago, Dec. 1977.
Mussalli, Y.G., E.P Taft III and J. Larson. "Offshore Water Intakes Designed to Protect Fish." Journal of
the Hydraulics Division Proceedings of the American Society of Civil Engineers. Vol. 106Hyll (1980):
1885-1901.
O'Keefe, W., Intake Technology Moves Ahead. Power. January 1978.
Ray, S.S. and R.L. Snipes and D.A. Tomljanovich. A State-of-the-Art Report on Intake Technologies.
Prepared for Office of Energy, Minerals, and Industry, Office of Research and Development. U.S.
A-22
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§ 316(b) Phase II TDD Attachment A to Chapter 3
Fish Diversion or Avoidance Systems || Fact Sheet No. 8: Louver Systems
Environmental Protection Agency, Washington, B.C. by the Tennessee Valley Authority. EPA 600/7-76-
020. October 1976.
Uziel, Mary S. "Entrainment and Impingement at Cooling Water Intakes." Literature Review. Journal
Water Pollution Control Federation. 52 (6) (1980): 1616-1630.
Additional References:
Adams, S.M.etal. Analysis of the Prairie Island Nuclear Generating Station- Intake Related Studies. Report
to Minnesota Pollution Control Agency. Oak Ridge National Lab. Oak Ridge TN (1979).
Bates, D.W. and R. Vinsonhaler, "The Use of Louvers for Guiding Fish." Trans. Am. Fish. Soc. 86
(1956):39-57.
Bates, D.W., and S.G., Jewett Jr., "Louver Efficiency in Deflecting Downstream Migrant Steelhead," Trans.
Am. Fish Soc. 90(3)(1961):336-337.
Cada, G.G., and A.T. Szluha. "A Biological Evaluation of Devices Used for Reducing Entrainment and
Impingement Losses at Thermal Power Plants." In International Symposium on the Environmental Effects
of Hydraulic Engineering Works. Environmental Sciences Division, Publication No. 1276. Oak Ridge Nat'l.
Lab., Oak Ridge TN (1978).
Cannon, J.B., et al. "Fish Protection at Steam Electric Power Plants: Alternative Screening Devices."
ORAL/TM-6473. Oak Ridge Nat'l. Lab. Oak Ridge, TN (1979).
Downs, D.I., and K.R. Meddock, "Design of Fish Conserving Intake System," Journal of the Power
Division. ASCE. Vol. 100, No. P02, Proc. Paper 1108 (1974): 191-205.
Ducharme, L. J.A. "An Application of Louver Deflectors for Guiding Atlantic Salmon (Salmo salar) Smolts
from Power Turbines." Journal Fisheries Research Board of Canada 29 (1974): 1397-1404.
Hallock, R.J., R.A. Iselin, and D.H.J. Fry, Efficiency Tests of the Primary Louver Systems. Tracy Fish
Screen. 1966-67." Marine Resources Branch, California Department of Fish and Game (1968).
Katapodis, C. et al. A Study of Model and Prototype Culvert Baffling for Fish Passage. Fisheries and
Marine Service, Tech. Report No. 828. Winnipeg, Manitoba (1978).
Kerr, J.E., "Studies on Fish Preservation at the Contra Costa Steam Plant of the Pacific Gas and Electric
Co," California Fish and Game Bulletin No. 92 (1953).
Marcy, B.C., and M.D. Dahlberg. Review of Best Technology Available for Cooling Water Intakes. NUS
A-23
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§ 316(b) Phase II TDD Attachment A to Chapter 3
Fish Diversion or Avoidance Systems || Fact Sheet No. 8: Louver Systems
Corporation. Pittsburgh, PA (1978).
NUS Corp., "Review of Best Technology Available for Cooling Water Intakes." Los Angeles Dept. of Water
& Power Report. Los Angeles CA (1978).
Schuler, V.J., "Experimental Studies In Guiding Marine Fishes of Southern California with Screens and
Louvers," Ichthvol. Assoc.. Bulletin 8 (1973).
Skinner, J.E. "A Functional Evaluation of Large Louver Screen Installation and Fish Facilities Research on
California Water Diversion Projects." In: L.D. Jensen, ed. Entrainment and Intake Screening. Proceedings
of the Second Entrainment and Intake Screening Workshop. The John Hopkins University, Baltimore,
Maryland. February 5-9, 1973. pp 225-249 (Edison Electric Institute and Electric Power Research
Institute, EPRI Publication No. 74-049-00-5 (1974).
Stone and Webster Engineering Corporation, Studies to Alleviate Potential Fish Entrapment Problems -
Final Report. Nine Mile Point Nuclear Station - Unit 2. Prepared for Niagara Mohawk Power Corporation,
Syracuse, New York, May 1972.
Stone and Webster Engineering Corporation. Final Report. Indian Point Flume Study. Prepared for
Consolidated Edison Company of New York, IN. July 1976.
Taft, E.P., and Y.G. Mussalli, "Angled Screens and Louvers for Diverting Fish at Power Plants,"
Proceedings of the American Society of Civil Engineers, Journal of Hydraulics Division. Vol 104
(1978):623-634.
Thompson, J.S., and Paulick, G.J. An Evaluation of Louvers and Bypass Facilities for Guiding Seaward
Migrant Salmonid Past Mayfield Dam in West Washington. Washington Department of Fisheries, Olympia,
Washington (1967).
Watts, F.J., "Design of Culvert Fishways." University of Idaho Water Resources Research Institute Report.
Moscow, Idaho (1974).
A-24
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§ 316(b) Phase II TDD Attachment A to Chapter 3
Fish Diversion or Avoidance Systems Fact Sheet No. 9: Velocity Cap
Description:
A velocity cap is a device that is placed over vertical inlets at offshore intakes (see figure
below). This cover converts vertical flow into horizontal flow at the entrance into the intake.
The device works on the premise that fish will avoid rapid changes in horizontal flow. Fish do
not exhibit this same avoidance behavior to the vertical flow that occurs without the use of such
a device. Velocity caps have been implemented at many offshore intakes and have been
successful in decreasing the impingement of fish.
Testing Facilities And/or Facilities Using the Technology:
The available literature (EPA, 1976;Hanson, 1979; and Paganoetal, 1977) states that velocity
caps have been installed at offshore intakes in Southern California, the Great Lakes Region, the
Pacific Coast, the Caribbean and overseas; however, exact locations are not specified.
Velocity caps are known to have been installed at the El Segundo, Redondo Beach, and
Huntington Beach Steam Electric Stations and the San Onofre Nuclear Generation Station in
Southern California (Mussalli, 1980; Pagano et al, 1977; EPRI, 1985).
Model tests have been conducted by a New York State Utility (ASCE, 1982) and several
facilities have installed velocity caps in the New York State /Great Lakes Area including the
Nine Mile Point Nuclear Station, the Oswego Steam Electric Station, and the Kintigh
Generating Station (EPRI, 1985).
Additional known facilities with velocity caps include the Edgewater Generation Station in
Wisconsin, the Seabrook Power Plant in New Hampshire, and the Nanticoke Thermal
Generating Station in Ontario, Canada (EPRI, 1985).
Research/Operation Findings:
Horizontal velocities within a range of 0.5 to 1.5 feet per second (ft/sec) did not
significantly affect the efficiency of a velocity cap tested at a New York facility;
however, this design velocity may be specific to the species present at that site
(ASCE, 1982).
Preliminary decreases in fish entrapment averaging 80 to 90 percent were seen at the
El Segundo and Huntington Beach Steam Electric Plants (Mussalli, 1980).
Performance of the velocity cap may be associated with cap design and the total
volumes of water flowing into the cap rather than to the critical velocity threshold of
the cap (Mussalli, 1980).
Design Considerations:
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§ 316(b) Phase II TDD Attachment A to Chapter 3
Fish Diversion or Avoidance Systems Fact Sheet No. 9: Velocity Cap
• Designs with rims around the cap edge prevent water from sweeping around the edge
causing turbulence and high velocities, thereby providing more uniform horizontal
flows (EPA, 1976; Mussalli, 1980).
• Site-specific testing should be conducted to determine appropriate velocities to
minimize entrainment of particular species in the intake (ASCE, 1982).
• Most structures are sized to achieve a low intake velocity between 0.5 and 1.5 ft/sec
to lessen the chances of entrainment (ASCE, 1982).
• Design criteria developed for a model test conducted by Southern California Edison
Company used a velocity through the cap of 0.5 to 1.5 ft/sec; the ratio of the
dimension of the rim to the height of the intake areas was 1.5 to 1 (ASCE, 1982;
Schuler, 1975).
Advantages:
• Efficiencies of velocity caps on West Coast offshore intakes have exceeded 90
percent (ASCE, 1982).
Limitations:
• Velocity caps are difficult to inspect due to their location under water (EPA, 1976).
• In some studies, the velocity cap only minimized the entrainment of fish and did not
eliminate it. Therefore, additional fish recovery devices are be needed in when using
such systems (ASCE, 1982; Mussalli, 1980).
• Velocity caps are ineffective in preventing passage of non-motile organisms and
early life stage fish (Mussalli, 1980).
References:
ASCE. Design of Water Intake Structures for Fish Protection. American Society of Civil Engineers,
New York, NY. 1982.
EPRI. Intake Research Facilities Manual. Prepared by Lawler, Matusky & Skelly Engineers, Pearl
River, New York for Electric Power Research Institute. EPRI CS-3976. May 1985.
Hanson, C.H., et al. "Entrapment and Impingement of Fishes by Power Plant Cooling Water Intakes:
An Overview." Marine Fisheries Review. October 1977.
Mussalli, Y.G., E.P Taft III and J. Larson. "Offshore Water Intakes Designed to Protect Fish." Journal
of the Hydraulics Division Proceedings of the American Society of Civil Engineers. Vol. 106 Hyll
(1980): 1885-1901.
A-26
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§ 316(b) Phase II TDD Attachment A to Chapter 3
Fish Diversion or Avoidance Systems Fact Sheet No. 9: Velocity Cap
PaganoR. andW.H.B. Smith. Recent Development in Techniques to Protect Aquatic Organisms at the
Water Intakes of Steam Electric Power Plants. Prepared for Electricite' de France. MITRE Technical
Report 7671. November 1977.
Ray, S.S. andR.L. Snipes andD.A. Tomljanovich. A State-of-the-Art Report on Intake Technologies.
Prepared for Office of Energy, Minerals, and Industry, Office of Research and Development. U.S.
Environmental Protection Agency, Washington, D.C. by the Tennessee Valley Authority. EPA 600/7-
76-020. October 1976.
U.S. EPA. Development Document for Best Technology Available for the Location. Design.
Construction, and Capacity of Cooling Water Intake Structures for Minimizing Adverse Environmental
Impact. U.S. Environmental Protection Agency, Effluent Guidelines Division, Office of Water and
Hazardous Materials. April 1976.
Additional References:
Maxwell, W.A. Fish Diversion for Electrical Generating Station Cooling Systems a State of the Art
Report. Southern Nuclear Engineering, Inc. Report SNE-123, NUS Corporation, Dunedin, FL. (1973)
78p.
Weight, R.H. "Ocean Cooling Water System for 800 MW Power Station." J. Power Div., Proc. Am.
Soc. Civil Engr. 84(6)(1958): 1888-1 to 1888-222.
Stone and Webster Engineering Corporation. Studies to Alleviate Fish Entrapment at Power Plant
Cooling Water Intakes, Final Report. Prepared for Niagara Mohawk Power Corporation and Rochester
Gas and Electric Corporation, November 1976.
Richards, R.T. "Power Plant Circulating Water Systems - A Case Study." Short Course on the
Hydraulics of Cooling Water Systems for Thermal Power Plants. Colorado State University. June 1978.
A-27
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§ 316(b) Phase II TDD Attachment A to Chapter 3
Fish Diversion or Avoidance Systems
Fact Sheet No. 10: Fish Barrier Nets
Description:
Fish barrier nets are wide mesh nets, which are placed in front of the entrance to an intake
structure (see figure below). The size of the mesh needed is a function of the species that are
present at a particular site. Fish barrier nets have been used at numerous facilities and lend
themselves to intakes where the seasonal migration of fish and other organisms require fish
diversion facilities for only specific times of the year.
Testing Facilities And/or Facilities Using the Technology:
The Bowline Point Generating Station, the J.P. Pulliam Power Plant in Wisconsin, the
Ludington Storage Plant in Michigan, and the Nanticoke Thermal Generating Station in Ontario
use barrier nets (EPRI, 1999).
Barrier Nets have been tested at the Detroit Edison Monroe Plant on Lake Erie and the Chalk
Point Station on the Patuxent River in Maryland (ASCE, 1982; EPRI, 1985). The Chalk Point
Station now uses barrier nets seasonally to reduce fish and Blue Crab entry into the intake canal
(EPRI, 1985). The Pickering Generation Station in Ontario evaluated rope nets in 1981
illuminated by strobe lights (EPRI, 1985).
Research/Operation Findings:
• At the Bowline Point Generating Station in New York, good results (91 percent
impingement reductions) have been realized with a net placed in a V arrangement
around the intake structure (ASCE, 1982; EPRI, 1999).
• In 1980, a barrier net was installed at the J.R. Whiting Plant (Michigan) to protect
MaumeeBay. Prior to net installation, 17,378,518 fish were impinged on conventional
traveling screens. With the net, sampling in 1983 and 84 showed 421,978 fish
impinged (97 percent effective), sampling in 1987 showed 82,872 fish impinged (99
percent effective), and sampling in 1991 showed 316,575 fish impinged (98 percent
effective) (EPRI, 1999).
• Nets tested with high intake velocities (greater than 1.3 feet per second) at the Monroe
Plant have clogged and subsequentially collapsed. This has not occurred at facilities
where the velocities are 0.4 to 0.5 feet per second (ASCE, 1982).
• Barrier nets at the Nanticoke Thermal Generating Station in Ontario reduced intake of
fish by 50 percent (EPRI, 1985).
• The J.P Pulliam Generating Station in Wisconsin uses dual barrier nets (0.64
centimeters stretch mesh) to permit net rotation for cleaning. Nets are used from April
to December or when water temperatures go above 4 degrees Celsius. Impingement has
been reduced by as much as 90 percent. Operating costs run about $5,000 per year,
and nets are replaced every two years at $2,500 per net (EPRI, 1985).
A-28
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§ 316(b) Phase II TDD
Attachment A to Chapter 3
Fish Diversion or Avoidance Systems
Fact Sheet No. 10: Fish Barrier Nets
• The Chalk Point Station in Maryland realized operational costs of $5,000-10,000 per
year with the nets being replaced every two years (EPRI, 1985). However, crab
impingement has been reduced by 84 percent and overall impingrment liability has been
reduced from $2 million to $140,000 (EPRI, 1999).
• The Ludington Storage Plant (Michigan) provides water from Lake Michigan to a
number of power plant facilities. The plant has a 2.5-mile long barrier net that has
successfully reduced impingement and entrainment. The overall net effectiveness for
target species (five salmonids, yellow perch, rainbow smelt, alewife, and chub) has been
over 80 percent since 1991 and 96 percent since 1995. The net is deployed from mid-
April to mid-October, with storms and icing preventing use during the remainder of the
year (EPRI, 1999).
Design Considerations:
• The most important factors to consider in the design of a net barrier are the site-specific
velocities and the potential for clogging with debris (ASCE, 1982).
• The size of the mesh must permit effective operations, without excessive clogging.
Designs at the Bowline Point Station in New York have 0.15 and 0.2 inch openings in
the mesh nets, while the J.P. Pulliam Plant in Wisconsin has 0.25 inch openings
(ASCE, 1982).
Advantages:
• Net barriers, if operating properly, should require very little maintenance.
• Net barriers have relatively little cost associated with them.
Limitations:
• Net barriers are not effective for the protection of the early life stages of fish or
zooplankton (ASCE, 1982).
References:
ASCE. Design of Water Intake Structures for Fish Protection. American Society of Civil Engineers
(1982).
Electric Power Research Institute (EPRI). Fish Protection at Cooling Water Intakes: Status Report.
1999.
EPRI. Intake Research Facilities Manual. Prepared by Lawler, Matusky & Skelly Engineers, Pearl
River, New York for Electric Power Research Institute. EPRI CS-3976. May 1985.
A-29
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§ 316(b) Phase II TDD Attachment A to Chapter 3
Fish Diversion or Avoidance Systems
Fact Sheet No. 10: Fish Barrier Nets
Lawler, Matusky, and Skelly Engineers. 1977 Hudson River Aquatic Ecology Studies at the Bowline
Point Generating Stations. Prepared for Orange and Rockland Utilities, Inc. Pearl River, NY. 1978.
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§ 316(b) Phase II TDD
Attachment A to Chapter 3
Fish Diversion or Avoidance Systems
Fact Sheet No. 11: Aquatic Filter Barrier
Systems
Description:
Aquatic filter barrier systems are barriers that employ a filter fabric designed to allow for passage
of water into a cooling water intake structure, but exclude aquatic organisms. These systems are
designed to be placed some distance from the cooling water intake structure within the source
waterbody and act as a filter for the water that enters into the cooling water system. These
systems may be floating, flexible, or fixed. Since these systems generally have such a large
surface area, the velocities that are maintained at the face of the permeable curtain are very low.
One company, Gunderboom, Inc., has a patented full-water-depth filter curtain comprised of
polyethylene or polypropylene fabric that is suspended by flotation billets at the surface of the
water and anchored to the substrate below. The curtain fabric is manufactured as a matting of
minute unwoven fibers with an apparent opening size of 20 microns. The Gunderboom
Marine/Aquatic Life Exclusion System (MLES)™ also employs an automated "air burst"™
technology to periodically shake the material and pass air bubbles through the curtain system to
clean it of sediment buildup and release any other material back in to the water column.
Testing Facilities and/or Facilities Using the Technology:
• Gunderboom MLES ™ have been tested and are currently installed on a seasonal
basis at Unit 3 of the Lovett Station in New York. Prototype testing of the
Gunderboom system began in 1994 as a means of lowering ichthyoplankton
entrainment at Unit 3. This was the first use of the technology at a cooling water
intake structure. The Gunderboom tested was a single layer fabric. Material
clogging resulted in loss of filtration capacity and boom submergence within 12
hours of deployment. Ichthyoplankton monitoring while the boom was intact
indicated an 80 percent reduction in entrainable organisms (Lawler, Matusky, and
Skelly Engineers, 1996).
• A Gunderboom MLES ™ was effectively deployed at the Lovett Station for 43 days
in June and July of 1998 using an Air-Burst cleaning system and newly designed
deadweight anchoring system. The cleaning system coupled with a perforated
material proved effective at limiting sediment on the boom, however it required an
intensive operational schedule (Lawler, Matusky, and Skelly Engineers, 1998).
• A 1999 study was performed on the Gunderboom MLES ™ at the Lovett Station in
New York to qualitatively determine the characteristics of the fabric with respect to
the impingement of ichthyoplankton at various flow regimes. Conclusions were that
the viability of striped bass eggs and larvae were not affected (Lawler, Matusky, and
Skelly Engineers, 1999).
• Ichthyoplankton sampling at Unit 3 (with Gunderboom MLES ™ deployed) and
Unit 4 (without Gunderboom) in May through August 2000 showed an overall
effectiveness of approximately 80 percent. For juvenile fish, the density at Unit 3
was 58 percent lower. For post yolk-sac larvae, densities were 76 percent lower.
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§ 316(b) Phase II TDD
Attachment A to Chapter 3
Fish Diversion or Avoidance Systems
Fact Sheet No. 11: Aquatic Filter Barrier
Systems
For yolk-sac larvae, densities were 87 percent lower (Lawler, Matusky & Skelly
Engineers 2000).
Research/operation Findings:
Extensive testing of the Gunderboom MLES ™ has been performed at the Lovett Station in
New York. Anchoring, material, cleaning, and monitoring systems have all been redesigned
to meet the site-specific conditions in the waterbody and to optimize the operations of the
Gunderboom. Although this technology has been implemented at only one cooling water
intake structure, it appears to be a promising technology to reduce impingement and
entrainment impacts. It is also being evaluated for use at the Centre Costa Power Plant in
California.
Design Considerations:
The most important parameters in the design of a Gunderboom ® Marine/Aquatic Life
Exclusion System include the following (Gunderboom, Inc. 1999):
• Size of booms designed for 3-5 gpm per square foot of submerged fabric. Flows
greater than 10-12 gallons per minute.
• Flow-through velocity is approximately 0.02 ft/s.
• Performance monitoring and regular maintenance.
Advantages:
• Can be used in all waterbody types.
• All larger and nearly all other organisms can swim away from the barrier because of
low velocities.
• Little damage is caused to fish eggs and larvae if they are drawn up against the
fabric.
• Modulized panels may easily be replaced.
• Easily deployed for seasonal use.
• Biofouling appears to be controllable through use of the sparging system.
• Impinged organisms released back into the waterbody.
• Benefits relative to cost appear to be very promising, but remain unproven to date.
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§ 316(b) Phase II TDD
Attachment A to Chapter 3
Fish Diversion or Avoidance Systems
Fact Sheet No. 11: Aquatic Filter Barrier
Systems
• Installation can occur with no or minimal plant shutdown.
Limitations:
• Currently only a proven technology for this application at one facility.
• Extensive waterbody-specific field testing may be required.
• May not be appropriate for conditions with large fluctuations in ambient flow and
heavy currents and wave action.
• High level of maintenance and monitoring required.
• Recent studies have asserted that biofouling can be significant.
• Higher flow facilities may require very large surface areas; could interfere with other
waterbody uses.
References:
Lawler, Matusky & Skelly Engineers, "Lovett Generating Station Gunderboom Evaluation Program
- 1995" Prepared for Orange and Rockland Utilities, Inc. Pearl River, New York, June 1996.
Lawler, Matusky & Skelly Engineers, "Lovett Generating Station Gunderboom System Evaluation
Program - 1998" Prepared for Orange and Rockland Utilities, Inc. Pearl River, New York,
December 1998.
Lawler, Matusky & Skelly Engineers, " Lovett Gunderboom Fabric Ichthyoplankton Bench Scale
Testing" Southern Energy Lovett. New York, November 1999.
Lawler, Matusky & Skelly Engineers, "Lovett 2000 Report" Prepared for Orange and Rockland
Utilities, Inc. Pearl River, New York, 2000.
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§ 316(b) Phase II TDD Attachment A to Chapter 3
Fish Diversion or Avoidance Systems Fact Sheet No. 12: Sound Barriers
Description:
Sound barriers are non-contact barriers that rely on mechanical_or electronic equipment that
generates various sound patterns to elicit avoidance responses in fish. Acoustic barriers are
used to deter fish from entering industrial water intakes and power plant turbines.
Historically, the most widely-used acoustical barrier is a pneumatic air gun or "popper." The
pneumatic air gun is a modified seismic device which produces high-amplitude,
low-frequency sounds to exclude fish. Closely related devices include "fishdrones" and
"fishpulsers" (also called "hammers"). The fishdrone produces a wider range of sound
frequencies and amplitudes than the popper. The fishpulser produces a repetitive sharp
hammering sound of low-frequency and high-amplitude. Both instruments have ahd limited
effectiveness in the field (EPRI, 1995; EPRI, 1989; Hanson, et al, 1977; EPA, 1976; Taft,
etal, 1988; ASCE, 1992).
Researchers have generally been unable to demonstrate or apply acoustic barriers as fish
deterrents, even though fish studies showed that fish respond to sound, because the response
varies as a function of fish species, age, and size as well as environmental factors at specific
locations. Fish may also acclimate to the sound patterns used (EPA, 1976; Taft et al., 1988;
EPRI, 1995; Ray at al., 1976; Hadderingh, 1979; Hanson et al., 1977; ASCE, 1982).
Since about 1989, the application of highly refined sound generation equipment originally
developed for military use (e.g., sonar in submarines) has greatly advanced acoustic barrier
technology. Ibis technology has the ability to generate a wide array of frequencies, patterns,
and volumes, which are monitored and controlled by computer. Video and computer
monitoring provide immediate feedback on the effectiveness of an experimental sound
pattern at a given location. In a particular environment, background sounds can be accounted
for, target fish species or fish populations can quickly be characterized, and the most
effective sound pattern can be selected (Menezes, at al., 1991; Sonalysts, Inc.).
Testing Facilities and/or Facilities with Technology in Use:
No fishpulsers and pneumatic air guns are currently in use at power plant water intakes.
Research facilities that have completed studies or have on-going testing involving fishpulsers
or pneumatic air guns include the Ludington Storage Plant on Lake Michigan; Nova Scotia
Power; the Hells Gate Hydroelectric Station on the Black River; the Annapolis Generating
Station on the Bay of Fundy; Ontario Hydro's Pickering Nuclear Generating station; the
Roseton Generating Station in New York; the Seton Hydroelectric Station in British
Columbia; the Surry Power Plant in Virginia; the Indian Point Nuclear Generating Station
Unit 3 in New York; and the U.S. Army Corps of Engineers on the Savannah River (EPRI,
1985; EPRI, 1989; EPRI, 1988; and Taft, et al., 1998).
Updated acoustic technology developed by Sonalysts, Inc. has been applied at the James A.
Fitzpatrick Nuclear Power Plant in New York on Lake Ontario; the Vernon Hydroelectric
plant on the Connecticut River (New England Power Company, 1993; Menezes, et al., 1991;
personal communication with Sonalysts, Inc., by SAIC, 1993); and in a quarry in Verplank,
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§ 316(b) Phase II TDD Attachment A to Chapter 3
Fish Diversion or Avoidance Systems Fact Sheet No. 12: Sound Barriers
New York (Dunning, et al, 1993).
Research/operation Findings:
• Most pre-1976 research was related to fish response to sound rather than on field
applications of sound barriers (EPA, 1976; Ray et al., 1976; Uziel, 1980; Hanson,
etal, 1977).
• Before 1986, no acoustic barriers were deemed reliable for field use. Since 1986,
several facilities have tried to use pneumatic poppers with limited successes. Even in
combination with light barriers and air bubble barriers, poppers and fishpulsers,
were ineffective for most intakes (Taft and Downing, 1988; EPRI, 1985; Patrick, et
al., 1988; EPRI, 1989; EPRI, 1988; Taft, et al., 1988; McKinley and Patrick, 1998;
Chow, 1981).
• A 1991 full-scale 4-month demonstration at the James A. FitzPatrick (JAF) Nuclear
Power Plant in New York on Lake Ontario showed that the Sonalysts, Inc.
FishStartle System reduced alewife impingement by 97 percent as compared to a
control power plant located 1 mile away. (Ross, et al., 1993; Menezes, et al., 1991).
JAF experienced a 96 percent reduction compared to fish impingement when the
acoustic system was not in use. A 1993 3-month test of the system at JAF was
reported to be successful, i.e., 85 percent reduction in alewife impingement.
(Menezes, etal., 1991; EPRI, 1999).
• In tests at the Pickering Station in Ontario, poppers were found to be effective in
reducing alewife impingement and entrainment by 73 percent in 1985 and 76 percent
in 1986. No benefits were observed for rainbow smelt and gizzard shad. Sound
provided little or no deterrence for any species at the Roseton Generating Station in
New York.
• During marine construction of Boston's third Harbor Tunnel in 1992, the Sonalysts,
Inc. FishStartle System was used to prevent shad, blueback herring, and alewives
from entering underwater blasting areas during the fishes' annual spring migration.
The portable system was used prior to each blast to temporarily deter fish and allow
periods of blastmg as necessary for the construction of the tunnel (personal
communication to SAIC from M. Curtin, Sonalysts, Inc., September 17, 1993).
• In fall 1992, the Sonalysts, Inc. FishStartle System was tested in a series of
experiments conducted at the Vernon Hydroelectric plant on the Connecticut River.
Caged juvenile shad were exposed to various acoustical signals to see which signals
elicited the strongest reactions. Successful in situ tests involved applying the signals
with a transducer system to divert juvenile shad from the forebay to a bypass pipe.
Shad exhibited consistent avoidance reactions to the signals and did not show
evidence of acclimation to the source (New England Power Company, 1993).
Design Considerations:
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§ 316(b) Phase II TDD
Attachment A to Chapter 3
Fish Diversion or Avoidance Systems
Fact Sheet No. 12: Sound Barriers
Sonalysts Inc.'s FishStartle system uses frequencies between 15 hertz tolSO
kilohertz at sound pressure levels ranging from 130 to 206+ decibels referenced to
one micropascal (dB//uPa). To develop a site-specific FishStartle program, a test
program using frequencies in the low frequency portion of the spectrum between 25
and 3300 herz were used. Fish species tested by Sonalysts, Inc. include white perch,
striped bass, atlantic tomcod, spottail shiner, and golden shiner (Menezes et al.,
1991).
Sonalysts' FishStartle system used fixed programming contained on Erasable
Programmable Read Only Memory (EPROM) micro circuitry. For field
applications, a system was developed using IBM PC compatible software. Sonalysts'
FishStartle system includes a power source, power amplifiers, computer controls
and analyzer in a control room, all of which are connected to a noise hydrophone in
the water. The system also uses a television monitor and camera controller that is
linked to an underwater light and camera to count fish and evaluate their behavior.
One Sonalysts, Inc. system has transducers placed 5 m from the bar rack of the
intake.
At the Seton Hydroelectric Station in British Columbia, the distance from the water
intake to the fishpulser was 350m(1150ft);at Hells Gate, a fishpulser was
installed at a distance of 500 feet from the intake.
The pneumatic gun evaluated at the Roseton intake had a 16.4 cubic cm (1.0 cubic
inch) chamber connected by a high pressure hose and pipe assembly to an Air Power
Supply Model APS-F2-25 air compressor. The pressure used was a line pressure of
20.7 MPa (3000 psi) (EPRI, 1988).
Advantages:
• The pneumatic air gun, hammer, and fishpulser are easily implemented at low costs.
• Behavioral barriers do not require physical handling of the fish.
Limitations:
• The pneumatic air gun, hammer, and fishpulser are not considered reliable.
• Sophisticated acoustic sound generating system require relatively expensive systems,
including cameras, sound generating systems, and control systems. No cost
information is available since a permanent system has yet to be installed.
• Sound barrier systems require site-specific designs consisting of relatively high
technology equipment that must be maintained at the site.
References:
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§ 316(b) Phase II TDD Attachment A to Chapter 3
Fish Diversion or Avoidance Systems Fact Sheet No. 12: Sound Barriers
ASCE. Design of Water Intake Structures for Fish Protection. American Society of Civil Engineers.
New York, NY. 1982. pp. 69-73.
Chow, W., Isbwar P. Murarka, Robert W. Brocksen. Electric Power Research Institute, Entrainment
and Impingement in Power Plant Cooling Systems. June 1981.
Dunning, D.J., Q.E. Ross, P. Geoghegan, J.J. Reichle, J. K. Menezes, and J.K. Watson. Alewives
Avoid High Frequency Sound. 1993.
Electric Power Research Institute (EPRI). Fish Protection at Cooling Water Intakes: Status Report.
1999.
EPRI. Field Testing of Behavioral Barriers for Fish Exclusion at Cooling Water Intake Svtems:
Ontario Hydro Pickering Nuclear Generating Station. Electric Power Research Institute. March
1989a.
EPRI. Intake Technologies: Research S . Prepared by Lawler, Matusky & Skelly Engineers, Pearl
River, for Electric Power Research Institute. EPRI GS-6293. March 1989.
EPRI. Field Testing of Behavioral Barriers for Fish Exclusion at Cooling Water Intake Systems:
Central Hudson Gas and Electric CoMany. Roseton Generating Statoni. Electric Power Research
Institute. September 1988.
EPRI. Intake Research Facilities Manual. 1985. Prepared by Lawler, Matusky & Skelly Enginem,
Pearl River, for Electric Power Research Institute. EPRI CS-3976. May 1985.
Hadderingh, R. H. "Fish Intake Mortality at Power Stations: The Problem and Its Remedy."
Netherlands Hydrobiological Bulletin . 13(2-3), 83-93, 1979.
Hanson, C. H., J.R. White, and H.W. Li. "Entrapment and Impingement of Fishes by Power Plant
Cooling Water Intakes: An Overview." from Fisheries Review. MFR Paper 1266. October 1977.
McKinley, R.S. and P.H. Patrick. 'Use of Behavioral Stimuli to Divert Sockeye Salmon Smolts at
the Seton Hydro-Electric Station, British Columbia." In the Electric Power Research Institute
Proceedings Fish Protection at Steam and Hydroelectric Power Plants. March 1988.
Menezes, Stephen W. Dolat, Gary W. Tiller, and Peter J. Dolan. Sonalysts, Inc. Waterford,
Connecticut. The Electronic FishStartle System. 1991.
New England_Power Company. Effect of Ensonification on Juvenile American Shad Movement and
Behavior at Vernon Hydroelectric Station, 1992. March 1993.
Patrick, P.H., R.S. McKinley, and W.C. Micheletti. "Field Testing of Behavioral Barriers for
Cooling Water Intake Structures-Test Site 1-Pickering Nuclear Generating Station, 1985/96.* In the
Electric Power Research Institute Proceedings Fish Protection at Steam and Hvdroelectri Power
Plants. March 1988.
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§ 316(b) Phase II TDD Attachment A to Chapter 3
Fish Diversion or Avoidance Systems Fact Sheet No. 12: Sound Barriers
Personal Communication, September 17, 1993, letter and enclosure from MJ. Curtin (Sonalysts,
Inc.) to D. Benelmouffok (SAIC).
Ray, S.S., R.L. Snipes, and D. A Tomljanovich. *A State-of-the-Art Report on Intake
Technologies.- TVA PRS-16 and EPA 6OOn-76-020. October 1976.
Sonalysts, Inc. "FishStartle System in Action: Acoustic Solutions to Environmental Problems" (on
video tape). 215 Parkway North, Waterfbrd, CT 06385.
Taft, E. P., and J.K. Downing. -Comparative Assessment of Fish Protection Alternatives fbr Fossil
and Hydroelectric Facilities.' In the Electric Power Research Institute Proceedingso Fish Protection
at Steam and Hydroelectric Power Plants. March 1998.
Taft, E.P, J. K. Downing, and C. W. Sullivan. "Laboratory and Field Evaluations of Fish Protection
Systems for Use at Hydroelectric Plants Study Update." In the Electric Power Research Institute's
Proceedings: Fish Protection at Stearn and Hydroelectric Power Plants. March 1988.
U.S. EPA. Development Document for Best Technology Available for the Location, D Construction.
and Capacity of Cooling Water Intake Structures fbr Minimizing Adverse Environmental Impact.
U.S. Environmental Protection Agency, Effluent Guidelines Division, Office of Water and
Hazardous Materials. April 1976.
Uziel, Mary S., "Entrainment and Impingement at Cooling Water Intakes." Journal WPCF. Vol. 52,
No.6. June 1980.
ADDITIONAL REFERENCES:
Blaxter, J.H.S., and D.E. Hoss. "Startle Response in Herring: the Effect of Sound Stimulus
Frequency, Size of Fish and Selective Interference with the Acoustical-lateralis System. " Journal of
the Marine Biolozical Association of the United Kingdom. 61:971-879. 1981.
Blaxter, U.S., J.A.B. Gray, and E.J. Denton. "Sound and Startle Response in Herring Shoals." J._
Mar. Biol. Ass. U.K. 61:851-869. 1981.
Burdic, W.S. Underwater Acoustic System Analysis. Englewood Cliffs, New Jersey: PrenticeHall.
1984.
Burner, C.J., and H.L. Moore. "Attempts to Guide Small Fish with Underwater Sound. "U.S. Fish
and Wildlife Service. Special Scientific Report: Fisheries No. 403. 1962. p. 29.
C.H. Hocutt. "Behavioral Barriers and Guidance Systems." In Power Plants: Effects on Fish and
Shellfish Behavior. C.H. Hocutt, J.R. Stauffer, Jr., J. Edinger, L. Hall, Jr., and R. Morgan, II
(Editors). Academic Press. New York, NY. 1980. pp. 183-205.
Empire State Electric Energy Research Corporation. 'Alternative Fish Protective Techniques:
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§ 316(b) Phase II TDD Attachment A to Chapter 3
Fish Diversion or Avoidance Systems Fact Sheet No. 12: Sound Barriers
Pneumatic Guns and Rope. Nets." EP-83-12. March 1984.
Fay, R.R. Hearing in Invertebrates* A Psychg2-hysics Data Boo . HUI-Fay Associates. Winnetka,
Illinois. 1988.
Frizzell, L.A., *Biological Effects of Acoustic Cavitation." In Ultrasound Its Chemical, Physical and
Biological Effects. K.S. Suslick (Editor). VCH Publishers, Inc. New York. 1988. pp. 297-319.
Haymes, G.T., and P.H. Patrick. "Exclusion of Adult Alewife (Alosa pseuoharengus), Using
Low-Frequency Sound for Application of Water Intakes.' Can. J. Fish. Aamatics Srd. 43:855862.
1986.
Micheletti, Coal Combustion Systems Division. "Fish Protection at Cooling Water Intake Systems."
EM Journal. September 1987.
Micheletti, Coal Combustion Systems Division. wFish Protection at Cooling Water Intake Systems."
EPRI Journal. September 1997.
Patrick, P.H., R.S. McKinley, A. E. Christie, and J.G. Holsapple. "Fish Protection: Sonic
Deterrents.' In the EPRI Proceeding: Fish Protection at Steam and Hydroelectric Power Plants.
March 1988.
Platt, C., and A.N. Popper. "Find Structure and Function of the Ear." In Hearing and Sound
Communication in Fishes. W.N. Tavolga, A.N. Popper and R.R. Ray (Editors). SpringerVerlag.
New York.
Ross, Q.E., D. J. Dunning, R. Thorne, J. Menezes, G. W. Tiller, and J. K. Watson. Response of
Alewives to High Frequency Sound at a Power Plant Intake on Lake Ontario. 1993.
Schwarz, A.L., and G.L. Greer. "Responses, of Pacific Herring, Clultea harengus Rallasi. to Some
Undervrater Sounds." Can. J. Fish. Aquatic Sci. 41:1193-1192. 1984.
Smith, E.J., and J.K. Andersen. "Attempts to Alleviate Fish Losses from Allegheny Reservoir,
Pennsylvania and New York, Using Acoustic." North American Journal of Fisheries Management
vol 4(3), 1994. pp. 300-307.
Thorne, R.E. "Assessment of Population Density by Hydroacoustics." In Journal of Biological
Oceanography. Vol. 2. 1983. pp. 252-262.
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§ 316(b) Phase II TDD Cooling System Conversions at Existing Facilities
Chapter 4 Cooling System Conversions at Existing
Facilities
INTRODUCTION
Reducing the cooling water intake structure's capacity is one of the most effective means of reducing entrainment (and
impingement). For the traditional steam electric utility industry, facilities located in freshwater areas that have closed-
cycle, recirculating cooling water systems can, depending on the quality of the make-up water, reduce water use by 96
to 98 percent from the amount they would use if they had once-through cooling water systems, though many of these
areas generally contain species that are less susceptible to entrainment. Steam electric generating facilities that have
closed-cycle, recirculating cooling systems using salt water can reduce water usage by 70 to 96 percent.1
Of the 539 existing steam electric power generating facilities that EPA views are potentially subject to the Phase II
existing facility proposed rule, 73 of these facilities already have a recirculating wet cooling system (for example, wet
cooling towers or ponds).
A closed-cycle recirculating cooling system is an available technology for facilities that currently have once-through
cooling water systems. The Agency learned of several examples of existing facilities converting from one type of
cooling system to another (for example, from once-through to closed-cycle recirculating cooling system). Converting
to a different type of cooling water system, the Agency determined, is significantly more expensive than the technologies
on which the performance standards of the proposed rule are based and significantly more expensive than designing new
facilities to utilize recirculating systems. EPA has identified four power plants that have converted to closed-cycle
recirculating wet cooling tower systems. Three of these facilities—Palisades Nuclear Plant in Michigan, Jefferies
Generating Station in South Carolina, and Canadys Station in South Carolina— converted from once-through to closed-
cycle wet cooling tower systems after significant periods of operation utilizing the once-through system. The fourth
facility — Pittsburg Unit 7 - converted from a recirculating spray-canal system to a closed-cycle wet cooling tower
system. In this case, the conversion occurred after approximately four years of operation utilizing the original design.
6.1 EXAMPLE CASES OF COOLING SYSTEM CONVERSIONS
Canadys Steam Plant. This 490 MW (nameplate, steam capacity), coal-fired facility with three generating units is
located in Colleton County, South Carolina. The first unit initially came online in 1962, the second in 1964, and the
third in 1967. All three units operated with a once-through cooling water system for many years. The Canadys Steam
plant was converted from a once-through to a closed-cycle recirculating cooling system in two separate projects. Unit
3 (218 MW) was first converted in 1972. Units 1 and 2, both with nameplate capacities of 136 MW, were
simultaneously converted from once-through to closed-cycle, a single recirculating wet cooling system in 1992.
The Agency contacted South Carolina Electric & Gas to learn about the cooling system conversions at Canadys
1 The lower range would be appropriate where State water quality standards limit chloride to a maximum increase of
10 percent over background and therefore require a 1.1 cycle of concentration. The higher range may be attained
where cycles of concentration up to 2.0 are used for the design.
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§ 316(b) Phase II TDD Cooling System Conversions at Existing Facilities
(Wicker, 2002). According to plant personnel, the primary motivation for conversion from once-through to
recirculating systems related to fresh water availability in both cases. Due to water shortages, the plant chose to convert
the cooling systems and avoid water supply and thermal discharge problems.
For the initial cooling system conversion the plant constructed a mechanical-draft, wood cooling tower. The wood tower
with design approach of 6 degrees F was refurbished into a fiberglass tower in 1999. The second recirculating cooling
system utilizes a concrete mechanical-draft tower, with a design approach of 7 degrees F. For both tower systems, a
lack of proximity between the cooling towers and the original intake pumps caused the plant to install new circulating
water pumps. The circulating water flows through 84 inch diameter pipes for Unit 3 (with a piping distance of 650 ft
from tower to condenser) and 72 inch diameter pipes for the Unit 1, 2 common system (with a piping distance from
tower to condenser of 1700 ft). The plant continues to withdraw water through the original intake, although the plant
now operates with new intake pumps. In addition, the condensers for each generating unit remained unchanged after
the conversions, maintaining the design circulating flow. No condenser problems have emerged due to the recirculating
system operation. The principle operational problem for the Canadys Station recirculating system appears to be the
quality of the source water, which shows significant algae problems. The station has mitigated this problem through
the optimization of tower fill and chemical addition and treatment. (Pearrow, 2001).
The construction of the entire Unit 1, 2 cooling tower system occurred in 8 months. The same information was not
available for Unit 3. However, in both cases the cooling system tie-in process lasted approximately 30 days. Although
the net downtime was not quantified by South Carolina Power & Light, the owners stated that the tie-in process was
scheduled to coincide with planned maintenance outages. Each of the conversions occurred in the Spring, with the Unit
3 tie-in occurring in May of 1972 and that of Unit 1, 2 occurring in roughly May/June of 1992. The Agency has
analyzed the historical, monthly-electricity generation for the Canadys Station. The Agency analyzed the generation
about the time of the cooling system conversions (specific to the months of, before, and after the conversions). The
Agency could not demonstrate that the electricity generation for the months of the conversions differ dramatically from
other, non-conversion years. (See DCN 4-2545.)
The Agency inquired of South Carolina Power & Light as to whether they had conducted any historical energy penalty
analyses of the cooling system conversions, which they had not. In addition, the Agency did not receive cost information
for the cooling tower conversions, outside of the statement from South Carolina Power & Light that it did not
experience any significant, unplanned cost overruns for either project.
Jefferies Coal Units 3 & 4. Located in Moncks Corner, South Carolina, this facility has a combined, coal-fired
capacity of 346 MW (nameplate, steam). The two coal units (each with 173 MW nameplate capacity) came online in
1970 and operated for approximately 15 years utilizing once-through cooling. Because the U.S. Army Corps of
Engineers (USAGE) re-diverted the Santee Cooper River, thereby limiting the plant's available water supply, the cooling
system was converted from once-through to a closed-cycle recirculating tower system.
The Agency contacted Santee Cooper to learn about the cooling system conversions at Jefferies (Henderson, 2002).
The Charleston District of the USAGE paid for the construction of the tower system (a common, mechanical-draft,
concrete cooling tower unit for both units with a design approach of 10 degree F and a range of 19 degree F) because
of the re-diversion of the Santee Cooper River. Both the re-diversion of the river and the construction of the
recirculating system occurred between 1983 and 1985. The towers came online in March of 1985. However, the
connection of the recirculating system piping to the existing once-through piping occurred in May of 1983, started up
in June of 1984, and performance tested in September of 1984. The plant installed valves and a Y-connection in May
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§ 316(b) Phase II TDD Cooling System Conversions at Existing Facilities
of 1983, and then continued to operate as a once-through system while the construction of the cooling tower and the
re-diversion project finished. After the tower construction and re-diversion had occurred, the Jefferies plant switched
the valve over to the recirculating system for full conversion.
The plant was able to utilize the existing circulating water pumps of the Jefferies coal units after the cooling system
conversion. However, due to additional pumping head requirements, two small "booster" pumps were added in series
after the existing, large circulating water pumps. The plant was able to continue using the original intake without
modification, but installed a full new set of intake pumps for the reduced capacity. The condenser flow rate did not
change after the conversion. In addition, the plant has not experienced any condenser or tube failure problems as a
result of the conversion to a recirculating cooling system. The plant installed new, 108" diameter circulating piping
between condenser and tower for a total piping distance of 1700 ft.
Santee Cooper conducted an empirical energy-penalty study over several years to determine the economic impact of
the cooling system conversion. Santee Cooper claimed the lost efficiency of the turbines as an economic impact of the
closed-cycle cooling system and obtained reimbursement, after significant and extended negotiation, from the USAGE.
See Chapter 5.6.1 for a discussion of the historical Jefferies Station energy penalty study.
The USAGE owns the cooling towers at the Jefferies plant. Because of this arrangement, the USAGE has paid for the
operation and maintenance (O&M) of the cooling tower system since its construction. The Agency requested historical
capital and O&M cost information from the USAGE but did not receive it prior to publication of the proposed rule.
Because the Agency did not receive the historical O&M information from the plant (which would include the fan and
pump operation for the recirculating system), it cannot assess the full energy penalty of the wet cooling tower system
at the Jefferies plant.
Palisades Nuclear Generating Plant. Located in Covert, Michigan, the Palisades Nuclear Plant was originally built
as an 821 MW (nameplate, steam capacity) plant with a pressurized water reactor, utilizing once-through cooling. The
original license for the plant allowed for 700 MW(e) of net generation. The plant is currently rated for 800 MW(e) of
power, which is an increase of 100 MW over the initial license, and utilizes a mechanical-draft, wood cooling tower
system to condense the steam load of the plant. The plant has replaced the steam generators since originally coming
online, and the system now has a nameplate capacity of 812 MW. The plant began operation in early 1972 utilizing
the once-through cooling system and subsequently converted to a closed-cycle, recirculating system in May of 1974,
when the cooling towers became operational.
Citizen organizations concerned with the impact of the plant on Lake Michigan intervened in the plant's licensing
proceedings. The groups sought to limit radioactive releases from the liquid radwaste system and to limit thermal
discharges to Lake Michigan (Gulvas, 2002). Through a settlement agreement, the Palisades plant agreed to adopt a
recirculating wet system and to make modifications to the radwaste system. Procurement and construction of the
cooling tower system began in mid- to late-1971. Consumers Power Company (now known as Consumers Energy)
originally designed the cooling system for a once-through, maximum-design intake flow of 486,3 80 gpm (30,686 L/sec)
(Benda and Gulvas, 1976). The plant maintained its original, operating condenser flow of approximately 400,000 gpm
after the conversion. The operating intake flow decreased from 405,000 gpm to 78,000 gpm (Consumers Energy,
2001). Because the plant utilized the existing offshore intake without modification for the reduced flow, the intake
velocity decreased from 0.5 ft/sec to less than 0.1 ft/sec. The cooling tower system constructed on plant property
comprises two tower systems, each with 18 mechanical-draft cells. The system is designed to reduce the water
temperature 30 degrees F. The recirculating flow through the system was designed for 410,000 gpm (NRC, 1978).
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§ 316(b) Phase II TDD Cooling System Conversions at Existing Facilities
A modification to cooling tower operation in 1998 resulted in a decreased intake flow rate of 68,000 gpm. In 1999 the
plant obtained approval from the Michigan Department of Environmental Quality to increase its intake flow rate, and
has operated with an intake from Lake Michigan of approximately 100,000 gpm since the approval. The plant sought
to obtain the intake flow rate increase in order to improve electrical generation efficiency (Consumers Energy, 2001).
Subsequently, the cooling water circulation through the condensers increased to 460,700 gpm, but the cooling tower
flow rate remained the same (Gulvas, 2002).
The conversion process at Palisades utilized the original, offshore intake for the reduced flow rates in addition to the
original 3,300-feet long, 11-feet diameter intake piping. However, the plant installed new intake pumps and removed
two traveling screens to install additional "dilution" pumps for the recirculating system. The plant also installed entirely
new circulating water pumps to convey water between the condenser and tower systems. The Agency learned initially
from Consumers Energy that the original once-through pumps might have been utilized for the recirculating system
(DCN 4-2502). However, Consumers Energy's follow-up research indicated that the historical conversion required
new circulating pumps due to increased pumping head. Although the plant chose to install the relatively low-head,
mechanical-draft cooling towers, the converted system required enough additional power from the pumps in order to
warrant full replacement.2
The circulating water flow rate through the condensers did not change from before to after the cooling system
conversion (though the intake flow rate increase in 1999 apparently increased condenser flow). The plant made no
modifications to the condenser in order to accommodate the recirculating system, despite the original once-through
design. However, prior to operation with the recirculating system, a significant portion of the condenser tubes had
begun to fail. The tubes were failing with the once-through system due to vibration. After conversion of the cooling
system, the plant continued to operate with condenser leaks, thereby raising SO4 levels in the generators. This led to
more time necessary to bring the levels in line with specifications before power escalation with the cooling system
operating in recirculating mode. After conversion to the recirculating system, the condenser tubes were replaced.
The Agency concludes that the choice of installation of mechanical-draft towers, as opposed to the more traditional
nuclear design of natural-draft towers, at the Palisades Nuclear Plant may have been, in part, to minimize the plume
migration from the system. The plant is located along a scenic portion of Lake Michigan, in close proximity to sensitive
lakeside vegetation and nearby orchards. In addition, within a half-mile of the plant is a highway. According to
Consumers Energy, the plant has not experienced any problems with the plumes from the mechanical-draft units
interfering with the nearby highway, nor with boating and recreation on the lake (DCN 4-2502). However, vegetation
within 90 meters of the towers was damaged by frost induced by the tower plumes. The NRC estimates that drift from
the Palisades cooling towers (built with drift eliminators and splash fill) deposits within short distances from the towers,
all within 800 feet and 70 percent within 300 feet (NRC, 1978).
The Palisades plant constructed the main portions of the tower system in 1972 and 1973, while the plant operated in
once-through mode. Construction finished by early 1974. In August of 1973 the plant experienced the beginning of
a sizeable outage (ten months), which according to Consumers Energy was due primarily to the connection and testing
of the recirculating system. The Agency had initially learned from a journal article that the plant was off-line for a
variety of maintenance outages, which the Agency interpreted as being mostly unrelated to the cooling tower system.3
2 According to cooling tower bid descriptions from three reputable cooling tower manufacturers, the
typical total dynamic head requirements of a mechanical draft cooling tower unit is approximately 30 feet.
See DCN 4-2501.
3 Benda, R.S. and J. Gulvas, 1976, states "the plant was shutdown because of various operational problems in
August 1973." In addition, during a conference call with the Agency regarding the cooling system conversion,
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§ 316(b) Phase II TDD Cooling System Conversions at Existing Facilities
However, in a letter submitted to the Agency, Consumers Energy stated, "it appears that the outage was primarily for
the purpose of installing the new circulating water system and the modifications necessary for its operation." Through
research into the historical electricity generation of the plant, the Agency confirms that the outage of ten-months
occurred (see DCN 4-2545). However, the Agency notes that it was unable to obtain specific records to show the
cause(s) of the outage. The Agency also notes that part of the settlement agreement called for modifications to the
radwaste system. In addition, plant operation prior to the conversion had shown problems with the condenser.
The final installed cost of the project was $18.8 million (in 1973-1974 dollars), as paid by Consumers Energy. The
key items for this project capital cost included the following: two wood cooling towers (including splash fill, drift
eliminators, and 36-200 hp fans with 28 ft blades); two circulating water pumps; two dilution water pumps; startup
transformers; yard piping for extension of the plant's fire protection system; modifications to the plant screenhouse to
eliminate travelling screens and prepare for installation of the dilution pumps; a new discharge pump stucture with
pump pits; a new pumphouse to enclose the new cooling tower pumps; yard piping for the circulating water system to
connect the new pumphouse and towers; switchgear cubicles for the fans; roads, parking lots, drains, fencing, and
landscaping; and a chemical additive and control system. Additionally, Consumers Energy estimates that the plant
abandoned approximately $683,000 (1973/1974 dollars) of original plant equipment. Excluding the sunk costs of the
abandoned equipment, the project cost is $58.5 in year 2001 dollars (the cost basis of this proposed rule) or $55.9 in
year 1999 dollars (the dollar basis of facility level cost estimates discussed in Chapter 2 of this document). Frequently,
in historical studies of cooling system conversions, the cost basis has been presented as dollars per kW. If the Palisades
conversion project were presented on such a basis, the ratio would be $68 per kW (1999 $ per kW of nameplate
capacity). Utilizing the EPA methodology presented in Chapter 2 for assessing cooling tower "retrofits" gives an
estimated installed capital cost of $68 per kW (1999 $) for a nuclear site with the original design characteristics of
Palisades.
The Agency learned that Consumers Energy believes that the cooling tower system at Palisades has a significant impact
on the efficiency of the plant's generating unit. See Chapter 5.6.3 for a discussion of the Palisades estimates of energy
penalty impacts from the operation of cooling towers.
PittsburgPower Plant, Unit 7. Located in Contra Costa County, California, this 751 MW (nameplate, gas-fired steam)
unit was originally constructed with a recirculating canal cooling system. The plant began operation in 1972 and
converted to a system with mechanical-draft cooling towers in 1976. The original spray canal system, according to
plant personnel, did not operate efficiently enough for the plants needs (DCN 4-2554). The plant then constructed the
mechanical-draft cooling tower system between two reaches of the original canal. Because of the proximity of the
cooling towers to the original circulating piping that serviced the canal, the plant was able to utilize the majority of this
existing circulating piping system with the converted design. The construction of the cooling towers occurred on a very
narrow strip of land between the canals. The location provides minimal buffer land surrounding the towers, and
indicates that the site required significant prepartion work. The cooling towers extend along the canal divider from
about 300 meters away from the generating unit buildings to approximately 800 meters. The mechanical-draft towers
consist of two units, each with 13 cells. The water supply used in the system is brackish water from Suisun Bay. The
cooling system conversion utilized the existing condenser in addition to the conduit system. The design condenser flow
is 352,000 gpm. The plant's design intake flow rate is 20,200 gpm (EEI, 1994).
Consumers Energy stated that operational problems unrelated to the conversion process had been mostly
responsible for the extended outage (see DCN 4-2502).
4-5
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§ 316(b) Phase II TDD Cooling System Conversions at Existing Facilities
Pacific Gas & Electric, former owners of the Pittsburg Power Plant, reported the total project cost for the cooling
conversion at Pittsburg Unit 7 as $16.7 million (1976 $) (DCN 4-2506). This corresponds to $40.87 million in 1999
dollars or $54 per kW (1999 $ per kW of nameplate capacity). Because the plant is in Contra Costa County,
California, the cost of construction in this area may not be representative of other areas of the country. The Oakland,
California area has a city construction multiplier of approximately 1.19 according to a cost estimating reference (R.S.
Means, 2000). Therefore, the costs for the Pittsburg Unit 7 conversion on a national average basis would be
approximately $34.4 million for total project capital cost (in 1999 $) or $46 per kW (1999 $ per kW of nameplate
capacity). Utilizing the EPA methodology presented in Chapter 2 for assessing cooling tower "retrofits" gives an
estimated installed capital cost of $38 per kW (1999 $, national-average cost basis) for a site with the characteristics
of Pittsburg Unit 7.
Dry Cooling Conversion Projects. At the time of this proposal, the Agency is unaware of demonstrated cases of
cooling system conversions involving dry cooling systems for the size of power plants within the scope of this proposed
rule. See Appendix D of this document for a discussion of dry cooling systems and their applicability for retrofit
designs.
4.2 PLANT OUTAGES FOR COOLING SYSTEM CONVERSIONS
For three of the cooling system conversion cases examined above, the Agency obtained information from the plants
regarding the gross outage duration for converting between cooling system types. The duration of the outages reported
to the Agency were 83 hours (gross) for the Jefferies Station, 30 days (gross) for each of the two Canadys conversions,
and 10 months (gross) for Palisades Nuclear. The Agency examined historical electricity generation data for these
plants and could infer that these outages did occur. However, due to the historical nature of the projects (that is,
conversions that occurred from 10 to 30 years ago), the Agency found the documentation of the engineering aspects
of the conversions to be limited. For the more recent projects - Jefferies and Canadys Unit 3 - the Agency received
information directly from members of the plant staff that participated in, or were employed at the stations during the
conversions. For Palisades, the Agency received a significant historical information about the plant, but limited
information relating to the specifics of the plant outage for the cooling system conversion.
Based on these limited data points provided to the Agency, conclusions as to the expected duration of outages for a
variety of cooling system conversions cannot be conclusively drawn. The only substantial conclusion the Agency can
reach is that the gross duration of the outage varies widely, based on the data reported to the Agency, and that the
possibility exists for both extremely short outages and those of extremely long duration. The Agency based the
economic analysis of the regulatory options summarized in Section 4.3 on a gross outage of one-month per converted
plant. The Agency based this estimate on the information it had received from Jefferies and Canadys stations and
research into other projections (see below). The Agency did not receive the Palisades information until very late in the
development of this proposed rule. Based on the information provided to the Agency (including the late Palisades
submission), the estimate of one-month could in some cases over- and others under-estimate the expected outage
duration for a cooling system conversion. In addition, there is some evidence that the durations of outages may differ
based on fuel type (that is, nuclear versus non-nuclear).
As mentioned above, the Agency researched outage projections from historical 316 demonstrations, where plants
conducted engineering studies as to the duration of the expected outage for a site-specific cooling system conversion.
Appendix VIII-3 of the Draft Environmental Impact Statement (DEIS) for Bowline Point, Indian Point 2 & 3, and
Roseton Generating Stations (Power Tech Associates, 1999) estimates net outage durations for an evaluation of four
closed-cycle cooling projects. The DEIS states, "plants must be shut down for construction and commissioning beyond
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§ 316(b) Phase II TDD Cooling System Conversions at Existing Facilities
the normal shutdowns of the plants. In the cases of Roseton and Bowline, this period was estimated at one month
beyond normal outages." For the two nuclear units of Indian Point, the authors estimate two outages for each unit, with
each outage lasting 4 months. The DEIS states that the basis of the longer estimates for the nuclear plants is as follows:
"the safety issues have to be addressed during excavation (particularly when blasting is required), tying the new system
into the plant, and the extensive testing which must follow." The DEIS estimates that the separate blasting and tying-in
outages would last four months each, considerably longer than for the fossil-fueled Bowline Point and Roseton Stations.
The Agency notes that there is no detailed engineering basis (such as detailed descriptions of the types of connections
to be made, etc.) given by the Authors for any of the projections made in Appendix VIII-3 of the 1999 DEIS.
The Agency also consulted a detailed historical proposal for a Roseton Generating Station cooling system conversion
(Central Hudson Gas & Electric, 1977). The report estimates a gross outage period of one-month for the final pipe
connections for the recirculating system. The report estimates the net outage as 10 days for one of the two units and
no downtime for the second. The reason for the short estimates of downtime are due to the coincidence of the
connection process with planned winter maintenance outages. Unlike the projection in the 1999 DEIS described above,
this 1977 projection was accompanied by a relatively detailed description of the expected level of effort and engineering
expectations for connecting the reciruclating system to existing equipment.
The Agency learned from the NPDES permit application for Salem Generating Station estimates that outages due to
construction and conversion to cooling towers are expected to last 7 months per generating unit, in addition to the
station's planned outages for refueling (see Appendix F, Attachment 8 of the 1999 PSE&G Permit Application for
Salem Generating Station, Permit No. NJ0005622).
In addition, the Agency consulted a variety of sources to determine the typical occurrence and duration of planned
maintenance outages. As noted in the example cases described in Section 4.1 above, each of the cooling system
conversions coincided with planned maintenance outages. Appendix VIII-2.A of the DEIS for the fossil-fuel Roseton
Station states, "a review of historical data indicates that there has [sic] been 30 day maintenance outages occurring
nominally from mid-Sept, to mid-Oct."
The 1999 Permit Application for Salem predicts a three year refueling cycle for each unit that is accompanied by
outages of approximately 60 days one year, 40 days in a second year, and no outage in the third. This data is consistent
with other information the Agency obtained from literature. The Agency learned that for 2000 the industry mean
nuclear refueling outage was approximately 40 days (Nucleonics Week, January 18,2001). In addition, NUREG-1437
shows that nuclear plants undergo periodic and predictable outages for inspections. The following excerpts from
NUREG-1437 explain the NRC's view of outages at nuclear plants:
From Section 2.2.6-
Nuclear power plants must periodically discontinue the production of electricity for refueling, periodic in-
service inspection (ISI), and scheduled maintenance. Refueling cycles occur approximately every 12 to 18
months. The duration of a refueling outage is typically on the order of 2 months. Enhanced or expanded
inspection and surveillance activities are typically performed at 5- and 10-year intervals. These enhanced
inspections are performed to comply with Nuclear Regulatory Commission (NRC) and/or industry standards
or requirements such as the American Society of Mechanical Engineers Boiler and Pressure Vessel Code. Five-
year ISIs are scheduled for the 5th, 15th, 25th, and 35th years of operation, and 10-year ISIs are performed
in the 10th, 20th, and 30th years. Each of these outages typically requires 2 to 4 months of down time for the
4-7
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§ 316(b) Phase II TDD
Cooling System Conversions at Existing Facilities
plant. For economic reasons, many of these activities are conducted simultaneously (e.g., refueling activities
typically coincide with the ISI and maintenance activities).
Many plants also undertake various major refurbishment activities during their operational lives. These
activities are performed to ensure both that the plant can be operated safely and that the capacity and reliability
of the plant remain at acceptable levels. Typical major refurbishments that have occurred in the past include
replacing PWR steam generators, replacing BWR recirculation piping, and rebuilding main steam turbine
stages. The need to perform maj or refurbishments is highly plant-specific and depends on factors such as design
features, operational history, and construction and fabrication details. The plants may remain out of service
for extended periods of time, ranging from a few months to more than a year, while these major refurbishments
are accomplished. Outage durations vary considerably, depending on factors such as the scope of the repairs
or modifications undertaken, the effectiveness of the outage planning, and the availability of replacement parts
and components.
Each nuclear power plant is part of a utility system that may own several nuclear power plants, fossil-fired
plants, or other means of generating electricity. An on-site staff is responsible for the actual operation of each
plant, and an off-site staff may be headquartered at the plant site or some other location. Typically, from 800
to 2300 people are employed at nuclear power plant sites during periods of normal operation, depending on the
number of operating reactors located at a particular site. The permanent on-site work force is usually in the
range of 600 to 800 people per reactor unit. However, during outage periods, the on-site work force typically
increases by 200 to 900 additional workers. The additional workers include engineering support staff,
technicians, specialty craftspersons, and laborers called in both to perform specialized repairs, maintenance,
tests, and inspections and to assist the permanent staff with the more routine activities carried out during plant
QRHL-DWQ 95-1751
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§ 316(b) Phase II TDD Cooling System Conversions at Existing Facilities
Figure 2.3 from NUREG-1437, Volume I.
The Agency also found information on outage information contained in the April, 2001 accounting report for Mirant,
Corp. (form 8K, April 27, 2001). The report gave the following information on planned outages at Mirant's California
fossil-fueled power plants:
Major maintenance is presently scheduled on a three-year cycle for the boilers and a 6-year interval for the
steam turbine-generators. The overhaul duration is typically six to eight weeks, depending on the scope of the
work to be performed. Virtually all of the Mirant California Facilities' major maintenance for the next few
years will be performed during outages dictated by the installation of SCR systems or low-NO(X) burners, both
to reduce NO(X) emissions.
Major outages are scheduled for Contra Costa Units 6 and 7 in 2000-2001 to install systems to reduce stack
emissions. Low-NO(X) burners were recently installed on Contra Costa Unit 6. Contra Costa Unit 7 is
scheduled for installation of a SCR system from March to June of 2001 with Contra Costa Unit 6 SCR
installation scheduled for 2003.
Major outages are scheduled for Pittsburg Units 1 through 7 within the next three years to install systems to
reduce stack emissions or correct equipment concerns that are affecting reliability. Pittsburg Units 1 through
4 will retube the condensers and perform boiler repair work in 2001. Pittsburg Units 5 and 6 just completed
installation of low-NO(X) burners and are scheduled to install SCRs in 2001-2002. Pittsburg Unit 7 is
scheduled to install an SCR in 2003. The SCR outages will be between 14 and 20 weeks long.
Potrero Unit 3 will have two major outages in the next four years, 2001 to retube the condenser and make boiler
repairs as necessary and 2004 to install an SCR. The scheduled duration of these outages is 10 and 20 weeks
respectively.
The Agency located a reference for a project where four condenser waterboxes and tube bundles were removed and
replaced at a large nuclear plant (Arkansas Nuclear One). The full project lasted approximately 2 days. The facility,
based on experience, had estimated the full condenser replacement to occur over the course of 8 days. Even though the
scope of condenser replacements differ from potential cooling system conversions, the regulatory options considered
for flow reduction commensurate with wet cooling anticipate that a subset of conversions would precipitate condenser
tube replacements. As such, the condenser replacement schedule is important to the consideration of select cooling
system conversions.
4.3 SUMMARY OF FLOW-REDUCTION OPTIONS CONSIDERED
The Agency examined regulatory options based on intake flow reduction at in-scope, existing power plants for the
proposed rule. The following summaries describe the three wet cooling based options considered by the Agency.
Intake Capacity Commensurate with Closed-Cycle, Recirculating Cooling System for All Facilities
EPA considered a regulatory option that would require Phase II existing facilities having a design intake flow 50
MGD or more to reduce the total design intake flow to a level, at a minimum, commensurate with that which can be
attained by a closed-cycle recirculating cooling system using minimized make-up and blowdown flows. In addition,
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§ 316(b) Phase II TDD Cooling System Conversions at Existing Facilities
facilities in specified circumstances (for example, located where additional protection is needed due to concerns
regarding threatened, endangered, or protected species or habitat; migratory, sport or commercial species of
concern) would have to select and implement design and construction technologies to minimize impingement
mortality and entrainment. This option does not distinguish between facilities on the basis of the waterbody from
which they withdraw cooling water. Rather, it would ensure that the same stringent controls are the nationally
applicable minimum for all waterbody types. This is the regulatory approach EPA adopted for new facilities. As
stated above, 73 of the facilities potentially subject to this proposed rule already utilize a recirculating wet cooling
system (e.g., wet cooling towers or ponds). These facilities would meet the requirements under this option unless
they are located in areas where the director or fisheries managers determine that fisheries need additional protection.
Therefore, under this option, 466 steam electric power generating facilities would be required to meet performance
standards for reducing impingement mortality and entrainment based on a reduction in intake flow to a level
commensurate with that which can be attained by a recirculating, closed-cycle wet system.
EPA did not select closed-cycle, recirculating cooling systems as the best technology available for existing facilities
because of the generally high costs of such conversions. According to EPA's cost estimates, capital costs for
individual high-flow plants to convert to wet towers generally ranged from 130 to 200 million dollars, with annual
operating costs in the range of 4 to 20 million dollars. EPA estimates that the total annualized post-tax cost of
compliance for this option is approximately $2.26 billion. Not included in this estimate are 9 facilities that are
projected to be baseline closures. Including compliance costs for these 9 facilities would increase the total cost of
compliance with this option to approximately $2.32 billion. EPA also has serious concerns about the short-term
energy implications of a massive concurrent conversion and the potential for supply disruptions that it would entail.
The estimated annual benefits (in $2001) for requiring all Phase II existing facilities to reduce intake capacity
commensurate with the use of closed-cycle, recirculating cooling systems are $83.9 million per year and $1.08
billion for entrainment reductions.
Intake Capacity Commensurate with Closed-Cycle Wet Cooling Systems for All Facilities on Oceans,
Estuaries, and Tidal Rivers
EPA considered an alternate technology-based option in which closed-cycle, recirculating cooling systems would be
required for all facilities on certain waterbody types. Under this option, EPA would group waterbodies into the
same five categories as in today's proposal: (1) freshwater rivers or streams, (2) lakes or reservoirs, (3) Great
Lakes, (4) tidal rivers or estuaries; and (5) oceans. Because oceans, estuaries and tidal rivers contain essential
habitat and nursery areas for the vast majority of commercial and recreational important species of shell and fin
fish, including many species that are subject to intensive fishing pressures, these waterbody types would require
more stringent controls based on the performance of closed-cycle, recirculating cooling systems. EPA discussed the
susceptibility of these waters in a Notice of Data Availability (NODA) for the new facility rule (66 FR 28853, May
25, 2001) and invited comment on documents that may support its judgment that these waters are particularly
susceptible to adverse impacts from cooling water intake structures. In addition, the NODA presented information
regarding the low susceptibility of non-tidal freshwater rivers and streams to impacts from entrainment from
cooling water intake structures.
Under this alternative option, facilities that operate at less than 15 percent capacity utilization would, as in the
proposed option, only be required to have impingement control technology. Facilities that have a closed-cycle,
recirculating cooling system would require additional design and construction technologies to increase the survival
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§ 316(b) Phase II TDD Cooling System Conversions at Existing Facilities
rate of impinged biota or to further reduce the amount of entrained biota if the intake structure was located within
an ocean, tidal river, or estuary where there are fishery resources of concern to permitting authorities or fishery
managers.
Facilities with cooling water intake structures located in a freshwater (including rivers and streams, the Great Lakes
and other lakes) would have the same requirements as under the proposed rule. If a facility chose to comply with
Track II, then the facility would have to demonstrate that alternative technologies would reduce impingement and
entrainment to levels comparable to those that would be achieved with a closed-loop recirculating system (90%
reduction). If such a facility chose to supplement its alternative technologies with restoration measures, it would
have to demonstrate the same or substantially similar level of protection. (For additional discussion see the new
facility final rule 66 FR 65256, at 65315 columns 1 and 2.)
EPA has estimated that there are 109 facilities located on oceans, estuaries, or tidal rivers that do not have a closed
cycle recirculating system and would be required to meet performance standards for reducing impingement
mortality and entrainment based on a reduction in intake flow to a level commensurate with that which can be
attained by a closed-cycle recirculating system. The other 430 facilities would be required to meet the same
performance standards in the in today's proposal.
The potential environmental benefits of this option have been estimated at $87.8 million and $1.24 billion for
entrainment reductions annually. Although this option is estimated (a full cost analysis was not done for this option)
to be less expensive at a national level than requiring closed-cycle, recirculating cooling systems for all Phase II
existing facilities, EPA is not proposing this option. Facilities located on oceans, estuaries, and tidal rivers would
incur high capital and operating and maintenance costs for conversions of their cooling water systems.
Furthermore, since impacted facilities would be concentrated in coastal regions, there is the potential for short-term
energy impacts and supply disruptions in these areas. EPA also invites comment on this option.
Intake Capacity Commensurate with Closed-Cycle, Recirculating Cooling System Based on Waterbody Type
EPA also considered a variation on the above approach that would require only facilities withdrawing very large
amounts of water from an estuary, tidal river, or ocean to reduce their intake capacity to a level commensurate with
that which can be attained by a closed-cycle, recirculating cooling system.
For example, for facilities with cooling water intake structures located in a tidal river or estuary, if the intake flow
is greater than 1 percent of the source water tidal excursion, then the facility would have to meet standards for
reducing impingement mortality and entrainment based on the performance of wet cooling towers. These facilities
would have the choice of complying with Track I or Track II requirements. If a facility on a tidal river or estuary
has intake flow equal to or less than 1 percent of the source water tidal excursion, the facility would only be
required to meet the performance standards in the proposed rule. These standards are based on the performance of
technologies such as fine mesh screens and traveling screens with well-designed and operating fish return systems.
The more stringent, closed-cycle, recirculating cooling system-based requirements would also apply to a facility
that has a cooling water intake structure located in an ocean with an intake flow greater than 500 MOD.
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§ 316(b) Phase II TDD Cooling System Conversions at Existing Facilities
REFERENCES
Benda, R.S. and J. Gulvas, 1976, "Effects of Palisades Nuclear Power Plant on Lake Michigan," Thermal Ecology
II, Proceedings of a Symposium Held at Augusta, Georgia.
Central Hudson Gas & Electric Corporation, 1977, "Engineering, Environmental (Nonbiological), and Economic
Aspects of a Closed-Cycle Cooling System," Roseton Generating Station.
Consumers Energy Company and Nuclear Management Corporation, May 2001, "Biological Assessment of the
1999 Cooling Water Flow Increase at the Palisades Nuclear Plant, near South Haven, Michigan."
Edison Electric Institute, 1994, "Power Statistics Unit Design Data File Part B of the 1994 UDI Database."
Gulvas, J.A., Consumers Energy, Feb. 28, 2002, Data Submission to Tim Connor of the U.S. EPA, "RE: Palisades
Plant Once-Through and Cooling Towers."
Henderson, J., Santee Cooper, 2002, Response to Information Request from Tim Connor of USEPA. (DCN 4-
2528)
Platts, 2001, "U.S. Utilities Reporting Record 2000 Nuclear Output," Nucleonics Week, Vol. 42 No. 3, January
18, 2001, McGraw-Hill Companies, Inc.
Mirant Corp., 2001, Form 8K - April 27, 2001, Item 9. Regulation FD Disclosure.
http://www.biz.yahoo.eom/e/010427/mir.html
Pearrow, J. J., 2001, "Hydrogen Peroxide Keeps Cooling Tower Fill Clean," Power Magazine, May/June 2001.
(DCN 4-2523)
Perry, W. J., 1991, "Adverse Impact Study, Cooling Water Facilities, Jefferies Generating Station," Moncks
Corner, South Carolina, Santee Cooper.
Power Tech Associates, 1999, "Economic and Environmental Review of Closed Cooling Water Systems for the
Hudson River Power Plants," prepared for Central Hudson Gas & Electric, Corp., et al., Appendix VIII-3 of the
Draft Environmental Impact Statement for Bowline Point, Indian Point 2 & 3, and Roseton Generating Stations.
United States Nuclear Regulatory Comission, 1978, "Final Adendum to the Final Environmental Statement for
Palisades Nuclear Generating Plant," Docket No. 50-255, Final Adendum to FES (NUREG-0343).
U.S. EPA teleconference with John Gulvas of Consumers Energy; December 2001. (DCN 4-2502)
U.S. EPA, 2002, "Phone Memorandum - Conversation with Ron Kino of Mirant Pittsburgh (DCN 4-2554)
Veil, J., 2002, Correspondence with US EPA. (DCN 4-2506)
Waier, P. R., Senior Editor, 2000, "R.S. Means Building Construction Cost Data," 58th Annual Edition, R.S.
Means Company, Inc.
Wicker, K., South Carolina Electric & Gas Co., 2002, Response to Information Request from Tim Connor of
USEPA. (DCN 4-2508)
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§ 316(b) Phase II TDD Energy Penalties of Cooling Towers
Chapter 5: Energy Penalties of Cooling Towers
INTRODUCTION
For the Existing Facility 316(b) Proposal, the Agency considered regulatory options in which regulated facilities (or
a subset thereof) would achieve flow reduction commensurate with closed-cycle wet cooling systems. In addition, the
Agency analyzed regulatory options based on flow reduction commensurate with near-zero intake of dry cooling
systems. This chapter discusses the topics of energy penalties of such cooling systems.
For the Section 316(b) New Facility Final Rule the Agency researched and derived energy penalty estimates, based on
empirical data and proven theoretical concepts, for a variety of conditions. The regulatory analysis conducted by the
Agency for this Existing Facility Section 316(b) Proposal utilized the results of the New Facility analysis. This chapter
presents the research, methodology, results, and conclusions for the Agency's thorough effort to estimate energy
penalties due to the operational performance of power plant cooling systems.
As a consequence of energy penalties for some cooling systems, increased air pollutant emissions may occur for some
power plants as compared to a baseline system. The discussion of air pollutant emissions and other potential
environmental impacts from cooling towers are presented in Chapter 6 of this document.
The remainder of this chapter is organized as follows:
*• Section 5.1 presents the energy penalty estimates used for analysis of the flow reduction regulatory options.
> Section 5.2 presents an introduction to the Agency's energy penalty estimates.
> Section 5.3 focuses on steam turbines and the changes in efficiency associated with using alternative cooling
systems.
*• Section 5.4 evaluates the net difference in required pumping and fan energy for alternative cooling systems.
> Section 5.5 combines and summarizes the energy impacts of pumping and fan energy requirements for alternative
cooling systems.
> Section 5.6 summarizes data from other sources on the potential energy penalty of alternative cooling systems at
existing facilities.
5-1
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§ 316(b) Phase II TDD
Energy Penalties of Cooling Towers
5.1 ENERGY PENALTY ESTIMATES FOR COOLINS
Tables 5-1 through 5-4 present the energy penalty estimates utilized for assessing the operational energy impacts of
certain, flow-reduction regulatory options considered for this proposal. The Agency presents the methodology for
estimation of energy penalties in Sections 5.2 through 5.5 of this chapter.
Table 5-1: National Average, Mean- Annual Energy Penalty, Summary Table
Cooling Type
Wet Tower vs. Once-Through
Dry Tower vs. Once-Through
Dry Tower vs. Wet Tower
Percent
Maximum
Load3
67
67
67
Mean-Annual
Nuclear
Percent of
Plant Output
1.7
8.5
6.8
Mean-Annual
Combined-Cycle
Percent of Plant
Output
0.4
2.1
1.7
Mean-Annual
Fossil-Fuel
Percent of
Plant Output
1.7
8.6
6.9
For calculating the average annual penalties, the Agency conservatively estimated that plants will
operate over the course of the year at non-peak loads. See below for a discussion of percent maximum
load.
Table 5-2: National Average, Peak-Summer Energy Penalty, Summary Table
Cooling Type
Wet Tower vs. Once-Through
Dry Tower vs. Once-Through
Dry Tower vs. Wet Tower
Percent
Maximum
Load3
100
100
100
Peak-Summer
Nuclear
Percent of
Plant Output
1.9
11.4
9.6
Peak-Summer
Combined-Cycle
Percent of Plant
Output
0.4
2.8
2.4
Peak-Summer
Fossil-Fuel
Percent of
Plant Output
1.7
10.0
8.4
3 Peak-summer shortfalls occur when plants are at or near maximum capacity.
The Agency developed its estimates of average annual energy penalties based on the assumption that during non-peak
loads turbines would operate at roughly 67 percent of maximum peak load. Therefore, the Agency's estimates of annual
energy penalties in Tables 5-1 and 5 -3 represent calculations of turbine energy penalties at 67 percent of maximum load.
The Agency considered this to be a conservative assumption for the calculation of energy penalties because turbine
efficiency is considerably higher for the 100 percent of maximum load condition. The Agency understands, based on
discussions with the Department of Energy, that a significant portion of existing power plants, when dispatched, would
likely operate at near maximum loads. Therefore, the turbine energy penalty portion of mean annual energy penalty
estimates presented in Tables 5-1 and 5-3 could be overstated. The Agency estimates that had it calculated the mean
annual penalties for the 100 percent of maximum load condition, the national average annual energy penalty of wet
cooling versus once-through systems would be approximately 0.3 percent for combined-cycle, 1.1 percent for fossil-
5-2
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§ 316(b) Phase II TDD
Energy Penalties of Cooling Towers
fuel, and 1.3 for nuclear plants. However, the Agency utilized the higher values in Tables 5-1 and 5 -3 for the economic
analyses of the regulatory options considered for this proposal.
Table 5-3: Total Energy Penalties at 67 Percent Maximum Load"
Location
Boston
Jacksonville
Chicago
Seattle
Cooling Type
Wet Tower vs. Once-Through
Dry Tower vs. Once-Through
Dry Tower vs. Wet Tower
Wet Tower vs. Once-Through
Dry Tower vs. Once-Through
Dry Tower vs. Wet Tower
Wet Tower vs. Once-Through
Dry Tower vs. Once-Through
Dry Tower vs. Wet Tower
Wet Tower vs. Once-Through
Dry Tower vs. Once-Through
Dry Tower vs. Wet Tower
Nuclear Annual
Average
1.6
7.4
5.8
1.9
12.0
10.1
1.8
7.8
5.9
1.5
7.0
5.5
Combined-Cycle
Annual Average
0.4
1.8
1.4
0.4
3.0
2.5
0.4
1.9
1.5
0.4
1.7
1.3
Fossil-Fuel
Annual Average
1.6
7.1
5.5
1.7
12.5
10.8
1.8
7.7
5.9
1.5
6.9
5.4
For calculating the average annual penalties, the Agency conservatively estimated that plants will operate over the
course of the year at non-peak loads. See above for a discussion of percent maximum load.
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§ 316(b) Phase II TDD
Energy Penalties of Cooling Towers
Table 5-4: Total Energy Penalties at 100 Percent Maximum Load0
Location
Boston
Jacksonville
Chicago
Seattle
Cooling Type
Wet Tower vs. Once-Through
Dry Tower vs. Once-Through
Dry Tower vs. Wet Tower
Wet Tower vs. Once-Through
Dry Tower vs. Once-Through
Dry Tower vs. Wet Tower
Wet Tower vs. Once-Through
Dry Tower vs. Once-Through
Dry Tower vs. Wet Tower
Wet Tower vs. Once-Through
Dry Tower vs. Once-Through
Dry Tower vs. Wet Tower
Peak-Summer
Nuclear Percent
of Plant Output
2.1
11.6
9.5
1.6
12.3
10.7
2.2
11.9
9.6
1.6
10.0
8.4
Peak-Summer
Combined-Cycle
Percent of Plant Output
0.5
2.9
2.4
0.4
3.1
2.7
0.5
2.9
2.4
0.4
2.4
2.0
Peak-Summer Fossil-
Fuel Percent of
Plant Output
1.9
10.2
8.3
1.4
10.7
9.3
2.0
10.4
8.4
1.5
8.9
7.4
Peak-summer shortfalls occur when plants are at or near maximum capacity.
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§ 316(b) Phase II TDD Energy Penalties of Cooling Towers
5.2 INTRODUCTION TO ENERGY PENALTY ESTIMATES
This energy penalty discussion presents differences in steam power plant efficiency or output associated with the effect
of using alternative cooling systems. In particular, this evaluation focuses on power plants that use steam turbines and
the changes in efficiency associated with using alternative cooling systems. The cooling systems evaluated include:
once-through cooling systems; wet tower closed-cycle systems; and direct-dry cooling systems using air cooled
condensers. However, the methodology is flexible and can be extended to other alternative types of cooling systems
so long as the steam condenser performance or the steam turbine exhaust pressure can be estimated.
The energy penalties presented in this chapter were developed for new, "greenfield" facilities. As such, the Agency
estimates for this proposal for existing facilities that the energy penalties of cooling system conversions from once-
through to recirculating wet cooling towers would be similar to the new, "greenfield" cases. The Department of Energy
expressed concern that this methodology may underestimate the pumping energy requirements of recirculating wet tower
systems for converted cooling systems. This matter, among others, is discussed in Section 5.6 below.
The Agency acknowledges that direct-dry cooling systems are unlikely candidates for cooling system conversions at
existing power plants. A direct-dry cooling system (as discussed in Appendix D of this document) condenses the
exhaust steam that is fed directly to the dry tower from the generating turbine. However, steam turbines at the existing
power plants within the scope of this rule are, without exception, configured to condense steam utilizing a surface
condenser system. Therefore, the only type of dry cooling system that would be considered for a cooling system
conversion is an indirect-air cooled condenser. Otherwise, the entire steam turbine would be replaced or dramatically
reconfigured to feed exhaust steam to a direct-dry cooling system. The engineering feasibility of this type of plant
reconfiguration was considered unproven by the Agency and the costs of turbine replacement were also deemed too high
for this proposal.
Indirect-dry cooling systems operate less efficiently than direct-dry cooled systems. Therefore, the energy penalties for
dry cooling systems presented in this chapter would be higher for the only application that would be considered for
existing facilities. The Department of Energy (DOE) studied the peak summer energy penalty resulting from converting
plants with once-through cooling to wet towers or indirect dry towers (see DCN 4-2512). DOE modeled five locations
- Delaware River Basin (Philadelphia), Michigan/Great Lakes (Detroit), Ohio River Valley (Indianapolis), South
(Atlanta), and Southwest (Yuma) - using an ASPEN simulator model. The model evaluated the performance and
energy penalty for hypothetical 400-MW coal-fired plants that were retrofitted from using once-through cooling systems
to wet- and dry-recirculating systems. The DOE estimates that conversion to an indirect-dry tower could cause peak
summer energy penalties ranging from 8.9 percent to 14.1 percent with a design approach of 20 degrees Fahrenheit and
12.7 percent to approximately 18 percent with an approach of 40 degrees Fahrenheit. Note that these peak summer
energy penalties are higher than those estimated by EPA (as presented in Tables 5-2 and 5-4 above) for the direct-dry
cooling system. The Agency's estimates of direct-dry cooling system peak summer energy penalties range from 7.4
percent to 10.7 percent for fossil-fuel plants. As such, the analysis of energy effects of the dry cooling-based regulatory
options considered for this proposal may not reflect the full magnitude of the energy penalty of the indirect-dry cooling
systems.
5.2.1 Power Plant Efficiencies
Most power plants that use a heat-generating fuel as the power source use a steam cycle referred to as a "Rankine
Engine," in which water is heated into steam in a boiler and the steam is then passed through a turbine (Woodruff
1998). After exiting the turbine, the spent steam is condensed back into water and pumped back into the boiler to repeat
the cycle. The turbine, in turn, drives a generator that produces electricity. As with any system that converts energy
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§ 316(b) Phase II TDD Energy Penalties of Cooling Towers
from one form to another, not all of the energy available from the fuel source can be converted into useful energy in a
power plant.
Steam turbines extract power from steam as the steam passes from high pressure and high temperature conditions at
the turbine inlet to low pressure and lower temperature conditions at the turbine outlet. Steam exiting the turbine goes
to the condenser, where it is condensed to water. The condensation process is what creates the low pressure conditions
at the turbine outlet. The steam turbine outlet or exhaust pressure (which is often a partial vacuum) is a function of
the temperature maintained at the condensing surface (among other factors) and the value of the exhaust pressure can
have a direct effect on the energy available to drive the turbine. The lower the exhaust pressure, the greater the amount
of energy that is available to drive the turbine, which in turn increases the overall efficiency of the system since no
additional fuel energy is involved.
The temperature of the condensing surface is dependent on the design and operating conditions within the condensing
system (e.g., surface area, materials, cooling fluid flow rate, etc.) and especially the temperature of the cooling water
or air used to absorb heat and reject it from the condenser. Thus, the use of a different cooling system can affect the
temperature maintained at the steam condensing surface (true in many circumstances). This difference can result in
a change in the efficiency of the power plant. These efficiency differences vary throughout the year and may be more
pronounced during the warmer months. Equally important is the fact that most alternative cooling systems will require
a different amount of power to operate equipment such as fans and pumps, which also can have an effect on the overall
plant energy efficiency. The reductions in energy output resulting from the energy required to operate the cooling
system equipment are often referred to as parasitic losses.
In general, the penalty described here is only associated with power plants that utilize a steam cycle for power
production. Therefore, this analysis will focus only on steam turbine power plants and combined-cycle gas plants. The
most common steam turbine power plants are those powered by steam generated in boilers heated by the combustion
of fossil fuels or by nuclear reactors.
Combined-cycle plants use a two-step process in which the first step consists of turbines powered directly by high
pressure hot gases from the combustion of natural gas, oil, or gasified coal. The second step consists of a steam cycle
in which a turbine is powered by steam generated in a boiler heated by the low pressure hot gases exiting the gas
turbines. Consequently, the combined-cycle plants have much greater overall system efficiencies. However, the energy
penalty associated with using alternative cooling systems is only associated with the steam cycle portion of the system.
Because steam plants cannot be quickly started or stopped, they often operate as base load plants, which are
continuously run to serve the minimum load required by the system. Since combined-cycle plants obtain only a portion
of their energy from the slow-to-start/stop steam power step, the inefficiency of the start-up/stop time period is more
economically acceptable and therefore they are generally used for intermediate loads. In other words, they are started
and stopped at a greater frequency and with greater efficiency than base load steam plant facilities.
One measure of the plant thermal efficiency used by the power industry is the Net Plant Heat Rate (NPHR), which is
the ratio of the total fuel heat input (BTU/hr) divided by the net electric generation (kW). The net electric generation
includes only electricity that leaves the plant. The total energy plant efficiency can be calculated from the NPHR using
the following formula:
Plant Energy Efficiency = 3413 / NPHR x 100 (1)
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Table 5-5 presents the NPHR and plant efficiency numbers for different types of power plants. Note that while there
may be some differences in efficiencies for steam turbine systems using different fossil fuels, these differences are not
significant enough for consideration here. The data presented to represent fossil fuel plants is for coal-fired plants,
which comprise the majority in that category.
Table 5-5: Heat Rates and
Type of Plant
Steam Turbine - Fossil Fuel
Steam Turbine - Nuclear
Combined Cycle - Gas
Combustion Turbine
'lant Efficiencies for Different Type
Plants
Net Plant Heat Rate (BTU/kWh)
9,355
10,200
6,762
11,488
.s of Steam Powered
Efficiency (%)
37 to 40
34
51
30
Source: Analyzing Electric Power Generation under the CAAA. Office of Air and Radiation U.S.
Environmental Protection Agency. April 1996 (Projections for year 2000-2004).
Overall, fossil fuel steam electric power plants have net efficiencies with regard to the available fuel heat energy ranging
from 37 to 40 percent. Attachment A at the end of this chapter (Ishigai, S. 1999.) shows a steam power plant heat
diagram in which approximately 40 percent of the energy is converted to the power output and 44 percent exits the
system through the condensation of the turbine exhaust steam, which exits the system primarily through the cooling
system with the remainder exiting the system through various other means including exhaust gases. Note that the exergy
diagram in Attachment A shows that this heat passing through the condenser is not a significant source of plant
inefficiency, but as would be expected it shows a similar percent of available energy being converted to power as shown
in Table 5-5 and Attachment A.
Nuclear plants have a lower overall efficiency of approximately 34 percent, due to the fact that they generally operate
at lower boiler temperatures and pressures and the fact that they use an additional heat transfer loop. In nuclear plants,
heat is extracted from the core using a primary loop of pressurized liquid such as water. The steam is then formed in
a secondary boiler system. This indirect steam generation arrangement results in lower boiler temperatures and
pressures, but is deemed necessary to provide for safer operation of the reactor and to help prevent the release of
radioactive substances. Nuclear reactors generate a near constant heat output when operating and therefore tend to
produce a near constant electric output.
Combustion turbines are shown here for comparative purposes only. Combustion turbine plants use only the force of
hot gases produced by combustion of the fuel to drive the turbines. Therefore, they do not require much cooling water
since they do not use steam in the process, but they are also not as efficient as steam plants. They are, however, more
readily able to start and stop quickly and therefore are generally used for peaking loads.
Combined cycle plants have the highest efficiency because they combine the energy extraction methods of both
combustion turbine and steam cycle systems. Efficiencies as high as 58 percent have been reported (Woodruff 1998).
Only the efficiency of the second stage (which is a steam cycle) is affected by cooling water temperatures. Therefore,
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§ 316(b) Phase II TDD Energy Penalties of Cooling Towers
for the purposes of this analysis, the energy penalty for combined cycle plants is applicable only to the energy output
of the steam plant component, which is generally reported to be approximately one-third of the overall combined-cycle
plant energy output.
5.3 TURBINE EFFICIENCY ENERGY PENALTY
5.3.1 Effect of Turbine Exhaust Pressure
The temperature of the cooling water (or air in air-cooled systems) entering the steam cycle condensers affects the
exhaust pressure at the outlet of the turbine. In general, a lower cooling water or air temperature at the condenser inlet
will result in a lower turbine exhaust pressure. Note that for a simple steam turbine, the available energy is equal to
the difference in the enthalpy of the inlet steam and the combined enthalpy of the steam and condensed moisture at the
turbine outlet. A reduction in the outlet steam pressure results in a lower outlet steam enthalpy. A reduction in the
enthalpy of the turbine exhaust steam, in combination with an increase in the partial condensation of the steam, results
in an increase in the efficiency of the turbine system. Of course, not all of this energy is converted to the torque energy
(work) that is available to turn the generator, since steam and heat flow through the turbine systems is complex with
various losses and returns throughout the system.
The turbine efficiency energy penalty as described below rises and drops in direct response to the temperature of the
cooling water (or air in air-cooled systems) delivered to the steam plant condenser. As a result, it tends to peak during
the summer and may be substantially diminished or not exist at all during other parts of the year.
The design and operation of the steam condensing system can also affect the system efficiency. In general, design and
operational changes that improve system efficiency such as greater condenser surface areas and coolant flow rates will
tend to result in an increase in the economic costs and potentially the environmental detriments of the system. Thus,
the design and operation of individual systems can differ depending on financial decisions and other site-specific
conditions. Consideration of such site-specific design variations is beyond the scope of this evaluation. Therefore,
conditions that represent a typical, or average, system derived from available information for each technology will be
used. However, regional and annual differences in cooling fluid temperatures are considered. Where uncertainty exists,
a conservative estimate is used. In this context, conservative means the penalty estimate is biased toward a higher value.
Literature sources indicate that condenser inlet temperatures of 55 °F and 95 °F will produce turbine exhaust pressures
of 1.5 and 3.5 inches Hg, respectively, in a typical surface condenser (Woodruff 1998). If the turbine steam inlet
conditions remain constant, lower turbine exhaust pressures will result in greater changes in steam enthalpy between
the turbine inlet and outlet. This in turn will result in higher available energy and higher turbine efficiencies.
The lower outlet pressures can also result in the formation of condensed liquid water within the low pressure end of the
turbine. Note that liquid water has a significantly lower enthalpy value which, based on enthalpy alone, should result
in even greater turbine efficiencies. However, the physical effects of moisture in the turbines can cause damage to the
turbine blades and can result in lower efficiencies than would be expected based on enthalpy data alone. This damage
and lower efficiency is due to the fact that the moisture does not follow the steam path and impinges upon the turbine
blades. More importantly, as the pressure in the turbine drops, the steam volume increases. While the turbines are
designed to accommodate this increase in volume through a progressive increase in the cross-sectional area, economic
considerations tend to limit the size increase such that the turbine cannot fully accommodate the expansion that occurs
at very low exhaust pressures.
Thus, for typical turbines, as the exhaust pressure drops below a certain level, the increase in the volume of the steam
is not fully accommodated by the turbine geometry, resulting in an increase in steam velocity near the turbine exit. This
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§ 316(b) Phase II TDD Energy Penalties of Cooling Towers
increase in steam velocity results in the conversion of a portion of the available steam energy to kinetic energy, thus
reducing the energy that could otherwise be available to drive the turbine. Note that kinetic energy is proportional to
the square of the velocity. Consequently, as the steam velocity increases, the resultant progressive reduction in available
energy tends to offset the gains in available energy that would result from the greater enthalpy changes due to the
reduced pressure. Thus, the expansion of the steam within the turbine and the formation of condensed moisture
establishes a practical lower limit for turbine exhaust pressures, reducing the efficiency advantage of even lower
condenser surface temperatures particularly at higher turbine steam loading rates. As can be seen in the turbine
performance curves presented below, this reduction in efficiency at lower exhaust pressures is most pronounced at
higher turbine steam loading rates. This is due to the fact that higher steam loading rates will produce proportionately
higher turbine exit velocities.
Attachment B presents several graphs showing the change in heat rate resulting from differences in the turbine exhaust
pressure at a nuclear power plant, a fossil fueled power plant, and a combined-cycle power plant (steam portion). The
first graph (Attachment B-l) is for a GE turbine and was submitted by the industry in support of an analysis for a
nuclear power plant. The second graph (Attachment B-2) is from a steam turbine technical manual and is for a turbine
operating at steam temperatures and pressures consistent with a sub-critical fossil fuel plant (2,400 psig, 1,000 °F).
The third graph (Attachment B-3) is from an engineering report analyzing operational considerations and design of
modifications to a cooling system for a combined-cycle power plant.
The changes in heat rate shown in the graphs can be converted to changes in turbine efficiency using Equation 1.
Several curves on each graph show that the degree of the change (slope of the curve) decreases with increasing loads.
Note that the amount of electricity being generated will also vary with the steam loading rates such that the more
pronounced reduction in efficiency at lower steam loading rates applies to a reduced power output. The curves also
indicate that, at higher steam loads, the plant efficiency optimizes at an exhaust pressure of approximately 1.5 inches
Hg. At lower exhaust pressures the effect of increased steam velocities actually results in a reduction in overall
efficiency. The graphs in Attachment B will serve as the basis for estimating the energy penalty for each type of
facility.
Since the turbine efficiency varies with the steam loading rate, it is important to relate the steam loading rates to typical
operating conditions. It is apparent from the heat rate curves in Attachment B that peak loading, particularly if the
exhaust pressure is close to 1.5 inches Hg, presents the most efficient and desirable operating condition. Obviously,
during peak loading periods, all turbines will be operating near the maximum steam loading rates and the energy penalty
derived from the maximum loading curve would apply. It is also reasonable to assume that power plants that operate
as base load facilities will operate near maximum load for a majority of the time they are operating. However, there
will be times when the power plant is not operating at peak capacity. One measure of this is the capacity factor, which
is the ratio of the average load on the plant over a given period to its total capacity. For example, if a 200 MW plant
operates, on average, at 50 percent of capacity (producing an average of 100 MW when operating) over a year, then
its capacity factor would be 50 percent.
The average capacity factor for nuclear power plants in the U.S. has been improving steadily and recently has been
reported to be approximately 89 percent. This suggests that for nuclear power plants, the majority appear to be
operating near capacity most of the time. Therefore, use of the energy penalty factors derived from the maximum load
curves for nuclear power plants is reasonably valid. In 1998, utility coal plants operated at an average capacity of 69
percent (DOE 2000). Therefore, use of the energy penalty values derived from the 67 percent load curves would appear
to be more appropriate for fossil-fuel plants. Capacity factors for combined-cycle plants tend to be lower than coal-
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§ 316(b) Phase II TDD Energy Penalties of Cooling Towers
fired plants and use of the energy penalty values derived from the 67 percent load curves rather than the 100 percent
load curves would be appropriate.
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§ 316(b) Phase II TDD
Energy Penalties of Cooling Towers
5.3.2 Estimated Changes in Turbine Efficiency
Table 5-6 below presents a summary of steam plant turbine inlet operating conditions for various types of steam plants
described in literature. EPA performed a rudimentary estimation of the theoretical energy penalty based on steam
enthalpy data using turbine inlet conditions similar to those shown in Table 5-6. EPA found that the theoretical values
were similar to the changes in plant efficiency derived from the changes in heat rate shown in Attachment B. The
theoretical calculations indicated that the energy penalties for the two different types of fossil fuel plants (sub-critical
and super-critical) were similar in value, with the sub-critical plant having the larger penalty. Since the two types of
fossil fuel plants had similar penalty values, only one was selected for use in the analysis in order to simplify the
analysis. The type of plant with the greater penalty value (i.e., sub-critical fossil fuel) was selected as representative
of both types.
Table 5-6: Summary of Steam Plant Operating Conditions from Various Sources
System Type
Fossil Fuel - Sub-critical
Recirculating Boiler
Fossil Fuel - Super-critical
Once-through Boiler
Nuclear
Combined Cycle
Fossil Fuel Ranges
Inlet Temp. /
Pressure
Not Given /
2,415 psia
1,000 °F /
3,515 psia
595 °F /
900 psia
Gas - 2,400 °F
Steam - 900 °F
900-1,000 °F /
1,800-3,600
psia
Outlet
Pressure
1.5 In. Hg
Not Given
2.5 In. Hg
Not Given
1.0-4.5 In
Hg
Comments
Large Plants (>500MW)
have three (high, med, low)
pressure turbines. Reheated
boiler feed water is 540 °F.
Plants have two (high, low)
pressure turbines with low
pressure turbine data at left.
Reheated boiler feed water
is 464 °F.
Operating efficiency ranges
from 45-53%
Outlet pressures can be
even higher with high
cooling water temperatures
or air cooled condensers.
Source
Kirk-Othmer 1997
Kirk-Othmer 1997
Kirk-Othmer 1997
www.greentie.org
Woodruff 1998.
The three turbine performance curve graphs in Attachment B present the change in heat rate from which changes in
plant efficiency were calculated. The change in heat rate value for several points along each curve was determined and
then converted to changes in efficiency using Equation 1. The calculated efficiency values derived from the Attachment
B graphs representing the 100 percent or maximum steam load and the 67 percent steam load conditions have been
plotted in Figure 1. Curves were then fitted to these data to obtain equations that can be used to estimate energy
penalties. Figure 1 establishes the energy efficiency and turbine exhaust pressure relationship. The next step is to relate
the turbine exhaust pressure to ambient conditions and to determine ambient conditions for selected locations.
Note that for fossil fuel plants the energy penalty affects mostly the amount of fuel used, since operating conditions can
be modified, within limits, to offset the penalty. However, the same is not true for nuclear plants, which are constrained
by the limitations of the reactor system.
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§ 316(b) Phase II TDD
Energy Penalties of Cooling Towers
Figure 1
Plot of Various Turbine Exhaust Pressure Correction Curves
for 100% and 67% Steam Loads
15.0%
13.0%
11.0%
(0
O 9.0%
I
C 7.0%
O)
c
5.0%
O
+j
£J
a)
a.
3.0%
1.0%
-1.0%
-3.0% -I
Nuclear (67% Load)
V=-0.0013x3+ 0.0169x2-0.0286x+ 0.0098
R2= 0.9982
Nuclear (100% Load)
y =-0.0006X3 + 0.0099X2 - 0.0208X + 0.0111
= u.yyy/
Fossil Fuel (67% Load)
y = 0.0063X2- 0.004x- 0.0062
.9928
Combined Cycle (67% Load)
y=-0.0004x3 + 0.0082x2-0.016x+d.0033
R2= 0.9987
Fossil Fuel (100% Load)
v2.
.0081x"-0.016x+d.0078
R2= 0.9983
ined C\
Combined Cycle (100% Load)
y= -O.OOOSx3 + 0.0062X2- 0.0154x+ 0.0084
R2= 0.9999
Exhaust Pressure - Inches Hg
Fossil Fuel (100% Load)
Nuclear (67% Load)
• Nuclear (100% Load)
x Fossil Fuel (67% Load)
A Combined Cycle (100% Load)
• Combined Cycle (67% Load)
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§ 316(b) Phase II TDD
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Figure 2
Surface Condenser Cooling Water Inlet Temperature and Steam Pressure Relationship
40
50
60 70
Condenser Inlet Temperature
(Degree F)
80
90
100
i Exhaust Pressure
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§ 316(b) Phase II TDD Energy Penalties of Cooling Towers
.3.3 Relationship of Condenser Cooling Water (or Air) Temperature to Steam Side Pressure
for Different Cooling System Types and Operating Conditions
<» Surface Condensers
Both once-through and wet cooling towers use surface condensers. As noted previously, condenser inlet temperatures
of 55 °F and 95 °F will produce turbine exhaust pressures of 1.5 and 3.5 inches Hg, respectively. Additionally, data
from the Calvert Cliffs nuclear power plant showed an exhaust pressure of 2.0 inches Hg at a cooling water temperature
of 70 °F. Figure 2 provides a plot of these data which, even though they are from two sources, appear to be consistent.
A curve was fitted to these data and was used as the basis for estimating the turbine exhaust pressure for different
surface condenser cooling water inlet temperatures. Note that this methodology is based on empirical data that
simplifies the relationship between turbine exhaust pressure and condenser inlet temperature, which would otherwise
require more complex heat exchange calculations. Those calculations, however, would require numerous assumptions,
the selection of which may produce a different curve but with a similar general relationship.
<» Once-through Systems
For once-through cooling systems, the steam cycle condenser cooling water inlet temperature is also the temperature
of the source water. Note that the outlet temperature of the cooling water is typically 15 - 20 °F higher than the inlet
temperature. This difference is referred to as the "range." The practical limit of the outlet temperature is approximately
100 °F, since many NPDES permits have limitations in the vicinity of 102 - 105 °F . This does not appear to present
a problem, since the maximum monthly average surface water temperature at Jacksonville, Florida (selected by EPA
as representing warmer U.S. surface waters) was 83.5 °F which would, using the range values above, result in an
effluent temperature of 98.5 - 103.5 °F. To gauge the turbine efficiency energy penalty for once-through cooling
systems, the temperature of the source water must be known. These temperatures will vary with location and time of
year and estimates for several selected locations are presented in Table 5-7 below.
V Wet Cooling Towers
For wet cooling towers, the temperature of the cooling tower outlet is the same as the condenser cooling water inlet
temperature. The performance of the cooling tower in terms of the temperature of the cooling tower outlet is a function
of the wet bulb temperature of the ambient air and the tower type, size, design, and operation. The wet bulb
temperature is a function of the ambient air temperature and the humidity. Wet bulb thermometers were historically
used to estimate relative humidity and consist of a standard thermometer with the bulb encircled with a wet piece of
cloth. Thus, the temperature read from a wet bulb thermometer includes the cooling effect of water evaporation.
Of all of the tower design parameters, the temperature difference between the wet bulb temperature and the cooling
tower outlet (referred to as the "approach") is the most useful in estimating tower performance. The wet cooling tower
cooling water outlet temperature of the systems that were used in the analysis for the regulatory options had a design
approach of 10 °F. Note that the design approach value is equal to the difference between the tower cooling water outlet
temperature and the ambient wet bulb temperature only at the design wet bulb temperature. The actual approach value
at wet bulb temperatures other than the design value will vary as described below.
The selection of a 10 °F design approach is based on the data in Attachment C for recently constructed towers.
Moreover, a 10 °F approach is considered conservative. As can be seen in Attachment D, a plot of the tower size factor
versus the approach shows that a 10 °F approach has a tower size factor of 1.5. The approach is a key factor in sizing
towers and has significant cost implications. The trade-off between selecting a small approach versus a higher value
is a trade-off between greater capital cost investment versus lower potential energy production. In states where the rates
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§ 316(b) Phase II TDD Energy Penalties of Cooling Towers
of return on energy investments are fixed (say between 12% and 15%), the higher the capital investment, the higher the
return.
For the wet cooling towers used in this analysis, the steam cycle condenser inlet temperature is set equal to the ambient
air wet bulb temperature for the location plus the estimated approach value. A design approach value of 10 °F was
selected as the common design value for all locations. However, this value is only applicable to instances when the
ambient wet bulb temperature is equal to the design wet bulb temperature. In this analysis, the design wet bulb
temperature was selected as the 1 percent exceedence value for the specific selected locations.
Attachment E provides a graph showing the relationship between different ambient wet bulb temperatures and the
corresponding approach for a "typical" wet tower. The graph shows that as the ambient wet bulb temperature
decreases, the approach value increases. The graph in Attachment E was used as the basis for estimating the change
in the approach value as the ambient wet bulb temperature changes from the design value for each location. Differences
in the location-specific design wet bulb temperature were incorporated by fitting a second order polynomial equation
to the data in this graph. The equation was then modified by adjusting the intercept value such that the approach was
equal to 10 °F when the wet bulb temperature was equal to the design 1 percent wet bulb temperature for the selected
location. The location-specific equations were then used to estimate the condenser inlet temperatures that correspond
to the estimated monthly values for wet bulb temperatures at the selected locations.
*** Air Cooled Condensers
Air cooled condensers reject heat by conducting it directly from the condensing steam to the ambient air by forcing the
air over the heat conducting surface. No evaporation of water is involved. Thus, for air cooled condensers, the
condenser performance with regard to turbine exhaust pressure is directly related to the ambient (dry bulb) air
temperature, as well as to the condenser design and operating conditions. Note that dry bulb temperature is the same
as the standard ambient air temperature with which most people are familiar. Figure 3 presents a plot of the design
ambient air temperature and corresponding turbine exhaust pressure for air cooled condensers recently installed by a
major cooling system manufacturer (GEA Power Cooling Systems, Inc.). An analysis of the multiple facility data in
Figure 3 did not find any trends with respect to plant capacity, location, or age that could justify the separation of these
data into subgroups. Three facilities that had very large differences (i.e., >80 °F) in the design dry bulb temperature
compared to the temperature of saturated steam at the exhaust pressure were deleted from the data set used in Figure
3.
A review of the design temperatures indicated that the design temperatures did not always correspond to annual
temperature extremes of the location of the plant as might be expected. Thus, it appears that the selection of design
values for each application included economic considerations. EPA concluded that these design data represent the
range of condenser performance at different temperatures and design conditions. A curve was fitted to the entire set
of data to serve as a reasonable means of estimating the relationship of turbine exhaust pressure to different ambient
air (dry bulb) temperatures. To validate this approach, condenser performance data for a power plant from an
engineering contractor report (Litton, no date) was also plotted. This single plant data produced a flatter curve than
the multi-facility plot. In other words, the multi-facility curve predicts a greater increase in turbine exhaust pressure
as the dry bulb temperature increases. Therefore, the multi-facility curve was selected as a conservative estimation of
the relationship between ambient air temperatures and the turbine exhaust pressure. Note that in the case of air cooled
condensers, the turbine exhaust steam pressure includes values above 3.5 inches Hg.
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§ 316(b) Phase II TDD
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R
20
Figure 3
Design Dry Bulb and Design Exhaust Pressure for
Recently Installed Air Cooled Condensers
40
60 80 100
Design Dry Bulb Temperature Degree F
• Muli-Facility Design Data • Single Unit Data
120
140
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Energy Penalties of Cooling Towers
egional and Seasonal Data
As noted above, both the source water temperature for once-through cooling systems and the ambient wet bulb and dry
bulb temperatures for cooling towers will vary with location and time of year. To estimate average annual energy
penalties, EPA sought data to estimate representative monthly values for selected locations. Since plant-specific
temperature data may not be available or practical, the conditions for selected locations in different regions are used
as examples of the range of possibilities. These four regions include Northeast (Boston, MA), Southeast (Jacksonville,
FL), Midwest (Chicago, IL) and Northwest (Seattle, WA). The Southwest Region of the US was not included, since
there generally are few once-through systems using surface water in this region.
Table 5-7 presents monthly average coastal water temperatures at the four selected locations. Since the water
temperatures remain fairly constant over short periods of time, these data are considered as representative for each
month.
Table 5-7: Monthly Average Coastal Water Temperatures (°F)
Location
Boston, MAa
Jacksonville, FLa
Chicago, ILb
Seattle, WAa
Jan
40
57
39
47
Feb
36
56
36
46
Mar
41
61
34
46
Apr
47
69.5
36
48.5
May
56
75.5
37
50.5
Jun
62
80.5
48
53.5
Jul
64.5
83.5
61
55.5
Aug
68
83
68
56
Sep
64.5
82.5
70
55.5
Oct
57
75
63
53.5
Nov
51
67
50
51
Dec
42
60
45
49
a Source: NOAA Coastal Water Temperature Guides, (www.nodc.noaa.gov/dsdt/cwtg).
b Source: Estimate from multi-year plot "Great Lakes Average GLSEA Surface Water Temperature"
(http ://coastwatch. glerl. noaa. gov/statistics/).
<» Wet and Dry Bulb Temperatures
Table 5-8 presents design wet bulb temperatures (provided by a cooling system vendor) for the selected locations as
the wet bulb temperature that ambient conditions will equal or exceed at selected percent of time (June through
September) values. Note that 1 percent represents a period of 29.3 hours. These data, however, represent relatively
short periods of time and do not provide any insight as to how the temperatures vary throughout the year. The Agency
obtained the Engineering Weather Data Published by the National Climatic Data Center to provide monthly wet and
dry bulb temperatures. In this data set, wet bulb temperatures were not summarized on a monthly basis, but rather were
presented as the average values for different dry bulb temperature ranges along with the average number of hours
reported for each range during each month. These hours were further divided into 8-hour periods (midnight to SAM,
SAM to 4PM, and 4PM to midnight).
Unlike surface water temperature, which tends to change more slowly, the wet bulb and dry bulb temperatures can vary
significantly throughout each day and especially from day-to-day. Thus, selecting the temperature to represent the
entire month requires some consideration of this variation. The use of daily maximum values would tend to
overestimate the overall energy penalty and conversely, the use of 24-hour averages may underestimate the penalty,
since the peak power production period is generally during the day.
5-17
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§ 316(b) Phase II TDD
Energy Penalties of Cooling Towers
Since the power demand and ambient wet bulb temperatures tend to peak during the daytime, a time- weighted average
of the hourly wet bulb and dry bulb temperatures during the daytime period between SAM and 4PM was selected as
the best method of estimating the ambient wet bulb and dry bulb temperature values to be used in the analysis. The
SAM - 4PM time-weighted average values for wet bulb and dry bulb temperatures were selected as a reasonable
compromise between using daily maximum values and 24-hour averages. Table 5-9 presents a summary of the time-
weighted wet bulb and dry bulb temperatures for each month for the selected locations. Note that the highest monthly
SAM - 4PM time-weighted average tends to correspond well with the 15 percent exceedence design values. The 15
percent values represent a time period of approximately 18 days which are not necessarily consecutive.
Table 5-8: Design Wet Bulb Temperature Data for Selected Locations
Location
Boston, MA
Jacksonville, FL
Chicago, IL
Seattle, WA
Wet Bulb Temp (°F)
% Time Exceeding
1%
76
80
78
66
5%
73
79
75
63
15%
70
77
72
60
Corresponding Cooling Tower Outlet
Temperature (°F)
% Time Exceeding
1%
86
90
88
76
5%
83
89
85
73
15%
80
87
82
70
Source: www.deltacooling.com
Table 5-9: Time- Weighted Averages for Eight- Hour Period from Sam to 4pm (°F)
Location
Boston
Jacksonville
Chicago
Seattle
Wet Bulb
Dry Bulb
Wet Bulb
Dry Bulb
Wet Bulb
Dry Bulb
Wet Bulb
Dry Bulb
Jan
27.5
33.0
52.9
59.8
23.3
27.6
39.4
44.3
Feb
29.3
35.3
55.3
63.6
27.0
31.8
41.8
47.8
Mar
36.3
43.2
59.6
70.3
37.2
43.9
44.2
51.5
Apr
44.6
53.5
64.5
76.6
46.6
55.7
47.2
55.6
May
53.9
63.8
70.3
83.0
56.6
67.9
52.0
61.8
Jun
62.7
73.9
75.1
87.2
64.9
77.4
56.0
67.2
Jul
67.9
80.0
77.1
89.3
69.8
82.5
59.2
71.6
Aug
67.4
78.2
77.1
88.1
69.3
80.6
59.6
71.6
Sep
61.5
70.4
75.1
85.1
62.2
72.4
57.2
67.3
Oct
52.0
59.9
69.1
77.8
51.2
59.9
51.0
58.1
Nov
42.6
49.5
63.1
70.6
39.1
45.0
44.0
49.0
Dec Design
1%
32.6
38.4
55.9
62.6
27.9
32.2
39.7
44.3
74.0
88.0
79.0
93.0
76.0
89.0
65.0
82.0
5-18
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§ 316(b) Phase II TDD Energy Penalties of Cooling Towers
5.3.4 Calculation of Energy Penalty
Since the energy penalty will vary over time as ambient climatic and source water temperatures vary, the calculation
of the total annual energy penalty for a chosen location would best be performed by combining (integrating) the results
of individual calculations performed on a periodic basis. For this analysis, a monthly basis was chosen.
The estimated monthly turbine exhaust pressure values for alternative cooling system scenarios were derived using the
curves in Figures 2 and 3 in conjunction with the monthly temperature values in Tables 5-7 and 5-9. These turbine
exhaust pressure values were then used to estimate the associated change in turbine efficiency using the equations from
Figure 1. EPA then calculated the energy penalty for each month. Annual values were calculated by averaging the 12
monthly values.
Tables 5-10 and 5-11 present a summary of the calculated annual average energy penalty values for steam rates of 100
percent and 67 percent of maximum load. These values can be applied directly to the power plant output to determine
economic and other impacts. In other words, an energy penalty of 2 percent indicates that the plant output power would
be reduced by 2 percent. In addition, Tables 5-10 and 5-11 include the maximum turbine energy penalty associated
with maximum design conditions such as once-through systems drawing water at the highest monthly average, and wet
towers and air cooled condensers operating in air with a wet bulb and dry bulb temperature at the 1 percent exceedence
level. EPA notes that the maximum design values result from using the maximum monthly water temperatures from
Table 5-7 and the 1% percent exceedence wet bulb and dry bulb temperatures from Table 5-8.
EPA notes that the penalties presented in Tables 5-10 and 5-11 do not comprise the total energy penalties (which
incorporate all three components of energy penalties: turbine efficiency penalty, fan energy requirements, and pumping
energy usage) as a percent of power output. The total energy penalties are presented in section 5.1 above. The tables
below only present the turbine efficiency penalty. Section 5.4 presents the fan and pumping components of the energy
penalty.
5-19
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§ 316(b) Phase II TDD
Energy Penalties of Cooling Towers
Table 5-10: Calculated Energy Penalties
^ocation
Boston
Tacksonville
Chicago
Seattle
Average
Cooling Type
Wet
Dry
Dry
Wet
Dry
Dry
Wet
Dry
Dry
Wet
Dry
Dry
Wet
Dry
Dry
Tower vs
Tower vs.
Tower vs.
Tower vs
Tower vs.
Tower vs.
Tower vs
Tower vs.
Tower vs.
Tower vs
Tower vs.
Tower vs.
Tower vs
Tower vs.
Tower vs.
for the Turbine Efficiency Component at 100
Percent Nuclear
Maximum Maximum
Load Design
Once-through
Once-through
Wet Tower
Once-through
Once-through
Wet Tower
Once-through
Once-through
Wet Tower
Once-through
Once-through
Wet Tower
Once-through
Once-through
Wet Tower
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
1.25%
9.22%
7.96%
0.71%
9.86%
9.14%
1.39%
9.47%
8.08%
0.77%
7.60%
6.83%
1.03%
9.04%
8.00%
Nuclear
Annual
Average
0.37%
2.85%
2.48%
0.54%
6.21%
5.68%
0.42%
3.09%
2.67%
0.29%
2.63%
2.34%
0.40%
3.70%
3.29%
Recent of
Maximum Steam Load;
Combined Combined Fossil Fuel
Cycle Cycle Maximum
Maximum Annual Design
Design Average
0.23%
2.04%
1.81%
0.14%
2.30%
2.16%
0.26%
2.12%
1.85%
0.12%
1.61%
1.48%
0.19%
2.02%
1.83%
0.05%
0.55%
0.50%
0.10%
1.35%
1.25%
0.05%
0.60%
0.55%
0.03%
0.49%
0.45%
0.06%
0.75%
0.69%
1
7
6
0
8
7
1
7
6
0
6
5
0
7
6
09%
76%
66%
61%
22%
61%
21%
96%
75%
70%
46%
76%
90%
60%
70%
Fossil Fuel
Annual
Average
0.35%
2.48%
2.13%
0.38%
5.16%
4.78%
0.40%
2.68%
2.28%
0.28%
2.30%
2.02%
0.35%
3.15%
2.80%
Note: See Section 5.1 for the total energy penalties. This table presents only the turbine component of the total energy penalty.
5-20
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§ 316(b) Phase II TDD
Energy Penalties of Cooling Towers
Table 5-11: Calculated Energy Penalties for the
^ocation
Boston
Tacksonville
Chicago
Seattle
Average
Cooling Type
Wet
Dry
Dry
Wet
Dry
Dry
Wet
Dry
Dry
Wet
Dry
Dry
Wet
Dry
Dry
Tower vs
Tower vs.
Tower vs.
Tower vs
Tower vs.
Tower vs.
Tower vs
Tower vs.
Tower vs.
Tower vs
Tower vs.
Tower vs.
Tower vs
Tower vs.
Tower vs.
Turbine Efficiency Component at 67% Recent
Load
of Maximum Steam i
Percent Nuclear Nuclear Combined Combined Fossil Fuel Fossil Fuel
Maximum Maximum Annual Cycle Cycle Maximum Annual
Load Design Average Maximum Annual Design Average
Design Average
Once-through
Once-through
Wet Tower
Once-through
Once-through
Wet Tower
Once-through
Once-through
Wet Tower
Once-through
Once-through
Wet Tower
Once-through
Once-through
Wet Tower
67%
67%
67%
67%
67%
67%
67%
67%
67%
67%
67%
67%
67%
67%
67%
2.32%
13.82%
11.50%
1.22%
13.61%
12.39%
2.53%
14.03%
11.50%
1.60%
12.16%
10.56%
1.92%
13.41%
11.49%
0.73%
4.96%
4.23%
1.03%
9.63%
8.60%
0.98%
5.39%
4.41%
0.67%
4.60%
3.93%
0.85%
6.14%
5.29%
0.42%
3.20%
2.78%
0.24%
3.50%
3.27%
0.47%
3.30%
2.83%
0.27%
2.60%
2.33%
0.35%
3.15%
2.80%
0.14%
0.98%
0.84%
0.18%
2.14%
1.96%
0.16%
1.07%
0.91%
0.11%
0.90%
0.79%
0.15%
1.27%
1.12%
2
15
13
1
16
15
2
15
13
04%
15%
11%
08%
96%
88%
23%
67%
44%
1.50%
12
10
1
15
13
31%
81%
71%
02%
31%
0.88%
4.69%
3.81%
0.93%
10.06%
9.14%
1.02%
5.30%
4.27%
0.74%
4.50%
3.75%
0.89%
6.14%
5.24%
Note: See Section 5.1 for the total energy penalties. This table presents only the turbine component of the total energy penalty.
5-21
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§ 316(b) Phase II TDD Energy Penalties of Cooling Towers
5.4 ENERGY PENALTY ASSOCIATED WITH COOLING SYSTEM ENERGY REQUIREMENTS
This analysis is presented to evaluate the energy requirements associated with the operation of the alternative types of
cooling systems. As noted previously, the reductions in energy output resulting from the energy required to operate the
cooling system equipment are often referred to as parasitic losses. In evaluating this component of the energy penalty,
it is the differences between the parasitic losses of the alternative systems that are important. In general, the costs
associated with the cooling system energy requirements have been included within the annual O&M cost values for
certain regulatory options developed using the methodologies presented in Chapter 2 of this document. Thus, the costs
of the cooling system operating energy requirements do not need to be factored into the overall energy penalty cost
analysis as a separate value.
Alternative cooling systems can create additional energy demands primarily through the use of fans and pumps. There
are other energy demands such as treatment of tower blowdown, but these are insignificant compared to the pump and
fan requirements and will not be included here. Some seasonal variation may be expected due to reduced requirements
for cooling media flow volume during colder periods. These reduced requirements can include reduced cooling water
pumping for once-through systems and reduced fan energy requirements for both wet and dry towers. However, no
adjustments were made concerning the potential seasonal variations in cooling water pumping. The seasonal variation
in fan power requirements is accounted for in this evaluation by applying an annual fan usage rate. The pumping
energy estimates are calculated using a selected cooling water flow rate of 100,000 gpm (223 cfs).
5.4.1 Fan Power Requirements
* Wet Towers
In the reference Cooling Tower Technology (Burger 1995), several examples are provided for cooling towers with flow
rates of 20,000 gpm using 4 cells with either 75 (example #1) or 100 Hp (example #2) fans each. The primary
difference between these two examples is that the tower with the higher fan power requirement has an approach of 5
°F compared to 11 °F for the tower with the lower fan power requirement. Using an electric motor efficiency of 92
percent and a fan usage factor of 93 percent (Fleming 2001), the resulting fan electric power requirements are equal
to 0.236 MW and 0.314 MW for the four cells with 75 and 100 Hp fan motors, respectively. These example towers
both had a heat load of 150 million BTU/hr. Table 5-14 provides the percent of power output penalty based on
equivalent plant capacities derived using the heat rejection factors described below. Note that fan gear efficiency values
are not applicable because they do not affect the fan motor power rating or the amount of electricity required to operate
the fan motors.
A third example was provided in vendor-supplied data (Fleming 2001), in which a cooling tower with a cooling water
flow rate of 243,000 gpm had a total fan motor capacity brake-Hp of 250 for each of 12 cells. This wet tower had a
design temperature range of 15 °F and an approach of 10 °F. The percent of power output turbine penalty shown in
Tables 5-10 and 5-11 is also based on equivalent plant capacities derived using the heat rejection factors described
below.
A fourth example is a cross-flow cooling tower for a 35 MW coal-fired plant in Iowa (Litton, no date). In this example,
the wet tower consists of two cells with one 150 Hp fan each, with a cooling water flow rate of 30,000 gpm. This wet
tower had a design temperature range of 16 °F, an approach of 12 °F, and wet bulb temperature of 78 °F. The
calculated energy penalty in this example is 0.67 percent.
5-22
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§ 316(b) Phase II TDD
Energy Penalties of Cooling Towers
Example #2, which has the smallest approach value, represents the high end of the range of calculated wet tower fan
energy penalties presented in Table 5-12. Note that smaller approach values correspond to larger, more expensive (both
in capital and O&M costs) towers. Since the fossil fuel plant penalty value for example #4, which is based mostly on
empirical data, is just below the fossil fuel penalty calculated for example #2, EPA has chosen the calculated values
for example #2 as representing a conservative estimate for the wet tower fan energy penalty.
EPA notes that the penalties presented in Tables 5-12 do not comprise the total energy penalty (which incorporates all
three components of energy penalties: turbine efficiency penalty, fan energy requirements, and pumping energy usage)
as a percent of power output. The total energy penalties are presented in section 3.1 above. The table below only
presents the fan component of the penalty.
Example
Plant
#1
#2
#3
#4
Table 5-12
Range/ Flow
Approach (gpm)
(Degree F)
15/11 20,000
15/5 20,000
15/10 243,000
16/12 30,000
: Wet Tower Fan Power
Fan Power
Rating
(Hp)
300
400
3,000
300.0
Fan Power
Required
(MW)
0.236
0.314
2.357
0.236
Energy Penalty
Plant Type Plant
Capacity
(MW)
Nuclear
Fossil Fuel
Comb. Cycle
Nuclear
Fossil Fuel
Comb. Cycle
Nuclear
Fossil Fuel
Comb. Cycle
Fossil Fuel
35
43
130
35
43
130
420
525
1574
35
Percent of
Output
(%)
0.68%
0.55%
0.18%
0.91%
0.73%
0.24%
0.56%
0.45%
0.15%
0.67%
Note: See Section 5.1 for the total energy penalties. This table presents only the fan component of the
total energy penalty.
<» Air Cooled Condensers
Air cooled condensers require greater air flow than recirculating wet towers because they cannot rely on evaporative
heat transfer. The fan power requirements are generally greater than those needed by wet towers by a factor of 3 to
4 (Tallon 2001). While the fan power requirements can be substantial, at least a portion of this increase over wet
cooling systems is offset by the elimination of the pumping energy requirements associated with wet cooling systems
described below.
The El Dorado power plant in Boulder, Nevada which was visited by EPA is a combined-cycle plant that uses air cooled
condensers due to the lack of sufficient water resources. This facility is located in a relatively hot section of the U.S.
Because the plant has a relatively low design temperature (67 °F) in a hot environment, it should be considered as
representative of a conservative situation with respect to the energy requirements for operating fans in air cooled
5-23
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§ 316(b) Phase II TDD Energy Penalties of Cooling Towers
condensers. The steam portion of the plant has a capacity of 150 MW (1.1 million Ib/hr steam flow). The air cooled
condensers consist of 30 cells with a 200 Hp fan each. A fan motor efficiency of 92 percent is assumed. Each fan has
two operating speeds, with the low speed consuming 20 percent of the fan motor power rating.
The facility manager provided estimates of the proportion of time that the fans were operated at low or full speed during
different portions of the year (Tatar 2001). Factoring in the time proportions and the corresponding power requirements
results in an overall annual fan power factor of 72 percent for this facility. In other words, over a one year period, the
fan power requirement will average 75 percent of the fan motor power rating. A comparison of the climatic data for
Las Vegas (located nearby) and Jacksonville, Florida shows that the Jacksonville mean maximum temperature values
were slightly warmer in the winter and slightly cooler in the summer. Adjustments in the annual fan power factor
calculations to address Jacksonville's slightly warmer winter months resulted in a projected annual fan power factor
of 77 percent. EPA chose a factor of 75 percent as representative of warmer regions of the U.S. Due to lack of
available operational data for other locations, this value is used for facilities throughout the U.S. and represents an
conservative value for the much cooler regions.
Prior to applying this factor, the resulting maximum energy penalty during warmer months is 3.2 percent for the steam
portion only. This value is the maximum instantaneous penalty that would be experienced during high temperature
conditions. When the annual fan power factor of 75 percent is applied, the annual fan energy penalty becomes 2.4
percent of the plant power output. An engineer from an air cooled condenser manufacturer indicated that the majority
of air cooled condensers being installed today also include two-speed fans and that the 20 percent power ratio for the
low speed was the factor that they used also. In fact, some dry cooling systems, particularly those in very cold regions,
use fans with variable speed drives to provide even better operational control. Similar calculations for a waste-to-
energy plant in Spokane, Washington resulted in a maximum fan operating penalty of 2.8 percent and an annual average
of 2.1 percent using the 75 percent fan power factor. Thus, the factor of 2.4 percent selected by EPA as a conservative
annual penalty value appears valid.
5.4.2 Cooling Water Pumping Requirements
The Agency notes that it conducted the following analysis for new, "greenfield" facilities and transferred the results of
this analysis to the cooling system conversions for existing facilities considered as regulatory options for this proposal.
As discussed in Section 5.6 below, the Department of Energy (DOE) concludes in their draft energy penalty analysis
that the pumping component of the energy penalty for existing facilities may be higher than calculated herein by EPA
for new, "greenfield" facilities.
The energy requirements for cooling water pumping can be estimated by combining the flow rates and the total head
(usually given in feet of water) that must be pumped. Estimating the power requirements for the alternative cooling
systems that use water is somewhat complex in that there are several components to the total pumping head involved.
For example, a once-through system must pump water from the water source to the steam condensers, which will
include both a static head from the elevation of the source to the condenser (use of groundwater would represent an
extreme case) and friction head losses through the piping and the condenser. The pipe friction head is dependent on the
distance between the power plant and the source plus the size and number of pipes, pipe fittings, and the flow rate. The
condenser friction head loss is a function of the condenser design and flow rate.
5-24
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§ 316(b) Phase II TDD Energy Penalties of Cooling Towers
Wet cooling towers must also pump water against both a static and friction head. A power plant engineering consultant
estimated that the total pumping head at a typical once-through facility would be approximately 50 ft (Taylor 2001).
EPA performed a detailed analysis of the cooling water pumping head that would result from different combinations
of piping velocities and distances. The results of this analysis showed that the pumping head was in many scenarios
similar in value for both once-through and wet towers, and that the estimated pumping head ranged from approximately
40 to 60 feet depending on the assumed values. Since EPA's analysis produced similar values as the 50 ft pumping
head provided by the engineering consultant, this value was used in the estimation of the pumping requirements for
cooling water intakes for both once-through and wet tower systems. The following sections describe the method for
deriving these pumping head values.
*«* Friction Losses
In order to provide a point of comparison, a cooling water flow rate of 100,000 gpm (223 cfs) was used. A recently
reported general pipe sizing rule indicating that a pipe flow velocity of 5.7 fps is the optimum flow rate with regards
to the competing cost values was used as the starting point for flow velocity (Durand et al. 1999). Such a minimum
velocity is needed to prevent sediment deposition and pipe fouling. Using this criterion as a starting point, four 42-inch
steel pipes carrying 25,000 gpm each at a velocity of 5.8 fps were selected. Each pipe would have a friction head loss
of 0.358 ft/100 ft of pipe (Permutit 1961), resulting in a friction loss of 3.6 ft for every 1,000 ft of length. Since capital
costs may dictate using fewer pipes with greater pipe flow rates, two other scenarios using either three or two parallel
42-inch pipes were also evaluated. Three pipes would result in a flow rate and velocity of 33,000 gpm and 7.7 fps,
which results in a friction head loss of 6.1 ft/lOOOft. Two pipes would result in a flow rate and velocity of 50,000 gpm
and 11.6 fps, which results in a friction head loss of 12.8 ft/1000ft. The estimated 50 ft total pumping head was most
consistent with a pipe velocity of 7.7 fps (three 42-inch pipes).
The relative distances of the power plant condensers to the once-through cooling water intakes as compared to the
distance from the plant to the alternative cooling tower can be an important factor. In general, the distances that the
large volumes of cooling water must be pumped will be greater for once-through cooling systems. For this analysis, a
fixed distance of 300 ft was selected for the cooling tower. Various distances ranging from 300 ft to 3,000 ft are used
for the once-through system. The friction head was also assumed to include miscellaneous losses due to inlets, outlets,
bends, valves, etc., which can be calculated using equivalent lengths of pipe. For 42-in. steel pipe, each entrance and
long sweep elbow is equal to about 60 ft in added pipe length. For the purposes of this analysis, both systems were
assumed to have five such fittings for an added length of 300 ft. The engineering estimate of 50 ft for pumping head
was most consistent with a once-through pumping distance of approximately 1,000 ft.
Static head refers to the distance in height that the water must be pumped from the source elevation to the destination.
In the case of once-through cooling systems, this is the distance in elevation between the source water and the condenser
inlet. However, many power plants eliminate a significant portion of the static head loss by operating the condenser
piping as a siphon. This is done by installing vacuum pumps at the high point of the water loop. In EPA's analysis,
a static head of 20 ft produced a total pumping head value that was most consistent with the engineering consultant's
estimate of 50 feet.
In the case of cooling towers, static head is related to the height of the tower, and vendor data for the overall pumping
head through the tower is available. This pumping head includes both the static and dynamic heads within the tower,
5-25
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§ 316(b) Phase II TDD Energy Penalties of Cooling Towers
but was included as the static head component for the analysis. Vendor data reported a total pumping head of 25 ft for
a large cooling tower sized to handle 335,000 gpm (Fleming 2001). The tower is a counter-flow packed tower design.
Adding the condenser losses and pipe losses resulted in a total pumping head of approximately 50 feet.
*«* Condenser Losses
Condenser design data provided by a condenser manufacturer, Graham Corporation, showed condenser head losses
ranging from 21 ft of water for small condensers (cooling flow <50,000 gpm) to 41 ft for larger condensers (Hess
2001). Another source showed head losses through the tubes of a large condenser (311,000 gpm) to be approximately
9 ft of water (HES. 2001). For the purposes of this analysis, EPA estimated condenser head losses to be 20 ft of water.
For comparable systems with similar cooling water flow rates, the condenser head loss component should be the same
for both once-through systems and recirculating wet towers.
»«» Flow Rates
In general, the cooling water flow rate is a function of the heat rejection rate through the condensers and the range of
temperature between the condenser inlet and outlet. The flow rate for cooling towers is approximately 95 percent that
of once-through cooling water systems, depending on the cooling temperature range. However, cooling tower systems
also still require some pumping of make-up water. For the purposes of this analysis, the flow rates for each system will
be assumed to be essentially the same. All values used in the calculations are for a cooling water flow rate of 100,000
gpm. Values for larger and smaller systems can be factored against these values. The total pump and motor efficiency
is assumed to be equal to 70 percent.
5.5 ANALYSIS OF COOLING SYSTEM ENERGY REQUIREMENTS
This analysis evaluates the energy penalty associated with the operation of cooling system equipment for conversion
from once-through systems to wet towers and for conversion to air cooled systems by estimating the net difference in
required pumping and fan energy between the systems. This penalty can then be compared to the power output
associated with a cooling flow rate of 100,000 gpm to derive a percent of plant output figure that is a similar measure
to the turbine efficiency penalty described earlier. The power output was determined by comparing condenser heat
rejection rates for different types of systems. As noted earlier, the cost of this energy penalty component has already
been included in the alternative cooling system O&M costs discussed in Chapter 2 of this document, but was derived
independently for this analysis.
Table 5-13 shows the pumping head and energy requirements for pumping 100,000 gpm of cooling water for both once-
through and recirculating wet towers using the various piping scenario assumptions. In general, the comparison of two
types of cooling systems shows offsetting energy requirements that essentially show zero pumping penalty between
once-through and wet towers as the pumping distance for the once-through system increases to approximately 1,000
ft. In fact, it is apparent that for once-through systems with higher pipe velocities and pumping distances, more cooling
water pumping energy may be required for the once-through system than for a wet cooling tower. Thus, when
converting from once-through to recirculating wet towers, the differences in pumping energy requirements may be
relatively small.
As described above, wet towers will require additional energy to operate the fans, which results in a net increase in the
energy needed to operate the wet tower cooling system compared to once-through. Note that the average calculated
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§ 316(b) Phase II TDD Energy Penalties of Cooling Towers
pumping head across the various scenarios for once-through systems was 54 ft. This data suggests that an average
pumping head of 50 feet for once-through systems appears to be a reasonable assumption where specific data are not
available.
EPA notes that the penalties presented in Tables 5-13 and 5-14 do not comprise the total energy penalties (which
incorporate all three components of energy penalties: turbine efficiency penalty, fan energy requirements, and pumping
energy usage) as a percent of power output. The total energy penalties are presented in section 3.1 above. The tables
below only present the pumping components.
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§ 316(b) Phase II TDD
Energy Penalties of Cooling Towers
Table 5-13: Cooling Water Pumping Head and Energy for 100,000 gpm System
Cooling
System Type
Once-through
Once-through
Wet Tower
Once-through
Once-through
Wet Tower
Once-through
Once-through
Wet Tower
Once-through
Once-through
Wet Tower
Once-through
Once-through
Wet Tower
Once-through
Once-through
Wet Tower
Once-through
Once-through
Wet Tower
Once-through
Once-through
Wet Tower
Once-through
Once-through
Wet Tower
Distance Static Condenser Equiv. Pipe Friction Friction
Pumped Head Head Length velocity Loss Head
Misc. Rate
ft.
at 20' Static
300
300
at 20' Static
300
300
at 20' Static
300
300
at 20' Static
1000
300
at 20' Static
1000
300
at 20' Static
1000
300
at 20' Static
3000
300
at 20' Static
3000
300
at 20' Static
3000
300
ft. ft
Head Using 4:
20 21
25 21
Head Using 3:
20 21
25 21
Head Using 2:
20 21
25 21
Head Using 4:
20 21
25 21
Head Using 3:
20 21
25 21
Head Using 2:
20 21
25 21
Head Using 4:
20 21
25 21
Head Using 3:
20 21
25 21
Head Using 2:
20 21
25 21
Losses
ft. fps
ft/l,000ft
ft.
Total
Head
ft.
Wet Towers Versus
Once -through At 20' Static Head
Net Flow Hydraulic-
Difference Rate HP
ft gpm
HP
Brake-
Hp
Hp
Power
Required
kW
Energy
Penalty
kW
42" Pipes at 300' Length
300 5.8
300 5.8
3.6
3.6
2
2
43
48
100,000
5 100,000
1089
1216
1556
1737
1161
1296
135
42" Pipes at 300' Length
300 7.7
300 7.7
6.1
6.1
4
4
45
50
100,000
5 100,000
1127
1254
1610
1791
1201
1336
135
42" Pipes at 300' Length
300 11.6 12.8
300 11.6 12.8
42" Pipes at 1000'
300 5.8
300 5.8
42" Pipes at 1000'
300 7.7
300 7.7
42" Pipes at 1000'
Length
3.6
3.6
Length
6.1
6.1
Length
300 11.6 12.8
300 11.6 12.8
42" Pipes at 3000'
300 5.8
300 5.8
42" Pipes at 3000'
300 7.7
300 7.7
42" Pipes at 3000'
Length
3.6
3.6
Length
6.1
6.1
Length
300 11.6 12.8
300 11.6 12.8
8
8
5
2
8
4
17
8
12
2
20
4
42
8
49
54
46
48
49
50
58
54
53
48
61
50
83
54
100,000
5 100,000
100,000
2 100,000
100,000
1 100,000
100,000
-4 100,000
100,000
-5 100,000
100,000
-11 100,000
100,000
-30 100,000
1229
1355
1153
1216
1235
1254
1455
1355
1335
1216
1543
1254
2101
1355
1755
1936
1647
1737
1764
1791
2079
1936
1907
1737
2204
1791
3002
1936
1310
1444
1229
1296
1316
1336
1551
1444
1423
1296
1644
1336
2239
1444
135
67
20
-107
-127
-309
-795
Note: Wet Towers are assumed to always be at 300' distance and have the same tower pumping head of 25' in all scenarios shown.
The same flow rate of 100,000gpm (223 cfs) is used for all scenarios.
See Section 5.1 for the total energy penalties. This table presents only the pumping component of the total energy penalty.
5-28
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§ 316(b) Phase II TDD Energy Penalties of Cooling Towers
5-29
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§ 316(b) Phase II TDD Energy Penalties of Cooling Towers
*»* Cooling System Energy Requirements Penalty as Percent of Power Output
One method of estimating the capacity of a power plant associated with a given cooling flow rate is to compute the heat
rejected by the cooling system and determine the capacity that would match this rejection rate for a "typical" power
plant in each category. In order to determine the cooling system heat rejection rate, both the cooling flow (100,000
gpm) and the condenser temperature range between inlet and outlet must be estimated. In addition, the capacity that
corresponds to the power plant heat rejection rate must be determined. The heat rejection rate is directly related to the
type, design, and capacity of a power plant. The method used here was to determine the ratio of the plant capacity
divided by the heat rejection rate as measured in equivalent electric power.
An analysis of condenser cooling water flow rates, temperature ranges and power outputs for several existing nuclear
plants provided ratios of the plant output to the power equivalent of heat rejection ranging from 0.75 to 0.92. A similar
analysis for coal-fired power plants provided ratios ranging from 1.0 to 1.45. Use of a lower factor results in a lower
power plant capacity estimate and, consequently, a higher value for the energy requirement as a percent of capacity.
Therefore, EPA chose to use values near the lower end of the range observed. EPA selected ratios of 0.8 and 1.0 for
nuclear and fossil-fueled plants, respectively. The steam portion of a combined cycle plant is assumed to have a factor
similar to fossil fuel plants of 1.0. Considering that this applies to only one-third of the total plant output, the overall
factor for combined-cycle plants is estimated to be 3.0.
In order to correlate the cooling flow energy requirement data to the power output, a condenser temperature range must
also be estimated. A review of data from newly constructed plants in Attachment C showed no immediately discernable
pattern on a regional basis for approach or range values. Therefore, these values will not be differentiated on a regional
basis in this analysis. The data did, however, indicate a median approach of 10 °F (average 10.4 °F) and a median
range of 20 °F (average 21.1 °F). This range value is consistent with the value assumed in other EPA analyses and
therefore a range of 20 °F will be used. Table 5-14 presents the energy penalties corresponding to the pumping energy
requirements from Table 5-13 using the above factors.
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§ 316(b) Phase II TDD
Energy Penalties of Cooling Towers
Table 5-14: Comparison of Pumping Power
Cooling
system Type
Once-through
Once-through
Wet Tower
Once-through
Once-through
Wet Tower
Once-through
Once-through
Wet Tower
Once-through
Once-through
Wet Tower
Once-through
Once-through
Wet Tower
Once-through
Once-through
Wet Tower
Once-through
Once-through
Wet Tower
Once-through
Once-through
Wet Tower
Once-through
Once-through
Wet Tower
Distance Static Power Flow
Pumped Head Required Rate
ft. ft. kW gpm
at 20' Static Head Using 4:
300 20 1161.1
300 25 1295.6
at 20' Static Head Using 3:
300 20 1201.4
300 25 1335.9
at 20' Static Head Using 2:
300 20 1309.6
300 25 1444.1
at 20' Static Head Using 4:
1000 20 1228.8
300 25 1295.6
at 20' Static Head Using 3:
1000 20 1316.3
300 25 1335.9
at 20' Static Head Using 2:
1000 20 1550.6
300 25 1444.1
at 20' Static Head Using 4:
3000 20 1422.5
300 25 1295.6
at 20' Static Head Using 3:
3000 20 1644.5
300 25 1335.9
at 20' Static Head Using 2:
3000 20 2239.3
300 25 1444.1
Requirement and Energy Penalty to Power Plant Output
Range Nuclear Nuclear Nuclear Fossil Fuel Fossil Fuel Fossil Comb.- Comb.- Comb.-
Power/ Equiv. Pumping Power/ Equiv. Fuel Cycle Cycle Cycle
Heat Output Heat Output Pumping Power/ Equiv. Pumping
Heat
°F Ratio (MW) % of Output Ratio (MW) % of Ratio Output % of
Output (MW) Output
42" Pipes at 300' Length
100,000
100,000
20
20
0.8
0.8
235
235
0.49%
0.55%
1 294
1 294
0.39%
0.44%
3
3
882
882
0.13%
0.15%
42" Pipes at 300' Length
100,000
100,000
20
20
0.8
0.8
235
235
0.51%
0.57%
1 294
1 294
0.41%
0.45%
3
3
882
882
0.14%
0.15%
42" Pipes at 300' Length
100,000
100,000
42" Pipes at
100,000
100,000
42" Pipes at
100,000
100,000
42" Pipes at
100,000
100,000
20
20
1000' Length
20
20
1000' Length
20
20
1000' Length
20
20
0.8
0.8
0.8
0.8
0.8
0.8
0.8
0.8
235
235
235
235
235
235
235
235
0.56%
0.61%
0.52%
0.55%
0.56%
0.57%
0.66%
0.61%
1 294
1 294
1 294
1 294
1 294
1 294
1 294
1 294
0.45%
0.49%
0.42%
0.44%
0.45%
0.45%
0.53%
0.49%
3
3
3
3
3
3
3
3
882
882
882
882
882
882
882
882
0.15%
0.16%
0.14%
0.15%
0.15%
0.15%
0.18%
0.16%
42" Pipes at 3000' Length
100,000
100,000
20
20
0.8
0.8
235
235
0.60%
0.55%
1 294
1 294
0.48%
0.44%
3
3
882
882
0.16%
0.15%
42" Pipes at 3000' Length
100,000
100,000
20
20
0.8
0.8
235
235
0.70%
0.57%
1 294
1 294
0.56%
0.45%
3
3
882
882
0.19%
0.15%
42" Pipes at 3000' Length
100,000
100,000
20
20
0.8
0.8
235
235
0.95%
0.61%
1 294
1 294
0.76%
0.49%
3
3
882
882
0.25%
0.16%
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§ 316(b) Phase II TDD Energy Penalties of Cooling Towers
Note: Wet Towers are assumed to always be at 300' distance and have the same tower pumping head of 25' in all scenarios shown. The same flow rate
cfs) is used for all scenarios. Power/Heat Ratio refers to the ratio of Power Plant Output (MW) to the heat (in equivalent MW) transferred through th<
3-1 for the total energy penalties. This table presents only the pumping component of the total energy penalty
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§ 316(b) Phase II TDD
Energy Penalties of Cooling Towers
5.5.1 Summary of Cooling System Energy Requirements
EPA chose the piping scenario in Table 5-13 where pumping head is close to 50 ft for both once-through and recirculating
systems at new, "greenfield" facilities (that is, once-through at 1,000 ft and 3-42 in. pipes in Table 5-13). Thus, the cooling
water pumping requirements for once-through and recirculating wet towers are nearly equal using the chosen site-specific
conditions. Table 5-15 summarizes the fan and pumping equipment energy requirements as a percent of power output for each
type of power plant. Table 5-16 presents the net difference in energy requirements shown in Table 5-15 for the alternative
cooling systems. The net differences in Table 5-16 are the equipment operating energy penalties associated with conversion
from one cooling technology to another.
EPA notes that the penalties presented in Tables 5-15 and 5-16 do not comprise the total energy penalties (which incorporate
all three components of energy penalties: turbine efficiency penalty, fan energy requirements, and pumping energy usage) as
a percent of power output. The total energy penalties are presented in section 5.1 above. The tables below only present the
pumping and fan components. Section 5.3.4 presents the turbine efficiency components of the energy penalty.
Table 5-15: Summary of Fan and Pumping Energy Requirements as a Percent
Output
Nuclear
Fossil Fuel
Combined-Cycle
Wet Tower Wet
Pumping Tower
Fan
0.57% 0.91%
0.45% 0.73%
0.15% 0.24%
Wet Tower
Total
1.48%
1.18%
0.39%
Once-through
Total
(Pumping)
0.56%
0.45%
0.15%
of Power
Dry Tower
Total (Fan)
3.04%
2.43%
0.81%
Note: See Section 5.1 for the total energy penalties.
Table 5-16:
Nuclear
Fossil Fuel
Combined-Cycle
Fan and Pumping Energy Penalty Associated with
Cooling System as a Percent of Power Output
Wet Tower Vs
Once-through
0.92%
0.73%
0.24%
Alternative
Dry Tower Vs Wet Dry Tower Vs Once-
Tower through
1.56%
1.25%
0.42%
2.48%
1.98%
0.66%
Note: See Section 5.1 for the total energy penalties.
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§ 316(b) Phase II TDD Energy Penalties of Cooling Towers
5.6 OTHER SOURCES OF ENERGY PENALTY ESTIMATES
The Agency sought out additional sources of energy penalty estimates for its analysis of regulatory options for the
316(b) Existing Facility proposal. In part due to the lack of robust, empirical data available, the Agency undertook
the original energy penalty analysis in support of the New Facility Rule. For this Existing Facility proposal the fact
that certain regulatory options involved the conversion of aging cooling systems at existing facilities presented an
additional complexity to the Agency. The following sections summarize the Agency's data collection for estimates of
energy penalties at existing facilities.
5.6.1 Jefferies Generating Station Energy Penalty Study
As a result of its research for empirical examples of cooling system conversions, the Agency identified an empirical
energy penalty study associated with the construction of wet, mechanical-draft cooling towers to replace an original
once-through system. The Jefferies Generating Station ~ a 346 MW, coal-fired plant in South Carolina - owned by
Santee Cooper, conducted a turbine efficiency loss study in the late 1980s. The facility converted their cooling system
(after many years of operation utilizing a once-through system) to a full recirculating, mechanical-draft system around
1985. Due to the unusual arrangement whereby the U. S. Army Corps of Engineers (USAGE) paid for the construction
and operation of the cooling tower, Santee Cooper began an empirical study to assess the economic impact of the
operation of the cooling towers over the previous once-through system, in order to obtain reimbursement from the
USAGE. The study lasted several years (1985 to 1990). However, the empirical stage of data gathering occurred
primarily in 198 8. Santee Cooper determined (and the USAGE eventually agreed) that the cooling tower had decreased
the efficiency of each of the plant's steam turbines. The efficiency penalties determined by Santee Cooper were a
maximum of 0.97 percent of plant capacity (for both units, combined) and an annual average of 0.16 percent for the
year 1988. Note, that because the USAGE maintains and pays for the operation of the cooling towers, Santee Cooper
only examined the turbine portion of the energy penalty at the plant. The Agency requested documentation on the
historic operation of the towers from the USAGE (in addition to the construction costs from 1986) but did not receive
this information at the time of publication of this proposal. The study conducted by Santee Cooper is included in the
record of today's proposal (see DCN 4-2527). The Agency notes that its fossil-fuel estimate for the national-average,
peak-summer, turbine energy penalty is 0.90 percent and the mean-annual, national-average energy penalty is 0.35
percent (at 100 percent of maximum load). For the model plant in Jacksonville, Florida the Agency calculated a fossil-
fuel peak-summer turbine energy penalty of 0.61 percent and the mean-annual turbine energy penalty of 0.38 percent
(at 100 percent of maximum load).
5.6.2 U.S. Department of Energy Peak-Summer Energy Penalty Study
The U.S. Department of Energy (DOE), through its Office of Fossil Energy, National Energy Technology Laboratory
(NETL), and Argonne National Laboratory (ANL), studied the energy penalty resulting from converting plants with
once-through cooling to wet towers or indirect dry towers. DOE modeled five locations - Delaware River Basin
(Philadelphia), Michigan/Great Lakes (Detroit), Ohio River Valley (Indianapolis), South (Atlanta), and Southwest
(Yuma) - using an ASPEN simulator model. The model evaluated the performance and energy penalty for hypothetical
400-MW coal-fired plants that were retrofitted from using once-through cooling systems to indirect-wet- and indirect-
dry-recirculating systems. The modeling was done to simulate the hottest time of the year using temperature input
values that are exceeded only 1 percent of the time between June through September at each modeled location. At
DOE's request, EPA provided, discharge temperature data and thermal discharge permit limits for facilities at or near
the DOE study locations for use in the model. EPA also provided comments regarding the framework of the modeling
project, which are included in the record of this proposal (see DCN 4-2512)
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§ 316(b) Phase II TDD Energy Penalties of Cooling Towers
After completing their initial modeling, DOE shared the results of their working draft report with the EPA, which is
included in the record of this proposal (see DCN 4-2511). DOE estimates that conversion to a wet tower could cause
peak-summer energy penalties ranging from 2.8 percent to 4.0 percent. Therefore, DOE estimates that the plant will
produce 2.8 percent to 4.0 percent less electricity with a wet tower than it did with a once-through system while burning
the same amount of coal. Further, DOE estimates that conversion to an indirect-dry tower could cause peak-summer
energy penalties ranging from 8.9 percent to 14.1 percent with a design approach of 20 degrees Fahrenheit and 12.7
percent to approximately 18 percent with an approach of 40 degrees Fahrenheit.
EPA did not model indirect-dry cooling systems, and therefore cannot directly compare its estimates to those developed
by DOE. However, EPA can compare its estimates of peak summer energy penalties for mechanical draft wet cooling
towers to those developed by DOE. The Agency finds that its estimates of peak summer energy penalties are
significantly lower than those developed by DOE (see section 5.1 for EPA's estimates of peak summer energy penalties
of mechanical draft cooling towers). EPA and DOE believe that the difference in these estimates is most likely due to
two key factors: (1) the estimated energy penalty attributable to the parasitic energy use of cooling water pumps and
(2) the estimated design temperature ranges of cooling water from condenser inlet to outlet.
As discussed at Section 5.3 above, EPA developed energy penalty estimates for this proposal based on its estimates for
the 316(b) New Facility Rule. For the energy penalty estimates of the 316(b) New Facility Rule, the Agency conducted
an analysis of a variety of pumping scenarios for once-through versus recirculating systems at new "greenfield"
facilities. The Agency concluded that for "greenfield" facilities, the cooling towers would generally be sited in close
proximity to condenser units. Therefore, the Agency estimated that pumping distances for recirculating systems would
be significantly less than those for once-through systems. (The Agency provided this analysis for public comment in
the June 2001 Notice of Data Availability). In the analysis of energy penalties for new, "greenfield" plants, the Agency
concluded that the difference in pumping distance for a once-through system would offset the additional static head
pumping requirements of a typical mechanical draft cooling tower (see section 5.4.2 for the Agency's analysis of
pumping energy requirements). Therefore, the analysis of energy penalties used by the Agency for this proposal
estimates 0.0 percent energy penalty due to pumping requirements. DOE, on the other hand, estimates that a retrofitted
wet cooling tower would require significantly more pumping energy than a baseline, once-through cooling system. The
results of the DOE study show pumping energy penalties ranging from 0.2 to 0.7 percent. The Agency views the DOE
estimates to be reasonable for a variety of retrofit scenarios at existing facilities and will reconsider this subject in the
analysis of regulatory options for the final rule.
While EPA did not directly estimate design temperature range in its modeling approach, in effect DOE and EPA used
different design temperature ranges, which can dramatically affect energy penalty estimates. The DOE modeling
approach used simulated inlet and discharge water temperatures for the chosen sites. EPA provided thermal discharge
permit information, which DOE incorporated into a parametric analysis of design temperature ranges (that is, DOE
examined a variety of temperature ranges, from 5 degrees F to 25 degrees F). For example, the design ranges examined
by DOE for their Michigan site show peak energy penalties that vary by 1 percent, from 3.95 % for a 7 degree F design
range to 2.94 % for a 25 degree F design range. In the case of other model sites, such as Georgia, a design range
increase of 5 degrees F (from 5 degrees F to 10 degrees F) can dramatically effect the results of the energy penalty
estimates. The DOE model estimates a 3.99 % percent energy penalty for the 5 degrees F design range in Georgia and
2.78 % for the 10 degrees F design range assumption. As EPA noted in its comments on DOE's proposed energy
penalty analysis, EPA believes that design temperature ranges of less than 13 degrees F are not realistic at most
5-35
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§ 316(b) Phase II TDD Energy Penalties of Cooling Towers
locations and are likely to lead to energy penalty estimates that are higher than would occur under realistic operating
conditions.
In addition to the two key factors described above, DOE expressed concern to EPA that the Agency' s modeling analysis
of turbine energy penalties did not incorporate subtle effects on the condenser duty. Specifically, DOE did not believe
that the Agency's model takes into account the increase in turbine exhaust temperature (or steam temperature to
condenser) resulting from a corresponding increase in condenser duty when changing the once-through cooling water
system to a wet cooling tower. Under peak energy penalty periods, the temperature of the condenser cooling water will
be greater under wet cooling tower operation then the same plant operated under once-through cooling because of the
difference between ambient wet-bulb and surface water temperatures. DOE believes that the increased condenser duty
for the wet cooling tower results in an increase in cooling water flow which increases the cooling water pump and
cooling tower fan energy penalties compared to the Agency's approach.
DOE also points out that the Agency's model does not consider a second effect that since the steam is condensed at a
slightly higher temperature for the wet cooling tower case, the reheating of the recirculated steam condensate will
require a reduction in the amount of steam bleed from the turbine system. This results in a slightly higher steam
flowrate through the turbines and into the condenser. This again increases the condenser duty and would again increase
the parasitic energy penalties. However, this would probably be offset by an increase in power due to a small increase
in the steam flowrate in the turbines. DOE estimates that these effects may contribute a maximum of 0.5 percentage
points to the Agency 's evaluation of the peak-summer energy penalty.
5.6.3 Catawba and McGuire Nuclear Plant Comparison
One literature source the Agency encountered calculated the energy penalty of a nuclear plant employing a mechanical-
draft wet cooling system by comparing the electrical ratings of the Catawba and McGuire Nuclear Plants. Because
the two plants were constructed nearly identically, the author hypothesized that the percent difference electrical rating
between the two plants would represent the energy usage of a cooling tower. The Agency notes that even though a
comparison of this type would theoretically calculate the net energy use of the pumps and fans of the wet cooling tower
system as compared to the once-through system, there are a variety of complicating factors that are not accounted for
or are overlooked in this case. The electrical rating of a nuclear plant does not, to the Agency's knowledge, account
for the turbine efficiency penalty component. This key portion of the energy penalty would not be included in the
electrical rating calculations of the plant. The comparison could, therefore, underestimate the total energy penalty of
the cooling system.
Nonetheless, the Agency examined the historical energy penalty estimate for the Catawba versus McGuire case and
determined that the source had made an error in calculating an estimate of 3 percent for the overall energy use of the
cooling towers over the once-through system. The error made was to assume that each plant had the same gross
capacity. In fact, the McGuire plant has a gross capacity that is 31 MW greater than Catawba. Therefore, a
comparison of the percentage difference between gross and net capacity for the two plants actually should be calculated
as 1.7 percent. This energy penalty estimate for the fan and pumping components is higher than that estimated by the
Agency elsewhere in this chapte for nuclear facilities. The Agency estimates that the total of the fanning and pumping
components for a nuclear plant would be 0.9 percent. As described in Section 5.3 of this chapter, the Agency's
estimates of the pumping components developed for new, "greenfield" facilities calculate no net change in the pumping
5-36
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§ 316(b) Phase II TDD Energy Penalties of Cooling Towers
requirements between once-through and recirculating wet cooling tower systems. As stated in Section 5.6.2 above, this
may also explain to some degree the differences between the Agency's and the Catawba/McGuire estimate.
5.6.3 Palisades Cooling System Conversion Energy Penalty Estimate
The Agency learned from discussions with, and information submitted by, Consumers Energy that the cooling tower
system at Palisades might have a significant impact on the efficiency of the plant's generating unit. Though the plant
was unable to provide historical studies of the energy penalty of the cooling tower system, they estimate that the effect
could be approximately 7 percent (Gulvas, 2002). Prior to the 1970' s conversion, the Nuclear Regulatory Commission
(NRC) estimated that the cooling tower system would affect plant efficiency by 3 percent (Gulvas, 2002). Consumers
Energy estimates that the cooling system fans utilize 4 MW of electricity for operation, and the circulating and intake
pumps utilize approximately 16 MW and 3 MW, respectively (Gulvas, 2002). Consumers Energy further estimate that
the cooling tower system reduces the efficiency of the steam turbine by 6 to 8 percent compared to the original once-
through system. Consumers Energy did not provide supporting documentation for the turbine efficiency penalties or
pumping and fanning losses as submitted to the Agency.
Based on the Agency's energy penalty methodology, the turbine energy penalty for a nuclear unit (at peak summer
conditions) would be approximately 1.4 percent (11.3 MW for Palisades). The Agency calculated this penalty using
the historic cooling water temperature data for Palisades provided by Consumers Energy and ambient dry bulb and wet
bulb air temperatures specific to Chicago, IL (Consumers, 2001).1 This estimate of turbine efficiency penalty is
substantially less than that estimated by Consumers Energy. The Agency notes that Consumers Energy did not estimate
the original pumping requirements of the once-through system, and, therefore, the net energy penalty (that is, wet
cooling tower energy use less the once-through system energy use) of the conversion estimated by Consumers Energy
may not be the appropriate comparison. The Agency also notes that the electricity usage of 36-200 hp fans would be
5.4 MW with each fan at full operation, slightly higher than the estimate by Consumers Energy. EPA also estimated
the pumping energy penalty for the recirculating system at Palisades and compared this to the pumping energy required
for the former once-through operation of the plant. EPA determined, conservatively (that is, erring on the high side),
that the circulating pumping requirements of the cooling tower system currently in place at Palisades would require
approximately 7.5 MW (that is, 8.5 MW less than the estimate given by Palisades above). The original once-through
system would have required approximately 5 MW to convey water 3,300 feet from the offshore intake through 11 ft
diameter pipe, through the condenser, and to discharge at the lake shore. The Agency did not analyze the "dilution"
pumping requirements estimated by Consumers Energy as 3 MW above. Therefore, the Agency estimates that the total
energy penalty of the recirculating tower system at Palisades may have a peak energy penalty close to 2.7 percent and
an annual penalty approaching 1.8 percent as compared to the original once-through system (Sunda, et al, 2002).
1 The EPA calculations for energy penalties specific to Palisades and Lake Michigan utilized the data from the 2001
Consumers Energy permit document with the energy penalty methodology outlined in this chapter.
5-37
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§ 316(b) Phase II TDD Energy Penalties of Cooling Towers
REFERENCES
Air Force Combat Climatology Center in Ashville, NC. CD entitled Engineering Weather Data (2000 Interactive
Edition). National Climatic Data Center.
Burns, J. M. and W. C. Micheletti. November 2000. Comparison of Wet and Dry Cooling Systems for Combined
Cycle Power Plants. Version 2.1. Submitted as Appendix F to the comments of the Utility Water Act Group on EPA's
Proposed Section 316(b) Rule for New Facilities.
Consumers Energy Company and Nuclear Management Corporation, May 2001, "Biological Assessment of the 1999
Cooling Water Flow Increase at the Palisades Nuclear Plant, near South Haven, Michigan."
Durand, A et al. May 1999. Updated Rules for Pipe Sizing. Chemical Engineering.
Entergy Nuclear Generation Company (Entergy). February 2001. Condenser Performance Analysis - Additional
Data; Pilgrim Nuclear Power Station. Submitted by J.F. Alexander, to Nicholas Prodany, EPA Region 1.
Environmental Protection Agency. September 2001. The Emissions & Generation Resource Integrated Database
2000 (E-GRID 2000). Version 2.0. http://www.epa.gov/airmarkets/egrid/index.html
Fleming, Robert. 2001. Personal communications between Robert Fleming, The Marley Cooling Tower Co., and
Faysal Bekdash, SAIC.
General Electric. No Date. Steam Turbine Technology. Field Engineering Development Center Mechanical &
Nuclear.
Gulvas, J. A., 2002, "The Palisades Plant Once-through and Cooling Towers," Consumers Energy data submission
to the U.S. EPA. February 28, 2002.
Heat Exchanger Systems, Inc (HES). 2001. Condenser Performance Analysis.
Hensley, J.C. 1985. Cooling Tower Fundamentals. 2nd Edition. The Marley Cooling Tower Company (Mission,
Kansas).
Hess, Dale. June 2001. Condenser Cost Study. Graham Corporation.
Ishigai, S. 1999. Steam Power Engineering-Thermal Hydraulic Design Principles. Cambridge university Press. UK.
Kirk-Othmer. 1997. Encyclopedia of Chemical Technology. Fourth Edition. Volume 22. John Wiley and Sons, Inc.
New York.
5-38
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§ 316(b) Phase II TDD Energy Penalties of Cooling Towers
Litton, T.R. Stanley Consultants, Inc. No Date. "Application of Parallel wet and Dry Condensing Systems to a 35
MW Steam Turbine"
Mirsky, Gary. 2001. Personal communications between Gary Mirsky, Hamon Cooling Towers, and Faysal Bekdash,
SAIC.
Nuclear Regulatory Commission. 1996. Generic Environmental Impact Statement for License Renewal of Nuclear
Plants. NUREG-1437 Vol. 1. http://www.nrc.gov/docs/nuregs/staff/srl437A^l/srl437vl.html#_l_128
Perry, W. J., 1991, "Adverse Impact Study; Cooling Water Facilities - Jefferies Generating Station," for Santee Cooper,
Moncks Corners, South Carolina.
Sunda, J.B., et al., 2002, "Analysis of Palisades Nuclear Plant Pumping Energy Requirements."
Tallon, B. Not Dated. GEA Power Systems Inc. Telephone Contact with John Sunda, SAIC. Regarding Air Cooled
Condenser Fans.
Tatar, G. October 2001. Telephone Contact with John Sunda, SAIC. Regarding operation of the air cooled condenser
fans. El Dorado Energy.
Taylor, S. May 2001. Telephone Contact with John Sunda, SAIC. Regarding cooling water pumping and condenser
operation. Bechtel.
U.S. Department of Energy. May 2000. Statement of Jay E. Hakes Administrator, Energy Information Administration,
Department of Energy before the Committee on Energy and Natural Resources, United States Senate.
U.S. Department of Energy. August 2001. "Energy Penalty Analysis on Possible Cooling Water Intake Structure
Requirements on Existing Coal-Fired Power Plants," Working Draft, Office of Fossil Fuel Energy, National Energy
Technology Laboratory, and Argonne National Laboratory.
U. S. Environmental Protection Agency. April 2001. Memorandum from Tim Connor to Tom Feeley (U. S. Department
of Energy). "Comments on Proposed Energy Penalty Analysis."
Woodruff, E.B.,Lammers, H.B.,Lammers, T.F. 1998. Steam Plant Operation. Seventh Edition. McGraw-Hill. New
York.
5-39
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§ 316(b) Phase II TDD Attachments to Chapter 5
ATTACHMENT A TO CHAPTER 5: HEAT DIAGRAM FOR STEAM
POWER PLANT
(Source: Ishigai 1999)
See Hard Copy
Attachm ents
-------
§ 316(b) Phase II TDD Attachments to Chapter 5
ATTACHMENT B TO CHAPTER 5: EXHAUST PRESSURE
CORRECTION FACTORS
FOR A NUCLEAR POWER PLANT (Attachment B-l)
(Source: Entergy 2001)
See Hard Copy
FOR A FOSSIL FUEL PLANT (Attachment B-2)
(Source: General Electric. Steam Turbine Technology)
See Hard Copy
FOR A COMBINED CYCLE PLANT (Attachment B-3)
(Source: Litton)
See Hard Copy
Attachm ents
-------
§ 316(b) Phase II TDD Attachments to Chapter 5
ATTACHMENT C TO CHAPTER 5: DESIGN APPROACH DATA FOR
RECENT COOLING TOWER PROJECTS
(Source: Mirsky 2001)
Attachm ents
-------
§ 316(b) Phase II TDD
Attachments to Chapter 5
Table AA-1. Coding Tower Design Tern per ato a. Range andApproach
STATE
AL
OR
CA
NJ
AL
AL
IL
TX
TX
MO
FL
TX
CA
AL
MO
MS
SC
TX
TX
AL
LA
TX
SC
SC
AR
NJ
TX
CA
TX
SC
LA
OH
LA
MO
PA
AL
OK
WA
MT
GA
OH
MH
LA
NY
SC
YEAR
2000
2000
2000
2000
2000
2000
2000
2000
2000
1999
1999
1999
1999
1999
1999
1998
1998
1998
1998
1998
1998
1998
1998
1998
1998
1998
1998
1998
1998
1998
1998
1998
1997
1997
1997
1997
1997
1997
1997
1997
1997
1997
1997
1997
1997
FLQW(GPM)
208000
132000
99746
146000
278480
147361
189041
192300
106400
60000
21500
277190
101000
50000
25000
230846
150000
90000
278480
125000
45000
90400
8500
14000
13200
4400
18000
7000
15000
15000
1000
6400
20000
60000
30000
16000
8350
14000
12000
3000
6000
7500
12000
4800
50000
TEMPERATURE. (DEG F)
HOT WATER
85
98
94.3
90.3
103
112.5
96.87
104.3
89.2
85.3
120
105
111.05
107
98
106.2
110
110
105
105.7
110
117.1
114
116
116
100
105
105
115
123
124
135
104
85.3
105
114
112
120
96
97.6
118
106
110
103.5
93
COLD WATER
72
77.8
72.5
75
89
96.7
85.46
87
78.5
67
93
89
89
86
83
91.2
90
90
89
85.7
90
94.1
95
95
95
71
85
80
90
95
90
90
86
67.5
85
90
89
74
74
87.6
86
87
85
85
81
WET BULB
62
68.35
55.5
52
81
84.7
76
79
64.2
52.4
80
81
75
80
78
84.7
80
83
81
80
82
82.68
81
81
81
66
72
71
81
81
80
77
81
52.4
78
79
79
58
64
80
77
74
80
78
72
RANGE
(DEGF)
13
20.2
21.8
15.3
16
15.8
11.41
17.3
10.7
18.3
27
16
22.05
21
15
15
20
20
16
20
20
23
19
21
21
29
20
25
25
28
34
45
18
17.8
20
24
23
46
22
10
32
19
25
18.5
12
APPROACH
(DEGF)
10
9.43
17
23
8
12
9.46
8
14.3
14.6
13
8
14
6
3
6.5
10
7
8
5.7
8
11.42
14
14
14
5
13
9
9
14
10
13
5
15.1
7
11
10
16
10
7.6
9
13
5
7
9
#OF
CELLS
10
11
8
10
14
7
10
12
5
4
1
14
6
4
1
12
11
5
14
10
3
5
2
2
2
4
2
1
2
1
1
2
2
4
6
2
2
2
2
1
2
1
3
1
3
Maximum 278480 135 96.7 84.7 46 23 14
Minimum 1000 85 67 52 10 5 1
Average 75775.42222 106.3 85.2 74.8 21.1 10.4 5
Median 30000 105.7 87 79 20 10 3
Mode 278480 105 90 81 20 10 2
Attachm ents
-------
§ 316(b) Phase II TDD Attachments to Chapter 5
ATTACHMENT D TO CHAPTER 5: TOWER SIZE FACTOR PLOT
(Source: Hensley 1985)
See Hard Copy
Attachm ents
-------
§ 316(b) Phase II TDD Attachments to Chapter 5
ATTACHMENT E TO CHAPTER 5: COOLING TOWER WET BULB VERSUS
COLD WATER TEMPERATURE TYPICAL PERFORMANCE CURVE
(Source: Hensley 1985)
See Hard Copy
Attachm ents
-------
§ 316(b) Phase II TDD Non-water Quality Impacts
Chapter 6: Non-Water Quality Impacts
INTRODUCTION
This chapter discusses side effects of the operation of recirculating wet cooling towers including increased air
emissions due to energy penalties, vapor plumes, noise, salt or mineral drift, water consumption through evaporation,
and solid waste generation due to wastewater treatment of tower blowdown.
6.1 AIR EMISSIONS INCREASES
Due to recirculating wet cooling system energy penalties, as described in Chapter 5, EPA estimates that air emissions
may marginally increase frompower plants that retrofit from once-through to recirculating wet cooling systems. The
energy penalties reducethe efficiencyof the electricity generation process andincrease auxiliary power consumption;
thereby increasing the quantity of fuel consumed per unit of electricity generated. EPA assumes facilities will seek
to compensate for the energy penalties and maintain their electricity generation levels because of contractual
obligations and market conditions. EPA believes the facilities will be capable of compensating for the energy
penalties based on its analysis of unused capacity in the industry. EPApresents the estimates of annual air emissions
increases under the flow reduction-waterbody option (Option 1) in Table 6-1 below. This analysis describes
estimated increases only for Option 1.
EPA developed estimates of incremental increases in air emissions of carbon dioxide (CO2), mercury (Hg), sulfur
dioxide (SO2), nitrogen oxides (NOx), and particulate matter (PM2.5 and PM10) for the facilities projected to
upgrade their cooling systems under the flow reduction-waterbody option in today's proposed rule. These facilities
include nuclear, combined-cycle, and fossil fuel-fired power plants. Generally, combined-cycle plants produce
significantly less air emissions per kilowatt-hour of electricity generated than fossil fuel-fired plants. Because a
combined-cycle plant requires cooling for approximately one-third of its process (on a megawatt capacity basis) and
because of the differences in combustionproducts from natural gas versus other fossil fuels, the combined-cycle plant
produces less air emissions than fossil fuel-fired plants, even after such plants are equipped with state-of-the-art
emissions controls. Nuclear power plants utilize radioactive materials as fuel and have extremely low or negligible
emission rates of CO2, Hg, SO2, NOx, PM2.5, and PM10 in comparison to those found at either combined-cycle or
fossil fuel-fired facilities.
EPA assumed that a facility incurring an energy penalty from retrofitting a once-through cooling system to a
recirculating wet cooling system would seek to compensate for that penalty by increasing their electricity generation
and would be able to do so by increasing electricity generation on-site. Most facilities do not operate at full
electricity generation capacity on an annual basis. EPA believes such facilities would be able to compensate on an
annual basis for the annual energy penalty due to conversion to a recirculating wet cooling system by increasing on-
site electricity generation.
EPA could alternatively assume thatplants incurring an energy penalty will not increase their fuel consumption on-
site to overcome incurred energy penalties. Instead, facilities affected by the requirements of this rule would
purchase replacement power from the grid. Under this scenario, the air emissions increases associated with a
particular energy penalty at an affected plant would be released by the rest of the grid as a whole, thereby comprising
6-1
-------
§ 316(b) Phase II TDD Non-water Quality Impacts
small increases at a large number and variety of power plants. During the development of the Section 316(b) Final
Rule addressing new facilities, EPA received comments asserting that not all facilities, especially during times of
peak demand, would be able to increase their fuel consumption to overcome energy penalties. Nuclear facilities, in
particular, may not be able to increase generation on-site. EPA has not calculated the national marginal increase in
air emissions associated with purchase of electricity from the grid, though it notes that such purchases are a possible
outcome of cooling system conversions. The Agency believes 1hat the outcome of a national analysis would be
similar to that of the facility-specific analysis because the distribution of facility types and their associated emissions
profiles in each analysis would be comparable.
The estimated air emissions increasespresented in Table 6-x below represent facility-specific increases and are based
on the estimated energy penalty for each facility, the facility's historic average electricity generation level, and its
average historic emission rates. The data source for the Agency's air emissions estimates of CO2, SO2, NOX, and Hg
is the EPA-developed database titled E-GRID2000. This database is a compendium of reported air emissions, plant
characteristics, and industry profiles for the entire US electricitygeneration industry in the years 1996 through 1998.
The database relies on information from power plant emissions reporting data from the Energy Information
Administration of the Department of Energy. The database compiles information on every major power plant in the
United States and includes statistics such as plant operating capacity, air emissions, electricity generated, fuel
consumed, etc. This database provided ample data for the Agency to conduct air emissions increases analyses for
this rule. The emissions reported in the database are for the power plants' actual emissions to the atmosphere and
represent emissions after the influence of air pollution control devices. To test the veracity of the database for the
purposes of this rule, the Agency compared the information to other sources of data available on power plant
capacities, fuel-types, locations, owners, and ages. Without exception, the E-GRID 2000 database provided accurate
estimates of each of these characteristics versus information that EPA was ab le to obtain from other sources. E-GRID
2000, however, does not provide information on emissions of particulars matter. The data source for historic
emissions rates of PM2.5 and PM10 is the EPA-developed database titled National Emission Trends (NET). The
NET database is an emission inventory that contains data on stationary and mobile sources that emit criteria air
pollutants and their precursors. The NET is released every three years (e.g., 1996 and 1999) and includes emission
estimates for all 50 Stales, the District of Columbia, Puerto Rico, and the Virgin Islands. The database compiles
information from EPA air programs and the Department of Energy, and the information it contains was found to be
consistent with the information found in E-GRID 2000.
A facility thatincreases on-site electricity generation to compensate for the energy penalty associated with retrofitting
its cooling water system may, because of the resultant on-site increase in air pollutant emissions, be subject to new
source review (NSR). Major stationary sources of air pollution undergoing major modifications are required by the
Clean Air Act to obtain an air pollution permit before commencing construction. The process is called new source
review and is required whether the major source or modification is planned for an area where the national ambient
air quality standards (NAAQS) are exceeded (nonattainment areas) or an area where air quality is acceptable
(attainment and unclassifiable areas).
There are costs associated both with undergoing NSR and with measures taken to ensure compliance with new air
emission control requirements delineated during the NSR process. If a facility purchases electricity from the grid,
it does not need to undergo NSR and can therefore avoid the associated costs. EPA believes that some facilities
retrofitting their cooling systems under the proposed regulatory alternative requiring flow reduction commensurate
with closed cycle wet cooling based on water body type may choose to purchase energy from the grid rather than
incur the costs associated with NSR. The resulting increase in emissions would be similar to that estimated given
on-site generation of additional electricity.
6-2
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§ 316(b) Phase II TDD
Non-water Quality Impacts
However, to provide aconservative estimate of tiie number of facilities potentially subjectto NSR costs under today's
proposed Option 1, EPA first assumed all facilities would undergoNSR review before atte mpting to purcha se energy
off the grid. To yield a conservative estimate of the number of facilities potentially subject to NSR costs, EPA
assumed that all facilities would be operating at full capacity once they had increased electricity generation to
compensate for the energy penalty associated with retrofitting their cooling systems. This assumption maximizes
the estimated marginal increase in air pollutant emissions associated with energy penalty compensation. This
conservative screen indicated that 29 facilities could potentially be subject to NSR costs.
Table 6-1. Estimated Increase in Emissions under Flow Reduction- Waterbody Option*
„ . J\, i Annual i Annual i Annual i Annual i Annual PM2. 5 i Annual PM 10
C otle - i i i i i
| CO2 (tons) | SO2(tons) { NOx(tons) { Hg (Ibs) { (tons) { (tons) j
E E E E E E i
: : i : i i :
= 5 5 5 5 5 !
i i i i i 1
1: : : : : :
: : : : : :
: : : : : :
. _ ._._._. _ .
: : : : : :
: : : : : :
i i i i i 1
2 - - - - -
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
15,417
17,024
17,421
14,528
22,678
24,968
12,560
26,722
282,344
130,879
232,551
82,957
142,339
-
39,928
37,846
71,247
40,005
20,016
-
96,279
8,330
0.1
0.1
0.1
0.1
0.4
0.3
0.2
1,718.2
1,217
1,923.6
658.4
1,103.0
-
477.2
471
587.4
116.5
59
-
0.8
5.8
6.8
16.7
1.0
18
19.2
4.7
5.1
695.6
636
809.4
229.9
407.6
-
168.8
89
166.4
68.9
31
-
154.9
18
-
-
-
-
-
-
-
-
7.1
5.5
7.2
2.7
5.5
-
-
-
-
-
-
-
-
-
-
-
27 ! 70,291 1 0.6 I 154.1 I
j j i j
0.05
0.04
0.04
0.03
0.06
0.06
0.02
0.09
25.07
8.55
27.52
6.90
12.91
-
4.38
2.53
4.56
2.25
0.98
0.30
0.02
0.20
0.05
0.04
0.04
0.03
0.06
0.05
0.02
0.09
11.31
4.54
11.23
3.15
6.36
-
3.91
2.11
3.93
1.96
0.84
0.30
0.02
0.20
6-3
-------
§ 316(b) Phase II TDD
Non-water Quality Impacts
Table 6-1. Estimated Increase in Emissions under Flow Reduction- Waterbody Option*
E E E E E E
1-1-1-:= 5 = 5 5 =
r acilltv = 5555 i
^ | Annual { Annual { Annual { Annual { Annual PM2. 5 { Annual PM10
°Q \ CO2 (tons) 1 SO2(tons) { NOX (tons) 1 Hg (Ibs) { (tons) { (tons)
28 ! 39,540 ! 0.3 | 62.9 | - | 0.12 | 0.12
: : : : : :
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
50
51
52
53
54
55
56
57
58
59
29,876
71,191
147,288
47,497
48,034
2,802
52,664
80,985
821
1,626
1,204
3,095
15,848
74,962
154,087
116
1,974
32,941
66,131
76,207
41,229
22,708
56,147
-
50,286
7
-
552.5
1,464.5
209.7
279.2
255
461.7
7
1.4
1.0
81
549.4
851.1
0.7
31
290.2
263.9
98.9
242
-
291.2
49
188.0
462.0
227.3
159.1
0.8
104
322.2
2
3
3.3
3.8
26
114.9
264.3
36.1
74
79.6
52.7
27.9
75
-
67.0
-
3.1
6.7
0.2
1.8
-
-
-
1.9
2.4
-
-
-
-
-
0.1
3.8
-
-
-
-
-
-
-
-
-
-
-
-
-
-
0.08
4.41
10.26
1.76
3.60
-
-
-
3.07
18.24
0.02
0.06
0.02
0.08
0.56
9.76
12.27
-
-
0.63
0.70
-
-
-
0.11
2.95
1.15
3.87
3.05
0.08
2.00
4.65
0.97
1.64
1.89
7.91
0.01
0.06
0.02
0.07
0.26
4.96
5.77
0.63
0.61
0.09
2.60
0.99
2.04
2.71
Dashes indicate negligible emissions increases.
*This table includes information from those facilities with capacity utilization rates below 15%.
* *EPA developed model plants representing existing facilities for analyzing regulatory options and developing costs. To protect confidential
business information, EPA has assigned these model plants a random code number.
6-4
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§ 316(b) Phase II TDD Non-water Quality Impacts
6.2 VAPOR PLUMES
Natural draft or mechanical draft cooling towers can produce vapor plumes. Plumes can create problems for fogging
and icing, which have beenrecorded to create dangerous conditions for local roads and for airand water navigation.
Plumes are in some cases disfavored for reasons of aesthetics. Generally, mechanical draft cooling towers have
significantly shorter plumes than those for natural draft towers (by approximately 30 percent).
As discussed in Chapter 4,1he Agency considered regulatory options based on flow reduction commensurate with
closed-cycle wet cooling systems. The Department of Energy (DOE) expressed concern to the Agency that plume
abatement technologies would be required for a subset of existing plants projected to adopt wet cooling towers under
these options. The DOE believed that the options based on flow reduction should consider a significant portion of
existing facilities converting from once-through systems to hybrid wet/dry cooling towers, instead of the wet (only)
towers examined by the Agency.
Historical ly, plants have adopted plume reduction technologies for the following reasons: visual aesthetics,' liability
relating to icing and fogging of nearby transportation routes (US EPAReg 1,2002), and potentially elevated moisture
levels affected nearby agriculture. For the 316(b) New Facility Final Rule, 1he Agency considered plume effects of
wet cooling towers. The Agency determined thatfor the limited number of new, "greenfield" facilities that may adopt
towers to meet the flow reduction requirements of the rule,2 that the plume effects would not be a sufficient
environmental concern, especially in comparison to the significant aquatic environmental benefits of intake flow
reduction.3 However, in the Agency's view, the issue of vapor plume effects at existing facilities requires a slightly
different consideration. Existing fecilities do not have the advantage of siting and designing the plant layout to
minimize plume effects, which is far and away the most economic means of plume mitigation. Through the
utilization of terrain features, buffer areas, prevailing wind directions, and site selection, the new, "greenfield" facility
has a set of tools that provide a distinct advantage for plume mitigation over an existing plant converting its cooling
system. Therefore, the Agency examined historic studies and example cases of plumes and plume mitigation to
understand the prevalence and necessity of plume abatement for cooling tower installations at existing facilities.
Hybrid wet/dry tower systems are the technology most frequently associated with plume abatement. The primary
type of wet/dry tower employed in practice is a configuration where an air-cooled condensing unit sits atop a wet
evaporative unit. This technology, in effect, reduces the amount of moisture transferred to the air by raising the
temperature and lowering the relative humidity of the exhaust air. The heated water from the condensers is fed first
to the top, dry portion of the tower, where air flows around the air-cooled condenser and heat transfers to the
environment without evaporation of water. The water then disperses through the wet portion of the system, where
heat transfer from the water to the air occurs primarily through the more efficient means of evaporation. Because
the air-cooledportion creates an elevated temperature environment forthe exhaust plume and reduces the temperature
of the water before entering the evaporative section, the frequency and extent of the exhaust vapor plume is reduced.
The air-cooled portion of the hybrid-wet/dry tower is relatively inefficient in comparison to the wet-cooled system,
1 November 2001, "Hearing Report and Recommended Decision by State of New York, in the Matter of Mirant Bowline,
LLC, Application for a State Pollutant Discharge Elimination System." The report states, "Mirant has explained thatthe
primary reason for revising the cooling/intake proposal is to reduce cooling tower steam plumes, thereby further reducing
adverse visual impacts of the project."
2 Note: the 3 16(b) New Facility Rule estimated that nine-new, "greenfield" facilities over a twenty year period would comply
with the rule by installing wet cooling towers. However, the New Facility rule did not mandate a compliance technology and
provides flexible compliance options through a multi-track framework.
3 Chapter 3 of the Technical Development Document of the Final Regulations Addressing Cooling Water Intake Structures for
New Facilities.
6-5
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§ 316(b) Phase II TDD Non-water Quality Impacts
and the overall efficiency of the hybrid system is reduced compared to a wet (only) cooling tower. However,
advances in the design of the hybrid tower systems allow bypassing of the air-cooled condenser portion, thereby
allowing the tower to function in the more efficient wet (only) cooling mode when the meteorological conditions do
not favor visual plume formation or electricity demand requires maximum capacity of the plant (BDT Engineering,
2000) (US EPA Reg I, 2002). The Agency notes that the type of hybrid tower used for plume abatement generally
does not reduce water intake compared to a wet cooling tower and would, therefore, have no appreciable reduction
in the potential aquatic impacts of cooling water intakes. In addition, the technology may, through the fact that it is
less efficient than a wet (only) cooling tower system, cause the plant to emit more air pollutants due to the energy
penalty as compared to a wet cooling tower system and a once-through system.
The ratio of the capital cost of the hybrid tower systems (alone, without the necessary and costly auxiliary
components such as piping, pumps, etc.) to the cost of wet (only) towers (without necessary, auxiliary components)
generallyis on the order of 2.0 to 3.0 (Mirsky, etal., 1992) (Power Tech Associates, 1999). For a typical new facility
installation, including all of the auxiliary components of yard piping, pumps and motors, basin, sump, electrical
wiring and controls, excavation, site preparation, water treatment, etc., the cooling tower unit will comprise a portion
of the total capital costs. The Utility Water Act Group, in comments submitted to the Agency for the 316(b) New
Facility Proposed Rule presented wet (only) cooling tower unit costs as approximately 45 percent of the total cooling
tower system direct capital costs and approximately 35 percent of total estimated costs (Burns and Michiletti, 2000).
Several turnkey costs that the Agency received from cooling tower engineering firms showed the wet cooling tower
unit portion of total project costs varied from approximately 25 to 40 percent. The Agency expects that the hybrid
wet/dry tower would not appreciably affect the auxiliary component costs of a full cooling tower installation.
Therefore, the Agency concludes that hybrid wet/dry tower unit would increase the overall capital costs for the total
cooling tower system (including all auxiliary components) at a new, "greenfield" facility by approximately 25 to 80
percent as compared to a wet (only) unit. For cooling systems conversions, the Agency estimates that the cooling
tower unit would be identical to that of a new, "greenfield" facility, but that the auxiliary components would be
considerably more expensive. The Agency estimates that the overall cooling towerproject costs would be roughly
20 percent more expensive, due mostly to the increase in costs of the auxiliary components. Hence, for existing-
facility cooling tower retrofits, the Agency estimates the increase in overall project cost for a hybrid wet/dry cooling
tower unit over a wet (only) unit would range between 20 and 65 percent.4
As stated above, the primary reasons for adopting plume abatement are considerations of visual aesthetics,
transportation interference liability, and agricultural interference. The Agency is not aware of a database or a
combination of sources of information that identify the prevalence of installations of hybrid wet/dry cooling systems.
Approximately 80 of the 539 plants forwhich the Agency has detailedinformation employ some form of recirculating
cooling system, many ofthese are cooling towers. The Agency's data collection, unfortunately, did not distinguish
between the type of coolingtower in-place at these facilities. However, several other data sources do specify the type
of cooling tower in-place for many existing power plants: the Power Statistics Unit Design Data File Part B of the
1994 UDI Database and NUREG-1437, the Generic Environmental Impact Statement prepared by the Nuclear
Regulatory Commission. After consulting these two data additional data sources, the Agency was unable to
specifically identify any of the 539 plants that utilize hybrid wet/dry towers. The Agency, however, did learn from
one of the world's largest cooling tower vendors that roughly 3 to 5 percent of the ir recent installations utilize plume
abatement. This figure alone does not form adequate basis for decidingthe necessity of plume abatement, which can
only truly be gauged by detailed meteorological studies at each site. In order to gauge the prevalence of cooling
towers and their proximity to transportation corridors, the Agency examined a significant portion of the facilities
4 Power Tech Associates (1999) state, when referring to their estimates of cooling system conversion costs for the four
Hudson River pknts, "the effect of using wet/dry towers is much less than a 25 percent increase in the overall conversion
costs."
6-6
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§ 316(b) Phase II TDD Non-water Quality Impacts
within the scope of this rule that have closed cycle systems in-place in cold climates (that is, any climate deemed to
have periods each year with predictable freezing and icing). The Agency mapped as many of these plants as possible
and examined their proximity to highways, navigable rivers and lakes, and railways. The Agency identified 16
facilities with full-recirculating cooling systems and very large megawatt (steam) capacities that were within close
proximity (that is, several meters to several hundred meters) to major highways, navigable rivers and lakes, and
railways. Only one of these facilities (Bergen Generating Station) utilizes a form of plume abatement, to the
Agency's knowledge. The other plants - Keystone Generating Station (PA), Conemaugh Generating Station (PA),
Trojan Nuclear (OR, now retired and decommissioning), Michigan City Station (IN), Sherbourne County Station
(MN), General J M Gavin (OH), Mill Creek Units 2 & 3 (KY), Cardinal Unit 3 (OH), W H Zimmer (OH), Ghent
Station (KY), Rockport Station (IN), Big Sandy (KY), Muskingum River (OH), John E Amos (WV), and Muskogee
Station (OK) - utilize either natural draft or mechanical draft wet (only) towers (US EPA, 2002).
In addition to the examples above, the Agency examined the US Capitol Power Plant (DC) andPawtucket Power (RI).
Although the US Capitol Power Plantoperates a small, 7-cell mechanical-draft wet (only) cooling tower system, the
proximity of the cooling tower and plume to an elevated interstate and many of the United States primary landmarks
is striking. The thirty-foottall cooling tower system frequently projects a vapor plume that extends across and into
several lanes of traffic along one of the nation's busiest interstates, an elevated highway. The Pawtucket Power
Station near Providence is another small plant situated adjacent to a major highway. The mechanical draft cooling
towers of this 70-MW plant produce plumes in the winter inNew England that the Agency observed migrating across
1-95 and several stories high. The Agency considers these examples of wet cooling towers in close proximity to
transportation routes and in cold climates as examples of a relatively pervasive practice.
The Agency contacted Bergen Station regarding their cooling tower system, which is within 700 feet of the New
Jersey Turnpike (and nearby to a bridge on the same road). Bergen Station conducted a study of the possible plume
impacts to the interstate. The model (a SACTImodel) projected a 1-hour impact within a 5-year period. The station
mitigated this risk by installing a hybrid-wet/dry cooling system that employs several cells of wet (only) units. The
plant has the capability to switch between wet and dry modes and operates under the hybrid mode duringthe winter
and, on occasion, during humid days in the spring for aesthetic reasons (US EPA Reg. I, 2002).
The Agency also consulted the detailed historical study conducted by four Hudson River steam-electric plants
(Central Hudson Gas & Electric, 1977). The report examined the environmental and economic impacts from the
potential installation and operation of natural-draft wet (only) cooling towers at Bowline Point, Indian Point 2 and
3, and Roseton Generating Stations along the Hudson River in New York. The calculation of multi-plant induced
fog and icing impacts from the potential operation of 4 large natural-draft wet cooling towers was, "not expected to
be substantial." The Agency notes that this analysis focused on the operation of natural-draft wet cooling towers,
which have significantly larger and taller plumes than mechanical-draft wet cooling towers (the modern basis for the
vast majority of new cooling tower construction in the United States). Therefore, the effects of potential mechanical-
draft units would be even less than those studied.
Considering the evidence that it collected, the Agency determined that it should examine the sensitivity of compliance
costs for certain regulatory options based on the installation of plume abatement technologies at a small portion of
facilities expected to retrofit their cooling systems. Therefore, the Agency examined the sensitivity of the overall
national costs of regulatory option 1 (that is, the option based on flow reduction and installation of closed-cycle
cooling systems at approximately 53 facilities) to plume abatement installation costs at 3 facilities (that is, 6 percent
of 53). The overall impact on the annual compliance costs for regulatory option 1 was an increase of approximately
2 percent. Thisis based on the calculation of increased cooling system retrofit capital costs as discussed above (that
is, a conservative 65 percent increase of overall project-capital costs for three plants with compliance costs centered
6- 7
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§ 316(b) Phase II TDD Non-water Quality Impacts
about the median) and O&M increases as estimated by the operation multiplier factors recommended in literature
(Mirsky, et al., 1992). If as many as 6 facilities out of 53 (that is, a 3 fold increase over the percentage estimated by
the reputable tower supplier) would adopt plume abatement installation costs, the impact on the option's annual
compliance costs would be approximately a 4 percent increase. Based on the evidence gathered by the Agency,
installation of plume abatement at more than 10 percent of the facilities projected to convert cooling systems as a
result of regulatory option 1 would not be probable.
6.3 DISPLACEMENT OF WETLANDS OR OTHER LAND HABITATS
Mechanical draft cooling towers can require land areas (footprints) approaching 1.5 acres for the average sized new
cooling tower projected for this rule. The land requirements of mechanical draft wet cooling towers do not approach
the size of the campus. In consideration of displacement of wetlands or other land and habitat due to the moderate
plant size increases due to cooling tower installations at nine facilities, the Agency determined that existing 404
programs would more than adequately protect wetlands and habitats for these modest land uses. In addition, the
displacement of wetlands on an industrial site such as a large existing power plant is not a probable outcome of
cooling tower construction, in the Agency's opinion.
6.4 SALT OR MINERAL DRIFT
The operation of cooling towers using either brackish water or salt water can release water droplets containing
soluble salts, including sodium, calcium, chloride, and sulfate ions. Additionally, salt drift may occur at fresh water
systems that operate re circulating cooling water systems at very high cycles of concentration. Salt drift from such
towers may be carried by prevailing winds and settle onto soil, vegetation, and waterbodies. The DOE expressed
concern to the Agencythat salt drift may be problematic forthe types of plants potentially subject to the regulatory
option 1. This could cause damage to crops through deposition directly on the plants or accumulation of salts in the
soil. The cooling tower system design and the salt content of the source water are the primary factors affecting the
amount of salt emitted as drift. In addition, modern cooling towers utilize inexpensive drift reducing technologies
(called drift eliminators) that have been developed to minimize salt or mineral drift effects.
In the cases where it is necessary, salt drift effects (if any) may also be mitigated by additional means that are similar
to those used to minimize migrating vapor plumes (that is, through acquisition of buffer land area surrounding the
tower). Additionally, modern cooling towers are designed as to minimize drift through the use of drift elimination
technologies. The Agency has considered the capital costs forthe abatement of drift for all model plants projected
to install cooling towers through regulatory option 1. The approximate change in total annual compliance costs for
this option would be less than 1 percent. High efficiency drift eliminators, which reduce drift by an order of
magnitude, increase the capital cost of a cooling tower unit (which, as in the case of plume abatement above, is a
portion of the total project costs for a retrofit cooling system) by approximately 4 percent and the fan brake
horsepower by a similar margin (Mirsky, et al., 1992). These increases, as evidenced by the approximate analysis
conducted by the Agency, show very minimal cost impacts on regulatory Option 1.
NUREG-1437 states the following concerning salt/mineral drift from cooling towers: "generally, drift from cooling
towers using fresh water has low salt concentrations and, in 1he case of mechanical drafttowers, falls mostly wilhin
the immediate vicinity of the towers, representing little hazard to vegetation off-site. Typical amounts of salt or total
dissolved solids in freshwater environments are around 1000 ppm (ANL/ES-53)." The conclusions reached in
NUREG about salt-drift upon extensive study at existing nuclear plants: "monitoring results from the sample of
[eighteen] nuclear plants and from the coal-fired Chalk Point plant, in conjunction with the literature review and
information provided by the natural resource agencies and agricultural agencies in all states with nuclear power
plants, have revealed no instances where cooling tower operation has resulted in measurable productivity losses in
agricultural crops or measurable damage to ornamental vegetation. Because ongoing operational conditions of cooling
6-8
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§ 316(b) Phase II TDD Non-water Quality Impacts
towers would remain unchanged, it is expected that there would continue to be no measurable impacts on crops or
ornamental vegetation as a result of license renewal. The impact of cooling towers on agricultural crops and
ornamental vegetation will thereforebe of small significance. Because thereis no measurable impact, there is no need
to consider mitigation. Cumulative impacts on crops and ornamental vegetation are not a consideration because
deposition from cooling tower drift is a localized phenomenon and because of the distance between nuclear power
plant sites and other facilities that may have large cooling towers."
The historical study conducted by Central Hudson, et al. (1977) examined the economic and environmental impacts
of drift from the four estuarine power plants along the Hudson - Bowline Point, Indian Point 2 and 3, and Roseton
Generating Station - for proposed natural draft cooling tower systems. The analysis found the total economic impact
from drift damage to vegetation to range from $226,000 to $654,000 (sum present worth -1977 $). In the Agency's
view, these economic impacts are relatively small in comparison to the quantified benefits of entrainment reduction.
6.5 NOISE
Noise from mechanical draft cooling towers is generated by falling water inside the towers plus fan or motor noise
or both. However, power plant sites generally do not result in off-site levels more than 10 dB(A) above background
(NUREG-1437Vol. 1). Noise abatement features are an integral and inexpensive component of modern cooling tower
designs (See Appendix B, Charts 2-1 through 2-6 for a comparison of low-noise tower costs and other types of tower
modifiers). The cost contribution of low noise fans would comprise a very small portion of the total installed capital
cost of a retrofitted cooling system (on the same order as drift elimination technologies). As such, the Agency is
confident that the issue of noise abatement is not critical to the evaluation ofthe environmental side-effects of cooling
towers. In addition, this issue is primarily in terms of adverse public reactions to the noise and not environmental
or human health (i.e., hearing) impacts. The NRC adds further, "Natural-draft and mechanical -draft cooling towers
emit noise of a broadband nature...Because ofthe broadband character ofthe cooling towers, the noise associated
with them is largely indistinguishable and less obtrusive than transformer noise or loudspeaker noise."
6.6 SOLID WASTE GENERATION
For cooling towers, recirculation of cooling water increases solid wastes generated because some facilities treat the
cooling tower blowdown in a wastewater treatment system, and the concentrated pollutants removed from the
blowdown add to the amount of wastewater sludge generated by the racility. For facilities operating coolingtowers
with brackish or saline waters, the concentration of salts within the tower and blowdown are a primary design factor.
As such, these systems can have elevated salt concentrations over most freshwater sources. However, the
concentration of salts is a treatable condition for blowdown from towers. The costing model adopted by the Agency
for the capital and O&M costs of cooling towers accounts for the treatment of tower blow-down (see Chapter 2).
The increase in solids wastes would be a manageable problem for option 1, where approximately 53 coolingtowers
would be installed under the considered option. However, for all 539 facilities (a ten fold increase) the issue of solids
waste disposal may take on a greater concern to the Agency.
6.7 EVAPORATIVE CONSUMPTION OF WATER
Cooling tower operation is designed to result in a measurable evaporation of water drawn from the source water.
Depending on the size and flow conditions ofthe affected waterbody, evaporative water loss can affect the quality
of aquatic habitat and recreational fishing. Once-through cooling consumes water, in and of itself. According to
NUREG-1437, "water lost by evaporation from the heated discharge of once-through cooling is about 60 percent of
that which is lost through cooling towers." NUREG-1437 goes on to further state, "with once-through cooling
systems, evaporative losses...occur externally in the adjacent body of water instead of in the closed-cycle system."
Therefore, evaporation does occur due to heating of water in once-through cooling systems, even though the majority
6-9
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§ 316(b) Phase II TDD Non-water Quality Impacts
of this loss happens down-stream of the plant in the receiving water body. The Agency notes that for option 1, the
only cooling towers projected tobe installed would be in saline andbrackish waters. Competing uses for these waters
is not as great a concern as that for freshwater. As such, the Agency did not quantitatively determine water
consumption levels for this considered regulatory option. For considered options in which cooling towers were
projected in freshwaters, the Agency determined that the option was economically impracticable, and as such, did
not complete a quantitative analysis of the consumptive water use of this option.
6-10
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§ 316(b) Phase II TDD Non-water Quality Impacts
REFERENCES
BDT Engineering, November 2000, Hybrid Cooling Tower Product Brochure.
Burns, J. M. and Micheletti, W. C., 2000, "Comparison of Wet and Dry Cooling Systems for Combined Cycle Power
Plants," submitted as Appendix F to the comments of the Utility Water Act Group on the 316(b) New Facility
Proposed Rule.
Central Hudson Gas & Electric, Consolidated Edison Company of New York, Orange and Rockland Utilities, and
Power Authority of The State of New York, 1977, "Report on Cost-benefit Analysis of Operation of Hudson River
Steam-Electric Units with Once-through and Closed-cycle Cooling Systems."
Environmental Protection Agency. September 2001. The Emissions & Generation Resource Integrated Database
2000 (E-GRID 2000). Version 2.0. http://www.epa.gov/airmarkets/egrid/index.html
Mirsky, G.R., et al., 1992. The Latest Worldwide Technology in Environmentally Designed Cooling Towers.
Cooling Tower Institute 1992 Annual Meeting Technical Paper Number TP92-02.
Nuclear Regulatory Commission. 1996. Generic Environmental Impact Statement for license Renewal of Nuclear
Plants. NUREG-1437 Vol. 1. http://www.nrc.gov/docs/nuregs/staff/srl437/Vl/srl437vl.html#_l_128
Power Tech Associates, P.C., 1999, "Economic and Environmental Review of Closed Cooling Water Systems for
the Hudson River Power Plants," Appendix VIII-3 of the Draft Environmental Impact Statement for Bowline Point,
Roseton, and Indian Point 2 and 3.
U.S. EPA, Region I, February 2002; Phone Memorandum between Region land Bergen Station, Public Service of
NJ.
U.S. EPA, 2002, "Examples of Existing Plants with Wet Towers in Northern Climates and in Close Proximity to
Transportation Routes."
6-11
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§ 316(b) Phase II TDD Non-water Quality Impacts
This Page Intentionally Left Blank
6-12
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§ 316(b) Phase II TDD Appendix A
Appendix A: Compliance Cost Estimates for the
Proposed Rule
In order to execute the option for determining whether the compliance costs of a facility are
significantly greater than those considered for this rule, the compliance cost estimates prepared by the
Agency provide the basis of comparison for permit writers and regulated entities. In the case where a
facility' s compliance costs are significantly greater than those considered by the Agency, the proposed rule
states that the facility would qualify for a site-specific determination of the best technology available. In that
case the Director would approve less costlytechnologies to the extent justified by the significantly greater
cost. To document that its site-specific costs would be significantly greater than those EPA considered, the
facility would need to develop engineering cost estimates as part of its Comprehensive Cost Evaluation
Study. The facility would then consider the model plants presented herein, determine which model plantmost
closely matches its fuel source, mode of electricity generation, e xisting intake technologies, waterbody type,
geographic location, and intake flow and compare its engineering estimates to EPA's estimated cost for this
model plant. The Agency notes that geographic location (an important factor for the consideration of
installation capital costs) is not included in the datapresented here. This is due to the fact that the Agency,
at this juncture, could not reconcile a means to protect a limitedamount of confidential business information
claimed by respondents to the questionnaires and the need to provide this data to the public for the purposes
of evaluating this proposed cost test option. The Agency has worked diligently to protect confidential
information and, yet, meet the needs of presenting information to the public. In the interests of refining the
information for the final rule, the Agency intends to follow-up on this manner and determine a means of
incorporating geographic location without compromising the confidentiality of a limited amount of
information claimed by respondents to the questionnaires.
To adequately demonstrate site-specific compliance costs, EPA believes that a facility would need
to provide engineering cost estimates that are sufficiently detailed to allow review by a third party. The
preferred cost estimating methodology, in the Agency's view, is the adaption of empirical costs from similar
projects tailored to the facility's characteristics. The submission of generic costs relying on engineering
judgment should be verified with empirical data wherever possible. In the cases where empirical
demonstration costs are not available, the level of detail should allow the costs to be reproduced using
standard construction engineering unit cost databases. These costs should be supported by estimates from
architectural and engineering firms. Further, the engineering assumptions forming the basis of the cost
estimates should be clearly documented for the key cost items.
The Agency and other regulatory entities have reviewed recent cost estimates submitted by
permittees for several section 316(b) and 316(a) demonstrations. As discussed in Appendix C, where the
level of detail provided by the permittee was sufficient to afford a detailed review, EPA has some concerns
about the magnitude of these cost estimates. In other cases, the engineering assumptions that formed the
basis of the cost submissions were insufficiently documented to afford a critical review. Based in part on
these examples, 1he Agency emphasizes the importance of empirically verified and well documented
engineering cost submissions.
A-l
-------
§ 316(b) Phase II TDD
Appendix A
Model Plant Compliance Costs for the Section 316(b) Existing Facility Proposed Rule
Plant
Code*
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
Water Body Type
Estuary/Tidal Riv
Fresh Stream/Rv
Fresh Stream/Rv
Lake/Reservoir
Fresh Stream/Rv
Lake/Reservoir
Estuary/Tidal Riv
Fresh Stream/Rv
Lake/Reservoir
Estuary/Tidal Riv
Lake/Reservoir
Lake/Reservoir
Fresh Stream/Rv
Fresh Stream/Rv
Estuary/Tidal Riv
Fresh Stream/Rv
Estuary/Tidal Riv
Lake/Reservoir
Fresh Stream/Rv
Lake/Reservoir
Estuary/Tidal Riv
Estuary/Tidal Riv
Lake/Reservoir
Fresh Stream/Rv
Fresh Stream/Rv
Lake/Reservoir
Estuary/Tidal Riv
Steam Plant Design Baseline
Fuel Type Intake Cooling
Flow (gpm) System **
Coal
Coal
Coal
Other
Coal
Other
Coal
Nuclear
Coal
Oil
Coal
Other
Other
Coal
Coal
-
Coal
Coal
Coal
Other
Other
Other
Nuclear
Coal
Coal
Other
Other
190,000 Combination
360,000 OnceThrough
68,000 Combination
980,000 OnceThrough
220,000 OnceThrough
330,000 OnceThrough
500,000 OnceThrough
1,450,000 Recirculating
950,000 Recirculating
2,560,000 OnceThrough
290,000 OnceThrough
1,460,000 OnceThrough
680,000 Combination
400,000 OnceThrough
570,000 OnceThrough
690,000 OnceThrough
520,000 Other
580,000 OnceThrough
410,000 OnceThrough
760,000 OnceThrough
60,000 OnceThrough
1,100,000 OnceThrough
120,000 Recirculating
48,000 Recirculating
270,000 OnceThrough
910,000 OnceThrough
350,000 OnceThrough
Passive Fish Handling Compliance CWIS Technology
Intake? and/ or Modification
Return?
No
No
No
No
No
No
No
Yes
No
No
Yes
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
Yes
No
Yes
No
No
No
No
No
No
Yes
Yes
No
No
No
No
No
No
No
No
No
Yes
No
No
Yes
No
Yes
Fine Mesh Trav w/ Fish Handling
None
Fine Mesh Trav w/ Fish Handling
None
Fine Mesh Trav w/ Fish Handling
Fish Handling and Return System
Fine Mesh Trav w/ Fish Handling
None
None
None
None
None
Fine Mesh Trav w/ Fish Handling
None
Fine Mesh Trav w/ Fish Handling
None
Fine Mesh Trav w/ Fish Handling
Fish Handling and Return System
Fish Handling and Return System
Fish Handling and Return System
Fine Mesh Trav w/ Fish Handling
Fine Mesh Traveling Screen
None
None
None
Fish Handling and Return System
Fine Mesh Traveling Screen
CWIS Technolgy
Retrofit Capital
Cost
$1,805,761
$0
$835,790
$0
$1,858,940
$660,652
$3,676,159
$0
$0
$0
$0
$0
$6,414,541
$0
$5,462,857
$0
$3,412,701
$1,152,074
$981,350
$1,494,307
$630,600
$5,996,854
$0
$0
$0
$2,383,489
$2,596,753
Total Capital Intake CWIS Total O&M
Technology O&M Costs
$1,805,761
$0
$835,790
$0
$1,858,940
$660,652
$3,676,159
$0
$0
$0
$0
$0
$6,414,541
$0
$5,462,857
$0
$3,412,701
$1,152,074
$981,350
$1,494,307
$630,600
$5,996,854
$0
$0
$0
$2,383,489
$2,596,753
$47,101
$0
$25,450
$0
$51,560
$23,416
$130,875
$0
$0
$0
$0
$0
$177,697
$0
$142,194
$0
$134,395
$39,823
$27,619
$52,216
$20,915
$179,811
$0
$0
$0
$63,722
$63,142
$47,101
$0
$25,450
$0
$51,560
$23,416
$130,875
$0
$0
$0
$0
$0
$177,697
$0
$142,194
$0
$134,395
$39,823
$27,619
$52,216
$20,915
$179,811
$0
$0
$0
$63,722
$63,142
Annual
Monitoring
Cost
$90,000
$75,000
$75,000
$75,000
$75,000
$75,000
$90,000
$75,000
$75,000
$90,000
$75,000
$75,000
$75,000
$75,000
$90,000
$75,000
$90,000
$75,000
$75,000
$75,000
$90,000
$90,000
$75,000
$75,000
$75,000
$75,000
$90,000
A-2
-------
§ 316(b) Phase II TDD
Appendix A
Model Plant Compliance Costs for the Section 316(b) Existing Facility Proposed Rule
Plant
Code*
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
50
51
52
53
54
55
Water Body Type
Estuary/Tidal Riv
Lake/Reservoir
Estuary/Tidal Riv
Estuary/Tidal Riv
Ocean
Lake/Reservoir
Fresh Stream/Rv
Fresh Stream/Rv
Fresh Stream/Rv
Estuary/Tidal Riv
Fresh Stream/Rv
Ocean
Lake/Reservoir
Estuary/Tidal Riv
Fresh Stream/Rv
Fresh Stream/Rv
Estuary/Tidal Riv
Lake/Reservoir
Estuary/Tidal Riv
Lake/Reservoir
Estuary/Tidal Riv
Estuary/Tidal Riv
Lake/Reservoir
Lake/Reservoir
Fresh Stream/Rv
Fresh Stream/Rv
Fresh Stream/Rv
Fresh Stream/Rv
Steam Plant Design Baseline
Fuel Type Intake Cooling
Flow (gpm) System **
Nuclear
Coal
Coal
Oil
Nuclear
Nuclear
Coal
Other
Coal
Other
Other
Other
Other
Coal
Coal
Coal
Oil
Coal
Coal
Other
Oil
Other
Other
Coal
Coal
Coal
Coal
Coal
2,100,000 OnceThrough
270,000 OnceThrough
190,000 OnceThrough
750,000 Combination
1,850,000 OnceThrough
610,000 Recirculating
130,000 OnceThrough
1,060,000 OnceThrough
56,000 OnceThrough
770,000 OnceThrough
320,000 OnceThrough
520,000 OnceThrough
81,000 Recirculating
500,000 OnceThrough
89,000 OnceThrough
260,000 OnceThrough
2,450,000 OnceThrough
240,000 OnceThrough
61,000 Recirculating
340,000 OnceThrough
770,000 OnceThrough
280,000 OnceThrough
370,000 OnceThrough
79,000 Recirculating
63,000 OnceThrough
38,000 Recirculating
94,000 Combination
370,000 Combination
Passive Fish Handling Compliance CWIS Technology
Intake? and/ or Modification
Return?
No
No
No
Yes
No
No
No
No
No
No
No
No
No
No
Yes
No
No
Yes
No
No
No
No
No
No
No
No
No
No
Yes
No
No
No
No
No
No
Yes
No
Yes
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
Fine Mesh Traveling Screen
Fish Handling and Return System
Fine Mesh Trav w/ Fish Handling
Fish Handling and Return System
Fine Mesh Trav w/ Fish Handling
None
None
None
Fish Handling and Return System
Fine Mesh Traveling Screen
Fish Handling and Return System
Fish Handling and Return System
None
Fine Mesh Trav w/ Fish Handling
Fish Handling and Return System
Fish Handling and Return System
Fine Mesh Trav w/ Fish Handling
Fish Handling and Return System
Fine Mesh Trav w/ Fish Handling
Fish Handling and Return System
Fish Handling and Return System
Fine Mesh Trav w/ Fish Handling
Fish Handling and Return System
None
None
None
Fish Handling and Return System
Fish Handling and Return System
CWIS Technolgy
Retrofit Capital
Cost
$18,247,203
$619,002
$1,727,234
$1,651,646
$19,139,311
$0
$0
$0
$148,068
$4,367,081
$671,217
$1,421,831
$0
$3,989,369
$272,572
$640,529
$21,731,505
$628,037
$618,401
$685,536
$1,952,860
$2,160,144
$727,639
$0
$0
$0
$246,956
$922,742
Total Capital Intake CWIS Total O&M
Technology O&M Costs
$18,247,203
$619,002
$1,727,234
$1,651,646
$19,139,311
$0
$0
$0
$148,068
$4,367,081
$671,217
$1,421,831
$0
$3,989,369
$272,572
$640,529
$21,731,505
$628,037
$618,401
$685,536
$1,952,860
$2,160,144
$727,639
$0
$0
$0
$246,956
$922,742
$349,615
$20,420
$47,075
$51,765
$449,533
$0
$0
$0
$4,864
$133,295
$22,837
$36,956
$0
$131,120
$7,453
$19,768
$578,568
$18,615
$0
$24,217
$52,985
$78,597
$25,525
$0
$0
$0
$7,739
$25,892
$349,615
$20,420
$47,075
$51,765
$449,533
$0
$0
$0
$4,864
$133,295
$22,837
$36,956
$0
$131,120
$7,453
$19,768
$578,568
$18,615
$0
$24,217
$52,985
$78,597
$25,525
$0
$0
$0
$7,739
$25,892
Annual
Monitoring
Cost
$90,000
$75,000
$90,000
$90,000
$90,000
$75,000
$75,000
$75,000
$75,000
$90,000
$75,000
$90,000
$75,000
$90,000
$75,000
$75,000
$90,000
$75,000
$90,000
$75,000
$90,000
$90,000
$75,000
$75,000
$75,000
$75,000
$75,000
$75,000
A-3
-------
§ 316(b) Phase II TDD
Appendix A
Model Plant Compliance Costs for the Section 316(b) Existing Facility Proposed Rule
Plant
Code*
56
57
58
59
60
61
62
63
64
65
66
67
68
69
70
71
72
73
74
75
76
77
78
79
80
81
82
83
Water Body Type
Fresh Stream/Rv
Lake/Reservoir
Fresh Stream/Rv
Fresh Stream/Rv
Fresh Stream/Rv
Lake/Reservoir
Fresh Stream/Rv
Lake/Reservoir
Fresh Stream/Rv
Estuary/Tidal Riv
Estuary/Tidal Riv
Ocean
Fresh Stream/Rv
Ocean
Ocean
Fresh Stream/Rv
Fresh Stream/Rv
Fresh Stream/Rv
Ocean
Fresh Stream/Rv
Fresh Stream/Rv
Lake/Reservoir
Fresh Stream/Rv
Lake/Reservoir
Estuary/Tidal Riv
Lake/Reservoir
Fresh Stream/Rv
Fresh Stream/Rv
Steam Plant
Fuel Type
Coal
Nuclear
Coal
Nuclear
Coal
Other
Coal
Oil
Other
Other
Other
Other
Coal
Other
Nuclear
Coal
Coal
Coal
Comb Cycle
Other
Other
Nuclear
Coal
Coal
Other
Coal
Coal
Coal
Design Baseline
Intake Cooling
Flow (gpm) System **
64,000 OnceThrough
50,000 Recirculating
470,000 OnceThrough
68,000 Recirculating
66,000 OnceThrough
500,000 OnceThrough
310,000 OnceThrough
400,000 OnceThrough
45,000 OnceThrough
300,000 Combination
600,000 OnceThrough
250,000 OnceThrough
190,000 OnceThrough
180,000 OnceThrough
2,110,000 OnceThrough
230,000 OnceThrough
290,000 OnceThrough
170,000 OnceThrough
77,000 OnceThrough
52,000 OnceThrough
51,000 OnceThrough
510,000 OnceThrough
230,000 OnceThrough
680,000 Recirculating
420,000 OnceThrough
310,000 Recirculating
120,000 Recirculating
130,000 OnceThrough
Passive Fish Handling Compliance CWIS Technology
Intake? and/ or Modification
Return?
No
No
Yes
No
No
No
Yes
No
No
No
No
Yes
No
No
Yes
Yes
No
No
No
No
No
Yes
No
Yes
No
Yes
No
No
No
No
No
No
No
No
Yes
Yes
No
No
Yes
No
No
No
Yes
No
No
No
No
No
No
No
Yes
Yes
No
No
No
No
Fish Handling and Return System
None
None
None
None
Fish Handling and Return System
Fine Mesh Traveling Screen
None
Fish Handling and Return System
None
Fine Mesh Traveling Screen
None
Fine Mesh Trav w/ Fish Handling
Fine Mesh Trav w/ Fish Handling
Fine Mesh Traveling Screen
Fish Handling and Return System
Fine Mesh Trav w/ Fish Handling
Fish Handling and Return System
Fine Mesh Trav w/ Fish Handling
None
Fine Mesh Trav w/ Fish Handling
Fish Handling and Return System
None
None
Fine Mesh Trav w/ Fish Handling
None
None
Fine Mesh Trav w/ Fish Handling
CWIS Technolgy
Retrofit Capital
Cost
$194,875
$0
$0
$0
$0
$1,013,679
$2,198,242
$0
$136,324
$0
$3,271,616
$0
$1,672,082
$1,731,569
$18,025,893
$515,448
$2,638,235
$353,994
$935,072
$0
$430,310
$1,323,813
$0
$0
$3,894,496
$0
$0
$1,155,458
Total Capital Intake CWIS Total O&M
Technology O&M Costs
$194,875
$0
$0
$0
$0
$1,013,679
$2,198,242
$0
$136,324
$0
$3,271,616
$0
$1,672,082
$1,731,569
$18,025,893
$515,448
$2,638,235
$353,994
$935,072
$0
$430,310
$1,323,813
$0
$0
$3,894,496
$0
$0
$1,155,458
$6,013
$0
$0
$0
$0
$35,857
$59,178
$0
$4,215
$0
$101,715
$0
$47,931
$46,197
$350,546
$17,883
$80,265
$11,888
$27,151
$0
$18,797
$36,406
$0
$0
$100,601
$0
$0
$37,459
$6,013
$0
$0
$0
$0
$35,857
$59,178
$0
$4,215
$0
$101,715
$0
$47,931
$46,197
$350,546
$17,883
$80,265
$11,888
$27,151
$0
$18,797
$36,406
$0
$0
$100,601
$0
$0
$37,459
Annual
Monitoring
Cost
$75,000
$75,000
$75,000
$75,000
$75,000
$75,000
$75,000
$75,000
$75,000
$90,000
$90,000
$90,000
$75,000
$90,000
$90,000
$75,000
$75,000
$75,000
$90,000
$75,000
$75,000
$75,000
$75,000
$75,000
$90,000
$75,000
$75,000
$75,000
A-4
-------
§ 316(b) Phase II TDD
Appendix A
Model Plant Compliance Costs for the Section 316(b) Existing Facility Proposed Rule
Plant
Code*
84
85
86
87
88
89
90
91
92
93
94
95
96
97
98
99
100
101
102
103
104
105
106
107
108
109
110
111
Water Body Type
Lake/Reservoir
Lake/Reservoir
Estuary/Tidal Riv
Estuary/Tidal Riv
Lake/Reservoir
Lake/Reservoir
Ocean
Lake/Reservoir
Lake/Reservoir
Estuary/Tidal Riv
Fresh Stream/Rv
Fresh Stream/Rv
Fresh Stream/Rv
Lake/Reservoir
Fresh Stream/Rv
Fresh Stream/Rv
Fresh Stream/Rv
Lake/Reservoir
Fresh Stream/Rv
Estuary/Tidal Riv
Estuary/Tidal Riv
Lake/Reservoir
Fresh Stream/Rv
Lake/Reservoir
Estuary/Tidal Riv
Fresh Stream/Rv
Fresh Stream/Rv
Estuary/Tidal Riv
Steam Plant Design Baseline
Fuel Type Intake Cooling
Flow (gpm) System **
Other
Coal
Oil
Other
Nuclear
Other
Oil
Other
Coal
Oil
Coal
Coal
Coal
Nuclear
Coal
Coal
Coal
Nuclear
Other
Coal
Coal
Other
Coal
Coal
Coal
Coal
Coal
Other
160,000 OnceThrough
370,000 Recirculating
960,000 OnceThrough
120,000 OnceThrough
460,000 OnceThrough
66,000 OnceThrough
690,000 OnceThrough
130,000 OnceThrough
45,000 Recirculating
1,230,000 OnceThrough
150,000 OnceThrough
310,000 OnceThrough
60,000 OnceThrough
450,000 OnceThrough
500,000 OnceThrough
52,000 Combination
1,090,000 OnceThrough
59,000 Combination
1,330,000 Recirculating
320,000 OnceThrough
290,000 Combination
2,130,000 Recirculating
2,570,000 Recirculating
140,000 OnceThrough
790,000 OnceThrough
390,000 OnceThrough
410,000 OnceThrough
300,000 OnceThrough
Passive Fish Handling Compliance CWIS Technology
Intake? and/ or Modification
Return?
No
No
No
Yes
No
No
No
No
Yes
No
No
No
No
No
No
No
No
No
No
No
No
Yes
No
No
No
No
No
No
No
No
No
No
Yes
No
No
No
Yes
Yes
No
No
Yes
Yes
Yes
No
No
No
No
Yes
Yes
Yes
No
No
No
No
No
No
Fish Handling and Return System
None
Fine Mesh Trav w/ Fish Handling
Fine Mesh Trav w/ Fish Handling
None
Fish Handling and Return System
Fine Mesh Trav w/ Fish Handling
Fish Handling and Return System
None
Fine Mesh Traveling Screen
Fine Mesh Trav w/ Fish Handling
None
None
None
Fine Mesh Traveling Screen
Fish Handling and Return System
Fish Handling and Return System
None
None
Fine Mesh Traveling Screen
Fine Mesh Traveling Screen
None
None
Fish Handling and Return System
None
Fine Mesh Trav w/ Fish Handling
None
Fine Mesh Trav w/ Fish Handling
CWIS Technolgy
Retrofit Capital
Cost
$327,227
$0
$8,491 ,006
$1,046,549
$0
$162,937
$7,550,835
$276,698
$0
$7,473,140
$1,321,383
$0
$0
$0
$3,151,370
$116,865
$2,427,985
$0
$0
$2,333,617
$2,168,475
$0
$0
$366,143
$0
$3,167,570
$0
$2,807,761
Total Capital Intake CWIS Total O&M
Technology O&M Costs
$327,227
$0
$8,491 ,006
$1,046,549
$0
$162,937
$7,550,835
$276,698
$0
$7,473,140
$1,321,383
$0
$0
$0
$3,151,370
$116,865
$2,427,985
$0
$0
$2,333,617
$2,168,475
$0
$0
$366,143
$0
$3,167,570
$0
$2,807,761
$11,607
$0
$239,747
$35,490
$0
$6,132
$179,251
$9,644
$0
$206,406
$41,419
$0
$0
$0
$91,926
$4,641
$71,333
$0
$0
$59,460
$56,716
$0
$0
$10,484
$0
$97,102
$0
$81,333
$11,607
$0
$239,747
$35,490
$0
$6,132
$179,251
$9,644
$0
$206,406
$41,419
$0
$0
$0
$91,926
$4,641
$71,333
$0
$0
$59,460
$56,716
$0
$0
$10,484
$0
$97,102
$0
$81,333
Annual
Monitoring
Cost
$75,000
$75,000
$90,000
$90,000
$75,000
$75,000
$90,000
$75,000
$75,000
$90,000
$75,000
$75,000
$75,000
$75,000
$75,000
$75,000
$75,000
$75,000
$75,000
$90,000
$90,000
$75,000
$75,000
$75,000
$90,000
$75,000
$75,000
$90,000
A-5
-------
§ 316(b) Phase II TDD
Appendix A
Model Plant Compliance Costs for the Section 316(b) Existing Facility Proposed Rule
Plant
Code*
112
113
114
115
116
117
118
119
120
121
122
123
124
125
126
127
128
129
130
131
132
133
134
135
136
137
138
139
Water Body Type
Estuary/Tidal Riv
Lake/Reservoir
Great Lake
Lake/Reservoir
Lake/Reservoir
Estuary/Tidal Riv
Fresh Stream/Rv
Fresh Stream/Rv
Lake/Reservoir
Fresh Stream/Rv
Fresh Stream/Rv
Lake/Reservoir
Fresh Stream/Rv
Fresh Stream/Rv
Estuary/Tidal Riv
Fresh Stream/Rv
Estuary/Tidal Riv
Estuary/Tidal Riv
Ocean
Lake/Reservoir
Lake/Reservoir
Lake/Reservoir
Lake/Reservoir
Estuary/Tidal Riv
Fresh Stream/Rv
Lake/Reservoir
Estuary/Tidal Riv
Estuary/Tidal Riv
Steam Plant Design Baseline
Fuel Type Intake Cooling
Flow (gpm) System **
Coal
Nuclear
Coal
Nuclear
Other
Nuclear
Coal
Nuclear
Coal
Coal
Coal
Other
Coal
Coal
Other
Coal
Coal
Other
Other
Other
Coal
Other
Coal
Other
Coal
Coal
Nuclear
Oil
230,000 Combination
890,000 OnceThrough
910,000 OnceThrough
110,000 Recirculating
180,000 OnceThrough
1,210,000 OnceThrough
66,000 Combination
650,000 Combination
450,000 OnceThrough
210,000 Combination
920,000 OnceThrough
73,000 Recirculating
500,000 OnceThrough
51 ,000 Combination
420,000 OnceThrough
290,000 OnceThrough
140,000 OnceThrough
1,080,000 OnceThrough
120,000 OnceThrough
580,000 Recirculating
1,020,000 OnceThrough
210,000 OnceThrough
550,000 OnceThrough
370,000 OnceThrough
360,000 Combination
180,000 OnceThrough
780,000 OnceThrough
86,000 OnceThrough
Passive Fish Handling Compliance CWIS Technology
Intake? and/ or Modification
Return?
No
No
No
No
No
Yes
No
No
No
No
No
No
No
No
No
No
Yes
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
Yes
No
Yes
No
No
No
No
Yes
No
No
No
Yes
No
No
No
No
No
Yes
Yes
No
No
Yes
No
Fine Mesh Trav w/ Fish Handling
None
Fish Handling and Return System
None
Fish Handling and Return System
None
None
Fine Mesh Traveling Screen
Fish Handling and Return System
None
Fine Mesh Trav w/ Fish Handling
None
None
None
Fine Mesh Trav w/ Fish Handling
Fine Mesh Trav w/ Fish Handling
Fine Mesh Traveling Screen
Fish Handling and Return System
Fine Mesh Trav w/ Fish Handling
None
None
Fish Handling and Return System
None
Fine Mesh Traveling Screen
Fish Handling and Return System
None
Fine Mesh Traveling Screen
None
CWIS Technolgy
Retrofit Capital
Cost
$1,873,642
$0
$2,199,596
$0
$355,684
$0
$0
$5,379,051
$1,025,291
$0
$8,021 ,959
$0
$0
$0
$3,910,893
$2,652,473
$969,148
$2,127,820
$1,226,742
$0
$0
$408,905
$0
$2,684,782
$767,347
$0
$6,341,110
$0
Total Capital Intake CWIS Total O&M
Technology O&M Costs
$1,873,642
$0
$2,199,596
$0
$355,684
$0
$0
$5,379,051
$1,025,291
$0
$8,021 ,959
$0
$0
$0
$3,910,893
$2,652,473
$969,148
$2,127,820
$1,226,742
$0
$0
$408,905
$0
$2,684,782
$767,347
$0
$6,341,110
$0
$68,278
$0
$63,682
$0
$12,514
$0
$0
$106,937
$28,979
$0
$232,343
$0
$0
$0
$100,887
$80,641
$28,076
$71,248
$36,102
$0
$0
$14,030
$0
$64,671
$25,355
$0
$133,732
$0
$68,278
$0
$63,682
$0
$12,514
$0
$0
$106,937
$28,979
$0
$232,343
$0
$0
$0
$100,887
$80,641
$28,076
$71,248
$36,102
$0
$0
$14,030
$0
$64,671
$25,355
$0
$133,732
$0
Annual
Monitoring
Cost
$90,000
$75,000
$75,000
$75,000
$75,000
$90,000
$75,000
$75,000
$75,000
$75,000
$75,000
$75,000
$75,000
$75,000
$90,000
$75,000
$90,000
$90,000
$90,000
$75,000
$75,000
$75,000
$75,000
$90,000
$75,000
$75,000
$90,000
$90,000
A-6
-------
§ 316(b) Phase II TDD
Appendix A
Model Plant Compliance Costs for the Section 316(b) Existing Facility Proposed Rule
Plant
Code*
140
141
142
143
144
145
146
147
148
149
150
151
152
153
154
155
156
157
158
159
160
161
162
163
164
165
166
167
Water Body Type
Lake/Reservoir
Fresh Stream/Rv
Fresh Stream/Rv
Fresh Stream/Rv
Fresh Stream/Rv
Great Lake
Fresh Stream/Rv
Fresh Stream/Rv
Estuary/Tidal Riv
Great Lake
Estuary/Tidal Riv
Fresh Stream/Rv
Estuary/Tidal Riv
Fresh Stream/Rv
Estuary/Tidal Riv
Lake/Reservoir
Estuary/Tidal Riv
Fresh Stream/Rv
Fresh Stream/Rv
Estuary/Tidal Riv
Fresh Stream/Rv
Fresh Stream/Rv
Ocean
Fresh Stream/Rv
Estuary/Tidal Riv
Fresh Stream/Rv
Estuary/Tidal Riv
Lake/Reservoir
Steam Plant
Fuel Type
Comb Cycle
Coal
Coal
Oil
Coal
Coal
Coal
Coal
Comb Cycle
Coal
Other
Coal
Oil
Coal
Other
Nuclear
Oil
Nuclear
Coal
Nuclear
Nuclear
Coal
Other
Coal
Other
Coal
Nuclear
Other
Design Baseline
Intake Cooling
Flow (gpm) System **
190,000 Recirculating
170,000 OnceThrough
730,000 Combination
130,000 OnceThrough
260,000 OnceThrough
590,000 OnceThrough
250,000 OnceThrough
190,000 OnceThrough
370,000 OnceThrough
1,230,000 OnceThrough
1,120,000 OnceThrough
47,000 Recirculating
210,000 OnceThrough
140,000 OnceThrough
330,000 OnceThrough
510,000 Combination
530,000 OnceThrough
50,000 Recirculating
200,000 Combination
80,000 Recirculating
150,000 Recirculating
160,000 OnceThrough
1,680,000 OnceThrough
130,000 Recirculating
650,000 OnceThrough
450,000 OnceThrough
540,000 Recirculating
370,000 OnceThrough
Passive Fish Handling Compliance CWIS Technology
Intake? and/ or Modification
Return?
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
Yes
No
No
No
No
No
No
No
No
Yes
No
No
No
No
No
No
Yes
No
No
No
No
No
Yes
No
Yes
Yes
No
Yes
Yes
No
No
No
Yes
No
None
None
None
Fine Mesh Traveling Screen
Fine Mesh Trav w/ Fish Handling
Fine Mesh Trav w/ Fish Handling
Fish Handling and Return System
Fish Handling and Return System
Fine Mesh Trav w/ Fish Handling
Fine Mesh Trav w/ Fish Handling
Fine Mesh Traveling Screen
None
Fine Mesh Trav w/ Fish Handling
None
Fine Mesh Trav w/ Fish Handling
Fish Handling and Return System
Fine Mesh Traveling Screen
None
None
Fine Mesh Traveling Screen
None
None
None
None
Fish Handling and Return System
Fine Mesh Trav w/ Fish Handling
Fine Mesh Traveling Screen
Fish Handling and Return System
CWIS Technolgy
Retrofit Capital
Cost
$0
$0
$0
$805,636
$2,476,270
$5,096,487
$574,081
$433,686
$2,702,457
$10,370,446
$7,850,357
$0
$1,499,969
$0
$3,063,444
$961,373
$3,091 ,754
$0
$0
$925,206
$0
$0
$0
$0
$1,305,785
$3,143,587
$3,462,339
$960,544
Total Capital Intake CWIS Total O&M
Technology O&M Costs
$0
$0
$0
$805,636
$2,476,270
$5,096,487
$574,081
$433,686
$2,702,457
$10,370,446
$7,850,357
$0
$1,499,969
$0
$3,063,444
$961,373
$3,091 ,754
$0
$0
$925,206
$0
$0
$0
$0
$1,305,785
$3,143,587
$3,462,339
$960,544
$0
$0
$0
$26,003
$74,729
$145,462
$19,368
$13,093
$93,376
$299,579
$181,826
$0
$50,329
$0
$87,529
$36,025
$94,964
$0
$0
$20,477
$0
$0
$0
$0
$42,693
$105,377
$95,722
$25,654
$0
$0
$0
$26,003
$74,729
$145,462
$19,368
$13,093
$93,376
$299,579
$181,826
$0
$50,329
$0
$87,529
$36,025
$94,964
$0
$0
$20,477
$0
$0
$0
$0
$42,693
$105,377
$95,722
$25,654
Annual
Monitoring
Cost
$75,000
$75,000
$75,000
$75,000
$75,000
$75,000
$75,000
$75,000
$90,000
$75,000
$90,000
$75,000
$90,000
$75,000
$90,000
$75,000
$90,000
$75,000
$75,000
$90,000
$75,000
$75,000
$90,000
$75,000
$90,000
$75,000
$90,000
$75,000
A-7
-------
§ 316(b) Phase II TDD
Appendix A
Model Plant Compliance Costs for the Section 316(b) Existing Facility Proposed Rule
Plant
Code*
168
169
170
171
172
173
174
175
176
177
178
179
180
181
182
183
184
185
186
187
188
189
190
191
192
193
194
195
Water Body Type
Fresh Stream/Rv
Fresh Stream/Rv
Fresh Stream/Rv
Lake/Reservoir
Lake/Reservoir
Fresh Stream/Rv
Fresh Stream/Rv
Fresh Stream/Rv
Lake/Reservoir
Lake/Reservoir
Estuary/Tidal Riv
Lake/Reservoir
Lake/Reservoir
Fresh Stream/Rv
Fresh Stream/Rv
Lake/Reservoir
Fresh Stream/Rv
Ocean
Lake/Reservoir
Fresh Stream/Rv
Lake/Reservoir
Lake/Reservoir
Lake/Reservoir
Fresh Stream/Rv
Fresh Stream/Rv
Fresh Stream/Rv
Fresh Stream/Rv
Fresh Stream/Rv
Steam Plant
Fuel Type
Oil
Coal
Coal
Coal
Other
Other
Coal
Coal
Coal
Nuclear
Other
Coal
Other
Coal
Nuclear
Coal
Coal
Other
Coal
Nuclear
Coal
Coal
Coal
Coal
Comb Cycle
Coal
Coal
Coal
Design Baseline
Intake Cooling
Flow (gpm) System **
110,000 OnceThrough
360,000 OnceThrough
5,350,000 OnceThrough
170,000 OnceThrough
440,000 OnceThrough
620,000 OnceThrough
220,000 Recirculating
220,000 Combination
740,000 OnceThrough
1,910,000 OnceThrough
550,000 OnceThrough
440,000 OnceThrough
770,000 Recirculating
850,000 Combination
1,020,000 OnceThrough
770,000 OnceThrough
130,000 OnceThrough
89,000 OnceThrough
920,000 OnceThrough
470,000 OnceThrough
150,000 OnceThrough
630,000 OnceThrough
310,000 Recirculating
1,540,000 OnceThrough
43,000 Recirculating
610,000 OnceThrough
330,000 OnceThrough
50,000 Recirculating
Passive Fish Handling Compliance CWIS Technology
Intake? and/ or Modification
Return?
No
No
No
No
No
No
No
No
No
Yes
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
Yes
No
Yes
No
No
Yes
No
Yes
No
No
No
No
No
No
Yes
Yes
No
No
No
No
No
No
No
Fish Handling and Return System
Fish Handling and Return System
Fine Mesh Trav w/ Fish Handling
Fish Handling and Return System
Fish Handling and Return System
Fine Mesh Traveling Screen
None
Fine Mesh Traveling Screen
Fish Handling and Return System
Fish Handling and Return System
None
Fish Handling and Return System
None
Fish Handling and Return System
Fish Handling and Return System
Fish Handling and Return System
Fine Mesh Trav w/ Fish Handling
None
None
None
None
None
None
Fine Mesh Trav w/ Fish Handling
None
Fine Mesh Trav w/ Fish Handling
Fine Mesh Trav w/ Fish Handling
None
CWIS Technolgy Totel Capital Intake CWIS Totel O&M
Retrofit Capital Technology O&M Costs
Cost
$287,461
$736,780
$45,223,779
$405,292
$843,501
$3,456,701
$0
$1,413,188
$1,475,184
$4,471 ,237
$0
$850,359
$0
$1,897,495
$2,469,785
$1,763,704
$1,318,605
$0
$0
$0
$0
$0
$0
$12,311,066
$0
$5,046,381
$2,378,321
$0
$287,461
$736,780
$45,223,779
$405,292
$843,501
$3,456,701
$0
$1,413,188
$1,475,184
$4,471 ,237
$0
$850,359
$0
$1,897,495
$2,469,785
$1,763,704
$1,318,605
$0
$0
$0
$0
$0
$0
$12,311,066
$0
$5,046,381
$2,378,321
$0
$8,473
$25,389
$1,262,104
$11,840
$28,694
$103,550
$0
$35,606
$51,319
$126,492
$0
$28,856
$0
$56,236
$68,455
$52,955
$37,764
$0
$0
$0
$0
$0
$0
$365,482
$0
$148,708
$85,979
$0
$8,473
$25,389
$1,262,104
$11,840
$28,694
$103,550
$0
$35,606
$51,319
$126,492
$0
$28,856
$0
$56,236
$68,455
$52,955
$37,764
$0
$0
$0
$0
$0
$0
$365,482
$0
$148,708
$85,979
$0
Annual
Monitoring
Cost
$75,000
$75,000
$75,000
$75,000
$75,000
$75,000
$75,000
$75,000
$75,000
$75,000
$90,000
$75,000
$75,000
$75,000
$75,000
$75,000
$75,000
$90,000
$75,000
$75,000
$75,000
$75,000
$75,000
$75,000
$75,000
$75,000
$75,000
$75,000
A-8
-------
§ 316(b) Phase II TDD
Appendix A
Model Plant Compliance Costs for the Section 316(b) Existing Facility Proposed Rule
Plant
Code*
196
197
198
199
200
201
202
203
204
205
206
207
208
209
210
211
212
213
214
215
216
217
218
219
220
221
222
223
Water Body Type
Lake/Reservoir
Fresh Stream/Rv
Lake/Reservoir
Lake/Reservoir
Fresh Stream/Rv
Lake/Reservoir
Fresh Stream/Rv
Fresh Stream/Rv
Estuary/Tidal Riv
Lake/Reservoir
Lake/Reservoir
Fresh Stream/Rv
Lake/Reservoir
Fresh Stream/Rv
Fresh Stream/Rv
Fresh Stream/Rv
Lake/Reservoir
Lake/Reservoir
Fresh Stream/Rv
Lake/Reservoir
Lake/Reservoir
Ocean
Fresh Stream/Rv
Fresh Stream/Rv
Fresh Stream/Rv
Lake/Reservoir
Fresh Stream/Rv
Fresh Stream/Rv
Steam Plant
Fuel Type
Other
Coal
Coal
Other
Coal
Coal
Coal
Coal
Nuclear
Nuclear
Nuclear
Coal
Nuclear
Coal
Coal
Coal
Other
Comb Cycle
Coal
Other
Coal
Nuclear
Coal
Coal
Other
Nuclear
Coal
Coal
Design Baseline
Intake Cooling
Flow (gpm) System **
420,000 OnceThrough
170,000 OnceThrough
550,000 Recirculating
500,000 OnceThrough
90,000 OnceThrough
1,510,000 OnceThrough
710,000 Combination
280,000 OnceThrough
1,000,000 OnceThrough
550,000 OnceThrough
200,000 Combination
120,000 OnceThrough
1,130,000 OnceThrough
230,000 OnceThrough
950,000 OnceThrough
420,000 Other
76,000 OnceThrough
77,000 Combination
200,000 OnceThrough
44,000 OnceThrough
140,000 Recirculating
560,000 OnceThrough
64,000 OnceThrough
70,000 Recirculating
260,000 Recirculating
79,000 Recirculating
160,000 OnceThrough
88,000 Recirculating
Passive Fish Handling Compliance CWIS Technology
Intake? and/ or Modification
Return?
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
Yes
No
No
No
No
No
No
No
No
Yes
No
No
No
No
No
Yes
No
No
Yes
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
None
Fish Handling and Return System
None
Fish Handling and Return System
Fish Handling and Return System
Fish Handling and Return System
Fine Mesh Trav w/ Fish Handling
Fine Mesh Trav w/ Fish Handling
Fine Mesh Traveling Screen
Fish Handling and Return System
None
None
Fish Handling and Return System
Fine Mesh Trav w/ Fish Handling
Fine Mesh Trav w/ Fish Handling
None
None
None
Fine Mesh Trav w/ Fish Handling
Fish Handling and Return System
None
None
Fish Handling and Return System
None
None
None
Fish Handling and Return System
None
CWIS Technolgy
Retrofit Capital
Cost
$0
$433,985
$0
$1,017,517
$209,422
$2,915,937
$6,000,929
$2,624,121
$8,707,797
$1,018,849
$0
$0
$2,310,521
$2,192,914
$7,906,569
$0
$0
$0
$1,693,858
$102,577
$0
$0
$147,805
$0
$0
$0
$331,890
$0
Total Capital Intake CWIS Total O&M
Technology O&M Costs
$0
$433,985
$0
$1,017,517
$209,422
$2,915,937
$6,000,929
$2,624,121
$8,707,797
$1,018,849
$0
$0
$2,310,521
$2,192,914
$7,906,569
$0
$0
$0
$1,693,858
$102,577
$0
$0
$147,805
$0
$0
$0
$331,890
$0
$0
$12,273
$0
$35,981
$7,499
$99,551
$182,006
$78,660
$169,706
$38,532
$0
$0
$78,289
$69,478
$236,873
$0
$0
$0
$49,004
$4,165
$0
$0
$6,027
$0
$0
$0
$11,364
$0
$0
$12,273
$0
$35,981
$7,499
$99,551
$182,006
$78,660
$169,706
$38,532
$0
$0
$78,289
$69,478
$236,873
$0
$0
$0
$49,004
$4,165
$0
$0
$6,027
$0
$0
$0
$11,364
$0
Annual
Monitoring
Cost
$75,000
$75,000
$75,000
$75,000
$75,000
$75,000
$75,000
$75,000
$90,000
$75,000
$75,000
$75,000
$75,000
$75,000
$75,000
$75,000
$75,000
$75,000
$75,000
$75,000
$75,000
$90,000
$75,000
$75,000
$75,000
$75,000
$75,000
$75,000
A-9
-------
§ 316(b) Phase II TDD
Appendix A
Model Plant Compliance Costs for the Section 316(b) Existing Facility Proposed Rule
Plant
Code*
224
225
226
227
228
229
230
231
232
233
234
235
236
237
238
239
240
241
242
243
244
245
246
247
248
249
250
251
Water Body Type
Lake/Reservoir
Ocean
Estuary/Tidal Riv
Estuary/Tidal Riv
Fresh Stream/Rv
Fresh Stream/Rv
Estuary/Tidal Riv
Ocean
Lake/Reservoir
Lake/Reservoir
Estuary/Tidal Riv
Fresh Stream/Rv
Estuary/Tidal Riv
Fresh Stream/Rv
Fresh Stream/Rv
Fresh Stream/Rv
Fresh Stream/Rv
Estuary/Tidal Riv
Lake/Reservoir
Fresh Stream/Rv
Fresh Stream/Rv
Lake/Reservoir
Fresh Stream/Rv
Lake/Reservoir
Estuary/Tidal Riv
Great Lake
Fresh Stream/Rv
Lake/Reservoir
Steam Plant Design Baseline
Fuel Type Intake Cooling
Flow (gpm) System **
Coal
Other
Oil
Other
Coal
Coal
Other
Nuclear
Coal
Oil
Other
Coal
Other
Oil
Coal
Coal
Other
Oil
Other
Nuclear
Coal
Coal
Coal
Coal
Other
Other
Coal
Other
820,000 OnceThrough
170,000 OnceThrough
560,000 OnceThrough
230,000 OnceThrough
73,000 OnceThrough
260,000 Recirculating
1,280,000 OnceThrough
440,000 OnceThrough
71,000 OnceThrough
1,270,000 OnceThrough
290,000 OnceThrough
850,000 OnceThrough
100,000 OnceThrough
660,000 OnceThrough
130,000 OnceThrough
61,000 OnceThrough
340,000 Recirculating
2,680,000 OnceThrough
430,000 OnceThrough
460,000 Other
340,000 OnceThrough
130,000 OnceThrough
110,000 OnceThrough
480,000 Recirculating
580,000 OnceThrough
440,000 Combination
100,000 OnceThrough
450,000 OnceThrough
Passive Fish Handling Compliance CWIS Technology
Intake? and/ or Modification
Return?
No
Yes
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
Yes
No
No
No
No
No
No
No
No
No
Yes
No
No
No
No
No
No
Yes
No
No
Yes
No
No
No
No
No
No
No
No
No
No
Fish Handling and Return System
Fish Handling and Return System
Fine Mesh Trav w/ Fish Handling
None
Fine Mesh Trav w/ Fish Handling
None
Fish Handling and Return System
None
None
None
Fish Handling and Return System
Fine Mesh Trav w/ Fish Handling
Fine Mesh Trav w/ Fish Handling
None
Fine Mesh Traveling Screen
None
None
Fine Mesh Traveling Screen
Fish Handling and Return System
Fine Mesh Trav w/ Fish Handling
Fine Mesh Trav w/ Fish Handling
Fish Handling and Return System
Fine Mesh Trav w/ Fish Handling
None
Fish Handling and Return System
Fine Mesh Trav w/ Fish Handling
Fine Mesh Trav w/ Fish Handling
Fish Handling and Return System
CWIS Technolgy
Retrofit Capital
Cost
$1,623,313
$459,989
$4,073,795
$0
$700,542
$0
$3,411,906
$0
$0
$0
$603,732
$7,316,195
$1,171,873
$0
$913,055
$0
$0
$18,748,809
$825,540
$4,594,450
$2,239,456
$342,708
$1,099,875
$0
$1,542,186
$3,666,639
$931,121
$929,538
Total Capital Intake CWIS Total O&M
Technology O&M Costs
$1,623,313
$459,989
$4,073,795
$0
$700,542
$0
$3,411,906
$0
$0
$0
$603,732
$7,316,195
$1,171,873
$0
$913,055
$0
$0
$18,748,809
$825,540
$4,594,450
$2,239,456
$342,708
$1,099,875
$0
$1,542,186
$3,666,639
$931,121
$929,538
$55,009
$11,992
$140,592
$0
$26,346
$0
$84,707
$0
$0
$0
$21,529
$204,078
$32,521
$0
$26,501
$0
$0
$435,154
$28,255
$123,881
$88,464
$10,077
$34,353
$0
$39,638
$104,091
$31,977
$33,096
$55,009
$11,992
$140,592
$0
$26,346
$0
$84,707
$0
$0
$0
$21,529
$204,078
$32,521
$0
$26,501
$0
$0
$435,154
$28,255
$123,881
$88,464
$10,077
$34,353
$0
$39,638
$104,091
$31,977
$33,096
Annual
Monitoring
Cost
$75,000
$90,000
$90,000
$90,000
$75,000
$75,000
$90,000
$90,000
$75,000
$75,000
$90,000
$75,000
$90,000
$75,000
$75,000
$75,000
$75,000
$90,000
$75,000
$75,000
$75,000
$75,000
$75,000
$75,000
$90,000
$75,000
$75,000
$75,000
A-10
-------
§ 316(b) Phase II TDD
Appendix A
Model Plant Compliance Costs for the Section 316(b) Existing Facility Proposed Rule
Plant
Code*
252
253
254
255
256
257
258
259
260
261
262
263
264
265
266
267
268
269
270
271
272
273
274
275
276
277
278
279
Water Body Type
Lake/Reservoir
Fresh Stream/Rv
Lake/Reservoir
Fresh Stream/Rv
Fresh Stream/Rv
Fresh Stream/Rv
Fresh Stream/Rv
Estuary/Tidal Riv
Lake/Reservoir
Fresh Stream/Rv
Great Lake
Fresh Stream/Rv
Lake/Reservoir
Fresh Stream/Rv
Lake/Reservoir
Estuary/Tidal Riv
Estuary/Tidal Riv
Ocean
Lake/Reservoir
Lake/Reservoir
Fresh Stream/Rv
Lake/Reservoir
Fresh Stream/Rv
Fresh Stream/Rv
Fresh Stream/Rv
Estuary/Tidal Riv
Fresh Stream/Rv
Fresh Stream/Rv
Steam Plant Design Baseline
Fuel Type Intake Cooling
Flow (gpm) System **
Coal
Coal
Coal
Nuclear
Other
Other
Coal
Nuclear
Coal
Coal
Coal
Coal
Nuclear
Other
Coal
Other
Coal
Oil
Coal
Coal
Coal
Other
Coal
Coal
Coal
Oil
Coal
Coal
180,000 OnceThrough
180,000 OnceThrough
74,000 OnceThrough
630,000 Recirculating
75,000 OnceThrough
1,070,000 Recirculating
430,000 OnceThrough
110,000 OnceThrough
1,050,000 Recirculating
140,000 OnceThrough
41 ,000 OnceThrough
88,000 Recirculating
5,440,000 OnceThrough
66,000 OnceThrough
440,000 OnceThrough
38,000 OnceThrough
2,120,000 Combination
360,000 OnceThrough
63,000 OnceThrough
810,000 Recirculating
300,000 OnceThrough
320,000 OnceThrough
45,000 OnceThrough
400,000 OnceThrough
240,000 OnceThrough
220,000 OnceThrough
120,000 OnceThrough
80,000 OnceThrough
Passive Fish Handling Compliance CWIS Technology
Intake? and/ or Modification
Return?
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
Yes
Yes
No
Yes
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
Yes
No
Yes
Fish Handling and Return System
Fine Mesh Trav w/ Fish Handling
Fish Handling and Return System
None
Fish Handling and Return System
None
None
Fine Mesh Traveling Screen
None
None
Fine Mesh Trav w/ Fish Handling
None
Fish Handling and Return System
Fish Handling and Return System
Fish Handling and Return System
None
Fine Mesh Trav w/ Fish Handling
Fine Mesh Trav w/ Fish Handling
Fish Handling and Return System
None
Fish Handling and Return System
Fish Handling and Return System
None
None
Fine Mesh Trav w/ Fish Handling
Fine Mesh Traveling Screen
Fish Handling and Return System
None
CWIS Technolgy
Retrofit Capital
Cost
$373,886
$1,355,807
$232,739
$0
$188,492
$0
$0
$1,030,036
$0
$0
$464,121
$0
$9,882,287
$217,718
$858,875
$0
$15,282,924
$3,851 ,922
$161,118
$0
$749,245
$648,883
$0
$0
$1,926,190
$1,372,571
$316,951
$0
Total Capital Intake CWIS Total O&M
Technology O&M Costs
$373,886
$1,355,807
$232,739
$0
$188,492
$0
$0
$1,030,036
$0
$0
$464,121
$0
$9,882,287
$217,718
$858,875
$0
$15,282,924
$3,851 ,922
$161,118
$0
$749,245
$648,883
$0
$0
$1,926,190
$1,372,571
$316,951
$0
$12,393
$46,172
$6,583
$0
$6,631
$0
$0
$23,752
$0
$0
$16,467
$0
$356,995
$6,137
$28,905
$0
$509,611
$91,062
$5,985
$0
$22,251
$23,031
$0
$0
$70,751
$35,941
$9,138
$0
$12,393
$46,172
$6,583
$0
$6,631
$0
$0
$23,752
$0
$0
$16,467
$0
$356,995
$6,137
$28,905
$0
$509,611
$91,062
$5,985
$0
$22,251
$23,031
$0
$0
$70,751
$35,941
$9,138
$0
Annual
Monitoring
Cost
$75,000
$75,000
$75,000
$75,000
$75,000
$75,000
$75,000
$90,000
$75,000
$75,000
$75,000
$75,000
$75,000
$75,000
$75,000
$90,000
$90,000
$90,000
$75,000
$75,000
$75,000
$75,000
$75,000
$75,000
$75,000
$90,000
$75,000
$75,000
A-ll
-------
§ 316(b) Phase II TDD
Appendix A
Model Plant Compliance Costs for the Section 316(b) Existing Facility Proposed Rule
Plant
Code*
280
281
282
283
284
285
286
287
288
289
290
291
292
293
294
295
296
297
298
299
300
301
302
303
304
305
306
307
Water Body Type
Estuary/Tidal Riv
Lake/Reservoir
Lake/Reservoir
Estuary/Tidal Riv
Fresh Stream/Rv
Lake/Reservoir
Estuary/Tidal Riv
Fresh Stream/Rv
Estuary/Tidal Riv
Fresh Stream/Rv
Estuary/Tidal Riv
Fresh Stream/Rv
Lake/Reservoir
Lake/Reservoir
Ocean
Fresh Stream/Rv
Estuary/Tidal Riv
Fresh Stream/Rv
Estuary/Tidal Riv
Fresh Stream/Rv
Estuary/Tidal Riv
Estuary/Tidal Riv
Fresh Stream/Rv
Fresh Stream/Rv
Fresh Stream/Rv
Lake/Reservoir
Estuary/Tidal Riv
Estuary/Tidal Riv
Steam Plant
Fuel Type
Nuclear
Coal
Coal
Coal
Coal
Coal
Coal
Coal
Oil
Coal
Other
Coal
Comb Cycle
Other
Other
Coal
Other
Other
Other
Coal
Comb Cycle
Coal
Other
Nuclear
Coal
Coal
Other
Oil
Design Baseline
Intake Cooling
Flow (gpm) System **
2,020,000 OnceThrough
370,000 OnceThrough
700,000 OnceThrough
390,000 OnceThrough
230,000 OnceThrough
1,010,000 OnceThrough
1,500,000 OnceThrough
250,000 OnceThrough
330,000 OnceThrough
590,000 OnceThrough
500,000 OnceThrough
120,000 Recirculating
72,000 OnceThrough
720,000 Combination
370,000 OnceThrough
180,000 OnceThrough
100,000 OnceThrough
510,000 OnceThrough
350,000 OnceThrough
39,000 Recirculating
240,000 OnceThrough
440,000 OnceThrough
910,000 OnceThrough
61,000 Recirculating
490,000 OnceThrough
250,000 OnceThrough
140,000 OnceThrough
230,000 Combination
Passive Fish Handling Compliance CWIS Technology
Intake? and/ or Modification
Return?
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
Yes
No
Yes
Yes
Yes
No
Yes
No
No
Yes
No
No
No
No
No
No
Yes
Yes
No
No
Yes
No
No
No
No
Yes
No
Yes
Fine Mesh Traveling Screen
Fish Handling and Return System
None
Fine Mesh Traveling Screen
None
Fish Handling and Return System
None
None
Fine Mesh Trav w/ Fish Handling
None
Fine Mesh Trav w/ Fish Handling
None
None
Fish Handling and Return System
Fine Mesh Trav w/ Fish Handling
Fish Handling and Return System
None
None
Fine Mesh Trav w/ Fish Handling
None
Fine Mesh Traveling Screen
Fine Mesh Trav w/ Fish Handling
None
None
None
None
None
None
CWIS Technolgy Totel Capital Intake CWIS Totel O&M
Retrofit Capital Technology O&M Costs
Cost
$16,834,637
$846,303
$0
$2,206,407
$0
$1,992,079
$0
$0
$2,467,266
$0
$4,741,804
$0
$0
$1,432,577
$2,571,824
$448,331
$0
$0
$3,391,514
$0
$1,957,099
$4,016,929
$0
$0
$0
$0
$0
$0
$16,834,637
$846,303
$0
$2,206,407
$0
$1,992,079
$0
$0
$2,467,266
$0
$4,741,804
$0
$0
$1,432,577
$2,571,824
$448,331
$0
$0
$3,391,514
$0
$1,957,099
$4,016,929
$0
$0
$0
$0
$0
$0
$327,747
$25,572
$0
$66,950
$0
$68,370
$0
$0
$86,864
$0
$130,499
$0
$0
$50,358
$92,909
$12,630
$0
$0
$90,901
$0
$50,798
$103,736
$0
$0
$0
$0
$0
$0
$327,747
$25,572
$0
$66,950
$0
$68,370
$0
$0
$86,864
$0
$130,499
$0
$0
$50,358
$92,909
$12,630
$0
$0
$90,901
$0
$50,798
$103,736
$0
$0
$0
$0
$0
$0
Annual
Monitoring
Cost
$90,000
$75,000
$75,000
$90,000
$75,000
$75,000
$90,000
$75,000
$90,000
$75,000
$90,000
$75,000
$75,000
$75,000
$90,000
$75,000
$90,000
$75,000
$90,000
$75,000
$90,000
$90,000
$75,000
$75,000
$75,000
$75,000
$90,000
$90,000
A-12
-------
§ 316(b) Phase II TDD
Appendix A
Model Plant Compliance Costs for the Section 316(b) Existing Facility Proposed Rule
Plant
Code*
308
309
310
311
312
313
314
315
316
317
318
319
320
321
322
323
324
325
326
327
328
329
330
331
332
333
334
335
Water Body Type
Fresh Stream/Rv
Lake/Reservoir
Lake/Reservoir
Fresh Stream/Rv
Fresh Stream/Rv
Fresh Stream/Rv
Fresh Stream/Rv
Fresh Stream/Rv
Lake/Reservoir
Fresh Stream/Rv
Lake/Reservoir
Fresh Stream/Rv
Lake/Reservoir
Lake/Reservoir
Fresh Stream/Rv
Lake/Reservoir
Fresh Stream/Rv
Fresh Stream/Rv
Fresh Stream/Rv
Estuary/Tidal Riv
Estuary/Tidal Riv
Fresh Stream/Rv
Fresh Stream/Rv
Lake/Reservoir
Great Lake
Estuary/Tidal Riv
Fresh Stream/Rv
Fresh Stream/Rv
Steam Plant
Fuel Type
Oil
Other
Other
Coal
Other
Other
Coal
Coal
Nuclear
Other
Other
Coal
Coal
Comb Cycle
Coal
Coal
Coal
Nuclear
Nuclear
Oil
Coal
Coal
Coal
Coal
Coal
Coal
Other
Coal
Design Baseline
Intake Cooling
Flow (gpm) System **
180,000 OnceThrough
660,000 OnceThrough
100,000 Recirculating
130,000 OnceThrough
83,000 OnceThrough
190,000 OnceThrough
950,000 OnceThrough
270,000 OnceThrough
380,000 OnceThrough
180,000 OnceThrough
280,000 OnceThrough
360,000 Other
1,010,000 OnceThrough
150,000 OnceThrough
520,000 OnceThrough
650,000 OnceThrough
70,000 OnceThrough
870,000 OnceThrough
76,000 Recirculating
2,400,000 OnceThrough
82,000 OnceThrough
1,370,000 OnceThrough
110,000 OnceThrough
440,000 Recirculating
310,000 OnceThrough
130,000 OnceThrough
320,000 OnceThrough
1,080,000 OnceThrough
Passive Fish Handling Compliance CWIS Technology
Intake? and/ or Modification
Return?
No
No
No
No
No
No
No
No
Yes
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
Yes
Yes
No
No
No
No
Yes
No
No
No
No
No
No
Yes
No
No
No
Yes
Yes
No
Fish Handling and Return System
Fish Handling and Return System
None
Fish Handling and Return System
Fish Handling and Return System
Fish Handling and Return System
Fine Mesh Trav w/ Fish Handling
Fish Handling and Return System
None
None
Fish Handling and Return System
Fine Mesh Trav w/ Fish Handling
Fish Handling and Return System
Fish Handling and Return System
Fine Mesh Traveling Screen
Fish Handling and Return System
Fish Handling and Return System
Fine Mesh Trav w/ Fish Handling
None
Fish Handling and Return System
None
Fine Mesh Traveling Screen
Fine Mesh Trav w/ Fish Handling
None
Fine Mesh Trav w/ Fish Handling
Fine Mesh Traveling Screen
None
Fine Mesh Trav w/ Fish Handling
CWIS Technolgy
Retrofit Capital
Cost
$435,199
$1,273,883
$0
$287,270
$190,035
$468,083
$7,825,161
$699,405
$0
$0
$589,745
$2,332,769
$1,859,551
$326,129
$3,364,264
$1,558,441
$201,299
$8,084,704
$0
$6,379,540
$0
$9,113,298
$1,065,898
$0
$2,587,410
$1,068,066
$0
$7,564,068
Total Capital Intake CWIS Total O&M
Technology O&M Costs
$435,199
$1,273,883
$0
$287,270
$190,035
$468,083
$7,825,161
$699,405
$0
$0
$589,745
$2,332,769
$1,859,551
$326,129
$3,364,264
$1,558,441
$201,299
$8,084,704
$0
$6,379,540
$0
$9,113,298
$1,065,898
$0
$2,587,410
$1,068,066
$0
$7,564,068
$12,499
$43,246
$0
$10,113
$7,113
$13,300
$237,278
$20,414
$0
$0
$21,056
$91,387
$68,197
$11,118
$93,702
$42,662
$6,356
$206,638
$0
$157,514
$0
$234,978
$34,257
$0
$82,934
$26,804
$0
$257,171
$12,499
$43,246
$0
$10,113
$7,113
$13,300
$237,278
$20,414
$0
$0
$21,056
$91,387
$68,197
$11,118
$93,702
$42,662
$6,356
$206,638
$0
$157,514
$0
$234,978
$34,257
$0
$82,934
$26,804
$0
$257,171
Annual
Monitoring
Cost
$75,000
$75,000
$75,000
$75,000
$75,000
$75,000
$75,000
$75,000
$75,000
$75,000
$75,000
$75,000
$75,000
$75,000
$75,000
$75,000
$75,000
$75,000
$75,000
$90,000
$90,000
$75,000
$75,000
$75,000
$75,000
$90,000
$75,000
$75,000
A-13
-------
§ 316(b) Phase II TDD
Appendix A
Model Plant Compliance Costs for the Section 316(b) Existing Facility Proposed Rule
Plant
Code*
336
337
338
339
340
341
342
343
344
345
346
347
348
349
350
351
352
353
354
355
356
357
358
359
360
361
362
363
Water Body Type
Fresh Stream/Rv
Fresh Stream/Rv
Fresh Stream/Rv
Fresh Stream/Rv
Fresh Stream/Rv
Fresh Stream/Rv
Fresh Stream/Rv
Lake/Reservoir
Fresh Stream/Rv
Fresh Stream/Rv
Estuary/Tidal Riv
Lake/Reservoir
Fresh Stream/Rv
Fresh Stream/Rv
Lake/Reservoir
Estuary/Tidal Riv
Fresh Stream/Rv
Ocean
Fresh Stream/Rv
Fresh Stream/Rv
Fresh Stream/Rv
Fresh Stream/Rv
Estuary/Tidal Riv
Estuary/Tidal Riv
Fresh Stream/Rv
Fresh Stream/Rv
Lake/Reservoir
Estuary/Tidal Riv
Steam Plant
Fuel Type
Coal
Coal
Coal
Nuclear
Coal
Coal
Coal
Coal
Coal
Other
Other
Nuclear
Coal
Coal
Coal
Comb Cycle
Coal
Other
Other
Coal
Coal
Coal
Coal
Other
Nuclear
Coal
Coal
Other
Design Baseline
Intake Cooling
Flow (gpm) System **
690,000 Combination
1,050,000 OnceThrough
200,000 Combination
360,000 Combination
700,000 OnceThrough
100,000 Combination
310,000 Recirculating
42,000 Recirculating
110,000 Recirculating
1,050,000 OnceThrough
1,050,000 OnceThrough
810,000 Combination
150,000 OnceThrough
190,000 OnceThrough
130,000 OnceThrough
65,000 OnceThrough
820,000 Combination
420,000 OnceThrough
130,000 OnceThrough
270,000 OnceThrough
70,000 OnceThrough
200,000 OnceThrough
1,710,000 OnceThrough
140,000 OnceThrough
67,000 OnceThrough
500,000 OnceThrough
390,000 OnceThrough
65,000 OnceThrough
Passive Fish Handling Compliance CWIS Technology
Intake? and/ or Modification
Return?
No
No
No
No
No
No
No
No
No
No
No
Yes
No
No
No
No
No
Yes
No
No
No
No
No
No
No
No
No
No
No
No
No
Yes
Yes
Yes
Yes
No
No
Yes
Yes
No
Yes
No
No
No
Yes
No
No
No
No
Yes
No
Yes
No
No
No
No
Fine Mesh Trav w/ Fish Handling
Fish Handling and Return System
Fine Mesh Trav w/ Fish Handling
None
Fine Mesh Traveling Screen
None
None
None
None
None
None
Fish Handling and Return System
None
Fish Handling and Return System
Fish Handling and Return System
None
Fine Mesh Traveling Screen
Fine Mesh Trav w/ Fish Handling
Fine Mesh Trav w/ Fish Handling
Fine Mesh Trav w/ Fish Handling
Fine Mesh Trav w/ Fish Handling
None
Fine Mesh Trav w/ Fish Handling
None
Fish Handling and Return System
Fine Mesh Trav w/ Fish Handling
Fish Handling and Return System
Fine Mesh Trav w/ Fish Handling
CWIS Technolgy
Retrofit Capital
Cost
$4,962,647
$2,157,319
$1,373,019
$0
$4,545,063
$0
$0
$0
$0
$0
$0
$1,542,486
$0
$396,969
$292,561
$0
$4,601,345
$3,939,024
$985,436
$2,420,874
$771,245
$0
$12,330,972
$0
$171,556
$3,572,845
$766,332
$639,845
Total Capital Intake CWIS Total O&M
Technology O&M Costs
$4,962,647
$2,157,319
$1,373,019
$0
$4,545,063
$0
$0
$0
$0
$0
$0
$1,542,486
$0
$396,969
$292,561
$0
$4,601,345
$3,939,024
$985,436
$2,420,874
$771,245
$0
$12,330,972
$0
$171,556
$3,572,845
$766,332
$639,845
$178,383
$69,773
$49,203
$0
$125,850
$0
$0
$0
$0
$0
$0
$54,459
$0
$13,144
$10,031
$0
$137,922
$101,372
$36,506
$76,748
$25,669
$0
$409,972
$0
$6,200
$130,325
$26,664
$24,760
$178,383
$69,773
$49,203
$0
$125,850
$0
$0
$0
$0
$0
$0
$54,459
$0
$13,144
$10,031
$0
$137,922
$101,372
$36,506
$76,748
$25,669
$0
$409,972
$0
$6,200
$130,325
$26,664
$24,760
Annual
Monitoring
Cost
$75,000
$75,000
$75,000
$75,000
$75,000
$75,000
$75,000
$75,000
$75,000
$75,000
$90,000
$75,000
$75,000
$75,000
$75,000
$90,000
$75,000
$90,000
$75,000
$75,000
$75,000
$75,000
$90,000
$90,000
$75,000
$75,000
$75,000
$90,000
A-14
-------
§ 316(b) Phase II TDD
Appendix A
Model Plant Compliance Costs for the Section 316(b) Existing Facility Proposed Rule
Plant
Code*
364
365
366
367
368
369
370
371
372
373
374
375
376
377
378
379
380
381
382
383
384
385
386
387
388
389
390
391
Water Body Type
Lake/Reservoir
Fresh Stream/Rv
Fresh Stream/Rv
Fresh Stream/Rv
Ocean
Lake/Reservoir
Fresh Stream/Rv
Fresh Stream/Rv
Fresh Stream/Rv
Fresh Stream/Rv
Estuary/Tidal Riv
Fresh Stream/Rv
Lake/Reservoir
Fresh Stream/Rv
Fresh Stream/Rv
Fresh Stream/Rv
Fresh Stream/Rv
Fresh Stream/Rv
Lake/Reservoir
Fresh Stream/Rv
Fresh Stream/Rv
Fresh Stream/Rv
Fresh Stream/Rv
Fresh Stream/Rv
Fresh Stream/Rv
Fresh Stream/Rv
Estuary/Tidal Riv
Fresh Stream/Rv
Steam Plant
Fuel Type
Comb Cycle
Other
Coal
Coal
Nuclear
Coal
Coal
Coal
Other
Coal
Coal
Coal
Coal
Nuclear
Coal
Coal
Other
Comb Cycle
Coal
Coal
Coal
Oil
Coal
Coal
Nuclear
Coal
Other
Coal
Design Baseline
Intake Cooling
Flow (gpm) System **
130,000 OnceThrough
830,000 Recirculating
190,000 OnceThrough
87,000 OnceThrough
1,030,000 OnceThrough
400,000 OnceThrough
550,000 OnceThrough
270,000 OnceThrough
39,000 OnceThrough
340,000 OnceThrough
210,000 Combination
42,000 Recirculating
170,000 OnceThrough
140,000 Recirculating
67,000 OnceThrough
450,000 OnceThrough
91,000 OnceThrough
120,000 Combination
500,000 OnceThrough
97,000 OnceThrough
300,000 Combination
110,000 OnceThrough
780,000 OnceThrough
370,000 OnceThrough
1,180,000 OnceThrough
74,000 OnceThrough
380,000 OnceThrough
240,000 OnceThrough
Passive Fish Handling Compliance CWIS Technology
Intake? and/ or Modification
Return?
No
No
No
Yes
Yes
No
No
No
No
No
Yes
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
Yes
No
No
No
No
No
No
No
Yes
Yes
Yes
No
No
No
No
No
No
Yes
No
No
Fish Handling and Return System
None
Fish Handling and Return System
Fine Mesh Trav w/ Fish Handling
Fine Mesh Trav w/ Fish Handling
Fish Handling and Return System
Fish Handling and Return System
Fish Handling and Return System
None
Fine Mesh Trav w/ Fish Handling
Fine Mesh Trav w/ Fish Handling
None
Fish Handling and Return System
None
Fish Handling and Return System
None
None
None
None
Fish Handling and Return System
Fine Mesh Trav w/ Fish Handling
Fish Handling and Return System
Fine Mesh Trav w/ Fish Handling
None
None
None
Fish Handling and Return System
Fine Mesh Trav w/ Fish Handling
CWIS Technolgy
Retrofit Capital
Cost
$274,030
$0
$396,532
$693,184
$8,182,772
$973,966
$1,314,223
$738,387
$0
$3,019,394
$1,373,170
$0
$405,704
$0
$175,112
$0
$0
$0
$0
$261,841
$2,607,043
$301,754
$5,533,505
$0
$0
$0
$842,401
$2,262,696
Total Capital Intake CWIS Total O&M
Technology O&M Costs
$274,030
$0
$396,532
$693,184
$8,182,772
$973,966
$1,314,223
$738,387
$0
$3,019,394
$1,373,170
$0
$405,704
$0
$175,112
$0
$0
$0
$0
$261,841
$2,607,043
$301,754
$5,533,505
$0
$0
$0
$842,401
$2,262,696
$9,819
$0
$13,041
$29,089
$249,720
$27,075
$38,449
$20,134
$0
$88,587
$51,369
$0
$12,323
$0
$6,189
$0
$0
$0
$0
$7,930
$80,990
$8,961
$193,850
$0
$0
$0
$26,320
$70,725
$9,819
$0
$13,041
$29,089
$249,720
$27,075
$38,449
$20,134
$0
$88,587
$51,369
$0
$12,323
$0
$6,189
$0
$0
$0
$0
$7,930
$80,990
$8,961
$193,850
$0
$0
$0
$26,320
$70,725
Annual
Monitoring
Cost
$75,000
$75,000
$75,000
$75,000
$90,000
$75,000
$75,000
$75,000
$75,000
$75,000
$90,000
$75,000
$75,000
$75,000
$75,000
$75,000
$75,000
$75,000
$75,000
$75,000
$75,000
$75,000
$75,000
$75,000
$75,000
$75,000
$90,000
$75,000
A-15
-------
§ 316(b) Phase II TDD
Appendix A
Model Plant Compliance Costs for the Section 316(b) Existing Facility Proposed Rule
Plant
Code*
392
393
394
395
396
397
398
399
400
401
402
403
404
405
406
407
408
409
410
411
412
413
414
415
416
417
418
419
Water Body Type
Fresh Stream/Rv
Estuary/Tidal Riv
Fresh Stream/Rv
Estuary/Tidal Riv
Lake/Reservoir
Great Lake
Fresh Stream/Rv
Fresh Stream/Rv
Great Lake
Fresh Stream/Rv
Estuary/Tidal Riv
Fresh Stream/Rv
Lake/Reservoir
Fresh Stream/Rv
Estuary/Tidal Riv
Fresh Stream/Rv
Lake/Reservoir
Fresh Stream/Rv
Fresh Stream/Rv
Estuary/Tidal Riv
Lake/Reservoir
Fresh Stream/Rv
Fresh Stream/Rv
Ocean
Lake/Reservoir
Lake/Reservoir
Lake/Reservoir
Estuary/Tidal Riv
Steam Plant Design Baseline
Fuel Type Intake Cooling
Flow (gpm) System **
Coal
Other
Coal
Other
Coal
Coal
Coal
Coal
Coal
Coal
Oil
Coal
Coal
Coal
Coal
Other
Nuclear
Coal
Other
Other
Nuclear
Coal
Other
Oil
Other
Coal
Other
Other
1,030,000 OnceThrough
520,000 OnceThrough
54,000 OnceThrough
2,100,000 OnceThrough
200,000 OnceThrough
170,000 OnceThrough
180,000 OnceThrough
190,000 Other
840,000 OnceThrough
620,000 OnceThrough
570,000 OnceThrough
280,000 OnceThrough
1,120,000 OnceThrough
480,000 OnceThrough
310,000 Combination
300,000 OnceThrough
83,000 Recirculating
1,000,000 OnceThrough
89,000 OnceThrough
95,000 OnceThrough
2,200,000 OnceThrough
1,900,000 OnceThrough
350,000 Recirculating
1,990,000 OnceThrough
160,000 OnceThrough
610,000 Recirculating
650,000 OnceThrough
1,200,000 OnceThrough
Passive Fish Handling Compliance CWIS Technology
Intake? and/ or Modification
Return?
No
Yes
No
No
No
No
No
No
Yes
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
Yes
No
No
No
Yes
No
Yes
Yes
No
No
No
Yes
No
No
No
No
No
No
No
Yes
No
No
Yes
No
Yes
Fish Handling and Return System
Fine Mesh Trav w/ Fish Handling
None
Fine Mesh Traveling Screen
None
Fish Handling and Return System
Fish Handling and Return System
Fine Mesh Traveling Screen
Fine Mesh Trav w/ Fish Handling
None
Fine Mesh Traveling Screen
Fine Mesh Trav w/ Fish Handling
Fish Handling and Return System
Fish Handling and Return System
None
Fish Handling and Return System
None
Fish Handling and Return System
None
Fine Mesh Trav w/ Fish Handling
Fish Handling and Return System
Fine Mesh Trav w/ Fish Handling
None
Fine Mesh Trav w/ Fish Handling
Fish Handling and Return System
None
Fish Handling and Return System
Fine Mesh Traveling Screen
CWIS Technolgy
Retrofit Capital
Cost
$2,402,438
$4,708,410
$0
$14,707,137
$0
$411,092
$327,604
$1,006,660
$6,968,299
$0
$3,279,537
$2,494,743
$2,163,010
$1,153,848
$0
$628,979
$0
$2,254,314
$0
$829,916
$4,230,547
$13,190,121
$0
$14,339,794
$333,612
$0
$1,248,502
$6,563,060
Total Capital Intake CWIS Total O&M
Technology O&M Costs
$2,402,438
$4,708,410
$0
$14,707,137
$0
$411,092
$327,604
$1,006,660
$6,968,299
$0
$3,279,537
$2,494,743
$2,163,010
$1,153,848
$0
$628,979
$0
$2,254,314
$0
$829,916
$4,230,547
$13,190,121
$0
$14,339,794
$333,612
$0
$1,248,502
$6,563,060
$69,117
$133,910
$0
$349,761
$0
$12,118
$12,448
$33,417
$202,908
$0
$98,996
$77,936
$72,624
$34,608
$0
$21,986
$0
$67,586
$0
$30,663
$143,782
$456,702
$0
$471,062
$11,814
$0
$42,636
$203,833
$69,117
$133,910
$0
$349,761
$0
$12,118
$12,448
$33,417
$202,908
$0
$98,996
$77,936
$72,624
$34,608
$0
$21,986
$0
$67,586
$0
$30,663
$143,782
$456,702
$0
$471,062
$11,814
$0
$42,636
$203,833
Annual
Monitoring
Cost
$75,000
$90,000
$75,000
$90,000
$75,000
$75,000
$75,000
$75,000
$75,000
$75,000
$90,000
$75,000
$75,000
$75,000
$90,000
$75,000
$75,000
$75,000
$75,000
$90,000
$75,000
$75,000
$75,000
$90,000
$75,000
$75,000
$75,000
$90,000
A-16
-------
§ 316(b) Phase II TDD
Appendix A
Model Plant Compliance Costs for the Section 316(b) Existing Facility Proposed Rule
Plant
Code*
420
421
422
423
424
425
426
427
428
429
430
431
432
433
434
435
436
437
438
439
440
441
442
443
444
445
446
447
Water Body Type
Fresh Stream/Rv
Fresh Stream/Rv
Fresh Stream/Rv
Fresh Stream/Rv
Estuary/Tidal Riv
Estuary/Tidal Riv
Estuary/Tidal Riv
Ocean
Lake/Reservoir
Fresh Stream/Rv
Estuary/Tidal Riv
Fresh Stream/Rv
Lake/Reservoir
Estuary/Tidal Riv
Fresh Stream/Rv
Lake/Reservoir
Fresh Stream/Rv
Lake/Reservoir
Estuary/Tidal Riv
Fresh Stream/Rv
Lake/Reservoir
Estuary/Tidal Riv
Estuary/Tidal Riv
Lake/Reservoir
Ocean
Fresh Stream/Rv
Fresh Stream/Rv
Fresh Stream/Rv
Steam Plant
Fuel Type
Coal
Coal
Other
Other
Coal
Other
Comb Cycle
Other
Other
Coal
Other
Other
Coal
Other
Coal
Coal
Coal
Nuclear
Oil
Coal
Other
Coal
Nuclear
Coal
Other
Coal
Coal
Coal
Design Baseline
Intake Cooling
Flow (gpm) System **
350,000 OnceThrough
65,000 OnceThrough
230,000 OnceThrough
330,000 OnceThrough
970,000 OnceThrough
450,000 OnceThrough
510,000 OnceThrough
610,000 OnceThrough
1,200,000 OnceThrough
160,000 OnceThrough
440,000 Combination
160,000 OnceThrough
630,000 OnceThrough
58,000 OnceThrough
220,000 OnceThrough
70,000 OnceThrough
40,000 Recirculating
2,020,000 OnceThrough
950,000 OnceThrough
150,000 OnceThrough
260,000 OnceThrough
190,000 OnceThrough
1,670,000 OnceThrough
3,000 Recirculating
360,000 OnceThrough
390,000 OnceThrough
780,000 Combination
1,390,000 Recirculating
Passive Fish Handling Compliance CWIS Technology
Intake? and/ or Modification
Return?
No
No
No
No
No
No
No
Yes
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
Yes
No
No
Yes
Yes
No
No
No
No
No
No
No
No
No
Yes
No
No
No
Yes
No
No
No
Yes
No
Yes
Yes
No
No
None
Fish Handling and Return System
Fine Mesh Trav w/ Fish Handling
None
None
Fine Mesh Trav w/ Fish Handling
Fine Mesh Trav w/ Fish Handling
Fine Mesh Trav w/ Fish Handling
None
Fine Mesh Trav w/ Fish Handling
Fine Mesh Trav w/ Fish Handling
Fine Mesh Trav w/ Fish Handling
Fish Handling and Return System
Fish Handling and Return System
Fine Mesh Traveling Screen
None
None
None
Fine Mesh Traveling Screen
Fine Mesh Trav w/ Fish Handling
Fish Handling and Return System
Fine Mesh Trav w/ Fish Handling
Fine Mesh Traveling Screen
None
None
Fine Mesh Traveling Screen
Fine Mesh Trav w/ Fish Handling
None
CWIS Technolgy
Retrofit Capital
Cost
$0
$207,206
$1,900,594
$0
$0
$4,193,037
$4,923,758
$5,742,626
$0
$1,307,249
$4,073,922
$1,540,048
$1,224,686
$139,315
$1,266,020
$0
$0
$0
$5,472,686
$1,335,549
$557,464
$1,383,422
$10,835,998
$0
$0
$2,665,218
$5,539,282
$0
Total Capital Intake CWIS Total O&M
Technology O&M Costs
$0
$207,206
$1,900,594
$0
$0
$4,193,037
$4,923,758
$5,742,626
$0
$1,307,249
$4,073,922
$1,540,048
$1,224,686
$139,315
$1,266,020
$0
$0
$0
$5,472,686
$1,335,549
$557,464
$1,383,422
$10,835,998
$0
$0
$2,665,218
$5,539,282
$0
$0
$6,084
$52,865
$0
$0
$105,501
$132,842
$149,148
$0
$41,836
$103,620
$43,180
$42,037
$5,012
$35,819
$0
$0
$0
$165,133
$40,565
$19,958
$47,522
$278,379
$0
$0
$66,902
$193,651
$0
$0
$6,084
$52,865
$0
$0
$105,501
$132,842
$149,148
$0
$41,836
$103,620
$43,180
$42,037
$5,012
$35,819
$0
$0
$0
$165,133
$40,565
$19,958
$47,522
$278,379
$0
$0
$66,902
$193,651
$0
Annual
Monitoring
Cost
$75,000
$75,000
$75,000
$75,000
$90,000
$90,000
$90,000
$90,000
$75,000
$75,000
$90,000
$75,000
$75,000
$90,000
$75,000
$75,000
$75,000
$75,000
$90,000
$75,000
$75,000
$90,000
$90,000
$75,000
$90,000
$75,000
$75,000
$75,000
A-17
-------
§ 316(b) Phase II TDD
Appendix A
Model Plant Compliance Costs for the Section 316(b) Existing Facility Proposed Rule
Plant
Code*
448
449
450
451
452
453
454
455
456
457
458
459
460
461
462
463
464
465
466
467
468
469
470
471
472
473
474
475
Water Body Type
Estuary/Tidal Riv
Lake/Reservoir
Fresh Stream/Rv
Great Lake
Great Lake
Fresh Stream/Rv
Great Lake
Fresh Stream/Rv
Estuary/Tidal Riv
Fresh Stream/Rv
Fresh Stream/Rv
Fresh Stream/Rv
Fresh Stream/Rv
Fresh Stream/Rv
Great Lake
Lake/Reservoir
Fresh Stream/Rv
Fresh Stream/Rv
Fresh Stream/Rv
Fresh Stream/Rv
Fresh Stream/Rv
Fresh Stream/Rv
Fresh Stream/Rv
Fresh Stream/Rv
Estuary/Tidal Riv
Estuary/Tidal Riv
Great Lake
Lake/Reservoir
Steam Plant Design Baseline
Fuel Type Intake Cooling
Flow (gpm) System **
Other
Nuclear
Coal
Other
Coal
Coal
Coal
Nuclear
Coal
Coal
Coal
Coal
Coal
Coal
Coal
Nuclear
Coal
Coal
Coal
Other
Coal
Coal
Nuclear
Coal
Other
Other
Coal
Coal
380,000 OnceThrough
2,100,000 OnceThrough
380,000 Combination
120,000 OnceThrough
460,000 OnceThrough
460,000 OnceThrough
240,000 OnceThrough
98,000 Recirculating
620,000 OnceThrough
300,000 OnceThrough
110,000 Recirculating
14,000 Recirculating
120,000 Recirculating
990,000 OnceThrough
550,000 OnceThrough
600,000 Combination
300,000 OnceThrough
560,000 OnceThrough
46,000 OnceThrough
70,000 OnceThrough
300,000 OnceThrough
40,000 Other
360,000 Combination
450,000 OnceThrough
240,000 OnceThrough
530,000 OnceThrough
380,000 OnceThrough
790,000 Combination
Passive Fish Handling Compliance CWIS Technology
Intake? and/ or Modification
Return?
No
No
No
No
No
No
Yes
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
Yes
No
No
No
No
No
No
No
Yes
No
No
No
Yes
No
No
Yes
Yes
No
No
No
No
No
No
Yes
Yes
No
Yes
Yes
Yes
No
No
None
Fish Handling and Return System
Fish Handling and Return System
Fish Handling and Return System
Fine Mesh Trav w/ Fish Handling
None
Fine Mesh Trav w/ Fish Handling
None
Fine Mesh Trav w/ Fish Handling
Fine Mesh Traveling Screen
None
None
None
None
Fine Mesh Trav w/ Fish Handling
Fish Handling and Return System
Fine Mesh Trav w/ Fish Handling
Fine Mesh Trav w/ Fish Handling
Fish Handling and Return System
Fish Handling and Return System
None
None
Fine Mesh Trav w/ Fish Handling
None
Fine Mesh Traveling Screen
Fine Mesh Traveling Screen
Fine Mesh Trav w/ Fish Handling
None
CWIS Technolgy
Retrofit Capital
Cost
$0
$4,144,255
$774,817
$308,792
$3,845,181
$0
$2,281,101
$0
$5,910,341
$2,307,751
$0
$0
$0
$0
$4,693,678
$1,088,627
$2,459,139
$4,709,936
$135,272
$166,824
$0
$0
$2,604,583
$0
$1,487,122
$3,787,393
$3,192,473
$0
Total Capital Intake CWIS Total O&M
Technology O&M Costs
$0
$4,144,255
$774,817
$308,792
$3,845,181
$0
$2,281,101
$0
$5,910,341
$2,307,751
$0
$0
$0
$0
$4,693,678
$1,088,627
$2,459,139
$4,709,936
$135,272
$166,824
$0
$0
$2,604,583
$0
$1,487,122
$3,787,393
$3,192,473
$0
$0
$140,006
$26,095
$9,260
$123,415
$0
$71,240
$0
$150,407
$57,931
$0
$0
$0
$0
$139,331
$40,708
$81,839
$141,360
$4,272
$6,356
$0
$0
$91,795
$0
$50,391
$94,673
$95,412
$0
$0
$140,006
$26,095
$9,260
$123,415
$0
$71,240
$0
$150,407
$57,931
$0
$0
$0
$0
$139,331
$40,708
$81,839
$141,360
$4,272
$6,356
$0
$0
$91,795
$0
$50,391
$94,673
$95,412
$0
Annual
Monitoring
Cost
$90,000
$75,000
$75,000
$75,000
$75,000
$75,000
$75,000
$75,000
$90,000
$75,000
$75,000
$75,000
$75,000
$75,000
$75,000
$75,000
$75,000
$75,000
$75,000
$75,000
$75,000
$75,000
$75,000
$75,000
$90,000
$90,000
$75,000
$75,000
A-18
-------
§ 316(b) Phase II TDD
Appendix A
Model Plant Compliance Costs for the Section 316(b) Existing Facility Proposed Rule
Plant
Code*
476
477
478
479
480
481
482
483
484
485
486
487
488
489
490
491
492
493
494
495
496
497
498
499
500
501
502
503
Water Body Type
Fresh Stream/Rv
Fresh Stream/Rv
Lake/Reservoir
Fresh Stream/Rv
Estuary/Tidal Riv
Fresh Stream/Rv
Fresh Stream/Rv
Fresh Stream/Rv
Fresh Stream/Rv
Estuary/Tidal Riv
Fresh Stream/Rv
Lake/Reservoir
Fresh Stream/Rv
Fresh Stream/Rv
Fresh Stream/Rv
Great Lake
Fresh Stream/Rv
Fresh Stream/Rv
Lake/Reservoir
Fresh Stream/Rv
Fresh Stream/Rv
Lake/Reservoir
Great Lake
Ocean
Great Lake
Fresh Stream/Rv
Estuary/Tidal Riv
Fresh Stream/Rv
Steam Plant
Fuel Type
Coal
Coal
Nuclear
Coal
Coal
Coal
Other
Comb Cycle
Oil
Coal
Coal
Other
Coal
Other
Coal
Coal
Coal
Coal
Other
Coal
Coal
Coal
Coal
Other
Coal
Coal
Comb Cycle
Coal
Design Baseline
Intake Cooling
Flow (gpm) System **
530,000 Recirculating
610,000 OnceThrough
1,170,000 OnceThrough
300,000 OnceThrough
970,000 OnceThrough
520,000 OnceThrough
90,000 OnceThrough
130,000 Combination
260,000 OnceThrough
180,000 OnceThrough
140,000 OnceThrough
520,000 OnceThrough
220,000 OnceThrough
63,000 Combination
38,000 Recirculating
66,000 OnceThrough
690,000 Combination
75,000 OnceThrough
370,000 OnceThrough
460,000 OnceThrough
38,000 OnceThrough
1,240,000 OnceThrough
210,000 OnceThrough
180,000 OnceThrough
190,000 Combination
39,000 OnceThrough
44,000 OnceThrough
200,000 OnceThrough
Passive Fish Handling Compliance CWIS Technology
Intake? and/ or Modification
Return?
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
Yes
No
No
No
No
No
No
No
No
No
Yes
Yes
No
No
No
Yes
Yes
No
No
No
No
No
No
No
No
Yes
No
No
No
No
No
No
No
No
None
Fine Mesh Trav w/ Fish Handling
Fish Handling and Return System
Fine Mesh Trav w/ Fish Handling
Fine Mesh Traveling Screen
None
Fine Mesh Trav w/ Fish Handling
None
Fish Handling and Return System
Fine Mesh Traveling Screen
Fine Mesh Traveling Screen
Fish Handling and Return System
None
Fine Mesh Trav w/ Fish Handling
None
Fine Mesh Trav w/ Fish Handling
Fish Handling and Return System
Fish Handling and Return System
Fish Handling and Return System
Fine Mesh Traveling Screen
Fine Mesh Trav w/ Fish Handling
Fish Handling and Return System
Fine Mesh Trav w/ Fish Handling
Fish Handling and Return System
Fine Mesh Trav w/ Fish Handling
Fish Handling and Return System
Fine Mesh Trav w/ Fish Handling
Fine Mesh Trav w/ Fish Handling
CWIS Technolgy
Retrofit Capital
Cost
$0
$5,206,954
$2,313,355
$2,518,999
$7,117,155
$0
$876,076
$0
$705,356
$1,331,750
$962,776
$1,034,640
$0
$685,831
$0
$756,310
$1,654,100
$182,461
$727,770
$3,059,435
$423,094
$2,414,364
$1,788,730
$489,001
$1,505,392
$108,943
$493,753
$1,581,199
Total Capital Intake CWIS Total O&M
Technology O&M Costs
$0
$5,206,954
$2,313,355
$2,518,999
$7,117,155
$0
$876,076
$0
$705,356
$1,331,750
$962,776
$1,034,640
$0
$685,831
$0
$756,310
$1,654,100
$182,461
$727,770
$3,059,435
$423,094
$2,414,364
$1,788,730
$489,001
$1,505,392
$108,943
$493,753
$1,581,199
$0
$149,533
$79,908
$81,047
$167,017
$0
$29,591
$0
$19,678
$32,154
$27,700
$36,526
$0
$24,262
$0
$24,959
$48,730
$6,639
$25,529
$87,083
$15,837
$83,162
$51,230
$12,663
$46,877
$3,840
$17,343
$48,949
$0
$149,533
$79,908
$81,047
$167,017
$0
$29,591
$0
$19,678
$32,154
$27,700
$36,526
$0
$24,262
$0
$24,959
$48,730
$6,639
$25,529
$87,083
$15,837
$83,162
$51,230
$12,663
$46,877
$3,840
$17,343
$48,949
Annual
Monitoring
Cost
$75,000
$75,000
$75,000
$75,000
$90,000
$75,000
$75,000
$75,000
$75,000
$90,000
$75,000
$75,000
$75,000
$75,000
$75,000
$75,000
$75,000
$75,000
$75,000
$75,000
$75,000
$75,000
$75,000
$90,000
$75,000
$75,000
$90,000
$75,000
A-19
-------
§ 316(b) Phase II TDD
Appendix A
Model Plant Compliance Costs for the Section 316(b) Existing Facility Proposed Rule
Plant
Code*
504
505
506
507
508
509
510
511
512
513
514
515
516
517
518
519
520
521
522
523
524
525
526
527
528
529
530
531
Water Body Type
Fresh Stream/Rv
Fresh Stream/Rv
Fresh Stream/Rv
Fresh Stream/Rv
Fresh Stream/Rv
Lake/Reservoir
Estuary/Tidal Riv
Estuary/Tidal Riv
Lake/Reservoir
Estuary/Tidal Riv
Ocean
Fresh Stream/Rv
Lake/Reservoir
Fresh Stream/Rv
Lake/Reservoir
Fresh Stream/Rv
Lake/Reservoir
Lake/Reservoir
Fresh Stream/Rv
Estuary/Tidal Riv
Fresh Stream/Rv
Lake/Reservoir
Fresh Stream/Rv
Fresh Stream/Rv
Fresh Stream/Rv
Fresh Stream/Rv
Lake/Reservoir
Estuary/Tidal Riv
Steam Plant
Fuel Type
Coal
Other
Other
Other
Oil
Coal
Nuclear
Other
Other
Oil
Oil
Coal
Coal
Coal
Other
Coal
Coal
Other
Other
Other
Other
Coal
Coal
Coal
Coal
Comb Cycle
Coal
Other
Design Baseline
Intake Cooling
Flow (gpm) System **
140,000 OnceThrough
35,000 OnceThrough
1,010,000 OnceThrough
72,000 OnceThrough
75,000 Recirculating
290,000 OnceThrough
2,400,000 OnceThrough
160,000 OnceThrough
280,000 OnceThrough
110,000 OnceThrough
180,000 OnceThrough
90,000 OnceThrough
11 0,000 Other
320,000 OnceThrough
720,000 OnceThrough
950,000 OnceThrough
560,000 OnceThrough
190,000 OnceThrough
140,000 Combination
360,000 OnceThrough
210,000 OnceThrough
78,000 OnceThrough
1,160,000 OnceThrough
680,000 OnceThrough
110,000 Combination
41 ,000 OnceThrough
100,000 OnceThrough
42,000 OnceThrough
Passive Fish Handling Compliance CWIS Technology
Intake? and/ or Modification
Return?
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
Yes
No
No
No
Yes
No
Yes
Yes
Yes
No
No
No
No
No
No
No
No
Yes
No
No
Yes
Yes
Yes
No
No
No
No
No
No
Yes
Fine Mesh Trav w/ Fish Handling
Fine Mesh Trav w/ Fish Handling
Fine Mesh Traveling Screen
Fish Handling and Return System
None
None
Fine Mesh Traveling Screen
Fine Mesh Trav w/ Fish Handling
Fish Handling and Return System
Fish Handling and Return System
Fine Mesh Trav w/ Fish Handling
Fish Handling and Return System
Fish Handling and Return System
Fish Handling and Return System
Fish Handling and Return System
None
Fish Handling and Return System
Fish Handling and Return System
Fine Mesh Traveling Screen
Fine Mesh Traveling Screen
None
Fish Handling and Return System
Fine Mesh Trav w/ Fish Handling
None
Fish Handling and Return System
Fine Mesh Trav w/ Fish Handling
Fish Handling and Return System
Fine Mesh Traveling Screen
CWIS Technolgy Totel Capital Intake CWIS Totel O&M
Retrofit Capital Technology O&M Costs
Cost
$1,246,248
$421,139
$5,518,710
$210,378
$0
$0
$16,875,397
$1,539,775
$584,577
$240,807
$1,932,155
$214,580
$314,859
$745,665
$1,437,569
$0
$1,381,513
$391,428
$820,949
$2,673,080
$0
$214,248
$8,179,249
$0
$250,951
$490,252
$297,106
$432,089
$1,246,248
$421,139
$5,518,710
$210,378
$0
$0
$16,875,397
$1,539,775
$584,577
$240,807
$1,932,155
$214,580
$314,859
$745,665
$1,437,569
$0
$1,381,513
$391,428
$820,949
$2,673,080
$0
$214,248
$8,179,249
$0
$250,951
$490,252
$297,106
$432,089
$38,937
$15,043
$170,854
$6,442
$0
$0
$393,401
$42,000
$20,881
$8,532
$45,646
$7,499
$8,653
$22,821
$50,51 1
$0
$38,776
$13,268
$27,388
$63,952
$0
$6,835
$287,687
$0
$8,789
$16,484
$8,195
$13,737
$38,937
$15,043
$170,854
$6,442
$0
$0
$393,401
$42,000
$20,881
$8,532
$45,646
$7,499
$8,653
$22,821
$50,51 1
$0
$38,776
$13,268
$27,388
$63,952
$0
$6,835
$287,687
$0
$8,789
$16,484
$8,195
$13,737
Annual
Monitoring
Cost
$75,000
$75,000
$75,000
$75,000
$75,000
$75,000
$90,000
$90,000
$75,000
$90,000
$90,000
$75,000
$75,000
$75,000
$75,000
$75,000
$75,000
$75,000
$75,000
$90,000
$75,000
$75,000
$75,000
$75,000
$75,000
$75,000
$75,000
$90,000
A-20
-------
§ 316(b) Phase II TDD
Appendix A
Model Plant Compliance
Plant
Code*
532
533
534
535
536
537
538
539
Water Body Type
Estuary/Tidal Riv
Fresh Stream/Rv
Fresh Stream/Rv
Estuary/Tidal Riv
Estuary/Tidal Riv
Lake/Reservoir
Estuary/Tidal Riv
Fresh Stream/Rv
Steam Plant
Fuel Type
Oil
Other
Coal
Other
Other
Coal
Other
Coal
Design Baseline
Intake Cooling
Flow (gpm) System **
920,000 OnceThrough
70,000 Unknown
56,000 OnceThrough
76,000 OnceThrough
520,000 OnceThrough
170,000 OnceThrough
43,000 OnceThrough
41 ,000 OnceThrough
Passive
Intake?
No
No
No
No
No
Yes
No
No
Costs for
Fish Handling
and/ or
Return?
Yes
No
No
No
Yes
No
Yes
No
the Section 316(b) Existing Facility Proposed Rule
Compliance CWIS Technology
Modification
Fine Mesh Traveling Screen
Fish Handling and Return System
Fish Handling and Return System
Fine Mesh Trav w/ Fish Handling
Fine Mesh Traveling Screen
Fish Handling and Return System
Fine Mesh Traveling Screen
Fish Handling and Return System
CWIS Technolgy
Retrofit Capital
Cost
$5,251,551
$170,133
$142,950
$897,385
$3,906,397
$437,083
$367,493
$109,575
Total Capital
$5,251,551
$170,133
$142,950
$897,385
$3,906,397
$437,083
$367,493
$109,575
Intake CWIS
Technology O&M
$161,830
$6,356
$4,863
$26,839
$94,129
$12,031
$13,969
$4,011
Total O&M
Costs
$161,830
$6,356
$4,863
$26,839
$94,129
$12,031
$13,969
$4,011
Annual
Monitoring
Cost
$90,000
$75,000
$75,000
$90,000
$90,000
$75,000
$90,000
$75,000
** For the purposes of the costing methodology used for this proposed rule, the Agency considers combination cooling systems to be the equivalent of once-through. However, compliance requirements may
distinguish between the types under certain special cases (for instance, a mixed-mode facility that may operate in essentially recirculating mode save certain time periods).
A-21
-------
§ 316(b) Phase II TDD
THIS PAGE INTENTIONALLY LEFT BLANK
A-22
-------
§ 316(b) Phase II TDD Technology Cost Curves
Appendix B: Technology Cost Curves
-------
§ 316(b) Phase II TOO
Costing Methodology
$14,000,000
$12,000,000
$10,000,000
•% $8,000,000
o
O
a.
re
O $6,000,000
$4,000,000
$2,000,000
Chart 2-1. Capital Costs of Basic Cooling Towers with Various Building Material
(Delta 10 Degrees) - Costs for New Facility Projects
y = -1E-1 Ox3 -1 E-05x2 + 70.552x + 61609
R2 = 0.9997
y = -1 E-1 Ox3 -1 E-05x2 + 68.039x + 59511
R2 = 0.9997
50000
y = -1 E-1 Ox3 - 9E-06x2 + 56.453x + 49125
R2 = 0.9997
y = -1 E-1 Ox3 - 9E-06x2 + 55.432x + 48575
R2 = 0.9997
y = -9E-11x3 - 8E-06x2 + 50.395x + 44058
R2 = 0.9997
100000 150000
Flow GPM
200000
250000
Douglas Fir • Red wood A Concrete ^Steel x Fiberglass reinforced plastic
-------
§ 316(b) Phase II TOO
Costing Methodology
$40,000,000
$35,000,000
Chart 2-2. Douglas Fir Cooling Tower Capital Costs with Various Features
(Delta 10 Degrees) - Costs for New Facility Projects
y = -O.OOOIx" + 196.07X + 71424
y = -3E-10x -2E-05x+151.18x+13222£
ra $20,000,000
y = -4E-05x + 62.744x + 22836
y = -1E-1 Ox - 1 E-05x + 65.517x + 57246
$15,000,000
$10,000,000
= -1 E-1 Ox - 9E-06x + 55.432x + 48575
y = -9E-11x3 - 8E-06x2 + 50.395x + 44058
50000 100000 150000
FlowGPM
200000
250000
BasicTower • Splash fill A Non-fouling film fill • Hybrid tower (Plume abatement 32DBT) * Noise reduction 10 dBA • Dry/ wet
-------
§ 316(b) Phase II TOO
Costing Methodology
$45,000,000
$40,000,000
$35,000,000
$30,000,000
o $25,000,000
re $20,000,000
$15,000,000
Chart 2-3. Red Wood Cooling Tower Capital Costs with Various Features
(Delta 10 Degrees) - Costs for New Facility Projects
y = -4E-10x3 - 3E-05x2 + 2117x + 18433S
R2 = 0.9997
y = -3E-10x3 - 3E-05x2 + 169.36x + 147375
R2 = 0.9997
y = -5E-05x2 + 76.127x + 27653
y = -5E-05x2 + 70.271x + 25393
R2 = 0.9996
y = -4E-05x2 + 58.561x + 21173
R2 = 0.9996
y = -4E-05x2 + 64.419x + 23325
= 0.9996
50000 100000 150000
Flow GPM
200000
250000
BasicTower "Splash fill A Non-fouling film fill • Hybrid tower (Plume abatement 32DBT) * Noise reduction 10 dBA • Dry/wet
-------
§ 316(b) Phase II TOO
Costing Methodology
Chart 2-4. Concrete Cooling Tower Capital Costs with Various Features
(Delta 10 Degrees) - Costs for New Facility Projects
$60,000,000
$50,000,000
$40,000,000
in
o
O
ra $30,000,000
Q.
re
O
$20,000,000
$10,000,000
y = -9E-05x2 + 128.1x + 46441
0
50000
y = -5E-10x3 - 5E-05x2 + 296.32x + 258694
FT = 0.9997
y = -5E-10x3 - 4E-05x2 + 264.56x + 231239
R2 = 0.9997
y = -6E-05x2 + 95.16x + 34551
y = -6E-05x2 + 87.845x + 31674
FT = 0.9996
y = -5E-05x2 + 73.202x + 26463
FT = 0.9996
y = -5E-05X2 + 80.529x + 29070
R = 0.9996
100000 150000
Flow GPM
200000
250000
* BasicTower
• Hybrid tower (Plume abatement 32DBT)
+ Natural draft wet tower
Splash fill
Noise reduction 10 dBA
A Non-fouling film fill
• Dry/ wet
-------
§ 316(b) Phase II TOO
Costing Methodology
$60,000,000
$50,000,000
$40,000,000
in
o
O
ra $30,000,000
a.
re
O
$20,000,000
$10,000,000
Chart 2-5. Steel Cooling Tower Capital Costs with Various Features
(Delta 10 Degrees) - Costs for New Facility Projects
y = -5E-10x3 - 4E-05x2 + 255.15x + 223423
R2 = 0.9997
y = -6E-05x2 + 91756x + 33667
y = -6E-05x2 + 84.7x + 30845
y = -5E-05X2 + 70.584x + 25763
R = 0.9996
y = -5E-05x2 + 77.645x + 28309
R = 0.9996
50000 100000 150000
Flow GPM
200000
250000
BasicTower "Splash fill A Non-fouling film fill • Hybrid tower (Plume abatement 32DBT) * Noise reduction 10 dBA • Dry/ wet
-------
§ 316(b) Phase II TOO
Costing Methodology
$40,000,000
$35,000,000
$30,000,000
$25,000,000
ra $20,000,000
$15,000,000
$10,000,000
$5,000,000
in
o
O
a.
re
O
Chart 2-6. Fiberglass Cooling Tower Capital Costs with Various Features
(Delta 10 Degrees) - Costs for New Facility Projects
y = -3E-10x3 - 3E-05x2 + 166.3x + 145724
R2 = 0.9997
y = -4E-10x3 - 3E-05x2 + 207.87x + 182205
R = 0.9997
y = -5E-05x2 + 74.769x + 27353
y = -5E-05x2 + 69.015x + 25217
" = 0.9996
y = -4E-05x2 + 57.513x + 20980
R = 0.9996
y = -4E-05x2 + 63.263x + 23209
R2 = 0.9996
50000 100000 150000
Flow GPM
200000
250000
* BasicTower
A Non-fouling film fill
* Noise reduction 10 dBA
• Splash fill
• Hybrid tower (Plume abatement 32DBT)
* Dry/ wet
-------
§ 316(b) Phase II TOO
Costing Methodology
$50,000,000
$45,000,000
$40,000,000
$35,000,000
w $30,000,000
«
o
0
Chart 2-7. Actual Capital Costs for New Facility Tower Projects
and Comparable Costs from EPA Cooling Tower Cost Curves
R = 0.8915 case studies
100000 200000 300000 400000
Flow in gpm
500000
600000
700000
* New Facility Case studies • EPA's New Facility Estimates
-------
§ 316(b) Phase II TOO
Costing Methodology
Chart 2-8. O&M Redwood Tower Annual Costs
$5,000,000
$4,500,000
$4,000,000
o
U
a
a
a
y = -lE-05x + 21.36x + 5801.6
R2 = 0.9998
y = -lE-05x + 25.385x + 7328.1
R2 = 0.9998
y = -5E-06x + 12.235x + 2512.5
R2 = 0.9999
y = -4E-06x + 11.617x + 2055.2
R2 = 0.9999
y = -4E-06x + 11.163x + 2053.7
R2 = 0.9999
y = -4E-06x + 10.617X + 2055.2
R2 = 0.9999
50000
100000
150000
200000
250000
Flow GPM
* Red wood Standard Fill
•Splash fill
Non-fouling fill
"Plume abatement * Noise Reduction
• Dry/Wet
-------
§ 316(b) Phase II TOO
Costing Methodology
Chart 2-9. O&M Concrete Tower Annual Costs
$2,500,000
$2,000,000
$1,500,000
s
$1,000,000
$500,000
$0
y = -3E-06x + 10.305x+ 1837.2
R2 = 0.9999
y = -2E-06x + 8.4943x + 1139.9
R2 = l
50000
100000 150000
Flow GPM
200000
250000
I Natural draft wet tower
I splashfill mechnical
-------
§ 316(b) Phase II TDD Appendix C
Appendix C: Cost Estimate Report for a
Hypothetical Cooling System Conversion
The Agency conducted a detailed analysis of cost estimates for the hypothetical installation of a cooling tower
system at Bowline Point Station along the Hudson River in New York State. The Agency compared the results of its
analysis to that included in the Draft Environmental Impact Statement (DEIS) of four Hudson River power plants.
Power Tech Associates of New Jersey examined the costs of converting Bowline Point's cooling system from once-
through to recirculating in Appendix VIII-3 of the DEIS, which was submitted to New York State in December, 1999.
Section IV-B of the DEIS contains detailed information on the existing cooling water system and site characteristics.
The Power Tech report presents a narrative review of cooling tower technologies, a description of most key engineering
assumptions for and site characteristics affecting unit cost estimates, an environmental impact discussion of the cooling
towers, capital cost estimates at the aggregate level, and an economic analysis of these costs.
The focus of the Agency's analysis was to develop detailed unit cost estimates for comparison to the Power
Tech aggregate capital cost estimates. Although the Appendix VIII-3 cost estimates are at the aggregate level, the DEIS
(in addition to historical engineering work on behalf of the four Hudson plants) provides sufficient detail to afford
comparison to detailed unit cost estimates developed by EPA. The sources of cost data and reference information for
the Agency's unit cost estimates are presented below. The Agency chose to develop the detailed unit cost estimates for
the Bowline Plant, in order to examine the overall veracity of the estimates prepared by Power Tech Associates. The
Agency could have chosen to examine any of the four Hudson Plants, but selected Bowline because the degree of detail
in the DEIS (and supporting documentation) was high and the uncertainty about site characteristics was the lowest
amongst the four plants. For instance, the Agency had intended to also examine the Roseton Station, but was unable
to determine the distance between the proposed towers and the condensers from the Power Tech report. In turn, the
Agency was unable to develop detailed unit costs for the Roseton Station due to this key data omission.1
The Agency notes that the Mirant Bowline, LLC (the new owners and operators of Bowline Point Station)
currrently are in the process of obtaining approval for expansion of the plant with planned construction of a third,
combined-cycle unit on the site. If this construction commences as planned, the configuration of the plant would be
significantly altered. The land proposed by Power Tech Associates for construction of the cooling tower system for
units 2 and 3 (as analyzed herein) would likely be utilized in part for the new generating unit. Therefore, for this reason
and others, this analysis should be considered hypothetical in nature.
1 The Agency, however, obtained schematics of the Roseton Station retrofit design (1977) late in the development of this report.
The design schematic by Central Hudson (1977, Exhibit 2) proposes nearly complete reuse of the existing circulating piping
system with minimal additional circulating piping required to connect the tower system. From the detailed schematic, EPA
estimates that the lineal feet of new circulating water piping as less than 900 feet (that is, 2300 feet less than the Power Tech
design for Bowline Point Station), hi addition, the Central Hudson schematic proposes for the existing intake discharge piping to
be completely reused, thereby eliminating the need for new makeup and blowdown piping. Therefore, significant piping and
civil works cost savings would be afforded for the Roseton Station over the comparably sized and situated Bowline Point Station.
A rough estimate based on the detailed costs of Bowline Point developed by EPA would provide a total project capital cost
savings of approximately $6 million.
C-l
-------
§ 316(b) Phase II TDD Appendix C
Bowline Point Station is a fossil-fueled plant cooled by a once-through system withdrawing from the Hudson
River. The station is located approximately forty miles north of New York City in Haverstraw. The plant is located
on a flat expanse of land. The property encompasses a cove (referred to as Bowline Pond) from which cooling water
is withdrawn. The station utilizes two steam generators, each sized at 622 megawatts, nameplate capacity. The units
were installed in 1972 and 1974. Their utilization had slumped in the mid-1990s, with a rise shown after 1997. The
existing once-through cooling system services two condensers at a maximum design flow rate of 1,110,000 gallons per
minute (gpm). However, the plant generally operates with reduced pump usage for a design flow rate of 740,120 gpm.
Both of these flow rates represent greater than one percent of the mean tidal flow as presented in the DEIS. The Agency
notes that in the facility's response to the detailed questionnaire, Bowline Point reported a significantly lower flow rate
for its design intake flow than either capacity described here. In fact, the design intake flow reported by Bowline for
the detailed questionnaire was very similar to the average annual intake (in gallons per day) for the year 1998. In turn,
the Agency intends to update its questionnaire response database to reflect the design flows above. This is an important
fact for the consideration of the Agency's methodology for estimating costs of conversions from once-through to
recirculating wet cooling systems (which is outlined in Chapter 2 of this document), as the Agency utilizes the design
intake flow as the basis for assessing these costs.
The design circulating cooling flow estimated by Power Tech for the cooling towers is 642,000 gpm. Power
Tech based their analysis on four-hybrid, wet-dry cooling towers each with 160,500 gpm of design circulating capacity.
Power Tech states in Appendix VIII-3, page 10, "based on a conservative approach, the wet/dry mechanical draft tower
was chosen as the best way to evaluate economic... concerns associated with retrofitting cooling towers to the Hudson
River plants." As discussed in Grogan (2000), "a wet only (wet mechanical cooling tower) cooling water system will
have substantially less environmental impact and be less costly to the NY consumers. The trade-off is that the water
vapor plume will be visible during more days of the year." The Agency agrees with the Grogan assessment and
considers the benefits of a wet/dry cooling system to be debatable for this installation. In 1977, Consolidated Edison
conducted a detailed study of the potential effects of a natural-draft wet (only) cooling tower on the local environment
near the Roseton Generating Station. The analysis of plume effects from the natural-draft towers (each projected to
be about 400 ft tall) showed induced fogging at the station for a total of 85 hours per year, with a peak in February of
40 hours (Con. Ed, 1977; Table 4-1). Outside of 0.8 miles from the station the study predicted 7 hours or less of
fogging, in any direction, for the entire year. Plume induced icing, according to the 1977 study, would occur for a total
of 45 hours in a single year at the station itself. Outside of 0.8 miles the total hours of icing for any nearby area would
be 6 hours or less per year. Because of the similarities in size and location between Roseton and Bowline Stations, the
Agency considers these results to be relatively transferable to the Bowline Point location. However, the remote fogging
and icing effects of a natural-draft tower system would be significantly greater than those for a comparably sized
mechanical-draft tower, which would be roughly 5 0 feet in height with a plume that is approximately 3 0 percent smaller
than that of a natural-draft tower. In addition, Central Hudson, et al. (1977) quantified the economic impacts of these
effects in the Report on Cost-Benefit Analysis of Operation of Hudson River Steam-Electric Units with Once-through
and Closed-cycle Cooling Systems. In the report the authors state, "the impact of the operation of the proposed closed-
cycle cooling systems in terms of induced fog and icing is not expected to be substantial." This summary refers to the
combined total of the four power plants potentially converting to natural-draft wet cooling tower systems. The effects
for less than four plants (or a single plant) converting to a mechanical-draft wet cooling tower system would be even
less pronounced. Therefore, based on these 1977 analyses by Con. Ed. and Central Hudson, et al., the Agency
considers the mechanical draft wet (only) cooling towers to be a viable option for Bowline Point.
-------
§ 316(b) Phase II TDD Appendix C
Regardless of the configuration of the tower (that is, wet only or hybrid, wet-dry), the cooling flow would be
equivalent between the two types. Additionally, the land requirements, site preparation, and civil construction would
be nearly identical for both types of tower installations, with the exception of potential support piling requirements.
For the wet-dry models, marginal additional support piling (due to increased load) may be necessary. The Agency, in
its analysis, has estimated all costs based on mechanical-draft wet (only) cooling towers.
Bowline Point is located roughly 30 miles from Poughkeepsie, NY, which is one of the nearest towns to
Bowline included in the city cost index of R.S. Means. The R.S. Means City Cost Index contains other towns in the
vicinity of Haverstraw in addition to Poughkeepsie, such as Suffern and White Plains. Haverstraw is, in effect,
equidistant from each of these three cities. Poughkeepsie's cost index represents the median and near to the average
of these three surrounding city cost indexes. Therefore, the Agency utilized costs index multipliers specific to the
median of these three cities for its cost estimates. The DEIS states that truck traffic through Haverstraw would be
disruptive to the town, which the Agency cannot dispute. Therefore, in all cases, the Agency estimated the hauling
requirements as conservative (that is, small to medium trucks) and to account for alternative routing (that is, long round-
trips) to minimize and avoid town traffic disruptions. Additionally, the Bowline Point site covers 245 acres. Based
on the detailed aerial photographs (proprietary photos published by www.mapquest.com and available to the general
public through the website, but not for publication), significant available land for staging of construction
operations is available.
Power Tech estimates that the cooling tower system would occupy a total of 6 acres. However, they
assert that 13 acres would require clearing and preparation for construction. The plot of land projected for
construction would be approximately 800 feet east of the generators in a relatively low-lying, flat area. Power
Tech assert that this plot of land is populated by second-growth timber. Detailed aerial photographs reveal
brush and small trees covering approximately half of the 13 acres. Additionally, the Power Tech report asserts
that the land shows signs of being wetlands, but the body of the DEIS states that the NY DEC does not designate
any wetland areas on the Bowline Point property. The USDA soil survey included in Appendix IV-B.1-1
indicates that the tower would be constructed in part urban land, part wet substratum. Based on these factors,
the Agency's analysis estimates that significant dewatering control and foundation piling would be required for
the construction project.
The existing intake structure is a surface shoreline intake located to the south and west of the generator
units. The intake pumps sit immediately behind the intake screens, and, due to a lack of proximity, would not
be of use for circulating cooling water between the projected cooling tower location and the condensers. The
intake and discharge piping passes approximately 150 meters immediately to the east of the generator house and
bends southwesterly to and from the discharge and intake. This piping is in relatively close proximity to the
projected location of the cooling towers and could be used for a retrofit design, though, notably, Power Tech does
not address this prospect in their engineering assessment. In turn, the detailed cost estimates included in this file
estimate that only the existing intake and discharge structures will be used for the conversion design and minimal
existing piping will be utilized. Based on the example cooling system conversion cases discussed in Chapter 4,
the Agency views this design as potentially unrealistic and perhaps overly conservative with respect to capital
costs. In addition, as discussed in footnote 1 above, the detailed engineering schematics the Agency obtained for
C-3
-------
§ 316(b) Phase II TDD Appendix C
the historical, proposed Roseton Generating Station cooling system conversion show significant reuse of existing
circulating water piping for that design.
Based on the detailed description provided in the DEIS, the existing intake bays present flexibility for
converting to a reduced intake flow for makeup cooling water. Because the intake is comprised of 6 separate bays
with dedicated pumping stations, several of the bays could be retrofitted with a reduced size pump or a new
variable speed motor to provide makeup water to the cooling towers. The piping delivery to the tower could be
configured to branch from the existing piping. Other configurations that maintain the capability to return to
once-through cooling could be examined (such as diverting the flow from two bays to the makeup piping and
retaining the other four bays for peak-demand, once-through operation). For the Agency's conservative analysis,
the design assumes demolition and replacement of three intake pumps, in addition to construction of wholly new
intake and discharge piping.
The subject of plant outage for conversion of the cooling system is addressed in Appendix VIII-3 of the
DEIS (page 19), where Power Tech states, "it was assumed that each of the [Bowline and Roseton] plants would
experience about one month of outage during the winter months." EPA notes that several data sources indicate
that the outages could be appreciably lower than this estimate. One data source is an engineering report on
Roseton Station from Central Hudson Gas & Electric Corporation (July 1977), which estimates, "as a
conservative approach.. .the downtime cost was calculated for one (1) unit and for ten (10) days," to convert from
a once-through to recirculating cooling system. Additionally, the Agency obtained two empirical examples of
cooling system conversion projects with durations in one-case significantly less than thirty days and 83 hours in
the other (as discussed in the Chapter 4).
The results of the Agency's detailed cost analysis for Bowline Point show that the capital cost estimates
presented in Appendix VIII-3 of the DEIS overstate the potential cost to convert from a once-through to
recirculating cooling system. The Agency did not compare each line item of the Power Tech prepared capital
costs in Appendix VIII, but, rather, focused on the civil works estimates. The Agency prepared two sets of cost
estimates: high unit costs and moderate unit costs. The Agency based the high unit costs on extremely
conservative assumptions for design variables. The moderate costs are also conservative, but utilize optimized
design variables that would reflect a moderate engineering cost estimate. In both cases, the Agency's analysis
demonstrates that the Power Tech estimates overstate direct capital costs by approximately 24 to 36 percent.
Further, the Agency disagrees with several estimates of project overhead rates used by Power Tech.2
Considering the total project costs differences, in the Agency's view, the Appendix VIII-3 estimates may
overstate total project capital costs by 31 to 42 percent. As described above, the Agency disputes the utility of
the wet-dry, hybrid tower for this location. The Agency considers the incorporation of this technology into the
DEIS analysis, as stated in Appendix VIII, to be an overly conservative approach. The Agency's analysis,
therefore, focuses on the wet only mechanical draft tower system. However, had the Agency incorporated the
Power Tech cost estimates for the wet-dry, hybrid system, the Appendix VIII-3 total project capital costs would
remain overestimated by 20 to 30 percent, according to the Agency's analysis. Table C-l shows the Agency's
unit cost estimates as compared to those included in Appendix VIII-3 of the DEIS.
2 In the Agency's view, Appendix VHI-3 incorrectly states the tax rate for New York State, double-counts contractor profit, and
double-counts freight and insurance on materials.
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§ 316(b) Phase II TDD
Appendix C
Table C-l. Capital Cost Comparison for Hypothetical Cooling System
Conversion
Cost Component (1999 $)
App. VIII-3 EPA Estimated EPA Estimated
Estimated Capital Costs - Capital Costs -
Capital Costs Moderate High
Cooling Towers
Site Preparation
Excavation/Backfill for Towers
Piling for Towers
CW Piping Civil Works
CW Pipe
CW Pumphouse Civil/Structural
CW Pumps
CW Pumphouse Cranes
21,009,935 11,063,569
11,063,569
41,099,318 26,326,577
35,084,076
Concrete Basin for Towers 2,450,963 2,450,963 2,450,963
Condenser Tube Cleaning 2,081,000
Water Treat and Chem Add
Electrical 8,677,100 8,677,100 8,677,100
Instrumentation & Controls
Total Direct Cost (TDC) $75,318,316 $48,518,208 $ 57,275,708
Freight & Ins 2,644,788
Eng& Design 4,519,099 2,911,092 3,436,542
Indirect & Und Costs 7,531,832 4,851,821 5,727,571
Construction Mgt 3,012,733 1,940,728 2,291,028
Sales Tax 696,301 191,264 191,264
Contingency & Contractor Profit 15,063,663 4,851,821 5,727,571
Turnkey Contract Cost (TCC) $108,786,731 $63,264,934 $74,649,684
Owner's Costs (3% of TCC) 3,263,602 1,897,948 2,239,491
Start-up & Testing (0.5% of TCC) 543,934 316,325 373,248
Total Project Cost $112,594,000 $65,479,000 $77,262,000
Approximate $ per kW (nameplate) 91 53 62
Note that the Agency utilized the capital costs for concrete basins, water treatment and chemical addition,
and instrumentation and controls presented in Appendix VIII-3 of the DEIS without examining the basis of the cost
estimates. In addition, the Agency did not utilize the condenser tube cleaning system as proposed. In the Agency's
view, this is a cost that would benefit the performance of the condensers regardless of the cooling system in
operation and would not be a critical component of cooling system conversion. The detailed unit cost worksheets
developed by the Agency are in the public record of this proposal at DCN 4-2537. The Agency utilized the
following references in preparation of the analysis:
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§ 316(b) Phase II TDD Appendix C
References Used in the Cost Analysis:
J.M. Burns and Michilletti, W.C., 2000, "Comparison of Wet and Dry Cooling Systems for Combined Cycle Power
Plants," Appendix F to the Comments of the Utility Water Act Group (UWAG) on EPA's Proposed Sec. 316(b)
Rule for New Facilities.
J.M. Burns and Tsou, J.L., 2001, "Modular Steam Condenser Replacement Using Corrosion Resistant High
Performance Stainless Steel Tubing," Proceedings of the 2001 Conference of the American Society of Mechanical
Engineers.
Central Hudson Gas & Electric Corporation, 1977, "Engineering, Environmental (Non-Biological), and Economic
Aspects of a Closed-Cycle Cooling System," Roseton Generating Station.
Central Hudson Gas & Electric Corporation, et al., July 1977, "Report on Cost-Benefit Analysis of Operation of
Hudson River Steam-Electric Units with Once-through and Closed-cycle Cooling Systems," prepared by Mathtech,
Inc., a subsidiary of Mathematica, Inc.
Central Hudson Gas & Electric Corp., et al., 1994, "Utility Responses to New York State Department of
Environmental Conservation/Tellus Institute Commnets and Questions on Preliminary DEIS for SPDES Permits
for Indian Point 2 and 3, Bowline, and Roseton Power Plants."
Central Hudson Gas & Electric Corp., et al., December 1999, "Draft Environmental Impact Statement for State
Pollutant Discharge Elimination System Permits for Bowline Point, Indian Point 2 & 3, and Roseton Steam Electric
Generating Stations."
Consolidated Edison Company of New York, Inc., 1977, "Environmental Analysis of Natural Draft Cooling
Towers for Roseton Generating Station," prepared for Central Hudson Gas & Electric Corp.
Construction Industry Institute, 2001, "Benchmarking & Metrics Analysis Results - What is the Average
Contingency for Heavy Industrial Projects?" http://www.cii-benchmarking.org/news/contingency.htm, Austin,
Texas.
Engineering News-Record, 2002, "Construction Cost Index History (1908-2002),"
http://www.enr.com/cost/costcci.asp, McGraw-Hill, Inc., New York.
D.B. Grogan Associates, Inc., 2000, "Hudson River Power Plants - Cooling Water Design Assessment,"
prepared on behalf of ESSA Technologies, Ltd. for support of the New York State Department of
Environmental Conservation.
S.H. Kosmatka and Panarese, W.C., 1992, "Design and Control of Conrete Mixtures, Thirteenth Edition"
Portland Cement Association, Skokie, Illinois.
W.L. McCabe, et al., 1985, "Unit Operations of Chemical Engineering, Fourth Edition," McGraw-Hill, Inc.,
New York.
C-6
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§ 316(b) Phase II TDD Appendix C
Page, J. R., Senior Editor, 1998, "RS Means Heavy Construction Cost Data, 12th Edition," R.S. Means
Company, Inc.
Parsons Infrastructure and Technology, 1998, "Market-Based Advanced Coal Power Systems," Parsons
report no. 10198, Reading, Pennsylvania.
M.S. Peters and Timmerhaus, K.D., 1991, "Plant Design and Economics for Chemical Engineers, Fourth
Edition," McGraw-Hill, Inc., New York.
U.S. Army Corps of Engineers, 1998, "Conduits, Culverts, and Pipes," engineer manual 1110-2-2902.
USGen New England, 2001, "Section 316b Demonstration Report," submitted to the New England Interstate
Water Pollution Control Commission.
Waier, P. R., Senior Editor, 2000, "RS Means Building Construction Cost Data, 58th Edition," R.S. Means
Company, Inc.
C-7
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§ 316(b) Phase II TDD Appendix C
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§ 316(b) Phase II TDD Dry Cooling
Appendix D: Dry Cooling
INTRODUCTION
This appendix presents a synopsis of the design and operation of an air-cooled condenser system (dry cooling) and its
applicability for existing power plants. The majority of the background information included in this discussion on dry
cooling is from references listed at the end of this appendix, the background discussion draws primarily from Burns
and Michiletti, 2000.
Dry cooling systems transfer heat to the atmosphere without the evaporative loss of water. There are two types of dry
cooling systems for power plant applications: direct-dry cooling and indirect-dry cooling. Direct-dry cooling systems
utilize air to directly condense steam, while indirect dry cooling systems utilize a closed-cycle water cooling system to
condense steam, and the heated water is then air cooled. In the Agency's determination, indirect-dry cooling generally
is the only application of the technology that would be considered for retrofit situations at existing power plants because
a condenser would already be in place for a once-through or recirculated cooling system. For dry cooling towers the
turbine exhaust steam exits directly to an air-cooled, finned-tube condenser. In the Agency's view, if this application
would be applied to an existing plant, the entire steam turbine would necessarily be replaced or reconfigured in an
unprecedented fashion. The costs of steam turbines are significantly more expensive than any type of recirculating
cooling system, including the dry cooling systems. The Agency has determined that the feasibility of direct-dry cooling
systems for existing plants is not demonstrated and because of the limitations and potential costs is not a candidate for
retrofit situations. Therefore, the Agency does not further consider direct-dry cooling systems for existing facilities,
though they are referred to significantly throughout the remainder of this appendix. Because direct-dry cooling systems
would be more efficient and less costly than indirect-systems (ignoring the feasibility issues addressed above), the
Agency's analyses of dry cooling systems using direct-dry cooling systems would show increased energy penalties and
signficantly higher costs.
For indirect-dry cooled systems, recirculating fluid (usually water) passes through an air-cooled, finned tube tower. In
contrast to direct-dry cooling, indirect-dry cooling does not operate as an air-cooled condenser. In other words, the
steam is not condensed within the structure of the dry cooling tower, but instead indirectly through an indirect heat
exchanger (that is, a surface condenser). Therefore, the indirect-dry cooling system would need to overcome additional
heat resistance in the shell of the condenser compared to the direct dry cooling system. Ultimately, the inefficiency
penalties of indirect dry cooling systems will exceed those of direct-dry cooling systems in all cases. Similar to the
direct-dry cooling systems, the arrangement of the finned tubes are most generally of an A-frame pattern (which reduces
the land area required compared to other configurations). However, due to the fact that dry cooling towers do not
evaporate water for heat transfer, the towers are quite large in comparison to similarly sized wet cooling towers.
Additionally, because indirect-dry cooled systems also utilize a surface condenser, with additional heat transfer
inefficiencies compared to a direct-dry cooled system, the indirect systems are generally considered to be significantly
larger than direct systems for comparable heat loads. Because dry cooling towers rely on sensible heat transfer, a large
quantity of air must be forced across the finned tubes by fans to improve heat rejection. The number of fans is therefore
considerably larger than would be used in a mechanical-draft wet cooling tower.
The key feature of dry cooling systems is that no evaporative cooling or release of heat to surface water occurs. As
a result, water consumption rates are very low compared to wet cooling systems. Since the unit does not rely in
D-l
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§ 316(b) Phase II TDD Dry Cooling
principle on evaporative cooling as does a wet cooling tower, larger volumes of air must be passed through the system
compared to the volume of air used in wet cooling towers. As a result, dry cooling towers need larger heat transfer
surfaces and, therefore, tend to be larger in size than comparable wet cooling towers. The design and performance of
the dry cooling system is based on the ambient dry bulb temperature. The dry bulb temperature is higher than the wet
bulb temperature under most circumstances, being equal to the wet bulb temperature only when the relative humidity
is at 100%.
Direct-dry cooling has been installed at a variety of power plants utilizing many fuel types. In the United States, dry
cooling is most frequently applied at plants in northern climates. Additionally, arid areas with significant water scarcity
concerns have also experiencing growth in dry cooling system projects. However, each of the demonstrations that the
Agency has studied is for a direct-dry cooling system configured for a new facility project. As demonstrated in Chapter
5, the comparative energy penalty of a direct-dry cooling plant in a hot environment at peak summer conditions can
exceed 12 percent. Additionally, the indirect-dry cooling system would be even less efficient, producing maximum
energy penalties of 18 percent according to the Department of Energy (DOE, 2001). Additionally, indirect-dry cooling
systems would likely cause prohibitively high exhaust turbine backpressures, thereby potentially debilitating the
operation of some plants at peak-summer, peak-demand conditions (DOE, 2001).
As with wet cooling towers, the ambient air temperature and system design can have an effect on the steam turbine
exhaust pressure, which in turn affects the turbine efficiency. Thus, the turbine efficiency can change over time as the
air temperature changes. The fans used to mechanically force air through the condenser represent the greatest
operational energy requirement for dry cooling systems.
A design measure comparable to the approach value used in wet towers is the difference between the design dry bulb
temperature and the temperature of saturated steam at the design turbine exhaust pressure. In general, for direct-dry
cooling systems a larger, more costly dry cooling system will produce a smaller temperature difference across the dry
cooling tower and, therefore, a lower turbine exhaust pressure. However, as calculated by DOE, the 40 degree F
approach indirect-dry cooling towers may actually be less efficient than smaller sized 20 degree F towers in the cases
modeled by DOE.
Steam turbines are designed to operate within certain exhaust pressure ranges. In general, steam turbines that are
designed to operate at the exhaust steam pressure ranges typical of wet cooling systems, which generally operate at
lower exhaust pressures (e.g., <5 in Hg), may be damaged if the exhaust pressure exceeds a certain value. Even the
highest values of operable exhaust pressures may be exceed with retrofitted indirect-dry cooling systems. For existing
facilities, many with aged turbines, this is a fundamental engineering problem for the feasibility of the retrofitted dry
cooling system.
In an analysis for the New Facility rule, EPA examined turbine exhaust pressures at the highest design dry bulb
temperatures in the U.S. (which were around 100 °F), which ranged from 5.0 to 9.5 inches Hg. The highest value of
9.5 inches Hg was for a refinery power system in California which, based on the steam rate, was comparable to other
relatively small systems generating several megawatts and apparently did not warrant the use of an efficient cooling
system. The other data showed turbine exhaust pressures of around 6 to 7 inches Hg at dry bulb temperatures of
around 100 °F. Maximum exhaust pressures in the range of 8 to 12 inches Hg may be expected in hotter regions of the
U.S.(Hensley 1985). An air cooled condenser analysis (Weeks 2000) reports that for a combined cycle plant built in
Boulder City, Nevada, the maximum ambient temperature used for the maximum off-design specification was 108 °F
with a corresponding turbine exhaust pressure of 7.8 inches Hg. Note that the equation used by EPA to generate the
turbine exhaust pressure values in the energy penalty analysis produced an estimated exhaust pressure of 8.02 inches
Hg at a dry bulb temperature of 108 °F. For wet towers, the typical turbine exhaust pressure operating range is 1.5 to
D-2
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§ 316(b) Phase II TDD Dry Cooling
3.5 inches Hg(Woodruff 1998). EPA prepared all of this analysis in the context of direct-dry cooling systems installed
at new facility projects. For hypothetical indirect-dry systems at existing facilities, the backpressures would be
significantly higher than the values examined by the Agency for the New Facility rule.
In addition, the issue of demonstrated dry cooling systems (even for new facilities) emerges in the context of fossil-fuel
and nuclear plants. The largest operating coal-fired plant in the United States with dry cooling is the Wyodak Station
in Gillette, WY with a total cooling capacity of 330 MW (1.88 million Ib/hr of steam). EPA notes that this is
significantly smaller than a vast number of coal-fired plants within the scope of this proposal. In addition, the design
temperature of the direct-dry cooled system at this plant (which directly affects the size of the dry cooling system) is
below average for summer conditions throughout the United States (the Wyodak Station has a design temperature of
66 deg F). The Agency reiterates its reservation of applying requirements based on dry cooling at the sizes of coal-fired
and nuclear plants in the scope of this proposal.
Costs of Dry Cooling
For the New Facility Final Rule, the Agency projected that the total annualized cost for the dry cooling alternative was
$490 million (in 2000 dollars) for 121 facilities. This proposed rule applies to 5 3 9 facilities, and therefore, a regulatory
option based on dry cooling for all plants would impose a dramatically higher annual compliance cost than that
estimated for the New Facility Final Rule. In addition, the costs the dry cooling system would be even more dramatic,
due to the fact that the majority of existing facilities within the scope of this rule operate with once-through cooling
systems, whereas for the New Facility Final Rule, the vast majority of plants were projected to install recirculating wet
cooling at baseline, thereby reducing marginal cost increases.
Although the dry cooling option is extremely effective at reducing impingement and entrainment and would yield annual
benefits of $ 13 8.2 million for impingement reductions and $1.33 billion for entrainment reductions at existing facilities,
it does so at a cost that would be unacceptable. EPA recognizes that dry cooling technology uses extremely low-level
or no cooling water intake, thereby reducing impingement and entrainment of organisms to dramatically low levels.
However, EPA interprets the use of the word "minimize" in section 316(b) in a manner that allows EPA the discretion
to consider technologies that very effectively reduce, but do not completely eliminate, impingement and entrainment and
therefore meet the requirements of section 316(b). Although EPA has rejected dry cooling technology as a national
minimum requirement, EPA does not intend to restrict the use of dry cooling or to dispute that dry cooling may be the
appropriate cooling technology for some facilities. For example, facilities that are repowering and replacing the entire
infrastructure of the facility may find that dry cooling is an acceptable technology in some cases. A State may choose
to use its own authorities to require dry cooling in areas where the State finds its fishery resources need additional
protection above the levels provided by these technology-based minimum standards.
Methodology for Dry Cooling Cost Estimates at Existing Facilities
For the purposes of approximating the hypothetical costs of retrofitting to dry cooling for existing facilities, the Agency
used the following methodology for developing facility-level costs estimates:
Capital costs for the dry cooling towers were estimated using the cost equation that was developed for the New
Facility Rule (see the next section for the New Facility dry cooling cost estimates).
• The cost equations are based on equivalent cooling water flow rates (gpm) using the once-through design intake
cooling flow as the independent variable. To aviod using the equation outside of its valid range, for facilities with
D-3
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§ 316(b) Phase II TDD Dry Cooling
intake flows greater than 225,000 gpm (which is the maximum equation input value plus 10%), costs for multiple
equal size "units" were developed and then added together.
• An additional 5 percent was added to the capital costs as an "allowance" for unforseen costs.
• A cost factor of 5 percent was added to the dry tower capital costs to account for retrofit costs.
• Intake pumping was assumed to decrease to zero or near zero. Therefore, no costs are included for intake or piping
modifications.
The dry cooling capital cost equation is shown below:
Capital Cost (Dollars) = -0.00000000008*(gpm)3 + 0.000l*(gpm) 2+ 189.77*(gpm) + 800490
Note that the capital costs do not include any consideration for replacement or modification of the steam turbines. Nor
do the O&M costs below include consideration of the effects on turbine efficiency resulting from the differences in
turbine exhaust pressure caused by changes in the cooling system.
Dry Cooling O&M Costs
EPA has revised the O&M costs using a different basis than was used for the New Facility Rule compliance cost
estimates. Rather than base the costs on factors applied to the capital cost as was previously done, EPA based the
O&M cost on energy requirements and cost information obtained from facility personnel and an air-cooled condenser
manufacturer.
O&M cost components include the following:
Labor costs starting at $12,000/yr for a 2,000 gpm equivalent system increasing to a maximum of two full time
maintenance personnel (at a salary of $55,250/yr) for a 204,000 gpm equivalent system.
• Fan energy costs are based on 800 gpm/MW and $6,000/MW. The $6,000/MW value is based on EPA's estimated
fan energy penalty of 2.4% plus an annual operating duration of 7860 hours and an average electricity value of
$30/MW-hr**.
• Costs for grease, oil, and high pressure spray cleaning starting at $500/yr for a 2,000 gpm equivalent system
increasing to $19,500 for a 204,000 gpm equivalent system.
Costs for blade replacement, gaskets and other minor items not covered by warranty starting at $3,000/yr for a
2,000 gpm equivalent system increasing to $9,600/yr for a 204,000 gpm equivalent system.
Since intake volumes are reduced to near zero, post-compliance monitoring costs are assumed to be zero.
The dry cooling O&M cost equation is shown below:
O&M (Dollars) = 53.122*(gpm) °8442
A dry cooling system manufacturer has indicated that major components including the air cooled condenser and fan
motors should not require replacement over the 30 yr life of the equipment.
** the average electricity price of $30 per MWh is a combination of the energy price and the capacity price for the 530
in-scope facilities modeled by the Integrated Planning Model (IPM). It is a weighted average of the 530 facilities, based
on the 2008 IPM base case run using the EPA electricity demand growth projections.
D-4
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§ 316(b) Phase II TDD Dry Cooling
Methodology for Dry Cooling Cost Estimates at New Facilities
EPA estimated the capital costs using relative cost factors for various types of wet towers and air cooled condensers
(that is, direct-dry cooling systems), using the cost of a comparable wet tower constructed of Douglas Fir as the basis.
EPA used cost factors developed by industry experts who manufacture, sell and install cooling towers, including air
cooled systems, for power plants and other applications. EPA based the capital costs on these factors with some
modifications. To be conservative, EPA chose the highest value within each range as the basis. The factors chosen
are 325 percent and 225 percent (of the cost of a mechanical wet tower) for capital cost (for a tower with a delta of 10
°F) and O&M cost, respectively. EPA applied a multiplier of roughly 1.7 to the dry tower capital cost estimates for
a delta of 10 °F to yield capital cost estimates for a dry tower with a delta of 5 °F. EPA applied these factors to the
capital costs derived for the basic steel mechanical draft wet cooling towers to yield the capital cost estimates for dry
towers.
Note that the source document for the factors forming the basis of the estimates states that the factors represent
comparable cooling systems for plants with the same generated electric power and the same turbine exhaust pressure.
Since the cost factors generate equivalent dry cooling systems, the tower costs can still be referenced to the
corresponding equivalent cooling water flow rate of the mechanical wet tower used as the cost basis. Since the §316(b)
analyses focuses primarily on water use, the use of the cooling flow or the "equivalent" was considered as the best way
to compare costs. The costing methodology uses an equivalent cooling water flow rate as the independent input variable
for costing dry towers.
Using the estimated costs, EPA developed cost equations using a polynomial curve fitting function. Table 1 presents
capital cost equations for dry towers with deltas of 5 and 10 degrees.
Table 1. Capital Cost Equations of Dry Cooling Towers with Delta of 5 °F and 10 °F
Capital Cost Equation1
Correlation
Coefficient
y = -2E-10x3 + 0.0002x2 + 337.56x + 973608
v = -8E-llx3 + O.OOOlx2 + 189.77x + 800490
R2 = 0.9989
R2 = 0.9979
1) x is for flow in gpm and y is cost in dollars.
Validation of Dry Cooling Capital Cost Curves
To validate the dry tower capital cost curves and equations, EPA compared the costs predicted by the equation for dry
towers with delta of 10 °F to actual costs for five dry tower construction proj ects provided by industry representatives.
To make this comparison, EPA first needed to estimate equivalent flows for the dry tower construction project costs.
Obviously, as noted above, dry towers do not use cooling water. However, for every power plant of a given capacity
there will, dependent on the selected design parameters, be a corresponding equivalent recirculating cooling water flow
that would apply if wet cooling towers were installed to condense the same steam load.
D-5
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§ 316(b) Phase II TDD Dry Cooling
EPA used the steam load rate and cooling system efficiency to determine the equivalent flow. Note that the heat
rejection rate will be proportional to the plant capacity. EPA estimated the flow required for a wet cooling tower that
is functionally equivalent to the dry tower by converting each plant's steam tons/hour into cooling flow in gpm using
the following equations:
Steam tons/hr x 2000 Ibs/ton x 1000 BTUs/lb steam = BTUs/hr
One ton/hr = 12,000 BTU/hr
BTUs/hr / 12000 = Tons of ice
Tons of Ice x 3 = Flow (gpm) for wet systems
Chart 4-2 presents a comparison of the EPA capital cost estimates for dry towers with delta of 10 °F (with 25% error
bars) to actual dry tower installations. This chart shows that EPA's cost curves produce conservative cost estimates,
since the EPA estimates are greater than all of the dry tower project costs based on the calculated equivalent cooling
flow rate for the actual projects.
D-6
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§ 316(b) Phase II TDD
Dry Cooling
Chart 4-1. Capital Costs of Dry Cooling Towers Versus Rows Of Replaced We* Cooling Towers
(5 &10 Degrees Delta)
$180,000,000
$160,000,000
$140,000,000
$120,000,000
o $100,000,000
o
re $80,000,000
O
$60,000,000
$40,000,000
$20,000,000
y=-2E-1 OX5 + 0.0002)? + 337.56x+ 973608
R2=0.9989
Coding Tower Cost fora
delta of 5 degrees
=-8E-11X3 + 0.0001X2 +189.77X+ 800490
R2=0.9979
Cooling Tower Cost for a
delta of 10 degrees
50000 100000 150000 200000 250000 300000 350000 400000 450000
Equivalent Wet Cooling Row GPM
• Dy Coding Delta 5 x Dy Coding DeltalO
D-7
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§ 316(b) Phase II TDD
Dry Cooling
Chart 4-2. Actual Capital Costs of Dry Coding Tower Projects and Cbrrparable Costs from ERA
Cost Curves
$140,000,000
$120,000,000
$100,000,000
tS $80,000,000
o
O
$
a.
Q $60,000,000
$40,000,000
$20,000,000
y=-8E-11>?+0.0001^+189.77x+800490
RP=0.9979
100000 200000 300000
B^Li^lett \Afet Coding Row (PM
X Dy Coding Casts Used in EEA • Mual Dy Coding Reject 0
400000 500000
D-,
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§ 316(b) Phase II TDD Dry Cooling
EVALUATION OF DRY COOLING AS BTA
This section presents a summary of EPA's evaluation of the dry cooling technology as a candidate for best technology
available to minimize adverse environmental impacts. Based on the information presented in the previous sections, EPA
concluded that dry cooling systems do not represent the best technology available.
First, EPA concluded that dry cooling is not demonstrated nor likely feasible for the existing facilities within the scope
of this proposed rule. As noted previously, indirect-dry cooling generally is the only application of the technology that
would be considered for retrofit situations at existing power plants because a condenser would already be in place for
a once-through or recirculating wet cooling system. As estimated by the DOE (2001), the comparative energy penalty
of a retrofitted indirect-dry cooling plant in a hot environment at peak-summer conditions can approach 18 percent at
a facility, thereby making dry cooling extremely unfavorable in many areas of the U.S. for some types of power plant
types. Additionally, the predicted turbine backpressures of these systems may debilitate the operation of some plants,
thereby severely disrupting energy supply and distribution.
In addition, EPA evaluated a regulatory option for dry cooling systems, based on favorable cost assumptions and
concluded that the costs of dry cooling systems are prohibitively high in comparison to the benefits.
In summary, EPA concluded that dry cooling is not technically or economically feasible for the existing facilities
potentially subject to this proposed rule, would increase air emissions due to dramatic energy penalties, and has a cost
that is orders of magnitude more than requirements of this proposed rule. For these reasons, EPA concluded that dry
cooling does not represent the "best technology available" for minimizing adverse environmental impact.
D-9
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§ 316(b) Phase II TDD Dry Cooling
REFERENCES
Burns, J. M. and W. C. Micheletti. November 2000. "Comparison of Wet and Dry Cooling Systems for Combined
Cycle Power Plants." Submitted as Appendix F to the comments of the Utility Water Act Group on EPA's Proposed
Regulations Addressing Cooling Water Intake Structures for New Facilities. [DCN No. 2-038B]
Burns, J. M. and W. C. Micheletti. June 2001. "Technical Review of Tellus Institute Report." Submitted as Appendix
A to the comments of the Utility Water Act Group on the Notice of Data Availability; Proposed Regulations Addressing
Cooling Water Intake Structures for New Facilities.
Dougherty, B.T. andS. Bernow. November 2000. "Comments on the EPA's Proposed Regulations on Cooling Water
Intake Structures for New Facilities." Tellus Institute. Boston, MA. [DCN No. 2-038A]
Elliott, T. C., Chen, K., andR. C. Swanekamp. 1998. Standard Handbook of Power Plant Engineering. 2.152-2.158.
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