United States Office of Water EPA-821-R-01-036
Environmental Protection (4303) November 2001
Agency
EPA Technical Development
Document for the Final
Regulations Addressing
Cooling Water Intake
Structures for New Facilities
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Technical Development Document for the Final Regulations
Addressing Cooling Water Intake Structures for New Facilities
U.S. Environmental Protection Agency
Office of Science and Technology
Engineering and Analysis Division
Washington, DC 20460
November 9, 2001
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This document was prepared by Office of Water staff. The following contractors (in alphabetical order) provided assistance
and support in performing the underlying analysis supporting the conclusions detailed in this report.
Abt Associates Inc.,
Science Applications International Corporation,
Stratus Consulting Inc., and
Tetra Tech.
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Section 316(b) EA for New Facilities Table of Contents
Table of Contents
Chapter 1: Baseline Projections of New Facilities
1.1 New Electric Generators 1-2
1.1.1 Methodology 1-2
1.1.2 Projected Number of New Electric
Generators 1-5
-10
-11
-11
-17
-21
-21
-23
1.1.3 Summary of Forecasts for New Electric Generators
1.2 New Manufacturing Facilities
1.2.1 Methodology
1.2.2 Projected Number of New Manufacturing Facilities
1.2.3 Summary of Forecasts for New Manufacturing Facilities .
1.3 Summary of Baseline Projections
References
Chapter 2: Costing Methodology
2.1 Background 2-1
2.2 Overview of Costing Methodology 2-2
2.3 Facility Level Costs 2-4
2.3.1 General Approach 2-4
2.3.2 Capital Costs 2-5
2.3.3 Operation & Maintenance Costs 2-5
2.3.4 Development of Model Facilities 2-6
2.3.5 Wet Tower Intake Flow Factors 2-6
2.3.6 Baseline Cost Components 2-8
2.3.7 Baseline Once-Through Cooling 2-8
2.3.8 Baseline Recirculating Wet Towers 2-8
2.4 Compliance Cost Components 2-8
2.4.1 Recirculating Wet Towers 2-8
2.4.2 Reuse / Recycle 2-9
2.5 Cost Estimation Assumptions and Methodology 2-9
2.5.1 Once-Through Capital Costs 2-9
2.5.2 Once-ThroughO&M 2-12
2.5.3 Recirculating Wet Tower Capital Costs 2-12
2.5.2 Wet Tower O&M Costs 2-12
2.6 Alternative Regulatory Options 2-12
2.6.1 Opt 1: Technology-Based Performance Requirements for Different Waterbodies 2-13
2.6.2 Opt 2a: Flow Reduction Commensurate with Closed-Cycle Recirculating Wet Cooling 2-13
2.6.3 Opt 2b: Flow Reduction Commensurate with Dry Cooling Systems 2-14
2.6.4 Opt 3: Industry Two-Track Option 2-15
2.7 Summary of Costs by Regulatory Option 2-15
2.7.1 Final Rule 2-15
2.7.2 Option 1 2-17
2.7.3 Option 2a 2-18
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Section 316(b) EA for New Facilities Table of Contents
2.7.4 Option 2b 2-19
2.7.5 Option 3 2-20
2.8 Technology Unit Costs 2-21
2.8.1 General Cost Information 2-21
2.8.2 Flow 2-23
2.8.3 Additional Cost Considerations 2-24
2.8.4 Replacement Costs 2-26
2.9 Specific Cost Information for Technologies and Actions 2-26
2.9.1 Reducing Design Intake Flow 2-26
2.9.2 Reducing Design Intake Velocity 2-39
2.9.3 Design and Construction Technologies to Reduce Damage from Impingement and Entrainment 2-45
2.10 Additional Cost Information 2-56
References 2-57
Charts 2-1 through 2-30 2-60
Chapter 3: Energy Penalty, Air Emissions, and Cooling Tower Side-Effects
3.1 Energy Penalty Estimates for Cooling 3-2
3.2 Air Emissions Estimates for Cooling System Upgrades 3-6
3.3 Background, Research, and Methodology of Energy Penalty Estimates 3-6
3.3.1 Power Plant Efficiencies 3-6
3.3.2 Turbine Efficiency Energy Penalty 3-9
3.3.3 Energy Penalty Associated with Cooling System Energy Requirements 3-22
3.4 Air Emissions Increases 3-31
3.5 Other Environmental Impacts 3-33
3.5.1 Vapor Plumes 3-33
3.5.2 Displacement of Wetlands or Other Land Habitats 3-34
3.5.3 Salt or Mineral Drift 3-34
3.5.4 Noise 3-35
3.5.5 Solid Waste Generation 3-36
3.5.6 Evaporative Consumption of Water 3-36
3.5.7 Manufacturers 3-36
References 3-37
Attachment A Steam Power Plant Heat Diagram
Attachment B Turbine Exhaust Pressure Graphs
Attachment C Design Approach Data for Recently Constructed Cooling Towers
Attachment D Tower Size Factor Plot
Attachment E Cooling Tower Wet Bulb Versus Cold Water Temperature Performance Curve
Attachment F Summary and Discussion of Public Comments on Energy Penalty Estimates
Chapter 4: Dry Cooling
4.1 Demonstrated Dry Cooling Projects 4-2
4.2 Impacts of Dry Cooling 4-2
4.2.1 Cooling Water Reduction 4-6
4.2.2 Environmental and Energy Impacts 4-6
4.2.3 Costs of Dry Cooling 4-6
4.2.4 Methodology for Dry Cooling Cost Estimates 4-8
4.2.5 Economic Impacts 4-8
4.3 Evaluation of Dry Cooling as BTA 4-13
References 4-14
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Section 316(b) EA for New Facilities Table of Contents
Chapter 5: Efficacy of Cooling Water Intake Structure Technologies
5.1 Scope of Data Collection Efforts 5-1
5.2 Data Limitations 5-2
5.3 Closed-Cycle Cooling System Performance 5-3
5.4 Conventional Traveling Screens 5-3
5.5 Alternative Technologies 5-4
5.5.1 Modified Traveling Screens and Fish Handling and Return Systems 5-4
5.5.2 Cylindrical Wedgewire Screens 5-6
5.5.3 Fine-Mesh Screens 5-7
5.5.4 Fish Barrier Nets 5-8
5.5.5 Aquatic Microfiltration Barriers 5-9
5.5.6 Louver Systems 5-10
5.5.7 Angular and Modular Inclined Screens 5-11
5.5.8 Velocity Caps 5-13
5.5.9 Porous Dikes and Leaky Dams 5-13
5.5.10 Behavioral Systems 5-14
5.5.11 Other Technology Alternatives 5-14
5.6 Intake Location 5-15
5.7 Summary 5-17
References 5-20
Attachment A CWIS Technology Fact Sheets
Chapter 6: Industry Profile: Oil and Gas Extraction Industry
6.1 Historic and Projected Drilling Activities 6-1
6.2 Offshore and Coastal Oil and Gas Extraction Facilities 6-4
6.2.1 Fixed Oil and Gas Extraction Facilities 6-4
6.2.2 Mobile Oil and Gas Extraction Facilities 6-9
6.3 316(b) Issues Related to Offshore and Coastal Oil and Gas Extraction Facilities 6-9
6.3.1 Biofouling 6-9
6.3.2 Definition of New Souce 6-10
6.3.3 Potential Costs and Scheduling Impacts 6-10
6.3.4 Description of Benefits for Potential 316(b) Controls on Offshore and Coastal Oil and
Gas Extraction Facilities 6-12
6.4 Phase III Activities Related to Offshore and Coastal Oil and Gas Extraction Facilities 6-12
References 6-13
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§ 316(b) TDD Chapter 1 for New Facilities
Baseline Projections of New Facilities
Chapter 1: Baseline Projections of
New Facilities
INTRODUCTION
Chapter Contents
1.1 New Electric Generators 1-2
1.1.1 Methodology 1-2
1.1.2 Projected Number of New Electric
Generators 1-5
1.1.3 Summary of Forecasts for New Electric
Generators 1-10
New Manufacturing Facilities 1-11
1.2.1 Methodology 1-11
1.2.2 Projected Number of New Manufacturing
Facilities 1-17
1.2.3 Summary of Forecasts for New Manufacturing
Facilities 1-21
Summary of Baseline Projections 1-21
1.2
1.3
References
1-23
Facilities regulated under the final § 316(b) New
Facility Rule are new greenfield and stand alone
electric generators and manufacturing facilities
that operate a new cooling water intake structure
(CWIS) (or a CWIS whose design capacity is
increased), require a National Pollutant Discharge
Elimination System (NPDES) permit, have a
design intake flow of equal to or greater than two
million gallons per day (MOD), and use at least 25
percent of their intake water for cooling purposes.
The overall costs and economic impacts of the
final rule depend on the number of new facilities
subject to the rule and on the planned
characteristics (i.e., construction, design, location, and capacity) of their CWISs. The projection of the number and
characteristics of new facilities represents baseline conditions in the absence of the rule and identifies the facilities
that will be subject to the final § 316(b) New Facility Rule.
EPA did not consider the oil and gas industry in the Phase I 316(b) rulemaking for new facilities. The Phase I
proposal and its record included no analysis of issues associated with offshore and coastal oil and gas extraction
facilities that could significantly increase the costs and economic impacts and affect the technical feasibility of
complying with the proposed requirements for land-based industrial operations. Additionally, EPA believes it is not
appropriate to include these facilities in the Phase II regulations scheduled for proposal in February 2002; the Phase
II regulations are intended to address the largest existing facilities in the steam-electric generating industry. During
Phase III, EPA will address cooling water intake structures at existing facilities in a variety of industry sectors.
Therefore, EPA believes it is most appropriate to defer rulemaking for offshore and coastal [oil and gas] extraction
facilities to Phase III. For further discussion, see Chapter 5: Industry Profile - Oil and Gas Extraction Industry.
This chapter provides a summary EPA's forecasts for the number of new electric generators and manufacturing
facilities subject to the final § 316(b) New Facility Rule that will begin operating between 2001 and 2020. The
chapter consists of four sections. The first three sections address the forecasts of new facilities and the final section
presents a profile of the electricity generation industry. Section 1.1 presents the estimates for the number and
characteristics of new electric generating facilities. Section 1.2 presents the estimates for the number of new
manufacturing facilities. Section 1.3 summarizes the results of the new baseline projections of facilities. For
detailed discussion of the methodology behind the forecasts consult Chapter 5 of the Economic Analysis.
1-1
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§ 316(b) TDD Chapter 1 for New Facilities Baseline Projections of New Facilities
1.1 NEW ELECTRIC GENERATORS
EPA estimates that 83 new electric generators subject to the final § 316(b) New Facility Rule will begin operation
between 2001 and 2020. Of these, 69 are new combined-cycle facilities and 14 are new coal facilities.1 This
projection is based on a combination of national forecasts of new steam electric capacity additions and information
on the characteristics of specific facilities that are planned for construction in the near future or that have been
constructed in the recent past. Using these two types of information, EPA developed model facilities that provide
the basis for estimating costs and economic impacts for electric generators throughout the remainder of this
document. For more detailed information regarding new electric generators, see Economic Analysis of the Final
Regulations Addressing Cooling Water Intake Structures for New Facilities.
1.1.1 Methodology
EPA used four main data sources to project the number and characteristics of new steam electric generators subject
to the final rule: (1) the Energy Information Administration's (EIA) Annual Energy Outlook 2001 (AEO2001); (2)
Resource Data International's (RDI) NEWGen Database, (3) EPA's § 316(b) industry survey of existing facilities;
and (4) EIA's Form EIA-860A and 860B databases. The following sections provide detail on each data source used
in this analysis. The final subsection 5.1.1 .e summarizes how EPA combined the information from the different data
sources to calculate the number of new combined-cycle and coal facilities.
Annual Energy Outlook 2001
The Annual Energy Outlook (AEO) is published annually by the U.S. Department of Energy's Energy Information
Administration (EIA) and presents forecasts of energy supply, demand, and prices. These forecasts are based on
results generated from EIA's National Energy Modeling System (NEMS). The NEMS system generates projections
based on known levels of technological capabilities, technological and demographic trends, and current laws and
regulations. Other key assumptions are made regarding the pricing and availability of fossil fuels, levels of economic
growth, and trends in energy consumption. The AEO projections are used by Federal, State, and local governments,
trade associations, and other planners and decision makers in both the public and private sectors. EPA used the most
recent forecast of capacity additions between 2001 and 2020 (presented in the AEO2001) to estimate the number of
new combined-cycle and coal-fired steam electric plants.
The AEO2001 presents forecasts of both planned and unplanned capacity additions between 2001 and 2020 for eight
facility types (coal steam, other fossil steam, combined-cycle, combustion turbine/diesel, nuclear, pumped
storage/other, fuel cells and renewables). EPA has determined that only facilities that employ a steam electric cycle
require significant quantities of cooling water and are thus potentially affected by the final § 316(b) New Facility
Rule. As a result, this analysis considers capacity additions associated with coal steam, other fossil steam, combined-
cycle, and nuclear facilities only. In its Reference Case, the AEO2001 forecasts total capacity additions of 370 GW
Combined-cycle facilities use 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 a heat
recovery steam generator for utilization by a steam turbine to produce electricity. This process increases the efficiency of the
electric generating unit.
1-2
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§ 316(b) TDD Chapter 1 for New Facilities Baseline Projections of New Facilities
from all facility types between 2001 and 2020.2 Coal steam facilities account for 22 GW, or 6 percent of the total
forecast, and combined-cycle facilities account for 204 GW, or 55 percent. The remaining capacity additions, 39
percent of the total, come from non-steam facility types. Based on all available data in the rulemaking record, EPA
projects no new additions for nuclear and other fossil steam capacity.
NEWGen Database
The NEWGen database is created and regularly updated by Resource Data International's (RDI) Energy Industry
Consulting Practice. The database provides detailed facility-level data on electric generation proj ects, including new
(greenfield and stand alone) facilities and additions and modifications to existing facilities, proposed over the next
several years. Information in the NEWGen database includes: generating technology, fuel type, generation capacity,
owner and holding company, electric interconnection, project status, on-line dates, and other operational details.
The majority of the information contained in this database is obtained from trade journals, developers, local
authorities, siting boards, and state environmental agencies.
EPA used the February 2001 version of the NEWGen database to develop model facilities for the economic analysis
of electric generators. Specifically, the database was used to:
*• calculate the percentage of total combined-cycle capacity additions derived from new (greenfield and stand
alone) facilities;
*• calculate the percentage of total coal capacity additions derived from new (greenfield and stand alone)
facilities;
*• estimate the in-scope percentage of new combined-cycle facilities; and
*• determine the technical, operational, and ownership characteristics of new in-scope combined-cycle
facilities.
§ 316(b) Industry Survey of Existing Facilities
Because the NEWGen database discussed in the previous section contained information on only 16 new (greenfield
and stand alone) coal facilities, EPA believes that information from EPA's § 316(b) industry survey of existing
facilities (Industry Screener Questionnaire: Phase I Cooling Water Intake Structures, Detailed Industry
Questionnaire: Phase II Cooling Water Intake Structures, and Industry Short Technical Questionnaire: Phase II
Cooling Water Intake Structures) was more reliable for estimating characteristics of new coal facilities projected
over the 2001-2020 analysis period because it included far more plants over a longer time period.
All three survey instruments requested technical information, including the facility's in scope status, cooling system
type, intake flow, and source water body. In addition, the screener questionnaire and the detailed questionnaire also
requested economic and financial information. For more information on the three survey instruments, see ICRNo.
1973.02.
2Among other model parameters, the AEO2001 Reference Case assumes economic growth of 3 percent and electricity
demand growth of 1.8 percent.
1-3
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§ 316(b) TDD Chapter 1 for New Facilities Baseline Projections of New Facilities
EPA used the following survey data on coal plants constructed during the past 20 years to project the number and
characteristics of new (greenfield and stand alone) coal facilities: in-scope status, waterbodytype, and cooling system
type.3
In developing model coal facilities, EPA only considered those existing survey plants that have a once-through
system, a recirculating system, or a recirculating system with a cooling lake or pond.
EIA Databases
In addition to the § 316(b) industry survey of existing facilities, EPA used two of EIA's electricity databases (Form
EIA-860A, Annual Electric Generator Report - Utility; and Form EIA-860B, Annual Electric Generator Report -
Nonutility; both 1998) in the analysis of projected new coal plants. EPA used these databases for three purposes:
*• Identify which of the surveyed electric generators are "coal" plants: EPA used the prime mover and the
primary energy source, reported in the EIA databases, to determine if a surveyed facility is a coal plant. Only
plants that only have coal units were considered in this analysis.
*• Identify coalplants constructed during the past 20 years: Both EIA databases request the in-service date of
each unit. Of the surveyed facilities, 111 coal-fired plants began commercial operation between 1980 and
1999.
*• Determine the average size of new coalplants: The 111 identified coal plants have an average nameplate
rating of 475 MW.4
Summary of the Number of New Facilities
EPA estimated the number of projected new combined-cycle and coal plants using information from the four data
sources described in subsections 5.1.1.a to 5.1.l.d above. EPA used the U.S. Department of Energy's estimate of
new capacity additions (combined-cycle: 204 GW, coal: 22 GW) and multiplied it by the percentage of capacity
additions that will be built at new facilities (combined-cycle: 88%, coal: 76%) to determine the new capacity that will
be constructed atnew facilities (combined-cycle: 179 GW, coal: 17 GW). EPA then divided this value by the average
facility size (combined-cycle: 741 MW, coal: 475 MW) to determine the total number of potential new facilities
(combined-cycle: 241, coal: 35; both in scope and out of scope of today's final rule). Finally, based on EPA's
estimate of the percentage of facilities that meet the two MGD flow threshold (combined-cycle: 28.6%, coal: 40.5%),
EPA estimates there will be 69 new in-scope combined-cycle facilities and 14 new coal facilities over the 2001-2020
period.
Development of Model Facilities
The final step in the baseline projection of new electric generators was the development of model facilities for the
costing and economic impact analyses. This step required translating characteristics of the analyzed combined-cycle
and coal facilities into characteristics of the 83 projected new facilities. The characteristics of interest are: (1) the type
of water body from which the intake structure withdraws (freshwater or marine water); (2) the facility's type of
3Coal plants constructed during the past 20 years were identified from Forms EIA-860A and EIA-860B. See discussion in
subsection 1.1.1 .d below.
4The average capacity for in-scope coal facilities is 763 MW, while the average for out of scope coal facilities is 278 MW.
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§ 316(b) TDD Chapter 1 for New Facilities
Baseline Projections of New Facilities
cooling system (once-through or recirculating system); and (3) the facility's steam electric generating capacity. The
following two subsections discuss how EPA developed model facilities for combined-cycle and coal facilities,
respectively.
1.1.2 Projected Number of New Electric Generation Facilities
Combined-Cycle Facilities
EPA's analysis projected 69 new in-scope combined-cycle facilities. Cooling water and economic characteristics of
these 69 facilities were determined based on the characteristics of the 57 in-scope NEWGen facilities.5 EPA
developed six model facility types based on the 57 facilities' combinations of source water body and type of cooling
system. Within each source water body/cooling system group, EPA created between one and three model facilities,
depending on the number of facilities within that group and the range of their steam electric capacities.
Based on the distribution of the 57 NEWGen facilities by source water body group, cooling system type, and size
group, EPA determined how many of the 69 projected new facilities are represented by each of the six model facility
types. Table 1-1 below presents the six model facility types, their estimated steam electric capacity, the number of
NEWGen facilities upon which each model facility type was based, and the number of projected new facilities that
belong to each type.
Table 1-1: Combined -Cycle Model Facilities
Model
Facility Type
CC OT/M-1
CCR/M-1
CCR/M-2
CCR/FW-1
CC R/FW-2
CC R/FW-3
Total
Cooling System
Type
Once Through
Recirculating
Recirculating
Recirculating
Recirculating
Recirculating
Source i Steam Electric i Number of i Number of Projected
Water Body | Capacity (MW) ! NEWGen Facilities | New Facilities
Marine i
Marine i
Marine i
Freshwater i
Freshwater i
Freshwater i
1,031 !
489 !
1,030 !
439 !
699 !
1,061 !
4 i
4 i
1 I
15 i
17 i
16 !
57 i
5
5
1
18
21
19
69
Source: EPA Analysis, 2001.
Generally, NEWGen facilities were not always consistent in how they reported their intake flows. Some NEWGen
facilities reported design flows, some reported maximum flows and some reported average flows. It was therefore
necessary to estimate design flows for those facilities that had reported either maximum or average flows. To do
5EPA could determine the water body type for all 57 in-scope facilities but did not have information on the cooling system
type for 18 facilities. Since all freshwater facilities with a known cooling system type propose to build a recirculating system,
EPA assumed that the 15 freshwater facilities with an unknown cooling system type will also build a recirculating system. For
marine facilities, EPA assumed that two of the three facilities with an unknown system type would build a recirculating system
in the baseline while one would build a once-through system.
1-5
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§ 316(b) TDD Chapter 1 for New Facilities
Baseline Projections of New Facilities
so, EPA assumed estimated design flows to be equivalent to maximum flows, or to three times average flows, based
on the results of previous analysis of DQ combined cycle power plants. As was done for the coal-fired plants, EPA
normalized estimated design flows for the NEWGen facilities by dividing by MW capacities.
Many NEWGen facilities did not report any intake flow information. EPA developed model facility flow estimates
based only on those NEWGen facilities for which flows had been reported. The NEWGen facilities that did not
report flows were assumed to follow the same distribution as those which had reported flow information.
EPA grouped the NEWGen facilities according to CWS type (once-through vs. recirculating) and water body type
(freshwater vs. marine) to yield several baseline scenarios. The baseline scenarios for combined cycle power plants
are listed in Table 1-2 below.
Table 1-2: Baseline Combined Cycle Power Plant Scenarios
Industry Category
Combined Cycle
Power Plants
Combined Cycle
Power Plants
Combined Cycle
Power Plants
Industry Description
Includes both Utility and Non-utility
facilities
Includes both Utility and Non-utility
facilities
Includes both Utility and Non-utility
facilities
Baseline Cooling Water Body Type
Technology
Once-through Marine
Recirculating with Wet Marine
Towers
Recirculating with Wet Freshwater
Towers
It should be noted that a once-through, freshwater model plant was not developed because none of the NEWGen
facilities fell into this baseline scenario. Within each baseline scenario, EPA developed combined cycle model
facilities to represent low, medium and high MW capacity plants, using a similar methodology to that used to develop
the coal-fired model facilities. Table 1-3 below presents the baseline intake and cooling flow values used in
estimating the compliance costs for these model combined cycle power plants.
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§ 316(b) TDD Chapter 1 for New Facilities
Baseline Projections of New Facilities
Table 1-3: Additional Combined
Model Facility
ID
CC OT/M-1
CCR/M-1
CCR/M-2
CCR/FW-1
CC R/FW-2
CC R/FW-3
Baseline Cooling
Water System
Once Through
Recirculating
Recirculating
Recirculating
Recirculating
Recirculating
Cycle Power Plant Model Facility Baseline Intake and
Values
Waterbody Type
Marine
Marine
Marine
Freshwater
Freshwater
Freshwater
Capacity
(MW)
1031
489
1030
439
699
1061
Baseline
Intake Flow
(MGD)
613
8
18
10
12
14
Cooling Flow
Baseline
Cooling Flow
(MGD)
613
106
223
198
230
283
Coal Facilities
EPA's analysis projected 14 new in-scope coal facilities. The same approach was used to assign cooling water and
economic characteristics to these 14 facilities as was used for combined-cycle facilities (see discussion in the previous
section). EPA determined the characteristics of the 14 projected new coal facilities based on the characteristics of
the 41existing in-scope coal facilities. EPA developed eight model facility types based on the 41 facilities' source
water body and their type of cooling system. Within each source water body/cooling system group, EPA created
between one and three model facilities, depending on the number of facilities within that group and the range of their
steam electric capacities. Based on the distribution of the 41 survey facilities by source water body group, cooling
system type, and size group, EPA determined how many of the 14 projected new coal facilities are represented by
each of the eight model facility types. Table 1-4 below presents the eight model facility types, their estimated steam
electric capacity, the number of survey facilities upon which each model facility type was based, and the number of
projected new coal facilities that are represented by each type.
1-7
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§ 316(b) TDD Chapter 1 for New Facilities
Baseline Projections of New Facilities
Model
Facility Type
CoalR/M-1
Coal
OT/FW-1
Coal
OT/FW-2
Coal
OT/FW-3
CoalR/FW-1
Coal R/FW-2
Coal R/FW-3
Coal
RL/FW-1
Total
Table
Cooling System Type i
Recirculating i
Once Through i
Once Through i
Once Through i
Recirculating i
Recirculating i
Recirculating i
Recirculating with Lake3 i
1-4: Coal
ource Wate
Body
Marine
Freshwater
Freshwater
Freshwater
Freshwater
Freshwater
Freshwater
Freshwater
Model Facilities
; Steam Electric i Number of i
; Capacity i Existing Survey i
i (MW) i Facilities |
i 812 ! 3 !
! 63 i 3 1
i 515 i 5 i
i 3,564 i 1 i
! 173 ! 10 !
i 625 i 7 !
i 1,564 ! 8 !
1 660 i 4 1
i i 41 i
Number of
Projected New
Facilities
1
1
1
1
3
3
3
1
14
a For this analysis, recirculating facilities with cooling lakes are assumed to exhibit characteristics like a once-
through facility.
Source: EPA Analysis, 2001.
Data taken from the surveys included both design intake flow and average intake flows, where available. With the
exception of monitoring costs, all cost components used either the design intake flow or the design cooling water
flow (which was estimated from the design intake flow as described in Section 2.3.5 of Chapter 2: Wet Tower Intake
Flow Factors) as the input variable for deriving the cost. However, design intake flow data were not available for
the SQ and screener facilities. It was therefore necessary to estimate design intake flows for these facilities. To do
this, EPA calculated ratios of design to average intake flow (D/A) for those DQ facilities for which both design intake
and average intake flows were available. These facilities were then grouped according to cooling water system
(CWS) type (i.e., once-through vs. recirculating), and an average D/A ratio was calculated for each CWS type. This
yielded average D/A ratios of 1.18 for once-through coal-fired plants and 2.94 for recirculating coal-fired plants.
EPA then used these average D/A ratios to estimate design flows for those facilities for which design flows were not
available (D/A ratio was multiplied by average flow to yield estimated design flow).
Where design condenser flows were available from EEI1996 data, EPA compared the estimated design intake flows
to the design condenser flows as a check of their reasonableness. For once-through facilities, the design intake flow
would be expected to be similar in magnitude to the design condenser flow, while for recirculating facilities with
cooling towers, the design intake flows would be expected to be only a fraction of the design condenser flows. In
almost all cases, the estimated design flows were found to meet these expectations.
1 -,
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§ 316(b) TDD Chapter 1 for New Facilities
Baseline Projections of New Facilities
For a few facilities, however (notably, the facilities that had recirculating CWSs with cooling ponds), EPA found
the estimated design flows (calculated using the recirculating system D/A ratio of 2.94) to be several times higher
than the design condenser flows. Therefore, forthese facilities, the design condenser flows were used as being more
representative of the design intake flows that might be expected for such facilities (in fact, the design condenser
flows were much more in line with estimated design flows calculated using the once-through D/A ratio of 1.18).
See Chapter 2 for additional discussion of these recirculating facilities with cooling ponds.
Four survey facilities with estimated design flows less than the regulatory threshold of 2 million gallons per day
(MOD) were then eliminated from the flow analysis as being out of scope. The regulatory threshold represents the
intake flow rate at which intake systems would be required to comply with the regulation. Only those survey
facilities that were in scope (i.e., met the 2 MOD regulatory threshold) were included in the analysis to develop the
model facilities.
EPA then normalized the design flows for the in-scope facilities by dividing the design flow for each facility by the
corresponding MW capacity for that facility to yield a ratio of design flow to MW capacity (MGD/MW). This was
necessary in order to apply the flow values for plants with a range of MW capacities to average capacity model
plants.
EPA then grouped the surveyed facilities according to CWS type and water body type to yield several baseline
scenarios. The various water body types were divided into two general categories: freshwater, which included
facilities located on freshwater rivers, streams, lakes or reservoirs; and marine, which included facilities located on
tidal rivers, estuaries and oceans. The baseline scenarios for coal-fired power plants are listed in Table 1-5 below.
Table 1-5: Baseline Coal-Fired Power Plant Scenarios
Industry
Category
Coal-fired
Power Plants
Coal-fired
Power Plants
Coal-fired
Power Plants
Coal-fired
Power Plants
Industry Description
Includes both Utility and Non-utility
facilities
Includes both Utility and Non-utility
facilities
Includes both Utility and Non-utility
facilities
Includes both Utility and Non-utility
facilities
Baseline Cooling
Technology
Once-through
Recirculating with
Wet Towers
Recirculating with
Wet Towers
Recirculating with
Cooling Ponds
Water Body Type
Freshwater (includes freshwater
rivers, streams, lakes, and reservoirs
Freshwater
Marine (includes tidal rivers,
estuaries, and oceans)
Freshwater
It should be noted that EPA did not develop a once-through, marine baseline scenario for coal-fired power plants
because none of the surveyed facilities (and therefore none of the projected new facilities) fell into this baseline
scenario. It should also be noted that EPA developed a separate baseline scenario for coal-fired power plants that
had recirculating CWSs with cooling ponds. The design intake flows and MGD/MW ratios for these facilities were
found to be much higher than those for the coal-fired power plants that had recirculating systems with wet cooling
towers-more in line with what might be expected for once-through facilities. This would not be entirely unexpected,
if the reported flows forthese facilities represented the flows of water withdrawn from the cooling ponds for cooling
1-9
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§ 316(b) TDD Chapter 1 for New Facilities
Baseline Projections of New Facilities
use within the plants, rather than the flows of make-up intake water to the cooling ponds. EPA therefore decided
that these recirculating plants with cooling ponds deserved to be treated as a separate baseline scenario. For purposes
of cost estimation, these facilities were treated the same as once-through facilities. This represented a conservative
approach since, if anything, it would tend to overestimate the size of the baseline cooling water system that would
have to be replaced, as well as the corresponding compliance cost.
Within each baseline scenario, EPA ranked the survey facilities in ascending order of their MW capacities. EPA then
divided the ranked survey facilities into groups to yield low, medium and high MW capacity model facilities. For
baseline scenarios where only a single new facility was projected, only average MW capacities were calculated. EPA
developed corresponding average MGD/MW ratios for each grouping. The low, medium and high MW capacities
for each baseline scenario were then multiplied by the corresponding average MGD/MW ratios to yield normalized
design flow estimates for low, medium and high MW capacity model facilities. EPA then estimated the cooling water
flows for the model facilities based on the design intake flows, as described below under Chapter 2, Section 2.3.5:
Wet Tower Intake Flow Factors. Table 1-6 below presents the baseline intake and cooling flow values used in
estimating the compliance costs for the different model coal-fired plants.
Table 1-6: Coal-Fired Power Plant Model Facility Baseline Intake and Cooling Flow Values
Baseline
Cooling Flow
(MOD)
Recirculating with
Coolin
Model Facility
ID
Baseline Cooling
Water System
Waterbody Type
Capacity (MW) Baseline Intake
Flow
(MOD)
Coal OT/FW-1
Coal OT/FW-2
Coal OT/FW-3
CoalR/M-1
CoalR/FW-1
Coal R/FW-2
Coal R/FW-3
CoalRL/FW-1
Once Through
Once Through
Once Through
Recirculating
Recirculating
Recirculating
Recirculating
Freshwater
Freshwater
Freshwater
Marine
Freshwater
Freshwater
Freshwater
Freshwater
1.1.3 Summary of Forecasts for New Electric Generators
EPA estimates that a total of 276 new steam electric generators will begin operation between 2001 and 2020. Of the
total number of new plants, EPA projects that 83 will be in scope of the final § 316(b) New Facility Rule. Sixty-nine
are expected to be combined-cycle facilities and 14 coal-fired facilities. Table 1-7 summarizes the results of the
analysis.
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§ 316(b) TDD Chapter 1 for New Facilities
Baseline Projections of New Facilities
Table 1-7: Number of Projected New Electric Generators (2001 to 2020)
Facility Type
Combined-Cycle
Coal
Total
Total
Number of
New
Facilities
241
35
276
Facilities In Scope of the Final Rule
Recirculating i Recirc. with Lake I Once- Through
Freshwater i Marine i Freshwater i Marine i Freshwater i Marine
58 i 6 ! 0 ! 0 ! 0 ! 5
9 i i i i i o i 3 i o
67 i 7 i 1 i 0 i 3 i 5
Total
69
14
83
Source: EPA Analysis, 2001.
1.2 NEW MANUFACTURINS FACILITIES
EPA estimates that 38 new manufacturing facilities subject to the final § 316(b) New Facility Rule will begin
operation between 2001 and 2020. Of the 38 facilities, 22 are chemical facilities, ten are steel facilities, two are
petroleum refineries, two are paper mills, and two are aluminum facilities. The projection is based on a combination
of industry-specific forecasts and information on the characteristics of existing manufacturing facilities. For more
detailed information regarding new manufacturing facilities, see Economic Analysis of the Final Regulations
Addressing Cooling Water Intake Structures for New Facilities.
1.2.1 Methodology
EPA used several steps to estimate the number of new manufacturing facilities subject to the final rule. For each
industry sector, EPA:
*• identified the SIC codes with potential new in-scope facilities;
*• obtained industry growth forecasts;
*• determined the share of growth from new (greenfield and stand alone) facilities;
*• projected the number of new facilities;
*• determined cooling water characteristics of existing facilities; and
*• developed model facilities.
The remainder of this section briefly outlines each of these six steps. The following Section 5.2.2 describes the
baseline projections of new manufacturing facilities for each of the five industry sectors.6
SIC codes with potential new in-scope facilities
EPA used results from the § 316(b) Detailed Industry Questionnaire: Phase II Cooling Water Intake Structures
to identify the SIC codes within each of the five industry sectors that are likely to have one or more new (greenfield
6This analysis divides the Primary Metals sector (SIC 33) into two subsectors: steel (SIC 331) and aluminum (SIC
333/335). Section 5.2.2 therefore discusses five separate sectors, not four.
-------
§ 316(b) TDD Chapter 1 for New Facilities Baseline Projections of New Facilities
and stand alone) facilities subject to the final § 316(b) New Facility Rule. SIC codes that were included in this
analysis are those that, based on the Detailed Industry Questionnaire, have at least one existing facility that meets the
in-scope criteria of the final rule. Facilities meet the in-scope criteria of the final rule if they:
*• use a CWIS to withdraw from a water of the U.S.;
> hold an NPDES permit;
*• withdraw at least two million gallons per day (MOD); and
*• use 25 percent or more of their intake flow for cooling purposes.7
For each SIC code with at least one in-scope survey respondent, EPA estimated the total number of facilities in the
SIC code (based on the sample weighted estimate from EPA's § 316(b) industry survey of existing facilities), the
number of in-scope survey respondents, and the in-scope percentage.
Industry growth forecasts
Forecasts of the number of new (greenfield and stand alone) facilities that will be built in the various industrial
sectors are generally not available over the 20-year time period required forthis analysis. Projected growth rates for
value of shipments in each industry were used to project future growth in capacity. A number of sources provided
forecasts, including the annual U.S. Industry Trade & Industry Outlook (2000), the Assumptions to the Annual
Energy Outlook 2001, and other sources specific to each industry. EPA assumed that the growth in capacity will
equal growth in the value of shipments, except where industry-specific information supported alternative
assumptions.
Share of growth from new facilities
There are three possible sources of industry growth: (1) construction of new (greenfield and stand alone) facilities;
(2) higher or more efficient utilization of existing capacity; and (3) capacity expansions at existing facilities. Where
available, information from industry sources provided the basis for estimating the potential for construction of new
facilities. Where this information was not available, EPA assumed as a default that 50 percent of the projected
growth in capacity will be attributed to new facilities. This assumption likely overstates the actual number of new
(greenfield and stand alone) facilities that will be constructed.
Projected number of new facilities
EPA projected the number of new facilities in each SIC code by multiplying the total number of existing facilities
by the forecasted 10-year growth rate for that SIC code. The resulting value was then multiplied by the share of
growth from new facilities to derive the total number of new facilities over ten years. However, not all of the
projected new facilities will be subject to requirements of the final § 316(b) New Facility Rule. Information on the
likely water use characteristics of new facilities that will determine their in-scope status under the final rule is
generally not available for future manufacturing facilities. EPA estimated that the characteristics of new facilities
will be similar to the characteristics of existing survey respondents (i.e., the percentage of new facilities subject to
the final rule would be the same as the percentage of existing facilities that meet the rule's in-scope criteria). EPA
7For convenience, existing facilities that meet the criteria of the final § 316(b) New Facility Rule are referred to as
"existing in-scope facilities" or "in-scope survey respondents." As existing facilities, they will not in fact be subject to the
rule. However, they would be subject to the final § 316(b) New Facility Rule if they were new facilities.
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§ 316(b) TDD Chapter 1 for New Facilities Baseline Projections of New Facilities
then calculated the number of new in-scope facilities by multiplying the 10-year forecast of new facilities by the in-
scope percentage of existing facilities. To derive the 20-year estimate, both the estimated total number of new
facilities and the estimated number of new in-scope facilities were doubled. This approach most likely overstates
the number of new facilities that will incur regulatory costs, because new facilities may be more likely than existing
ones to recycle water and use cooling water sources other than a water of the U.S.
Cooling water characteristics of existing in- scope facilities
EPA used information from EPA's § 316(b) Detailed Industry Questionnaire: Phase II Cooling Water Intake
Structures to determine the characteristics of the in-scope survey respondents. The survey requested technical
information, including the facility's cooling system type, source water body, and intake flow in addition to economic
and financial information. Cooling water characteristics of interest to the analysis are the facility's baseline cooling
system type (i.e., once-through or recirculating system) and its cooling water source (i.e., freshwater or marine
water). In addition, the facility's design intake flow was used in the costing analysis.
Development of model facilities
The final step in the baseline projection of new manufacturing facilities was the development of model facilities for
the costing and economic impact analyses. This step required translating characteristics of the existing in-scope
facilities into characteristics of the projected new facilities. Again, the characteristics of interest are: (1) the facility's
type of cooling system in the baseline (once-through or recirculating system) and (2) the type of water body from
which the intake structure withdraws (freshwater or marine water). EPA developed one model facility for each
cooling system/water body combination within each 4-digit SIC code. Based on the distribution of the in-scope
survey respondents by cooling system type and source water body, EPA assigned the projected new in-scope
facilities to model facility types.
EPA developed model manufacturing facilities using DQ data for 178 manufacturing facilities, regardless of their
year of construction. Because the DQ manufacturing facilities represent only a sampling of the total population of
manufacturing facilities, EPA used survey weights in developing flow estimates for these model facilities.
EPA first sorted the DQ manufacturing facilities according to their 4-digit SIC Codes, and then according to CWS
type (once-through vs. recirculating) and water body type (freshwater vs. marine) to yield one or more baseline
scenarios within each 4-digit SIC Code. Many of the DQ manufacturing facilities were found to use mixed once-
through and recirculating CWSs. For purposes of cost estimation, EPA treated these facilities the same as once-
through CWSs. This represented a conservative approach since, if anything, it would tend to overestimate the size
of the baseline CWS that would have to be replaced, and thus overestimate the corresponding compliance costs.
Eighteen survey facilities with estimated design flows less than the regulatory threshold of 2 million gallons per day
(MOD) were then eliminated from the flow analysis as being out of scope. The regulatory threshold represents the
intake flow rate at which intake systems would be required to comply with the regulation. Only those survey
facilities that were in scope (i.e., met the 2 MOD regulatory threshold) were included in the analysis to develop the
model facilities.
The baseline scenarios for manufacturing facilities are listed in Table 1-8 below.
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§ 316(b) TDD Chapter 1 for New Facilities
Baseline Projections of New Facilities
Table 1-8: Baseline Manufacturing Facility Scenarios
Industry
Category
SIC 2621
SIC 2812
SIC 2812
SIC 2812
SIC 2819
SIC 2819
SIC 2819
SIC 2821
SIC 2821
SIC 2821
SIC 2834
SIC 2834
SIC 2869
SIC 2869
SIC 2869
SIC 2873
SIC 2873
SIC 2911
SIC 2911
SIC 33 12
Industry Description
Paper and Allied Products - Paper Mills
Chemical and Allied Products - Alkalies and
Chlorines
Chemical and Allied Products - Alkalies and
Chlorines
Chemical and Allied Products - Alkalies and
Chlorines
Chemicals and Allied Products - Industrial
Inorganic Chemicals, Not Elsewhere Classified
(NEC)
Chemicals and Allied Products - Industrial
Inorganic Chemicals, NEC
Chemicals and Allied Products - Industrial
Inorganic Chemicals, NEC
Chemicals and Allied Products - Plastics
Materials and Synthetic Resins
Chemicals and Allied Products - Plastics
Materials and Synthetic Resins
Chemicals and Allied Products - Plastics
Materials and Synthetic Resins
Chemicals and Allied Products - Pharmaceuticals
Chemicals and Allied Products - Pharmaceuticals
Chemicals and Allied Products - Industrial
Organic Chemicals, NEC
Chemicals and Allied Products - Industrial
Organic Chemicals, NEC
Chemicals and Allied Products - Industrial
Organic Chemicals, NEC
Chemicals and Allied Products - Nitrogenous
Fertilizers
Chemicals and Allied Products - Nitrogenous
Fertilizers
Petroleum Refining
Petroleum Refining
Primary Metal Industries - Steel Works, Blast
Furnaces and Rolling
Baseline Cooling Water Body Type
Technology
Once Through
Once Through
Once Through
Reuse/Recycle
Once Through
Reuse/Recycle
Once Through
Once Through
Once Through
Reuse/Recycle
Once Through
Reuse/Recycle
Once Through
Once Through
Reuse/Recycle
Once Through
Reuse/Recycle
Reuse/Recycle
Once Through
Once Through
Freshwater
Marine
Freshwater
Freshwater
Freshwater
Freshwater
Marine
Marine
Freshwater
Freshwater
Freshwater
Freshwater
Marine
Freshwater
Freshwater
Freshwater
Freshwater
Freshwater
Freshwater
Freshwater
1-14
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§ 316(b) TDD Chapter 1 for New Facilities
Baseline Projections of New Facilities
Table 1-8: Baseline Manufacturing Facility Scenarios
Industry
Category
Industry Description
Baseline Cooling
Technology
Water Body Type
SIC 3312
SIC 3316
SIC 3316
SIC 3317
SIC 3317
SIC 3353
SIC 3353
Primary Metal Industries •
Furnaces and Rolling
Primary Metal Industries
Sheet, Strip and Bars
Primary Metal Industries
Sheet, Strip and Bars
Primary Metal Industries •
Primary Metal Industries •
Primary Metal Industries •
Plate and Foils
Steel Works, Blast
Cold-Rolled Steel
Cold-Rolled Steel
Steel Pipe and Tubes
Steel Pipe and Tubes
Aluminum Sheet,
Primary Metal Industries - Aluminum Sheet,
Plate and Foils
Reuse/Recycle
Once Through
Reuse/Recycle
Once Through
Reuse/Recycle
Once Through
Reuse/Recycle
Freshwater
Freshwater
Freshwater
Freshwater
Freshwater
Freshwater
Freshwater
Within each baseline scenario, EPA ranked the DQ facilities in ascending order based on their design intake flows.
Design intake flows were not available for two of the DQ manufacturing facilities. However, average intake flows
were available for these facilities. EPA estimated design intake flows for these facilities by multiplying their average
intake flows by the average ratio of design intake to average intake flow for the other facilities within their baseline
scenarios.
EPA then divided the DQ facilities within each baseline scenario into thirds. EPA then calculated weighted average
design intake flows for the middle third to yield design flow values for medium-sized (as reflected by design flow)
manufacturing facilities; the lower and upper thirds were excluding from the averaging to minimize the effects of
unusually small or unusually large facilities on the average. Table 1 -9 below presents the baseline intake and cooling
flow values used in estimating the compliance costs for the different model manufacturing facilities.
Table 1-9: Manufacturing Model Facility Baseline Intake and Cooling
Model Facility ID
MANOT/FW-2621
MANOT/M-2812
MANOT/FW-2812
MANR/FW-2812
MANOT/FW-2819
Baseline Cooling
Water System
i Once Through
i Once Through
i Once Through
i Reuse/Recycle
; Once Through
Waterbody Type
i Freshwater i
i Marine i
i Freshwater i
i Freshwater i
; Freshwater i
Baseline Intake
Flow
(MGD)
24
94
265
6
19
Flow Values
Baseline Cooling
Flow
(MGD)
! 24
! 94
! 265
! 60
i 19
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§ 316(b) TDD Chapter 1 for New Facilities
Baseline Projections of New Facilities
Table 1-9: Manufacturing Model Facility Baseline Intake and Cooling Flow Values
Model Facility ID
Baseline Cooling
Water System
Waterbody Type
Baseline Intake
Flow
(MGD)
Baseline Cooling
Flow
(MGD)
MANR/FW-2819
MANOT/M-2819
MANOT/FW-2821
MANR/FW-2821
MANOT/M-2821
MAN OT/FW-2834
MAN R/FW-2834
MAN OT/FW-2869
MAN OT/M-2869
MAN R/FW-2869
MAN OT/FW-2873
MAN R/FW-2873
MANR/FW-2911
MANOT/FW-2911
MANOT/FW-3312
MANR/FW-3312
MANOT/FW-3316
MANR/FW-3316
MANOT/FW-3317
MANR/FW-3317
MANOT/FW-3353
MANR/FW-3353
Reuse/Recycle
Once Through
Once Through
Reuse/Recycle
Once Through
Once Through
Reuse/Recycle
Once Through
Once Through
Reuse/Recycle
Once Through
Reuse/Recycle
Reuse/Recycle
Once Through
Once Through
Reuse/Recycle
Once Through
Reuse/Recycle
Once Through
Reuse/Recycle
Once Through
Reuse/Recycle
Freshwater
Marine
Freshwater
Freshwater
Marine
Freshwater
Freshwater
Freshwater
Marine
Freshwater
Freshwater
Freshwater
Freshwater
Freshwater
Freshwater
Freshwater
Freshwater
Freshwater
Freshwater
Freshwater
Freshwater
Freshwater
^
27
78
14
30
18
^
40
26
4
o o
J J
30
105
124
85
23
12
39
4
35
6
20
27
78
140
30
18
20
40
26
40
o o
J J
300
80
105
124
850
23
120
39
40
35
60
1-16
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§ 316(b) TDD Chapter 1 for New Facilities Baseline Projections of New Facilities
1.2.2 Projected Number of New Manufacturing Facilities
Paper and Allied Products (SIC 26)
This analysis assumes that two new in-scope paper mills (SIC code 2621) will begin operation during the next 20
years. The distribution of existing facilities across water body and cooling system types showed that 88 percent of
all existing in-scope paper mills operate a once-through system and withdraw from a freshwater body. EPA
therefore assumed that both projected new in-scope paper mills will be freshwater facilities with a once-through
system. Table 1-10 below presents the model facility type, the number of in-scope survey facilities upon which the
model facility type was based, and the number of projected new facilities that belong to that model type.
Model Facility
Type
MANOT/F-2621
SIC
Code
2621
Table 1-10:
I Cooling
i System Type
i Once-Through
SIC 26 Model Facilities
Source i
Water Body
Freshwater i
Number of In-Scope
Survey Respondents
47
; Number of New
i In-Scope Facilities
i 2
Source: EPA Analysis.
Chemicals Manufacturing (SIC 28)
EPA projected that 22 new in-scope chemical facilities will begin operation during the next 20 years. Based on the
distribution of the in-scope survey respondents across water body and cooling system types, EPA assigned the 22
new facilities to 11 different model facility types, by SIC code:
*• SIC code 2812: EPA proj ects that two new in-scope facilities will begin operation during the next 20 years.
The distribution of existing in-scope facilities across water body and cooling system types showed that 36
percent of the existing facilities operate a once-through system and withdraw from a freshwater body and
36 percent operate a once-through system and withdraw from a marine body. EPA therefore projected one
new once-through/freshwater facility and new once-through system/marine facility.
*• SIC code 2819: Four new industrial inorganic chemicals, not elsewhere classified are projected to begin
operation during the 20-year analysis period. The distribution of existing facilities across water body and
cooling system types showed that 47 percentof the existing in-scope facilities operate a once-through system
and withdraw from a freshwater body, 39 percent operate a once-through system and withdraw from a
marine water body, and 14 percent operate a recirculating system and withdraw from a freshwater body.
EPA therefore projected two new once-through/freshwater facilities and two new once-through/marine
facilities.
*• SIC code 2821: EPA proj ects that four new in-scope facilities will begin operation during the next 20 years.
The distribution of existing facilities across water body and cooling system types showed that all existing
in-scope plastics material and synthetic resins, and nonvulcanizable elastomer facilities operate a once-
through system and withdraw from a freshwater body. EPA therefore assumed that all four projected new
in-scope facilities will be freshwater facilities with a once-through system.
*• SIC code 2834: EPA projects that two new in-scope facilities will begin operation during the next 20 years.
The distribution of existing facilities across water body and cooling system types showed that all existing
in-scope pharmaceutical preparation facilities operate a once-through system and withdraw from a
1-17
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§ 316(b) TDD Chapter 1 for New Facilities
Baseline Projections of New Facilities
freshwater body. EPA therefore assumed that both projected new in-scope facilities will be freshwater
facilities with a once-through system.
> SIC code 2869: Eight new facilities in the Industrial Organic Chemical, Not Elsewhere Classified sector are
projected to begin operation during the 20-year analysis period. The distribution of existing facilities across
water body and cooling system types showed that 89 percent of the existing facilities operate a once-through
system and withdraw from a freshwater body and 11 percent operate a recirculating system and withdraw
from a freshwater body. Therefore EPA projected that seven new once-through/freshwater facilities and
one new recirculating/freshwater facility.
*• SIC code 2873: EPA projected that two new in-scope nitrogenous fertilizer facilities will begin operation
in the next 20 years. The distribution of existing facilities across water body and cooling system types
showed that 50 percent of the existing facilities operate a recirculating system and withdraw from a
freshwater body and 50 percent operate once-through systems and withdraw from a freshwater body. EPA
therefore projected one new recirculating/freshwater facility and one new once-through/freshwater facility.
Table 1-11 below presents the model facility type, the number of in-scope survey facilities upon which the model
facility type was based, and the number of projected new facilities that belong to that model type.
Model Facility Type
MANOT/M-2812
MANRE/F-2812
MANOT/M-2819
MANOT/F-2819
MANOT/F-2821
MAN OT/F-2834
MAN OT/F-2869
MAN RE/F-2869
MAN OT/F-2873
MAN RE/F-2873
Total
SIC
2812
2812
2819
2819
2821
2834
2869
2869
2873
2873
Table 1-11: SIC
: Cooling System ;
Type
i Once-Through j
i Once-Through i
i Once-Through i
i Once-Through i
i Once-Through i
i Once-Through i
i Once-Through i
i Recirculating i
i Once-Through i
i Recirculating i
28 Model Facilities
Source Water
Body
Marine
Freshwater
Marine
Freshwater
Freshwater
Freshwater
Freshwater
Freshwater
Freshwater
Freshwater
Number of ;
Existing In- ;
Scope Facilities i
6 i
6 i
13 i
16 i
10 !
4 i
35 !
4 !
4 !
4 !
102 i
Number of
Projected New
Facilities
1
1
2
2
4
2
7
1
1
1
22
Source: EPA Analysis.
1-18
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§ 316(b) TDD Chapter 1 for New Facilities Baseline Projections of New Facilities
Petroleum and Coal Products (SIC 29)
EPA projected that two new in-scope petroleum refineries (SIC code 2911) will begin operation during the next 20
years. The distribution of existing facilities across water body and cooling system types showed that 52 percent of
the existing petroleum refineries operate a recirculating system and withdraw from a freshwater body and 30 percent
operate once-through systems and withdraw from a freshwater body. EPA therefore assumed that the two new
projected facilities would have those characteristics. Table 1-12 below presents the model facility type, the number
of in-scope survey facilities upon which the model facility type was based, and the number of proj ected new facilities
that belong to that model type.
Table 1-12: SIC 29 Model Facilities
Model Facility Type
MANOT/F-2911
MANRE/F-2911
Total
SIC
Code
2911
2911
Cooling System ;
Type
Once Through j
Recirculating j
Source Water
Body
Freshwater
Freshwater
Number of ;
Existing In- j
Scope Facilities j
9 i
15 i
24 i
Number of
Projected New
Facilities
1
1
2
Source: EPA Analysis.
Steel (SIC 331)
EPA projected that 10 new in-scope steel facilities will begin operation during the next 20 years. Based on the
distribution of the in-scope survey respondents across water body and cooling system types, EPA assigned the 10
new facilities to six different model facility types, by SIC code:
> SIC code 3312: Six steel mills are projected to begin operation during the 20-year analysis period. The
distribution of existing facilities across water body and cooling system types showed that 91 percent of the
existing facilities operate a once-through system and withdraw from a freshwater body and nine percent
operate a recirculating system and withdraw from a freshwater body. Therefore EPA projected that five new
once-through/freshwater facilities and one recirculating/freshwater facility.
> SIC code 3316: EPA projected that two new in-scope cold-rolled steel sheet, strip, and bar facilities will
begin operation in the next 20 years. The distribution of existing facilities across water body and cooling
system types showed that 67 percent of the existing facilities operate a once-through system and withdraw
from a freshwater body and 33 percent operate a recirculating system and withdraw from a freshwater body.
EPA therefore projected one once-through/freshwater and one recirculating/freshwater facility.
> SIC code 3317: EPA projected that two new in-scope steel pipe and tube facilities will begin operation in
the next 20 years. The distribution of existing facilities across water body and cooling system types showed
that 50 percent of the existing facilities operate a recirculating system and withdraw from a freshwater body
and 50 percent operate once-through systems and withdraw from a freshwater body. EPA therefore
assumed that the two new projected facilities would have those characteristics.
Table 1-13 below presents the model facility type, the number of in-scope survey facilities upon which the model
facility type was based, and the number of projected new facilities that belong to that model type.
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§ 316(b) TDD Chapter 1 for New Facilities
Baseline Projections of New Facilities
Table 1-13: SIC 331 Model Facilities
Model Facility Type
MANOT/F-3312
MANRE/F-3312
MANOT/F-3316
MANRE/F-3316
MANOT/F-3317
MANRE/F-3317
Total
SIC
Code
3312
3312
3316
3316
O O 1 T
3317
O O 1 T
3317
Cooling System ;
Type
Once-Through j
Recirculating j
Once-Through j
Recirculating j
Once-Through j
Recirculating j
Source Water
Body
Freshwater
Freshwater
Freshwater
Freshwater
Freshwater
Freshwater
Number of ;
Existing In- j
Scope Facilities j
32 !
o •
J \
6 i
o •
J \
o •
J \
o •
J \
50 i
Number of
Projected New
Facilities
5
1
1
1
1
1
10
Source: EPA Analysis.
Aluminum (SIC 333/335)
EPA projected that two new in-scope aluminum facilities will begin operation in the next 20 years. The distribution of
existing facilities across water body and cooling system types showed that 50 percent of the existing aluminum facilities
operate a recirculating system and withdraw from a freshwater body and 50 percent operate once-through systems and
withdraw from a freshwater body. EPA therefore assumed that the two new projected facilities would have those
characteristics. Table 1-14 below presents the model facility type, the number of in-scope survey facilities upon which
the model facility type was based, and the number of projected new facilities that belong to that model type.
Model Facility Type
MAN OT/F-3353
MANRE/F-3353
Total
SIC
Code
3353
3353
Table 1-14: SIC
Cooling System ;
Type
Once-Through i
Recirculating i
3353 Model Facilities
Source Water
Body
Freshwater
Freshwater
Number of ;
Existing In- i
Scope Facilities j
o •
J \
o •
J \
6 \
Number of
Projected New
Facilities
1
1
2
Source: EPA Analysis.
1-20
-------
§ 316(b) TDD Chapter 1 for New Facilities
Baseline Projections of New Facilities
1.2.3 Summary of Forecasts for New Manufacturing Facilities
EPA estimates that atotal of 380 new manufacturing facilities will begin operation between 2001 and 2020. Thirty-
eight of these are expected to be in scope of the final § 316(b) New Facility Rule. Of the 38 facilities, 22 are chemical
facilities, ten are steel facilities, two are petroleum refineries, two are paper mills, and two are aluminum facilities.
Table 1-15 summarizes the results of the analysis.
Table 1-15: Number of Projected New Manufacturers (2001 to 2020)
Facility Type |
Paper and Allied Products i
(SIC 26) i
Chemicals and Allied Products i
(SIC 28) i
Petroleum Refining And i
Related Industries (SIC 29) |
Blast Furnaces and Basic Steel i
Products (SIC 331) |
Aluminum Sheet, Plate, and i
Foil (SIC 3353) !
| Total !
Total Number
of New
Facilities
2
282
2
78
16
380
i Facilities In Scope of the Final Rule
i Recirculating
i Freshwater i Marine
i 0 i 0
i 2 i 0
i i i o
i 3 i 0
i i i o
i 7 i 0
i Once- Through i
i Freshwater i Marine i
i 2 i 0 i
i 17 i 3 i
1 1 1 0 1
1 7 i 0 i
1 1 1 0 1
i 28 i 3 i
Total
2
22
2
10
2
38 |
Source: EPA Analysis, 2001.
1.3 SUMMARY OF BASELINE PROJECTIONS
EPA estimates that over the next 20 years a total of 656 new greenfield and stand alone facilities will be built in the
industry sectors analyzed for this final regulation. Two hundred and seventy-six of these new facilities will be steam
electric generating facilities and 380 will be manufacturing facilities. As Table 1-16 shows, only 121 of the 656 new
facilities are projected to be in scope of the final § 316(b) New Facility Rule, including 83 electric generators, 22
chemical facilities, 12 primary metals facilities, two new pulp and paper, and two petroleum facilities. For more
detailed information, see Economic Analysis of the Final Regulations Addressing Cooling Water Intake Structures
for New Facilities.
1-21
-------
§ 316(b) TDD Chapter 1 for New Facilities
Baseline Projections of New Facilities
Table 1
SIC
-16: Projected Number of New In Scope
i SIC Description
Facilities (2001
to 2020)
Projected Number of New Facilities
Total
i In-Scope
Electric Generators
SIC 49
i Electric Generators
276
i 83
Manufacturing Facilities
SIC 26
SIC 28
SIC 29
SIC 33
SIC 331
SIC 333
SIC 335
Total Manufacturing
Total
i Paper and Allied Products
i Chemicals and Allied Products
i Petroleum Refining And Related Industries
i Primary Metals Industries
i Blast Furnaces and Basic Steel Products
i Primary Aluminum, Aluminum Rolling, and
i Drawing and Other Nonferrous Metals
2
282
2
78
16
380
656
i 2
! 22
i 2
i 10
i 2
\ 38
\ 121
Source: EPA Analysis, 2001.
1-22
-------
§ 316(b) TDD Chapter 1 for New Facilities Baseline Projections of New Facilities
REFERENCES
Dun and Bradstreet (D&B). 1999. Data as of April 1999.
Edison Electric Institute (EEI). 1994. Power Statistics Database. Utility Data Institute, McGraw Hill.
Joskow, Paul L. 1997. "Restructuring, Competition and Regulatory Reform in the U.S. Electricity Sector," Journal of
Economic Perspectives, Volume 11, Number 3 - Summer 1997 - Pages 119-138.
U.S. Department of Energy (DOE). 2000a. Energy Information Administration (EIA). Electric Power Indus try Overview.
@ httrj://www.eia.doe.gov/cneaf/electricitv/page/prim2.html.
U.S. Department of Energy (DOE). 2000b. Energy Information Administration (EIA). Status of State Electric Industry
Restructuring Activity as of September 2000. @ http://www.eia.doe.gov/cneaf/electricitv/chg str/regmap.html.
U.S. Department of Energy (DOE). 1999a. Energy Information Administration (EIA). "Market Trends." Annual Energy
Outlook 2000. Report#DOE/EIA-0383(2000). December 19.
U.S. Department of Energy (DOE). 1999b. Energy Information Administration (EIA). Electric Power Annual 1998 Volume
I.
Report#DOE/EIA-0348(98)/l.
U.S. Department of Energy (DOE). 1999c. Energy Information Administration (EIA). Electric Power Annual 1998 Volume
II. Report#DOE/EIA-0348(98)/2.
U.S. Department of Energy (DOE). 1998. Energy Information Administration (EIA). Form EIA-860A and Form EIA-860B
Annual Electric Generator Reports, Form EIA-861 Annual Electric Utility Report, @
http://www.eia.doe.gov/cneaf/electricitv/page/data.html.
U.S. Department of Energy (DOE). 1997. Energy Information Administration (EIA). Form EIA-767 Steam-Electric Plant
Operation and Design Report, @ http://www.eia.doe.gov/cneaf/electricitv/page/data.html.
U.S. Department of Energy (DOE). 1996a. Energy Information Administration (EIA) Electric Power Annual 1995 Volume
I.
U.S. Department of Energy (DOE). 1996b. Energy Information Administration (EIA). ElectricPowerAnnual 1995Volume
II.
U.S. Department of Energy (DOE). 1996. Energy Information Administration (EIA). Impacts of Electric Power Industry
Restructuring on the Coal Industry, (a), http://www.eia.doe.gov/cneaf/electricitv/chg str fuel/html/chapterl.html.
U.S. Environmental Protection Agency (EPA). 1999. Industry Screener Questionnaire: Phase I Cooling Water Intake
Structures.
U.S. Geological Survey (USGS). 1995. Estimated Use of Water in the United States in 1995. @
http://water.usgs.gov/watuse/pdfl995/html.
U.S. Environmental Protection Agency. 2001. Economic Analysis of the Final Regulations Addressing Cooling Water
Intake Structures for New Facilities
1-23
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§ 316(b) TDD Chapter 1 for New Facilities Baseline Projections of New Facilities
This Page Intentionally Left Blank
1-24
-------
§ 316(b) TDD Chapter 2 for New Facilities
Costing Methodology
Chapter 2: Costing Methodology
INTRODUCTION
This chapter presents the methodology used to estimate the
costs to facilities of complying with the final §316(b) New
Facility Rule. This chapter presents detailed information
on the development of unit cost estimates for a set of
technologies that may be used to meet requirements. This
chapter describes how the technology unit costs were used
to develop facility-level cost estimates for each projected
in-scope facility.
2.1 BACKSROUND
Facilities using cooling water may be subject to the final
§316(b) New Facility Rule. A facility using cooling water
can have either a once-through or a recirculating cooling
system.
In a once-through system, the cooling water that is drawn
in from a waterbody travels through the cooling system
once to provide cooling and is then discharged, typically
back to the waterbody from which it was withdrawn. The
cooling water is withdrawn from a water source, typically
a surface waterbody, through a cooling water intake
structure (CWIS). Many facilities using cooling water
(e.g., steam electric power generation facilities, chemical
and allied products manufacturers, pulp and paper plants)
need large volumes of cooling water, so the water is
generally drawn in through one or more large CWIS,
potentially at high velocities. Because of this, debris, tree
limbs, and many fish and other aquatic organisms can be
drawn toward or into the CWIS. Since a facility' s cooling
water system can be damaged or clogged by large debris,
most facilities have protective devices such as trash racks,
fixed screens, or traveling screens, on their CWIS. Some
of these devices provide limited protection to fish and
other aquatic organisms, but other measures such as the use
of passive (e.g., wedgewire) screens, velocity caps,
traveling screens with fish baskets, or the use of a
recirculating cooling system may provide better protection
Chapter Contents
2.1 Background 2-1
2.2 Overview of Costing Methodology 2-2
2.3 Facility Level Costs 2-4
2.3.1 General Approach 2-4
2.3.2 Capital Costs 2-5
2.3.3 Operation & Maintenance Costs 2-5
2.3.4 Development of Model Facilities 2-6
2.3.5 Wet Tower Intake Flow Factors 2-6
2.3.6 Baseline Cost Components 2-8
2.3.7 Baseline Once-Through Cooling 2-8
2.3.8 Baseline Recirculating Wet Towers 2-8
2.4 Compliance Cost Components 2-8
2.4.1 Recirculating Wet Towers 2-8
2.4.2 Reuse / Recycle 2-9
2.5 Cost Estimation Assumptions and Methodology .... 2-9
2.5.1 Once-Through Capital Costs 2-9
2.5.2 Once-Through O&M 2-12
2.5.3 Recirculating Wet Tower Capital Costs .... 2-12
2.5.2 Wet Tower O&M Costs 2-12
2.6 Alternative Regulatory Options 2-12
2.6.1 Opt 1: Technology-Based Performance
Requirements for Different Waterbodies ... 2-13
2.6.2 Opt 2a: Flow Reduction Commensurate with
Closed-Cycle Recirculating Wet Cooling .. 2-13
2.6.3 Opt 2b: Flow Reduction Commensurate with
Dry Cooling Systems 2-14
2.6.4 Opt 3: Industry Two-Track Option 2-15
2.7 Summary of Costs by Regulatory Option 2-15
2.7.1 Final Rule 2-15
2.7.2 Option 1 2-17
2.7.3 Option 2a 2-18
2.7.4 Option 2b 2-19
2.7.5 Option 3 2-20
2.8 Technology Unit Costs 2-21
2.8.1 General Cost Information 2-21
2.8.2 Flow 2-23
2.8.3 Additional Cost Considerations 2-24
2.8.4 Replacement Costs 2-26
2.9 Specific Cost Information for Technologies and
Actions 2-26
2.9.1 Reducing Design Intake Flow 2-26
2.9.2 Reducing Design Intake Velocity 2-39
2.9.3 Design and Construction Technologies to Reduce
Damage from Impingement and Entrainment 2-45
2.10 Additional Cost Information 2-56
References 2-57
Charts 2-1 through 2-30 2-60
2-1
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§ 316(b) TDD Chapter 2 for New Facilities Costing Methodology
and have greater capability to minimize adverse environmental impacts.1
In a recirculating system, the cooling water is used to cool equipment and steam, absorbing heat in the process, and is then cooled
and recirculated to the beginning of the system to be used again for cooling. The heated cooling water is generally cooled in either
a cooling tower or in a cooling pond. In the process of being cooled, some of the water evaporates or escapes as steam. Flow
lost through evaporation typically ranges from 0.5 percent to 1 percent of the total flow (Antaya, 1999). Also, because of the
heating and cooling of recirculating water, mineral deposition occurs which necessitates some bleeding of water from the system.
The water that is purged from the system to maintain chemical balance is called blowdown. The amount of blowdown is generally
around 1 percent of the flow. Cooling towers may also have a small amount of drift, or windage loss, which occurs when some
recirculating water is blown out of the tower by the wind or the velocity of the air flowing through the tower. The water lost to
evaporation, blowdown, and drift needs to be replaced by what is typically called makeup water. Overall, makeup water is
generally 3 percent or less of the recirculating water flow.2 Therefore, recirculating systems still need to draw in water and may
have cooling water intakes. However, the volume of water drawn in is significantly less than in once-through systems, so the
likelihood of adverse environmental impacts as a result of the CWIS is much lower.3 Also, some recirculating systems obtain their
makeup water from ground water sources or public water supplies, and a small but growing number use treated wastewater from
municipal wastewater treatment plants for makeup water.
The final §316(b) New Facility Rule establishes a two-track approach for regulating cooling water intake structures at new
facilities.4 Facilities have the opportunity to choose which track (Track I or Track II) they will follow. Facilities choosing to
comply with Track I requirements would be required to meet flow reduction, velocity, and design and construction technology
requirements. These requirements include reducing cooling water intake flow to a level commensurate with that achievable with
a closed-cycle, recirculating cooling system; achieving a through-screen intake velocity of 0.5 feet per second; meeting location-
and capacity-based limits on proportional intake flow; and implementing design and construction technologies for minimizing
impingement and entrainment and maximizing impingement survival. Facilities choosing to comply with Track II requirements
would be required to perform a comprehensive demonstration study to demonstrate that proposed technologies reduce the level
of impingement and entrainment to the same level that would be achieved by implementing the requirements of Track I.
2.2 OVERVIEW OF COSTING METHOooioey
Based on information provided by vendors and industry representatives, EPA first developed unit costs and cost curves, including
both capital costs and operations and maintenance (O&M) costs, for a number of primary technologies such as traveling screens
and cooling towers that facilities may use to meet requirements under the final §316(b) New Facility Rule. Unit costs are
estimated costs of certain activities or actions, expressed on a uniform basis (i.e., using the same units), that a facility may take
to meet the regulatory requirements. Unit costs are developed to facilitate comparison of the costs of different actions. For this
analysis, the unit basis is dollars per gallon per minute ($/gpm) of flow. For most technologies, EPA used the cooling water intake
flow as the basis for unit costs; for cooling towers, EPA used the cooling water recirculating flow through the tower as the basis
for unit costs. EPA estimated all capital and operating and maintenance (O&M) costs in these units. These unit costs and cost
curves are the building blocks for developing costs at the facility and national levels.
'CWIS devices used in an effort to protect fish also include other fish diversion and avoidance systems (e.g., barrier nets,
strobe lights, electric curtains), which may be effective in certain conditions and for certain species. See Chapter 5 of this
document.
2In some saltwater cooling towers, however, makeup water can be as much as 15 percent.
Manufacturer Bracket! Green notes that closed loop systems (i.e., recirculating systems) normally require one-sixth the
number of traveling screens as a power plant of equal size that has a once-through cooling system.
4See Economic Analysis of the Final Regulations Addressing Cooling Water Intake Structures for New Facilities
(hereinafter referred to as the Economic Analysis), Chapter 1: Introduction and Overview for a summary of this rule's
requirements.
2-2
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§ 316(b) TDD Chapter 2 for New Facilities Costing Methodology
While EPA developed unit costs for a number of available technologies, EPA used only a limited set of these technologies to
develop facility-level capital and O&M cost estimates. For purposes of cost estimation, EPA assumed that facilities would meet
the flow reduction requirement by installing cooling towers. EPA assumed that facilities would meet the velocity and design and
construction technology requirements by installing traveling screens with fish handling features, with an intake velocity of 0.5 ft/s.
EPA used unit cost curves to develop facility-level capital and O&M cost estimates for 41 model facilities. These model facilities
were then scaled to represent total industry compliance costs for the 121 facilities projected to begin operation between 2001 and
2020. Individual facilities will incur only a subset of the unit costs, depending on the extent to which they would have already
complied with the requirements as originally designed (in the baseline) and on the compliance response they select. To account
for this, EPA established a number of baseline scenarios (reflecting different baseline cooling water system types and waterbody
types) so that the unit costs could be applied to the various model facilities to obtain facility-level costs.
The cost estimates developed for various technologies are intended to represent a National "typical average" cost estimate. The
cost estimates should not be used as a project pricing tool as they cannot account for all the site-specific conditions for a particular
project.
The facility-level capital and O&M costs presented in this chapter represent the net increase in costs for each set of compliance
technology performance requirements as compared to the technology the facility would have installed absent this regulation. To
calculate net costs for each model facility, EPA first calculated the cost for the entire cooling system for the baseline technology
combination, and then subtracted those costs from the calculated cost of the entire cooling systemfor each compliance technology
combination.
Development of the facility-level capital and O&M costs for the final §316(b) New Facility Rule is discussed in detail in Section
2.3 below. In addition to the facility-level cost estimates developed for the preferred two-track option adopted for the final rule,
EPA also developed facility-level cost estimates for several additional options that EPA considered but did not adopt for the final
rule. Development of the facility-level capital and O&M cost estimates for these options are also discussed in Section 2.3.
In addition, EPA applied an energy penalty cost to those electric generators switching to recirculating systems to account for
performance penalties that may result in reductions of energy or capacity produced because of adoption of recirculating cooling
tower systems. These performance penalties are associated with reduced turbine efficiencies due to higher back pressures
associated with cooling towers, as well as with power requirements to operate cooling tower pumps and fans. EPA's costing
methodology for performance penalties is based on the concept of lost operating revenue due to a mean annual performance
penalty. EPA estimated the mean annual performance penalty for recirculating cooling tower systems as compared to once-
through cooling systems. EPA then applied this mean annual penalty to the annual revenue estimates for each facility projected
to install a recirculating cooling tower technology as a result of the rule. It should be noted that EPA took a conservative approach
and double-counted some parts of the energy penalty, since fan and pump power costs were included in both the energy penalty
and the cooling tower O&M costs. Energy penalties are discussed in detail in Chapter 3 of this document and their costs are
presented in the Economic Analysis.
Compliance with the final section §316(b) New Facility Rule also requires facilities to carry out certain administrative functions.
These are either one-time requirements (compilation of information for the initial NPDES permit) or recurring requirements
(compilation of information for NPDES permit renewal, and monitoring and record keeping), and depend on the facility' s water
body type and the permitting track the facility follows. Development of these administrative costs is discussed in the Information
Collection Request for Cooling Water Intake Structures, New Facility Final Rule (referred to as the ICR) and in the Economic
Analysis.
All costs presented in this chapter are expressed in 1999 dollars. For the Economic Analysis for the final §316(b) New Facility
Rule, EPA escalated these costs to 2000 dollars.
2-3
-------
§ 316(b) TDD Chapter 2 for New Facilities Costing Methodology
2.3 FACILITY LEVEL COSTS
2.3.1 Genera\ Approach
The facility-level cost estimates presented in this section are based on a limited set of the unit costs presented in detail in the
following sections of this Chapter. For purposes of cost estimation, EPA assumed that facilities would meet the flow reduction
requirement by switching to recirculating systems. EPA assumed that all planned facilities switching to recirculating systems
would use cooling towers (the most common type of recirculating system). This is consistent with the requirement of the final
section 316(b) New Facility Rule to reduce intake flow to a level commensurate with that which could be obtained by use of a
closed-cycle recirculating system. EPA assumed that facilities would meet the velocity and design and construction technology
requirements by installing traveling screens with fish handling features, with an intake velocity of 0.5 ft/s. This is a conservative
assumption because such technologies are among the more expensive technologies available for reducing velocity and I&E.
EPA used 41 model facilities to develop facility-level capital and O&M cost estimates for the 121 facilities projected to begin
operation between 2001 and 2020. The development of model facilities is described in Chapter 1. Individual facilities subject
to the regulation will incur differing costs depending on site specific conditions, technologies projected to be installed in the
baseline (i.e., regardless of this regulation), and on the compliance response they select. To account for this, EPA established a
number of baseline scenarios (reflecting different baseline cooling water system types and waterbody types) so that the unit costs
could be applied to the various model facilities to obtain facility-level costs.
In this analysis, the baseline technology represents an estimation of the technologies that would be constructed at new facilities
prior to implementation of the final New Facility Rule regulatory requirements. Specifically, the costs presented in the cost tables
represent the net increase in costs for each set of compliance technology/monitoring requirements as compared to the baseline
technology. EPA accomplished this by calculating the cost for the entire cooling system for the baseline technology combination
and then subtracting those costs fromthe calculated cost of the entire cooling systemfor each compliance technology combination.
The final New Facility Rule allows for facilities to comply with one of two alternative sets of permitting requirements (Track 1
and Track 2). Facilities choosing to comply with Track 1 permitting requirements would be required to meet flow reduction,
velocity, and design and construction technology requirements. Facilities choosing to comply with Track 2 permitting
requirements would be required to perform a comprehensive demonstration study to confirm that proposed technologies reduce
the level of impingement and entrainment mortality to the same level that would be achieved by implementing the flow reduction,
velocity, and design and construction technology requirements of Track I.
EPA assumed that facilities that were projected to have recirculating baseline cooling water systems would follow Track I. EPA
developed cost estimates for these facilities based on the assumption that they would already be installing cooling towers, and thus
would only have to install velocity reducing design and construction technologies of traveling screens with fish handling features.
EPA assumed that facilities that were projected to have once-through baseline cooling water systems would follow Track II. EPA
developed cost estimates for these facilities based on the assumption that they would perform comprehensive demonstration
studies, but would still have to install cooling towers and design and construction technologies of traveling screens with fish return
systems to meet the regulatory requirements. This is a conservative assumption that may overestimate compliance costs if a
significant number of Track II facilities are able to demonstrate that lower cost alternative technologies will reduce the level of
impingement and entrainment to the same level that would be achieved by implementing the flow reduction, velocity, and design
and construction technology requirements of Track I.
Some facilities were projected to have mixed once-through and recirculating baseline cooling water systems. EPA treated these
facilities the same as facilities with baseline once-through cooling water systems. This represents a conservative approach since
it will tend to overestimate the size of the baseline cooling water system that would have to be replaced, and thus overestimate
-------
§ 316(b) TDD Chapter 2 for New Facilities Costing Methodology
the corresponding compliance cost. In addition, one coal facility was projected to have a recirculating system with a cooling pond.
This facility was also costed to switch to a cooling tower.5
2.3.2 Capital Costs
Capital cost estimates used in calculating the net compliance costs include individual estimates for the following initial one-time
cost components where applicable:
Once-through system including intake structure, pumps, and piping costs.
Recirculating wet towers.
Intake for wet tower make-up water including intake pumps and piping.
Intake screens.
EPA summed these individual cost elements together to derive the total capital costs for each baseline and compliance scenario.
EPA then subtracted the total baseline cost from the total compliance cost to determine the incremental cost of compliance with
the final §316(b) New Facility Rule.
EPA concluded that the cooling water flow through the condenser at a given facility to be the same when switching from once-
through to wet towers because the design specifications of surface condensers for both types of systems are similar enough that
the condenser costs would also be similar. Thus, when comparing wet cooling systems, differences in costs from baseline for the
surface condensers were assumed to be zero.
2.3.3 Operation & Maintenance Costs
O&M cost estimates used in calculating the net compliance costs include individual estimates for the following cost components
where applicable:
Operating costs for pumping intake water.
O&M costs for operating recirculating wet towers.
O&M cost for operating intake screen technology.
Annual post-compliance operational monitoring.
EPA summed these individual cost elements together to derive the total O&M costs for each baseline and compliance scenario.
EPA then subtracted the total baseline cost from the total compliance cost to determine the incremental cost of compliance with
the final §316(b) New Facility Rule.
It should be noted that EPA overcosted the costs of post-compliance operational monitoring, since these costs were also included
in the annual administrative costs as described in the ICR and the Economic Analysis.
5In some states, a cooling pond is considered a water of the U.S. In these states, a plant with such a cooling system would
have to comply with the recirculating requirements of the final section 316(b) New Facility Rule. In those states where a
cooling pond is not considered a water of the U.S., a plant would not have to comply with the recirculating requirements of
this final New Facility Rule. This costing analysis made the conservative assumption that facilities with a cooling pond would
have to comply with the recirculating requirements. These facilities were therefore costed as if they had a once-through
system in the baseline.
2-5
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§ 316(b) TDD Chapter 2 for New Facilities Costing Methodology
2.3.4 Development of Model Facilities
EPA developed cost estimates for 41 model facilities within three industry categories: coal-fired power plants, combined cycle
power plants and manufacturers. These model facilities were developed to reflect a range of potential design intake flows and
(for power plants) megawatt (MW) capacities. The methodology for developing model facilities for each of these three industry
groups is described in Chapter 1.
2.3.5 Wet Tower Intake Flow Factors
EPA based all model facility flow values, including both intake and cooling water, upon projected intake flows for the baseline
technology. When switching from baseline once-through to recirculating wet tower cooling systems, EPA assumed that the
recirculating cooling flows through the wet towers would be equivalent to the baseline once-through flows. When either the intake
flow or the cooling flow had been projected for wet towers, EPA then calculated the corresponding cooling flow or intake flow
using a wet tower make-up water intake flow factor.
EPA used different make-up flow factors for power plants versus manufacturers, as well as for facilities using marine versus
freshwater source waters. Since seawater and brackish water in marine cooling water sources have higher dissolved solids (TDS)
content than freshwater, the blowdown rate should be higher to avoid the build-up of high TDS in the recirculating water as the
cooling water evaporates in the tower. The build-up of high TDS can affect the performance of the cooling system, increase
corrosion, and create potential water quality problems for the blowdown discharge. Therefore, the portion of the cooling water
that must be removed (blowdown) and replaced is greater for higher TDS source waters. Note that seawater represents the worst-
case scenario, but in most cases the intakes within the group of facilities attributed to this water body type will be withdrawing
brackish water (i.e., the TDS content will be somewhere between that of seawater and freshwater).
The make-up water must replace all cooling water losses, which include blowdown, evaporation, drift, and other uses. One
measure of the blowdown requirement is the "concentration factor," which is the ratio of the concentration of a conservative
pollutant, such as TDS, in the blowdown divided by the concentration in the make-up water. For freshwater, the concentration
factor can range from 2.0 to 10 (Kaplan 2000) depending on site-specific conditions. For marine sources including brackish and
saltwater, the concentration factor can range from 1.5 to 2.0 (Burns and Micheletti 2000).
Cooling Tower Fundamentals (Hensley, 1985) provides a set of equations and default values for estimating the rate of
evaporation, drift, and blowdown using the temperature rise (20 °F) and concentration factor. The make-up volume is the sum
of these three components. Input values in this calculation include the concentration factor and the temperature rise. The
temperature rise used (20 °F) is consistent with the design values used throughout the wet tower cost estimation efforts. Since
the estimate was for national average values, the default values for estimating evaporation and drift presented in the reference were
used. Table 2-1 provides the calculated make-up and blowdown rates as a percentage of the recirculating flow for different
concentration factors ranging from 1.1 to 10.0, for a wet tower with a recirculating rate of 100,000 gpm. Note that the selection
of the recirculating flow rate is not important, since the output values are percentages which would be the same regardless of the
flow rate chosen.
2-6
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§ 316(b) TDD Chapter 2 for New Facilities
Costing Methodology
Table 2-1: Make-Up and Slowdown Volumes for Different Wet Tower Concentration
Make-Up
(gpm)
Blowdown
(gpm)
Based on methodology presented in Cooling Tower Fundamentals (Henslej
"Evaporation = 0.0008 x Range (°F) x Recirculating Flow (gpm)
bDrift = 0.0002 x Recirculating flow (gpm)
Range = 20 °F
Recirculatin
Concentration
Factor
Evaporation
(gpm)
To be conservative, EPA selected the lower concentration factor for each of the two ranges of literature values (2.0 for freshwater
and 1.5 for marine water). Note that a lower concentration factor results in a higher make-up rate. EPA used the equations
presented in Hensley 1985 to derive the make-up water rates that correspond to the selected concentration factors of 1.5 and 2.0.
This method generated make-up rates of 3.2 percent and 4.8 percent for freshwater and marine water, respectively. These factors
were then compared to intake flow and generating capacity values of existing facilities. The resulting estimated cooling water
flow rates were somewhat high for the plant generating capacity. To correct for this observation and to account for site variations
and other cooling water uses, EPA increased the calculated make-up factors by approximately 50 percent and rounded off,
resulting in factors of 5 percent and 8 percent for freshwater and marine water, respectively. These values produced estimated
cooling flow values that were consistent with data from power plants with similar generating capacities.
Manufacturers use cooling water for numerous processes, some of which may not be amenable to use of recirculating wet towers
or to reuse/recycle. While wet towers are being used as a model for estimating cooling system water reduction technology costs
for manufacturers, the aggregate make-up water rates may be greater due to these limitations. In order to account for these
potential limitations, EPA set the make-up rates for manufacturers equal to twice the rate for power plants using similar water
source types. Thus, the makeup water rates for manufacturers were estimated at 10 percent and 16 percent for freshwater and
marine water, respectively.
2-7
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§ 316(b) TDD Chapter 2 for New Facilities Costing Methodology
2.3.6 Baseline Cost Components
EPA selected the baseline technologies based upon the projected type of baseline cooling system and the type of facility. The
type of water body affects the costs, but not the selection of technologies. The basic components and assumptions for each
baseline technology are described below:
2.3.7 Baseline Once-through Cooling
The intake is located near shoreline and water is pumped using constant speed pumps through steel pipes to and from a
surface condenser and is then discharged back to the water body. The once-through cost estimate includes the intake
structure, pumps and piping costs. The development of these costs is described in greater detail below.
For all types of power plants, baseline intakes are equipped with traveling screens (without fish handling systems) with an
intake velocity of 1.0 fps. For manufacturing facilities, intakes are equipped only with trash racks which were assumed to
be included in the cost of the intake system. Cost curve charts at the end of this chapter were used to generate the intake
screen cost estimates.
2.3.8 Baseline Recirculating Wet Towers
The cost estimates are for recirculating wet towers with redwood construction and splash fill. This is not the most common
construction material for cooling towers, it represents a median cost for cooling tower construction. The wet tower approach
was 10 °F with a temperature rise of 20 °F. Cost curve Charts presented at the end of the chapter were used to generate the
wet tower capital cost estimates.
O&M costs are based on Scenario 1 described in Section 2.2.2.1, in which make-up water is withdrawn from the surface
waterbody and blowdown is treated and discharged. Cost curve charts at the end of this chapter was used to generate the wet
tower O&M cost estimates.
EPA assumed that the make-up water volume would be a proportion of the recirculating flow. A separate cost estimate for
an appropriately sized cooling water intake with constant speed pumps was added to serve this purpose. EPA developed
intake costs in the same manner as for once-though intakes and included costs for an appropriately sized surface condenser.
For all types of power plants, baseline intakes are equipped with traveling screens (without fish handling systems) with an
intake velocity of 1.0 fps. For manufacturing facilities, intakes are equipped only with trash racks which were assumed to
be included in the cost of the intake system. Cost curve charts at the end of this chapter were used to generate the intake
screen cost estimates.
2.4 COMPLIANCE COST COMPONENTS
2.4.1 Recirculating Wet Towers
EPA developed costs for recirculating wet towers as the compliance technology using the same assumptions as for baseline
recirculating wet tower costs as described above, with the exception of the intake screen technology and the use of variable
speed pumps at the intake. All compliance costs included the cost of traveling screens with fish baskets and fish returns with
an intake velocity of 0.5 fps at the intake structure. EPA derived costs for traveling screens with fish baskets and fish returns
from cost curve data found at the end of this chapter.
As described above, the make-up water (intake flow) factors used for power plants were 5 percent for freshwater and 8
percent for marine water.
2-8
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§ 316(b) TDD Chapter 2 for New Facilities Costing Methodology
2.4.2 Reuse/recycle
Water reuse/recycle technologies at manufacturing facilities are expected to produce reductions in intake water use of a
similar degree as recirculating wet towers. However, due to the integrated nature and variable uses of cooling water at
manufacturing facilities, EPA did not consider the development of a model technology other than recirculating wet towers
to be practical. Since it is possible to use recirculating wet towers as a replacement for once-through cooling at manufacturing
facilities, the costs for reuse/recycle technologies were estimated to be similar to the cost of using recirculating wet towers.
Therefore, at manufacturing facilities, EPA developed the costs for water reuse/recycle and the water intakes using
recirculating wet towers as the model. EPA used the same methodology as described above for recirculating wet towers, with
the exception that the make-up factors used for reuse/recycle were set at twice the rate used for power plants (10 percent for
freshwater and 16 percent for marine water). The higher rate is intended to account for possible limitations in the degree of
water use reduction that may be attained by reuse/recycle.
2.5 COST ESTIMATION ASSUMPTIONS AND METHODOLOSY
The assumptions and cost data sources for each of the technologies is described below.
2.5.1 Once-through Capital Costs
The capital costs for the once-through system includes costs for the following:
Intake structure
Pumps, pump well, and pump housing
Piping to and from the condenser
Service road to the intake structure adjacent to the cooling water pipes
The maximum cooling flow value used to develop the once-through cost equations was 350,000 gpm. If the model facility flow
value exceeded this maximum by 10 percent (i.e., > 385,000 gpm), EPAcosted multiple parallel once-through units. Assumptions
for each of the cost components are described below:
Intake Structure
Size equivalent to a box with one side equal to the area needed for a traveling screen with an intake velocity of 1.0 fps. 10
ft were added to the height and the minimum side dimension was 8 ft. An adjacent pump well was also added.
Concrete thickness of 1.5 ft.
Excavated volume equal to 2.5 times box and pump well volume.
Dredged volume equal to 2.5 times box and pump well volume.
Installation of temporary bulkhead with 20 ft added to width.
Installation of temporary sheet piling to shore up excavation equal to 1.5 times side area for intake and pump well.
Area cleared was assumed to be 6 times intake and pump well area.
Service Road
The service road for the intake was made of 6-inch thick reinforced concrete, and a 12-ft width was assumed. An estimated
length of road (which is also the cooling water piping distance) was assigned to different intake volumes. EPA based the
lengths on the cooling water flow, since the cooling water flow should be proportional to the plant size and does not change
between types of cooling systems. The cooling flow corresponding to a freshwater system was used in the case of wet towers,
since it represented the greatest flow. For intake volumes corresponding to a cooling flow of 500 to 10,000 gpm, a 1,000 ft
length was assigned, for >10,000 gpm to 100,000 gpm a 1,500 ft length was used, and for >100,000 gpm a length of 2,000
ft was used.
2-9
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§ 316(b) TDD Chapter 2 for New Facilities
Costing Methodology
Area cleared was assumed to be length times 24 ft.
Pumps and Pump Well
Assumed 3 pumps with each pump sized at 50 percent of design flow (i.e., one pump served as a back-up). Constant speed
pumps were used for baseline costs and variable speed pumps were used for compliance costs.
Pump installation was set equal to 40 percent to 60 percent of pump and motor costs (60 percent at 500 gpm scaled to 40
percent at 350,000 gpm).
Pump and motor costs were from vendor quotes based on a 50 ft pumping head. Purchase costs were increased by 15 percent
to account for taxes, insurance, and freight.
Pump housing unit cost was estimated at $130/ft2.
Pump and pump well area was established using the per pump footprints in Table 2-2 below.
Table 2-2: Assumed Pump Pad and Well Area
Pump Design Flow
(gpm)
Piping to and from the Condenser
Pipe length in one direction is equal to service road length, which is described above. Total length is twice this distance.
Pipe diameters were selected to correspond to pipe velocities ranging from 6 fps for smaller diameter (i.e., 6 inch) to 12 fps
for larger diameter pipe.
Pipe unit cost ranged from $5.50 /in. dia - ft length for smaller pipe to $7.50 /in. dia - ft length for larger pipe.
Intake Screens
As described in Section 2.2.2.3 above, EPA developed cost curves for intake screens of varying widths. The cost curves for each
screen width covered a range of flow volumes that tended to overlap those with larger and smaller widths. For purposes of
estimating intake screen costs, EPA sized the intake screens according to intake flow volumes. Table 2-3 below summarizes the
screen width sizes that were selected for each intake flow volume for the given technology and design specification. Note that
the maximum flow volume listed is approximately 10 percent greater than the maximum cost curve input value. For intake flow
volumes that exceeded this maximum value, multiple parallel screens of the maximum width listed are costed.
2-10
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§ 316(b) TDD Chapter 2 for New Facilities
Costing Methodology
Table 2-3: Intake Flow Volume Criteria for Screen Width Selection
Screen Width
Intake Flow for Traveling Screens
@1.0fps
(gpm)
Intake Flow for Traveling Screens
@ 0.5 fps
(gpm)
2 - Foot
5 - Foot
10 - Foot
14 - Foot
Maximum Flow*
0 -10,000
>10,000 - 24,000
>24,000 - 60,000
>60,000 - 220,000
220,000
0 - 5,000
>5,000 - 12,000
>12,000 - 30,000
>30,000- 110,000
110,000
* Intake volumes above this value were costed for multiple parallel screens using the maximum screen width shown.
Additional Unit Costs
Table 2-4 below summarizes additional unit costs that were used in deriving the capital costs for the items described above.
Table 2-4: Additional Unit Costs
Cost Item
Foundation Concrete
Structural Concrete
Excavation
Bulkhead
Sheet Piling
Area Clearing
Road Paving
Unit
Cubic Yard
Cubic Yard
Cubic Yard
Linear foot
Square Foot
Acre
Square Yard
Cost/Unit
$259
$1,125
$26
$254
$15
$2,975
$23.30
Comment
RS Means Cost Works 2001
Based on 16 in column costs- RS Means Cost Works 2001
RS Means Cost Works 2001
RS Means Cost Works 2001
RS Means Cost Works 2001
Clear, grub, cut light trees to 6 in.- RS Means Cost Works 20(
Concrete pavement 6 in. thick with reinforcement -RS Means
Works 2001
)1
Cost
Miscellaneous Costs
EPA factored the following miscellaneous costs into the estimated capital costs as a percentage of the total capital cost. Values
were selected from the ranges given in Section 2.2.1.2 above:
Mobilization and demobilization was estimated to be 3 percent.
Process engineering was estimated to be 10 percent.
Contractor overhead and profit are included in the unit cost estimates.
Electrical was estimated to be 10 percent.
Site work was estimated to be 10 percent.
Controls were estimated to be 3 percent.
The contingency cost was estimated at 10 percent.
2-11
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§ 316(b) TDD Chapter 2 for New Facilities Costing Methodology
2.5.2 Once-through O&M
The O&M costs are estimated using the cooling water intake pumping energy requirements.
Pumping head was assumed to be 50 ft for all systems.
Pump and motor efficiency was 70 percent.
Annual hours of operation was assumed to be 7860.
Energy cost was estimated at $0.08/KWH. Note that this value is set near the average consumer costs and is higher than the
energy cost to the power plant. This overestimation of the unit energy cost is intended to account for other O&M costs, such
as for intake cleaning and maintenance and pumping equipment maintenance, that are not included as separate items.
2.5.3 Recirculating Wet Tower Capital Costs
For wet towers, it is assumed that recirculating (i.e., cooling) flow would be same as baseline once-through flow.
Capital costs for the recirculating wet tower include costs for all basic tower components, such as structure, foundation,
wiring, piping and recirculating pump costs. Wet tower costs are based on cost data for redwood towers with splash fill and
an approach of 10 °F taken from chart at the end of this chapter.
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.
Costs include installing an inlet structure and pumps using the same assumptions as the once-through intake, except they are
sizedbased on the make-up water requirements described above. Similarly, EPA developed the pipe and service road lengths
using same method as for once-through intakes except that road and piping length were based on a recirculating flow
corresponding to a freshwater system.
2.5.4 Wet Tower O&M Cost
Wet tower O&M costs have two components; one for the intake and one for the wet tower. EPA took wet tower O&M costs
from cost charts at the end of this chapter. Intake O&M costs were based on intake pumping energy requirements in a similar
manner as for once-through pumping described above.
EPA based the intake O&M costs on cooling water intake pumping energy requirements using the same cost assumptions as
for the once-through O&M costs. As with the once-through costs, the energy costs were inflated to account for O&M costs
in addition to the pumping energy requirements.
2.6 ALTERNATIVE RESULATORY OPTIONS
In addition to the preferred two-track option adopted for the final §316(b) New Facility Rule, EPA also developed facility-level
cost estimates for several additional options that EPA considered but did not adopt for the final rule. These additional regulatory
options include the following:
Option 1: Technology-Based Performance Requirements for Different Types of Waterbodies. Under this option, only
facilities located on marine waterbodies would be required to reduce intake flow commensurate with the level that can be
achieved using a closed-cycle recirculating wet cooling system. For all other waterbody types, the only capacity requirements
would be proportional flow reduction requirements. In all waterbodies, velocity limits and a requirement to study, select and
install design and construction technologies would apply.
Option 2 A: Flow Reduction Commensurate with the Level Achieved by Closed-Cycle Recirculating Wet Cooling Systems.
Under this option, all facilities would be required to reduce intake flow commensurate with the level that can be achieved
using a closed-cycle recirculating cooling water system, regardless of the type of waterbody from which they withdraw
cooling water. In addition, facilities would need to meet velocity limits, comply with proportional flow requirements, and
study, select and install design and construction technologies.
2-12
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§ 316(b) TDD Chapter 2 for New Facilities Costing Methodology
Option 2B: Flow Reduction Commensurate with the Level Achieved by Use of a Dry Cooling System. Under this option,
all steam electric powerplants would be required to reduce intake flow commensurate with zero orvery low-level intake (i.e.,
dry cooling). Manufacturing facilities would be required to comply with the national requirement of capacity reduction based
on closed-cycle recirculating wet cooling. This option does not distinguish between facilities on the basis of the waterbody
from which they withdraw cooling water.
Option 3: Industry Two-Track Option. Under this option, an applicant choosing Track I would install "highly protective"
technologies in return for expedited permitting without the need for pre-operational or operational studies in the source
waterbody. Such fast-track technologies might include technologies that reduce intake flow to a level commensurate with
closed-cycle recirculating wet cooling and that achieve an average approach velocity of no more than 0.5 ft/s, or any
technologies that achieve a level of protection from impingement and entrainment within the expected range for a closed-cycle
recirculating wet cooling system. Examples of candidate technologies include: (a) wedgewire screens, where there is constant
flow, as in rivers; (b) traveling fine mesh screens with a fish return system designed to minimize impingement and
entrainment; and (c) aquatic filter barrier systems, at sites where they would not be rendered ineffective by high flows or
fouling. Track II would provide an applicant who does not want to commit to any of the above technology options with an
opportunity to demonstrate that site-specific characteristics would justify another cooling water intake structure technology,
such as once-through cooling.
EPA used the same model facilities and baseline technologies that were used for the preferred two-track option to develop cost
estimates for the alternative regulatory options. In general, EPA used the same assumptions as described above when developing
cost estimates for the alternative regulatory options. Exceptions are noted below for each of the alternative regulatory options.
2.6.1 Option 1: Technology-Based Performance Requirements for Different Types of
Waterbodies
Freshwater Facilities
Compliance cooling system remains the same as baseline, but with variable speed intake pumps.
Compliance intake screen technology consists of traveling screens with fish handling features with an intake velocity of 0.5
fps.
Marine Facilities
Compliance cooling system consists of recirculating wet towers with variable speed intake pumps.
Compliance intake screen technology consists of traveling screens with fish handling features with an intake velocity of 0.5
fps.
Administrative costs for this option will differ from the preferred two-track option, as noted in the Economic Analysis.
2.6.2 Option 2A: Flow Reduction Commensurate with the Level Achieved by Closed-Cycle
Recirculating Wet Cooling Systems
Compliance technologies for this option are the same as for the preferred two-track option adopted in the final rule. Therefore,
EPA did not develop separate capital and O&M costs for this option. Administrative costs for this option will differ from the
administrative costs for the preferred two-track option, as noted in the Economic Analysis.
2-13
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§ 316(b) TDD Chapter 2 for New Facilities Costing Methodology
2.6.3 Option 2B: Flow Reduction Commensurate with the Level Achieved by Use of a
Dry Cooling System
Power Plants
• Compliance cooling system consists of dry cooling towers (air cooled condensers).
No surface water intakes are needed.
Manufacturing Facilities
Compliance cooling system consists of recirculating wet towers with variable speed intake pumps.
Compliance intake screen technology consists of traveling screens with fish handling features with an intake velocity of 0.5
fps.
Capital Costs
The use of air cooled condensers (dry cooling system) instead of wet cooling involves the substitution of the surface condenser
as well as the cold water system. Thus, the cost of surface condensers needs to be included in the baseline capital costs for once-
through and wet tower cooling systems for this option. For baseline once-through systems, EPA incorporated the condenser
capital costs into the cooling system cost component that includes intake structure, pumps, pipes, etc. For baseline wet towers,
EPA incorporated the condenser costs into the intake system cost component that includes intake structure, pumps, pipes, etc.
In the case of wet tower intake costs, the cost equation uses the intake flow as the input variable. Since the condenser cost is based
on the cooling water flow, EPA developed a separate intake/condenser cost curve for each scenario that uses a different make-up
water factor. For the dry cooling compliance systems, EPA included the air cooled condenser cost in the cooling cost.
Wet Cooling Surface Condensers
EPA obtained equipment costs for condensers sized to handle 12 cooling flow values ranging from 4,650 gpm to 329,333
gpm from a condenser manufacturer (Graham Corporation). Condenser capital costs include an air removal package plus
accessories.
Condenser installation was set equal to 40 percent to 60 percent of condenser equipment costs (60 percent at 500 gpm scaled
to 40 percent at 350,000 gpm).
Air Cooled Condensers
Costs for dry cooling are based on steel towers sized to handle the equivalent heat rejection rate of the replaced cooling water
flow. This conversion is factored into the cost formula, which uses the replaced cooling water flow as the input variable.
Development of the unit costs and cost curves for dry cooling systems is discussed in Chapter 4 of this document.
Dry cooling systems do not require water intakes.
O&MCosts
While EPA explicitly included consideration of surface condenser costs in the capital cost estimates where dry cooling systems
were involved, EPA did not directly incorporate corresponding costs for operation and maintenance of the surface condensers into
the O&M costs. In general, O&M costs for the condensers will involve maintenance only, since the condensers are static and any
energy or other consumable material is already considered in other cost components. Some maintenance, including cleaning of
fouled tubes and replacement of damaged tubes may be necessary. However, EPA has concluded that such costs are a small
portion of baseline operation of a power plant and would be similarly offset with O&M costs of drying cooling condenser tubes.
2-14
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§ 316(b) TDD Chapter 2 for New Facilities
Costing Methodology
2.6.4 Option 3: Industry Proposed Two-Track Option
Facilities with Baseline Once-through Cooling
Compliance cooling system consists of once-through cooling with variable speed intake pumps.
Compliance intake screen technology consists of wedgewire (passive) screens with an intake velocity of 0.5 fps.
Facilities with Baseline Recirculating Wet Towers
Compliance cooling system consists of recirculating wet towers with variable speed intake pumps.
Compliance intake screen technology consists of traveling screens with fish handling features with an intake velocity of 0.5
fps.
Wedgewire (Passive) Screens
Where applicable, compliance costs included the cost of wedgewire (passive) screens at the intake structure. Intake velocity
was 0.5 fps.
Costs for passive screens were derived from cost curve data presented at the end of this chapter.
Table 2-5 below summarizes the screen width sizes that were selected for each intake flow volume for the given technology
and design specification. Note that the maximum flow volume listed is approximately 10 percent greater than the maximum
cost curve input value. For intake flow volumes that exceeded this maximum value, multiple parallel screens of the maximum
width listed are costed.
Table 2-5: Intake Flow Volume Criteria for Screen Width Selection
Screen Width
Intake Flow for Wedgewire Screens @ 0.5 fps
(gpm)
2 - Foot
5 - Foot
10 - Foot
Maximum Flow*
0 - 5,000
>5,000 - 12,000
>12,000 - 25,000
25,000
* Intake volumes above this value were costed for multiple parallel screens using the maximum screen width shown.
Administrative costs for this option will differ from the administrative costs for the preferred two-track option, as noted in the
Economic Analysis.
2.7 SUMMARY OF COSTS BY RESULATORY OPTION
2.7.1 Final Rule
Table 2-6 summarizes the baseline, compliance and net technology costs for each model facility for the preferred two-track option
adopted for the final rule. These costs are presented in 1999 dollars. For the Economic Analysis, EPA escalated these values to
2000 dollars. Note that not all of the manufacturing model facility costs are used in the economic analysis model.
2-15
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§ 316(b) TDD Chapter 2 for New Facilities
Costing Methodology
Table 2-6: Baseline, Compliance
Model Facility ID
and Incremental Technology
Two-Track Option (1999
Baseline
Capital O&M
Costs for Model Facilities
$)
Compliance
Capital O&M
Preferred 1
Incremental 1
Capital O&M |
Coal-Fired Power Plants : 1
Coal OT/FW-1
Coal OT/FW-2
Coal OT/FW-3
Coal R/M-1
CoalR/FW-1
Coal R/FW-2
Coal R/FW-3
CoalRL/FW-1
$2,310,000
$9,991,000
$33,411,000
$25,265,000
$5,546,000
$19,148,000
$66,928,000
$11,372,000
$389,000
$2,522,000
$9,280,000
$4,396,000
$849,000
$3,241,000
$11,970,000
$3,219,000
$3,766,000
$19,967,000
$68,135,000
$25,739,000
$5,641,000
$19,365,000
$67,698,000
$24,585,000
$600,000
$3,423,000
$12,141,000
$4,484,000
$919,000
$3,311,000
$12,054,000
$4,296,000
$1,456,000
$9,976,000
$34,724,000
$474,000
$95,000
$217,000
$770,000
$13,213,000
$211,00ol
$901,000 1
$2,861,000 1
$88,000 1
$70,000 1
$70,000 1
$84,000 1
$1,077,000 1
Combined Cycle Power Plants : 1
CC OT/M-1
CC R/M-1
CCR/M-2
CC R/FW-1
CC R/FW-2
CC R/FW-3
$15,989,000
$5,796,000
$10,936,000
$9,650,000
$10,968,000
$12,999,000
$3,673,000
$890,000
$1,819,000
$1,585,000
$1,831,000
$2,223,000
$28,273,000
$5,911,000
$11,133,000
$9,776,000
$11,106,000
$13,157,000
$4,979,000
$971,000
$1,899,000
$1,655,000
$1,902,000
$2,294,000
$12,284,000
$115,000
$197,000
$126,000
$138,000
$158,000
$1,306,000 1
$81,000 1
$80,000 1
$70,000 1
$71,000 1
$71,000 1
Manufacturing Facilities: 1
MANOT/FW-2621
MANOT/M-2812
MANOT/FW-2812
MANR/FW-2812
MANOT/FW-2819
MANR/FW-2819
MANOT/M-2819
MANOT/FW-2821
MANR/FW-2821
MANOT/M-2821
MAN OT/FW-2834
MANR/FW-2834
MAN OT/FW-2869
MAN OT/M-2869
MAN R/FW-2869
MAN OT/FW-2873
MAN R/FW-2873
MANR/FW-2911
MANOT/FW-2911
MANOT/FW-3312
$1,012,000
$6,420,000
$2,814,000
$3,586,000
$875,000
$1,572,000
$1,094,000
$2,419,000
$7,367,000
$1,172,000
$848,000
$1,572,000
$1,440,000
$1,067,000
$2,589,000
$1,253,000
$13,997,000
$4,564,000
$3,079,000
$3,527,000
$141,000
$1,556,000
$552,000
$515,000
$112,000
$175,000
$159,000
$458,000
$1,175,000
$176,000
$106,000
$175,000
$235,000
$153,000
$346,000
$194,000
$2,424,000
$683,000
$617,000
$728,000
$1,871,000
$13,717,000
$5,450,000
$3,749,000
$1,598,000
$1,655,000
$2,117,000
$4,639,000
$7,616,000
$2,277,000
$1,550,000
$1,655,000
$2,713,000
$2,062,000
$2,713,000
$2,342,000
$14,435,000
$4,743,000
$5,959,000
$6,866,000
$281,000
$2,349,000
$877,000
$590,000
$236,000
$246,000
$328,000
$741,000
$1,254,000
$354,000
$228,000
$246,000
$419,000
$319,000
$419,000
$358,000
$2,506,000
$758,000
$966,000
$1,123,000
$859,000
$7,297,000
$2,636,000
$163,000
$723,000
$83,000
$1,023,000
$2,220,000
$249,000
$1,105,000
$702,000
$83,000
$1,273,000
$995,000
$124,000
$1,089,000
$4,380,000
$179,000
$2,880,000
$3,339,000
$140,000 1
$793,000 1
$325,000 1
$75,000 1
$124,000 1
$71,000 1
$169,000 1
$283,000 1
$79,000 1
$178,000 1
$122,000 1
$71,000 1
$184,000 1
$166,000 1
$73,000 1
$164,000 1
$82,000 1
$75,000 1
$349,000 1
$395,000 1
2-16
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§ 316(b) TDD Chapter 2 for New Facilities
Costing Methodology
Table 2-6: Baseline, Compliance and Incremental Technology Costs for Model Facilities Preferred 1
Two-Track Option (1999 $) |
Model Facility ID
Baseline
Capital O&M
Compliance
Capital O&M
Incremental 1
Capital O&M 1
MANR/FW-3312
MANOT/FW-3316
MANR/FW-3316
MANOT/FW-3317
MANR/FW-3317
MAN OT/FW-3353
MANR/FW-3353
$35,922,000
$985,000
$6,449,000
$1,414,000
$2,589,000
$1,306,000
$3,586,000
$6,664,000
$135,000
$1,012,000
$229,000
$346,000
$206,000
$515,000
$39,993,000
$1,815,000
$6,711,000
$2,658,000
$2,713,000
$2,445,000
$3,749,000
$7,000,000
$272,000
$1,092,000
$410,000
$419,000
$375,000
$590,000
$4,071,000
$830,000
$262,000
$1,244,000
$124,000
$1,139,000
$163,000
$336,000
$137,000
$80,000
$181,000
$73,000
$169,000
$75,000
2.7.2 Option 1: Technology-Based Performance Requirements for Different Types of
Waterbodies
Table 2-7 summarizes the baseline, compliance and net technology costs for each model facility for alternative regulatory Option
1. These costs are presented in 1999 dollars. For the Economic Analysis, EPA escalated these values to 2000 dollars. Note that
not all of the manufacturing model facility costs are used in the economic analysis model.
Table 2-7: Baseline, Compliance and Incremental Technology Costs for Model Facilities
Option 1 (1999 $)
Model Facility ID
Bas
Capital
eline
O&M
Comp
Capital
liance
O&M
Incremental
Capital O&M
Coal-Fired Power Plants:
Coal OT/FW-1
Coal OT/FW-2
Coal OT/FW-3
Coal R/M-1
CoalR/FW-1
Coal R/FW-2
Coal R/FW-3
CoalRL/FW-1
$2,310,000
$9,991,000
$33,411,000
$25,265,000
$5,546,000
$19,148,000
$66,928,000
$11,372,000
$389,000
$2,522,000
$9,280,000
$4,396,000
$849,000
$3,241,000
$11,970,000
$3,219,000
$2,964,000
$14,110,000
$49,121,000
$25,739,000
$5,641,000
$19,365,000
$67,698,000
$16,733,000
$470,000
$2,689,000
$9,741,000
$4,484,000
$919,000
$3,311,000
$12,054,000
$3,423,000
$654,000
$4,119,000
$15,710,000
$474,000
$95,000
$217,000
$770,000
$5,361,000
$81,000
$167,000
$461,000
$88,000
$70,000
$70,000
$84,000
$204,000
Combined Cycle Power Plants:
CC OT/M-1
CC R/M-1
CCR/M-2
CC R/FW-1
CC R/FW-2
CC R/FW-3
$15,989,000
$5,796,000
$10,936,000
$9,650,000
$10,968,000
$12,999,000
$3,673,000
$890,000
$1,819,000
$1,585,000
$1,831,000
$2,223,000
$28,273,000
$5,911,000
$11,133,000
$9,776,000
$11,106,000
$13,157,000
$4,979,000
$971,000
$1,899,000
$1,655,000
$1,902,000
$2,294,000
$12,284,000
$115,000
$197,000
$126,000
$138,000
$158,000
$1,306,000
$81,000
$80,000
$70,000
$71,000
$71,000
Manufacturing Facilities:
MANOT/FW-2621 $1,012,000
$141,000 $1,386,000
$221,000
$374,000
2-17
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§ 316(b) TDD Chapter 2 for New Facilities
Costing Methodology
Model
Table
Facility
2-7: Baseline, Compliance and Incremental Technology Costs for Model
Option 1 (1999 $)
ID
Bus
Capital
eline
O&M
Comp
Capital
liance
O&M
Facilities 1
Incremental 1
Capital O&M |
MANOT/M-2812
MANOT/FW-2812
MANR/FW-2812
MANOT/FW-2819
MANR/FW-2819
MANOT/M-2819
MANOT/FW-2821
MANR/FW-2821
MANOT/M-2821
MAN OT/FW-2834
MAN R/FW-2834
MAN OT/FW-2869
MAN OT/M-2869
MANR/FW-2869
MAN OT/FW-2873
MANR/FW-2873
MANR/FW-2911
MANOT/FW-2911
MANOT/FW-3312
MANR/FW-3312
MANOT/FW-3316
MANR/FW-3316
MANOT/FW-3317
MANR/FW-3317
MAN OT/FW-3353
MANR/FW-3353
$6,420,000
$2,814,000
$3,586,000
$875,000
$1,572,000
$1,094,000
$2,419,000
$7,367,000
$1,172,000
$848,000
$1,572,000
$1,440,000
$1,067,000
$2,589,000
$1,253,000
$13,997,000
$4,564,000
$3,079,000
$3,527,000
$38,851,000
$985,000
$6,449,000
$1,414,000
$2,589,000
$1,306,000
$3,586,000
$1,556,000
$552,000
$515,000
$112,000
$175,000
$159,000
$458,000
$1,175,000
$176,000
$106,000
$175,000
$235,000
$153,000
$346,000
$194,000
$2,424,000
$683,000
$617,000
$728,000
$6,898,000
$135,000
$1,012,000
$229,000
$346,000
$206,000
$515,000
$13,717,000
$4,058,000
$3,749,000
$1,193,000
$1,655,000
$2,117,000
$3,484,000
$7,616,000
$2,277,000
$1,154,000
$1,655,000
$1,984,000
$2,062,000
$2,713,000
$1,723,000
$14,435,000
$4,743,000
$4,448,000
$5,122,000
$39,993,000
$1,348,000
$6,674,000
$1,947,000
$2,713,000
$1,798,000
$3,749,000
$2,349,000
$657,000
$590,000
$190,000
$246,000
$328,000
$558,000
$1,254,000
$354,000
$183,000
$246,000
$320,000
$319,000
$419,000
$277,000
$2,506,000
$758,000
$724,000
$841,000
$7,000,000
$215,000
$1,089,000
$314,000
$419,000
$289,000
$590,000
$7,297,000
$1,244,000
$163,000
$318,000
$83,000
$1,023,000
$1,065,000
$249,000
$1,105,000
$306,000
$83,000
$544,000
$995,000
$124,000
$470,000
$438,000
$179,000
$1,369,000
$1,595,000
$1,142,000
$363,000
$225,000
$533,000
$124,000
$492,000
$163,000
$793,000
$105,000
$75,000
$78,000
$71,000
$169,000
$100,000
$79,000
$178,000
$77,000
$71,000
$85,000
$166,000
$73,000
$83,000
$82,000
$75,000
$107,000
$113,000
$102,000
$80,000
$77,000
$85,000
$73,000
$83,000
$75,000
2.7.3 Option 2A: Flow Reduction Commensurate with Closed-Cycle recirculating Wet
Cooling Systems
Baseline, compliance and incremental technology capital and O&M costs for this option are the same as for the preferred two-track
option.
2-18
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§ 316(b) TDD Chapter 2 for New Facilities
Costing Methodology
2.7.4 Option 2B: Flow Reduction Commensurate with Dry Cooling Systems
Table 2-8 summarizes the baseline, compliance and net technology costs for each model facility for alternative regulatory Option
2B. These costs are presented in 1999 dollars. For the Economic Analysis, EPA escalated these values to 2000 dollars.
Table 2-8: Baseline, Compliance and Incremental Technology Costs for Model Facilities
Option 2B (1999 $)
Model Facility ID
Baseline
Capital O&M
Compliance
Capital O&M
Incremental
Capital O&M
Coal-Fired Power Plants:
Coal OT/FW-1 $3,757,000
Coal OT/FW-2
Coal OT/FW-3
Coal R/M-1
CoalR/FW-1
Coal R/FW-2
Coal R/FW-3
CoalRL/FW-1
$17,139,000
$59,509,000
$34,738,000
$7,643,000
$26,241,000
$94,286,000
$20,397,000
Combined Cycle Power Plants:
CC OT/M-1 $26,663,000
CC R/M-1 $7,933,000
CCR/M-2 $14,985,000
CCR/FW-1 $13,298,000
CC R/FW-2 $15,137,000
CC R/FW-3 $18,025,000
$389,000
$2,522,000
$9,280,000
$4,396,000
$849,000
$3,241,000
$11,970,000
$3,219,000
$3,673,000
$590,000
$1,819,000
$1,585,000
$1,831,000
$2,223,000
$9,397,000
$62,634,000
$234,182,000
$79,792,000
$14,892,000
$60,315,000
$232,222,000
$81,323,000
$93,582,000
$15,277,000
$32,319,000
$28,513,000
$33,374,000
$41,410,000
$2,363,000
$11,427,000
$38,505,000
$16,882,000
$3,669,000
$11,173,000
$38,355,000
$13,074,000
$13,790,000
$3,757,000
$7,177,000
$6,486,000
$7,362,000
$8,677,000
$5,640,000
$45,495,000
$174,673,000
$45,054,000
$7,249,000
$34,074,000
$137,936,000
$60,926,000
$66,919,000
$7,344,000
$17,334,000
$15,215,000
$18,237,000
$23,385,000
$1,974,000
$8,905,000
$29,225,000
$12,486,000
$2,820,000
$7,932,000
$26,385,000
$9,855,000
$10,117,000
$2,867,000
$5,358,000
$4,901,000
$5,531,000 |
$6,454,000 |
Baseline, compliance and incremental technology capital and O&M costs for manufacturing facilities for this option are the same
as for the preferred two-track option.
2-19
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§ 316(b) TDD Chapter 2 for New Facilities
Costing Methodology
2.7.5 Option 3: Industry Two-Track Option
Table 2-9 summarizes the baseline, compliance and net technology costs for each model facility for alternative regulatory Option
2B. These costs are presented in 1999 dollars. For the Economic Analysis, EPA escalated these values to 2000 dollars. Note
that not all of the manufacturing model facility costs are used in the economic analysis model.
Table 2-9:
Model Facility ID
Baseline, Compliance and Incremental Technology Costs
Option 3 (1999 $)
Baseline
Capital O&M
Compliance
Capital O&M
for Model Facilities
Incremental 1
Capital O&M |
Coal-Fired Power Plants : 1
Coal OT/FW-1
Coal OT/FW-2
Coal OT/FW-3
Coal R/M-1
CoalR/FW-1
Coal R/FW-2
Coal R/FW-3
CoalRL/FW-1
$2,310,000
$9,991,000
$33,411,000
$25,265,000
$5,546,000
$19,148,000
$66,928,000
$11,372,000
$389,000
$2,522,000
$9,280,000
$4,396,000
$849,000
$3,241,000
$11,970,000
$3,219,000
$2,595,000
$12,178,000
$41,751,000
$25,739,000
$5,641,000
$19,365,000
$67,698,000
$14,247,000
$440,000
$2,530,000
$9,168,000
$4,484,000
$919,000
$3,311,000
$12,054,000
$3,219,000
$285,000
$2,187,000
$8,340,000
$474,000
$95,000
$217,000
$770,000
$2,875,000
$5 1,000 1
$8,000 1
$0*1
$88,000 1
$70,000 1
$70,000 1
$84,000 1
$0*1
Combined Cycle Power Plants : 1
CC OT/M-1
CC R/M-1
CCR/M-2
CC R/FW-1
CC R/FW-2
CC R/FW-3
$15,989,000
$5,796,000
$10,936,000
$9,650,000
$10,968,000
$12,999,000
$3,673,000
$890,000
$1,819,000
$1,585,000
$1,831,000
$2,223,000
$19,289,000
$5,911,000
$11,133,000
$9,776,000
$11,106,000
$13,157,000
$3,677,000
$971,000
$1,899,000
$1,655,000
$1,902,000
$2,294,000
$3,300,000
$115,000
$197,000
$126,000
$138,000
$158,000
$4,000 1
$81,000 1
$80,000 1
$70,000 1
$71,000 1
$71,000 1
Manufacturing Facilities: 1
MANOT/FW-2621
MANOT/M-2812
MANOT/FW-2812
MANR/FW-2812
MANOT/FW-2819
MANR/FW-2819
MANOT/M-2819
MANOT/FW-2821
MANR/FW-2821
MANOT/M-2821
MAN OT/FW-2834
MAN R/FW-2834
MAN OT/FW-2869
MAN OT/M-2869
MANR/FW-2869
$1,012,000
$6,420,000
$2,814,000
$3,586,000
$875,000
$1,572,000
$1,094,000
$2,419,000
$7,367,000
$1,172,000
$848,000
$1,572,000
$1,440,000
$1,067,000
$2,589,000
$141,000
$1,556,000
$552,000
$515,000
$112,000
$175,000
$159,000
$458,000
$1,175,000
$176,000
$106,000
$175,000
$235,000
$153,000
$346,000
$1,229,000
$8,632,000
$3,608,000
$3,749,000
$1,059,000
$1,655,000
$1,331,000
$3,108,000
$7,616,000
$8,632,000
$1,025,000
$1,655,000
$1,821,000
$1,297,000
$2,713,000
$206,000
$1,631,000
$617,000
$590,000
$177,000
$246,000
$234,000
$523,000
$1,254,000
$1,631,000
$171,000
$246,000
$300,000
$228,000
$419,000
$217,000
$2,212,000
$794,000
$163,000
$184,000
$83,000
$237,000
$689,000
$249,000
$2,212,000
$177,000
$83,000
$381,000
$230,000
$124,000
$65,000 1
$75,000 1
$65,000 1
$75,000 1
$65,000 1
$71,000 1
$75,000 1
$65,000 1
$79,000 1
$75,000 1
$65,000 1
$71,000 1
$65,000 1
$75,000 1
$73,000 1
2-20
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§ 316(b) TDD Chapter 2 for New Facilities
Costing Methodology
Table 2-9: Baseline, Compliance and Incremental Technology Costs for Model Facilities
Option 3 (1999 $)
Model Facility ID
MAN OT/FW-2873
MAN R/FW-2873
MANR/FW-2911
MANOT/FW-2911
MANOT/FW-3312
MANR/FW-3312
MANOT/FW-3316
MANR/FW-3316
MANOT/FW-3317
MANR/FW-3317
MAN OT/FW-3353
MANR/FW-3353
Baseline
Capital O&M
$1,253,000
$13,997,000
$4,564,000
$3,079,000
$3,527,000
$38,851,000
$985,000
$6,449,000
$1,414,000
$2,589,000
$1,306,000
$3,586,000
$194,000
$2,424,000
$683,000
$617,000
$728,000
$6,898,000
$135,000
$1,012,000
$229,000
$346,000
$206,000
$515,000
Compliance
Capital O&M
$1,528,000
$14,435,000
$4,743,000
$3,945,000
$4,577,000
$39,993,000
$1,195,000
$6,674,000
$1,787,000
$2,713,000
$1,595,000
$3,749,000
$259,000
$2,506,000
$758,000
$682,000
$793,000
$7,000,000
$200,000
$1,089,000
$294,000
$419,000
$271,000
$590,000
Incremental
Capital O&M
$275,000
$438,000
$179,000
$866,000
$1,050,000
$1,142,000
$210,000
$225,000
$373,000
$124,000
$289,000
$163,000
$65,000
$82,000
$75,000
$65,000
$65,000
$102,000
$65,000
$77,000
$65,000
$73,000
$65,000
$75,000
*For this model facility, O&M costs for wedgewire screens are actually less than the O&M costs for the baseline traveling screens.
To be conservative, EPA has set the incremental O&M cost at $0; this does not reflect potential savings to the facility associated
with switching intake screen types.
2.8 TECHNOLoey UNIT COSTS
2.8.1 General Cost Information
The cost estimates presented in this analysis include both capital costs and operations and maintenance (O&M) costs and are for
primary technologies such as traveling screens and cooling towers. Facilities may install these technologies to meet requirements
of the final §316(b) New Facility Rule. Cooling tower cost estimates are presented for various types of cooling towers including
towers fitted with features such as plume abatement and noise reduction. Estimated costs for traveling screens were developed
mainly from cost information provided by vendors. The cost of installing other CWIS technologies such as passive screens and
velocity caps are calculated by applying a cost factor based on the cost of traveling screens. All of the base cost estimates are for
new sources.
To provide a relative measurement of the differences in cost across technologies, costs need to be developed on a uniform basis.
The cost for many of the CWIS and flow reduction technologies depends on many factors, including site-specific conditions, and
the relative importance of many of these factors varies from technology to technology. 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. EPA
developed cost estimates, in $/gallons per minute (gpm), for most of the technologies for use at a range of different total intake
flow volumes. For cooling towers, EPA developed cost estimates for use at a range of different total recirculating flow volumes.
EPA assumed average values or typical situations for the other factors that also impact the cost components. For example, EPA
assumed an average debris level and an intake flow velocity of 0.5 feet per second (fps); EPA also used 1.0 fps for cost
comparison purposes. EPA separately assessed the cost effect of variations from these average conditions as add-on costs. For
instance, if the water being drawn in has a high debris level, this would tend to increase cost by about 20 percent.
EPA determined the specifications for each factor based on a review of information about the characteristics most likely to be
encountered at a typical facility withdrawing cooling water. Cost factors used in this analysis and the assumed values/scenarios
2-21
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§ 316(b) TDD Chapter 2 for New Facilities
Costing Methodology
are listed below in Table 2-10. EPA's unit cost estimates for the selected technologies are based on the information provided by
vendors, industry representative, and published documents.
Table 2-10. Basis for Development of Unit Costs
Base Factor for Developing Unit Costs
Assumed Values of Other Factors for Base Costs
Costs were developed for flows of: '
< 10,000 gpm - 4 flows
10,000 to < 100,000 gpm - 20 flows
100,000 to 200,000 gpm - 4 flows
> 200,000 gpm -1 flow.
Cost Elements
Intake flow velocity = 0.5 fps, and 1.0 fps for comparison
Amount and type of debris = average/typical
Water quality = fresh water
Waterbody flow velocity = moderate flow
Accessability to intake = average/typical (no dredging needed,
use of crane possible)
Cost estimates of screens include non-metallic fish handling panels, a spray system, a fish trough, housings and
transitions, continuous operating features (intermittent operation feature for traveling screens without fish
baskets), a drive unit, frame seals, engineering, and installation. EPA separately estimated costs for spray wash
pumps, permitting, and pilot studies.
Cooling towers cost estimates are based on unit costs that include all costs associated with the design,
construction, and commissioning of a standard fill cooling tower. Costs of cooling towers with various features,
building materials, and types are calculated based on cost comparisons with standard cooling towers.
O&M costs were estimated for each type of technology. These costs were estimated, in part, using a percent of
capital costs as a basis and considering additional factors.
Potential Add-Ons to Cost
Amount and type of debris = high or need for smaller than typical openings
Depth of waterbody = particularly shallow or deep
Water quality = salt or brackish water (extra cost for non-corrosive material for device and shorter life
expectancy/higher replacement cost)
Waterbody flow velocity = stagnant or rapidly moving
Accessability to intake = cost of difficult installation (extra cost for dredging, extra cost for unusual
installation due to site-specific conditions)
Existing intake structure = costs associated with retrofit and what existing structure(s) or conditions
would cause the extra costs. For example, if an existing structure has an intake flow of 2.0 fps and the intake
velocity will be reduced to 0.5 fps with a new device, additional equipment or changes to other
equipment/structures of that part of the intake system may increase capital costs (albeit minimally) when
compared to installing a new system.
1) Cost estimates were developed for selected flows in each range (e.g., 4 different flows less than 10,000 gpm).
10,000 spm = 14.4 MOD
The costs estimated for fish protection equipment are linked to both flow rates and intake width and depth. Cooling towers costs
are based on the recirculating flow rate, temperature approach (defined later), and the type of cooling tower. Several industry
representatives provided information on how they conduct preliminary cost estimates for cooling towers. This is considered to
be the "rule of thumb" in costing cooling towers (i.e., $/gallons per minute). Regional variations incests do exist. However, EPA
has based its cost estimates on average flow designs representing model facilities. EPA often used conservative (i.e. high cost)
assumptions in order to develop model facility costs that accurately represent average costs applicable to affected facilities across
the country. In addition to the costs presented below, cost curves and equations are provided at the end of this chapter. The cost
curves and equations can be used to estimate costs for implementing technologies or taking actions for facilities across a range
2-22
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§ 316(b) TDD Chapter 2 for New Facilities
Costing Methodology
of intake flows. Additional supporting information can be found in Cost Research and Analysis of Cooling Water Technologies
for 316(b) Regulatory Options (SAIC, 2000).
2.8.2 Flow
EPA determined preliminary intake flow values for the base factor based on data from the ICR (Information Collection Request)
for the §316(b) industry questionnaire, a sampling of responses to the §316(b) industry screener questionnaire, a Utility Data
Institute database (UDI, 1995), and industry brochures and technology background papers.6 Data from these sources represent
utility and nonutility steam electric facilities and industrial facilities that could be subject to prospective §316(b) requirements
and are provided in Table 2-11. EPA used these data to determine the range of typical intake flows for these types of facilities
to ensure that the flows included in the cost estimates were representative. Through data provided by equipment vendors, EPA
determined the flows typically handled by available CWIS equipment and cooling towers. Facilities with greater flows would
generally either use multiple screens, towers, or other technologies, or use a special design. Considering this information together,
EPA selected flows for various screen sizes, water depths, and intake velocities for use in collecting cost data directly from
industry representatives.
Table 2-11. Flow Data for Unit Costs
ICR (average intake flows by utility/industry category)
Steam electric utilities:
Steam electric non-utilities:
Chemicals & allied products:
Primary metals:
Petroleum & coal products:
Paper & allied products:
178 MOD (124,000 gpm) for 1,093 facilities
2.8 MOD (1,944 gpm) for 1,158 facilities
0.339 MOD (235 gpm) for 22,579 facilities
0.327 MOD (227 gpm) for 10,999 facilities
0.461 MOD (320 gpm) for 3,509 facilities
0.148 MOD (103 gpm) for 9,881 facilities
UDI Database (design intake flow for steam electric utilities) (UDI. 1995)
Up to 11,219 gpm (16.15 MOD) 401 units
11,220-44,877 gpm (16.16-64.62 MOD) 465 units
44,878-134,630 gpm (64.63-193.9 MOD) 684 units
134,631-448,766 gpm (194-646.2 MOD) 453 units
More than 448,766 gpm (646.2 MOD) 68 units
Sampling of Responses from Industry Screener Questionnaire (daily intake flow for non-utilities)
Up to 0.5 MOD (347 gpm) 6 facilities
XX5-1.0 MOD (348-694 gpm) 1 facilities
>1-5.0 MOD (695-3,472 gpm) 3 facilities
>5.0-10.0 MOD (3,473-6,944 gpm) 8 facilities
>10-20.0 MOD (6,945-13,889 gpm) 2 facilities
>20-30.0 MOD (13,890-20,833 gpm) 2 facilities
>30-40.0 MOD (20,834-27,778 gpm) 2 facilities
>40-50.0 MOD (27,779-34,722 gpm) 1 facility
>50-100.0 MOD (34,723-69,444 gpm) 0 facilities
>100 MOD (>69,444 gpm) 1 facility
US Filter/Johnson Screens Brochure (ranges for flow definitions) (US Filter. 1998)
Low flow: 200 to 4,000 gpm (0.288 to 5.76 MOD)
Intermediate flow: 1,500 to 15,000 gpm (2.16 to 21.6 MOD)
High flow: 5,000 to 30,000 gpm (7.2 to 43.2 MOD)
Background Technology Papers (SAIC. 1994: SAIC. 1996)
"Relatively low intake flow": 1-30 MOD (694-20,833 gpm)
"Relatively small quantities of water": up to 50,000 gpm (70 MOD)
6EPA sent the Industry Screener Questionnaire: Phase I Cooling Water Intake Structures to about 2,500 steam electric
non-utility power producers and manufacturers. This sample included most of the non-utility power producers that were
identified by EPA and a subset of the identified manufacturers in industry groups that EPA determined use relatively large
quantities of cooling water.
2-23
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§ 316(b) TDD Chapter 2 for New Facilities Costing Methodology
2.8.3 Additional Cost Considerations Included in the Analysis
The cost estimates include costs, such as design/engineering, process equipment, and installation, that are clearly part of getting
a CWIS structure or cooling tower in place and operational. However, there are additional associated capital costs that may be
less apparent but may also be incurred by a facility and have been included in the cost estimates either as stand-alone cost items
or included in installation and construction costs. EPA included the following costs as part of the unit cost estimates:
• Mobilization and demobilization,
• Architectural fees,
• Contractor's overhead and profit,
• Process engineering,
• Sitework and yard piping,
• Standby power,
• Electrical allowance,
• Instrumentation and controls, and
• Contingencies
• Installation.
Following is a brief description of these miscellaneous capital cost items to provide an indication of their general effect on capital
costs. These descriptions are also intended to help economists adjust costs to account for regional variations within the U. S. EPA
notes that for the costs of cooling towers, each of these items is included the total installed capital costs estimates, but these
specific items are not necessarily itemized due to EPA's use of a total inclusive cost per gallon estimate for cooling towers.
Mobilization and Demobilization
Mobilization and demobilization costs are costs incurred by the contractor to assemble crews and equipment on-site and to
dismantle semi-permanent and temporary construction facilities once the job is completed. The equipment that may be needed
includes backhoes, bulldozers, front-end loaders, self-propelled scrapers, pavers, pavement rollers, sheeps-foot rollers, rubbertire
rollers, cranes, temporary generators, trucks (including water and fuel trucks), and trailers. Mobilization costs also include bonds
and insurance. To account for mobilization and demobilization costs, a range of 2 percent to 5 percent is was added to the total
capital cost, depending on the specific site characteristics.
Architectural Fees
Estimates need to include the cost of the building design, architectural drawings, building construction supervision, construction
engineering, and travel, not to exceed 8 percent of the capital cost.
Contractor's Overhead and Profit
This element includes field supervision, main office expenses, tools and minor equipment, workers' compensation and employer's
liability, field office expenses, performance and payment bonds, unemployment tax, profit, Social Security andMedicare, builder's
risk insurance, and public liability insurance. This was estimated at 12 percent of the capital cost.
Process Engineering
Costs for this category include treatment process engineering, unit operation construction supervision, travel, system start-up
engineering, study, design, operation and maintenance (O&M) manuals, and record drawings. These costs were estimated by
adding a range of 10 percent to 20 percent to the estimated capital cost.
2-24
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§ 316(b) TDD Chapter 2 for New Facilities Costing Methodology
Sitework and Yard Piping
Cost estimates for sitework include site preparation, excavation, backfilling, roads, walls, landscaping, parking lots, fencing, storm
water control, yard structures, and yard piping (interconnecting piping between treatment units). These costs were estimated by
adding a range of 5 percent to 15 percent to the estimated capital cost for sitework and a range of 3 percent to 7 percent for yard
piping.
For installation of CWIS technologies (e.g., screens), a yard piping cost of 5 percent of the total capital cost is sometimes used
based on site-specific conditions. Cooling towers require a significant amount of piping (for both new facilities and retrofits to
existing facilities) and these costs are already included in the capital cost estimate for cooling towers so an additional 5 percent
was not applied.
Standby Power
Standby generators may be needed to produce power to the treatment and distribution system during power outages and should
be included in cost estimates. These costs are estimated by adding a range of 2 percent to 5 percent to the estimated construction
cost.
Electrical Allowance (including yard wiring)
An electrical allowance should be made for electric wiring, motors, duct banks, MCCs, relays, lighting, etc. These costs are
estimated by adding a range of 10 percent to 15 percent to the estimated construction cost.
Instrumentation and Controls
Instrumentation and control (I&C) costs may include a facility control system, software, etc. The cost depends on the degree of
automation desired for the entire facility. These costs are estimated by adding a range of 3 percent to 8 percent to the estimated
construction cost.
Contingencies
Contingency cost estimates include compensationforuncertainty within the scope of labor, materials, equipment, and construction
specifications. This uncertainty factor is estimated to range from 5 percent to 25 percent of all capital costs, with an average of
10 percent for general engineering projects.
Contingency costs can range from 2 percent to 20 percent for construction projects. CWIS technology projects are not typical
construction projects since most of the construction is done at the manufacturing facility and site work mainly involves installation.
So some of the uncertainties that could occur in typical construction projects are less likely in CWIS projects. Design and
manufacture of the technology can be around 90 percent of the total cost for a project that involves a straightforward installation
(e.g., no dredging). The approach used in this cost estimate is conservative and is considered to cover contingencies for typical
CWIS technology or cooling tower projects.
In its 1992 study of cooling tower retrofit costs, Stone and Webster (1992) included, in its line item costs, an allowance for
indeterminates (e.g., contingencies) of 15 percent for future utility projects. The Stone and Webster study involved major retrofit
work on existing plants (i.e., converting a once through cooling system plant to recirculating), so the contingencies allowance fell
in the higher end of the typical range.
Installation costs
Installation costs are estimated at 80 percent of cooling tower equipment cost based on information provided by equipment
vendors. See the end of this chapter for cost curves and equations.
2-25
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§ 316(b) TDD Chapter 2 for New Facilities Costing Methodology
2.8.4 Replacement Costs
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.
2.9 SPECIFIC COST INFORMATION FOR TECHNOLOSIES AND ACTIONS
The following sections present information on potential compliance actions that a facility might take, including the installation
of certain technologies, in order to meet requirements under the §316(b) New Facility Rule. The information presented includes
the cost curves and unit costs developed for each potential compliance action. Estimated costs are presented in 1999 dollars. The
cost equations and cost curves can be used to estimate costs. The equations and cost curves generally use flow as the basis for
determining estimated costs (i.e., unit costs are in $/gpm). For screens, since flow is dependent on the flow velocity through the
screen, different equations and cost curves are included for the two velocities of 0.5 fps and 1.0 fps.
2.9.1 Reducing Design Intake Flow
Switching to a recirculating system
As noted earlier, in a recirculating system cooling water is used to cool equipment and steam, and absorbs heat in the process.
The cooling water is then cooled and recirculated to the beginning of the system to be used again for cooling. 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 (e.g., topographic
conditions, soils and underground conditions, water quality) affect cost, but in most situations are secondary to the primary cost
factors. Table 2-12 presents relative capital and operation cost estimates for various cooling towers in comparison to the
conventional, basic Douglas Fir cooling tower as a standard. EPA notes that based on its data collection for recent cooling tower
projects, for most cases, environmental considerations such as plume abatement and noise abatement are rarely installed.
Therefore, EPA is presenting costs in the following sections for comparison purposes only and these types of costs are not
uniformly applicable to a national rule.
Table 2-12.
Tower Type
Douglas Fir
Redwood
Concrete
Steel
Fiberglass Reinforced Plastic
Splash Fill
Relative Cost Factors for Various
Capital Cost Factor (%)
100
1122
140
135
110
120
Cooling Tower Types1 |
Operation Cost Factor (%) |
100 1
100 1
90 1
98 1
98 1
150 1
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§ 316(b) TDD Chapter 2 for New Facilities Costing Methodology
Table 2-12. Relative Cost Factors for Various Cooling Tower Types1
1) Percent estimates are relative to the Douglas Fir cooling tower.
2) Redwood cooling tower costs may be higher because redwood trees are a protected species, particularly in the
Northwest.
Non-Fouling Film Fill
Mechanical draft
Natural draft (concrete)
Hybrid [Plume abatement (32DBT)]
Dry/wet
Air condenser (steel)
Noise reduction (lOdBA)
Sources: Mirsky et al. (1992), Mirsky and Bauthier (1997), and Mirsky (2000).
There are two general types of cooling towers, wet and dry. Wet cooling towers, which are the far more common type, reduce
the temperature of the water by bringing it directly into contact with large amounts of air. Through this process, heat is transferred
from the water to the air which is then discharged into the atmosphere. Part of the water evaporates through this process thereby
having a cooling effect on the rest of the water. This water then exits the cooling tower at a temperature approaching the wet bulb
temperature of the air.
For dry cooling towers, the water does not come in direct contact with the air, but instead travels in closed pipes through the tower.
Air going through the tower flows along the outside of the pipe walls and absorbs heat from the pipe walls which absorb heat from
the water in the pipes. Dry cooling towers tend to be much larger and more costly than wet towers because the dry cooling process
is less efficient. Also, the effluent water temperature is warmer because it only approaches the dry bulb temperature of the air (not
the cooler wet bulb temperature). Development of unit costs and cost curves for dry cooling towers is discussed in Chapter 4 of
this document.
Hybrid wet-dry towers, which combine dry heat exchange surfaces with standard wet cooling towers, are plume abatement towers.
These towers tend to be used most where plume abatement is required by local authorities. Technologies for achieving low noise
and low drift can be fitted to all types of towers.
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.
2-27
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§ 316(b) TDD Chapter 2 for New Facilities Costing Methodology
• Construction materials: Towers can be made from concrete, steel, wood, and/or fiberglass.
Generally, all cooling towers with plume abatement features are hybrid towers. According to the Standard Handbook of Power
Plant Design, attempts to modify towers with special designs and construction features to abate plumes has been tested but not
accepted as an effective technology. Natural draft towers are concrete towers, although some old natural draft wood cooling
towers do exist. Therefore, for costing purposes, concrete is assumed to be the material used for building natural draft cooling
towers.
Capital Cost of Cooling Towers
Typically, the cost of the project is determined based on the following factors: type of equipment to be cooled (e.g., coal fired
equipment, natural gas powered equipment); location of the water intake (on a river, lake, or seashore); amount of power to-be-
generated (e.g., 50 Megawatt vs. 200 Megawatt); and volume of water needed. 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 a delta of 10 degrees and $50/gpm for a delta of 5 degrees.7 This cost is for a "small" tower (flow less
than 10,000 gpm) and equipment associated with the "basic" tower, and does notinclude installation. Ancillary 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 in calculating screen capacities at 1 ft/sec and 0.5 ft/sec.
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).8 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
7The delta 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 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.
8With 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.
2-28
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§ 316(b) TDD Chapter 2 for New Facilities
Costing Methodology
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.
• Pollution control requirements: Air pollution control facilities require electricity to operate. Local requirements to control
drift, plume, fog, and noise and to consider aesthetics can also increase costs for a given site (e.g., different design
specifications may be required).
Summaries of some EPRI research on dry cooling systems and wet-dry supplemental cooling systems note that dry cooling towers
may cost as much as four times more than conventional wet towers (EPRI, 1986a and 1986b).
Table 2-13: Estimated Capital Costs of Cooling Towers
without Special Environmental Impact Mitigation Features (1999 Dollars)
Flow Basic Douglas Fir
(gpm) Cooling Tower Cost1
Redwood Tower Concrete Tower
Steel Tower
Fiberglass Reinforced|
Plastic Tower
2000
4000
7000
9000
11,000
13,000
15,000
17,000
18,000
22,000
25,000
28,000
29,000
31,000
34,000
36,000
45,000
47,000
56,000
63,000
67,000
73,000
79,000
94,000
102,000
112,000
146,000
157,000
204,000
$108,000
$216,000
$378,000
$486,000
$594,000
$702,000
$810,000
$918,000
$972,000
$1,148,400
$1,305,000
$1,461,600
$1,513,800
$1,618,200
$1,774,800
$1,879,200
$2,268,000
$2,368,800
$2,822,400
$3,175,200
$3,376,800
$3,679,200
$3,839,400
$4,568,400
$4,957,200
$5,443,200
$7,095,600
$7,347,600
$9,180,000
1) Includes installation at 80 percent
$121,000
$242,000
$423,000
$544,000
$665,000
$786,000
$907,000
$1,028,000
$1,089,000
$1,286,000
$1,462,000
$1,637,000
$1,695,000
$1,812,000
$1,988,000
$2,105,000
$2,540,000
$2,653,000
$3,161,000
$3,556,000
$3,782,000
$4,121,000
$4,300,000
$5,117,000
$5,552,000
$6,096,000
$7,947,000
$8,229,000
$10,282,000
of equipment cost for a
$151,000
$302,000
$529,000
$680,000
$832,000
$983,000
$1,134,000
$1,285,000
$1,361,000
$1,608,000
$1,827,000
$2,046,000
$2,119,000
$2,265,000
$2,485,000
$2,631,000
$3,175,000
$3,316,000
$3,951,000
$4,445,000
$4,728,000
$5,151,000
$5,375,000
$6,396,000
$6,940,000
$7,620,000
$9,934,000
$10,287,000
$12,852,000
delta of 10 degrees.
$146,000
$ 292,000
$510,000
$ 656,000
$ 802,000
$ 948,000
$1,094,000
$1,239,000
$1,312,000
$1,550,000
$1,762,000
$1,973,000
$2,044,000
$2,185,000
$2,396,000
$2,537,000
$3,062,000
$3,198,000
$3,810,000
$4,287,000
$4,559,000
$4,967,000
$5,183,000
$6,167,000
$6,692,000
$7,348,000
$9,579,000
$9,919,000
$12,393,000
$119,00(
$238,00(
$416,00(
$535,00(
$653,00(
$772,00(
$891,00(
$1,010,00(
$1,069,00(
$1,263,00(
$1,436,00(
$1,608,00(
$1,665,00(
$1,780,00(
$1,952,00(
$2,067,00(
$2,495,00(
$2,606,00(
$3,105,00(
$3,493,00(
$3,714,00(
$4,047,00(
$4,223,00(
$5,025,00(
$5,453,00(
$5,988,00(
$7,805,00(
$8,082,00(
$10,098,00(
2-29
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§ 316(b) TDD Chapter 2 for New Facilities
Costing Methodology
Using the estimated costs, EPA developed cost equations using a polynomial curve fitting function. Table 2-14 presents cost
equations for basic tower types built with different building materials and assuming a delta of 10 degrees. The cost equations
presented in Table 2-13 include installation costs. The "x" in the presented cost equations is for flow in gpm and the "y" is in
dollars.
Table 2-14. Capital Cost Equations of Cooling Towers without Special Environmental Impact
Mitigation Features (Delta 10 degrees)
Tower Type
Capital Cost Equation1
Correlation
Coefficient
Douglas Fir
Redwood
Steel
Concrete
Fiberglass Reinforced Plastic
y = -9E-llx3 - 8E-06x2 + 50.395x + 44058
y = -lE-lOx3 - 9E-06x2 + 56.453x + 49125
y = -lE-lOx3 - lE-05x2 + 68.039x + 59511
y = -lE-lOx3 - lE-05x2 + 70.552x + 61609
y = -lE-lOx3 - 9E-06x2 + 55.432x + 48575
R2 = 0.9997
R2 = 0.9997
R2 = 0.9997
R2 = 0.9997
R2 = 0.9997
1) x is for flow in gpm and y is cost in dollars.
Using the cost comparison information published by Mirskyetal. (1992), EPA calculated the costs of cooling towers with various
additional features. These costs are presented in Table 2-15. Table 2-15 presents capital costs of the Douglas Fir Tower with
various features. The costs for other types of cooling towers were calculated in a similar manner.
Table 2-16 presents cost equations for Douglas fir cooling towers with special environmental mitigation features, built with
different building materials and assuming a delta of 10 degrees. The cost equations presented in Table 2-16 include installation
costs. The "x" in the presented cost equations is for flow in gpm and the "y" is in dollars. The final costs were based on cost
curves constructed for redwood splash fill towers. Costs and cost equations for Douglas fir towers are listed here as an example
of how cost equation curves were developed, although these are not the costs used to develop the facility costs.
At the end of this chapter, cost curves with equations are also presented for other types of cooling towers.
2-30
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§ 316(b) TDD Chapter 2 for New Facilities
Costing Methodology
Table 2-15: Capital Costs of Douglas Fir Cooling Towers with Special Environmental Impact Mitigation Features
(Delta 10 degrees ) (1999 Dollars)
Flow Douglas Fir Cooling
(gpm) Tower
Splash Fill Non-fouling Film Fill
Noise Reduction 10
dBA
Dry/wet
Hybrid Tower
(32DBT Plume
Abatement)
2000
4000
7000
9000
11,000
13,000
15,000
17,000
18,000
22,000
25,000
28,000
29,000
31,000
34,000
36,000
45,000
47,000
56,000
63,000
67,000
73,000
79,000
94,000
102,000
112,000
146,000
157,000
204,000
$108,000
$216,000
$378,000
$486,000
$594,000
$702,000
$810,000
$918,000
$972,000
$1,148,400
$1,305,000
$1,461,600
$1,513,800
$1,618,200
$1,774,800
$1,879,200
$2,268,000
$2,368,800
$2,822,400
$3,175,200
$3,376,800
$3,679,200
$3,839,400
$4,568,400
$4,957,200
$5,443,200
$7,095,600
$7,347,600
$9,180,000
$130,000
$259,000
$454,000
$583,000
$713,000
$842,000
$972,000
$1,102,000
$1,166,000
$1,378,000
$1,566,000
$1,754,000
$1,817,000
$1,942,000
$2,130,000
$2,255,000
$2,722,000
$2,843,000
$3,387,000
$3,810,000
$4,052,000
$4,415,000
$4,607,000
$5,482,000
$5,949,000
$6,532,000
$8,515,000
$8,817,000
$11,016,000
$119,000
$238,000
$416,000
$535,000
$653,000
$772,000
$891,000
$1,010,000
$1,069,000
$1,263,000
$1,436,000
$1,608,000
$1,665,000
$1,780,000
$1,952,000
$2,067,000
$2,495,000
$2,606,000
$3,105,000
$3,493,000
$3,714,000
$4,047,000
$4,223,000
$5,025,000
$5,453,000
$5,988,000
$7,805,000
$8,082,000
$10,098,000
$140,000
$281,000
$491,000
$632,000
$772,000
$913,000
$1,053,000
$1,193,000
$1,264,000
$1,493,000
$1,697,000
$1,900,000
$1,968,000
$2,104,000
$2,307,000
$2,443,000
$2,948,000
$3,079,000
$3,669,000
$4,128,000
$4,390,000
$4,783,000
$4,991,000
$5,939,000
$6,444,000
$7,076,000
$9,224,000
$9,552,000
$11,934,000
$405,000
$810,000
$1,418,000
$1,823,000
$2,228,000
$2,633,000
$3,038,000
$3,443,000
$3,645,000
$4,307,000
$4,894,000
$5,481,000
$5,677,000
$6,068,000
$6,656,000
$7,047,000
$8,505,000
$8,883,000
$10,584,000
$11,907,000
$12,663,000
$13,797,000
$14,398,000
$17,132,000
$18,590,000
$20,412,000
$26,609,000
$27,554,000
$34,425,000
$324,000
$648,000
$1,134,000
$1,458,000
$1,782,000
$2,106,000
$2,430,000
$2,754,000
$2,916,000
$3,445,000
$3,915,000
$4,385,000
$4,541,000
$4,855,000
$5,324,000
$5,638,000
$6,804,000,
$7,106,OOC
$8,467,OOC
$9,526,OOC
$10,130,000
$11,038,000
$11,518,000
$13,705,000
$14,872,000
$16,330,000
$21,287,000
$22,043,000
$27,540,000
2-31
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§ 316(b) TDD Chapter 2 for New Facilities
Costing Methodology
Table 2-16. Capital Cost Equations of Douglas Fir Cooling Towers with Special Environmental
Impact Mitigation Features (Delta 10 degrees)
Tower Type
Capital Cost Equation1
Correlation
Coefficient
Douglas Fir
Splash Fill
Non-fouling Film Fill
Noise Reduction 10 dBA
Dry/Wet
Hybrid Tower (Plume Abatement
32DBT)
1) x is flow in gpm and y is cost in dollars.
y = -9E-llx3 - 8E-06x2 + 50.395x + 44058
y = -4E-05x2 + 62.744x + 22836
y = -lE-lOx3 - 9E-06x2 + 55.432x + 48575
y = -lE-lOx3 - lE-05x2 + 65.517x + 57246
y = -O.OOOlx2 + 196.07x + 71424
y = -3E-10x3 - 2E-05x2 + 151.18x + 132225
R2 = 0.9997
R2 = 0.9996
R2 = 0.9997
R2 = 0.9997
R2 = 0.9996
R2 = 0.9997
Validation of Cooling Tower Capital Cost Equations
To validate the cooling tower capital cost curves and equations, EPA compared the costs predicted by the cooling tower capital
cost equations to actual costs for cooling tower construction projects provided by cooling tower vendors. 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 (forpurposes of comparison, EPA compared these last two towers to predicted costs
for redwood towers). In some cases, the project costs did 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 at the end of this chapter compares actual capital costs for wet cooling tower projects against predicted costs fromEPA' 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 deltas different
than the 10 °F used for EPA's cost curves.
Operation and Maintenance (O&M) Cost of Cooling Towers
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.
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§ 316(b) TDD Chapter 2 for New Facilities Costing Methodology
For example, if make-up water is obtained from a lesser quality source, additional treatment may be required to prevent biofcuring
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 used three scenarios at proposal, as
documented in the Economic and Engineering Analyses of the Proposed §316(b) New Facility Rule (EEA). The first scenario
is based 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. The second scenario is based on the facility using
gray water (treated municipal wastewater) for makeup water and disposing of the blow down water into a POTW sewer line
at a combined cost of $3/1000 gallons. The third scenario is based on the facility using municipal sources for clean makeup
water and disposing of the blowdown water into a POTW sewer line at a combined cost of $4/1000 gallons. For the final
§316(b) New Facility Rule, EPA based all cooling tower O&M costs on Scenario 1 (use of surface water sources for makeup
water and disposal of blowdown water either to a pond or back to the surface water source).
• 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 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, as documented in the proposal EEA. In preparing O&M cost
estimates for the final rule, EPA discovered an error in how the costs for major maintenance were calculated in the proposal EEA.
In the proposal EEA, these costs were calculated as annual costs following the years that they were to occur. However, some of
these costs actually represent one-time costs. This calculation error caused the O&M cost estimates in the proposal EEA to be
in error on the high side. EPA's total O&M cost estimates in the proposal EEA were (for Douglas fir cooling towers, for example)
about 25-30 percent of the cooling tower capital cost. EPA's revised calculations indicate that the correct value for total O&M
costs should be about 50 percent lower. EPA updated the O&M cost curves for the first scenario for the redwood towers which
were used in developing cost estimates for the final rule, and for the concrete towers which were used in the sensitivity analysis
for the final rule cost estimates. The updated equations and costs are shown in Tables 2-17 through 2-20 for the first scenario for
redwood towers with various features. Updated cost curves and equations for O&M costs for redwood and concrete cooling
towers are also presented at the end of the chapter. O&M cost curves and equations contained in the EEA for other types of towers
and for the other scenarios would need to be updated in a similar manner before being used to develop cost estimates.
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.
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§ 316(b) TDD Chapter 2 for New Facilities
Costing Methodology
Table 2-17. Total Annual O&M Cost Equations for Redwood Towers - 1st Scenario
Cooling Tower Material Type
Total Annual O&M Cost Equations1
Correlation Coefficient
Redwood y =-4E-06x2 + 10.617x +2055.2
1) x is flow in gpm and y is annual O&M cost in dollars.
R2 =0.9999
Table 2-18. Total
for Redwood Towers
Estimated Annual O&M Costs
- 1st Scenario (1999 Dollars)
Flow
(gpm)
Redwood Tower
2000
4000
7000
9000
11,000
13,000
15,000
17,000
18,000
22,000
25,000
28,000
29,000
31,000
34,000
36,000
45,000
47,000
56,000
63,000
67,000
73,000
79,000
94,000
102,000
112,000
146,000
157,000
204,000
$22,000
$43,000
$76,000
$97,000
$119,000
$140,000
$162,000
$184,000
$194,000
$234,000
$265,000
$297,000
$308,000
$329,000
$361,000
$382,000
$469,000
$490,000
$584,000
$657,000
$699,000
$761,000
$809,000
$963,000
$1,045,000
$1,147,000
$1,496,000
$1,580,000
$2,015,000
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§ 316(b) TDD Chapter 2 for New Facilities
Costing Methodology
Table 2-19. Total Annual O&M Cost Equations - 1st scenario
for Redwood Towers with Environmental Mitigation Features1
Type of Tower
O&M Cost Equations2
Correlation
Coefficient
Non-Fouling Film Fill tower
Noise reduction (lOdBA)
Hybrid tower (Plume Abatement 32DBT)
Splash Fill tower
Dry/wet tower
y =-4E-06x2 + 11.163x + 2053.7
y = -5E-06x2 + 12.235x + 2512.5
y = -lE-05x2 + 21.36x + 5801.6
y = -4E-06x2 + 11.163x + 2053.7
y = -lE-05x2 + 25.385x + 7328.1
R2 = 0.9999
R2 = 0.9999
R2 = 0.9998
R2 = 0.9999
R2 = 0.9998
1) Features include non-fouling film, noise reduction, plume abatement, or splash fill
2) x is flow in gpm and y is annual O&M cost in dollars.
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§ 316(b) TDD Chapter 2 for New Facilities
Costing Methodology
Table 2-20. Total Estimated Annual O&M Costs -
for Redwood with Environmental Mitigation Features
1st scenario
(1999 Dollars)
Flows
(gpm)
Splash Fill Tower
Non-Fouling Film
Fill Tower
Hybrid Tower (Plume abatement
(32DBT
Dry/Wet Tower
Noise Reduction
(IQdBA)
2000
4000
7000
9000
11,000
13,000
15,000
17,000
18,000
22,000
25,000
28,000
29,000
31,000
34,000
36,000
45,000
47,000
56,000
63,000
67,000
73,000
79,000
94,000
102,000
112,000
146,000
157,000
204,000
$24,000
$47,000
$83,000
$106,000
$130,000
$153,000
$177,000
$201,000
$212,000
$256,000
$290,000
$325,000
$337,000
$360,000
$395,000
$418,000
$514,000
$537,000
$640,000
$720,000
$766,000
$834,000
$888,000
$1,057,000
$1,147,000
$1,259,000
$1,642,000
$1,737,000
$2,219,000
$23,000
$45,000
$79,000
$102,000
$125,000
$148,000
$170,000
$193,000
$204,000
$245,000
$279,000
$312,000
$323,000
$346,000
$379,000
$402,000
$493,000
$515,000
$613,000
$690,000
$733,000
$799,000
$849,000
$1,010,000
$1,096,000
$1,203,000
$1,569,000
$1,655,000
$2,109,000
$44,000
$88,000
$153,000
$197,000
$241,000
$284,000
$328,000
$372,000
$394,000
$469,000
$533,000
$597,000
$619,000
$661,000
$725,000
$768,000
$935,000
$977,000
$1,164,000
$1,309,000
$1,392,000
$1,517,000
$1,598,000
$1,901,000
$2,063,000
$2,265,000
$2,953,000
$3,088,000
$3,900,000
$25,000
$50,000
$87,000
$112,000
$137,000
$162,000
$187,000
$212,000
$224,000
$269,000
$306,000
$342,000
$354,000
$379,000
$416,000
$440,000
$539,000
$563,000
$671,000
$755,000
$803,000
$875,000
$928,000
$1,104,000
$1,198,000
$1,315,000
$1,714,000
$1,806,000
$2,298,000
$52,000
$104,000
$182,000
$234,000
$286,000
$339,000
$391,000
$443,000
$469,000
$558,000
$634,000
$710,000
$735,000
$786,000
$862,000
$913,000
$1,110,000
$1,159,000
$1,381,000
$1,554,000
$1,652,000
$1,800,000
$1,893,000
$2,253,000
$2,445,000
$2,684,000
$3,499,000
$3,654,000
$4,607,0001
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§ 316(b) TDD Chapter 2 for New Facilities Costing Methodology
Variable speed pumps
For a power plant operating at near constant power output (e.g., at or near capacity), the amount of heat rejected through the
cooling system will also remain nearly constant regardless of changes in ambient conditions. In cooling systems where heat from
steam condensation is transferred to cooling water (i.e., those that use surface condensers), the amount of heat rejected can be
measured as the product of the cooling water flow rate times the difference in temperature of the cooling water between the
condenser inlet and outlet. If the cooling water flow rate remains constant, then the temperature difference will also remain
relatively constant regardless of changes in the inlet temperature. Therefore, a decrease in the cooling water temperature at the
condenser inlet will result in a similar decrease in the condenser outlet temperature and a corresponding decrease in the
temperature of the condenser surface where steam is condensed.
As described in Chapter 3 on the energy penalty, a decrease in condenser temperatures will produce a decrease in the turbine
exhaust, which can result in an increase in the turbine efficiency. Thus, seasonal changes in ambient source water temperature will
result in changes in the condenser temperatures, which can affect the steam turbine efficiency. However, as the ambient and
condenser temperatures progressively drop, the system performance can approach a point where turbine efficiency no longer
increases and may begin to decrease. In addition, significantly reduced turbine exhaust pressures can result in condensed moisture
within the turbine, which can damage turbine blades and further reduce turbine efficiency. Thus, progressive reductions in the
cooling water temperature in a cooling system operating at a constant cooling water flow rate may approach a point where
continued reduction in ambient temperatures results in detrimental or less than optimal operating conditions. The ambient
conditions at which this begins to occur will be dependent on the cooling and turbine system design, which is often subject to site-
specific and economic considerations.
In a once-through cooling system, one method of controlling the steam condenser temperature is to control the cooling water flow
rate. If the heat rejection rate remains relatively constant (near constant plant output), a reduction in the cooling water flow rate
will result in an increase in the difference in temperature of the cooling water between the condenser inlet and outlet (referred to
as the "range"). An increase in the range will result in an increase in the temperature of the steam condensing surface. Therefore,
through careful control of the cooling water flow rate, the condenser temperature can be controlled such that the power plant
turbine performance does not degrade and damaging conditions are avoided. Thus, the ability to reduce cooling water flow rate
can provide for improved plant operation as well as reducing the environmental impacts of cooling water withdrawals from surface
waters.
Use of variable speed pumps is an efficient method for attaining control of the cooling water flow rate and thus the condenser
performance. Variable frequency drives are used to vary the pump speed, which in turn allows the flow rate to be adjusted through
a range from zero to its maximum output.
There are some limitations on the range of flow rates that can be used. Most once-through cooling systems discharge to surface
waters under an NPDES permit, which often includes discharge limits on both the maximum temperature (a concern during the
warmer months) and the temperature increase of the discharge over the intake temperature (a concern if flow rates are adjusted).
Exceedence of the maximum temperature limit can be avoided by operating at the maximum cooling water flow rate and, when
necessary, reducing the plant output (i.e., the heat rejection rate). The limit on temperature increase may create an effective lower
limit on the cooling water flow rate (at a given heat rejection rate) in the sense that further reduction in cooling water flow rate
would result in a temperature rise that exceeded the NPDES temperature increase limitation. These constraints, however, do not
prevent varying the cooling water flow rate; rather, they set the range in flow rates (for a given plant power output level) over
which the system may operate. Note that varying the cooling water flow rate does not change the amount of heat being discharged.
Rather, it only affects the "concentration" of the heat. Limitation of the temperature increase is intended to reduce detrimental
impacts on entrained organisms, as well as on those in the mixing zone downstream.
EPA chose to include the cost of variable frequency drives as part of the pump costs for the post-compliance cost estimates for
all once-though systems and for wet tower system intakes. While condenser performance is not affected by using variable speed
pumps in the wet tower make-up water intake, EPA included them to provide greater process control. For the baseline system
costs to which post-compliance costs are compared, EPA used the costs for constant speed pumps even though facilities may
2-37
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§ 316(b) TDD Chapter 2 for New Facilities
Costing Methodology
install variable speed pumps regardless of the rule's implementation. EPA chose this approach as a means for generating a
conservative (on the high side) compliance cost estimate.
A recent evaluation of the equipment cost for variable speed pumps indicates that EPA may have underestimated the cost for the
variable frequency drive component of the pumping system. Recent investigation of estimated costs for VFDs from other sources
indicates that the unit cost of $100/Hp obtained from the original contact is lower than estimates from these other sources. EPA
has re-evaluated the costs for addition of VFDs using data from these other sources. See DCN 3-3038. EPA finds that the
contribution to capital cost fromthe uncertainty of variable speed drive costs is not appreciable forthe final annualized compliance
costs of the effected facilities. Analogous to the sensitivity analysis performed on the material of construction of the cooling
towers of coal-fired plants (i.e., concrete vs. redwood), the percentage of capital cost due to the uncertainty, when amortized over
the appropriate period would not significantly influence total annualized compliance costs.
Pump Equipment Cost Development
The distinction between constant and variable speed pumping systems is the presence of variable frequency drives (VFD). A
pump supplier estimated that the unit cost of the variable frequency drives was approximately $100/Hp (Flory 2001). This unit
cost is consistent with the cost of a VFD of $20,000 to $30,000 cited for a 200 Hp fan for an air cooled condenser (Tallon 2001).
Table 2-21 provides a summary of the data that EPA used to develop the equipment costs for constant speed and variable speed
pumps.
Table 2-21: Pump Cost Data (Source: Flory 2001) |
Flow
(gpm)
5,000
50,000
250,000
Brake-Hp at
50 ft Pumping Head1
90
902
3,606
Pump and Motor with
Freight and Tax2
$23,000
$115,000
$402,500
Variable Frequency
Drive
$9,015
$90,150
$360,600
Total with Variable
Frequency Drive |
$32,015 1
$205,150 1
$763,100 1
1 Based on flow and a pumping head of 50 ft.
2 Includes 15 percent for cost of freight and tax.
EPA also included pump installation costs, with the value scaled from 60 percent of equipment costs at 500 gpm to 40 percent
at 350,000 gpm.
Table 2-22 presents cost equations for estimating capital costs for variable speed pumps. Cost curves and equations for
variable speed pumps are also presented at the end of this chapter.
Table 2-22. Capital Cost Equations for Constant Speed and Variable Speed Pumps
Pump Type
Capital Cost Equation1
Correlation Coefficient
Constant Speed y = 1.6859x + 13369
Variable Speed y = 3.1667x + 16667
1) x is flow in gpm and y is cost in dollars.
R2 = 0.9998
R2=l
2-38
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§ 316(b) TDD Chapter 2 for New Facilities Costing Methodology
Using non-surface water sources
A facility may be able to obtain some of its cooling water from a source other than the surface water it is using (WWTP gray
water, ground water, or municipal water supply) and thereby reduce the volume of its withdrawals from the surface water and
meet the percent of flow requirements. Some facilities may only need to use this alternate source during low flow periods in
the surface water source. To use this option, a facility would need to build a pond or basin for the supplemental cooling
water.
A facility using gray water may need to install some water treatment equipment (e.g., sedimentation, filtration) to ensure that
its discharge of the combined source water and gray water meets any applicable effluent limits. For costing purposes, EPA
has assumed that a facility would only need to install treatment for gray water in situations where treatment would have been
required for river intake water. Therefore, no additional (i.e., "new") costs are incurred for treatment of gray water after
intake or before discharge.
See the end of this chapter for cost curves and equations for estimating gray water and municipal water costs.
2.9.2 Reducing Design Intake Velocity
Passive screens
Passive screens, typically made of wedge wire, are screens that use little or no mechanical activity to prevent debris and
aquatic organisms from entering a cooling water intake. The screens reduce impingement and entrainment by using a small
mesh size for the wedge wire and a low through-slot velocity that is quickly dissipated. The main components of a passive
screening system are typically the screen(s), framing, an air backwash system if needed, and possibly guide rails depending on
the installation location.
Passive screens vary in shape and form and include flat panels, curved panels, tee screens, vee screens, and cylinder screens.
Screen dimensions (width and depth) vary; they are generally made to order with sizing as required by site conditions. Panels
can be of any size, while cylinders are generally in the 12" to 96" diameter range. The main advantages of passive intake
systems are:
• They are fish-friendly due to low slot velocities (peak <0.5 fps), and
• They have no moving parts and thus minimal O&M costs.
New passive intake screens have higher capacity (due to higher screen efficiency) than older versions of passive screens.
Wedge wire screens are effective in reducing impingement and entrainment as long as a sufficiently small screen slot size is
used and ambient currents have enough velocity to move aquatic organisms around the screen and flush debris away.
The key parameters and additional features that are considered in estimating the cost of passive/wedge wire screening systems
on CWIS are:
• Size of screen and flow rate (i.e., volume of water used),
• Size of screen slots/openings,
• Screen material,
• Water depth,
• Water quality (debris, biological growth, salinity), and
• Air backwash systems.
The size and material of a screen most affect cost. Branched intakes, with a screen on each branch, can be used for large
flows. Screen slot size also impacts the size of a screen. A smaller slot opening will result in a larger screen being required to
keep the peak slot velocity under 0.5 fps.
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§ 316(b) TDD Chapter 2 for New Facilities Costing Methodology
Site-specific conditions significantly affect costs of the screen(s). The water depth affects equipment and installation costs
because structural reinforcement is required as depth increases, air backwash system capacities need to be increased due to the
reduced air volume at greater depths, and installation is generally more difficult. The potential for clogging from debris and
fouling from biogrowth are water quality concerns that affect costs. The amount and type of debris influence the size of
openings in the screen, which affects water flow through the screen and thus screen size. Finer debris may require a smaller
slot opening to prevent debris from entering and clogging the openings.
Generally, speed and flow of water do not affect the installation cost or the operation of passive intakes, however there must
be adequate current in the source water to carry away debris that is backwashed from the screen so that it does not become
(re)clogged. It is recommended as good engineering practice that the axis of the screen cylinder be oriented parallel with the
water flow to minimize fish entrainment and to aid in removal of debris during air backwash. The effects of the presence of
sensitive species or certain types of species affect the design of the screen and may increase screen cost. For example, the
lesser strength of a local species could result in the need for a peak velocity less than 0.5 fps which would result in a larger
screen. Biofouling from the attachment of zebra mussels and barnacles and the growth of algae may necessitate the use of a
special screen material, periodic flushing with biocides, and in limited cases, manual cleaning by divers. For example, the
presence of zebra mussels often requires the use of a special alloy material to prevent attachment to the screen assembly.
The level of debris in the water also affects whether an air backwash system is needed and how often it is used. Heavy debris
loadings may dictate the need for more frequent air backwashing. If the air backwash frequency is high enough, a larger
compressor may be required to recharge the accumulator tank more quickly.
Another water quality factor that affects screen cost is water corrosiveness (e.g., whether the intake water is seawater,
freshwater, or brackish). Most passive screens are manufactured in either 304 or 316 stainless steel for freshwater
installations. The 316L stainless steel can be used for some saltwater installations, but has limited life. Screens made of
copper-nickel alloys (70/30 or 90/10) have shown excellent corrosion resistance in saltwater, however they are significantly
more expensive than stainless steel (50 percent to 100 percent greater in cost, i.e., can be double the cost).
Capital Costs
EPA assumed that the capital cost of passive screens will be 60 percent of the capital cost of a basic traveling screen of
similar size. This assumption is based on discussions with industry representatives. The lower capital cost is because passive
screen systems have lower onshore site preparation and installation costs (no extensive mechanical equipment as in the
traveling screens) and are easier to install in offshore situations. The estimated capital costs for passive screens are shown in
Table 2-23, corresponding to the flows shown in Table 2-31 for a through screen velocity of 0.5 fps. Passive screens for sizes
larger than those shown in Table 2-23 will generate flows higher than 50,000 gpm. For flows greater than 50,000 gpm,
particularly when water is drawn in from a river, the size of the CWIS site becomes very big and the necessary network
fanning for intake points and screens generally makes passive screen systems unfeasible.
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§ 316(b) TDD Chapter 2 for New Facilities
Costing Methodology
Table 2-23 Estimated Capital Costs for a Through Flow Passive Water Screen
Stainless Steel 304 - Standard Design1 (1999 Dollars)
Well Depth
(ft)
10
25
50
75
100
Screen Panel Width (ft)
2
$34
$49
$74
$99
$135
,200
,800
,400
,000
,600
5
$56,100
$84,900
$122,700
(2)
(2)
10
$91,800
$140,400
(2)
(2)
(2)
14
$128,700
(2)
(2)
(2)
(2)
1) Cost estimate includes stainless steel 304 structure.
2) Not estimated because passive screen systems of this size are not feasible.
As noted above, the capital costs for special screen materials (e.g., copper-nickel alloys) are typically 50 percent to 100
percent higher.
Table 2-24 presents cost equations for estimating capital costs for passive screens. The "x" in the equation represents the
flow volume in gpm and the "y" value is the passive screen total capital cost. Cost equations associated with a flow of 1 fps
are provided for comparative purposes.
Screen
Width
(ft)
Passive Screens Velocity
Equation1
0.5 ft/sec
Correlation
Coefficient
Passive Screens Velocity Ift/sec
Correlation
Equation1 Coefficient
Table 2-24. Capital Cost Equations for Passive Screens
y = 3E-08x3-0.0008x2+12.535x+ R2 = 0.9991 y = 5E-09x3 - 0.0002x2 + 6.550Ix R2 = 0.9991
11263
5 y = 0.0002x2+1.5923x +47041 R2 = 1
10 y = 3.7385x +58154 R2 = 1
1) x is the flow in gpm y is the capital cost in dollars.
+ 9792.6
y = 4E-05x2 + 1.0565x + 43564
y=1.8x +59400
See the end of this chapter for cost curves and equations.
Operation and Maintenance (O&M) Costs for Passive Screens
Generally, there are no appreciable O&M costs for passive screens unless there are biofouling problems or zebra mussels in
the environment. Biofouling problems can be remedied through the proper choice of materials and periodic mechanical
cleaning. Screens equipped with air backwash systems require periodic compressor/motor/valve maintenance. Therefore,
EPA has estimated zero O&M costs for passive screens.
2-41
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§ 316(b) TDD Chapter 2 for New Facilities
Costing Methodology
Velocity Caps
The cost driver of velocity caps is the installation cost. Installation is carried out underwater where the water intake mouth is
modified to fit the velocity cap over the intake. EPA estimated capital costs for velocity caps based on the following
assumptions:
• Four velocity caps can be installed in a day,
• Cost of the installation crew is similar to the cost of the water screen installation crew (see Box 2-1),
• To account for the difficulty in installing in deep water, an additional work day is assumed for every increase in
depth size category, and
• Equipment cost for a velocity cap is assumed to be 25 percent of the velocity cap installation cost. In our BPJ, this is
a conservatively high estimate of the cost of velocity cap material and delivery to the installation site.
Based on these assumptions, EPA calculated estimated costs for velocity caps, which are shown in Tables 2-25 and 2-26.
EPA calculated the number of velocity caps needed for various flow sizes based on a flow velocity of 0.5ft/sec and assuming
that the intake area to be covered by the velocity cap is 20 ft2 which is the area comparable to a pipe diameter of about 5 feet.
For flows requiring pipes larger than this, EPA assumed, for velocity cap costing purposes, that multiple intake pipes with a
standard, easy-to-handle pipe diameter will be used rather than larger-diameter, custom made pipes (based on BPJ). Cost
curves and equations are at the end of the chapter.
Table 2-25. Estimated Velocity
Flow (gpm)
(No. of velocity caps)
Up to 18,000
1 8,000 < flow
35,000
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§ 316(b) TDD Chapter 2 for New Facilities
Costing Methodology
Table 2-26. Estimated Velocity Cap Equipment and Installation Costs 1
(1999 Dollars) |
Flow (gpm)
(No. of velocity caps)
Water Depth (ft)
8 20 30 50
65 |
Up to 18,000
(4VC)
18,000 < flow <35,000
(9VC)
35,000
-------
§ 316(b) TDD Chapter 2 for New Facilities Costing Methodology
water body. The MLES system is designed to allow a through-fabric velocity of approximately 0.01 to 0.05 feet/second (fps),
yielding an average velocity of approximately 0.02 fps. The system may be designed for lower or higher flows, as needed.
The Gunderboom is enhanced by an automated "Air Burst" cleaning system. This system uses periodic bursts of air between
the two fabric layers to free any organisms or debris caught against the filter curtain.
Based on information provided by the manufacturer, the main advantages of the MLES system are:
The system has been demonstrated to reduce entrainment by at least 80 percent. According to Gunderboom, the
MLES can produce up to 100 percent exclusion for many applications.
The Gunderboom fabric consists of a minute fiber matting with an Apparent Opening Size (AOS) of approximately
20 microns. As such, the system has been shown to significantly reduce turbidity, suspended solids, coliform
bacteria, and other paniculate-associated contaminants. For MLES systems, perforations ranging in diameter from
0.4 mm to 3.0 mm or more are added to increase the flow of water through the fabric. Perforation size can be
customized to prevent entrainment of the specific eggs or fish larvae that are present at the installation site.
The double fabric layer system with an "Air Burst" Technology cleaning system reduces overall O&M costs. Since
debris and sediment are excluded, the Gunderboom may also help reduce O&M costs for intake screens, condensers
and other parts of the cooling water system.
Once the anchoring and "Air Burst" Technology have been installed, deployment of the MLES can be achieved in
two to three weeks, barring logistics or weather problems, and requires no or minimal plant shutdown.
Gunderbooms are designed and engineered for the specific site at which they are to be installed. The designs may include
plant intakes, floating walkways, pile-supported structures, concrete submerged structures, removable panels and solid frames.
However, and in general, the key parameters that may have a significant impact on estimating the cost of the Gunderboom
system are:
CWIS flow rates,
Physical factors of the water body and facility intake structure,
Target species and life stages,
Water body characteristics, including elevation changes, currents, wind-induced wave action and suspended
sediment concentrations,
Degree of automation, and
Water quality
Factors such as the CWIS flow rates and physical factors of the water body and intake structure affect the capital cost because
they determine the required size of the Gunderboom filter curtain. Other factors such as water quality and degree of
automation contribute to greater O&M costs.
Installation
The Gunderboom MLES installation cost is largely a function of site conditions. Strong current flow, winds, wave action, and
low accessibility can make installation more difficult. However, for the purpose of developing national cost estimates, EPA
did not consider abnormal conditions in developing its cost equations and cost curves.
Capital Costs
EPA estimated capital costs of the MLES system based on information submitted by representatives of Gunderboom, Inc.
Low and high capital cost estimates were provided for flows of 10,000, 104,000, and 347,000 gpm. EPA then calculated
average capital costs as shown in Table 2-28. For purposes of estimating costs, EPA assumed that a simple floating
configuration, as opposed to a rigid configuration, would be used.
2-44
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§ 316(b) TDD Chapter 2 for New Facilities
Costing Methodology
Table 2-28. Estimated Capital Costs for a Simple Floating Gunderboom Structure 1
Flow
(gpm)
10,000
104,000
347,000
Low Cost
$500,000
$1,800,000
$5,700,000
High Cost
$700,000
$2,500,000
$7,800,000
Average Cost |
$600,000 1
$2,150,000 1
$6,750,000 1
According to the manufacturers, the cost of a fixed system for a CWIS of 10,000 gpm capacity ranges between $0.7M and
$ 1. 5M while the cost of a complete independent system can be greater than $2M.
Operation and Maintenance (O&M) Costs
EPA also estimated O&M costs of the MLES system based on information submitted by representatives of Gunderboom, Inc.
Low and high O&M cost estimates were provided for flows of 10,000,104,000, and 347,000 gpm. EPA then calculated average
O&M costs as shown in Table 2-29. Again, a simple floating configuration was assumed.
Table 2-29. Estimated O&M Costs for a Simple Floating Gunderboom Structure 1
Flow
(gpm)
10,000
104,000
347,000
Low Cost
$100,000
$150,000
$500,000
High Cost
$300,000
$300,000
$700,000
Average Cost |
$200,000 1
$225,000 1
$600,000 1
EPA plotted the high, low and average capital as well as the average O&M costs, then fitted equations and curves to the data as
shown in Chart 2-30. In the cost equations, "x" represents the flow volume in gpm, and "y" represents the total capital or annual
O&M cost.
Branching the intake pipe to increase the number of openings or widening the intake pipe
Branching an intake pipe involves the use of fittings to attach the separate pipe sections. See the end of this chapter for costs
curves and equations.
2.9.3 Design and Construction Technologies to Reduce Damage from I&E
Installation of traveling screens with fish baskets
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.
2-45
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§ 316(b) TDD Chapter 2 for New Facilities
Costing Methodology
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 Bracket! 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 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
Well Depth
(ft)
10
25
50
75
100
2-30. Average
for
Water Depth
(ft)
8
20
30
50
65
Flow Through A
a Flow Velocity
Traveling Water Screen (gpm)
of 1.0 fps
Basket Panel Screening Width (ft) 1
2
4000
9000
13,000
22,000
29,000
5 10
9000 18,000
22,000 45,000
34,000 67,000
56,000 112,000
73,000 146,000
14 |
25,OOOJ
63,00ol
94,00ol
157,00ol
204,00o|
Table 2-31. Average Flow Through A Traveling Water Screen (gpm) for a Flow
Velocity of 0.5 fps
2000
4000
7000
11,000
15.000
4000
11,000
17,000
28,000
36,000
9000
22,000
34,000
56,000
73,000
13,000
31,000
47,000
79,000
102
Well Depth
(ft)
Water Depth
(ft)
Basket Screening Panel Width (ft)
2 5 10
10
25
50
75
100
2-46
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§ 316(b) TDD Chapter 2 for New Facilities
Costing Methodology
Capital Costs
Equipment Cost
Basic costs for screens with flows comparable to those shown in the above tables are presented in Tables 2-32 and 2-33.
Table 2-32 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.
Table 2-32. Estimated Equipment Cost for Traveling Water Screens Without Fish|
Handling Features1 (1999 Dollars)
Well Depth
(ft)
Basket Screening Panel Width (ft)
5 10
14
10 $30,000
25 $35,000
50 $55,000
75 $75,000
100 $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
Type 304 stainless mesh and intermittent operation components.
Source: Vendor estimates.
Table 2-33. 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.
2-47
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§ 316(b) TDD Chapter 2 for New Facilities
Costing Methodology
Installation Cost
Installation costs of traveling screens 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 2-34 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 2-35 presents the estimated costs of site preparation for
four sizes of screen widths and various well depths.
Table 2-34. Estimated Installation (Site Preparation) Costs for Traveling Water
Screens Installed at a 10-foot Well Depth (1999 Dollars)
Screen Clearing Clearing
Width and Cost1
(ft) Grabbing
(acre)
2 0.1
5 0.35
10 0.7
14 1
$250
$875
$1,750
$2,500
Earth
Work
(cy)
200
500
1000
1400
Earth Paving and
Work Surfacing
Cost1 Using
Concrete (sy)
$17
$43
$87
$121
,400
,500
,000
,800
18
40
75
150
Paving Structura Structural Total
Cost1 1 Cost Onshore
Concrete Construction
(cy) Costs
$250
$560
$1,050
$2,100
0
0
54
63
0.72
1
08
$680
$790
$900
$1,350
$19
$46
$91
$128
,000
,000
,000
,000
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).
2-4
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§ 316(b) TDD Chapter 2 for New Facilities
Costing Methodology
Table 2-35. Estimated Installation (Site Preparation, Construction, and Onshore Installation) 1
Costs for Traveling Water Screens of Various Well Depths (1999 Dollars) |
Well Depth
(ft)
10
25
50
75
100
Source: R.S. Means (1997b)
2
$19,000
$31,000
$43,000
$55,000
$67,000
and vendor estimates.
Screen Panel
5
$46,000
$75,000
$104,000
$132,000
$161,000
Width (ft)
10
$91,000
$148,000
$205,000
$262,000
$319,000
14 |
$128,000
$208,000
$288,000
$368,000
$448,000
1
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 2-35. 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 increase in well depth size and of one day
for every increase in screen width size.
2-49
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§ 316(b) TDD Chapter 2 for New Facilities Costing Methodology
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 NF 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).
Other Considerations:
Uncontrollable factors like weather, water temperature, water depth, underwater visibility, currents, and
distance to shore can affect the daily production of the dive team. These variables always have to be
considered when a job is quoted on a daily rate. Normally, the dive-company takes on the risks for these
variables because the job is quoted on a "to completion" status. These types of jobs usually take a week or
more for medium to large-size installations.
Total of Estimated Costs:
The final estimated total for this hypothetical job is nearly $4500 per day for personnel and equipment. For a
three-day job, this would total about $13,500. Adding to this amount about $3,500 for mobilization and
demobilization, the complete job is estimated at $17,000.
Note: Costs for a given project vary greatly depending on screen size, depth of water, and other site-specific
conditions such as climate and site accessibility.
2-50
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§ 316(b) TDD Chapter 2 for New Facilities
Costing Methodology
Table 2-36. 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|
$30,50C
$39,50C
$48,5001
$57,500
Table 2-37 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 2-37. Estimated Total Installation Costs for Traveling Water Screens1
(1999 Dollars)
Basket Screening Panel Width (ft)
5 10
Well Depth
(ft)
$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
$149,50
$238,50
$327,500
$416,500
$505,50
1) Includes site pre
tion. and onshore and underwater construction and installation costs.
Total Estimated Capital Costs
The installation costs in Table 2-37 were added to the equipment costs in Tables 2-32 and 2-33 to derive total equipment and
installation costs for traveling screens with and without fish handling features. These estimated costs are presented in Tables
2-38 and 2-39. 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 2-30 and 2-31 for flow velocities of 1.0 fps and 0.5 fps,
respectively.
2-51
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§ 316(b) TDD Chapter 2 for New Facilities
Costing Methodology
Table 2-38. Estimated Total Capital Costs for Traveling Screens Without
Handling Features (Equipment and Installation)1 (1999 Dollars)
Well Depth
(ft)
10
25
50
75
100
Screening Basket Panel Width (ft)
2 5 10
$57,000 $93,500 $153,000
$83,000 $141,500 $234,000
$124,000 $204,500 $345,000
$165,000 $271,500 $436,000
$226,000 $339,500 $527,000
Fish
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 2-39. 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
^^^^^^^^^^^^^^^^^^m
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 2-40 and 2-41 present equations that can be used to estimate costs for traveling screens at 0.5 fps and 1.0 fps,
respectively. See the end of this chapter for cost curves and equations.
Table 2-40. Capital Cost Equations for Traveling Screens for Velocity of 0.5 fps
Traveling Screens with Fish Handling
Screen
Width
(ft)
2
5
10
14
1) x is the
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
flow in gpm y is the capital cost
Correlation
Coefficient
R2 = 0.9992
R2 = 0.994
R2 = 0.9931
R2 = 0.995
in dollars.
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
Coefficient |
R2 = 0.9991 1
R2 = 0.9995
R2 = 0.9928
R2 = 0.9961
1
2-52
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§ 316(b) TDD Chapter 2 for New Facilities
Costing Methodology
Table 2-41. Capital Cost Equations for Traveling Screens for Velocity of 1 fps
Screen
Width
(ft)
Traveling Screens with Fish Handling
Equipment
Traveling Screens without Fish Handling
Equipment
Equation1
Correlation
Coefficient
Equation1
Correlation
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 2-32 and 2-33, 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 2-42 and 2-43 for flow velocities of 1.0 fps and 0.5 fps,
respectively.
Table 2-42. Estimated Annual O&M Costs for Traveling Water Screens
Without Fish Handling Features
(Carbon Steel - Standard Design)1 (1999 Dollars)
Well Depth
(ft)
Screen Panel Width (ft)
5 10
14
10
25
50
75
100
$4560
$5810
$8680
$11,550
$13,560
$6545
$9905
$12,270
$16,290
$16,975
$7650
$14,040
$17,250
$21,800
$26,350
$12,87^
$17,175
$23,625
$29,575
$35,275
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.
2-53
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§ 316(b) TDD Chapter 2 for New Facilities
Costing Methodology
Table 2-43. 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 2-44: Annual O&M Cost Equations for Traveling Screens Velocity 0.5 fps
Screen
Width
(ft)
Traveling Screens with Fish Handling
Equipment
Correlation
Equation1 Coefficient
Traveling Screens without Fish Handling
Equipment
Correlation
Equation1 Coefficient
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
R2 = 0.9943 y = -2E-05x2 + 1.0121x
2392.4
R2 = 0.9943 y = -7E-06x2 + 0.6204x
4045.7
R2 = 0.9907 y = 9E-1 lx3 - lE-05x2 +
0.8216x+1319.5
R2 = 0.9912 y = 8E-12x3 - 2E-06x2 +
0.3899x +7836.7
R2 = 0.9965
R2 = 0.9956
R2 = 0.9997
R2 = 0.9922
1) x is the flow in gpm and y is the annual O&M cost in dollars.
2-54
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§ 316(b) TDD Chapter 2 for New Facilities
Costing Methodology
Table 2-45. Annual O&M Cost Equations for Traveling Screens Velocity 1 fps
Correlation
Coefficient
y = -4E-06xz + 0.5035x + 2334 Rz = 0.9853
= -2E-06x2
3621.1
R2 = 0.9915
R2 = 0.9903
1) x is the flow in gpm and y is the annual O&M cost in dollars.
y=lE-llx3-3E-06x2
0.4047x+1359.4
y = 4E-13x3 - 3E-07x2
0.1715x +8472.1
Screen
Width
(ft)
Traveling Screens with Fish Handling
Equipment
Traveling Screens without Fish Handling
Equipment
Equation1
Correlation
Coefficient
10
14
y = -8E-06x2 + 0.806x + 3646.7 R2 = 0.982
y = -3E-06x2 + 0.4585x + R2 = 0.9954
5080.7
y = -6E-07x2 + 0.2895x +
5705.3
y = -3E-13x3 - 4E-08x2
0.2081x+11485
Adding fish baskets to existing traveling screens
Capital Costs
Table 2-46 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 2-32), plus a 20 percent add-on for upgrading existing equipment (mainly to convert traveling screens from
intermittent operation to continuous operation).9 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 2-46.
Estimated Capital
Costs of Fish Handling
Equipment (1999
Dollars) |
Basket Screening Panel Width (ft) |
Well Depth
(ft)
10
25
50
75
100
Source: Vendor estimates.
2
$40,200
$55,500
$81,000
$106,500
$132,000
5
$46,200
$63,000
$99,000
$132,000
$165,000
10
$58,800
$87,600
$135,600
$183,600
$231,600
14
$84,600
$131,400
$209,400
$287,400
$365,400
Installation of Fish Handling Features to Existing Traveling Screens
As stated earlier, the basic equipment cost of fish handling features (presented in Table 2-46) 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
9This 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.
2-55
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§ 316(b) TDD Chapter 2 for New Facilities
Costing Methodology
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 2-36) for a traveling screen (based on BPJ). Table 2-47
shows total estimated costs (equipment and installation) for adding fish handling equipment to an existing traveling screen.
Table 2-47. Estimated
Well Depth
(ft)
10
25
50
75
100
Capitol Costs of Fish Handling
Basket
2
$46,200
$68,250
$100,500
$132,750
$165,000
Equipment and
Screening Panel
5
$55,575
$79,125
$121,875
$161,625
$201,375
Installation1
Width (ft)
10
$71,550
$107,100
$161,850
$216,600
$271,350
(1999 Dollars) |
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 of fish 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 end of this
chapter for cost curves and equations.
2.10 ADDITIONAL COST CONSIDERATIONS
To account for other minor cost elements, EPA estimates that 5 percent may need to be added to the total cost for each
alteration. Minor cost elements include:
• Permanent buoys for shallow waters to warn fishing boats and other boats against dropping anchor over the pipes.
Temporary buoys and warning signs during construction.
• Additional permit costs. Permit costs may increase because of the trenching and dredging for pipe installation.
• Facility replanning/redesign costs may be incurred if the facility is far enough along in the facility planning and
development process. This cost would likely be minimal to negligible for most of the alterations discussed above,
but could be much higher for switching a facility to a recirculating cooling system.
• Monitoring costs (e.g., to test for contaminated sediments).
As noted earlier, if the intake structure installation involves disturbance of contaminated sediments, the permitting authority
may require special construction procedures, including hauling the sediments to an appropriate disposal facility offsite. This
may increase the cost of the project by more than two to three times the original cost estimate.
2-56
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§ 316(b) TDD Chapter 2 for New Facilities Costing Methodology
REFERENCES
In addition to the references listed below, EPA recognizes contributions from the following individuals and organizations:
Russel Bellman and Brian Julius, Acting Chief, Gulf Coast Branch NOAA Damage Assessment Center, Silver Spring, MD, of
the National Oceanic and Atmospheric Administration; Adnan Alsaffar, Arman Sanver, and John Gantnier, Bechtel Power
Corporation, Fredrick, MD; Gary R. Mirsky Vice President, Hamon Cooling Towers, Somerville, NJ; Jim Prillaman,
Prillaman Cooling Towers, Richmond, VA; Ken Campbell GEA Power Systems, Denver, CO and David Sanderlin, GEA
Power Systems, San Diego, CA; Michael D. Quick, Manager - Marketing / Communications, U.S. Filter - Envirex Products,
Waukesha, WI; Trent T. Gathright, Fish Handling Band Screen Specialist, Marketing Manager, Brackett Geiger USA, Inc.,
Houston, TX; Richard J. Sommers, U.S. Filter Intake Systems, Chalfont, PA; Ken McKay, VP Sales/Marketing, USF Intake
Products; and Larry Sloan, District Representative, Sloan Equipment Sales Co.,Inc., Owings Mills, MD.
Anderson, R. 2000. Personal communication (February, and March) between Roland Anderson, Price Brothers, 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.
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 EPRFs 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
EPRFs 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.
2-57
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§ 316(b) TDD Chapter 2 for New Facilities Costing Methodology
Federal Energy Regulatory Commission (FERC). 1995. Preliminary Assessment of Fish Entrainment at Hydropower
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 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., et al. 1992. The Latest 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 EPRI1997 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.
2-58
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§ 316(b) TDD Chapter 2 for New Facilities Costing Methodology
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.
SAIC. 1996. Supplement to Background Paper 3: Cooling Water Intake Technologies. Prepared by SAICforU.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. Geiger Fipro - 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 and Nonutilities. 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.
2-59
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§ 316(b) TDD Chapter 2 for New Facilities
Costing Methodology
LIST OF COST CURVES AND EQUATIONS
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
2-60
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§ 316(b) TDD Chapter 2 for New Facilities
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)
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
2-61
-------
§ 316(b) TDD Chapter 2 for New Facilities
Costing Methodology
$40,000,000
$35,000,000
Chart 2-2. Douglas Fir Cooling Tower Capital Costs with Various Features
(Delta 10 Degrees)
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
y = -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
2-62
-------
§ 316(b) TDD Chapter 2 for New Facilities
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)
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
2-63
-------
§ 316(b) TDD Chapter 2 for New Facilities
Costing Methodology
Chart 2-4. Concrete Cooling Tower Capital Costs with Various Features
(Delta 10 Degrees)
$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
R2 = 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
R2 = 0.9996
y = -5E-05x2 + 73.202x + 26463
R2 = 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
2-64
-------
§ 316(b) TDD Chapter 2 for New Facilities
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)
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
2-65
-------
§ 316(b) TDD Chapter 2 for New Facilities
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)
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
2-55
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§ 316(b) TDD Chapter 2 for New Facilities
Costing Methodology
Chart 2-7. Actual Capital Costs for Wet Cooling Tower Projects
and Comparable Costs from EPA Cost Curves
$50,000,000
$45,000,000
$40,000,000
$35,000,000
w $30,000,000
•4-i
O
!_ $25,000,000
4-1
Q.
re
O
$20,000,000
$15,000,000
$10,000,000
$5,000,000
y = 90.742X
R2 = 0.9968
R = 0.8915 case studies
100000
200000
300000 400000
Flow in gpm
500000
600000
* Case studies
I EPA's Estimates
700000
2-67
-------
§ 316(b) TDD Chapter 2 for New Facilities
Costing Methodology
Chart 2-8. O&M Redwood Tower Annual Costs - 1st Scenario
$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
2-68
-------
§ 316(b) TDD Chapter 2 for New Facilities
Costing Methodology
Chart 2-9. O&M Concrete Tower Annual Costs - 1st Scenario
$2,500,000
$2,000,000
$1,500,000
s
$1,000,000
$500,000
50000
y = -3E-06x + 10.305x+ 1837.2
R2 = 0.9999
\
y = -2E-06xz + 8.4943x + 1139.9
100000 150000
Flow GPM
200000
250000
Natural draft wet tower • splashfill mechnical
2-69
-------
§ 316(b) TDD Chapter 2 for New Facilities
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
2-70
70
-------
§ 316(b) TDD Chapter 2 for New Facilities
Costing Methodology
Chart 2-1 1 . Municipal Water Use Costs
$10,000,000
$9,000,000
$8,000,000
$7,000,000
$6,000,000
•4-i
O
o
re $5,000,000
c
c
$4,000,000
$3,000,000
$2,000,000
$1,000,000
$0
y = 2102.4x
R2=1
500 1000 1500 2000 2500
FlowGPM
3000
3500 4000
4500
71
2-71
-------
§ 316(b) TDD Chapter 2 for New Facilities
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
0 500 1000 1500
2000 2500
FlowGPM
3000 3500 4000 4500
2-72
72
-------
§ 316(b) TDD Chapter 2 for New Facilities
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
y = 0.088x3 - 11.406x2 + 1406.4x + 20961
R2 = 0.9999
2277x +34350
R2=1
20
40
60
Well Depth Feet
80
100
* Screen width 2 feet Screen width 5 feet Screen width 10 feet * Screen width 14 feet
120
73
2-73
-------
§ 316(b) TDD Chapter 2 for New Facilities
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
2-74
74
-------
§ 316(b) TDD Chapter 2 for New Facilities
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
75
2-75
-------
§ 316(b) TDD Chapter 2 for New Facilities
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)
2-76
76
-------
§ 316(b) TDD Chapter 2 for New Facilities
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
77
2-77
-------
§ 316(b) TDD Chapter 2 for New Facilities
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
$60,000
$40,000
$20,000
$-
y = 5E-08x2 + 0.5222X + 1250.3
R2 = 0.9998
50000
100000
150000 200000
Flow GPM
250000
300000
350000
2-78
78
-------
§ 316(b) TDD Chapter 2 for New Facilities
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
R = 0.9961
Chart 2-19. Travel Screens Capital Cost Without Fish Handling Features
Flow Velocity 0.5ft/sec
v = 5E-10x3 - 0.0001X2 + 12.467x + 65934
_JiL
y = 5E-10x3 - 9E-05X2 + 10.143x + 63746
R = 0.9928
y = 2E-09x3 - O.OOOIx2 + 9.7773x + 54004
R = 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
79
2-79
-------
§ 316(b) TDD Chapter 2 for New Facilities
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
y = 6E-10x3 - O.OOOIx2 + 15.874x + 91207
R = 0.995
y = 5E-10x3 - 9E-05x2 + 12.726x + 88302
FT = 0.9931
y = 1 E-09x3 - 8E-05x2 + 12.223x + 80790
R = 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
2-80
-------
§ 316(b) TDD Chapter 2 for New Facilities
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
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
FT = 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
81
2-81
-------
§ 316(b) TDD Chapter 2 for New Facilities
Costing Methodology
1200000
1000000
800000
in
o
O
a.
re
O
600000
400000
200000
Chart 2-22. Travel Screens Capital Cost With Fish Handling Features
Flow Velocity 1 ft/sec
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
2-82
82
-------
§ 316(b) TDD Chapter 2 for New Facilities
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
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
83
2-83
-------
§ 316(b) TDD Chapter 2 for New Facilities
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
y = 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
2-84
84
-------
§ 316(b) TDD Chapter 2 for New Facilities
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
85
2-85
-------
§ 316(b) TDD Chapter 2 for New Facilities
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
1 Screen width 10 feet
* Screen width 14 feet
2-86
-------
§ 316(b) TDD Chapter 2 for New Facilities
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
250000
i Screen Width 2 ft
A Screen Width 5 ft
i Screen Width 10ft
Screen Width 14ft
87
2-87
-------
§ 316(b) TDD Chapter 2 for New Facilities
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
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
2-88
-------
§ 316(b) TDD Chapter 2 for New Facilities
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
89
2-89
-------
§ 316(b) TDD Chapter 2 for New Facilities
Costing Methodology
1,000,000
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
FlowGPM
250,000 300,000 350,000 400,000
Gunderboom Average Capital •Gunderboom O&M Gunderboom Maximum Capital
2-90
90
-------
§ 316(b) TDD Chapter 3 for New Facilities
Energy Penalties, Air Emissions, and Cooling Tower Side-Effects
Chapter 3: Energy Penalties, Air Emissions,
and Cooling Tower Side-Effects
INTRODUCTION
This chapter discusses the topics of energy penalties,
air emissions, and other environmental impacts of
cooling tower systems. The final rule projects that
nine new facility power plants will install
recirculating closed-cycle wet cooling systems as a
result of this rule. These systems, mainly represented
by natural-draft wet cooling towers, may present
trade-offs in energy efficiency, associated air
emissions increases, and some other environmental
issues.
The energy penalty is an important and controversial
topic for the electricity generation industry. The
topic is widely discussed and debated, yet precise
theoretical or empirical measures of energy penalties
were not readily available to met the Agency's needs.
Therefore, the Agency researched and derived energy
penalty estimates, based on empirical data and proven
theoretical concepts, for a variety of conditions. This
chapter presents the research, methodology, public
comments, results, and conclusions for the Agency's
thorough effort to estimate energy penalties due to the
operational performance of power plant cooling
systems.
CHAPTER CONTENTS
3.1 Energy Penalty Estimates for Cooling 3-2
3.2 Air Emissions Estimates for Cooling System
Upgrades 3-6
3.3 Background, Research, and Methodology of Energy
Penalty Estimates 3-6
3.3.1 Power Plant Efficiencies 3-6
3.3.2 Turbine Efficiency Energy Penalty 3-9
3.3.3 Energy Penalty Associated with Cooling System
Energy Requirements 3-22
3.4 Air Emissions Increases 3-31
3.5 Other Environmental Impacts 3-33
3.5.1 Vapor Plumes 3-33
3.5.2 Displacement of Wetlands or Other Land
Habitats 3-34
3.5.3 Salt or Mineral Drift 3-34
3.5.4 Noise 3-35
3.5.5 Solid Waste Generation 3-36
3.5.6 Evaporative Consumption of Water 3-36
3.5.7 Manufacturers 3-36
References 3-37
Attachment A Steam Power Plant Heat Diagram
Attachment B Turbine Exhaust Pressure Graphs
Attachment C Design Approach Data for Recently
Constructed Cooling Towers
Attachment D Tower Size Factor Plot
Attachment E Cooling Tower Wet Bulb Versus Cold
Water Temperature Performance Curve
Attachment F Summary and Discussion of Public
Comments on Energy Penalty Estimates
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. This chapter presents estimates of the increased
air emissions for the four key pollutants that are currently well researched and monitored for at power plants in the
United States: carbon dioxide (CO2), sulfur dioxide (SO2), nitrogen oxides (NOx), and mercury (Hg).
The remainder of this chapter is organized as follows:
3-1
-------
§ 316(b) TDD Chapter 3 for New Facilities
Energy Penalties, Air Emissions, and Cooling Tower Side-Effects
*• Section 3.1 presents the energy penalty estimates developed for the final rule and the dry cooling regulatory
alternative.
*• Section 3.2 presents the air emissions estimates developed for the final rule and the dry cooling regulatory
alternative.
*• Section 3.3 presents the background, research, and methodology of the energy penalty evaluation. The section
focuses on power plants that use steam turbines and the changes in efficiency associated with using alternative
cooling systems.
*• Section 3.4 presents the methodology for estimation of air emissions increases.
*• Section 3.5 discusses side effects of recirculating wet cooling towers, such as vapor plumes, displacement of
habitat or wetlands, noise, salt or mineral drift, water consumption through evaporation, and solid waste
generation due to wastewater treatment of tower blowdown.
3.1 ENERGY PENALTY ESTIMATES FOR COOLING
Tables 3-1 through 3-6 present the energy penalty estimates developed for the final rule and the dry cooling
regulatory alternative. The Agency presents the methodology for estimation of energy penalties in Section 3.3 of this
chapter.
Table 3-1: National Average 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
Nuclear
Percent of
Plant Output
1.7
8.5
6.8
Combined-Cycle
Percent of Plant
Output
0.4
2.1
1.7
Fossil-Fuel
Percent of
Plant Output
1.7
8.6 !
6.9 1
Average annual penalties occur at non-peak loads..
Table 3-2: National 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
Nuclear
Percent of
Plant Output
1.9
11.4
9.6
Combined-Cycle
Percent of Plant
Output
0.4
2.8
2.4
Fossil-Fuel
Percent of
Plant Output
1.7
10.0
8.4 I
Peak-summer shortfalls occur when plants are at or near maximum capacity.
3-.
-------
§ 316(b) TDD Chapter 3 for New Facilities
Energy Penalties, Air Emissions, and Cooling Tower Side-Effects
Table 3-3: 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
Average annual penalties occur at non-peak loads.
Table 3-4: Total Energy Penalties at 100 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 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
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
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.
3-3
-------
§ 316(b) TDD Chapter 3 for New Facilities
Energy Penalties, Air Emissions, and Cooling Tower Side-Effects
Table 3-5: Annual Penalties (in MW) for the Final Rule by Online Year"
Year
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
Total
Coal-Fired Once-Through
Cooling at Baseline
70
9
1
79
Combined-Cycle, Once-Through
Cooling at Baseline
4
4
4
4
4
21
The total energy penalty for the final rule is 100 MW, or 0.027 percent of all new
generating capacity in the US over the next twenty years.
3-4
-------
§ 316(b) TDD Chapter 3 for New Facilities
Energy Penalties, Air Emissions, and Cooling Tower Side-Effects
Table 3-6: Annual Penalties (in MW) for the Dry Cooling-Based Alternative by Online Year"
Year
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
Total
Coal-Fired
Recirculating Wet Cooling
Baseline
Freshwater
164
164
108
43
12
491
Estuary
56
56
Once-Through
Baseline
Freshwater
362
44
5
412
Combined-Cycle j
Recirculating Wet Cooling
Baseline
Freshwater
71
54
40
77
46
61
102
38
33
54
35
34
30
37
37
31
779
Estuary
8
17
8
8
58
Once-Through i
Baseline i
Estuary i
22
22
22
22
22
108
The total energy penalty for the dry cooling option (at a total of 83 potentially impacted plants) would be 1900
MW, or 0.5 percent of all new capacity in the US over the next twenty years.
3-5
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§ 316(b) TDD Chapter 3 for New Facilities
Energy Penalties, Air Emissions, and Cooling Tower Side-Effects
3.2 AIR EMISSIONS ESTIMATES FOR COOLINS SYSTEMS UPGRADES
Tables 3-7 and 3-8 present the incremental air emissions estimates developed for the final rule and the dry cooling
regulatory alternative. The Agency presents the methodology for estimation of air emissions increases in section 3.4
of this Chapter.
Table 3-7: Air Emissions Increases for the Final Rule0
Fuel Type
All
Total Effected
Capacity (MW)
9,957
Annual CO2
(tons)
485,860
Annual SO2
(tons)
2,561
Annual NOX
(tons)
1,214
Annual Hg
(Ibs)
16
These emissions increases represent an increase for the entire US electricity generation industry of
approximately 0.02 percent per pollutant.
Table 3-8: Air Emissions Increases for the a Dry Cooling-Based Alternative"
Fuel Type
All
Total Effected
Capacity (MW)
64,070
Annual CO2
(tons)
8,931,056
Annual SO2
(tons)
47,074
Annual NOX
(tons)
22,313
Annual Hg
(Ibs)
300
These emissions increases represent an increase for the US electricity generation industry of approximately
0.35 percent. For the mercury emissions alone, these emissions are equivalent to the addition of three 800-
MW coal-fired power plants operating at near full capacity.
3.3 BACKSROUND, RESEARCH, AND METHODOLO
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§ 316(b) TDD Chapter 3 for New Facilities Energy Penalties, Air Emissions, and Cooling Tower Side-Effects
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 tend to be operated 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 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 = 34737 NPHR x 100 (1)
Table 3-9 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.
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§ 316(b) TDD Chapter 3 for New Facilities Energy Penalties, Air Emissions, and Cooling Tower Side-Effects
Table 3-9: Heat Rates and Plar
Type of Plant
Steam Turbine - Fossil Fuel
Steam Turbine - Nuclear
Combined Cycle - Gas
Combustion Turbine
it Efficiencies for Different Types o
Net Plant Heat Rate (BTU/kWh)
9,355
10,200
6,762
11,488
F Steam Powered Plants
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 3 7 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 3-9 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 watertemperatures. Therefore,
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.
3-,
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§ 316(b) TDD Chapter 3 for New Facilities Energy Penalties, Air Emissions, and Cooling Tower Side-Effects
3.3.2 Turbine Efficiency Energy Penalty
a. 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 atypical 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 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
3-9
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§ 316(b) TDD Chapter 3 for New Facilities Energy Penalties, Air Emissions, and Cooling Tower Side-Effects
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 showthatthe degree ofthe change (slope ofthe 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 ofthe 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 ofthe time. Therefore, use ofthe 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 ofthe 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-fired plants and use ofthe energy penalty values derived from the 67 percent load curves rather than
the 100 percent load curves would be appropriate.
3-10
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§ 316(b) TDD Chapter 3 for New Facilities
Energy Penalties, Air Emissions, and Cooling Tower Side-Effects
b. Estimated Changes in Turbine Efficiency
Table 3-10 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 3-10. 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 3-10: 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 i
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.
3-11
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§ 316(b) TDD Chapter 3 for New Facilities
Energy Penalties, Air Emissions, and Cooling Tower Side-Effects
15.0%
13.0%
11.0%
•a
re
9.0%
1
7.0%
a>
O)
c
5.0%
j_
O
+*
£J 3.0%
o>
a.
1.0%
-1.0%
-3.0%
Figure 1
Plot of Various Turbine Exhaust Pressure Correction Curves
for 100% and 67% Steam Loads
Nuclear (67% Load)
y = -Q.QQ13X3 + 0 Q169X2 - 0 Q286x + 0 0098
R2 = 0.9982
Nuclear (100% Load)
y = -O.OOOSx3 + 0.0099X2 - 0.0208x + 0.0111
= u.yyy/
Fossil Fuel (67% Load)
y = 0.0063X2 -0.004x- 0.0062
R = 0.9928
Combined Cycle (67% Load)
y = -0.0004X3 + 0.0082X2 - 0.016x + C
R2 = 0.9987
Fossil Fuel (100% Load)
y =-O.OOOSx3 i O.OOSI^-O.Oiex i C
= 0.9983
Combined Cycle (100% Load)
y = -O.OOOSx3 + 0.0062X2 - 0.0154X + 0.0084
R2 = 0.9999
.0033
.0078
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)
3-12
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§ 316(b) TDD Chapter 3 for New Facilities
Energy Penalties, Air Emissions, and Cooling Tower Side-Effects
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
3-13
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§ 316(b) TDD Chapter 3 for New Facilities Energy Penalties, Air Emissions, and Cooling Tower Side-Effects
c. 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 °Fand95 °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 3 below.
• 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 economic analysis for the final §316(b)
New Facility Rule 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
highervalue is a trade-off between greater capital cost investment versus lower potential energy production. In states
3-14
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§ 316(b) TDD Chapter 3 for New Facilities Energy Penalties, Air Emissions, and Cooling Tower Side-Effects
where the rates 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.
3-15
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§ 316(b) TDD Chapter 3 for New Facilities
Energy Penalties, Air Emissions, and Cooling Tower Side-Effects
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
120
i M u I i-Facility Design Data • Single Unit Data
5-7(5
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§ 316(b) TDD Chapter 3 for New Facilities
Energy Penalties, Air Emissions, and Cooling Tower Side-Effects
• Regional 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 3-11 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 3-11: 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 3-12 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.
3-17
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§ 316(b) TDD Chapter 3 for New Facilities
Energy Penalties, Air Emissions, and Cooling Tower Side-Effects
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 3-13 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 3-12: Design Wet Bulb Temperature Data for Selected Locations
Location
Boston, MA
Jacksonville, FL
Chicago, IL
Seattlfe.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 3-13: 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
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§ 316(b) TDD Chapter 3 for New Facilities Energy Penalties, Air Emissions, and Cooling Tower Side-Effects
c. 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 3-11 and 3-13. 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 3-14 and 3-15 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 3-14 and 3-15 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 3-11 and the 1% percent exceedence wet bulb and dry bulb temperatures from Table
3-12.
EPA notes that the penalties presented in Tables 3-14 and 3-15 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 presentthe turbine efficiency penalty. Section 3.3.3 presents the fan and pumping components
of the energy penalty.
3-19
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§ 316(b) TDD Chapter 3 for New Facilities
Energy Penalties, Air Emissions, and Cooling Tower Side-Effects
Table 3-14: Calculated
Location
Boston
Jacksonville
Chicago
Seattle
Average
Energy Penalties for the Turbine Efficiency
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.
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
Percent Nuclear
Maximum Maximum
Load Design
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%
Component at 100
Nuclear
Annual
Average
0
2
2
0
6
5
0
3
2
0
2
2
0
3
3
37%
85%
48%
54%
21%
68%
42%
09%
67%
29%
63%
34%
40%
70%
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%
1.09%
7.76%
6.66%
0.61%
8.22%
7.61%
1.21%
7.96%
6.75%
0.70%
6.46%
5.76%
0.90%
7.60%
6.70%
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 3-1 for the total energy penalties. This table presents only the turbine component of the total energy penalty.
3-20
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§ 316(b) TDD Chapter 3 for New Facilities
Energy Penalties, Air Emissions, and Cooling Tower Side-Effects
Table 3-15: Calculated
Location
Boston
Jacksonville
Chicago
Seattle
Average
Cooling Type
Wet Tower vs
Dry Tower vs.
Dry Tower vs.
Wet Tower vs
Dry Tower vs.
Dry Tower vs.
Wet Tower vs
Dry Tower vs.
Dry Tower vs.
Wet Tower vs
Dry Tower vs.
Dry Tower vs.
Wet Tower vs
Dry Tower vs.
Dry Tower vs.
Energy Penalties
for the Turbine Efficiency Component at 67% Recent of
Maximum Steam Load
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
13
11
1
13
12
2
14
11
1
12
10
1
13
11
32%
82%
50%
22%
61%
39%
53%
03%
50%
60%
16%
56%
92%
41%
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
1
12
10
1
15
13
04%
15%
11%
08%
96%
88%
23%
67%
44%
50%
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 3-1 for the total energy penalties. This table presents only the turbine component of the total energy penalty.
3-21
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§ 316(b) TDD Chapter 3 for New Facilities Energy Penalties, Air Emissions, and Cooling Tower Side-Effects
3.3.3 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 developed 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, but may have
been in some instances as part of a conservative approach.
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).
a. 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 3-16 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 penalty shown in Table
7 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.
3-22
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§ 316(b) TDD Chapter 3 for New Facilities
Energy Penalties, Air Emissions, and Cooling Tower Side-Effects
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 3-16. 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 3-16 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
Range/
Approach
(Degree F)
15/11
15/5
15/10
16/12
Table 3-16
Flow
(gpm)
20,000
20,000
243,000
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
i
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 3-1 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 condensers. The steam portion of the plant has a capacity of 150 MW (1.1 million Ib/hr steam flow).
3-23
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§ 316(b) TDD Chapter 3 for New Facilities Energy Penalties, Air Emissions, and Cooling Tower Side-Effects
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.
b. Cooling Water Pumping Requirements
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.
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
3-24
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§ 316(b) TDD Chapter 3 for New Facilities Energy Penalties, Air Emissions, and Cooling Tower Side-Effects
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/lOOOft. 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
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,
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 <5 0,000 gpm) to 41 ft for larger condensers (Hess
3-25
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§ 316(b) TDD Chapter 3 for New Facilities Energy Penalties, Air Emissions, and Cooling Tower Side-Effects
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.
c. 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 3-17 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 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 3-17 and 3-18 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.
3-26
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§ 316(b) TDD Chapter 3 for New Facilities
Energy Penalties, Air Emissions, and Cooling Tower Side-Effects
Table 3-17: 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
Pumped Head
ft. ft.
at 20' Static Head
300 20
300 25
at 20' Static Head
300 20
300 25
at 20' Static Head
300 20
300 25
at 20' Static Head
1000 20
300 25
at 20' Static Head
1000 20
300 25
at 20' Static Head
1000 20
300 25
at 20' Static Head
3000 20
300 25
at 20' Static Head
3000 20
300 25
at 20' Static Head
3000 20
300 25
Condenser
Head
ft
Using 4: 42"
21
21
Using 3: 42"
21
21
Using 2: 42"
21
21
Using 4: 42"
21
21
Using 3: 42"
21
21
Using 2: 42"
21
21
Using 4: 42"
21
21
Using 3: 42"
21
21
Using 2: 42"
21
21
Equiv. Pipe Friction
Length Velocity Loss
Misc. Rate
Losses
ft. fps ft/l,000ft
Pipes at 300' Length
300 5.8 3.6
300 5.8 3.6
Pipes at 300' Length
300 7.7 6.1
300 7.7 6.1
Pipes at 300' Length
300 11.6 12.8
300 11.6 12.8
Pipes at 1000' Length
300 5.8 3.6
300 5.8 3.6
Pipes at 1000' Length
300 7.7 6.1
300 7.7 6.1
Pipes at 1000' Length
300 11.6 12.8
300 11.6 12.8
Pipes at 3000' Length
300 5.8 3.6
300 5.8 3.6
Pipes at 3000' Length
300 7.7 6.1
300 7.7 6.1
Pipes at 3000' Length
300 11.6 12.8
300 11.6 12.8
Friction
Head
ft.
2
2
4
4
8
8
5
2
8
4
17
8
12
2
20
4
42
8
Total
Head
ft.
43
48
45
50
49
54
46
48
49
50
58
54
53
48
61
50
83
54
Wet Towers Versus Once -through At 20' Static Head
Net
Difference
ft
5
5
5
2
1
-4
-5
-11
-30
Flow
Rate
gpm
100,000
100,000
100,000
100,000
100,000
100,000
100,000
100,000
100,000
100,000
100,000
100,000
100,000
100,000
100,000
100,000
100,000
100.000
Hydraulic-
Hp
Hp
1089
1216
1127
1254
1229
1355
1153
1216
1235
1254
1455
1355
1335
1216
1543
1254
2101
1355
Brake-
Hp
Hp
1556
1737
1610
1791
1755
1936
1647
1737
1764
1791
2079
1936
1907
1737
2204
1791
3002
1936
Power
Required
kW
1161
1296
1201
1336
1310
1444
1229
1296
1316
1336
1551
1444
1423
1296
1644
1336
2239
1444
Energy
Penalty
kW
135
135
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 3-1 for the total energy penalties. This table presents only the pumping component of the total energy penalty.
3-27
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§ 316(b) TDD Chapter 3 for New Facilities Energy Penalties, Air Emissions, and Cooling Tower Side-Effects
• 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 3-18 presents the energy penalties corresponding to the
pumping energy requirements from Table 3-17 using the above factors.
3-28
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§ 316(b) TDD Chapter 3 for New Facilities
Energy Penalties, Air Emissions, and Cooling Tower Side-Effects
Table 3-18: Comparison of Pumping
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
Pumped
ft.
Static Power
Head Required
ft. kW
at 20' Static Head Using 4: 42"
300
300
20 1161.1
25 1295.6
at 20' Static Head Using 3: 42"
300
300
20 1201.4
25 1335.9
at 20' Static Head Using 2: 42"
300
300
20 1309.6
25 1444.1
at 20' Static Head Using 4: 42"
1000
300
20 1228.8
25 1295.6
at 20' Static Head Using 3: 42"
1000
300
20 1316.3
25 1335.9
at 20' Static Head Using 2: 42"
1000
300
20 1550.6
25 1444.1
at 20' Static Head Using 4: 42"
3000
300
20 1422.5
25 1295.6
at 20' Static Head Using 3: 42"
3000
300
20 1644.5
25 1335.9
at 20' Static Head Using 2: 42"
3000
300
20 2239.3
25 1444.1
Power
Requirement and Energy Penalty to Power Plant Output
Flow Range Nuclear Nuclear Nuclear Fossil Fuel Fossil Fuel Fossil Comb.- Comb.- Comb.-
Rate Power/ Equiv. Pumping Power/ Equiv. Fuel Cycle Cycle Cycle
Heat Output Heat Output Pumping Power/ Equiv. Pumnine
Heat l 8
gpm °F Ratio (MW) % of Output Ratio (MW) % of Ratio Output %of
Output (MW) Output
Pipes at 300' Length
100,000 20
100,000 20
Pipes at 300' Length
100,000 20
100,000 20
Pipes at 300' Length
100,000 20
100,000 20
Pipes at 1000' Length
100,000 20
100,000 20
Pipes at 1000' Length
100,000 20
100,000 20
Pipes at 1000' Length
100,000 20
100,000 20
Pipes at 3000' Length
100,000 20
100,000 20
Pipes at 3000' Length
100,000 20
100,000 20
Pipes at 3000' Length
100,000 20
100,000 20
0.8
0.8
0.8
0.8
0.8
0.8
0.8
0.8
0.8
0.8
0.8
0.8
0.8
0.8
0.8
0.8
0.8
0.8
235
235
235
235
235
235
235
235
235
235
235
235
235
235
235
235
235
235
0.49%
0.55%
0.51%
0.57%
0.56%
0.61%
0.52%
0.55%
0.56%
0.57%
0.66%
0.61%
0.60%
0.55%
0.70%
0.57%
0.95%
0.61%
1 294
1 294
1 294
1 294
1 294
1 294
1 294
1 294
1 294
1 294
1 294
1 294
1 294
1 294
1 294
1 294
1 294
1 294
0.39%
0.44%
0.41%
0.45%
0.45%
0.49%
0.42%
0.44%
0.45%
0.45%
0.53%
0.49%
0.48%
0.44%
0.56%
0.45%
0.76%
0.49%
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
882
882
882
882
882
882
882
882
882
882
882
882
882
882
882
882
882
882
0.13%
0.15%
0.14%
0.15%
0.15%
0.16%
0.14%
0.15%
0.15%
0.15%
0.18%
0.16%
0.16%
0.15%
0.19%
0.15%
0.25%
0.16%
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. Power/Heat Ratio refers to the ratio of Power Plant Output (MW) to the heat (in equivalent MW) transferred through the condenser. See Section 3-1
for the total energy penalties. This table presents only the pumping component of the total energy penalty
3-29
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§ 316(b) TDD Chapter 3 for New Facilities
Energy Penalties, Air Emissions, and Cooling Tower Side-Effects
d. Summary of Cooling System Energy Requirements
EPA chose the piping scenario in Table 3-17 where pumping head is close to 50 ft for both (i.e., once-through at 1,000 ft and
3-42 in. pipes in Table 3-17). Thus, the cooling water pumping requirements for once-through and recirculating wet towers
are nearly equal using the chosen site-specific conditions. Table 3-19 summarizes the fan and pumping equipment energy
requirements as a percent of power output for each type of power plant. Table 3-20 presents the net difference in energy
requirements shown in Table 3-19 for the alternative cooling systems. The net differences in Table 3-20 are the equipment
operating energy penalties associated with conversion from one cooling technology to another.
EPA notes that the penalties presented in Tables 3-19 and 3-20 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 and fan components. Section 3.3.2 presents the turbine efficiency components of the energy penalty.
Table 3-19: Summary of Fan and Pumping Energy Requirements as a Percent of Power 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%
Dry Tower
Total (Fan)
3.04%
2.43%
0.81%
Note: See Section 3.1 for the total energy penalties.
Table 3-20: Fan and Pumping Energy Penalty Associated with Alternative
Cooling System as a Percent of Power Output
Nuclear
Fossil Fuel
Combined-Cycle
Wet Tower Vs
Once-through
0.92%
0.73%
0.24%
Dry Tower Vs Wet
Tower
1.56%
1.25%
0.42%
Dry Tower Vs Once-
through
2.48%
1.98%
0.66%
Note: See Section 3.1 for the total energy penalties.
3-30
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§ 316(b) TDD Chapter 3 for New Facilities Energy Penalties, Air Emissions, and Cooling Tower Side-Effects
3.4 AIR EMISSIONS INCREASES
Due to the cooling system energy penalties, as described in section 3.3 and presented in section 3.1 above, EPA
estimates that air emissions will marginally increase from power plants which upgrade cooling systems. The energy
penalties reduce the efficiency of the electricity generation process and thereby increase the quantity of fuel
consumed per unit of electricity generated. In estimating annual increases in air emissions, the Agency based its
calculations on the mean annual energy penalties provided in Table 3-1 above. EPA presents the annual air emissions
increases for the final rule and the dry cooling regulatory alternative in Tables 3-7 and 3-8 in section 3.2 above.
EPA developed estimates of incremental air emissions estimates for the two types of power plants projected to
upgrade cooling systems as a result of this rule (or a regulatory alternative): combined-cycle and coal-fired power
plants. Generally, combined-cycle plants produce significantly less air emissions per kilowatt-hour of electricity
generated than coal-fired plants. Because the combined-cycle plant requires cooling for approximately one-third of
its process (on a megawatt capacity basis) and because of the differences in combustion products from natural gas
versus coal, the combined-cycle plantproduces less air emissions, even after coal-fired plants are equipped with state-
of-the-art emissions controls. However, for the case of the air emissions estimates for the final rule and regulatory
alternatives considered, EPA estimates that plants incurring an energy penalty will not increase their fuel
consumption on-site to overcome incurred energy penalties. Instead, the Agency estimates that energy penalties at
facilities affected by the requirements of this rule (or the regulatory alternatives) would purchase replacement power
from the grid and the air emissions increases associated with a particular energy penalty at an effected plant would
be released by the rest of the grid as a whole (thereby comprising negligible increases at a large number and variety
of power plants). 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. Therefore, the air emissions increases
presented in section 3.2 of this chapter represent uniform national air emissions increases per unit of energy penalty,
regardless of the plant at which the energy penalty is occurring. For the final rule and regulatory alternatives
considered, the key difference between air emissions increases estimated at facilities projected to upgrade cooling
systems is directly related to the size of the energy penalty that the plant will incur. For the sake of comparison, EPA
also calculated the air emissions increases for the final rule and regulatory alternatives in the case where the effected
plants would increase fuel consumption to overcome the penalties. The comparative results are presented in Tables
3-21 and 3-22. EPA found small national differences between increased air emissions as calculated on the plant
versus grid basis. For more information on the supporting calculations see DCN 3-3085.
The data source for the Agency's air emissions estimates of CO2, SO2, NOX, and Hg is the EPA developed database
titled E-GRID 2000. This database is a compendium of reported air emissions, plant characteristics, and industry
profiles for the entire US electricity generation 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 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 dataforthe Agencyto conduct air emissions increases analyses forthis 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 able to obtain from other sources.
3-31
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§ 316(b) TDD Chapter 3 for New Facilities
Energy Penalties, Air Emissions, and Cooling Tower Side-Effects
As noted above, the E-GRID 2000 database contains data on existing power plants. For the national analysis
presented in section 3.2 above, EPA estimated that the annual generation of electricity would not increase over the
life of the rule. Therefore, the emissions increases as a percent of national capacity presented in Tables 3-7 and 3-8
above are conservatively estimated and ignore projected growth rates of power plant capacity. For the comparative
analysis of plant versus grid based emissions the Agency purposefully chose, when analyzing specific power plants
(and not just the grid as a whole), to focus on the most recently constructed plants with multiple years of operating
data (where possible). In addition, the Agency selected a variety of plants from different regions of the country with
different urban versus rural locations. The capacity of the model plants was chosen as closely as possible to the
average size plant within scope of the rule. Therefore, the Agency's comparative estimates of the air emissions
increases from the scenario where individual plants are able to consume more fuel to overcome the energy penalties
present nationally applicable results for the variety of plants and locations expected for the new facility rule. The
model facility plant information along with the supporting calculations for this analysis can be found in DCN 3-3085.
Because the Agency estimates that the air emissions increases for the final rule (and regulatory alternatives) will
come from the mix of plant types across the nation, the issue of baseline cooling systems is moot. However, for the
scenario where EPA estimated (for the sake of comparison) that plants would increase fuel consumption to overcome
energy penalties, and the air emissions would occur at the site, the issue of cooling system is more relevant. EPA
attempted to consider baseline cooling systems when selecting the model facilities upon which to base the air
emissions profiles for combined-cycle and coal-fired plants. However, because the emissions would be used to
estimate changes in cooling systems from once-through to wet towers and, for the case of regulatory alternatives,
from once-through to dry towers and wet towers to dry towers, the Agency ultimately determined that age, size, and
location of the plant were more important factors to consider than the baseline cooling system. The effect is such,
for the comparative example of plants increasing fuel consumption to overcome energy penalties as a result of the
final rule, the Agency may have marginally overestimated the air emissions increases due to cooling system changes.
EPA reiterates that this has no bearing on the estimated air emissions for the final rule and is relevant only for the
comparative analysis presented in Tables 3-21 and 3-22. The basis for the Agency stating that it may have
overestimated emissions in this comparative case for the final rule is due to the fact that several of the plants used
as model facilities in the air emissions analysis actually utilize wet-cooling towers at baseline. Therefore, the baseline
energy efficiency would be lower than a once-through system and the related baseline air emissions rates per unit
of fuel consumed would be higher. Thus, for the case of the upgrades from once-through to wet cooling towers, EPA
likely is overestimating the compliance air emissions rates per unit of fuel consumed in this comparative case. For
the case of the dry cooling alternative, the effect is less pronounced and the Agency may be underestimating, in the
end, the comparative air emissions increases. This is due to the fact that the majority of power plants have wet
cooling towers at baseline. For the case of 90 percent of the plants to be upgraded to dry cooling in this regulatory
alternative, the proper baseline cooling system is wet cooling towers. Therefore, the baseline air emissions rates per
unit of electricity generated are lower than would represent a majority of plants employing wet cooling at baseline.
Table3-21. Comparison of Calculation Techniques for Net Air Emissions Increases of the Final Rule
Compensation
Technique
Increased Fuel
Consumption
Market Power
Replacement
Total Energy
Penalty MW
100
100
Annual
CO2 (tons)
712,886
485,860
Annual
SO2 (tons)
1,543
2,561
Annual
NOx (tons)
1,518
1,214
Annual
Hs (Ibs)
23
16
3-32
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§ 316(b) TDD Chapter 3 for New Facilities
Energy Penalties, Air Emissions, and Cooling Tower Side-Effects
Table3-22. Comparison of Calculation Techniques for Net Air Emissions Increases of Dry Cooling
Compensation
Technique
Increased Fuel
Consumption
Market Power
Replacement
Total Energy
Penalty MW
1,900
1,900
Annual
CO2 (tons)
11,427,552
8,931,036
Annual
SO2 (tons)
18,649
47,074
Annual
NOx (tons)
23,432
22,313
Annual j
Hg (Ibs) !
272
300
3.5 OTHER ENVIRONMENTAL IMPACTS
Recirculating wet cooling towers can produce side effects such as vapor plumes, displacement of habitat or wetlands,
noise, salt or mineral drift, water consumption through evaporation, and increased solid waste generation due to
wastewater treatment of tower blowdown. The Generic Environmental Impact Statement for License Renewal of
Nuclear Plants (NUREG-1437 Vol. 1, Nuclear Regulatory Commission) addresses the majority of these issues in
depth, and the Agency refers to the detailed research contained therein several times in this discussion.
The Agency considered non-aquatic impacts of recirculating cooling towers for the proposal. While the Agency did
not present quantified information regarding these side effects in the proposal, the Agency discussed the effects of
both wet and dry cooling towers in the proposal. Specifically, the Agency discussed discharge water quality, salt
drift, water conditioning chemicals and biocides, vapor plumes, energy efficiency, land use, and air emissions
increases (65 FR 49080-49081). The Agency invited comments to the proposal on the subject of adverse
environmental impact and whether or not it should consider non-aquatic impacts such as salt/mineral drift and
reductions in the efficiency of electricity generation leading to increased air emissions as examples of adverse
environmental impact (65 FR 49075). In turn, the Agency received no usable data (only anecdotal information) from
commenters supporting assertions that these "side effects" pose significant environmental problems. The Agency
researched the subjects further after proposal and provided some of the information in the notice of data availability
and has cited other information from NUREG-1437.
The vast majority (90 percent) of power plants projected within the scope of this rule would install recirculating wet
cooling towers in absence of this rule. Of these 74 power plants, the Agency projects that the cooling towers to be
constructed will be of the mechanical draft type. (Stone & Webster 1992). Forthe other nine power plants forwhich
EPA has projected the compliance costs associated with wet cooling towers, the Agency projects that the towers to
be installed would be of the mechanical draft type, also.
3.5.1 Vapor Plumes
Natural draft or mechanical draft cooling towers can produce vapor plumes. Plumes can create problems for fogging
and icing, which have been recorded to create dangerous conditions for local roads and for air and 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). A "treatment"
technique for these plumes in very rare cases is the installation of plume abatement (wet/dry hybrid cooling towers)
on the tower. This is currently practiced at a small portion of recently constructed facilities (See DCN #2-037). As
such, EPA's capital costs are not adjusted to reflect this type of plume abatement for this nationally applicable rule
in which only 9 facilities are projected to install wet cooling towers.
3-33
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§ 316(b) TDD Chapter 3 for New Facilities Energy Penalties, Air Emissions, and Cooling Tower Side-Effects
Regarding aesthetics of cooling tower plumes, the Agency points to the Track II compliance option as an alternative
for new facility power plants, in addition to the plume abatement controls, which are an option for new plants that
choose to site where plume aesthetics are a public nuisance. The Agency notes that land area buffers may also be
a simple means for reducing the effects of visible plumes, though this would be highly site-specific. As such, EPA
has considered the subject of visible plumes to be a small issue when weighed against the serious aquatic
environmental impacts of once-through cooling.
In the development of the final rule, the Agency considered the land area required for installation of cooling towers
at new power plants. The Agency examined the sensitivity of costs to new power plants of purchasing additional land
for (1) installing mechanical draft cooling towers in lieu of once-through cooling (for those power plants expected
to incur the costs of cooling towers only) and (2) providing land area buffers for plumes at a portion of facilities. The
Agency determined the final annualized costs were not sensitive to the described changes in land costs. The Agency
also understands that the costs of these land acquisitions as a portion of total project costs for new power plants are
negligible. In addition, because this rule applies to new facilities which have the ability, in the majority of cases, to
alter the design and location of their facilities without encountering most of the hurdles associated with retrofitting
existing facilities, the issue of additional land acquisition is not as significant.
The Agency considers the issue of plume "re-entrainment" to be an issue that has been well addressed by designers
and operators of wet cooling towers. The technology is mature and well designed after many decades of use
throughout the world in a variety of climates. The Agency considers plume re-entrainment at the nine power plants
projected to upgrade their cooling system to be a small effect. For wet cooling towers, the plume re-entrainment
value occasionally referenced is 2 percent (Burns & Micheletti 2000). This value, in the Agency's estimates would
not appreciably impact cooling tower performance, nor have a discernable environmental impact.
3.5.2 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. When determining the area needed for wet cooling towers, plants generally
consider the possible plume effects, and plan for the amount of space needed to minimize the effects of local fogging
and icing and to minimize re-entrainment of the plume by the tower. The land requirements of mechanical draft wet
cooling towers at new combined-cycle power plants generally do not approach the size of the campus. Dry cooling
towers generally require approximately 3 to 4 times the area of a wet tower for a comparable cooling capacity. 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.
3.5.3 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 recirculating 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. Commenters expressed
the concern that salt drift may 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 advanced fill materials that
have been developed to minimize salt or mineral drift effects. The Agency estimates that the typical plant installing
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§ 316(b) TDD Chapter 3 for New Facilities Energy Penalties, Air Emissions, and Cooling Tower Side-Effects
a cooling tower as a result of the requirements of this rule will equip the tower with modern splash fill materials. As
such, the Agency has applied capital costs for the abatement of drift in the compliance costs of this rule.
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 such as those costed by the Agency. 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 the
case of mechanical draft towers, falls mostly within 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 Agency projects that four of the nine power plants which will upgrade their cooling system
from once-through to recirculating closed-cycle will utilize freshwater sources, where salt drift will not be an issue.
The Agency anticipates that the other five plants (each a combined-cycle design) will utilize estuarine/tidal water
sources for cooling and that the issue of salt drift at these plants is of small significance and can be mitigated. This
conclusion is supported by those 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 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 therefore be of small significance. Because
there is 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."
3.5.4 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-1437 Vol. 1). Noise abatement features are an integral component of modern cooling tower designs, and
as such are reflected in the capital costs of this rule, which were empirically verified against real-life, turn-key costs
of recently installed cooling towers. A very small fraction of recently constructed cooling towers also further install
noise abatement features associated with low noise fans. The Agency collected data on recently constructed cooling
tower projects from cooling tower vendors. The Agency obtained detailed project descriptions forthese 20 projects
and none utilize low noise fans. In addition, the cost contribution of low noise fans, in the rare case in which they
may be installed at a new facility, would comprise a very small portion of the total installed capital cost of the cooling
system. As such, the Agency is confident that the issue of noise abatement is not critical to the evaluation of the
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 of the broadband character of the
cooling towers, the noise associated with them is largely indistinguishable and less obtrusive than transformer noise
or loudspeaker noise."
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§ 316(b) TDD Chapter 3 for New Facilities Energy Penalties, Air Emissions, and Cooling Tower Side-Effects
3.5.5 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 facility.
EPA has accounted for solid waste disposal from cooling tower blow-down wastewater treatment in the operation
and maintenance costs of this rule. EPA reiterates that only nine power plants would incur the costs to install wet
cooling towers as a result of this rule. The associated solid waste disposal increases for these plants would be
extremely small compared to the scope of facilities covered by the rule and negligible for the industry as a whole.
3.5.6 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 of the 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 maj ority
of this loss happens down-stream of the plant in the receiving waterbody.
The Agency has considered evaporation of water and finds these issues not to be significant for this rule. The Agency
notes, again, that 90 percent of the in-scope power plants will install cooling towers regardless of the requirements
of this rule. The nine other facilities, which may comply with the rule either through installation of flow reduction
technologies similar to cooling towers (such as recirculating cooling lakes, cooling canals, or hybrid wet-dry cooling
towers) or compliance with track II, are expected to consume approximately 127,000 gallons per minute (evaporative
loss) when all new plants are operating. This represents less than three (3) percent of the baseline intake flow of the
power plants within the scope of the rule. As a percentage of the total flow of water used for electricity generation
in the US, this represents 0.1 percent. See DCN 3-3085.
3.5.7 Manufacturers
The Agency notes that the discussion thus far concerning side effects has focused exclusively on power plants. The
Agency expects that 29 manufacturers will incur costs equivalent to installations of closed-cycle wet cooling towers
as a result of this rule. However, even though these costs reflect cooling tower installations, the Agency projects that
manufacturing facilities will comply, in the majority of cases, with this rule through the adoption of recycling and
reuse design changes and operational practices at their plants. Therefore, the majority of issues discussed in this
section are not of concern to manufacturing facilities for the final rule nor is the issue of energy penalties.
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§ 316(b) TDD Chapter 3 for New Facilities Energy Penalties, Air Emissions, and Cooling Tower Side-Effects
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.
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.
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.
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.
Litton, T.R. Stanley Consultants, Inc. No Date. "Application of Parallel wet and Dry Condensing Systems to a 35
MW Steam Turbine"
3-37
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§ 316(b) TDD Chapter 3 for New Facilities Energy Penalties, Air Emissions, and Cooling Tower Side-Effects
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/srl437/Vl/srl437vl.html#J_128
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.
Woodruff, E.B.,Lammers, H.B.,Lammers, T.F. 1998. Steam Plant Operation. Seventh Edition. McGraw-Hill. New
York.
Stone & Webster Engineering Corporation. April 1992. Evaluation of the Potential Costs and Environmental
Impacts ofRetrofitting Cooling Towers on Existing Steam Electric Power Plants that Have Obtained Variances under
Section 316(a) of the Clean Water Act. Prepared for the Edison Electric Institute.
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§ 316(b) TDD Chapter 3 for New Facilities Attachments
ATTACHMENT A TO CHAPTER 3: HEAT DIAGRAM FOR STEAM
POWER PLANT
(Source: Ishigai 1999)
See Hard Copy
Attachments
-------
§ 316(b) TDD Chapter 3 for New Facilities Attachments
ATTACHMENT B TO CHAPTER 3: 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
Attachments
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§ 316(b) TDD Chapter 3 for New Facilities Attachments
ATTACHMENT C TO CHAPTER 3: DESIGN APPROACH DATA FOR
RECENT COOLING TOWER PROJECTS
(Source: Mirsky 2001)
Attachments
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§ 316(b) TDD Chapter 3 for New Facilities
Attachments
Table AA-1. Cooling Tower Design Temperature, Range and Approach
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
MN
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
FLOW (GPM)
208000
152000
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
105
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
(DEG F)
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
9.45
17
23
8
12
9.46
8
14.3
14.6
13
8
14
6
5
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
2
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
o
3
i
3
Maximum 278480 135 96.7 84.7 46 23 14
Minimum 1000 85 67 52 10 51
Average 75775.42222 106.3 85.2 74.8 21.1 10.4 5
Median 30000 105.7 87 79 1 20 10 3
Mode 278480 105 90 81 20 10 2
Attachments
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§ 316(b) TDD Chapter 3 for New Facilities Attachments
ATTACHMENT D TO CHAPTER 3: TOWER SIZE FACTOR PLOT
(Source: Hensley 1985)
See Hard Copy
Attachments
-------
§ 316(b) TDD Chapter 3 for New Facilities Attachments
ATTACHMENT E TO CHAPTER 3: COOLINS TOWER WET BULB VERSUS
COLD WATER TEMPERATURE TYPICAL PERFORMANCE CURVE
(Source: Hensley 1985)
See Hard Copy
Attachments
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§ 316(b) TDD Chapter 3 for New Facilities Attachments
ATTACHMENT F TO CHAPTER 3: SUMMARY AND DISCUSSION
OF PUBLIC COMMENTS ON ENERGY PENALTIES
For the November 2000 proposal, the Agency presented a discussion on energy penalties for dry cooling systems,
but did not present detailed estimates of penalties. The Agency also stated that energy penalties at wet cooling
towers were negligible in their effect on final cost estimates for the proposed rule. Subsequent to the proposal,
the Agency recognized, based, in part, on public comments, that the proposal did not sufficiently consider energy
penalties for the regulatory options considered and proposed. In turn, EPA began a thorough program to assess
the state of research into energy penalties that would meet its broad needs. After learning that the appropriate
energy penalty data did not exist or was not well documented and explained, EPA began a project to assess the
energy penalty of a variety of cooling systems for a variety of conditions. In order to notify the public of its
intention, the Agency included information in the June 2001 notice of data availability that explained the status
of the research project, the types of information the Agency was considering, the methodology for estimating the
penalties, and the ultimate methodology for assessing the cost of the penalties and the associated air emissions
increases.
In addition to a host of general comments on the proposal and notice of data availability that urged consideration
of the energy penalty in the technical, economic, and environmental analyses of the final rule, the Agency
primarily received its most technical comments in response to the notice of data availability. The Agency fully
considered all of the comments received on the subject of energy penalties (see the response to comment
document), which came from all manner of stakeholders. However, due to the detailed technical nature of select
comments, the Agency devotes the following discussion to evaluation of public comments received from the
Department of Energy (DOE) and the Utility Water Act Group (UWAG) concerning EPA's energy penalty
estimates and the methodology presented in the draft report, titled "Steam Plant Energy Penalty Evaluation, April
20, 2001," which was included in the public record for the notice of data availability. For the sake of clarity and
simplicity, this discussion will address the commenters by their representative organizations, even though select
individuals within, legal firms representing, or contractors hired by the organizations may have prepared the
comments.
The DOE comments were the more general of the comments in nature. The Agency addresses these comments
first, along with general comments made by UWAG on energy consumption for different cooling systems. The
UWAG technical comments (Appendix B of their comments) on the draft energy penalty report are then
addressed, followed by a brief discussion of other issues related to EPA's notice of data availability draft report
(here after referred to as the "draft report"). Finally, EPA provides conclusions on the comments and their
influence on the final energy penalty estimates.
F.I General Comments from DOE and UWAG
F.I.I The Components of Energy Penalties
Both the Agency and the commenters agree that the total energy penalty consists of three components: 1) changes
in turbine efficiency, 2) changes in cooling water pumping requirements, and 3) changes in cooling system fan
energy requirements. The commenters make no references to other significant components, implying that no
other additional factors need to be considered.
Attachments
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§ 316(b) TDD Chapter 3 for New Facilities Attachments
In the draft report, the Agency estimated the three components and presented them separately to allow flexibility
in application and to avoid double counting. For example, the fan and pumping energy costs were incorporated
into the Agency estimates for the cooling tower O&M costs. Therefore, the notice of data availability presented
each component separately and factored them in separately, where necessary, depending on the analysis being
performed. However, from an energy output perspective (i.e., ignoring costs), the DOE comment is correct that
for the total energy penalty, all three components should be added together. The Agency intended to do this all
along.
F.I.2 Turbine Efficiency and the Presentation of Energy Penalty
The Agency agrees with DOE that the energy penalty should be expressed as a "percentage reduction in plant
output." Again, the Agency had intended to do so and, as noted by DOE, presented the pumping and fan power
components as such in the draft report. While the Agency intended for the calculated values for changes in
turbine efficiency to be representative of percent changes in plant output, the calculation method, as presented by
the Agency, unfortunately led to other interpretations. Therefore, for the sake of clarity, the Agency developed a
revised method for determining the changes in turbine efficiency, now based on turbine exhaust pressure
response curves, for the final rule. This method removes the confusion cited above but does not change results
dramatically.
F.I.3 Energy Penalties for Dry Cooling Towers and the Basis of Comparison
The draft report only addressed the energy penalty for once-through versus recirculating wet cooling towers.
Subsequent to the draft report, the Agency developed energy penalty estimates for dry towers (air cooled
condensers) for comparison to either once-through or wet tower cooling baseline systems. These estimates are
presented in section 3.1. The estimates in the draft report were for alternative cooling systems to be installed at
new facilities (in other words, they represented a change in design from once-through to wet tower cooling
systems). As such, the Agency did not consider factors that would be associated with retrofitting an existing
facility, contrary to the commenter's assertion.
F.I.4 Condenser Inlet Temperature
Both the UWAG and DOE comments noted that the Agency only considered the condenser inlet temperature.
The commenters correctly point out that condenser inlet temperature is not the only factor that will affect the
turbine exhaust pressure. However, in the Agency's view, it is the major driving factor. While condenser inlet
temperature is the starting point, temperature rise (or "range") through the condenser and the design of the
condenser will influence the exhaust steam pressure. The Agency chose cooling system design parameters that
best represent the wide range of systems recently constructed. These same design parameters are used as the
basis for the compliance cost estimates for installing recirculating wet towers. The representativeness of these
numbers will be discussed in more detail below. The trade-off is that plants with smaller temperature rises must
accomplish the cooling by using a larger volume of cooling water flow. UWAG only notes that the method
neglects the influence of condenser performance (Comment 2).
F.2 Detailed Technical Comments from UWA6
F.2.1 Turbine Exhaust Pressure, Performance, and Loading
In the Agency's view, UWAG is correct in noting that the exhaust pressure at which condensed moisture may
cause damage to the turbine will vary depending upon throttle conditions, the shape of the expansion curve, and
blade metallurgy. If the throttle settings are low (that is, the plant is operating much below capacity), then the
exhaust pressure at which damaging moisture levels may occur will be lower. Agency evaluation of energy
Attachments
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§ 316(b) TDD Chapter 3 for New Facilities Attachments
penalty focused primarily on turbines operating close to their capacity, which is supported by the results of the
Agency's data collection efforts for the final new facility rule. For instance, the Agency projects that the mean
capacity factor at new plants is approximately 85 percent (that is, near to full capacity). See the Economic
Analysis.
Condensed moisture is but one of several factors that may prevent more efficient operation at lower exhaust
pressures. Another more important factor is the dynamic losses mentioned in UWAG Technical Comment 2. As
can be seen in the turbine response graph showing turbine exhaust pressure versus turbine heat rate (included as
Attachment B to the draft report), the curve representing the maximum steam loading rates straightens and begins
to increase (that is, the efficiency decreases) as the pressure drops below approximately 1.5 inches Hg. This
efficiency decrease is, for the most part, due to dynamic exhaust losses which occur when the expansion of steam
(due to steam pressure progressively dropping through the turbine) results in an increase in the velocity of the
steam as it exits the turbine.
In general, manufacturers design steam turbines to prevent a steam velocity increase by increasing the turbine
cross-sectional area as the steam passes through the turbine. However, as the exhaust pressure approaches a
vacuum, the amount of area required at the outlet end increases rapidly and the corresponding cross-sectional
area needed increases the turbine costs such that the economic trade-off (increased cost vs. increased efficiency)
compels the designer to lose efficiency at low exhaust pressures. For standard turbines at low exhaust pressures,
the steam velocity increases and a portion of the steam energy is converted to kinetic energy (proportional to the
square of the velocity). This increase in the steam kinetic energy reduces the net amount of energy available to
the turbine. Thus, the commenters are correct: rather than condensed moisture, it is dynamic exhaust losses that
set a practical minimum exhaust pressure (at higher steam loading rates) for turbines of conventional design.
The Agency bases the final energy penalty estimates on actual turbine response curves representing the different
types of plants, rather than on theoretical calculations. The Agency developed two sets of values representing
maximum load and 67 percent load (that is, 67 percent of maximum steam load). Finally, the Agency bases its
estimates for reduced capacity at peak demand periods on the maximum load values and the estimate of mean
annual energy penalty (for the purpose of estimating economic impact over the entire year) based on the 67
percent load values. In the Agency's view, the nuclear penalty estimate based on the theoretical calculations is
validated by the turbine response curve for that facility. A comparison of this curve with the estimated penalty
curve (based on theoretical calculations) showed that the two curves were very close in value. In these estimates,
the Agency used the data from Attachment B to these comments (the turbine response curve) for the nuclear
power plant penalty estimates.
F.2.2 Optimal Turbine Back Pressures
UWAG argues that the use of 1.5 inches Hg as the optimal operating back pressure does not consider that many
U.S. plants operate below 1.5 inches Hg during substantial portions of the year. It then states that this assumption
is not likely to have a huge effect on the penalty (although it will tend to understate the penalty). As discussed
above, the 1.5 inches Hg value corresponds to turbines operating near capacity. Rather than assume that plants
will optimize the operation of the cooling system, the turbine efficiency analysis in the Agency's final energy
penalty study uses the values from the turbine response curves. Therefore, the Agency avoided setting any
minimum exhaust pressure value, about which the commenter expresses concern.
The Agency agrees with the point raised that some U.S. plants operate below 1.5 inches Hg for substantial
portions of the year. In some cases, the design of the plant does not provide for control of the cooling system (for
example, a once-through system with constant speed pumps). However, unless the plant is specifically designed
Attachments
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§ 316(b) TDD Chapter 3 for New Facilities Attachments
to operate efficiently at low pressures (with higher turbine capital costs), the turbine response curves indicate that
typical turbines operating at low exhaust pressures either operate efficiently but at well below the turbine
capacity, or operate in a less than optimal mode near full capacity. In fact, the curves suggest that turbines of
standard design operating at exhaust pressures below 1.5 inches Hg and near capacity may be experiencing an
energy penalty by not controlling the cooling system such that the exhaust pressure does not drop below the
optimum pressure. Turbines operating at low load experience improved efficiency at lower exhaust pressures,
but the diminished output tempers the overall effect. Therefore, the Agency's methodology does not
underestimate energy penalties as the commenters suggest.
F.2.3 Empirical Data Versus Subtle Effects
The Agency agrees that the estimation methodology simplifies complex relationships including subtle impacts of
turbine design. The use of empirical data simplifies the modeling of complex factors with subtle effects. This is
the fundamental approach of design engineering and is a reasonable approach for this rule.
The commenter takes exception to the Agency's perceived reliance on a cooling tower manufacturer for
comparison of its estimates. The Agency used data in Attachment C of the draft report (to which the commenter
questions) only as a benchmark value for comparison/validation. Since the Agency's estimates were derived
independently, the qualifications as a cooling tower manufacturer do not affect their validity.
F.2.4 Thermal Design Approach Values
The Agency disagrees that there is a disadvantage with using the median value (it is also the mean and the mode,
in this case) for the design approach of the model cooling tower used for the regulatory impact analysis. The data
in Attachment G of the draft report represents 45 wet cooling towers installed from 1997 through 2000 in
locations throughout the country. The Agency reviewed this data and did not discern any pattern, such as
regional trends, that would warrant use of values different than the statistical median. The Agency intended for
these estimates to support national estimates. Therefore, the Agency included regional and seasonal differences
in the cooling media (surface water, wet bulb, dry bulb) temperatures in the estimates for the final rule. Similar
to other construction projects, economic considerations, such as availability of capital and the desired time period
to recoup investment, among other factors, influence the selection of the design approach, design range, and other
design parameters. The Agency believes it is difficult to estimate these factors and variables and notes that the
commenter did not suggest a reasonable way to take these variables into consideration in the national energy
penalty estimates. In the Agency's view, the statistical median for recently constructed cooling towers
throughout the country best represents the full range of design operating conditions employed throughout the
country. In addition, the commenters do not take issue with the validity or representativeness of the data in
Attachment G to the draft report. See also Attachment C to Chapter 3 for the data supporting the Agency's
estimates of a design approach value of 10 deg F.
The Agency notes that the design approach value is for comparison to ambient wet bulb conditions and not to the
wet bulb temperature of the tower inlet, which can be slightly higher when air recirculation occurs. The Agency
also notes that air recirculation occurs intermittently and only at times when winds are high and are blowing from
a direction perpendicular (broadside) to the tower orientation. Where possible, towers, in their design, are
oriented so as to minimize this effect. In general, the installed tower is certified by the manufacturer to perform
within the design specifications with a wind velocity of up to 10 mph (Hensley 1985) . Thus, the tower size and
other design criteria that apply to the towers used in the cost estimates do include consideration of air
recirculation.
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The commenters take issue with the use of a constant approach value throughout the year. The approach value
that the Agency used for the draft report represents design conditions which generally apply to the worst-case
design (i.e., summer) conditions. As such, the use of a constant value throughout the year will not result in
inaccurate estimates for the maximum penalty value. After further review of this issue, the Agency agreed that
the commenters are correct that it is inappropriate to use the design approach value for estimating the average
energy penalty throughout the year. EPA has found within the suggested reference (Hensley 1985) a graph for
the relation between wet bulb temperature and cold water temperature for a tower that can be used as the basis
for estimating the approach at wet bulb temperatures other than the design temperature. The revised penalty
estimates in the final report incorporate this suggestion for estimating seasonal changes in the approach values.
F.2.5 Turbine Exhaust Pressure and Cooling Water Inlet Temperatures
For the final energy penalty report, the Agency investigated whether the Heat Exchange Institute Standards for
Steam Surface Condensers assist in more "precisely" estimating the relationship between turbine exhaust
pressure and cooling water inlet temperatures. The Agency notes that a revised method would in itself require
assumed values (for example, condenser heat transfer coefficient, number and arrangement of tubes, etc.) that
given the nature of the comments are then subject to the same arguments made by the commenter that they do not
represent the full variety of condenser designs being employed. In the end, the revised method suggested by the
commenter generated very similar results to EPA's method in the draft report, and, therefore, was not used.
F.2.6 Fan Energy Requirements
UWAG implicitly agrees with the EPA methodology for estimating wet cooling tower fan energy requirements.
The commenters only take issue with using an "optimistic" motor efficiency of 95 percent instead of 92 percent,
and failure to include a factor for fan gear efficiency (typically 96 percent). The factors used in the draft report,
including a fan usage factor of 93 percent, were obtained from a cooling tower manufacturer (Fleming 2001).
Incorporation of the UWAG suggestions increased the fan energy component by a total of 7.6 percent of a
component that itself is less than 1 percent of plant output. Regardless, the Agency incorporated the factors
suggested by the commenter.
F.2.7 Recirculoting Water Pumping Velocity
UWAG's comments dispute the use of a cooling water velocity of 5.7 ft/s in the circulating water pipes, reporting
that their past observation was that cooling water velocities in all three types of power plants were in the range of
8 to 11 ft/s. EPA notes that the 5.7 ft/s value was used as the minimum design starting point. The draft report
showed that the results of piping designs resulting in three different flow velocities of 5.8, 7.7, and 11.6 ft/s,
along with three different piping distances, were used in the analysis.
As a follow-up, the Agency contacted a Bechtel power systems engineer to obtain typical values for pumping
head and learned that a 50 ft total pumping head was typical for a once-through system (Taylor 2001). The
notice of data availability analysis shows that for a pumping distance of 1,000 ft, the total calculated pumping
heads were 49 ft and 58 ft at pipes sized to produce velocities of 7.7 and 11.6 ft/s, respectively. These values
compare favorably with the Bechtel estimate. Final Agency estimates for once-through pumping costs use this 50
ft pumping head value.
F.2.8 Static Head
UWAG states that the two static head values assumed by the Agency are inaccurate based upon reference to
Power Engineering sources. The commenters did not specify in what way the values used by the Agency were
inaccurate except to imply (as indicated in comment 10 below) that they may be overstated. The Agency
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§ 316(b) TDD Chapter 3 for New Facilities Attachments
reviewed the cited reference (Handbook of Energy Systems Engineering) to see if useful data was available for
inclusion in the final analysis. As such, the implication made by commenters, as elsewhere, is that Agency's
draft report estimates would tend to understate the penalty.
After review of the data, the Agency determined that it disagrees with the assertion made by the commenter
regarding understated static head values. The Agency estimates that the siphon will continue from pump inlet to
an open channel outlet, and, as a consequence, the static head would be the elevation difference between these
two. In many cases this static head difference would be relatively small. Thus, the Agency's estimates of static
head in the notice of data availability are reasonable. The Agency also notes that the static head is a site-specific
value.
F.2.9 Gravity Versus Siphon Flow of Cooling Water
The commenters contest the Agency's estimate that cooling water will flow by gravity back to the source. The
Agency was aware of the use of the siphon effect (with vacuum pumps at the high point) in condenser piping, but
was not certain of its wide-spread use and therefore did not include it in the analysis for the notice of data
availability. The estimate was intended to produce a more conservative (i.e., higher) pumping head. In this case,
the effect of the estimate for gravity flow was a conservative estimate.
The Agency subsequently obtained information concerning head losses within condensers (Hess 2001). The
pumping head component for condenser loss in the final estimates reflects consideration of this data. The
addition of condenser losses offset the reduction in static head that results from the siphon effect outlined above.
This appears to explain why, despite the comments, that the draft report estimates for total pumping head are
similar to the estimate provided by Bechtel (Taylor 2001).
F.2.10 Pumping Head as a Function of Tower Height
UWAG disagrees with the pumping head estimates for cooling towers in the notice of data availability report,
citing the Agency's lack of varying the tower height, using a small dynamic head, and neglecting to include
losses in the tower spray nozzles. The Agency's based the pumping head calculations on a single cooling water
flow value and therefore it is not necessary to consider variations in the tower height. The Agency chose a single
tower design and a total pumping head value for an actual tower reported by a tower manufacturer (Fleming
2001) which included all of these pumping head components in combination. The tower chosen is actually sized
for a slightly more conservative flow than that used in the calculations. Therefore, the tower design
specifications are consistent with the tower design used in other energy penalty components and in the cost
analysis.
F.2.11 Plant Operating Capacity
The commenters are correct that at times when the plant is operating near its engineering or regulatory limits, the
penalty will effectively reduce capacity. They also point out that the energy penalty is not just an economic
concern (that is, the penalty will require use of additional fuel or purchase of replacement power), but can also
limit plant capacity during peak demand periods. However, this comment has no bearing on the penalty estimates
themselves. The Agency also notes that for wet cooling tower systems, the magnitude of even the peak-summer
shortfall penalties do not approach a level that will impact plant capacity at peak demand periods. The
commenters make a similar statement in Appendix C of their comments to the notice availability. The same is
not true for dry cooling systems, based on the Agency's estimates.
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F.2.12 Turbine Efficiency Adjustment Factors
The turbine efficiency estimation methodology used in the final energy penalty analysis eliminates the need to
use the 17 percent factor to which the commenters object. However, the Agency's final method continues to
estimate that the steam turbine contributes approximately 1/3 of the total plant capacity for a combined-cycle
plant. The commenters did not take issue with the 1/3 capacity assumption.
F.2.13 Fan and Pumping Costs
The Agency wishes to clarify the estimated fan and pumping costs, in particular, the use of an electricity cost of
$0.08/kWh rather than $0.03-$0.04/kWh. The Agency uses an electricity cost value that represents the average
cost to the consumer. This value was chosen as a conservative value (on the high side) to ensure that the
estimates compensated for other minor O&M cost components associated with the operation of the cooling fans
and pumps that the Agency has not directly included.
F.3 Conclusions Regarding Public Comments
The Agency, as described above, fully considered the substance of the comments submitted and has incorporated
revisions in its final analysis based on a portion of the arguments, as noted. However, the Agency notes that the
commenters generally did not present detailed data to support their positions or that would assist the Agency in
revising its estimates. In turn, the Agency sought out additional reference material from a variety of sources, in
addition to some references cited by the commenters, to determine the most accurate final estimates possible.
These references are included in the record for the final rule.
Many of the comments take issue with the simplification of a very complex system. One of the greatest
challenges of this effort for the Agency was to balance the many design and operating variables that apply to a
variety of design-specific conditions with the need to develop national estimates that are valid for all of these
situations. Thus, where possible, the Agency employed statistical estimates and empirical data to best represent
the site-specific conditions and engineering relationships. The Agency points to the DOE comment which states
that the draft report methodology "is an approach based on historical correlations, but for most plants and
locations it is approximately correct." After incorporation of the revisions outlined above (which the Agency
conducted in response to comment and for confirmatory reasons) the Agency's final energy penalty estimates are
reasonable and defensible national estimates.
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§ 316(b) TDD Chapter 4 for New Facilities
Dry Cooling
Chapter 4: Dry Cooling
INTRODUCTION
This chapter addresses the use and performance of dry
cooling systems at power plants. Dry cooling systems
transfer heat to the atmo sphere withoutthe 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. Indirect dry cooling generally
applies to retrofit situations at existing power plants
because a water-cooled condenser would already be in
Therefore, indirect dry cooling systems are not further
regulation.
Chapter Contents
4.1 Demonstrated Dry Cooling Projects 4-2
4.2 Impacts of Dry Cooling 4-2
4.2.1 Cooling Water Reduction 4-6
4.2.2 Environmental and Energy Impacts .... 4-6
4.2.3 Costs of Dry Cooling 4-6
4.2.4 Methodology for Dry Cooling Cost
Estimates 4-8
4.2.5 Economic Impacts 4-8
4.3 Evaluation of Dry Cooling as BTA 4-13
References 4-14
place for a once-through or recirculated cooling system.
considered in the Chapter for new sources subject to this
The most common type of direct dry cooling systems (towers) for new power plants are recirculated cooling systems
with mechanical draft towers. Natural draft towers are infrequently used for installations in the United States and
were not considered for evaluation in this Chapter.
For dry cooling towers the turbine exhaust steam exits directly to an air-cooled, fmned-tube condenser. The
arrangement of the finned tubes are most generally of an A-frame pattern to reduce the land area required. 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. 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 larger than would be used in a mechanical draft wet cooling tower.
Hybrid wet-dry cooling towers employ both a wet section and dry section and are used primarily to reduce or
eliminate the vapor plumes associated with wet cooling towers. For the most common type of hybrid system,
exhaust steam flows through smooth tubes, where it is condensed by amixture of cascading water and air. The water
and air move in a downward direction across the tube bundles and the air is forced upward for discharge to the
atmosphere. The falling water is collected and recirculated, similarly to a wet cooling tower. The water usage of
a hybrid system is generally one-third to one-half of that for a wet cooling system and the required pumping head
is reduced somewhat. In the Agency's opinion, the common hybrid systems do not dramatically reduce water use
as compared to wet cooling towers. The comparative cost increases of the hybrid systems to the wet cooling systems
do not outweigh water use savings of approximately one-half to two-thirds. Therefore, the discussion of dry cooling
towers for the remainder of the chapter focuses on direct dry cooling systems exclusively.
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
principle on evaporative cooling as does a wet cooling tower, larger volumes of air must be passed through the
4-1
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§ 316(b) TDD Chapter 4 for New Facilities Dry Cooling
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%.
The remainder of this chapter is organized as follows:
*• Section 4.1 provides a brief overview of the status of dry cooling projects in the United States including
discussion of the types of generating facilities, their locations, and factors affecting plant performance.
*• Section 4.2 presents an evaluation of the dry cooling technology as a candidate for best technology available to
minimize adverse environmental impact.
4.1 DEMONSTRATED DRY COOLINS PROJECTS
This section provides a brief overview of the status of dry cooling projects in the United States. The section includes
a brief discussion of the types of generating facilities, their locations, and factors affecting plant performance.
Dry cooling has been installed atavariety 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. As demonstrated in Chapter 3, the
comparative energy penalty of a dry cooling plant in a hot environment at peak summer conditions can exceed 12
percent, and the benefit of the water use savings must be analyzed with regard to the reduced cooling efficiency.
Table 4-1 presents a compilation of data pertaining to dry cooling systems installed at power plants within the United
States and in foreign countries by a U.S. dry cooling system manufacturer from 1968 through the year 2000. The
majority of these systems have been installed at combined cycle plants and at alternative fuel plants such as municipal
solid waste and waste wood burning facilities. In many cases, systems with similar design dry bulb temperatures
have different design exhaust pressure values, reflecting the selection of different dry tower sizes by the facility
owners. Use of different relative dry tower sizes for similar facilities reflects the selection of different economic
criteria with respect to size, costs, and efficiency.
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§ 316(b) TDD Chapter 4 for New Facilities
Dry Cooling
Table 4-1: Air
' acility Name
City
Cooled
State
Condenser Data for Systems installed by £EA Power Cooling Systems, Inc. i|
Country
Size Steam Flow Turbine Design
MW Ibs/hr Exhaust Temp.
Pressure °F
Year Description Sat. Temp. 1
Steam Difference!
Temp. °F 1
In. Hg
•leil Simpson I Sta.
•JP Potter
Vyodak Sta.
jerber Cogen
•IAS North Is. Cogen
•TTC Cogen
Chinese Sta.
)uchess Cnty. RRF
Jherman Sta.
)lmstead Cnty. WTE
Chicago Northwest WTE
5EMASS WTE
laverhiU RRF
^ochrane Sta.
jrumman
•forth Branch Power Sta.
Jayreville Cogen Pro.
Sellingham Cogen Pro.
Spokane RRF
ixeter Energy L.P. Pro.
'eel Energy from Waste
•Tipogen Power Plant
linden Cogen Pro.
^laalaea Unit 15
•Torcon Welsh Plant
Jniv of Alaska
Jnion County RRF
Jaranac Energy
)nondaga County RRF
•leil Simpson II Sta.
jordonsville Plant
)utchess County RRF Exp.
Jamalayuca II Power Sta.
'otter Station
Gillette
Braintree
Gillette
Gerber
Coronado
San Diego
China Camp
Poughkeepsie
Sherman Station
Rochester
Chicago
Rochester
Haverhill
Cochrane
Bethpage
North Branch
Sayreville
Bellingham
Spokane
Sterling
Brampton
Nipogen
Linden
Main
North East
Fairbanks
Union
Saranac
Onondaga
Gillette
Gordonsville
Poughkeeksie
Samalayuca
Potter
WY
MA
WY
CA
CA
CA
CA
NY
ME
MN
IL
MA
MA
Ont.
NY
WV
NJ
MA
WA
CT
Ont.
Ont.
NJ
HI
PA
AK
NJ
NY
NY
WY
VA
NY
Ont.
USA
USA
USA
USA
USA
USA
USA
USA
USA
USA
USA
USA
USA
CAN
USA
USA
USA
USA
USA
USA
CAN
CAN
USA
USA
USA
USA
USA
USA
USA
USA
USA
USA
MEX
CAN
20
20
330
3.7
4
2.6
22.4
7.5
20
1
1
54
46.9
10.5
13
80
100
100
26
30
10
15
285
20
20
10
50
80
50
80
50
15
210
20
167,550
190,000
1,884,800
52,030
65,000
40,000
181,880
50,340
125,450
42,000
42,000
407,500
351,830
90,000
105,700
662,000
714,900
714,900
153,950
196,000
88,750
169,000
1,911,000
158,250
150,000
46,000
357,000
736,800
258,000
548,200
349,150
49,660
1,296,900
181,880
4.5
3.5
6
2.03
5
5
6
4
2
5.5
3.5
5
3
5.4
7
3
3
2
2.9
4.5
3
2.44
6
2.5
6
8
5
3
6
6
5
7
3.8
75
50
66
48
70
70
97
79
43
80
90
59
85
60
59
90
59
59
47
75
68
59
54
95
55
82
94
90
70
66
90
79
99
66
1968 Coal
1975 Combine Cycle
1977 Coal
1981 Combined Cycle Cogen
1984 Combined Cycle Cogen
1984 Combined Cycle Cogen
1984 Waste wood
1985 WTE
1985 Waste Wood
1985 WTE
1986 WTE
1986 WTE
1987 WTE
1988 Combined Cycle Cogen
1988 Combined Cycle Cogen
1989 Coal
1989 Combined Cycle Cogen
1989 Combined Cycle Cogen
1989 WTE
1989 PAC System
1990 WTE
1990 Combined Cycle Cogen
1990 Combined Cycle Cogen
1990 Combined Cycle
1990 Combined Cycle Cogen
1991 Combined Cycle Cogen
1991 WTE
1992 Combined Cycle Cogen
1992 WTE
1992 Coal
1 993 C-Cycle(x2 Units)
1993 WTE
1993 Combined Cycle
1993 Combined Cycle
°F
130
120
141
102
134
134
141
126
102
138
120
134
115
137
147
115
115
102
114
130
115
108
141
109
141
152
134
115
141
141
134
147
124
1
55 1
70 1
75 1
54 1
64 1
64 1
44 1
47 1
59 1
58 1
61 1
49 1
55 1
78 1
57 1
56 1
56 1
55 1
39 1
62 1
56 1
54 1
46 1
54 1
59 1
58 1
44 1
45 1
75 1
51 1
55 1
48 1
58 |
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§ 316(b) TDD Chapter 4 for New Facilities
Dry Cooling
Table 4-1: Air Cooled condenser Data for Systems installed by GtA Power Cooling Systems. Inc.
'acility Name
City
State
Country
Size
MW
Steam Flow
Ibs/hr
Turbine
Exhaust
Pressure
In.Hg
Design
Temp.
°F
Year Description
Sat. Temp.
Steam Difference |
Temp. °F
°F
Jtreeter Generating Sta.
*lacArthur RRF
forth Bay Plant
Capuskasing Plant
laverhill RRF Exp.
^.rbor Hills Landfill Gas Fac.
ine Bend Landfill Gas Fac
>ine Creek Power Sta.
^abo Negro Plant
meraldas Refinery
Mallard Lake Landfill Gas
liyadh Power Plant 9
Jarry CHP Project
'orlu Enerji Project
"ucuman Power Sta.
)ighton Power Project
1 Dorado Energy
"iverton Power Project
'oryton Energy Project
lumford Power Project
Ylillmerran Power Project
Jajio Power Project
Monterrey Cogen Project
jelugor Power Station
'ront Range Power Project
joldendale Energy Project
Athens Power Station
Cedar Falls
Ronkonkoma
North Bay
Kapuskasing
Haverhill
Northville
Eden Prairie
Pine Creek
Punta Arenas
Emeraldas
Hanover Park
Riyadh
Barry
Bursa
El Bracho
Dighton
Boulder
Tiverton
Corringham
Rumford
Toowoomba
Quertetaro
Monterrey
Penang
Fountain
Goldendale
Athens
IL
S. Wales
Tucuman
MA
NV
RI
ME
Queensland
Guananjuaro
USA
USA
CAN
CAN
USA
USA
USA
AUSTRAILIA
CHILE
EQUADOR
USA
SAUDI
ARABIA
UK
TURKEY
ARGENTINA
USA
USA
USA
ENGLAND
USA
AUSTRAILIA
MEX
MEX
MALAYSIA
USA
USA
USA
TiGH EXHAUST PRESSURE (Temperature Difference >80 °F)
Jeneccia Refinery Beneccia CA USA
MugaUnitS Beluga AK USA
250
246,000
40,000
245,000
245,000
44,500
87,309
58,260
95,300
74,540
123,215
101,400
966,750
596,900
83,775
1,150,000
442,141
1,065,429
549,999
1,637,312
545,800
2,050,000
1,307,000
671,970
946,600
1,266,477
678,000
749,183
Average
Min
Max
NA
65
48,950
478,400
1993 Coal-PAC System
1993 WTE
1994 Combined Cycle
1994 Combined Cycle
1994 WTE
1994 Combined Cycle
1994 Combined Cycle
1994 Combined Cycle
1995 Methanol Plant
1995 Combined Cycle
1996 Combined Cycle
1996 C-Cycle(x4 Units)
1996 Combined Cycle
1997 Combined Cycle
1997 PAC System
1997 Combined Cycle
1998 Combined Cycle
1998 Combined Cycle
1998 Combined Cycle
1998 Combined Cycle
1999 Coal (x 2 Units)
1999 Combined Cycle
1999 Combined Cycle Cogen.
2000 Combined Cycle Cogen.
2000 Combined Cycle
2000 C-Cycle PAC System
2000 Combined Cycle
1975
1979 Combined Cycle
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§ 316(b) TDD Chapter 4 for New Facilities Dry Cooling
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, a larger, more
costly dry cooling system will produce a smaller temperature difference across the condenser and, therefore, a lower
turbine exhaust pressure. Three facilities in Table 4-1 had high temperature differences (>80 °F), which represent
less efficient systems. Two of these facilities are from very cold climates where high temperature differences across
the condenser are acceptable and one was for an industrial process (petroleum refining). The range in the
temperature difference values for the remaining facilities was 35 to 78 °F. The average was 54 °F.
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. New steam
turbine facilities that are designed to condense steam with dry cooling systems can be equipped with steam turbines
that are designed to be safely operated at higher exhaust pressures. EPA has assumed that the difference in costs for
turbines that operate over different exhaust pressure ranges are insignificant compared to the total compliance cost
and, therefore, no net compliance costs are estimated for the steam turbines.
The data in Table 4-1 shows that turbine exhaust pressures at the highest design dry bulb temperatures in the U.S.
(which were around 100 °F) 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
show 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!2 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 3.5 inches
Hg(Woodruff 1998).
For coal-fired plants, the largest operating 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 10 of the projected coal-fired power plants within the scope of the rule and slightly smaller than 25 of the
combined cycle plants. The design temperature of the dry 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, whereas recent combined-cycle systems in Rhode Island, Massachusetts, and New
York have design targets above 90 deg F). EPA notes that the reported driving force behind the Wyodak Station's
decision to utilize dry cooling was the fact that the plant designers wished to locate the plant immediately adjacent to
a remote coal-mine mouth.
A demonstrated dry cooling system frequently recognized as the largest in the U.S. is the Linden Cogeneration Plant,
in NJ. This cogeneration unit has a comparable cooling capacity to that of a small-sized coal-fired facility (such as
the Wyodak Station described above). The cogeneration plant has a total steam flow which requires condensing of
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§ 316(b) TDD Chapter 4 for New Facilities Dry Cooling
1.91 million Ib/hr, which just slightly exceeds the steam flow of the Wyodak station (1.88 million Ib/hr). Despite the
fact that the Linden plant is designed for a total generating capacity of 640 MW, only 285 MW requires steam
condensing. This is because cogeneration units are designed to deliver steam to adjacent manufacturing plants for
their use in processes. Therefore, the cogeneration plant has been designed such that only a portion of its steam
generation requires cooling, and, for the purposes of evaluating the feasibility of dry cooling, EPA considers this a
285 MW dry cooling facility. EPA notes that the decision for this plant to adopt dry cooling over wet cooling related
primarily to a highway safety issue and the visible plume of steam.
Several new combined-cycle projects with dry cooling are either planned or under-construction in the Northeastern
US. EPA is aware of eight new dry cooling projects at combined cycle plants in this region that have 350 MW or
greater of total plant capacity. The largest of these projects is the permitted Sithe Mystic Station in Massachusetts,
which will be a 1500 MW combined-cycle plant. Because the project will utilize a combined-cycle, approximately
500 MW of steam power would require cooling. This will be the largest dry cooling system in the US when complete.
However, the system size does not approach the projected cooling requirements for amajority of the coal-fired plants
within the scope of this rule.
4.2 IMPACTS OF DRY COOLINe
In establishing best technology available for minimizing adverse environmental impact for the final rule, EPA
considered an alternative based on a zero-intake flow (or nearly zero, extremely low flow) requirement commensurate
with levels achievable through the use of dry cooling systems. In evaluating dry cooling-based regulatory alternatives,
EPA analyzed a zero or nearly zero intake flow requirement based on the use of dry cooling systems as the primary
regulatory requirement in all waters of the U.S. The Agency also considered subcategorization strategies for the new
facility regulation based on size and types of new facilities and location within regions of the country, since these
factors may affect the viability of dry cooling technologies. In its evaluation, the Agency considered factors including
the demonstration of existing or planned dry cooling systems, the reductions in cooling water intake flow, the
environmental and energy impacts, and the associated costs of dry cooling systems.
4.2.1 Cooling Water Reduction
A dry cooling system will achieve an average reduction in cooling water intake flow greater than 99 percent over a
once-through system. In comparison, the average flow reduction of a closed-cycle wet cooling system for an
estuarine/tidal source is approximately 92 percent, and is 95 percent for a freshwater source. Dry cooling systems
therefore achieve an incremental flow reduction from closed-cycle wet cooling to dry cooling of 4 to 7 percent.
4.2.2 Environmental and Energy Impacts
Dry cooling has the benefit of eliminating visual plumes, fog, mineral drift, and water treatment and disposal issues
associated with wet cooling towers. The disadvantages of dry cooling include an increase in noise generation and
decrease in efficiency of electricity generation which lead to an increase in air emissions as compared to wet cooling
systems.
EPA notes that dry cooling systems in all climates are less efficient at removing heat than comparable wet-cooling
systems. The practical limitations of the dry cooling system, as limited by the dry bulb temperature, which is always
equal to or greater than the wet bulb temperature met by wet cooling systems, prevent its performance from exceeding
4-6
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§ 316(b) TDD Chapter 4 for New Facilities Dry Cooling
that of wet cooling. Moreover, increased parasitic fan loads for dry cooling systems will ensure that the technology
will not operate as efficiently as a comparable wet cooling system.
Therefore, EPA assessed the negative environmental impacts caused by this loss of efficiency. For combined-cycle
plants the mean annual energy penalty (averaged across climates) is 2.1 percent for dry cooling compared to
once-through systems, and 1.7 percent for wet cooling compared to once-through systems. For coal-fired plants,
the mean annual energy penalty (averaged across climates) is 8.6 percent for dry cooling compared to once-through
systems, and 6.9 percent for wet cooling compared to once-through systems. However, for many specific cases, the
energy penalty may be dramatically higher for dry cooling due to climatic conditions of the cooling towers. For
example, the peak summer shortfalls during hot periods can be debilitating in certain climates due to the energy
penalty reaching up to 12.3 percent. See Chapter 3 of this document for further discussion of energy penalties.
EPA projects that a dry cooling based regulatory alternative would result in 1900 MW of lost energy. This is the
equivalent electricity generation of two very large (or three large) power plants that would need to be constructed to
overcome the energy losses of the dry cooling alternative. The air emissions increases as a result of this replacement
capacity, if they were to come from increased generation across the US market, would be equivalentto those of three
new 800MW coal-fired power plants. Alternatively, if the replacement capacity comes from new capacity exclusively,
it would be from dry cooling equipped plants with the associated elevated capital and annual costs and land area
requirements. Therefore, EPA considers the issue of inefficiency of dry cooling, and EPA's subsequent rejection of
the dry cooling alternative, to be principal to the concept of energy conservation. Considering that the State of
California recently experienced shortages of demand less than the energy penalty of the dry cooling option, the
imposition of 1900 MW of mean annual energy penalty capacity loss on planned new power plants does not support
the Administration's Energy Plan and associated Executive Orders.
The efficiency of the electricity generation process is directly affected by the cooling system to be installed. The vast
majority of projected new plants (i.e., 90 percent) would install closed-cycle recirculating cooling towers regardless
of the requirements of this rule. Therefore, EPA's technology-based performance requirements for the final rule
based on recirculating closed-cycle cooling would have little impact on the majority of new plants. The flow
reduction requirements of the rule are projected to impose changes in cooling system designs on only nine new plants.
The comparable effect on the efficiency of these plants will be small on a facility level and national basis.
In contrast, a regulatory alternative based on dry cooling is projected to impose cooling system design changes on
each of the 83 power plants within the scope of the final rule. Therefore, each of the 14 projected coal-fired plants
would experience mean annual energy penalties ranging from 6.9 to 8.6 percent. The typical steam electric generator
(such as modern coal-fired plants) would, at peak operation, operate at less than 40 percent efficiency. The energy
penalty of nearly 9 percent is very significant when compared to the system-wide energy efficiency of this type of
power plant. Additionally, each of the 69 projected new combined-cycle plants would experience mean annual energy
penalties ranging from 1.7 to 2.1 percent. With new design efficiencies of 60 percent, at peak operating efficiency,
a 2.1 percent energy penalty is less striking than in the coal-fired cases. However, the cumulative effect for all 69
power plants is substantial.
4.2.3 Costs of Dry Cooling
The final rule analysis, which includes the contribution of the energy penalty to the recurring annual costs, projects
that the total annualized cost for the dry cooling alternative is $490 million (in 2000 dollars). EPA notes that the vast
majority of costs associated with this option are incurred at the 83 power plants, and not at the 38 manufacturers
subject to this rule. Because dry cooling is not a feasible option for all manufacturing facilities, EPA only applied
4-7
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§ 316(b) TDD Chapter 4 for New Facilities Dry Cooling
costs of recirculating wet cooling towers to these types of facilities. The present value of total compliance costs for
drying cooling are projected to be $6 billion.
A comparison of capital costs between equally sized combined-cycle plants for wet and dry cooling tower systems
reveals that the dry cooling plant's capital costs would exceed those of the wet cooling tower plant by 3.3 fold. The
installed wet cooling tower capital cost is approximately $10 million, while the dry cooling installation would cost
approximately $33 million. For atypical, modern 700-MW combined-cycle power plant, the erected capital costs for
a wet cooling tower represent approximately 2 percent of the total capital costs of the power plant construction proj ect
compared to 6.5 percent for dry cooling towers.
EPA also evaluated a comparison of the operation and maintenance costs associated with these two types of cooling
systems for an equally sized combined-cycle model plant. The operation and maintenance costs of the wet cooling
tower (without including the effects of energy penalties) would be $1.8 million per year, while the dry cooling system
would cost $7.4 million per year. Without incorporating energy penalties, the ratio of operation and maintenance
costs of dry cooling to wet cooling for a typical 700-MW combined-cycle power plant would be greater than 4 to 1.
After factoring in the recurring costs of energy penalties for the two systems, the recurring annual costs increase to
$2.3 million for the wet tower plant and $10.4 million for the dry cooling plant. This corresponds to a dry to wet ratio
also greater than 4 to 1. The total annualized costs for this model facility are estimated at $3.1 for the wet cooling
tower system and $ 13.1 for the dry cooling system (a ratio of 4.2 to 1). Note that these are comparative cost estimates
for a hypothetical facility and do not represent actual compliance costs of the rule.
4.2.4 Methodology for Dry Cooling Cost Estimates
EPA estimated the capital and O&M costs using relative cost factors for various types of wet towers and air cooled
condensers, using the cost of a comparable wet tower constructed of Douglas Fir as the basis. Chapter 2 provides
the capital and operating cost factors that were used by EPA. These cost factors were developed by industry experts
who are in the business of manufacturing, selling and installing cooling towers, including air cooled systems, for
power plants and other applications. For air cooled condensers (constructed of steel), a range of cost factors is given
in Table 4-3. EPA based the capital and O&M 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 presented in Table 4- 2.
Note that the source document for these factors 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 final §316(b) New Facility Rule 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.
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§ 316(b) TDD Chapter 4 for New Facilities
Dry Cooling
Table 4-2: Estimated Capital Costs of Dry Cooling
Towers with Delta of 5 °F and 10 °F (1999 Dollars)
Flow
(gpm)
2000
4000
7000
9000
11,000
13,000
15,000
17,000
18,000
22,000
25,000
28,000
29,000
31,000
34,000
36,000
45,000
47,000
56,000
63,000
67,000
73,000
79,000
94,000
102,000
112,000
146,000
157,000
204,000
250,000
300,000
350,000
400.000
Delta 5 °F
Delta 10 °F
$790,000
$1,580,000
$2,766,000
$3,556,000
$4,345,000
$5,135,000
$5,925,000
$6,715,000
$7,108,000
$8,515,000
$9,675,000
$10,836,000
$11,222,000
$11,996,000
$13,156,000
$13,933,000
$17,059,000
$17,817,000
$21,229,000
$23,881,000
$25,399,000
$27,674,000
$29,325,000
$34,892,000
$37,859,000
$41,574,000
$54,194,000
$57,034,000
$72,498,000
$100,800,000
$120,000,000
$140,400,000
.800.000
$450,000
$949,000
$1,658,000
$2,132,000
$2,607,000
$3,081,000
$3,556,000
$4,027,000
$4,264,000
$5,038,000
$5,727,000
$6,412,000
$6,643,000
$7,101,000
$7,787,000
$8,245,000
$9,952,000
$10,394,000
$12,383,000
$13,933,000
$14,817,000
$16,143,000
$16,845,000
$20,043,000
$21,749,000
$23,881,000
$31,132,000
$32,237,000
$40,277,000
$58,800,000
$70,000,000
$81,900,000
.800.000
Using the estimated costs, EPA developed cost equations using a polynomial curve fitting function. Table 3 presents
capital cost equations for dry towers with deltas of 5 and 10 degrees.
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§ 316(b) TDD Chapter 4 for New Facilities Dry Cooling
Table 4-3. 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-1 Ix3 + O.OOOlx2 + 189.77x + 800490
R2 = 0.9989
R2 = 0.9979
1) x is for flow in gpm and y is cost in dollars.
Delta
For purposes of estimating costs for the dry cooling option (Option 2B) for the final §316(b) New Facility Rule, EPA
used the O&M cost curve for air condensers contained in Appendix A of the Economic and Engineering Analyses
of the Proposed §316(b) New Facility Rule without modification. Thus, EPA overcosted the O&M costs for dry
towers for Option 2B for the final §316(b) New Facility Rule. See Section 2.9.1 of this document and the response
to comment document (#316bNFR.068.330) for discussion of EPA's revised O&M costs for the final rule.
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 projects 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, dependenton 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.
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.
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§ 316(b) TDD Chapter 4 for New Facilities
Dry Cooling
Chart 4-1. Capital Costs of Dry Cooling Towers Versus Flows Of Replaced Wet 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
$60,000,000
$40,000,000
$20,000,000
y = -2E-1 Ox3 + 0.0002X2 + 337.56x + 973608
R2 = 0.9989
Cooling Tower Cost for a
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 Flow GPM
Dry Cooling Delta 5 x Dry Cooling DeltalO
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§ 316(b) TDD Chapter 4 for New Facilities
Dry Cooling
Chart 4-2. Actual Capital Costs of Dry Cooling Tower Projects and Comparable Costs from EPA
Cost Curves
$140,000,000
$120,000,000
$100,000,000
•55 $80,000,000
o
o
&
Q.
Q $60,000,000
$40,000,000
$20,000,000
$0
y = -8E-11X3 + O.OOOIx2 + 189.77x + 800490
R2= 0.9979
y = 0.0025x18686
R2 = 0.7841
100000
200000 300000
Equivalent Wet Cooling Flow GPM
400000
X Dry Cooling Costs Used in EEA • Actual Dry Cooling Project C<
500000
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§ 316(b) TDD Chapter 4 for New Facilities Dry Cooling
4.1.6 Economic Impacts of Dry Cooling
EPA concluded that the costs of dry cooling systems may be significantly prohibitive so as to pose barriers to entry
for some new plants. EPA projected that the cost to revenue impacts exceed 10 percent for 12 new power plants and
exceed 4 percent for all new plants under a dry cooling-based regulatory alternative. EPA considers this level of cost
to revenue impacts to be significant. In comparison, the cost to revenue impacts of the final rule, which is based in
part on flow reduction commensurate with that achieved using recirculating closed-cycle wet cooling, do not exceed
3 percent for a single facility, and the vast majority of the impacts are below 1 percent. A complete discussion of the
cost to revenue impacts and discussion of barrier to entry analysis can be found in the Economic Analysis for the final
rule. As such, regional subcategorization options would pose similar barriers to entry for new plants in the
Northeastern United States, combined with imposing competitive disadvantages for the subset of facilities complying
with more stringent and costly standards than the other regions of the country.
EPA is concerned that the barrier to entry, high costs, and energy penalty of dry cooling systems may remove the
incentive for replacing older coal-fired power plants with more efficient and environmentally favorable new
combined-cycle facilities. By basing the requirements of the rule on dry cooling, regulated entities faced with the
prospects of building new facility power plants that are required to utilize dry cooling would, instead of beginning
or continuing with the new facility project, turn to existing power-plants (many of which are significantly aged) and
attempt to extend their operating lives further or refurbish them such that the new facility rule would not apply.
EPA notes that there have been recent advances in the efficiency of power plants, specifically combined-cycle plants,
that have many environmental advantages. Combined-cycle plants produce significantly less air emissions of NOx,
SO2, and Hg per MWh generated, use less water for condensing of steam than fossil-fueled or nuclear plants (greater
than one-half water use reduction per MWh of generation), and are significantly more energy efficient in their
generation of electricity than comparable coal-fired plants. The Agency does not wish to create disincentives for the
construction of new efficient plants such as these.
4.3 EVALUATION OF DRY COOLINS 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 representthe best technology available for a national requirement and
under the subcategorization strategies described above.
First, EPA concluded that dry cooling is not adequately demonstrated for all facilities within the scope of this
regulation. As noted previously, the majority of operating or planned dry cooling systems are located either in colder
or arid climates where the average dry bulb temperatures of ambient air is amenable to dry cooling. As demonstrated
in Chapter 3, the comparative energy penalty of a dry cooling plant in a hot environment at peak summer conditions
can exceed 12 percent at a facility, thereby making dry cooling extremely unfavorable in many areas of the U.S. for
some types of power plant types.
EPA's record demonstrates that of the demonstrated, permitted, or planned power plants in the Northeastern United
States with dry cooling, the size and capacity of these dry cooling systems is considerably smaller than that necessary
to condense the steam load for even below average sized coal-fired power plants projected within the scope of this
rule.
Dry cooling technology has a detrimental effect on electricity production by reducing energy efficiency of steam
turbines, especially in warmer climates The reduced energy efficiency of the dry cooling system will have the effect
of increasing air emissions from power plants.
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§ 316(b) TDD Chapter 4 for New Facilities Dry Cooling
Lastly, EPA concluded that the costs of dry cooling systems may be significantly prohibitive so as to pose barriers
to entry for some new plants that may discourage the construction of new, more energy efficient plants.
In addition to the technical feasibility and cost impacts of dry cooling, EPA also evaluated the expected benefits that
would be achieved by dry cooling. EPA notes that the two-track option based on reducing intake flow to a level
commensurate with wet cooling towers reduces intake flows by 92 to 95 percent over a once-through system. Dry
cooling would only reduce intake flow by an additional 4 to 7 percent. Additionally, the selected option requires
velocity and design and construction technology-based performance requirements for the remaining intake flow.
These performance requirements are expected to further decrease the negative environmental impacts of the cooling
water intake flow, thereby reducing impingement and entrainment of organisms to dramatically low levels. See
Chapter 5 for discussion of design and construction technologies to reduce impingement and entrainment.
In summary, EPA concluded that dry cooling is not technically or economically feasible for all facilities subject to
this rule, would increase air emissions due to the energy penalty, has a cost more than three times that of the selected
regulatory option, and would not significantly reduce impingement and entrainment beyond the regulatory approach
selected by EPA to offset these drawbacks. For these reasons, EPA concluded that dry cooling does not represent
the "best technology available" for minimizing adverse environmental impact.
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. and S. 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., and R. C. Swanekamp. 1998. Standard Handbook of Power Plant Engineering. 2.152 -
2.158. New York: McGraw Hill.
GEA Power Cooling System, Inc. "Direct Air Cooled Condenser Installations." Company Brochure.
GEA Thermal and Energy Technology Division. 2000. Direct Air Cooled Condenser Installations. San Diego, CA:
GEA Power Cooling Systems, Inc.
Hensley, J.C. Cooling Tower Fundamentals. 2nd Edition. The Marley Cooling Tower Company (Mission, Kansas)
1985.
Weeks, EG. www.glencanvon.net/cooling.htm Accessed May 18, 2000.
Woodruff, E.B., Lammers, H.B., Lammers, T.F. Steam Plant Operation. Seventh Edition. McGraw-Hill. New York.
1998.
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Section 316(b) TDD Chapter 5 for New Facilities
Efficacy of Cooling Water Intake Structure Technologies
Chapter 5: Efficacy of Cooling Water
Intake Structure Technologies
INTRODUCTION
5.3
5.4
5.5
Chapter Contents
5.1 Scope of Data Collection Efforts 5-1
5.2 Data Limitations 5-2
Closed-Cycle Cooling System Performance .... 5-3
Conventional Traveling Screens 5-3
Alternative Technologies 5-4
5.5.1 Modified Traveling Screens and Fish
Handling and Return Systems 5-4
Cylindrical Wedgewire Screens 5-6
Fine-Mesh Screens 5-7
Fish Barrier Nets 5-8
Aquatic Microfiltration Barriers 5-9
Louver Systems 5-10
Angular and Modular Inclined Screens 5-11
Velocity Caps 5-13
Porous Dikes and Leaky Dams 5-13
Behavioral Systems 5-14
Other Technology Alternatives 5-14
Intake Location 5-15
Summary 5-17
5.5.2
5.5.3
5.5.4
5.5.5
5.5.6
5.5.7
5.5.8
5.5.9
5.5.10
5.5.11
5.6
5.6
References 5-20
Attachment A CWIS Technology Fact Sheets
To support the Section 316(b) new facility rulemaking,
the Agency has 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 has been
used throughout the rulemaking process including
comparing specific regulatory options and their
associated costs and benefits. It provides the supporting
information for the selected alternatives, which require
wet, closed-cycle cooling systems (under Track 1) with
the option of demonstrating comparable performance
(under Track II) using alternative technologies.
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.
5.1 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., TV A) 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.
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Section 316(b) TDD Chapter 5 for New Facilities Efficacy of Cooling Water Intake Structure Technologies
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.
5.2 DATA LIMITATIONS
Because the Agency did not undertake a systematic data collection effort with consistent data collection procedures,
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 other than closed-cycle cooling and velocity reduction technologies the practicality or
effectiveness of alternative technologies 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 are required
to optimize their use.
The remainder of this chapter is organized by groups of technologies. A discussion of wet, closed-cycle cooling
tower performance is included to present the Agency's view of the likely minimum standard that Track II facilities
will be required to achieve (although each facility will have to present it's own closed-cycle system scenario). A
brief description of conventional, once-through traveling screens is also 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 at
new facilities.
5-.
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Section 316(b) TDD Chapter 5 for New Facilities Efficacy of Cooling Water Intake Structure Technologies
Finally, under Track II in the new facility rule, facilities may use habitat restoration projects as an additional means
to demonstrate consistency with Track I performance. 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.
5.3 CLOSED-CYCLE WET COOLINS SYSTEM PERFORMANCE
Under Track I, facilities are required meet requirements based on the design and installation of wet, closed-cycle
cooling systems. Although flow reduction serves the purpose of reducing both impingement and entrainment, these
requirements function as the primary entrainment reduction portion of Track I. Under Track II, new facilities must
demonstrate I&E performance comparable to 90 percent of the performance of a wet, closed-cycle system designed
for their facility. In part, to evaluate the feasibility of meeting this requirement 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.
See Section 2.3.5 of Chapter 2 of this document for further discussion of flow reduction using wet, closed-cycle
cooling.
An additional question that the Agency has considered is the feasibility of constructing salt-water make-up cooling
towers. 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) thathave 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.
5.4 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 re-impinged on the screens. Conventional traveling screens are used by approximately 60
percent of all existing steam electric generating units in the U.S. (EEI, 1993).
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5.5 ALTERNATIVE TECHNOLOGIES
5.5.1 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 recentyears, some researchers, primarily Fletcher 1996, have evaluated the factors
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 of their
fish handling system. In 1996, the facility subsequently reported an increase in juvenile weakfish impingement
survival from 58 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
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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 14 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 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.
5.5.2 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).
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Wedgewire screens may also be referred to as profile screens or Johnson screens.
Technology Performance
Wide mesh wedgewire screens have been used at 2 Ahigh 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 56 MGD
through a 10-mm screen from the Kansas River in Kansas. The system at the Jeffrey Plant has specifically 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, 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 sufficient crosscurrent in the waterbody
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to carry organisms 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 (MOO
MGD). However, they have been used at some power plants with lower intake flow requirements (25-50 MGD) that
would be comparable to a 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 would 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.
5.5.3 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 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
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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.
5.5.4 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 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.
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 J^iver 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
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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 showed316,575 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.
5.5.5 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
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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.
5.5.6 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
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 188,583 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. 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.
EPRI 2000 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,
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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
5.5.7 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 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 1980s 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.
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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 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.
5.5.8 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)
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Section 316(b) TDD Chapter 5 for New Facilities Efficacy of Cooling Water Intake Structure Technologies
• 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.
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.
5.5.9 Porous Dikes and Leaky Dams
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 finfish 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.
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Section 316(b) TDD Chapter 5 for New Facilities Efficacy of Cooling Water Intake Structure Technologies
5.5.10 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."
• 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).
5.5.11 Other Technology Alternatives
The proposed new facility rule does not specify the individual technology (or group of technologies) to be used to
minimize I&E to same levels as those achieved with the Track I requirements based, in part, on wet, closed-cycle
cooling system. 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 10-30percent. 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 would have to be used in conjunction with other technologies. EPA
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Section 316(b) TDD Chapter 5 for New Facilities Efficacy of Cooling Water Intake Structure Technologies
conservatively estimated that facilities complying with the requirements final rule would install variable
speed pumps regardless of the baseline cooling system projected for the facility. See Chapter 2 of this
document for more information.
• 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 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.
5.6 INTAKE LOCATION
Beyond design alternatives for CWISs, an operator may able to locate CWISs offshore or otherwise in areas that
minimize I&E (compared to conventional onshore locations). 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.
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Section 316(b) TDD Chapter 5 for New Facilities Efficacy of Cooling Water Intake Structure Technologies
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, 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 photo synthetic available light) typically does not extend beyond the first 100 meters (328 feet) of depth. Therefore,
inshore waters are generally more productive due to photo synthetic 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) TDD Chapter 5 for New Facilities Efficacy of Cooling Water Intake Structure Technologies
5.7 SUMMARY
Tables 5-1 and 5-2 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 can achieve comparable entrainment performance to closed-cycle
systems 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 location and timing of cooling water
withdrawals. Similarly, habitat restoration could also be used, as appropriate as needed, in conjunction with CWIS
technologies and/or locational requirements.
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Section 316(b) TDD Chapter 5 for New Facilities
Efficacy of Cooling Water Intake Structure Technologies
Table 5-1: Impingement Performance
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
Eddy stone
Lovett
J.P. Pulliam
Ludington Storage
Chalk Point
Bowline
J.R. Whiting
D.C. Cook
Oswego Steam
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
Name/Type of
Waterbody
Pacific Ocean
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
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
Notes
63% latent
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) TDD Chapter 5 for New Facilities
Efficacy of Cooling Water Intake Structure Technologies
Table 5-2: Entrainment Performance i
Site
Big Bend
Seminole
Logan
TVA (studies)
Lovett
Brunswick
Chalk Point
Kintigh
Summit
I Name/Type of j
Location ! Waterbody ! Technology
Florida i Tampa Bay ; Fine mesh traveling
Florida i River/Estuary i Fine mesh wedgewire
New Jersey i River/Estuary i Fine mesh wedgewire
Various i Fresh Water i Fine mesh traveling
New York i River/Tidal i Gunderboom
North Carolina i River/Estuary i Fine mesh traveling
Maryland i Bay/Estuary i Fine mesh wedgewire
New York i Great Lake i Fine mesh traveling
Delaware j Bay/Estuary j 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"
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Section 316(b) TDD Chapter 5 for New Facilities Efficacy of Cooling Water Intake Structure Technologies
REFERENCES
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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 Ichthyoplankton 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.
ESSA 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.
Cook Nuclear Plant, Southeastern Lake Michigan." In: Jensen, L.D. (Ed.), Third National Workshop on
Entrainment & Impingement: Section 316(b) - Research and Compliance.
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Section 316(b) TDD Chapter 5 for New Facilities Efficacy of Cooling Water Intake Structure Technologies
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
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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,
NoHYll.
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.
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Systems For Power Plant Cooling Water Intakes.
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Presented at EPRI Power Generation Impacts on Aquatic Resources Conference.
Taft, E.P. March, 1999. PSE&G Renewal Application. Appendix F. Salem Generation Station.
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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 (TV A). 1976. A State of the Art Report on Intake Technologies.
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Canaveral/Orlando Utilities Plants at Canaveral Pool.
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and Review of Section 316(b) Issues.
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with a Discussion of Factors Responsible and Possible Impact on Local Populations.
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Discharges. Prepared for State of Delaware Department of Natural Resources.
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Wedge Wire Screen Model Intake Facility. Prepared for State of Maryland, Power Plant Siting Program.
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ATTACHMENT A
CWIS Technology Fact Sheets
-------
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).
Conventional Traveling Screen (EPA, 1976)
A-2
-------
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
to 3 feet per minute and 10 to 12 feet per minute). These speeds can be increased to
handle heavy debris load.
ADVANTAGES:
Conventional traveling screens are a proven "off-the-shelf" technology that is readily
available.
LIMITATIONS:
• 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.
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Pagano R. and W.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.
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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; Paganoetal, 1977; EPA , 1976).
Modified Vertical Traveling Screens (White et al, 1976)
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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 14 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).
• 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).
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DESIGN CONSIDERATIONS:
The same design considerations as for Fact Sheet No. 1: Conventional Vertical
Traveling Screens apply (ASCE, 1982).
ADVANTAGES:
• 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.
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.
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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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Intake Screening Systems Fact 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).
fig : Richards, 4th page 419
Inclined Traveling Screens (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).
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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
• Ratio of screen velocity to bypass velocity: 1:1
• Minimum width of bypass opening: 6 inches
ADVANTAGES:
• The fish are guided instead of being impinged.
• The fish remain in water and are not subject to high pressure rinsing.
LIMITATIONS:
• 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).
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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.
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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 is used seasonally on two of four screens has
shown 84 percent reduction in entrainment compared to the conventional screen systems.
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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-
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 very 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.
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• 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:
• There are indications that fine mesh screens reduce entrainment.
LIMITATIONS:
• Fine mesh screens may increase the impingement of fish, 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
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., 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.
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.
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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.
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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.
mitre report
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Schematic of Cylindrical Wedgewire Screen (Pagano et al, 1977)
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 (EPRI 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 (EPRI, 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 (EPRI, 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 of fish 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
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:
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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).
ADVANTAGES:
Wedgewire screens have been demonstrated to reduce impingement and entrainment in
laboratory and prototype field studies.
LIMITATIONS:
• 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.
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
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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.
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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 Ichthyoplankton Through Wedge-
Wire Screens. Martin Marrietta Environmental Studies, Columbia MD. August 1984.
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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).
(Figure ASCE page 79).
Perforations and Slots in Perforated Pipe (ASCE, 1982)
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.
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• 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.
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.
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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).
Porous Dike (Schrader and Ketschke, 1978)
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
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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.
ADVANTAGES:
• Dikes can be used at marine, fresh water, and estuarine locations.
LIMITATIONS:
• The major problem with porous dikes comes from clogging by debris and silt, and
from fouling by colonization of fish 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).
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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.
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.
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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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.
Top view of a Louver Barrier with Fish By-Pass (Hadderingh, 1979)
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
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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 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
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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.
• 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,
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• 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).
• 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.
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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. 106
Hyll (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.
Environmental Protection Agency, Washington, D.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. et al. 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).
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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 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," Ichthyol. 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
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Fisheries, Olympia, Washington (1967).
Watts, F.J., "Design of Culvert Fishways." University of Idaho Water Resources Research Institute
Report, Moscow, Idaho (1974).
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.
Typical Offshore Coling Water Intake Structure with Velocity Caps (Helrey, 1985; ASCE, 1982)
TESTING FACILITIES AND/OR FACILITIES USING THE TECHNOLOGY:
The available literature (EPA, 1976; Hanson, 1979; and Pagano et al, 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).
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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:
• Designs with rims around the cap edge prevent water from sweeping around the edge
causing turbulence and high velocities, thereby providing more uniform horizontal
Hows (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:
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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.
Pagano R. and W.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. 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. 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.
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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.
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.
V-Arrangement of Fish Barrier Net (ASCE, 1982)
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:
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• 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
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) (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).
• 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).
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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.
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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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.
Gunderboom Marine/Aquatic Life Exclusion System (Gunderboom, Inc., 1999)
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
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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.
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.
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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 not significant.
• Impinged organisms released back into the waterbody.
• Benefits relative to cost appear to be very promising, but remain unproven to date.
• 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.
• 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.
A-40
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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.
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; Rayatal, 1976; Hadderingh, 1979; Hanson etal., 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:
A-41
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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, 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.
A-42
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• 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:
• Sonalysts Inc.'s FishStartle system uses frequencies between 15 hertz 10130 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 350 m (1150 ft); 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.
A-43
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• 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:
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 Sytems:
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
A-44
-------
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 Hydroelectri Power
Plants. March 1988.
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 600n-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 Steam 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
A-45
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the Marine Biolozical Association of the United Kingdom. 61:971-879. 1981.
Blaxter, JJ.S., J.A.B. Gray, and E.J. Denton. "Sound and Startle Response in Herring Shoals." ]_._
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:
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. Thome, 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
A-46
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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
vo!4(3), 1994. pp. 300-307.
Thome, R.E. "Assessment of Population Density by Hydroacoustics." In Journal of Biological
Oceanography. Vol. 2. 1983. pp. 252-262.
A-47
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§ 316(b) TDD Chapter 6 for New Facilities
Industry Profile: Oil and Gas Extraction Industry
Chapter 6: Industry Profile:
Oil and Gas Extraction Industry
INTRODUCTION
The oil and gas industry uses non-contact, once-
through water to cool crude oil, produced water,
power generators, and various other pieces of
machinery at oil and gas extraction facilities.1 EPA
did not consider oil and gas extraction facilities in the
Phase I 316(b) rulemaking.
The Phase I proposal and its record included no
analysis of issues associated with offshore and
coastal oil and gas extraction facilities (such as
significant space limitations on mobile drilling
platforms and ships) that could significantly increase
the costs and economic impacts and affect the
technical feasibility of complying with the proposed
requirements for land-based industrial operations.
Additionally, EPA believes it is not appropriate to
include these facilities in the Phase II regulations
scheduled for proposal in February 2002; the Phase
II regulations are intended to address the largest
existing facilities in the steam-electric generating
industry. During Phase III, EPA will address cooling
water intake structures at existing facilities in a variety
of industry sectors. Therefore, EPA believes it is most
and gas extraction facilities to Phase III.
Chapter Contents
6.1 Historic and Projected Drilling
Activities 6-1
6.2 Offshore and Coastal Oil and Gas Extraction
Facilities 6-4
6.2.1 Fixed Oil and Gas Extraction
Facilities 6-4
6.2.2 Mobile Oil and Gas Extraction
Facilities 6-9
6.3 316(b) Issues Related to Offshore and Coastal Oil
and Gas Extraction Facilities 6-9
6.3.1 Biofouling 6-9
6.3.2 Definition of New Souce 6-10
6.3.3 Potential Costs and Scheduling
Impacts 6-10
6.3.4 Description of Benefits for Potential 316(b)
Controls on Offshore and
Coastal Oil and Gas Extraction
Facilities 6-12
6.4 Phase III Activities Related to Offshore and
Coastal Oil and Gas Extraction
Facilities 6-12
References 6-13
appropriate to defer rulemaking for offshore and coastal oil
This chapter provides a starting point for future discussions with industry and other stakeholders on future Phase
III regulatory decisions.
6.1 HISTORIC AND PROJECTED DRILLINS ACTIVITIES
The oil and gas extraction industry drills wells both onshore, coastal, and offshore regions for the exploration and
development of oil and natural gas. Various engines and brakes are employed which require some type of cooling
system. The U.S. oil and gas extraction industry currently produces over 60 billion cubic feet of natural gas and over
9 million barrels of oil per day.2 There were roughly 1,096 onshore drilling rigs in operation in August 2001.3 This
section focuses on the OCS oil and gas extraction activities as onshore facilities have less demand for cooling water
and have more available options for using dry cooling systems. Moreover, OCS facilities are limited in physical
space, payload capacity, and operating environments. EPA will further investigate onshore oil and gas extraction
facilities for the Phase III rulemaking.
6-1
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§ 316(b) TDD Chapter 6 for New Facilities Industry Profile: Oil and Gas Extraction Industry
A large majority of the OCS oil and gas extraction occurs in the Gulf of Mexico (GOM). The Federal OCS generally
starts three miles from shore and extends out to the outer territorial boundary (about 200 miles).1' The U.S.
Departmentof Interior's Mineral Management Service (MMS) is the Federal agency responsible for managing OCS
mineral resources. The following summary statistics are from the 1999 MMS factbook.2
• The OCS accounts for about 27% of the Nation's domestic natural gas production and about 20% of its
domestic oil production. On an energy basis (BTU), about 67 percent of the energy currently produced
offshore is natural gas.
• The OCS contains about 19% of the Nation's proven natural gas reserves and 15% of its proven oil reserves.
The OCS is estimated to contain more than 50% of the Nation's remaining undiscovered natural gas and oil
resources.
• To date, the OCS has produced about 131 trillion cubic feet of natural gas and about 12 billion barrels of
oil. The Federal OCS provides the bulk—about 89%—of all U.S. offshore production. Five coastal
States—Alaska, Alabama, California, Louisiana and Texas—make up the remaining 11%.
Table 1 presents the number of wells drilled in three areas (GOM, Offshore California, and Coastal Cook Inlet,
Alaska) for 1995 through 1997. The table also separates the wells into four categories: shallow water development,
shallow water exploratory, deep water development, and deep water exploratory. Exploratory drilling includes those
operations drilling wells to determine potential hydrocarbon reserves. Development drilling includes those
operations drilling production wells once a hydrocarbon reserve has been discovered and delineated. Although the
rigs used in exploratory and developmentdrilling sometimes differ, the drilling process is generally the same for both
types of drilling operations.
The water depth in which either exploratory or development drilling occurs may determine the operator's choice of
drill rigs and drilling systems. MMS and the drilling industry classify wells as located in either deep water or shallow
water, depending on whether drilling is in water depths greater than 1,000 feet or less than 1,000 feet, respectively.
TThe Federal OCS starts approximately 10 miles from the Florida and Texas shores.
6-2
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§ 316(b) TDD Chapter 6 for New Facilities
Industry Profile: Oil and Gas Extraction Industry
Table 6-1:
Data Source
Number
of Wells Drilled Annually. 1995 - 1997. by
ii Shallow Water
ii (<1,000 ft)
ii
Development ii
Exploration
Geographic Area
ii Deep Water ii
ii (> 1,000 ft) ii
ii Development
ii Exploration ii
Total
Wells
Gulf of Mexicof
MMS:
RRC
Average
1995 ii
1996 ii
1997 ii
Annual ii
::
j:""
Total Gulf of Mexico ii
Offshore
MMS:
California
Average
1995 ii
1996 ii
1997 ii
Annual ii
557 ii
617 ii
726 ii
640 ii
5 ii
!:•"
645 ii
4 ii
15 ii
14 ii
11 ii
314
348
403
355
3
358
0
0
0
0
ii 32
ii 42
ii 69
ii 48
ii NA
•j:
ii 48
ii 15
ii 16
ii 14
ii 15
:: C ^ ::
:: / j ::
ii 104 ii
ii 76 ii
ii NA ii
•j: ji-
ii 76 ii
ii o ii
ii o ii
ii 0 ii
i oji
975
1,080
1,302
1,119
8
1,127
19
31
28
26
Coastal Cook Inlet
AOGC:
Average
1995 ii
1996 ii
1997 ii
Annual ;;
12 ii
5 ii
5 ii
0
1
2
1
0
ii °
ii o
ii 0
0
ii 0 ii
ii o ii
12
6
7
8
Source: Ref. 4
t Note: GOM figures do not include wells within State bay and inlet waters (considered "coastal" under 40 CFR 435)
and State offshore waters (0-3 miles from shore). In August 2001, there were 1 and 23 drilling rigs in State bay and
inlet waters of Texas and Louisiana, respectively. There were also 19 and 112 drilling rigs in State offshore waters
(0-3 miles from shore), respectively.3
Offshore production in the Gulf of Mexico began in 1949 with a shallow well drilled in shallow water. It took
another 25 years until the first deepwater well (> 1,000ft. of water) was drilled in 1974. Barriers to deepwater activity
include technological difficulties of stabilizing a drilling rig in the open ocean, high financial costs, and natural and
manmade barriers to oil and gas activities in the deep waters.
These barriers have been offset in recentyears by technological developments (e.g., 3-D seismic data covering large
areas of the deepwater Gulf and innovative structure designs) and economic incentives. As a result, deepwater oil
and gas activity in the Gulf of Mexico has dramatically increased from 1992 to 1999. In fact, in late 1999, oil
production from deepwater wells surpassed that produced from shallow water wells for the first time in the history
of oil production in the Gulf of Mexico.5
As shown in Table 1, 1,127 wells were drilled in the Gulf of Mexico, on average, from 1995 to 1997, compared to
26 wells in California and 8 wells in Cook Inlet. In the Gulf of Mexico, over the last few years, there has been high
growth in the number of wells drilled in deep water, defined as water greater than 1,000 feet deep. For example, in
1995, 84 wells were drilled in deep water, or 8.6 percent of all Gulf of Mexico wells drilled that year. By 1997, that
number increased to 173 wells drilled, or over 13 percentof all Gulf of Mexico wells drilled. Nearly all exploration
and development activities in the Gulf are taking place in the Western Gulf of Mexico, that is, the regions off the
Texas and Louisiana shores.
6-3
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§ 316(b) TDD Chapter 6 for New Facilities
Industry Profile: Oil and Gas Extraction Industry
6.2 OFFSHORE AND COASTAL OIL AND SAS EXTRACTION FACILITIES
There are numerous different types of offshore and coastal oil extraction facilities. Some facilities are fixed for
development drilling while other facilities are mobile for both exploration and development drilling. Previous EPA
estimates of non-contact cooling water for offshore and coastal oil and gas extraction facilities (OCOGEF) showed
a wide range of cooling water demands (294 - 5,208,000 gal/day).1
6.2.1 Fixed Oil and Gas Extraction Facilities
Most of these structures use a pipe with passive screens (strainers) to convey cooling water. Non-contact, once-
through water is used to cool crude oil, produced water, power generators and various other pieces of machinery
(e.g., drawworks brakes). Due to the number of oil and gas extraction facilities in the GOMin relation to other OCS
regions, EPA estimated the number of fixed active platforms in the Federal OCS region of the Gulf of Mexico using
the MMS Platform Inspection System, Complex/Structure database. These fixed structures are generally used for
development drilling. Out of atotal of 5,026 structures, EPA identified 2,381 active platforms where drilling is likely
to occur (Table 2).
Table 6-2: Identification of Structures in the Gulf of Mexico OCS i
Category j Count I Remaining Count i
All Structures
Abandoned Structures
Structures classified as production structures, i.e., with no well
slots and production equipment
Structures known not to be in production
Structures with missing information on product type (oil or gas or
both)
Structures whose drilled well slots are used solely for injection,
disposal, or as a water source
5,026
1,403
245
688
309
0
5,026
3,623
3,378
2,690
2,381
2,381
Source: Ref 5
The Offshore Operators Committee (OOC) and the National Oceans Industries Association (NOIA) also noted in
their comments to the May 25, 2001 316(b) Federal Register Notice that a typical platform rig for a Tension Leg
Platform1'1' will require 10 - 15 MM Btu/hr heat removal for its engines and 3-6 MM Btu/hr heat removal for the
drawworks brake. The total heat removal (cooling capacity) is 13 - 21 MM Btu/hr. OOC/NOIAalso estimated that
approximately 200 production facilities have seawater intake requirements that exceed 2 MGD. OOC/NOIA estimate
that these facilities have seawater intake requirements ranging from 2-10 MGD with one-third or more of the
volume needed for cooling water. Other seawater intake requirements include firewater and ballasting. The
firewater system on offshore platforms must maintain a positive pressure at all times and therefore requires the
T1A Tension Leg Platform (TLP) is a fixed production facilities in deepwater
environments (> 1,000 ft).
6-4
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§ 316(b) TDD Chapter 6 for New Facilities Industry Profile: Oil and Gas Extraction Industry
firewater pumps in the deep well casings to run continuously. Ballasting water for floating facilities may not be a
continuous flow but is an essential intake to maintain the stability of the facility.
EPA and MMS could only identify one case where the environmental impacts of a fixed OCOGEF CWIS were
considered.6BP Exploration (Alaska) Inc. (BPXA) plans to locate a vertical intake pipe for aseawater-treatmentplant
on the south side of Liberty Island, Beaufort Sea, Alaska. The pipe would have an opening 8 feet by 5.67 feet and
would be located approximately 7.5 feet below the mean low-water level (Fig. 6-1). The discharge from the
continuous flush system consists of the seawater that would be continuously pumped through the process-water
system to prevent ice formation and blockage. Recirculation pipes located just inside the opening would help keep
large fish, other animals, and debris out of the intake. Two vertically parallel screens (6 inches apart) would be
located in the intake pipe above the intake opening. They would have a mesh size of 1 inch by 1/4 inch. Maximum
water velocity would be 0.29 feet per second at the first screen and 0.33 feet per second at the second screen. These
velocities typically would occur only for a few hours each week while testing the fire-control water system. At other
times, the velocities would be considerably lower. Periodically, the screens would be removed, cleaned, and
replaced.
MMS states in the Liberty Draft Environmental Impact Statement that the proposed seawater-intake structure will
likely harm or kill some young-of-the-year arctic cisco during the summer migration period and some eggs and fry
of other species in the immediate vicinity of the intake. However, MMS estimates that less than 1% of the arctic cisco
in the Liberty area are likely to be harmed or killed by the intake structure. Further, MMS concludes that: (1) the
intake structure is not expected to have a measurable effect on young-of-the-year arctic cisco in the migration
corridor; and (2) the intake structure is not expected to have a measurable effect on other fishes populations because
of the wide distribution/low density of their eggs and fry.
6-5
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DOCK SURFACE
DOCtSURFAGE
INTAKEUDEL 10'
MLLW
C 36" INLET UNE
o c' a"
4' SEAWATER RECIRCULATION PIPES
8'-0"x5'-8" SEAWATER INLET OPENING
'•'•'"• I •'"!'• -IX
f T ~ rn ii
P^
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SEAWATER
xK
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XMxMrT
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WARM SEAWATEfl
v^j
FLOW
2ND RSH SCREEN 1*
-
1ST FISH SCREEN tt
l
!
A
T
,-•
•
E
^
i
i
"
»
TOP OF RSH SCREEN
tS
I Maw
-rr ao-
1
BOHOM OF SCREEN
TRAP
4"0 SEAWATER
RECIRCULATION
TOP OF OPENING EL-8'
SEAWATER FLOW
EL -16'
ILU
;zo
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LLI Z
«gs
!°
FRONT ELEVATION
MLLW = Mean Lower Low Water
EL -21'
SIDE ELEVATION
Source: BPXA, 1998b
ALL DIMENSIONS ARE APPROXIMATE
FigUf6 6-1 Liberty Development Project: Seawater Intake Detail
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§ 316(b) TDD Chapter 6 for New Facilities
Industry Profile: Oil and Gas Extraction Industry
6.2.2 Mobile Oil and Gas Extraction Facilities
EPA also estimated the number of mobile offshore drilling units (MODUs) currently in operation. These numbers
change in response to market demands. Over the past five years the total number of mobile offshore drilling units
(MODUs) operating at one time in areas under U.S. jurisdiction has ranged from less than 100 to more than 200.
There are five main types of MODUs operating in areas under U.S. jurisdiction: drillships, semi-submersibles,
jack-ups, submersibles and drilling barges. Table 3 gives a brief summary of each MODU. EPA and MMS could not
identify any cases where the environmental impacts of a MODU CWIS were considered.
Table 6-3: Description of Mobile Offshore Drilling Units and their CWIS i
;; „, , , ;; ;; No. ;; No. Currently Under ;
•• W ilTPf" 1 tlTfl liP? •• •• •• •
MODU Type ii , __ . ii Water Depth ii Currently ii Construction Over Next i
I andDes'Sn | | taGOM ii Three Years i
Drill Ships
Semi-
submersibles
Jack-ups
Submersibles
Drill Barges
16 - 20 MOD
Seachest
2 -15+ MOD
Seachest
2 - 10+ MOD
Intake Pipe
<2MGD
Intake Pipe
<2MGD
Intake Pipe
Greater than 400 ft
Greater than 400 ft
Less than 400 ft
Shallow Water (Bays and Inlet
Waters)
Shallow Water (Bays and Inlet
Waters)
5
37
140
6
20
0
5
9
0
0
Sources: Ref. 7, Ref 8, Ref. 9, Ref. 10
t Approximately 80% of the water intake is used for cooling water with the remainder being used for hotel loads,
fire water testing, cleaning, and ballast water.7
The particular type of MODU selected for operation at a specific location is governed primarily by water depth
(which may be controlling), anticipated environmental conditions, and the design (depth, wellbore diameter, and
pressure) of the well in relation to the units equipment. In general, deeper water depths or deeper wells demand units
with a higher peak power-generation and drawworks brake cooling capacities, and this directly impacts the demand
for cooling water.10
Drillships and Semi-Submersibles MODUs
Drill ships and semi-submersibles use a "seachest" as a CWIS. In general there are three pipes for each sea chest
(these include CWIs and fire pumps). One of the three intake pipes is always set aside for use solely for emergency
fire fighting operations. These pipes are usually back on the flush line of the sea chest. The sea chest is a cavity in
the hull or pontoon of the MODU and is exposed to the ocean with a passive screen (strainer) often set along the
flush line of the sea chest. These passive screens or weirs generally have a maximum opening of 1 inch.9 There are
generally two sea chests for each drill ship or semi-submersible (port and starboard) for redundancy and ship
stability considerations. In general, only one seachest is required at any given time for drilling operations.7
6-7
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§ 316(b) TDD Chapter 6 for New Facilities Industry Profile: Oil and Gas Extraction Industry
While engaged in drilling operations most drillships and one-third of semi-submersibles maintain their position over
the well by means of "dynamic positioning" thrusters which counter the effects of wind and current. Additional
power is required to operate the drilling and associated industrial machinery, which is most often powered
electrically from the same diesel generators that supply propulsion power. While the equipment powered by the
ship's electrical generating system changes, the total power requirements for drillships are similar to those while in
transit. Thus, during drilling operations the total seawater intake on a drillship is approximately the same as while
underway. The majority of semi-submersibles are not self- propelled, and thus require the assistance of towing
vessels to move from location to location.
Information from the U.S. Coast Guard indicates that when semi-submersibles are drilling their sea chests are 80 to
100 feet below the water surface and are less than 20 feet below water when the pontoons are raised for transit or
screen cleaning operations.7 Drill ships have their sea chests on the bottom of their hulls and are typically 20 to 40
feet below water at all times.
IADC notes that one of the earlier semi-submersible designs still in use is the "victory" class unit.10 This unit is
provided with two seawater-cooling pumps, each with a design capacity of 2.3 MOD with a 300 head. At operating
draft the center of the inlet, measuring approximately 4 feet by 6 feet, is located 80 feet below the sea surface and
is covered by an inlet screen. In the original design this screen had 3024 holes of 15mm diameter. The approximate
inlet velocity is therefore 0.9 feet/sec.
The more recent semi-submersible designs typically have higher installed power to meet the challenges of operating
in deeper water, harsher environmental condition, or for propulsion or positioning. IADC notes that a new design,
newly-built unit has a seawater intake capacity of 34.8 MOD (including saltwater service pumps and ballast pumps)
and averages 10.7 MGD of seawater intake of which 7.4 MGD is used for cooling water.
Jack-up MODUs
Jack-up, submersibles, and drill barges use intake pipes for CWIS. These OCOGEF basically use a pipe with a
passive screens (strainers) to convey cooling water. Non-contact, once-through water is used to cool crude oil,
produced water, power generators and various other pieces of machinery on OCOGEF (e.g., drawworks brakes).
The jack-up is the most numerous type of MODU. These vessels are rarely self- propelled and must be towed from
location to location. Once on location, their legs are lowered to the seabed, and the hull is raised (jacked-up) above
the sea surface to an elevation that prevents wave impingement with the hull. Although all of these ships do use
seawater cooling for some purposes (e.g., desalinators), as with the semi-submersibles a few use air-cooled
diesel-electric generators because of the height of the machinery above the sea surface.9 Seawater is drawn from
deep-well or submersible pumps that are lowered far enough below the sea surface to assure that suction is not lost
through wave action. Total seawater intake of these ships varies considerably and ranges from less than 2 MGD to
more than 10 MGD. Jack-ups are limited to operating in water depths of less than 500 feet, and may rarely operate
in water depths of less than 20 feet.
The most widely used of the jack-up unit designs is the Marathon Letourneau 116-C.10 For these types of jack-ups
typically one pump is used during rig operations with a 6" diameter suction at 20 to 50 feet below water level which
delivers cooling water intake rates of 1.73 MGD at an inlet velocity of 13.33 ft/sec.10 Additionally, pre-loading
involves the use of two or three pumps in sequence. Pre-loading is not a cooling water procedure, but a ballasting
procedure (ballast water is later discharged). Each pump is fitted with its own passive screen (strainer) at the suction
point which provides for primary protection against foreign materials entering the system.
6-,
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§ 316(b) TDD Chapter 6 for New Facilities Industry Profile: Oil and Gas Extraction Industry
In their early configurations, these jack-up MODUs were typically outfitted with either 5 diesel generator units (each
rated at about 1,200 horsepower) or three diesel generator units (each rated at about 2,200 horsepower).10 In
subsequent configurations of this design or re-powering of these units, more installed power has generally been
provided, as it has in more recent designs. With more installed power, there is a demand for more cooling water.
The International Association of Drilling Contractors (IADC) reports that a newly-built jack-up, of a new design,
typically requires 3.17 MOD of cooling water for its drawworks brakes and cooling of six diesel generator units, each
rated at 1,845 horsepower.10 In this case, one pump is typically used during rig operations with a 10" diameter suction
at 20 to 50 feet below water level, delivering the cooling water at 3.2 MOD.
Submersibles and Drill Barge MODUs
The submersible MODUis used most often in very shallow waters of bays and inlet waters. These MODUs are not
self-propelled. Most are powered by air-cooled diesel-electric
generators, but require seawater intake for cooling of other equipment, desalinators, and for other purposes. Total
seawater intake varies considerably with most below 2 MOD.
The drilling barge MODU There are approximately 50 drilling barges available for operation in areas under U.S.
jurisdiction, although the number currently in operation is less than 20. These ships operate in shallow bays and
inlets along the Gulf Coast, and occasionally in shallow offshore areas. Many are powered by air-cooled
diesel-electric generators. While they have some water intake for sanitary and some cooling purposes, water intake
is generally below 2 MGD.
6.3 316(B) ISSUES RELATED TO OFFSHORE AND COASTAL OIL AND GAS
EXTRACTION FACILITIES
There are several important 316(b) issues related to OCOGEF CWIS that EPA will be investigating in the Phase III
316(b) rulemaking: (1) Biofouling; (2) Definition of New Source; (3) Potential Costs and Scheduling Impacts. EPA
will work with stakeholders to identify other issues for resolution during the Phase III 316(b) rulemaking process.
6.3.1 Biofouling
Industry comments to the 316(b) Phase I proposal assert that operators must maintain a minimum intake velocity
of 2 to 5 ft/sec in order to prevent biofouling of the offshore oil and gas extraction facility CWIS. EPA requested
documentation from industry regarding the relationship between marine growth (biofouling) and intake velocities.11
Industry was unable to provide any authoritative information to support the assertion that a minimum intake velocity
of 2 to 5 ft/sec is required in order to prevent biofouling of the OCOGEF CWIS. IADC asserts that it is common
marine engineering practice to maintain high velocities in the seachest to inhibit attachment of marine biofouling
organisms.10
The Offshore Operators Committee (OOC) and the National Oceans Industries Association (NOIA) also noted in
their comments to the May 25,2001316(b) Federal Register Notice that the ASCE "Design of Water Intake Structures
for Fish Protection" recommends an approach velocity in the range of 0.5 to 1 ft/s for fish protection and 1 ft/s for
debris management but does not address biofouling specifically. OOC/NOIA were unable to find technical papers
to support a higher intake velocity. The U.S. Coast Guard and MMS were also unable to provide EPA with any
information on velocity requirements or preventative measures regarding marine growth inhibition or has a history
of excessive marine growth at the sea chest.
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§ 316(b) TDD Chapter 6 for New Facilities Industry Profile: Oil and Gas Extraction Industry
EPA was able to identify some of the major factors affecting marine growth on offshore structures. These factors
include temperature, oxygen content, pH, current, turbidity, and light.12'13 Fouling is particularly troublesome in the
more fertile coastal waters, and although it diminishes with distance from the shoreline, it does not disappear in
midoceanic and in the abyssal depths.13 Moreover, operators are required to perform regular inspection and cleaning
of these CWIS in accordance with USCG regulations.
Operators are also required by the U.S. Coast Guard to inspect sea chests twice in five years with at least one cleaning
to prevent blockages of firewater lines. The requirementto drydock MODUs twice in five years and inspect and clean
their sea chests and sea valves are found in U.S. Coast Guard regulations (46 CFR 107.261 and 46 CFR61.20-5). The
U.S. Coast Guard may require the sea chests to be cleaned twice in 5 years at every drydocking if the unit is in an
area of high marine growth or has had history of excessive marine growth at the sea chests.
EPA and industry also identified that there are a variety of specialty screens, coatings, or treatments to reduce
biofouling. Industry and a technology vendor (Johnson Screens) also identified several technologies currently being
used to control biofouling (e.g., air sparing, Ni-Cu alloy materials). Johnson Screens asserted in May 25,2001 316(b)
Federal Register Notice comments to EPA that their copper based material can reduce biofouling in many
applications including coastal and offshore drilling facilities in marine environments.
Biocide treatment can also be used to minimize biofouling. IADC reports that one of their members uses Chloropac
systems to reduce biofouling (www.elcat.co.uk/chloro_anti_mar.htm). The Liberty Project plans to use chlorine, in
the form of calcium hypochlorite, to reduce biofouling. The operator (BPXA) will reduce the total residual chlorine
concentration in the discharged cooling water by adding sodium metabisulfate in order to comply with limits of the
National Pollution Discharge Elimination System Permit. MMS estimates that the effluent pH will vary slightly from
the intake seawater because of the chlorination/dechlorination processes, butthis variation is not expected to be more
than 0.1 pH units.
In summary, EPA has not yet identified any relationship between the intake velocity and biofouling of a offshore
oil and gas extraction facility CWIS. However, EPA will be pursuing this and other matters related to biofouling in
the offshore oil and gas industry in the Phase III 316(b) regulation.
6.3.2 Definition of New Source
Industry claimed in comments to the Phase I 316(b) proposal and the May 25, 2001 316(b) Federal Register Notice
that existing MODUs could be considered "new sources" when they drill new development wells under 40 CFR
435.11 (exploration facilities are excluded from the definition of new sources). EPA will work with stakeholders to
clarify the regulatory status of existing MODUs in the Phase III 316(b) proposal and final rule.
6.3.3 Potential Costs and Scheduling Impacts
Costs to Retrofit for Velocity Standard
EPA did not identify any additional costs to incorporate the 0.5 fps maximum velocity standard into new designs for
future (not yet built) OCOGEF CWIS. Retrofit cost for production facilities will vary depending on the type of
cooling water intake structure the facility has in place. The U.S. Coast Guard did not have agood estimate of seachest
CWIS retrofit costs but did have a general idea of the work requirements for these potential retrofits.7 The Coast
Guard stated that retrofits for drill ships and semi-submersibles that use seachests as the CWI structure could
6-10
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§ 316(b) TDD Chapter 6 for New Facilities Industry Profile: Oil and Gas Extraction Industry
probably be in the millions of dollars (approximately 8-10 million dollars) and require several weeks to months for
drydocking operations. Complicating matters is that there are only a few deepwater drydock harbors capable of
handling semi-submersibles. MMS did not have any information on costs and issues relating to retrofitting sea chests
or other offshore CWIS.
OOC/NOIA estimated costs for retrofitting a larger intake for a floating production system tension leg platform
(TLP).14 Under their costing scenario, it was assumed that the TLP had a seachest intake structure with a pre-existing
flange on the exterior of the intake structure which could be used to bolt on a larger diameter intake in order to
reduce the intake velocity to below 0.5 ft/s. The estimated cost to retrofit this new intake is $75,000. OOC/NOIA
estimates that this same cost can be assumed for retrofiting a deep well pump casing with a larger diameter intake
provided the bottom of the casing is not obstructed and the intake structure can be clamped over the casing.
OOC/NOIA further estimates that for TLP's with seachests without a pre-existing flange for an intake structure and
for deep well pump casings that are obstructed and prevent the installation of an intake structure, the retrofit costs
are estimated to be much higher.14 OOC/NOIA estimates that if underwater welding or the installation of new pump
casing are required, the costs can be as high as $500,000. In these cases, the platform would need to be shut-in for
some period of time (1-3 days) to allow for this installation. Included in this estimate is the need to provide for
additional stiffening of underwater legs and supports to resist the wave loading forces of the new intake structures.
OOC/NOIA estimates that many facilities have multiple deepwell casings or seachests that would require retrofitting.
IADC notes that the feasibility of redesigning seachests to reduce intake velocity would need to be examined on a
case-by-case basis.10 As interior space is typically optimized for the particular machinery installation, IADC further
notes that a prerequisite for enlarging any seachest would be repositioning of machinery, piping and electrical
systems and that such operations could only be undertaken in a drydock. Seachests on semi-submersible units are
notlikely located in stress-critical areas, so effective compensation of hull strength is unlikely to be a major concern,
unlike a drillship where, depending on the design, it might be difficult to provide effective compensation to hull
girder strength for an enlarged seachest
Costs for retro-fitting jack-ups would likely be much less complicated and expensive than semi-submersible and
drillship sea chest retro-fits.7 The U.S. Coast Guard estimates that operators could install a bell or cone intake device
on the existing CWIS to reduce CWI velocities. IADC notes that installing passive screens (strainers) with a larger
surface area on jack-up CWIS in order to reduce the intake velocity at the face of the screen would add weight and
pose handling problems (e.g., require more frequent cleaning).
Costs to Retrofit to Dry Cooling
OOC/NOIA stated in their May 25,2001316(b) Federal Register Notice comments that offshore production platforms
will typically use direct air cooling or cooling with a closed loop system for cooling requirements where technically
feasible. The following items are typically direct air cooled: gas coolers on compressors, lubrication oil coolers on
compressors and generators, and hydraulic oil coolers on pumps. These coolers will range from 1 to 35 MM Btu/hr
heat removal capacity. Seawater cooling is necessary in many cases because space and weight limitations render air
cooling infeasible. This is particularly true for floating production systems which have strict payload limitations.
IADC reports that some jack-up MODUs were converted from sea water cooling systems to closed-loop air cooling
systems for engine and drawworks brake cooling.10 IADC reported the cost of the conversion, completed during a
regular shipyard period, was approximately $1.2 million and required a six-month lead-time to obtain the required
equipment. The conversion resulted in the loss of deck space associated with the installation of the air-cooling units,
6-11
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§ 316(b) TDD Chapter 6 for New Facilities Industry Profile: Oil and Gas Extraction Industry
and a small loss in variable deck load equal to the additional weight of the air-cooling units and associated piping.
OOC/NOIA provided initial costs to convert from seawater cooling to air cooling with a radiator on a platform rig.
In this case, a cantilevered deck was installed onto the side of the pipe rack. The radiator was rated at about 15 MM
Btu/hr, and the cost for the installation was about $150,000. The weight of the addition was about 15,000 pounds.
The cost of space and payload on an offshore platform is about $5/pound; therefore, the added weight cost about
$75,000 bringing the total cost to about $225,000.
EPA agrees with industry that dry cooling systems are most easily installed during
planning and construction, but some can be retrofitted with additional costs. IADC believes that it is already difficult
to justify such conversions of jack-ups and that it would be far more difficult to justify conversion of drillships or
semi-submersibles. EPA will also look at the net gain or loss in the energy efficiency of conversions from wet to dry
cooling.
6.3.4 Description of Benefits for Potential 316(b) Controls on Offshore and Coastal
Oil and Gas Extraction Facilities
EPA was only able to identify one case where potential impacts to aquatic communities from OCOGEF CWIS were
described (MMS Liberty Draft Environmental Impact Statement).6 MMS estimated that less than 1% of the arctic
cisco in the Liberty area are likely to be harmed or killed by the intake structure but that the intake structure is not
expected to have a measurable effect on young-of-the-year arctic cisco in the migration corridor or on other fishes
populations.
OOC submitted a video tape of three different OCOGEF CWIS as part of their public comments. These CWIS have
an intake of 5.9 to 6.3 MOD with a intake velocity of 2.6 to 2.9 ft/s. The intake has a passive screen (strainer) with
1 inch diameter slots. EPA will use this documentation in determining potential impacts on aquatic communities from
OCOGEF CWIS.
6.4 PHASE III ACTIVITIES RELATED TO OFFSHORE AND COASTAL
OIL AND GAS EXTRACTION FACILITIES
Numerous researchers and State and Federal regulatory agencies have studied and controlled the discharges from
these facilities for decades. The technology-based standards for the discharges from these facilities are located in 40
CFR 435. Conversely, there has been extremely little work done to investigate the environmental impacts or
evaluation of the location, design, construction, and capacity characteristics of OCOGEF CWIS that reduce
impingement and entrainment of aquatic organisms.
EPA discussions with two main regulatory entities of OCOGEF (i.e., MMS, USCG) identified no regulatory
requirements on these OCOGEF CWIS with respect to environmental impacts. MMS generally does not regulate or
consider the potential environmental impacts of these OCOGEF CWIS. MMS could only identify one case where
the environmental impacts of a OCOGEF CWIS were considered.6 Moreover, MMS does not collect information
on CWI rates, velocities and durations for any OCOGEF CWIS. The U.S. Coast Guard does not investigate potential
environmental impacts of MODU CWIS but does require operators to inspect sea chests twice in five years with at
least one cleaning to prevent blockages of firewater lines.
6-12
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§ 316(b) TDD Chapter 6 for New Facilities Industry Profile: Oil and Gas Extraction Industry
EPA will work with industry and other stakeholders to identify all maj or issues associated with OCOGEF CWIS and
potential Phase III 316(b) requirements. EPA will also collect additional data to identify the costs and benefits
associated with any regulatory alternative.
REFERENCES
1. U.S. EPA, Development Document for Effluent Limitations and Guidelines and New Source Performance
Standards for the Offshore Subcategory of the Oil and Gas Extraction Point Source Category, EPA-821-R-
93-003, January 1993.
2. U.S. Department of Interior, Minerals Management Service, 1999 Factbook,
http://www.mms.gov/ooc/newweb/publications/FACTBOOK.PDF.
3. Baker-Hughes Rig Count for August 24,2001, Oil & Gas Journal, PennWell, Vol. 99.36, September 2, 2001.
4. U.S. EPA, Development Document for Final Effluent Limitations Guidelines and Standards for Synthetic-
Based Drilling Fluids and other Non-Aqueous Drilling Fluids in the Oil and Gas Extraction Point Category,
EPA-821-B-00-013, December 2000.
5. U.S. EPA, Economic Analysis of Final Effluent Limitations Guidelines and Standards for Synthetic-Based
Drilling Fluids and other Non-Aqueous Drilling Fluids in the Oil and Gas Extraction Point Source Category,
EPA-821-B-00-012, December 2000.
6. U.S. Department of Interior, Minerals Management Service, Liberty Developmentand Production Plan Draft
Environmental Impact Statement, OCS EIS/EA, MMS 2001-001, January 2001.
7. Johnston, Carey A. U.S. EPA, Memo to File, Notes from April 4, 2001 Meeting with US Coast Guard. April
23, 2001, 316(b) Rulemaking Record No. 2-012A.
8. ODS-Petrodata Group, Offshore Rig Locator, Houston, Texas, Vol. 28, No. 4, April 4, 2001.
9. Spackman, Alan, International Association of Drilling Contractors, Comments on Phase 1316(b) Proposed
Rule, Comment Number 316bNFR.004.001.
10. Spackman, Alan, International Association of Drilling Contractors, Memo to Carey Johnston, U.S. EPA,
316(b) Rulemaking Record No. 3-3013/3-3014, May 8, 2001.
11. Johnston, Carey A. U.S. EPA, Memo to Alan Spackman (IADC) et al., EPA Data Needs to Help EPA Assess
section 316(b) Comments related to MODUs, 316(b) Rulemaking Record No. 3-3007, March 21, 2001.
12. Johnston, Carey A. U.S. EPA, Memo to File, Marine Growth Literature Reference: "Construction of Marine
and Offshore Structures" by Ben C. Gerwick Jr., CRC Press, 316(b) Rulemaking Record No. 3-3010, March
26,2001.
13. Johnston, Carey A. U.S. EPA, Memo to File, Marine Growth Literature Reference: "Seawater Corrosion
Handbook" edited by M. Schumacher, Noyes Data Corporation, Park Ridge, New Jersey, 1979, 316(b)
Rulemaking Record No. 3-3018, October 9, 2001.
14. Satterlee, Kent, Offshore Operators Committee, Comments on May 25,2001316(b) Federal Register Notice,
Comment Number 316bNFR503.004.
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§ 316(b) TDD Chapter 6 for New Facilities Industry Profile: Oil and Gas Extraction Industry
This Pace Intentionally Left Blank
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