821R04015
Unites Slates
E tiy t renmentai Prate etio«
Document for the Proposed
Section 316(b) Phase III Rule
November 2004
-------
-------
U.S. Environmental Protection Agency
Office of Water (4303T)
1200 Pennsylvania Avenue, NW
Washington, DC 20460
EPA-821-R-04-015
-------
-------
Disclaimer
This is a guidance manual and is not a regulation. It does not change or substitute for any legal
requirements. While EPA has made every effort to ensure the accuracy of the discussion in this guidance,
the obligations of the regulated community are determined by the relevant statutes, regulations, or other
legally binding requirements. This guidance manual is not a rule, is not legally enforceable, and does not
confer legal rights or impose legal obligations upon any member of the public, EPA, States, or any other
agency. In the event of a conflict between the discussion in this document and any statute or regulation,
this document would not be controlling. The word "should" as used in this guidance manual does not
connote a requirement, but does indicate EPA's strongly preferred approach to assure effective
implementation of legal requirements. This guidance may not apply in a particular situation based upon
the circumstances, and EPA, States and Tribes retain the discretion to adopt approaches on a case-by-case
basis that differ from this guidance manual where appropriate. Permitting authorities will make each
permitting decision on a case-by-case basis and will be guided by the applicable requirements of the
CWA and implementing regulations, taking into account comments and information presented at that time
by interested persons regarding the appropriateness of applying these recommendations to the particular
situation. In addition, EPA may decide to revise this guidance manual without public notice to reflect
changes in EPA's approach to implementing the regulations or to clarify and update text.
-------
-------
§ 316(b) Phase III - Technical Development Document Table of Contents
Table of Contents
CHAPTER 1: SUMMARY OF THE PROPOSED RULE 1-1
1.0 APPLICABILITY OF THE PROPOSED RULE 1-1
2.0 AFFECTED SUBCATEGORIES 1-1
3.0 OVERVIEW OF THE PROPOSED REQUIREMENTS 1-2
3.1 Phase III Existing Facilities 1-2
3.2 New Offshore Oil and Gas Extraction Facilities 1-5
CHAPTER!: DESCRIPTION OF THE INDUSTRY .. 2-1
I. LAND-BASED INDUSTRIES 2-1
1.0 DESCRIPTION OF THE INDUSTRIES 2-1
1.1 Estimated Numbers of Land-based Facilities in Scope of 316(b) 2-2
1.2 Source Waterbodies 2-2
1.3 Design Intake Flows 2-3
1.4 Cooling Water System Configurations 2-4
1.5 Design Through-Screen Velocities 2-5
1.6 Existing Intake Technologies 2-6
1.7 Operating Days per Year 2-6
1.8 Land-based Liquefied Natural Gas Facilities 2-7
2.0 PRELIMINARY ASSESSMENT OF COMPLIANCE 2-7
II. OFFSHORE INDUSTRIES 2-7
1.0 DESCRIPTION OF THE INDUSTRIES 2-8
1.1 Estimated Numbers of Offshore Facilities Potentially Subject to Regulation 2-8
1.2 Offshore Facility Characteristics 2-9
2.0 PRELIMINARY ASSESSMENT OF COMPLIANCE 2-9
CHAPTERS: TECHNOLOGY COST MODULES 3-1
1.0 SUBMERGED PASSIVE INTAKES 3-1
1.1 Relocated Shore-based Intake to Submerged Near-Shore and Offshore with Fine Mesh Passive Screens at
Inlet : 3-1
1.2 Add Submerged Fine Mesh Passive Screens to Existing Offshore Intakes 3-16
ATTACHMENT A3
O&M DEVELOPMENT DATA 3-20
2.0 IMPROVEMENTS TO EXISTING SHORELINE INTAKES WITH TRAVELING SCREENS 3-39
2.1 Replace Existing Traveling Screens with New Traveling Screen Equipment 3-39
2.2 New Larger Intake Structure for Decreasing Intake Velocities 3-54
3.0 EXISTING SUBMERGED OFFSHORE INTAKES - ADD VELOCITY CAPS 3-79
3.1 Capital Costs 3-79
3.2 O&M Costs 3-79
3.3 Application 3-80
4.0 FISH BARRIER NETS 3-85
4.1 Capital Cost Development 3-88
4.2 O&M Costs Development 3-91
4.3 Nuclear Facilities 3-93
4.4 Application 3-93
5.0 AQUATIC FILTER BARRIERS 3-97
5.1 Capital Cost Development 3-98
5.2 O&M Costs 3-98
5.3 Application 3-99
II. TECHNOLOGY COST MODULES FOR SEAFOOD PROCESSING VESSELS 3-101
1.0 REPLACE EXISTING GRILL WITH FINE MESH SCREEN 3-101
1.1 Capital Cost Development 3-101
-------
§ 316(b) Phase III - Technical Development Document Table of Contents
1.2 O & M Cost Development 3-102
2.0 ENLARGE THE INTAKE STRUCTURE INTERNALLY 3-103
2.1 Capital Cost Development 3-103
2.2 O & M Cost Development 3-103
3.0 ENLARGE THE INTAKE STRUCTURE EXTERNALLY 3-108
3.1 Capital Cost Development 3-108
3.2 O&M Cost Development 3-108
4.0 HORIZONTAL FLOW MODIFIER 3-110
4.1 Capital Cost Development 3-110
4.2 O&M Cost Development 3-110
III. TECHNOLOGY COST MODULES FOR OFFSHORE OIL AND GAS EXTRACTION FACILITIES 3-130
1.0 INDUSTRIAL SECTOR PROFILE: OFFSHORE OIL AND GAS EXTRACTION FACILITIES 3-130
1.1 Fixed Oil and Gas Extraction Facilities 3-132
1.2 Mobile Oil and Gas Extraction Facilities 3-136
2.0 PHASE III INFORMATION COLLECTION FOR OIL AND GAS EXTRACTION FACILITIES 3-139
2.1 Consultations with USCG and MMS 3-139
2.2 EPA 316(b) Phase III Survey 3-142
2.3 Technical Data Submittals from Industry 3-143
2.4 Internet Sources 3-147
2.5 Regulatory Agencies 3-149
3.0 FACILITIES IN THIS INDUSTRIAL SECTOR WHICH EPA EVALUATED
FOR THE PHASE III RULEMAKING 3-150
4.0 TECHNOLOGY OPTIONS AVAILABLE TO CONTROL IMPINGEMENT AND ENTRAINMENT OF
AQUATIC ORGANISMS 3-150
4.1 Summary of Technology Options to Control Impingement and Entrainment
of Aquatic Organisms 3-150
4.2 Incremental Costs Associated with Technology Options to Control Impingement
and Entrainment of Aquatic Organisms 3-153
5.0 PROPOSED TECHNOLOGY OPTIONS IDENTIFIED IN THE PHASE III PROPOSAL 3-161
6.0 316(b) ISSUES RELATED TO OFFSHORE OIL AND GAS EXTRACTION FACILITIES 3-162
6.1 Biofouling 3-162
6.2 Definition of New Source 3-163
6.3 Potential Lost Production and Downtime Associated with Proposed Technology Option Impacts ... 3-163
6.4 Drilling Equipment at Production Platforms 3-164
6.5 Current Regulatory Requirements 3-166
IV. TECHNOLOGY COST MODULES FOR LIQUEFIED NATURAL GAS FACILITIES 3-167
1.0 EXISTING LNG IMPORT TERMINALS IN THE U.S 3-167
2.0 PLANNED LNG IMPORT TERMINALS IN THE U.S 3-168
3.0 LNG IMPORT TERMINALS EPA EVALUATED FOR THE PHASE III RULEMAKING 3-170
3.1 Existing Onshore LNG Import Terminals 3-170
3.2 New Onshore LNG Import Terminals 3-172
3.3 New Offshore LNG Import Terminals 3-174
4.0 TECHNOLOGY OPTIONS AVAILABLE TO CONTROL IMPINGEMENT AND ENTRAINMENT OF
AQUATIC ORGANISMS 3-184
4.1 Summary of Technology Options to Control Impingement and Entrainment of Aquatic Organisms .. 3-184
4.2 Incremental Costs Associated with Technology Options to Control Impingement and Entrainment of
Aquatic Organisms 3-187
5.0 RATIONALE FOR ESTABLISHING IMPINGEMENT AND ENTRAINMENT CONTROLS USING BEST
PROFESSIONAL JUDGMENT 3-192
V. FIXED AND VARIABLE O&M COSTS 3-193
1.0 DETERMINING FIXED VERSUS VARIABLE O&M COSTS 3-193
1.1 Overall Approach 3-193
1.2 Estimating the Fixed/variable O&M Cost Mix 3-193
1.3 O&M Fixed Cost Factors 3-195
-------
S 316(b) Phase IH - Technical Development Document Table of Contents
CHAPTER 4: IMPINGEMENT AND ENTRAINMENT CONTROLS 4-1
1.0 IMPINGEMENT AND ENTRAINMENT EFFECTS 4-1
2.0 PERFORMANCE STANDARDS 4-1
3.0 REGULATORY OPTIONS CONSIDERED 4-2
4.0 OTHER CONSIDERATIONS 4-4
4.1 Closed Cycle Cooling 4-4
4.2 Entrainment Reductions for Offshore Oil and Gas Facilities Using Sea Chests 4-4
CHAPTER 5: COSTING METHODOLOGY FOR MODEL FACILITIES 5-1
1.0 REGULATORY OPTIONS 5-1
1.1 Analysis of Capacity Utilization Rate 5-2
1.2 Analysis of Cooling System Type for Electric Power Generating Facilities 5-3
1.3 Regulatory Options for Offshore Oil and Gas Facilities 5-4
1.4 Regulatory Options for Seafood Processing Vessels 5-5
2.0 COST TEST TOOL APPLIED TO MODEL FACILITIES 5-6
2.1 The Cost-Test Tool Structure 5-7
2.2 Cost-Test Tool Inputs 5-9
2.3 Limitations of the Cost Test Tool 5-13
2.4 Fixed and Variable Costs 5-13
3.0 EXAMPLES OF APPLICATION OF TECHNOLOGY COST MODULES TO MODEL FACILITIES 5-15
4.0 ANALYSIS OF THE CONFIDENCE IN ACCURACY OF THE COMPLIANCE COST MODULES 5-26
5.0 FACILITY DOWNTIME ESTIMATES 5-41
CHAPTER 6: IMPINGEMENT MORTALITY AND ENTRAINMENT REDUCTION ESTIMATES 6-1
1.0 REQUIRED INFORMATION 6-1
2.0 ASSIGNING A REDUCTION 6-1
3.0 CONSIDERATIONS 6-2
APPENDIX 6A: DETAILED DESCRIPTION OF IMPINGEMENT MORTALITY AND
ENTRAINMENT REDUCTION ESTIMATES 6A-1
1.0 REQUIRED INFORMATION 6A-1
1.1 Technology Costing Information 6A-1
2.0 ASSIGNING A THRESHOLD 6A-3
2.1 Facilities With No Requirements 6A-3
2.2 Example of A Co-Proposed Threshold (Option 5) 6A-3
2.3 Option 2 6A-5
2.4 Conclusion 6A-6
CHAPTER 7: COST-COST TEST 7-1
1.0 SITE-SPECIFIC REQUIREMENTS - THE COST TO COST TEST 7-1
2.0 DETERMINING A FACILITY'S COSTS 7-1
3.0 COST TO COST TEST 7-3
4.0 COST CORRECTION 7-6
CHAPTER 8: EFFICACY OF COOLING WATER INTAKE STRUCTURE TECHNOLOGIES 8-1
I. EXISTING MANUFACTURING FACILITIES 8-1
1.0 DATA COLLECTION OVERVIEW 8-1
1.1 Scope of Data Collection Efforts 8-1
1.2 Technology Database 8-2
1.3 Data Limitations 8-2
1.4 Conventional Traveling Screens 8-3
1.5 Closed-cycle Wet Cooling System Performance 8-4
2.0 ALTERNATIVE TECHNOLOGIES 8-4
2.1 Modified Traveling Screens and Fish Handling and Return Systems 8-4
2.2 Cylindrical Wedgewire Screens 8-9
2.3 Fine-mesh Screens 8-13
2.4 Fish Net Barriers 8-14
2.5 Aquatic Microfiltration Barriers 8-15
lit
-------
§ 316(b) Phase IH - Technical Development Document Table of Contents
2.6 Louver Systems 8-16
2.7 Angled and Modular Inclined Screens 8-16
2.8 Velocity Caps 8-18
2.9 Porous Dikes and Leaky Dams 8-18
2.10 Behavioral Systems 8-19
2.11 Other Technology Alternatives 8-19
2.12 Intake Location 8-20
II. Offshore Oil and Gas Extraction Facilities 8-21
1.0 AVAILABLE TECHNOLOGIES 8-21
1.1 Known Technologies 8-21
2.0 OTHER TECHNOLOGIES 8-23
2.1 Acoustic Barriers 8-23
2.2 Air Curtains 8-25
2.3 Electro Fish Barriers 8-27
2.4 Intake Location 8-28
2.5 Keel Cooling 8-28
2.6 Strobe Lights and Illumination 8-28
3.0 ANTI BIO FOULING TECHNOLOGIES 8-29
3.1 Air Sparges 8-29
3.2 Cu-Ni Alloys 8-29
3.3 Chemical Injection 8-29
3.4 Hot Kill 8-29
III. CONCLUSION 8-29
Attachment A to Chapter 8 8A-1
List of Exhibits
Exhibit 1-1. Performance Standard Requirements 1-2
Exhibit 1-2. Summary of Comprehensive Demonstration Study Requirements for Compliance Alternatives 1-4
Exhibit 2-1. Cooling Water Use in Surveyed Industries 2-2
Exhibit 2-2. Distribution of Source Waterbodies for Phase III Facilities 2-3
Exhibit 2-3. Design Intake Flows at Facilities Potentially Regulated Under Phase III 2-3
Exhibit 2-4. Design Intake Flow by Industry Type 2-4
Exhibit 2-5. Industry Overview 2-4
Exhibit 2-6. Distribution of Cooling Water System Configurations 2-5
Exhibit 2-7. Distribution of Cooling Water Intake Structure Arrangements 2-5
Exhibit 2-8. Distribution of Cooling Water Intake Structure (CWIS) Design Through-Screen Velocities 2-5
Exhibit 2-9. Distribution of Intake Technologies 2-6
Exhibit 2-10. Distribution of Manufacturing Facilities by Number of Operating Days 2-7
Exhibit 2-11. Technologies Already In Place at Facilities Potentially Regulated Under Phase III 2-7
Exhibit 3-1. Fine Mesh Passive T-Screen Design Specifications 3-2
Exhibit 3-2. Very Fine Mesh Passive T-Screen Design Specifications 3-2
Exhibit 3-3. Minimum Depth at Screen Location For Single Screen Scenario 3-4
Exhibit 3-4. List of States with Freshwater Zebra Mussels as of 2001 3-6
Exhibit 3-5. T-Screen Equipment and Installation Costs 3-7
Exhibit 3-6. Sheet Pile Wall Capital Costs for Fine Mesh Screens 3-8
Exhibit 3-7. Sheet Pile Wall Capital Costs for Very Fine Mesh Screens 3-9
Exhibit 3-8. Capital Costs of Airburst Air Supply Equipment 3-10
Exhibit 3-9. Capital Costs of Installed Air Supply Pipes for Fine Mesh Screens 3-11
Exhibit 3-10. Total Capital Costs of Installed Fine Mesh T-screen System at Existing Shoreline
Based Intakes 3-12
IV
-------
S 316(b) Phase III - Technical Development Document Table of Contents
Exhibit 3-11. Total Capital Costs of Installed Very Fine Mesh T-screen System at Existing Shoreline
Based Intakes 3-12
Exhibit 3-12. Estimated Costs for Dive Team to Inspect and Clean T-screens 3-14
Exhibit 3-13. Total O&M Costs for Passive Screens Relocated Offshore 3-14
Exhibit 3-14. Selection of Applicable Relocation Offshore Pipe Lengths By Waterbody 3-16
Exhibit 3-15. Capital Cost of Installing Fine Mesh Passive T-screens at an Existing Submerged Offshore Intake 3-17
Exhibit 3-16. Capital Cost of Installing Very Fine Mesh Passive T-screens at an Existing Submerged Offshore Intake .. 3-17
Exhibit 3-17. Net Intake O&M Costs for Fine Mesh Passive T-screens Installed at Existing Submerged Offshore
Intakes 3-18
Exhibit 3-18. Guidance for Selecting Screen Well Depth for Cost Estimation 3-40
Exhibit 3-19. Compliance Action Scenarios and Corresponding Cost Components 3-41
Exhibit 3-20. Equipment Costs for Traveling Screens with Fish Handling for Freshwater Environments,
2002 Dollars 3-43
Exhibit 3-21. Equipment Costs for Traveling Screens with Fish Handling for Saltwater Environments,
2002 Dollars 3-43
Exhibit 3-22. Traveling Screen Installation Costs 3-44
Exhibit 3-23. Fish Spray Pump Equipment and Installation Costs 3-46
Exhibit 3-24. Spray Pump and Flume Costs 3-47
Exhibit 3-25. Total Capital Costs for Scenario A - Adding Fine Mesh Without Fish Handling Freshwater Environments 3-61
Exhibit 3-26. Total Capital Costs for Scenario A - Adding Fine Mesh Without Fish Handling Saltwater Environments . 3-61
Exhibit 3-27. Total Capital Costs for Scenario B - Adding Fish Handling and Return Freshwater Environments 3-62
Exhibit 3-28. Total Capital Costs for Scenario B - Adding Fish Handling and Return Saltwater Environments 3-62
Exhibit 3-29. Total Capital Costs for Scenario C - Adding Fine Mesh with Fish Handling and Return Freshwater
Environments 3-63
Exhibit 3-30. Total Capital Costs for Scenario C - Adding Fine Mesh with Fish Handling and Return Saltwater
Environments 3-63
Exhibit 3-31. Basic Annual O&M Labor Hours for Coarse Mesh Traveling Screens Without Fish Handling 3-48
Exhibit 3-32. Basic Annual O&M Labor Hours for Traveling Screens With Fish Handling 3-48
Exhibit 3-33. Total Annual O&M Hours for Fine Mesh Overlay Screen Placement and Removal 3-49
Exhibit 3-34. Screen Drive Motor Power Costs 3-50
Exhibit 3-35. Wash Water Power Costs Traveling Screens Without Fish Handling 3-50
Exhibit 3-36. Wash Water and Fish Spray Power Costs Traveling Screens With Fish Handling 3-50
Exhibit 3-37. Mix of O&M Cost Components for Various Scenarios 3-51
Exhibit 3-38. Baseline O&M Costs for Traveling Screens Without Fish Handling Freshwater Environments 3-64
Exhibit 3-39. Baseline O&M Costs for Traveling Screens Without Fish Handling Saltwater Environments 3-64
Exhibit 3-40. Baseline & Scenario B Compliance O&M Totals for Traveling Screens With Fish Handling Freshwater
Environments 3-65
Exhibit 3-41. Baseline & Scenario B Compliance O&M Totals for Traveling Screens With Fish Handling Saltwater
Environments 3-65
Exhibit 3-42. Scenario A & C Compliance O&M Totals for Traveling Screens With Fish Handling Freshwater
Environments 3-66
Exhibit 3-43. Scenario A & C Compliance O&M Totals for Traveling Screens With Fish Handling Saltwater
Environments 3-66
Exhibit 3-44. Nuclear Facility O&M Cost Factors 3-52
Exhibit 3-45. Capital Cost Factors for Dual-Flow Screens 3-53
Exhibit 3-46. Total Capital Costs for Adding New Larger Intake Screen Well Structure in Front of Existing
Shoreline Intake 3-57
Exhibit 3-47. Velocity Cap Retrofit Capital and O&M Costs (2002 $) 3-81
Exhibit 3-48. Installation and Maintenance Diver Team Costs 3-82
Exhibit 3-49. Net Velocity Data Derived from Barrier Net Questionnaire Data 3-85
Exhibit 3-50. Available Barrier Net Mesh Size Data 3-86
Exhibit 3-51 Net Size and Cost Data 3-89
Exhibit 3-52. Capital Costs for Scenario A Fish Barrier Net With Anchors/Buoys as Support Structure 3-89
Exhibit 3-53. Pile Costs and Net Section Flow 3-90
Exhibit 3-54. Capital Costs for Fish Barrier Net With Piling Support Structure for 10 Ft Deep Nets 3-85
Exhibit 3-55 Capital Costs for Fish Barrier Net With Piling Support Structure for 20 Ft Deep Nets 3-85
Exhibit 3-56. Capital Costs for Fish Barrier Net With Piling Support Structure for 30 Ft Deep Nets 3-85
Exhibit 3-57. Cost Basis for O&M Costs 3-86
-------
§ 316(b) Phase HI - Technical Development Document Table of Contents
Exhibit 3-58. Annual O&M Cost Estimates 3-88
Exhibit 3-59. Capital Costs for Aquatic Filter Barrier Provided by Vendor 3-98
Exhibit 3-60. Estimated AFB Annual O&M Costs 3-99
Exhibit 3-61. Capital and O&M costs for Replacing Existing Coarse Screen with Fine Mesh Screen 3-102
Exhibit 3-62. Capital and O & M Costs for Enlarging Intake Internally 3-103
Exhibit 3-63. Capital and O&M Costs for Enlarging Intake Externally 3-108
Exhibit 3-64. Capital and O&M Costs for Intake Modification Using Flow Modifier for Vessels with
Bottom Sea Chests 3-111
Exhibit 3-65. Capital and O&M Costs for Intake Modification Using Flow Modifier for Vessels with
Side Sea Chests 3-111
Exhibit 3-66. Number of Wells Drilled Annually, 1995 -1997, By Geographic Area 3-131
Exhibit 3-67. Identification of Structures in the Gulf of Mexico OCS 3-136
Exhibit 3-68. Description of Mobile Offshore Drilling Units and Their Cooling Water Intake Structures 3-137
Exhibit 3-69. 316(b) Phase III Survey Statistics 3-142
Exhibit 3-70. Number of In-Scope Facilities and Number Sampled by Frame 3-143
Exhibit 3-71. Oil & Gas Extraction Facilities - Information Collected from Internet Sources
Exhibit 3-72. Regulatory Options and the Technologies Applicable to Each Option 3-152
Exhibit 3-73. Installed Capital Cost Equations and Variables for Stationary Platforms 3-155
Exhibit 3-74. Operating and Maintenance (O&M) Cost Equations and Variables Used for Stationary Platforms 3-157
Exhibit 3-75. Installed Capital Cost Equations and Variables for Jack-Up MODUs 3-158
Exhibit 3-76. Installed Capital Cost Equations and Variables for Submersibles, Semi-Submersibles, Drill Ships, and
Drill Barge MODUs 3-159
Exhibit 3-77. Summary of Technology Option Costs for Existing Oil and Gas Extraction Facilities 3-160
Exhibit 3-78. Five Existing Onshore LNG Import Terminals 3-167
Exhibit 3-79. Proposed U.S. Onshore LNG Import Terminals 3-172
Exhibit 3-80. Proposed U.S. Offshore LNG Import Terminals 3-174
Exhibit 3-81. Number and Type of Surface Water Intake Structures at Five Proposed Offshore LNG Import
Terminals 3-188
Exhibit 3-82. Cost Equations and Design Variables for Entrainment and Impingement Equipment at LNG
Import Terminals 3-189
Exhibit 3-83. Estimated Total Costs for Impingement and Entrainment Equipment at Five Proposed LNG
Import Terminals 3-190
Exhibit 3-84. Screening Level Estimates for LNG Import Terminals to Construct and Operate SCV Systems 3-192
Exhibit 3-85. O&M Cost Component Fixed Factor 3-194
Exhibit 3-86. Baseline Technology Fixed O&M Cost Factors 3-196
Exhibit 3-87. Compliance Technology Fixed O&M Cost Factors 3-197
Exhibit 4-1. Performance Standards for the Regulatory Options Considered 4-3
Exhibit 5-1. Break-Even Analysis for Facilities that Might Reduce Capacity Utilization Rates To
Avoid Entrainment Controls 5-3
Exhibit 5-2. Threshold Comparison Analysis 5-3
Exhibit 5-3. Proposed Regulatory Options for Offshore Oil and Gas Extraction Facilities 5-5
Exhibit 5-4. Proposed Technology Options for Seafood Processing Vessels 5-6
Exhibit 5-5. Technology Codes and Descriptions 5-6
Exhibit 5-6. Mean Intake Water Depth and Well Depth at Phase III Facilities 5-11
Exhibit 5-7. Through-Screen Velocity at Phase III Facilities 5-11
Exhibit 5-8. Data Sources for Baseline Impingement and Entrainment Technologies In-place 5-12
Exhibit 5-9. Baseline Cost Factors for Control Technologies 5-14
Exhibit 5-10. Baseline Technology Fixed O&M Cost Factors 5-14
Exhibit 5-11. Compliance Technology Fixed O&M Cost Factors 5-15
Exhibit 5-12. Initial Capital-Cost Equations for Phase III Technology Upgrades 5-15
Exhibit 5-13. Plant Type Cost Factors 5-16
Exhibit5-14. Regional Cost Factors and List of States with Freshwater Zebra Mussels as of 2001 5-17
Exhibit 5-15. Baseline O&M Cost Equations for Phase II Technology Upgrades 5-18
Exhibit 5-16. Initial Gross Compliance O&M Cost Equations for Phase III Technology Upgrades 5-18
Exhibit 5-17. Information Collection Request Cost for Facility A and Facility B 5-19
Exhibit 5-18. Construction Cost Estimating Categories 5-27
vi
-------
§ 316(b) Phase HI - Technical Development Document Table of Contents
Exhibit 5-19. Relative Proportion of Each Capital Cost Component for Freshwater Applications . 5-28
Exhibit 5-20. Relative Proportion of Each O&M Cost Component for Freshwater Applications 5-30
Exhibit 5-21. Compliance Module Scenarios and Corresponding Cost Component Relative
Proportions for 10 ft Wide and 25 ft Deep Screen Well 5-32
Exhibit 5-22. Compliance Module Scenarios and Corresponding O&M Cost Component
Relative Proportions for 10 ft Wide and 25 ft Deep Screen Well 5-36
Exhibit 5-23. Weeks of Downtime Included in Costs of Technology Modules 5-41
Exhibit 6.A-1 • Results of Technology Costing 6A-1
Exhibit 6A-2. Assigning Zero Reductions 6A-3
Exhibit 6A-3. Assigning Reductions Under Option 5 6A-4
Exhibit 6A-4. Assigning Reductions Under the Proposed Option, with 5% Adaptive Management 6A-5
Exhibit 6A-5. Assigning Reductions Under Option 2, Including Incidental Benefits 6A-6
Exhibit 7-1. Technology Codes and Descriptions 7-3
Exhibit 7-2. Costs Considered by EPA in Establishing Performance Standards ($2002) 7-5
Exhibit 7-3. Facility ID and Facility Name for All Facilities Not Claiming Survey Information CBI 7-6
List of Figures
Figure 3-1. Capital Costs Conventional Steel Pipe Laying Method at Various Offshore Distances 3-22
Figure 3-2. Capital Costs for Fine Mesh Passive Screen Relocation Offshore in Freshwater at Selected
Offshore Distances 3-23
Figure 3-3. Capital Costs for Mesh Passive Screen Relocation Offshore in Saltwater at Selected Offshore Distances ... 3-24
Figure 3-4. Capital Costs for Fine Mesh Passive Screen Relocation Offshore in Freshwater with Zebra
Mussels at Selected Offshore Distances 3-25
Figure 3-5. Capital Costs for Very Fine Mesh Passive Screen Relocation Offshore in Freshwater at Selected
Offshore Distances 3-26
Figure 3-6. Capital Costs for Very Fine Mesh Passive Screen Relocation Offshore in Selected Offshore Distances .... 3-27
Figure 3-7. Capital Costs for Very Fine Mesh Passive Screen Relocation Offshore in Freshwater with Zebra Mussels
at Selected Offshore Distances 3-28
Figure 3-8. Total O&M Cost for Fine Mesh Passive Screen Relocated Offshore with Airburst Backwash 3-29
Figure 3-9. Total O&M Cost for Very Fine Mesh Passive Screen Relocated Offshore with Airburst Backwash 3-30
Figure 3-10. Capital Costs for Fine Mesh Passive Screen Existing Offshore in Freshwater at Selected
Offshore Distances 3-31
Figure 3-11. Capital Costs for Fine Mesh Passive Screen Existing Offshore in Saltwater at Selected
Offshore Distances 3-32
Figure 3-12. Capital Costs for Fine Mesh Passive Screen Existing Offshore in Freshwater with Zebra Mussels at
Selected Offshore Distances 3-33
Figure 3-13. Capital Costs for Very Fine Mesh Passive Screen Existing Offshore in Freshwater at Selected
Offshore Distances 3-34
Figure 3-14. Capital Costs for Very Fine Mesh Passive Screen Existing Offshore in Saltwater at Selected
Offshore Distances 3-35
Figure 3-15. Capital Costs for Very Fine Mesh Passive Screen Existing Offshore in Freshwater with Zebra
Mussels at Selected Offshore Distances 3-36
Figure 3-16. Total O&M Costs for Fine Mesh Passive Screen Existing Offshore with Airburst Backwash 3-37
Figure 3-17. Total O&M Costs for Very Fine Mesh Passive Screen Existing Offshore with Airburst Backwash 3-38
Figure 3-18. Scenario A - Capital Cost - Add Fine Mesh Replacement Screen Panels Freshwater 3-66
Figure 3-19. Scenario A - Capital Cost - Add Fine Mesh Replacement Screen Panels Saltwater 3-67
Figure 3-20. Scenario B - Capital Cost - Add Traveling Screen with Fish Handling and Return Freshwater 3-68
Figure 3-21. Scenario B - Capital Cost - Add Traveling Screen with Fish Handling and Return Saltwater 3-69
Figure 3-22. Scenario C - Capital Cost - Add Fine Mesh Traveling Screen With and Fish Handling and
Return Saltwater 3-70
Figure 3-23. Scenario C - Capital Cost - Add Fine Mesh Traveling Screen With and Fish Handling and
Return Freshwater 3-71
Figure 3-24. Baseline O&M Costs for Traveling Screens Without Fish Handling Freshwater Environments 3-72
Figure 3-25. Baseline O&M Costs for Traveling Screens Without Fish Handling Saltwater Environments 3-73
vii
-------
§ 316(b) Phase III - Technical Development Document Table of Contents
Figure 3-26. Scenarios A & C Compliance O&M Total Costs for Traveling Screens With Fish Handling
Freshwater Environments 3-74
Figure 3-27. Scenarios A & C Compliance O&M Total Costs for Traveling Screens With Fish Handling
Saltwater Environments 3-75
Figure 3-28. Baseline & Scenarios B Compliance O&M Total Costs for Traveling Screens With Fish Handling
Freshwater Environments 3-76
Figure 3-29. Baseline & Scenarios B Compliance O&M Total Costs for Traveling Screens With Fish Handling
Saltwater Environments 3-77
Figure 3-30. Total Capital Costs of New Larger Intake Structure 3-78
Figure 3-31. Velocity Cap Capital Costs 2002 Dollars 3-83
Figure 3-32. Velocity Cap O&M Cost 2002 Dollars 3-84
Figure 3-33. Total Capital Costs for Fish Barrier Nets 3-95
Figure 3-34. Barrier Net Annual O&M Costs 3-96
Figure 3-35. Gunderboom Capital and O&M Costs for Floating Structure in 2002 Dollars 3-100
Figure 3-36. Enlarged (Internal) Fine Mesh Sea Water Intake Configuration 3-104
Figure 3-37. Outer Bar Screen (for Internal and External Intake Modification) 3-104
Figure 3-38. Fine Mesh Inner Screen (for Internal and External Intake Modification) 3-105
Figure 3-39. Fine Mesh Frame and Inner Diffuser (for Internal and External Intake Modification) 3-106
Figure 3-40. Main Frame for Internal Intake Modification 3-107
Figure 3-41. External (Protruding) Fine Mesh Sea Water Intake Configuration 3-109
Figure 3-42. Main Frame for External (Protruding) Intake Modification 3-109
Figure 3-43. Plan View of Bottom Sea Chest Horizontal Flow Modifier 3-112
Figure 3-44. Sectional View of Bottom Sea Chest Horizontal Flow Modifier 3-113
Figure 3-45. Plan View of Side Sea Chest Horizontal Flow Modifier 3-114
Figure 3-46. Sectional View of Side Sea Chest Horizontal Flow Modifier 3-115
Figure 3-47 Capital Cost for Replacing Existing Grill with Fine Mesh Stainless Steel Screen 3-116
Figure 3-48. Capital Cost for Replacing Existing Grill with Fine Mesh Cu/Ni Screen 3-117
Figure 3-49. Capital Costs for Enlarging Intake Internally With Stainless Steel Fine Mesh Screen 3-118
Figure 3-50. O&M Costs for Enlarging Intake Internally With Stainless Steel Fine Mesh Screen 3-119
Figure 3-51. Capital Costs for Enlarging Intake Internally With CU/Ni Fine Mesh Screen 3-120
Figure 3-52. O&M Costs for Enlarging Intake Internally With CU/Ni Fine Mesh Screen 3-121
Figure 3-53. Capital Costs for Enlarging Intake Externally With Stainless Steel Fine Mesh Screen 3-122
Figure 3-54. O&M Costs for Enlarging Intake Externally With Stainless Steel Fine Mesh Screen 3-123
Figure 3-55. Capital Costs for Enlarging Intake Externally With Cu/Ni Fine Mesh Screen 3-124
Figure 3-56. O&M Costs for Enlarging Intake Externally With Cu/Ni Fine Mesh Screen 3-125
Figure 3-57. Capital Costs for Intake Modification Using Flow Modifier for Vessels with Side Sea Chest 3-126
Figure 3-58. O&M Costs for Intake Modification Using Flow Modifier for Vessels with Side Sea Chest 3-127
Figure 3-59. Capital Costs for Intake Modification Using Flow Modifier for Vessels with Bottom Sea Chest 3-128
Figure 3-60. O&M Costs for Intake Modification Using Flow Modifier for Vessels with Bottom Sea Chest 3-129
Figure 3-61. Fixed Oil and Gas Extraction Facilities 3-132
Figure 3-62. Offshore Seachest Cooling Water Intake Structure Design 3-133
Figure 3-63. Offshore Simple Pipe Cooling Water Intake Structure Design (Schematic) 3-133
Figure 3-64. Offshore Simple Pipe Cooling Water Intake Structure Design - Wet Leg 3-134
Figure 3-65. Offshore Caisson Cooling Water Intake Structure Design (Thompson Culvert Company) 3-134
Figure 3-66. Offshore Caisson Cooling Water Intake Structure Design - Leg Mounted Well Tower 3-135
Figure 3-67. Offshore Caisson Cooling Water Intake Structure Design - Conventional Well Tower 3-135
Figure 3-68. Mobile Oil and Gas Extraction Facilities 3-137
Figure 3-69. Liberty Island Cooling Water Intake Structure 3-141
Figure 3-70. Gulf of Mexico Oil and Gas Extraction Facilities 3-145
Figure 3-71. Gulf of Mexico Oil and Gas Extraction Facilities That Withdraw More than 2 MOD of
Seawater with More than 25% of the Intake Is Used for Cooling 3-146
Figure 3-72. Cook Inlet, Alaska, Oil and Gas Extraction Facilities 3-146
Figure 3-73. California Oil and Gas Extraction Facilities 3-147
Figure 3-74. Cylindrical Wedgewire Screen (Johnson Screens) 3-151
Figure 3-75. Schematic of Seabed Mounted Velocity Cap 3-152
Figure 3-76. Cylindrical Wedgewire Screen with Air Sparging (Johnson Screens) 3-163
vm
-------
3 316(b) Phase III - Technical Development Document Table of Contents
Figure 3-77. Design Intake Flow for Production Platforms with Surface Water Intakes Greater than 2 MGD
and Installation Year 3-165
Figure 3-78. Existing and Proposed North American LNG Terminals 3-169
Figure 3-79. Current and Potential Future U.S. LNG Import Capacity 3-169
Figure 3-80. EcoElectrica Simplified Flow Diagram 3-171
Figure 3-81. Open Rack Vaporizer (from Port Pelican LLC Deepwater Port License Application) 3-177
Figure 3-82. Compass Port LLC Proposed LNG Import Terminal 3-180
Figure 3-83. Conversion Gas Imports Re-Gasification Schematic 3-184
Figure 5-1. Flow Chart for Assigning Cost Modules 5-8
Figure 5-2. Screen Capture of Cost-Test Tool User Inputs 5-9
Figure 7-1. Module 1: Add fish handling and return system to traveling screens 7-7
Figure 7-2. Module 2: Add fine-mesh screens to traveling screens 7-7
Figure 7-3. Module 3: Add new, larger intake in front of existing intake 7-8
Figure 7-4. Module 4: Add passive fine-mesh screen near shoreline w/1.75 mm mesh 7-8
Figure 7-5. Module 5: Add fish net barrier system 7-9
Figure 7-6. Module 6: Add aquatic filter barrier system 7-9
Figure 7-7. Module 7: Relocate to submerged offshore w/passive fine-mesh screen inlet & 1.75 mm mesh 7-10
Figure 7-8. Module 8: Add velocity cap inlet to offshore intake 7-10
Figure 7-9. Module 9: Add passive fine-mesh screen to offshore intake w/1.75 mm mesh 7-11
Figure 7-10. Module 11: Add dual-entry, single-exit traveling screens (with fine-mesh) 7-11
Figure 7-11. Module 12: Add passive fine-mesh screen near shoreline w/ 0.76 mm mesh ... 7-12
Figure 7-12. Module 13: Add passive fine-mesh screen to offshore intake w/ 0.76 mm mesh 7-12
Figure 7-13. Module 14: Relocate to submerged offshore w/ passive fine-mesh screen inlet & 0.76 mm mesh 7-13
IX
-------
-------
§ 316(b) Phase HI - Technical Development Document Summary of the Proposed Rule
Chapter 1: Summary of the Proposed Rule
1.0 APPLICABILITY OF THE PROPOSED RULE
The proposed 316(b) rule for Phase III would apply to two groups of facilities that use cooling water intake structures to withdraw
water from waters of the U.S. First, it would apply to existing facilities not already regulated by EPA's "Phase II" regulation that
withdraw above a certain flow threshold (see below). Based on the co-proposed flow thresholds, the proposed rule would, in effect,
only apply to existing manufacturing and industrial facilities. Phase III existing facilities are defined in § 125.101 and § 125.102 of
the proposed rule, and include existing manufacturing and industrial facilities (including but not limited to chemical, metal, pulp and
paper, and petroleum refining facilities) that meet the criteria specified below. Under the proposed rule, these facilities would be
subject to similar requirements to the final 316(b) rule for Phase II, with Phase III requirements specified in Part 125, Subpart K.
Second, the proposed rule would apply to new offshore oil and gas extraction facilities, with requirements specified in Part 125,
Subpart N.
Existing facilities must meet all of the following criteria to be considered a "Phase III existing facility" subject to the uniform national
requirements of proposed rule:
• The facility is a point source that has or is required to have a NPDES permit under section 402 of the Clean Water Act;
• The facility is an existing facility other than a Phase II existing facility;
• The facility uses at least 25 percent of water withdrawn exclusively for cooling purposes, measured on an average annual basis;
and
• The facility uses, or proposes to use, cooling water intake structures, including a cooling water intake structure operated by an
independent supplier, with a total design intake flow equal to or greater than the proposed threshold in million gallons per day
(MOD) to withdraw cooling water from waters of the United States.
The proposed rules describe three regulatory options based on design intake flow and source waterbody type that define which
facilities would be Phase III existing facilities subject to uniform national requirements:
• The facility has a total design intake flow of 50 MGD or more, and withdraws from any source waterbody type;
• The facility has a total design intake flow of 200 MGD or more, and withdraws from any source waterbody type;
• The facility has a total design intake flow of 100 MGD or more, and withdraws water from an ocean, estuary, tidal river or stream,
or Great Lake.
If a facility is a point source that uses a cooling water intake structure and has, or is required to have, an NPDES permit, but does not
meet the appropriate threshold based on design intake flow/source waterbody typeor the 25% cooling purposes threshold, it would be
subject to permit conditions implementing section 316(b) of the Clean Water Act set by the permit director on a case-by-case basis,
using best professional judgment (BPJ). For example, under the 100 MGD coastal and Great Lakes option, facilities withdrawing from
a freshwater river or stream would not be subject to national requirements, but rather to site-specific best professional judgment (BPJ)-
based limits.
The proposed Phase III rule also would make new offshore oil and gas extraction facilities subject to requirements similar to those
under the final Phase I new facility regulation (40 CFR 125 Subpart I). Requirements for new offshore oil and gas extraction facilities
are proposed in a new Subpart N. For purposes of this proposed rule, new offshore oil and gas extraction facilities are those facilities
that are subject to the Oil and Gas Extraction Point Source Category Effluent Guidelines (i.e., 435.10 Offshore Subcategory or 435.40
Coastal Subcategory), and meet the definition of "new offshore oil and gas extraction facility" in proposed Subpart N, § 125.133.
2.0 AFFECTED SUBCATEGORIES
The national requirements of the proposed rule may apply to existing facilities in the following sectors: chemical and allied products,
primary metals, paper and allied products, petroleum and coal products, and other industries. In addition, facilities not covered by the
national requirements would continue to be subject to permit requirements that implement section 316(b) requirements on case-by-
case, BPJ basis. The following is a list of industries potentially affected by Phase III section 316(b) through either national
requirements or BPJ-based limits. A detailed description of the industry sectors subject to the proposed rule is found in Chapter 2 of
the TDD.
1-1
-------
§ 316(b) Phase III - Technical Development Document
Summary of the Proposed Rule
Industries Potentially Affected bv Section 316(b) Phase III
Operators of steam electric generating point source dischargers that employ cooling water intake structures.
Agricultural production
Metal mining
Oil and gas extraction
Mining and quarrying of nonmetallic minerals
Food and kindred products
Tobacco products
Textile mill products
Lumber and wood products, except furniture
Paper and allied products
Chemical and allied products
Petroleum refining and related industries
Rubber and miscellaneous plastics products
Stone, clay, glass, and concrete products
Primary metal industries
Fabricated metal products, except machinery and transportation equipment
Industrial and commercial machinery and computer equipment
Transportation equipment
Measuring, analyzing, and controlling instruments; photographic, medical, and optical goods; watches and clocks
Electric, gas, and sanitary services
Educational services
Engineering, accounting, research, management and related services
3.0 OVERVIEW OF THE PROPOSED REQUIREMENTS
As in Phase I and II, section 316(b) requirements for Phase III existing facilities would be implemented through the NPDES permit
program. The proposed 316(b) rule for phase III existing facilities would establish performance standards similar to those that exist in
the Phase II rule for Phase II existing facilities. The performance standards would consist of ranges of reductions in impingement
mortality and/or entrainment (e.g., reduce impingement mortality by 80 to 95 percent and/or entrainment by 60 to 90 percent). These
performance standards reflect the best technology available for minimizing adverse environmental impacts determined on a national
categorical basis. The type of performance standard applicable to a particular facility (i.e., reductions in impingement mortality only
or impingement mortality and entrainment) would be based on several factors, including the facility's location (i.e., source waterbody),
and the proportion of the waterbody withdrawn. The proposed rule would establish requirements for new offshore oil and gas
extraction facilities that are similar to requirements established under the 316(b) Phase I rule for other new facilities. These
requirements are described below.
3.1 Phase III Existing Facilities
As noted above, performance requirements would vary under the proposed rule depending upon the location (waterbody) of the facility
and the proportion of the waterbody withdrawn for cooling. Exhibit 1-1 presents the proposed performance standard requirements for
Phase III existing facilities.
Exhibit 1-1. Performance Standard Requirements
Waterbody Type
Freshwater River or Stream
Tidal river, Estuary, Ocean, or Great
Lakes
Lakes or Reservoirs
Design Intake Flow
5% or less of mean annual flow
Greater than 5% of mean annual flow
N/A
Increase in design intake flow must not
disrupt thermal stratification except where
it does not adversely affect the
management of fisheries.
Type of Performance Standard
Impingement mortality only
Impingement mortality and entrainment
Impingement mortality and entrainment
Impingement mortality only
1-2
-------
§ 316(b) Phase III - Technical Development Document Summary of the Proposed Rule
As in the Phase II final rule, the proposed Phase III rale identifies five alternatives a Phase III existing facility may use to achieve
compliance with the requirements for best technology available for minimizing adverse environmental impacts associated with cooling
water intake structures. Four of these alternatives are based on meeting the applicable performance standards and the fifth allows the
facility to request a site-specific determination of best technology available for minimizing adverse environmental impacts under
certain circumstances. Application requirements would vary based on the compliance alternative selected and, for some facilities,
include development of a Comprehensive Demonstration Study (see, section VII, Implementation, of the preamble to the proposed
Phase III rale).
Under the first proposed compliance alternative (at § 125.103(a)(l)(i) and (ii)), a Phase III existing facility may demonstrate to the
Director that it has already reduced its flow commensurate with a closed-cycle recirculating system, or that it has already reduced its
design intake velocity to 0.5 feet per second or less. If a facility can demonstrate to the Director that it has reduced, or will reduce,
flow commensurate with a closed-cycle recirculating system, the facility is deemed to have met the performance standards to reduce
impingement mortality and entrainment (see § 125.103(a)(l)(i)). Those facilities would not be required to submit a Comprehensive
Demonstration Study with their NPDES application. If the facility can demonstrate to the Director that is has reduced, or will reduce
maximum through-screen design intake velocity to 0.5 feet per second or less, the facility is deemed to have met the performance
standards to reduce impingement mortality only. Facilities that meet the velocity requirements would only need to submit application
studies related to determining entrainment reduction, if subject to the performance standards for entrainment.
Under § 125.103(a)(2) and (3), a Phase III existing facility may demonstrate to the Director either that its current cooling water intake
structure configuration meets the applicable performance standards or that it has selected design and construction technologies,
operational measures, and/or restoration measures that, in combination with any existing design and construction technologies,
operational measures, and/or restoration measures, meet the specified performance standards in § 125.103(b) and/or the requirements
in§125.103(c).
Under § 125.103(a)(4), a Phase III existing facility may demonstrate to the Director that it has installed and is properly operating and
maintaining a rule-specified and approved design and construction technology in accordance with § 125.108(a). Submerged
cylindrical wedgewire screen technology is proposed as a rule-specified design and construction technology that may be used in
instances in which a facility's cooling water intake structure is located in a freshwater river or stream and meets other criteria specified
at § 125.108(a). In addition, under the fourth compliance alternative, a facility or other interested person may submit a request to the
Director for approval of a different technology. If the Director approves the technology, the proposed rule states that it may be used by
all facilities with similar site conditions under his or her jurisdiction if allowed under the State's administrative procedures. Under the
proposed rule, a Director may only approve an alternative technology following public notice and opportunity for comment on the
approval of the technology (§ 125.108(b)).
Under the fifth proposed compliance alternative (at § 125.103(a)(5) (i) or (ii)), if the Director determines that a facility's costs of
compliance would be significantly greater than the costs considered by the Administrator for a like facility to meet the applicable
performance standards, or that the costs of compliance would be significantly greater than the benefits of meeting the applicable
performance standards at the facility, the Director must make a site-specific determination of best technology available for minimizing
adverse environmental impact. Under this alternative, a facility would either compare its projected costs of compliance using a
particular technology or technologies to the costs the Agency considered for a like facility in establishing the applicable performance
standards, or compare its projected costs of compliance with the projected benefits at its site of meeting the applicable performance
standards of this proposed rale. If in either case costs are significantly greater, the technology selected by the Director must achieve an
efficacy level that comes as close as practicable to the applicable performance standards without resulting in significantly greater costs.
Additionally, the proposed rale states that during the first permit term, a facility that chooses compliance alternatives in §
125.103(a)(2), (3), (4), or (5) may request that compliance with the requirements of this rale be determined based on the
implementation of a Technology Installation and Operation Plan indicating how the facility will install and ensure the efficacy, to the
extent practicable, of design and construction technologies and/or operational measures, and/or a Restoration Plan (§ 125.103(d)).
The Technology Installation and Operation Plan must be developed and submitted to the Director in accordance with §
125.104(b)(4)(ii). The Restoration Plan must be developed in accordance with § 125.104(b)(5). During subsequent permit terms, if
the facility has been in compliance with the construction, operational, maintenance, monitoring, and adaptive management
requirements in its Technology Installation and Operation Plan and/or Restoration Plan during the preceding permit term, the facility
may request that compliance during subsequent permit terms be based on its remaining in compliance with its Technology Installation
and Operation Plan and/or Restoration Plan, revised in accordance with applicable adaptive management requirements if the applicable
performance standards are not being met.
1-3
-------
§ 316(b) Phase III - Technical Development document
Summary of the Proposed Rule
Similar to the Phase II requirements, Phase III existing facilities would be required to submit three sets of data at least 180 days prior
to expiration of a facility's existing permit by all facilities regardless of compliance alternative selected (see § 122.21(r)(2)(3) and
(5)). These are:
• Source Water Physical Data: a narrative description and scaled drawings showing the physical configuration of all source
waterbodies used by the facility, including areal dimensions, depths, salinity and temperature regimes, and other documentation
that supports its determination of the waterbody type where each cooling water intake structure is located; identification and
characterization of the source waterbody's hydrological and geomorphological features, as well as the methods used to conduct
any physical studies to determine the intake's area of influence and the results of such studies; and locational maps.
• Cooling Water Intake Structure Data: a narrative description of the configuration of each of the facility's cooling water intake
structures and where it is located in the waterbody and in the water column; latitude and longitude in degrees, minutes, and
seconds for each of its cooling water intake structures; a narrative description of the operation of each of its cooling water intake
structures, including design intake flows, daily hours of operation, number of days of the year in operation, and seasonal changes,
if applicable; a flow distribution and water balance diagram that includes all sources of water to the facility, recirculating flows,
and discharges; and engineering drawings of the cooling water intake structure.
• Cooling Water System Data: a narrative description of the operation of each cooling water system, its relationship to the cooling
water intake structures, proportion of the design intake flow that is used in the system, the number of days of the year the system
is in operation, and seasonal changes in the operation of the system, if applicable; and engineering calculations and supporting
data to support the narrative description.
In addition to the specified data facilities would be required to submit, some facilities would also be required to conduct a
Comprehensive Demonstration Study. Specific requirements for the Comprehensive Demonstration Study would vary based on the
compliance alternative selected. Exhibit 1-2 summarizes the Comprehensive Demonstration Study requirements for each proposed
compliance alternative. Specific details of each Comprehensive Demonstration Study component are provided in section VII of this
preamble.
Exhibit 1-2. Summary of Comprehensive Demonstration Study Requirements for Compliance Alternatives
Compliance
Alternative (§ 125.103(a))
Comprehensive Demonstration Study Requirements
(§ 125.103(a))
1 - Demonstrate facility has reduced
flow commensurate with closed-
cycle recirculating system
None
1 - Demonstrate facility has reduced
design intake velocity to s 0.5 feet
per second
No requirements relative to impingement mortality reduction. If subject to entrainment
performance standard, the facility must only address entrainment in the applicable
components of its Comprehensive Demonstration Study, based on the compliance option
selected for entrainment reduction.
2 - Demonstrate that existing design
and construction technologies,
operational measures, and/or
restoration measures meet the
performance standards
Proposal for Information Collection
Source Waterbody Flow Information
Impingement Mortality and/or Entrainment Characterization Study (as appropriate)
Technology and Compliance Assessment Information
- Design and Construction Technology Plan
- Technology Installation and Operation Plan
Restoration Plan (if appropriate)
Verification Monitoring Plan
3 - Demonstrate that facility has
selected design and construction
technologies, operational measures,
and/or restoration measures that
will, in combination with any
existing design and construction
technologies, operational measures,
and/or restoration measures, meet
the performance standards
Proposal for Information Collection
Source Waterbody Flow Information
Impingement Mortality and/or Entrainment Characterization Study (as appropriate)
Technology and Compliance Assessment Information
- Design and Construction Technology Plan
- Technology Installation and Operation Plan
Restoration Plan (if appropriate)
Verification Monitoring Plan
1-4
-------
S 316(b) Phase III - Technical Development Document
Summary of the Proposed Rule
Exhibit 1-2. Summary of Comprehensive Demonstration Study Requirements for Compliance Alternatives (continued)
Compliance
Alternative (§ 125.103(a))
Comprehensive Demonstration Study Requirements
(§ 125.103(a))
4 - Demonstrate that facility has
installed and properly operates and
maintains an approved technology
Technology Installation and Operation Plan
Verification Monitoring Plan
Demonstrate that a site-specific
determination of BTA is appropriate
Proposal for Information Collection
Source Waterbody Flow Information
Impingement Mortality and/or Entrainment Characterization Study (as appropriate)
Technology Installation and Operation Plan
Restoration Plan (if appropriate)
Information to Support Site Specific Determination of BTA including:
-Comprehensive Cost Evaluation Study (cost-cost test and cost-benefit test);
-Valuation of Monetized Benefits of Reducing IM&E (cost-benefit test only);
-Site-Specific Technology Plan (cost-cost test and cost-benefit test);
Verification Monitoring Plan ----- .- •-
3.2
New Offshore Oil and Gas Extraction Facilities
Under the proposed Subpart N, new offshore oil and gas extraction facilities that withdraw more than 2 MGD would have to comply
with the requirements in § 122.21(r) and proposed § 125.134. These requirements address fixed and non-fixed (mobile) facilities with
and without sea chests and are similar to requirements in the Phase I rule for new facilities. Under this proposal, new offshore oil and
gas extraction facilities that are fixed facilities and withdraw more than 2 MGD and that do not employ sea chests as cooling water
intake structures would have to comply with the requirements in § 125.134(b)(2) through (8). The same facilities with sea chests must
comply with all of the same requirements except § 125.134(b)(5) for entrainment requirements. Proposed requirements at §
125.134(b) address intake flow velocity, proportional flow restrictions for facilities on tidal rivers or estuaries, specific impact
concerns (e.g., threatened or endangered species, critical habitat, migratory or sport or commercial species), required information
submission, monitoring, and recordkeeping.
Under the proposed Subpart N, new offshore oil and gas extraction facilities that are non-fixed facilities would be required to submit
appropriate Track 1 application requirements under § 122.2l(r) and § 125.136(b). This includes source water physical data, cooling
water intake structure data, velocity information, source waterbody flow information, and a design and construction technology plan.
Facilities would also have the opportunity to request alternative requirements under proposed § 125.135 and provide data to determine
if compliance with the proposed requirements would result in compliance costs wholly out of proportion to those EPA considered in
establishing the requirement, or would result in significant adverse impacts on local air quality, local water resources other than
impingement or entrainment, or local energy markets.
Source Water Physical Data (§ 122.21 (r)(2))
The requirements are the same as those described above for Phase III existing facilities. Track I fixed facilities would submit
all of the data except for proposed § 122.21(r)(2)(iv), only required by non-fixed facilities: a narrative description and/or
locational maps providing information on predicted locations within the waterbody during the permit term in sufficient detail
for the Director to determine the appropriateness of additional impingement requirements under § 125.134(b)(4). Non-fixed
facilities would only be required to submit § 122.21(r)(2)(iv) of the § 122.21(r)(2) requirements.
1-5
-------
S 316(b) Phase III - Technical Development Document Summary of the Proposed Rule
Cooling Water Intake Structure Data (§ 122.2l(r)(3))
The requirements are the same as those described above for Phase III existing facilities for fixed facilities; non-fixed facilities
would only submit f§ 122.21(r)(3)(i) and (ii), narrative description of the configuration of each cooling water intake structure,
and the latitude and longitude for each cooling water intake structure.
Source Water Baseline Biological Characterization Data (§ 122.21(r)(4))
Under the proposed Subpart N, new offshore oil and gas extraction fixed facilities would be required to submit source water
baseline biological characterization data as required for other new facilities under Phase I. The data would be used to
characterize the biological community in the vicinity of the cooling water intake structure and to characterize the operation of
the cooling water intake structure. The data would include existing data (if available) supplemented with new field studies as
necessary. Detailed data requirements are at § 122.21(r)(4). Under the proposed rule, facilities may choose to conduct
regional studies to collect this information as approved by the Director. EPA recognizes that many offshore oil and gas
extraction facilities are regulated under NPDES general permits and that regional studies are typically conducted as part of
the general permit requirements. Under this proposed rule, the regional study would include annual monitoring requirements.
Velocity Information
The proposed rule would require that new offshore oil and gas extraction facilities submit velocity information consistent
with Subpart N requirements found at § 125.136(b)(l). The information would be used to demonstrate to the Director that
the facility is complying with the requirement to meet a maximum through-screen design intake velocity of no more than 0.5
feet per second at the cooling water intake structure. The following information would be required to be submitted: 1) a
narrative description of the design, structure, equipment, and operation used to meet the velocity requirement; and 2) design
calculations showing that the velocity requirement would be met at minimum ambient source water surface elevations (based
on best professional judgment using available hydrological data) and maximum head loss across the screens or other device.
Source Waterbody Flow Information
The proposed rule would also require that new offshore oil and gas extraction facilities submit source waterbody flow
information consistent with Phase I requirements at § 125.136(b)(2). The information would be used to demonstrate to the
Director that the facility's cooling water intake structure meets the proportional flow requirements at § 125.134(b)(3). These
requirements include specific provisions for facilities located on estuaries or tidal rivers to provide greater protection for these
sensitive waters. Specifically, the proposed rule requires that the total design intake flow over one tidal cycle of ebb and flow
must be no greater than one (1) percent of the volume of the water column within the area centered about the opening of the
intake with a diameter defined by the distance of one tidal excursion at the mean low water level. Calculations and guidance
on determining the tidal excursion is found in the preamble to the final Phase I rule at section VII.B.l.d
Design and Construction Technology Plan
The proposed rule also would require that new offshore oil and gas extraction facilities submit a design and construction
technology plan at § 125.136(b)(3). The design and construction technology plan would demonstrate that the facility has
selected and will implement the design and construction technologies necessary to minimize impingement mortality and/or
entrainment. The design and construction technology plan would require delineation of the hydrologic zone of influence for
the cooling water intake structure; a description of the technologies implemented (or to be implemented) at the facility; the
basis for the selection of that technology; the expected performance of the technology, and design calculations, drawings and
estimates to support the technology description and performance. The Agency recognizes that the selection of a specific
technology or a group of technologies will depend on the individual facility and waterbody conditions.
1-6
-------
§ 316(b) Phase III - Technical Development Document Description of the Industry
Chapter 2: Description of the Industry
Today's proposed rule would apply national requirements to two general groups of facilities that use cooling water intake structures to
withdraw water from waters of the U.S. First, it would apply to existing facilities not already regulated by EPA's "Phase II" regulation
that withdraw above a certain flow threshold. Based on the co-proposed thresholds, the proposed rule would in effect only apply to
existing manufacturing and industrial facilities. Based on the co-proposed thresholds, the national requirements would not apply to
existing electric generators not covered under Phase II, existing offshore oil and gas extraction facilities, and existing seafood
processing vessels. Second, the proposed rule would apply to new offshore oil and gas extraction facilities. Although EPA considered
proposing requirements for new seafood processing vessels and offshore liquified natural gas terminals, EPA has opted not to do so,
for reasons described in the proposed preamble and these development documents. This section presents information characterizing all
of the categories of facilities that EPA considered in developing this proposed rule, even if EPA did not ultimately propose national
requirements for such facilities under the proposed rule. EPA has generally categorized all of these industries into two groups: land-
based facilities and offshore facilities.
I. LAND-BASED INDUSTRIES
This category includes existing electric generators not covered under the Phase II rule (those with a design intake flow (DIP) less than
50 million gallons per day (MOD)) and all existing manufacturers. This section will describe these facilities, their source waterbodies,
their intakes, and their intake technologies. Much of the data in this section is derived from the industry questionnaire data.
1.0 DESCRIPTION OF THE INDUSTRIES
In 1997, EPA estimated that over 400,000 facilities could potentially be subject to a cooling water intake regulation. Given the large
number of facilities potentially subject to regulation, EPA decided to focus its data collection efforts on six industrial categories that,
as a whole, are estimated to account for over 99 percent of all cooling water withdrawals. These six sectors are: Utility Steam Electric,
Nonutility Steam Electric, Chemicals & Allied Products, Primary Metals Industries, Petroleum & Coal Products, and Paper & Allied
Products.
EPA's data collection efforts (via the 1998 industry questionnaire) focused on the electric generators (both utility and nonutility steam
electric) and the four manufacturing industry groups that were identified as significant users of cooling water. EPA maintains,
however, that a manufacturing facility that is not classified within one of those four groups may also be subject to requirements under
today's proposed rule if it meet the requisite criteria. These industries are shown below, as described by the Standard Industrial
Classification (SIC) system.
Electric Services
This industry sector is classified under SIC Major Group 49. This major group includes establishments engaged in the generation,
transmission, and/or distribution of electricity or gas or steam.
Chemical and Allied Products
This industry sector is classified under SIC Major Group 28. This major group includes establishments producing basic chemicals and
establishments manufacturing products by predominantly chemical processes. Establishments classified in this major group
manufacture three general classes of products: (1) basic chemicals, such as acids, alkalies, salts, and organic chemicals; (2) chemical
products to be used in further manufacture, such as synthetic fibers, plastics materials, dry colors, and pigments; and (3) finished
chemical products to be used for ultimate consumption, such as drugs, cosmetics, and soaps; or to be used as materials or supplies in
other industries, such as paints, fertilizers, and explosives.
Primary Metals Industries
This industry sector is classified under SIC Major Group 33. This major group includes establishments engaged in smelting and
refining ferrous and nonferrous metals from ore, pig, or scrap; in rolling, drawing, and alloying metals; in manufacturing castings and
other basic metal products; and in manufacturing nails, spikes, and insulated wire and cable.
2-1
-------
§ 316(b) Phase III - Technical Development Document
Description of the Industry
Paper and Allied Products
This industry sector is classified under SIC Major Group 26. This major group includes establishments primarily engaged in the
manufacture of pulps from wood and other cellulose fibers, the manufacture of paper and paperboard, and the manufacture of paper
and paperboard into converted products.
Petroleum and Coal Products
This industry sector is classified under SIC Major Group 29. This major group includes establishments primarily engaged in
petroleum refining, manufacturing paving and roofing materials, and compounding lubricating oils and greases from purchased
materials.
Other Industries
EPA sent industry questionnaires to individual facilities from a number of other industries outside of the four listed above and
incorporated that data into the analysis for Phase III. In 2004, EPA also collected information on land-based liquefied natural gas
(LNG) facilities.
1.1 Estimated Numbers of Land-based Facilities in Scope of 316(b)
EPA estimates that approximately 683 land-based facilities in the six industrial categories would be subject to regulation under 316(b).
These facilities combine to account for a design intake flow of over 40 billion gallons per day of cooling water from approximately
908 cooling water intake structures. See Exhibit 2-1 below. For comparison, the numbers of in-scope facilities for Phase I and Phase
II are also included.
Exhibit 2-1. Cooling Water Use in Surveyed Industries
Phase I (new electric generators and
manufacturers)
Phase II (existing electric generators >50
MOD)
Facility Potentially Regulated Under
Phase III (existing electric generators <50
MOD and all existing manufacturers)
Existing electric generators <50
MOD
Existing manufacturers <50 MGD
Existing manufacturers >50 MGD
Estimated Number of Facilities
121 (over 20 years)
554
683
118
410
155
Estimated Design Intake Flow
(MGD)
N/A
367,752
40,441
2,374
7,931
30,136
Source: Survey Data from Detailed Industry Questionnaire: Phase II Cooling Water Intake Structures (DCN 4-0016F-CBI)
Note: All values are weighted and include facilities identified as baseline closures.
1.2
Source Waterbodies
Facilities potentially regulated under Phase III can be found on all waterbody types, but are predominantly located on freshwater rivers
and streams. Exhibit 2-2 below illustrates the distribution of facilities by waterbody type.
2-2
-------
§ 316(b) Phase HI - Technical Development Document
Description of the Industry
Exhibit 2-2. Distribution of Source Waterbodies for Phase III Facilities
Source of Surface Water
Freshwater River or Stream
Lake or Reservoir
Great Lakes
Estuary or Tidal River
Ocean
Total
Estimated Number of Facilities
496
60
77
39
11
683
Percent of Facilities
72.6
8.8
11.3
5.7
1.6
100
Source: Survey Data from Detailed Industry Questionnaire: Phase II Cooling Water Intake Structures (DCN 4-0016F-CBI)
Note: All values are weighted and include those facilities identified as baseline closures.
1.3 Design Intake Flows
Exhibit 2-3 below illustrates the range of design intake flows in facilities considered for regulation under the proposed Phase III rule.
Of these facilities, only existing manufacturing facilities would be subject to the national requirements, as the lowest co-proposed flow
threshold is 50 MOD. Therefore, power producers and manufacturers under 50 MGD would not be subject to the national
requirements under Phase III. Power producers with a design intake flow of 50 million gallons per day (MGD) or greater are covered
under Phase II.
Exhibit 2-3. Design Intake Flows at Facilities Potentially Regulated Under Phase III
Design Intake Flow
(MGD)
0-2
2-5
5-10
10-15
15-25
25-50
50-100
>100
Total
Estimated Number of
Facilities
0
83
84
74
104
183
82
73
683
Percent of Number of
Facilities
0
12.2
12.3
10.8
15.2
26.8
12
10.7
100
Cumulative Percent
0
12.2
24.5
35.3
50.5
77.3
89.3
100
Percent of Total
Design Intake Flow
0
0.6
1.5
2.3
5.1
16
14.2
60.3
100
Source: Survey Data from Detailed Industry Questionnaire: Phase II Cooling Water Intake Structures (DCN 4-0016F-CBI)
Note: All values are weighted and include those facilities identified as baseline closures.
Exhibit 2-4 below illustrates the range of design intake flows by industry type.
2-3
-------
S 316(b) Phase III - Technical Development Document
Description of the Industry
Exhibit 2-4. Design Intake Flow by Industry Type
Industry Type
Utilities
Nonutilities
Chemical and Allied
Products
Primary Metals
Paper and Allied
Products
Petroleum and Coal
Products
Food Products
Textiles
Other Manufacturing
Total
Estimated Number of
Facilities
85
36
181
89
225
39
13
<5
14
683
Total Design Intake
Flow (MGD)
1,927
482
12,340
8,870
11,904
3,259
670
6
983
40,441
Percent of Total
Design Intake Flow
5
1
31
22
30
8
1
1
2
100
Average Design
Intake Flow (MGD)*
23
16
247
240
127
112
52
6
98
921
* Average based on surveyed facilities. May not be reflective of actual industry-wide average design intake flows.
Source: Survey Data from Detailed Industry Questionnaire: Phase II Cooling Water Intake Structures (DCN 4-0016F-CBI)
Note: All values are weighted and include facilities identified as baseline closures.
Exhibit 2-5 combines data from Exhibit 2-3 and 2-4 and provides summary-level data for all industry types.
Exhibit 2-5. Industry Overview
Design Intake Flow (MGD)
2-20
20-50
>50
Total
Estimated Number of
Facilities
290
238
155
683
Total Design Intake Flow
(MGD)
2,612
7,693
30,136
40,441
Percent of Total Design
Intake Flow
6.5
19
74.5
100
Source: Survey Data from Detailed Industry Questionnaire: Phase II Cooling Water Intake Structures (DCN 4-0016F-CBI)
Note: All values are weighted and include facilities identified as baseline closures.
1.4 Cooling Water System Configurations
Facilities potentially regulated under Phase III employ a variety of cooling water system (CWS) types. Exhibit 2-6 shows the
distribution of cooling water system configurations.
2-4
-------
§ 316(b) Phase III - Technical Development Document
Description of the Industry
Exhibit 2-6. Distribution of Cooling Water System Configurations
cws
Configuration
Once-through
Recirculating
Combination
Other
Total
Estimated
Number of
CWS*
436
285
92
76
889
Percent of
Total CWS
49
32
10
9
100
Estimated
Number of
CWS for
Electric
Generators
32
93
3
1
129
Percent of
Total Electric
Generator
CWS
25
72
2
1
100
Estimated
Number of
CWS for
Manufacturers
404
192
89
75
760
Percent of
Total
Manufacturer
CWS
53
25
12
10
100
* Some facilities have more than one cooling water system.
Source: Survey Data from Detailed Industry Questionnaire: Phase II Cooling Water Intake Structures (DCN 4-0016F-CBI)
Note: All values are weighted and include facilities identified as baseline closures.
Exhibit 2-7 illustrates the intake structure arrangements for facilities potentially regulated under Phase III.
Exhibit 2-7. Distribution of Cooling Water Intake Structure Arrangements
Intake Arrangement
Canal or Channel Intake
Bay or Cove Intake
Submerged Shoreline Intake
Surface Shoreline Intake
Submerged Offshore Intake
Estimated Number of Arrangements
123
49
208
151
216
Percent of Arrangements
16
7
28
20
29
Note: The total number of facilities exceeds 683, since some facilities employ multiple intake arrangements.
Source: Survey Data from Detailed Industry Questionnaire: Phase II Cooling Water Intake Structures (DCN 4-0016F-CBI)
Note: All values are weighted and include facilities identified as baseline closures.
1.5 Design Through-Screen Velocities
Exhibit 2-8 below illustrates the wide range of design intake velocities at facilities potentially regulated under Phase III.
Exhibit 2-8. Distribution of Cooling Water Intake Structure (CWIS) Design Through-Screen Velocities
Velocity (feet per second)
0-0.5
0.5-1
1-2
2-3
3-5
Estimated Number of CWIS
156
112
112
71
26
Percent of CWIS
31
22
22
14
5
Cumulative Percent
31
53
75
89
94
2-5
-------
§ 316(b) Phase III - Technical Development Document
Description of the Industry
Exhibit 2-8. Distribution of Cooling Water Intake Structure (CWIS) Design Through-Screen Velocities (continued)
Velocity (feet per second)
5-7
>7
Total
Estimated Number of CWIS
11
19
507
Percent of CWIS
2
4
100
Cumulative Percent
96
100
Note: The average design through-screen velocity for all surveyed cooling water intake structures (unweighted) is 1.67 feet per second.
The median design through-screen velocity for all surveyed facilities is 0.92 feet per second.
Source: Survey Data from Detailed Industry Questionnaire: Phase II Cooling Water Intake Structures (DCN 4-0016F-CBI)
Note: All values are weighted and include those facilities identified as baseline closures.
1.6 Existing Intake Technologies
Many facilities potentially regulated under Phase III have intake technologies already in place. Exhibit 2-9 illustrates the number of
existing intake technologies. EPA notes that not all intake technologies may be sufficient to meet the performance standards or the
requirements of the rule. While not using an intake technology per se, facilities with cooling towers have also been included in this
table to demonstrate the usage of flow reduction as a method to reduce impingement mortality and entrainment.
Exhibit 2-9. Distribution of Intake Technologies
Intake Technology Type
Bar Rack/Trash Rack
Screening Technologies
Passive Intake Technologies
Fish Diversion or Avoidance System
Fish Handling or Return System
No Intake Technologies
Cooling Tower
Estimated Number of Technologies
427
500
233
35
33
13
286
Percent of Technologies
28
33
15
2
2
1
19
Note: The total number of technologies exceeds 683, since some facilities employ multiple intake technologies.
Source: Survey Data from Detailed Industry Questionnaire: Phase II Cooling Water Intake Structures (DCN 4-0016F-CBI)
Note: All Values are weighted and include those facilities identified as baseline closures.
1.7 Operating Days per Year
As a corollary to the capacity utilization rate (CUR) for electric generators, EPA attempted to analyze the number of operating days for
manufacturing facilities. EPA notes, however, that it has not determined an appropriate minimum threshold, nor has it decided to
propose such a threshold. Exhibit 2-10 is for informational purposes only. For more information, see the preamble to the proposed
rule.
2-6
-------
§ 316(b) Phase IH - Technical Development Document
Description of the Industry
Exhibit 2-10. Distribution of Manufacturing Facilities by Number of Operating Days
Number of Operating Days
< 60 days
60- 180 days
> 180 days
Total
Percent of Facilities
4.26
3.55
92.18
100
Source: Survey Data from Detailed Industry Questionnaire: Phase II Cooling Water Intake Structures (DCN 4-0016F-CBI)
Note: An electric generator operating at 15% CUR is roughly equivalent to 55 operating days per year. These data reflect the average
number of facility operating hours over a three year period (1996-1998).
Note: All values are weighted and include those facilities identified as baseline closures.
1.8 Land-based Liquefied Natural Gas Facilities
EPA's research also indicates that there are five existing land-based liquefied natural gas facilities in the United States, all on the East
coast. Most of these facilities do not withdraw surface water for cooling purposes and would therefore be out of scope of the
regulations.
2.0
PRELIMINARY ASSESSMENT OF COMPLIANCE
EPA considered all of the above data in determining the scope, applicability, and flow thresholds in today's proposed rule. Exhibit 2-
11 below illustrates a synthesis of some of the pertinent data.
Exhibit 2-11. Technologies Already In Place at Facilities Potentially Regulated Under Phase III.
Design Intake Flow
(MGD) Threshold
>50
20-50
2-20
Total
Electric Generators
% of Facilities With
Technology Satisfying
Phase II Requirements
n/a
69
93
82
% of Facilities With
Closed-Cycle,
Recirculating Cooling
Systems
n/a
60
82
72
Manufacturers
% of Facilities With
Technology Satisfying
Phase II Requirements
29
54
58
48
% of Facilities With
Closed-Cycle,
Recirculating Cooling
Systems
4
22
29
20
Source: Survey Data from Detailed Industry Questionnaire: Phase II Cooling Water Intake Structures (DCN 4-0016F-CBI)
Note: All values are weighted and include those facilities identified as baseline closures.
OFFSHORE INDUSTRIES
EPA considered establishing national requirements for three additional industry groups that have been identified as potential large
users of cooling water: offshore oil and gas exploration facilities , seafood processing vessels, and offshore liquefied natural gas
(LNG) terminals. An industry survey was developed in 2003 to collect data on offshore oil and gas extraction facilities and seafood
processing vessels and EPA independently collected information on offshore liquefied natural gas facilities in 2004.
Under the proposed rule, only new offshore oil and gas extraction facilities would be subject to national requirements.
2-7
-------
S 316(b) Phase III - Technical Development Document Description of the Industry
1.0 DESCRIPTION OF THE INDUSTRIES
After EPA proposed the Phase I rale for new facilities (65 FR 49060), the Agency received adverse comment from operators of mobile
offshore and coastal drilling units concerning the limited information about their cooling water intakes, associated impingement and
entrainment, costs of technologies, or achievability of the controls proposed by EPA. In the Phase I final rale, EPA committed to
"propose and take final action on regulations for new offshore oil and gas extraction facilities, as defined at 40 CFR 435.10 and 40
CFR 435.40, in the Phase III section 316(b) rale." EPA subsequently identified seafood processing vessels and offshore liquefied
natural gas facilities as other potential large users of cooling water that may be subject to regulation under 316(b). Each of these
industries are shown below, as described by the Standard Industrial Classification (SIC) system.
Offshore Oil and Gas Extraction
This industry sector is classified under SIC Major Group 13. This major group includes establishments primarily engaged in: (1)
producing crude petroleum and natural gas; (2) extracting oil from oil sands and oil shale; (3) producing natural gasoline and cycle
condensate; and (4) producing, gas and hydrocarbon liquids from coal at the mine site.
Seafood Processing
This industry sector is classified under SIC Major Group 09. This major group includes establishments primarily engaged in
commercial fishing (including crabbing, lobstering, clamming, oy storing, and the gathering of sponges and seaweed), and the
operation of fish hatcheries and fish and game preserves, in commercial hunting and trapping, and in game propagation.
Offshore Liquefied Natural Gas
This industry sector is classified under SIC Major Group 49. This major group includes establishments engaged in the generation,
transmission, and/or distribution of electricity or gas or steam.
1.1 Estimated Numbers of Offshore Facilities Potentially Subject to Regulation
1.1.1 Existing Offshore Facilities
EPA estimated the number of existing facilities potentially regulated under Phase III in each of the three offshore industries.
Offshore Oil and Gas Extraction
Using information from industry sources and other Federal agencies, EPA determined that there were approximately 2929 offshore oil
and gas extraction facilities potentially within the scope of the regulations. Of these, 2478 facilities are fixed facilities (i.e., fixed
platforms) and were primarily located in the Gulf of Mexico, with some facilities also located in Alaska and along the Pacific coast.
The remaining 451 facilities are mobile facilities (i.e., mobile offshore drilling units (MODU)), which can operate in or out of United
States waters. Like the fixed platforms, the majority of MODUs operate in the Gulf of Mexico. All fixed platforms and MODUs were
considered to be in scope of the regulation, as nearly all operate in Federal waters and are likely to meet the applicability requirements
for316(b).
Seafood Processing
Through existing databases and mailing lists, EPA determined that there were approximately 123 seafood processing vessels
potentially within the scope of the regulations. Each of these vessels has been issued an NPDES permit and it was initially assumed
that all vessels would meet the minimum flow threshold (greater than 2 MGD) and that at least 25% of the water withdrawn was for
cooling purposes. EPA's research indicated that vessels shorter than 100 feet in length were unlikely to withdraw more than 2 MGD
and these vessels were removed from the universe of facilities under consideration.
Offshore Liquefied Natural Gas
EPA's research indicates that there are currently no offshore liquefied natural gas facilities in the United States.
2-8
-------
S 316(b) Phase in - Technical Development Document Description of the Industry
7.7.2 New Offshore Facilities
Offshore Oil and Gas Extraction
EPA projects approximately 20 new offshore oil and gas extraction facilities in the next 3 years.
Seafood Processing
Because seafood processing vessels were determined to be outside the scope of the proposed rule, EPA did not estimate the number of
projected new seafood processing vessels.
Offshore Liquefied Natural Gas
EPA determined that there are approximately eight offshore liquefied natural gas facilities that are currently under proposal. More are
likely to be proposed in the future, as this energy sector is growing rapidly.
1.2 Offshore Facility Characteristics
EPA collected somewhat less information on the offshore industries and therefore will not present detailed tables as in the section
above for land-based facilities. This section will, however, provide a summary of the offshore facility characteristics.
Offshore Oil and Gas Exploration Facilities
New offshore oil and gas extraction facilities include both fixed facilities (such as platforms) and mobile facilities (such as MODUs
and barges). See chapter 3 for additional details on these facilities.
Seafood Processing Vessel
In developing technology cost modules, EPA assumed that a typical seafood processing vessel was 280 feet in length and primarily
used sea chests as the cooling water intake structure. Data available to EPA did not identify intake technologies designed to reduce
impingement mortality or entrainment, as most vessels have a simple screen or grate to screen trash and other debris.
Data from respondents to the EPA Technical Survey for Seafood Processing Vessels indicate that the combined design intake flow
from all the cooling water intakes in a vessel range from 3 MOD to 45 MOD. The total number of intakes per vessel withdrawing
water for cooling purposes ranged from two to ten. These vessels had either a seachest or simple pipe intake for withdrawing cooling
water.
Offshore Liquefied Natural Gas Facility
As stated above, most offshore liquefied natural gas facilities do not use surface water for cooling purposes. Some future facilities
have indicated that they may use surface water, but are presently planning to use submerged cylindrical wedgewire screens as an
intake technology.
2.0 PRELIMINARY ASSESSMENT OF COMPLIANCE
Based upon the information summarized above, the proposed rule would not establish natural requirements for existing offshore oil
and gas extraction facilities, new or existing seafood processing vessels, and new or existing offshore liquefied natural gas facilities.
For additional detail, see the preamble to today's proposed rule.
2-9
-------
-------
§ 316(b) Phase III - Technical Development Document Technology Cost Modules
Chapter 3: Technology Cost Modules
I. TECHNOLOGY COST MODULES FOR MANUFACTURERS
INTRODUCTION
This chapter presents the technology cost modules used by the Agency to develop compliance costs at model facilities for the proposed
rule. Chapter 5 of this document describes the Agency's methodology for assigning particular cost modules to model facilities.
The technology cost modules used in Phase III are the same as those used to determine the compliance costs for Phase II facilities.
EPA considers the types of intakes and the technologies available to address impingement and entrainment at Phase II facilities to be
consistent with the intakes and technologies at Phase HI facilities. Similarly, EPA considers the intakes and technologies found at
electric generators and manufacturers to be consistent with one another, again permitting EPA to apply the technology cost modules
from Phase II to Phase III facilities.
Note that the cost modules presented in this chapter reference costs developed for year 2002 dollars, which were used to develop Phase
II facility costs. However, all costs for Phase III facilities presented in the preamble of today's proposed rule reflect costs that were
adjusted to year 2003 dollars.
1.0 SUBMERGED PASSIVE INTAKES
The modules described in this section involve submerged passive intakes, and address both adding technologies to the inlet of existing
submerged intakes and converting shoreline based intakes (e.g., shoreline intakes with traveling screens) to submerged offshore
intakes with added passive inlet technologies. The passive inlet technologies that are considered include passive screens and velocity
caps. All intakes relocated from shore-based to submerged offshore are assumed to employ either a velocity cap or passive screens.
Costs for velocity caps are presented separately in section 3.0.
1.1 Relocated Shore-based Intake to Submerged Near-Shore and Offshore with Fine Mesh Passive Screens at Inlet
This section contains three subsections. The first two sections respectively present documentation for passive screen technology
selection and estimation parameters; and for development of capital costs for submerged passive intakes. This discussion includes:
passive screen technology selection, selection of flow values, intake configurations, connecting walls, and connecting pipes. The
second section discusses cost development for: screen construction materials, connecting walls, pipe manifolds, airburst systems,
indirect costs, nuclear facilities, O&M costs, construction-related downtime. The third section presents a discussion of the
applicability of this cost module.
1.1.1 Selection/Derivation of Cost Input Values
Passive Screen Technology Selection
Passive screens come in one of three general configurations: flat panel, cylindrical, and cylindrical T-type. Only passive screens
constructed of welded wedgewire were considered due to the improved performance of wedgewire with respect to debris and fish
protection. After discussion with vendors concerning the attributes and prevalence of the various passive screen technology
configurations, EPA selected the T-screen configuration as the most versatile with respect to a variety of local intake and waterbody
attributes. The most important screen attribute was the requirement for screen placement. Both cylindrical and T-screens allow for
placement of the screens extending into the waterbody, which allows for debris to migrate away from the screens once dislodged. T-
screens produce greater flow per screen unit and thus were chosen because they are more practical in multi-screen installations.
Due to the potential for build-up and plugging by debris, passive screens are usually installed with an airburst backwash system. This
system includes a compressor, an accumulator (also known as, receiver), controls, a distributor and air piping that directs a burst of air
into each screen. The air burst produces a rapid backflow through the screen; this air-induced turbulence dislodges accumulated
debris, which then drifts away from the screen unit. Vendors claimed (although with minimal data) that only very stagnant water with
a high debris load or very shallow water (<2 ft deep) would prevent use of this screen technology. Areas with low water velocities
would simply require more frequent airburst backwashes, and few facilities are constrained by water depths as shallow as 2 feet.
3-1
-------
§ 316(b) Phase III - Technical Development Document
Technology Cost Modules
While there are waterbodies with levels of debris low enough to preclude installation of an airburst system, EPA has chosen to include
an airburst backwash system with each T-screen installation as a prudent precaution. The capital cost of the airburst backwash system
is a substantial component, particularly in offshore applications, because of the need to install a separate air supply pipe from the
shoreline air supply to each screen or group of smaller screens. Thus, the assumption that airburst backwash systems are needed in all
applications is considered as part of an overall cost approach that increases projected capital costs to the industry to develop a high-
side cost estimate.
T-screens ranging in diameter from 2 feet (T24) to 8 feet (T96), in one-foot intervals, are used in the analysis. Costs provided are for
two types of screens one with a slot size of approximately 1.75 mm referred to as "fine mesh" and one with a slot size of 0.76 mm
referred to as "very fine mesh." The design flow values used for each size screen correspond to wedgewire T-screens with a through
screen velocity of 0.5 feet per second. Exhibits 3-1 and 3-2 presents design specifications for the fine mesh and very fine mesh
wedgewire T-screens costed.
Exhibit 3-1. Fine Mesh Passive T-Screen Design Specifications
Fine Mesh Passive T-Screen Design Specifications
Screen
Size
T24
T36
T48
T60
T72
T84
T96
Caoacitv
gpm
2.500
5.700
10.000
15.800
22.700
31.000
40,750
Slot Size
mm
1.75
1.75
1.75
1.75
1.75
1.75
1.75
Screen
Lenath
Ft
6.3
9.3
13.3
16.6
19.8
22.9
26.4
Airburst
Pipie
Diameter
Inches
2
3
4
6
8
10
12
Screen
Outlet
Diameter
Inches
18
30
36
42
48
60
72
Screen
Weiaht
Lbs
375
1.050
1.600
2.500
4.300
6.000
NA
*Source: Johnson Screen - Brochure 2002 - High Capacity Screen at 50% Open Area
Exhibit 3-2. Very Fine Mesh Passive T-Screen Design Specifications
Very Fine Mesh Passive T-Screen Design Specifications
Screen
Size
T24
T36
T48
T60
T72
T84
T96
Caoacitv
gpm
1.680
3.850
6.750
10.700
15.300
20.900
27,500
Slot Size
mm
0.76
0.76
0.76
0.76
0.76
0.76
0.76
Screen
Lenath
Ft
6.3
9.3
13.3
16.6
19.8
22.9
26.4
Airburst
Pipie
Diameter
Inches
2
3
4
6
8
10
12
Screen
Outlet
Diameter
Inches
18
30
36
42
48
60
72
Screen
Weiaht
Lbs
375
1.050
1.600
2.500
4.300
6.000
NA
'Source: Johnson Screen - Brochure 2002 - High Capacity Screen at 33% Open Are
-------
5 316(b) Phase III - Technical Development Document Technology Cost Modules
Selection of Flow Values
The flow values used in the development of cost equations range from a design flow of 2,500 gpm (which is the design flow for the
smallest screen (T24) for which costs were obtained) to a flow of 163,000 gpm (which is equivalent to the design flow of four T96
screens) for fine mesh screens and 1,680 gpm to 165,000 (which is equivalent to the design flow of six T96 screens) for very fine mesh
screens. The higher flow values were chosen because they were nearly equal to the flow in a 10-foot diameter pipe at a pipe velocity
of just 4.6 feet per second. A 10-foot diameter pipe was chosen as the largest size for individual pipes because this size was within the
range of sizes that are capable of being installed using the technology assumed in the cost model. Additionally, the need to spread out
the multiple screens across the bottom is facilitated by multiple pipes. One result of this decision is that for facilities with design flows
significantly greater than 165,000 gpm, the total costs are based on dividing the intake into multiple units and summing the costs of
each.
Intake Configuration
The scenarios evaluated in this analysis are based on retrofit construction in which the new passive screens are connected to the
existing intake by newly installed pipes, while the existing intake pumps and pump wells remain intact and functional. The cost
scenario also retains the existing screen wells and bays, since in most cases they are connected directly to the pump wells. Facilities
may retain the existing traveling screens as a backup, but the retention of functioning traveling screens is not necessary. No operating
costs are considered for the existing screens since they are not needed. Even if they are retained, there should be almost no debris to
collect on their surfaces. Thus, they would only need to be operated on an infrequent basis to ensure they remain functional.
The new passive screens are placed along the bottom of the waterway in front of the existing intake and connected to the existing
intake with pipes that are laid either directly on or buried below the stream bed. The key components of the retrofit are: the transition
connection to the existing intake, the connecting pipe or pipes (a.k.a. manifold or header), the passive screens or velocity cap located at
the pipe inlet, and if passive screens are used, the backwash system.
At most of the T-screen retrofit installations, particularly those requiring more than one screen, the installation of passive T-screens
will likely require relocating the intake to a near-shore location or to a submerged location farther offshore, depending on the screen
spacing, water depth, and other requirements. An exception would be smaller flow intakes where the screen could be connected
directly to the front of the intake with a minimal pipe length (e.g., half screen diameter). Other considerations that may make locating
farther offshore necessary or desirable include: the availability of cooler water, lower levels of debris, and fewer aquatic organisms for
placements outside the littoral zone. As such, costs have been developed for a series of distances from the shoreline.
In retrofits where flow requirements do not increase, EPA has found existing pumps and pump wells can be, and have been, retained as
part of the new system. The cost scenarios assume flow volumes do not increase. Thus, using existing pumps and pump wells is both
feasible and economically prudent. There are, however, two concerns regarding the use of existing pumps and pump wells. One is the
degree of additional head loss associated with the new pipes and screens. The second is the intake downtime needed to complete the
installation and connection of the new passive screen system or velocity cap. The downtime considerations are discussed later in a
separate section.
The additional head losses associated with the passive screen retrofit scenario described here include the frictional losses in the
connecting pipes and the losses through the screen surface. If the new connecting pipe velocities are kept low (e.g., 5 feet per second is
used in this analysis), then the head loss in the extension pipe should remain low enough to allow the existing pumps to function
properly in most instances. For example, a 48-inch diameter pipe at a flow of 28,000 gpm (average velocity of 4.96 feet per second)
will have a head loss of 2.31 feet of water per 1,000-foot pipe length (Shaw and Loomis 1970). The new passive screens will
contribute an additional 0.5 to 0.75 feet of water to this head loss, which will further increase when the screen is clogged by debris
(Screen Services 2002). In fact, the rate at which this screen head loss increases due to debris build-up will dictate the frequency of
use of the air backwash. Pump wells are generally equipped with alarms that warn of low water levels due to increased head loss
through the intake. If the screen becomes plugged to the point where backwash fails to maintain the necessary water level in the pump
well, the pump flow rate must be reduced. This reduction may result in a derating or shut down of the associated generating unit.
Lower than normal surface water levels may exacerbate this problem.
In terms of required dimensions for installation, Exhibits 3-1 and 3-2 show screen length is just over three times the diameter and each
screen requires a minimum clearance of one-half diameter on all sides except the ends. Thus, an 8-foot diameter screen will require a
minimum water depth of 16 feet at the screen location (four feet above, four feet below, and eight feet for the screen itself). It is
recommended that T-screens be oriented such that the long axis is parallel to the waterbody flow direction. T-screens can be arranged
in an end-to-end configuration if necessary. However, using a greater separation above the minimum will facilitate dispersion of the
released accumulated debris during screen backwashes.
_____ _
-------
S 316(b) Phase III - Technical Development Document
Technology Cost Modules
In the retrofit scenario described here, screen size and number are based on using a single screen with the screen size increasing with
increasing design flows. When flow exceeds the capacity of a single T96 screen, multiple T96 screens are used. This retrofit scenario
also assumes the selected screen location has a minimum water depth equal to or greater than the values shown in Exhibit 3-3.
Exhibit 3-3. Minimum Depth at Screen Location For Single Screen Scenario
Fine Mesh Flow
2,500 gpm
5,700 gpm
10,000 gpm
15,800 gpm
22,700 gpm
3 1,000 gpm
40,750 gpm
>40,750 gpm
Very Fine Mesh Flow
1,680 gpm
3,850 gpm
6,750 gpm
10,700 gpm
15,300 gpm
20,900 gpm
27,500 gpm
>27,500 gpm
Screen Size
T24
T36
T48
T60
T72
T84
T96
Multiple T96
Minimum Depth
4ft
6ft
8ft
10ft
12ft
14ft
16ft
16ft
In certain instances water depth or other considerations will require using a greater number of smaller diameter screens. For these
cases the same size header pipe can be used, but the intake will require either more branched piping or multiple connections along the
header pipe.
Connecting Wall
The retrofit of passive T-screen technology where the existing pump well and pumps are retained will require a means of connecting
the new screen pipes to the pump well. Pump wells that are an integral part of shoreline intakes (often the case) will require installing
a wall in front of the existing intake pump well or screen bays. This wall serves to block the existing intake opening and to connect
the T-screen pipe(s) to the existing intake pump wells. In the proposed cost scenario, the T-screen pipe(s) can be attached directly to
holes passing through the wall at the bottom.
Two different types of construction have been used in past retrofits or have been proposed in feasibility studies. In one, a wall
constructed of steel plates is attached to and covers the front of each intake bay or pump well, such that one or more connecting pipes
feed water into each screen bay or pump well individually. In this scenario, a single steel plate or several interlocking plates are
affixed to the front of the screen bays by divers, and the T-screen pipe manifolds are then attached to flanged fittings welded at the
bottom of the plate(s). For smaller flow intakes that require a single screen, this may be the best configuration since the screen can be
attached directly to the front of the intake minimizing the intrusion of the retrofit operation into the waterway.
In the second scenario, an interlocking sheet pile wall is installed in the waterbody directly in front of, and running the length of, the
existing intake. Individual screen manifold pipe(s) are attached to holes cut in the bottom along the length of the sheet pile wall. In
this case, a common plenum between the sheet pile wall and the existing intake runs the length of the intake. This configuration
provides the best performance from an operational standpoint because it allows for flow balancing between the screen/pump bays and
the individual manifold pipes. If there are no concerns with obstructing the waterway, the sheet pile wall can be placed far enough out
so that the portion of the wall parallel to the intake can be installed first along with the pipes and screens that extend further offshore.
In this case, the plenum ends are left open so that the intake can remain functional until the offshore construction is completed. At that
point, the intake must shut down to install the final end portions of the wall, the air piping connection to the air supply, and make final
connections of the manifold pipes. EPA is not aware of any existing retrofits where this construction technique has been used.
However, it has been proposed in a feasibility study where a new, larger intake was to be constructed offshore (see discussion in
Construction Downtime section).
Costs were developed for this module based on the second scenario described above. These costs are assumed equal or greater than
costs for steel plate(s) affixed to the existing intake opening, and therefore inclusive of either approach. This assumption is based on
the use of a greater amount of steel material for sheet piles (which is offset somewhat by the fabrication cost for the steel plates), the
3-4
-------
S 316(b) Phase III - Technical Development Document Technology Cost Modules
use of similarly-sized heavy equipment (pile driver versus crane), and similar diver costs for constructing pipe connections and
reinforcements in the sheet pile wall versus installing plates. Costs were developed for both freshwater environments and, with the
inclusion a cost factor for coating the steel with a corrosion-resistant material, for saltwater environments.
Connecting Pipes
The design (length and configuration) of the connecting pipes (also referred to as pipe manifold or header) is partly dictated by intake
flow and water depth. A review of the pipe diameter and design flow data submitted to EPA by facilities with submerged offshore
intakes indicates intake pipe velocities at design flow were typically around 5 feet per second. Note that a minimum of 2.5 to 3 feet
per second is recommended to prevent deposition of sediment and sand in the pipe (Metcalf & Eddy 1972). Also, calculations based
on vendor data concerning screen attachment flange size and design flow data resulted in pipe velocities ranging from 3.2 to 4.5 feet
per second for the nominal size pipe connection. EPA has elected to size the connecting pipes based on a typical design pipe velocity
of 5 feet per second.
Even at 5 feet per second, the piping requirements are substantial. For example, if the existing intake has traveling screens with a high
velocity (e.g., 2.5 feet per second through-screen velocity), then the cross-sectional area of the intake pipe needed to provide the same
flow would be approximately one-third of the existing screen area (assuming existing screen open area is 68%). Given the above
assumptions, an existing intake with a 10-foot wide traveling screen and a 20-foot water depth would require a 9.4-foot diameter pipe
and be connected to at least four 8-foot diameter fine mesh T-screens (T96). The flow rate for this hypothetical intake screen would be
155,000 gpm.
For small volume flows (40,750 gpm or less for fine mesh-see Exhibit 3-3), T-screens (particularly those with a single screen unit) can
be installed very close to the existing intake structure, as the upstream or downstream extensions of the screen should not be an issue.
In the 10-foot wide by 20-foot deep traveling screen example above, each of the T96 screens required is 26 feet long. For this
example, it is possible to place the four T96 screens directly in front of the existing intake connected to a single manifold extending 56
feet (2*8+2*8+2*8+8) to the centerline of the last T-screen. This is based on a configuration where the manifold has multiple ports
(four in this case) spaced along the top. However, this configuration will experience some flow imbalance between the screens. A
better configuration would be a single pipe branching twice in a double "H" arrangement. In this case, the total pipe length would be
62 feet (20+26+2*8). Therefore, a minimum pipe length of 66 feet (20 meters) was selected to cover the pipe installation costs for
screens installed close to the intake.
Based on the above discussion, facilities with design flow values requiring multiple manifold pipes (i.e., >163,000 gpm) will require
the screens to extend even further out. In these cases, costs for a longer pipe size are appropriate. Using a longer pipe allows for
individual screens to be spread out laterally and/or longitudinally. Longer pipes would also tend to provide access to deeper water
where larger screens can be used. While using smaller screens allows for operations in shallower water, many more screens would be
needed. This configuration covers a greater bottom area and requires more branching and longer, but smaller, pipes. Therefore, with
the exception of the lower intake flow facilities, a length of connecting pipe longer than66 feet (20 meters) is assumed to be required.
The next assumed pipe length is 410 feet (125 meters), based on the Phase I proposed rule cost estimates. A length of 125 meters was
selected in Phase I costing as a reasonable estimate for extending intakes beyond the littoral zone. Additional lengths of 820 feet (250
meters) and 1640 feet (500 meters) were selected to cover the possible range of intake distances. The longest distance (1640 feet) is
similar in magnitude to the intake distances reported for many of the facilities with offshore intakes located on large bodies of water,
such as oceans and Great Lakes.
As described in the document Economic and Engineering Analyses of the Proposed Section 316(b') New Facility Rule. Appendix A,
submerged intake pipes can be constructed in two ways. One construction uses steel that is concrete-lined and coated on the outside
with epoxy and a concrete overcoat. The second construction uses prestressed concrete cylinder pipe (PCCP). Steel is generally used
for lake applications; both steel and PCCP are used for riverine applications; PCCP is typically used in ocean applications. A review
of the submerged pipe laying costs developed for the Phase I proposed rule showed that the costs of installing steel and PCCP pipe
using the conventional method were similar, with steel being somewhat higher in cost. EPA has thus elected to use the Phase I cost
methodology for conventional steel pipe as representative of the cost for both steel and concrete pipes installed in all waterbodies. The
conventional pipe laying method was selected because it could be performed in front of an existing intake and was least affected by the
limitations associated with local topography.
While other methods such as the bottom-pull or micro-tunneling methods could potentially be used, the bottom-pull method requires
sufficient space for laying pipe onshore while the micro-tunneling method requires that a shaft be drilled near the shoreline, which may
be difficult to perform in conjunction with an existing intake. The conventional steel pipe laying cost methodology and assumptions
3-5
-------
§ 316(b) Phase HI - Technical Development Document
Technology Cost Modules
are described in detail in the document Economic and Engineering Analyses of the Proposed Section 316(bt New Facility Rule.
Appendix A.
7.7.2 Capital Cost Development
Screen Material Construction and Costs
Costs were obtained for T-screens constructed of three different types of materials: 304 stainless steel, 316 stainless steel, and copper-
nickel (CuNi) alloy. In general, screens installed in freshwater are constructed of 304 stainless steel. However, where Zebra Mussels
are a problem, CuNi alloys are often used because the leached copper tends to discourage screen biofouling with Zebra mussels. In
corrosive environments such as brackish and saltwater, 316 stainless steel is often used. If the corrosive environment is harsh,
particularly where oxygen levels are low, CuNi alloys are recommended. Since the T-screens are to be placed extending out into the
waterway, such low oxygen environments are not expected to be encountered.
Based on this information, EPA has chosen to base the cost estimates on utilizing screens made of 304 stainless steel for freshwater
environments without Zebra Mussels, CuNi alloy for freshwater environments with the potential for Zebra Mussels and 316 stainless
steel for brackish and saltwater environments. Exhibit 3-4 provides a list of states that contain or are adjacent to waterbodies where
Zebra Mussels are currently found. The cost for CuNi screens are applied to all freshwater environments located within these states.
EPA notes that the screens comprise only a small portion of the total costs, particularly where the design of other components are the
same, such as the proposed design scenarios for freshwater environments with Zebra Mussels versus those without.
Exhibit 3-4. List of States with Freshwater Zebra Mussels as of 2001
List of States with
Freshwater Zebra Mussels
as of 2001
State Name
Alabama
Connecticut
Illinois
Indiana
Iowa
Kentucky
Louisiana
Michigan
Minnesota
Mississippi
Missouri
New York
Ohio
Oklahoma
Pennsylvania
Tennessee
Vermont
West Virginia
Wisconsin
Abbreviation
AL
CT
IL
IN
IA
KY
LA
Ml
MN
MS
MO
NY
OH
OK
PA
TN
VT
WV
Wl
Exhibit 3-5 presents the component and total installed costs for the three types of screens. A vendor indicated that the per screen costs
will not change significantly between those with fine mesh and very fine mesh so the same screen costs are used for each. Installation
and mobilization costs are based on vendor-provided cost estimates for velocity caps, which are comparable to those for T-screens.
The individual installation cost per screen of $35,000 was reduced by 30% for multiple screen installations. Costs for steel fittings are
also included. These costs are based on steel fitting costs developed for the new facility Phase I effort and are adjusted for a pipe
3-6
-------
§ 316(b) Phase III - Technical Development Document
Technology Cost Modules
velocity of 5 feet per second and converted to 2002 dollars. An additional 5% was added to the total installed screen costs to account
for installation of intake protection and warning devices such as pilings, dolphins, buoys, and warning signs.
Exhibit 3-5. T-Screen Equipment and Installation Costs
T-Screen Equipment and Installation Costs
Size
T24
T36
T48
T60
T72
T84
T96
T96
T96
T96
Number
of
Screens
1
1
1
1
1
1
1
2
3
4
Caoacitv
dom
2.500
5.700
10.000
15.800
22.700
31.000
40.750
81.500
122.250
163,000
Total Screen Cost bv Material
304SS
$5.800
$10.000
$17.000
$23.000
$34.000
$45.000
$61.000
$122.000
$183.000
$244,000
316SS
$6.100
$11.200
$18.800
$26.200
$39.500
$51.900
$70.200
$140.400
$210.600
$280.800
CuNi
$8.000
$18.000
$31.700
$44.500
$69.700
$93.400
$124.000
$248.000
$372.000
$496,000
Air Burst
Equipmen
t
$10.450
$15.050
$22.362
$28.112
$35.708
$43.588
$49.338
$49.338
$49.338
$49,338
Screen
Installat
ion
$25.000
$25.000
$30.000
$35.000
$35.000
$35.000
$35.000
$49.000
$73.500
$98,000
Mobilizati
on
$15.000
$15.000
$15.000
$15.000
$20.000
$20.000
$25.000
$25.000
$30.000
$30,000
Steel
Fittina
$2.624
$3.666
$5.067
$6.964
$9.227
$11.961
$15.189
$28.865
$42.840
$57,113
The same costs are used for both fine mesh and very fine mesh with major difference being the design flow for each screen size.
Connecting Wall Cost Development
The cost for the connecting wall that blocks off the existing intake and provides the connection to the screen pipes is based on the cost
of an interlocking sheet pile wall constructed directly in front of the existing intake. In general, the costs are mostly a function of the
total area of the wall and will vary with depth. Cost estimates were developed for a range of wall dimensions. The first step was to
estimate the nominal length of the existing intake for each of the design flow values shown in Exhibits 3-1 and 3-2. The nominal
length was estimated using an assumed water depth and intake velocity. The use of actual depths and intake velocities imparted too
many variables for the selected costing methodology. A depth of 20 feet was selected because it was close to both the mean and
median intake water depth values reported by Phase III facilities in their Detailed Technical Questionnaires.
The length of the wall was also based on an assumed existing intake, through-screen velocity of 1 feet per second and an existing
screen open area of 50%. Most existing coarse screens have an open area of 68%. However, a 50% area was chosen to produce a
larger (i.e., more costly) wall size. Selecting a screen velocity of 1 feet per second also will overestimate wall length (and therefore,
costs) for existing screen velocities greater than 1 feet per second. This is the case for most of the facilities (approximately 50% of
Phase III facilities reported screen velocities of 1 feet per second or greater for at least one cooling water intake structure and just
under 70% of the Phase II Facilities reported screen velocities of 1 feet per second or greater). An additional length of 30 to 60 feet
(scaled between 30 feet for 2,500 to 60 feet for 163,000 gpm with a minimum of 30 ft for lower flows) was added to cover the end
portions of the wall and to cover fixed costs for smaller intakes. The costs are based on the following:
3-7
-------
§ 316(b) Phase III - Technical Development Document
Technology Cost Modules
Sheet pile unit cost of $24.50/sq ft RS Means 2001)
An additional 50% of sheet pile cost to cover costs not included in sheet pile unit cost1
Total pile length of 45 feet for 20-foot depth including 15-foot penetration and 10-foot extension above water level
Mobilization of $18,300 for 20-foot depth RS Means 2001), added twice (assuming sheet pile would be installed in two stages to
minimize generating unit downtime (see Downtime discussion). The same mobilization costs are used for both saltwater and
freshwater environments.
• An additional cost of 33% for corrosion-resistant coating for saltwater environments.
Exhibits 3-6 and 3-7 present the estimated wall lengths, mobilization costs, and total costs for 20-foot depth for both freshwater and
saltwater environments for fine mesh and very fine mesh screens, respectively.
Exhibit 3-6. Sheet Pile Wall Capital Costs for Fine Mesh Screens
Sheet Pile Wall Capital Costs for Fine Mesh Screens
Design
Flow
dom
2.500
5.700
10.000
15.800
22.700
31.000
40.750
81.500
122.250
163,000
Total
Estimated
Wall
Lenath
Ft
31
32
34
36
39
43
47
64
81
96
Mobilization
$36.600
$36.600
$36.600
$36.600
$36.600
$36.600
$36.600
$36.600
$36.600
$36,600
Sheet Pile Wall Total
Costs 20 Ft Water
Death*
Freshwater
$87.157
$89.351
$92.359
$96.416
$101.243
$107.049
$113.870
$142.376
$170.883
$195,960
Saltwater
$103.840
$106.758
$110.759
$116.155
$122.575
$130.297
$139.369
$177.283
$215.196
$248,549
' Total costs include mobilization
'Note that this 50% value was derived by comparing the estimated costs of a sheet pile wall presented in a feasibility
study for the Salem Nuclear Plant to the cost estimated for a similarly sized sheet pile wall using the EPA method described here.
This factor was intended to cover the cost of items such as waters, bracing and installation costs not included in the R S Means
unit cost. The Salem facility costs included bypass gates, which are assumed to be similar in cost to the pipe connections.
J-8
-------
§ 316(b) Phase III - Technical Development Document
Technology Cost Modules
Exhibit 3-7. Sheet Pile Wall Capital Costs for Very Fine Mesh Screens
Sheet Pile Wall Capital Costs for Very Fine Mesh Screens
Design
Flow
com
1.680
3.850
6.750
10.700
15.300
20.900
27.500
55.000
82.500
110.000
165,000
Total
Estimated
Wall
Lenath
Ft
30
31
32
34
36
38
41
53
64
76
99
Mobilization
$36.600
$36.600
$36.600
$36.600
$36.600
$36.600
$36.600
$36.600
$36.600
$36.600
$36,600
Sheet Pile Wall Costs
20 Ft Water Deoth*
Freshwater
$86.854
$88.056
$90.085
$92.848
$96.066
$99.984
$104.601
$123.838
$143.076
$162.314
$200,789
Saltwater
$103.438
$105.037
$107.735
$111.410
$115.690
$120.900
$127.041
$152.627
$178.213
$203.799
$254,971
* Total costs include mobilization
Pipe Manifold Cost Development
For facilities with design intake flows that are 10% or more greater than the 163,000 gpm to 165,000 gpm maximum costed (i.e., above
180,000 gpm), multiple intakes are costed and the costs are summed. This approach leads to probable costing over-estimates for both
the added length of end sections wall costs.
Pipe costs are developed using the same general methodology as described in Economic and Engineering Analyses of the Proposed
Section 316(1^ New Facility Rule. Appendix A, but modified based on a design pipe velocity of 5 feet per second. The pipe laying
cost methodology was revised to include: costs for several different pipe lengths were developed. These pipe lengths include: 66 feet
(20 meters), 410 feet (125 meters), 820 feet (250 meters), and 1640 feet (500 meters). The cost for pipe installation includes an
equipment rental component for the pipe laying vessel, support barge, crew, and pipe laying equipment. The Phase I proposed rule
Economic and Engineering Analyses document estimates that 500 feet of pipe can be laid in a day under favorable conditions.
Equipment rental costs for the longer piping distances were adjusted upward, in single-day increments, to limit daily production rates
not to exceed 550 feet/day. For the shorter distance of 66 feet (20 meters), the single-day pipe laying vessel/equipment costs were
reduced by a factor of 40%. This reduction is based on the assumption that, in most cases, a pipe laying vessel is not needed because
installation can be performed via crane located on the shoreline.
Figure 3-1 presents the capital cost curves for the pipe portion only for each of the offshore distance scenarios. The pipe cost
development methodology adopted from the Phase I effort used a different set of flow values than are shown in Exhibit 3-1.
Therefore, second-order, best-fit equations were derived from pipe cost data. These equations were applied to the flow values in
Exhibit 3-1 to obtain the relevant installed pipe cost component.
An additional equipment component representing the cost of pipe fittings such as tees or elbows are included in the screen equipment
costs. The costs are based on the cost estimates developed for the Phase I proposed rule, adjusted to a pipe velocity of 5 feet per
second and 2002 dollars.
Airburst System Costs
Capital costs for airburst equipment sized to backwash each of the T-screens were obtained from vendor estimates. These costs
included air supply equipment (compressor, accumulator, distributor) minus the piping to the screens, air supply housing, and utility
3-9
-------
§ 316(b) Phase HI - Technical Development Document
Technology Cost Modules
connections and wiring. Capital costs of the airburst air supply system are shown in Exhibit 3-8. Costs for a housing structure,
electrical, and controls were added based on the following:
• electrical costs = 10% of air supply equipment (BPJ)
Controls = 5% of air supply equipment (BPJ)
• Housing = $142/sq ft for area shown in Exhibit 3-8. This cost was based on the $130/sq ft cost used in the Phase I cost for pump
housing, adjusted to 2002 dollars.
Exhibit 3-8. Capital Costs of Airburst Air Supply Equipment
Screen
Size
T24
T36
T48
T60
T72
T84
T96
Vendor
Supplied
Equipment
Costs
$6.000
$10.000
$15.000
$20.000
$25.000
$30.000
$35,000
Estimated
Housing
Area
5x5
5x5
6x6
6x6
7x7
8x8
8x8
Housing
Area
sqft
25
25
36
36
49
64
64
Housing
Costs
$3.550
$3.550
$5.112
$5.112
$6.958
$9.088
$9,088
Electrical
10%
$600
$1.000
$1.500
$2.000
$2.500
$3.000
$3.500
Controls
5%
$300
$500
$750
$1.000
$1.250
$1.500
$1,750
Total
Airburst
Minus Air
Piping to
Screens
$10.450
$15.050
$22.362
$28.112
$35.708
$43.588
$49,338
The costs of the air supply pipes, or "blow pipes," are calculated for each installation depending on the length of the intake pipe, plus
an assumed average distance of 70 feet from the airburst system housing to the intake pipe at the front of the sheet pile wall. Pipe
costs are based on this total distance multiplied by a derived unit cost of installed pipe Vendors indicated that the pipes are typically
made of schedule 10 stainless steel or high density polyethylene and that material costs are only a portion of the total installed costs.
Consistent with the selection of screen materials, EPA chose to assume that the blow pipes are constructed of 304 stainless steel for
freshwater and 316 stainless steel for saltwater applications.
The unit costs for the installed blow pipes are based on the installed cost of similar pipe in a structure on land multiplied by an
underwater installation factor. This underwater installation factor was derived by reviewing the materials-versus-total costs for
underwater steel pipe installation, which ranged from about 3.2 to 4.5 with values decreasing with increasing pipe size. A review of
the materials-versus-installed-on-land costs for the smaller diameter stainless steel pipe (RS Means 2001) found that if the installed-
on-land unit costs are multiplied by 2.0, the resulting materials-to-total- estimated (underwater)-installed-cost ratios fell within a
similar range. These costs are considered as over-estimating costs somewhat because they include 304 and 316 stainless steel where
less costly materials may be used. Also, they do not consider potential savings associated with concurrent installation alongside the
much larger water intake pipe.
Blow pipe sizes were provided by vendors for T60 and smaller screens. For larger screens, the blow pipe diameter was derived by
calculating pipe diameters (and rounding up to even pipe sizes) using the same ratio of screen area to blow pipe area calculated for T60
screens. This is based on the assumption that blow pipe air velocities are proportional to the needed air/water backwash velocities at
the screen surface. A separate blow pipe was included for each T-screen where multiple screens are included, but only one set of the
air supply equipment (compressor, accumulator, distributor, controls etc.) is included in each installation. The calculated costs for the
air supply pipes are shown in Exhibit 3-9.
3-10
-------
§ 316(b) Phase III - Technical Development Document
Technology Cost Modules
Exhibit 3-9. Capital Costs of Installed Air Supply Pipes for Fine Mesh Screens
Design
Flow Fine
Mesh
aom
2.500
5.700
10.000
15.800
22.700
31.000
40.750
81.500
122.250
163.000
-
Design
Flow
Very
Fine
Mesh
a Dm
1.680
3.850
6.750
10.700
15.300
20.900
27.500
55.000
82.500
110.000
165,000
Air Pipe
Unit Cost •
Schedule 10
304 SS
$/Ft
$57.3
$85.4
$102.0
$160.3
$222.8
$304.0
$376.8
$376.8
$376.8
$376.8
$376.8
Air Pipe
Unit Cost -
Schedule 10
316 SS
$/Ft
$119.5
$102.0
$118.7
$188.4
$279.0
$368.5
$456.0
$456.0
$456.0
$456.0
$456.0
Freshwater Airburst Distribution Installed Pipe
Costs
20 Meters
$7.764
$11.575
$1 3.834
$21.739
$30.209
$41.220
$51.100
$102.199
$153.299
$204.398
$306.597
125 Meters
$27.485
$40.973
$48.970
$76.954
$106.934
$145.910
$180.883
$361.766
$542.650
$723.533
$1.085.299
250 Meters
$50.961
$75.970
$90.798
$142.685
$198.274
$270.542
$335.388
$670.775
$1.006.163
$1.341.550
$2.012.326
500 Meters
$97.915
$145.966
$174.454
$274.147
$380.954
$519.806
$644.396
$1 288 793
$1.933.189
$2.577.586
$3.866.378
Saltwater Airburst Distribution Installed Pipe
Costs
20 Meters
$16.210
$13.834
S16.093
$25.550
$37.830
$49.971
$61.828
S123 656
$185.485
$247.313
$370.969
125 Meters
$57.379
$48.970
$56.966
$90.442
$133.910
$176.890
S218.861
$437722
S656582
$875.443
$1.313.165
250 Meters
$106.391
$90.798
$105.625
$167.694
$248.292
$327.983
$405.804
$811 609
S1 217413
$1.623.218
$2.434.826
500 Meters
$204.413
$174.454
$202.943
$322.198
$477.056
S630.169
$779.692
$1.559.383
$2.339.075
$3.118.766
$4.678.150
Indirect Costs
The total calculated capital costs were adjusted to include the following added costs:
• Engineering at 10% of direct capital costs
• Contractor overhead and profit at 15% of direct capital costs (based on O&P component of installing lift station in RS
Means 2001); some direct cost components, e.g., the intake pipe cost and blow pipe cost, already include costs for
contractor overhead and profit
Contingency at 10% of direct capital costs
• Sitework at 10% of direct capital costs; based on sitework component of Fairfax Water Intake costs data, including costs
for erosion & sediment control, trash removal, security, dust control, access road improvements, and restoration (trees,
shrubs, seeding & sodding).
Total Capital Costs
Fine Mesh
Exhibit 3-10 presents the total capital costs of the complete system for fine mesh screens including indirect costs. Figures 3-2, 3-3, and
3-4 present the plotted capital costs in Exhibit 3-10 for freshwater, saltwater, and freshwater with Zebra mussels, respectively. Figures
3-2, 3-3, and 3-4 also present the best-fit, second order equations used in estimating compliance costs.
Very Fine Mesh
Exhibit 3-11 presents the total capital costs of the complete system for very fine mesh screens including indirect costs. Figures 3-5,3-
6, and 3-7 present the plotted capital costs in Exhibit 3-11 for freshwater, saltwater, and freshwater with Zebra mussels, respectively.
3-77
-------
§ 316(b) Phase III - Technical Development Document
Technology Cost Modules
•a
«
CA
a
£
o
•a
w
•W
«
E
V
CA
e
01
0)
H
JS
M
«
V
•a
41
«
+*
'EL
U
"3
o
f>
•w
JO
w
I
5 a
ju.
O
p
M M
S
cvi
es
•«ri
a
o
X
CA
M
•a
w
I
o
£
JS
(A
V
S
o>
I
o
CA
I
3
EL
C9
U
e
f*>
4^
S
u
1
S
s
8
!H
S
-------
§ 316(b) PKose III - Technical bevelopment bocument Technology Cost Modules
Nuclear Facilities
Construction and material costs tend to be substantially greater for nuclear facilities due to burden of increased security and to the
requirements for more robust system design. Rather than performing a detailed evaluation of the differences in capital costs for
nuclear facilities, EPA has chosen to apply a simple cost factor based on total costs.
In the Phase I costing effort, EPA used data from an Argonne National Lab study on retrofitting costs of fossil fuel power plants and
nuclear power plants. This study reported average, comparative costs of $171 for nuclear facilities and $108 for fossil fuel facilities,
resulting in a 1.58 costing factor. In comparison, recent consultation with a traveling screen vendor, the vendor indicated costing
factors in the range of 1.5-2.0 were reasonable for estimating the increase in costs associated with nuclear power plants based on their
experience. Because today there are likely to be additional security burdens above that experienced when the Argonne Report was
generated, EPA has selected 1.8 as a capital costing factor for nuclear facilities. Capital costs for nuclear facilities are not presented
here but can be estimated by multiplying the applicable non-nuclear facility costs by the 1.8 costing factor.
O&M Costs
O&M cost are based on the sum of costs for annual inspection and cleaning of the intake screens by a dive team and for estimated
operating costs for the airburst air supply system. Dive team costs were estimated for a total job duration of one to four days, and are
shown in Exhibit 3-12. Dive team cleaning and inspections were estimated at once per year for low debris locations and twice per year
for high debris locations. The O&M costs for the airburst system are based on power requirements of the air compressor and labor
requirements for routine O&M. Vendors cited a backwash frequency per screen from as low as once per week to as high as once per
hour for fine mesh screens. The time needed to recharge the accumulator is about 0.5 hours, but can be as high as 1 hour for those
with smaller compressors or accumulators that backwash more than one screen simultaneously.
The Hp rating of the typical size airburst compressor for each screen size was obtained from a vendor and is presented in the table in
Attachment 3A. A vendor stated that several hours per week would be more than enough labor for routine maintenance, so labor is
assumed to be two to four hours per week based on roughly half-hour daily inspection of the airburst system. However, during
seasonal periods of high debris such as leaves in the fall, it may be necessary for someone to man the backwash system 24 hours/day
for several weeks (Frey 2002). Thus, an additional one to 4.5 weeks of 24-hour labor are included for these periods (one week low
debris fine mesh; 1.5 weeks low debris very fine mesh; three weeks high debris fine mesh; and 4.5 weeks high debris very fine mesh).
Since very fine mesh screens will tend to collect debris at a more rapid rate, backwash frequencies and labor requirements were
increased by 50% for very fine mesh screens.
The O&M cost of the airburst system are based on the following:
Average backwash frequency in low debris areas is 2 times per day (3 times per day for very fine mesh)
• Average backwash frequency in high debris areas is 12 times per day (18 times per day for very fine mesh)
• Time to recharge accumulator is 0.5 hours
• Compressor motor efficiency is 90%
Cost of electric power consumed is $0.04/Kwh
• Routine inspection and maintenance labor is 3 hours per week (4.5 hours per week for very fine mesh) for systems up to 182,400
gpm
O&M labor rate per hour is $41.10/hr. The rate is based on Bureau of Labor Statistics Data using the median labor rates for
electrical equipment maintenance technical labor (SOC 49-2095) and managerial labor (SOC 11-1021); benefits and other
compensation are added using factors based on SIC 29 data for blue collar and white collar labor. The two values were combined
into a single rate assuming 90% technical labor and 10% managerial. See Doley 2002 for details.
Exhibit 3-13 presents the total O&M cost for relocating intakes offshore with fine mesh and very fine mesh passive screens. These
data are plotted in Figures 3-8 and 3-9 which also shows the second-order equations that were fitted to these data and used to estimate
the O&M costs for individual Phase III facilities. Attachment 3A presents the worksheet data used to develop the annual O&M costs.
As with the capital costs, at facilities where the design flow exceeds the maximum cost model design flow of 165,000 gpm plus 10%
(180,000 gpm), the design flow are divided and the corresponding costs are summed.
3-13
-------
§ 316(b) Phase III - Technical Development Document
Technology Cost Modules
Exhibit 3-12. Estimated Costs for Dive Team to Inspect and Clean T-screens
Installation and Maintenance Diver Team Costs
Item
Duration
Cost Year
Supervisor
Tender
Diver
Air Packs
Boat
Mob/Demob
Total
Daily
Cost*
$575
$200
$375
$100
$200
One Time
Cost*
$3,000
Total
One Day
1999
$575
$200
$750
$100
$200
$3,000
$4,825
Adjusted Total
One Day
2002
$627
$218
$818
$109
$218
$3,270
$5,260
Two Day
2002
$1,254
$436
$1,635
$218
$436
$3,270
$7,250
Three Da\
2002
$1,880
$654
$2,453
$327
$654
$3,270
$9,240
Four Day
2002
$2,507
$872
$3,270
$436
$872
$3,270
$11,230
*Source: Paroby 1999 (cost adjusted to 2002 dollars).
Exhibit 3-13. Total O&M Costs for Passive Screens Relocated Offshore
Relocate Ofshore With New Fine
Mesh Screens
Design
Flow
dorm
2.500
5.700
10.000
15.800
22.700
31.000
40.750
81.500
122.250
163,000
-
Total O&M
Costs -
Low
Debris
$16.463
$16.500
$16.560
$20.712
$20.748
$20.808
$20.869
$25.299
$25.601
$27,894
-
Total O&M
Costs -
High
Debris
$35.654
$35.872
$36.235
$42.497
$42.715
$43.078
$43.441
$51.374
$53.189
$58,984
-
Relocate Ofshore With New
Verv Fine Mesh Screens
Design
Flow
dom
1.680
3.850
6.750
10.700
15.300
20.900
27.500
55.000
82.500
110,000
165000
Total
O&M
Costs -
Low
Debris
$22.065
$22.120
$22.210
$27.442
$27.497
$27.588
$27.678
$33.328
$33.782
$36,226
$37,133
Total
O&M
Costs -
High
Debris
$48.221
$48.548
$49.092
$56.496
$56.823
$57.367
$57.912
$67.821
$70.544
$77,246
$82.692
Construction Related Downtime
Downtime may be a substantial cost item for retrofits using the existing pump wells and pumps. The EPA retrofit scenario includes a
sheet pile wall in front of the existing intake. This scenario is modeled after a proposed scenario presented in a feasibility study for the
Salem Nuclear Plant. In this scenario, a sheet pile plenum with bypass gates is constructed 40 feet in front of the existing intake with
about twelve 10-foot diameter header pipes connecting the plenum to about 240 T-screens. Construction is estimated to take two
-------
§ 316(b) Phase III - Technical Development Document Technology Cost Modules
years, with installation of the sheet pile plenum in the first year. The facility projects the installation of 10-foot header pipes and
screens to take nine months and the air backwash piping to take two months. The feasibility study states that Units 1 & 2 would each
have to be shutdown for about six months, to install the plenum, and for an additional two months to install the 10-foot header pipe
connection to the plenum and to install the air piping. Thus, an estimated total of eight months downtime is estimated for this very
large (near worst case) intake scenario. This scenario was discarded by the facility due to uncertainty about biofouling and debris
removal at slack tides. No cost estimates were developed and, therefore no incentive to focus on a system design and a construction
sequence that would minimize downtime existed.
In the same feasibility study, a scenario is proposed where a new intake with dual flow traveling screens is installed at a distance of 65
feet offshore inside a cofferdam. In this scenario, a sheet pile plenum wall connects the new intake to the existing shore intake. In this
scenario the intake is constructed first; Units 1 & 2 are estimated to be shut down for about one month each to construct and connect
the plenum walls to the existing intake.
It would seem that the T-screen plenum construction scenario could follow the same approach, i.e., performed while the units are
operating. This approach would result in a much lower downtime, similar to that for the offshore intake, but including consideration
for added time for near-shore air pipe installation. There are two relevant differences between these scenarios. One is the distance
offshore to the T-screen piping connection versus the new intake structure (40 feet versus 65 feet). The second is that T-screens,
pipes, and plenum would be installed underwater while the new intake would be constructed behind a coffer dam. Conceivably the
offshore portion of the T-screen plenum (excluding the ends) and all pipe and screen installation on the offshore side could be
performed without shutting down the intake.
The WH Zimmer plant is a facility that EPA has identified as actually having converted an existing shoreline intake with traveling
screens to submerged offshore T-screens. This facility was originally constructed as a nuclear facility but was never completed. In the
late 80's it was converted to a coal fired plant. The original intake was to supply service water and make-up water for recirculating wet
towers, and had been completed. However, the area in front of the intake was plagued with sediment deposition. A decision was
made to abandon the traveling screens and install T-screens approximately 50 feet offshore. However, because the facility was not
operating at the time of this conversion, there was no monetary incentive to minimize construction time. Actual construction took six
to eight months for this intake, with a design flow of about 61,000 gpm (Frey 2002). The construction method in this case used a steel
wall installed in front of the existing intake pump wells.
The Agency consulted the WH Zimmer plant engineer and asked him to estimate how long it would take to perform this retrofit
particularly with a goal of minimizing generating unit downtime. The estimated downtime was a minimum of seven to nine weeks,
assuming mobilization goes smoothly and a tight construction schedule is maintained. A more generous estimate of a total of 12 to 15
weeks was estimated for their facility assuming some predictable disruption to construction schedules. This estimate includes five to
six weeks for installing piping (some support pilings can be laid ahead of time), an additional five to six weeks to tie in piping and
install the wall, and an additional two to three weeks to clean and dredge the intake area. This last two- to three-week period was a
construction step somewhat unique to the Zimmer plant, especially because the presence of sediment was the driving factor in the
decision to convert the system.
Based on the above information, EPA has concluded that a reasonable unit downtime should be in the range of 13 to 15 weeks for total
downtime. It is reasonable to assume that this downtime can be scheduled to coincide with routine generating unit downtime of
approximately four weeks, resulting in a total potential lost generation period of nine to 11 weeks. Rather than select a single
downtime for all facilities installing passive screens, EPA chose to apply a 13 to 15 week total downtime duration based on variations
in project size using design flow as a measure of size. As such, EPA assumed a downtime of 13 weeks for facilities with intake flow
volumes of less than 400,000 gpm, 14 weeks for facilities with intake flow volumes greater than 400,000 gpm but less than 800,000
gpm, and 15 weeks for facilities with intake flow volumes greater than 800,000 gpm.
Application
General Applicability
The following site-related conditions may preclude the use of passive T-screens or create operational problems:
Water depths of <2 feet at screen location; for existing facilities this should not be an issue
Stagnant waterbodies with high debris load
Waterbodies with frazil ice in winter.
3-15
-------
§ 316(b) Phase III - Technical Development Document
Technology Cost Modules
Frazil ice consists of fine, small, needle-like structures or thin, flat, circular plates of ice suspended in water. In rivers and lakes it is
formed in supercooled, turbulent water. Remedies for this problem include finding another location such as deeper water that is outside
of the turbulent water or creating a provision for periodically applying heated water to the screens. The application of heated water
may not be feasible or economically justifiable in many instances.
Some facilities have reported limited success in alleviating frazil ice problems by blowing a small constant stream of air through the
screen backwash system (Whitaker 2002b).
Application of Different Pipe Lengths
As noted previously, the shortest pipe length cost scenario (20 meters) are assumed to be applicable only to facilities with flows less
than 163,000 gpm. Conversely, facilities located on large waterbodies that are subject to wave action and shifting sediment are
assumed to install the longest pipe length scenario of 500 meters. Large waterbodies in this instance will include Great Lakes, oceans,
and some estuarine/tidal rivers. The matrix in Exhibit 3-14 will provide some initial guidance. Generally, if the waterbody width is
known, the pipe length should not exceed half the width.
Exhibit 3-14. Selection of Applicable Relocation Offshore Pipe Lengths By Waterbody
20 Meters
125 Meters
250 Meters
500 Meters
Freshwater
Rivers/Streams
Flow<163,000
TBD
TBD
NA
Lakes/Reservoirs
Flow <163,000
TBD
TBD
NA
Estuaries/Tidal
Rivers
NA
TBD
TBD
TBD
Great Lakes
NA
NA
TBD
TBD
Oceans
NA
NA
NA
ALL
TBD: Criteria or selection to be determined; criteria may include design flow, waterbody size (if readily available).
1.2 Add Submerged Fine Mesh Passive Screens to Existing Offshore Intakes
Please note that much of the supporting documentation has been previously described in section 1.1.
Capital Costs
Adding passive screens to an existing submerged offshore intake requires many of the same construction steps and components
described in section 1.1 above, excluding those related to the main trunk of the manifold pipe and connecting wall. Similar
construction components include: modifying the submerged inlet to connect the new screens, installing T-screens, and installing the
airburst backwash air supply equipment and the blowpipes. Nearly all of these components will require similar equipment,
construction steps and costs as described in section 1.1 for the specific components. One possible difference is that the existing
submerged piping distance may not match one of the four lengths for which costs were estimated. This difference only affects this
component of cost. The cost scenario distance chosen is the one that closely matches or exceeds the existing offshore distance.
Exhibits 3-15 and 3-16 present the combined costs of the installed T-screens, airburst air supply system, and air supply pipes for fine
mesh and very fine mesh screens, respectively. The costs in Exhibit 3-15 and 3-16 include direct and indirect costs, as described in
section 1.1. Figures 3-10,3-11, 3-12, 3-13,3-14, and 3-15 present plots of the data in Exhibits 3-15 and 3-16. The figures include the
second-order, best-fit equations are used to estimate technology costs for specific facilities.
-------
§ 316(b) Phase HI - Technical Development Document
Technology Cost Modules
Exhibit 3-15. Capital Cost of Installing Fine Mesh Passive T-screens at an Existing Submerged Offshore Intake
Design
Flow
a am
2,500
5.700
10.000
15.800
22.700
31.000
40.750
81.500
122.250
163.000
Total Co
304 SS
Freshwater
$100.137
$120.312
S154.594
$194.029
$245.131
$293.433
$352.983
$562.086
$795.243
$1.021.242
its 20 Mete
316 SS
Saltwater
$112.839
$125.414
$160.610
$204.426
$264.554
$316.628
$382.546
$621.213
$883.934
$1.139.497
CuNi
Zebra Mussels
S103.487
$132.492
$176 975
$226 763
S299.484
$367.122
$448.900
$753.921
$1.082995
$1.404.912
Total Co
304 SS
Freshwater
$128.732
$162.939
$205.541
$274.090
$356.382
$445.234
$541.169
$938.458
$1.359.802
$1.773.988
sts 125 Mete
316 SS
Saltwater
$172.535
$176.361
_$219J827
$298.519
$403.871
$500.659
^$610,243
$1.076.608
$1.567025
$2.050.286
CuNi
Zebra Mussels
$132.081
$175.119
$227.922
$306.823
$410.736
$51 8.923
$637.086
$1 130293
$1 647 554
$2.157,658
Total Costs 250 Meters Offshore
304 SS
Freshwater
$162.773
$213.685
$266.192
$369.400
$488.825
$625.950
$765.200
$1 386 521
$2.031.896
$2,670,113
316 SS
Saltwater
$243.602
$237.012
$290.432
$410.535
$569.725
$719.744
$881.312
$1 618 744
$2.380.230
$3.134,559
CuNi
Zebra Mussels
$166.122
$225.865
S288.573
$402.134
$543.178
$699.639
$861.118
$1 578 356
$2.319.649
$3.053,783
Total Co
304 SS
Freshwater
$230.855
$315.178
$387.494
$560.020
$753.711
$987.382
$1.213.263
$2 282 647
$3.376.084
$4.462.364
sts 500 Met
316 SS
Saltwater
S385.735
S358.314
$431.543
$634.566
$901.432
$1.157.915
$1.423.448
$2 703 017
$4.006.639
$5.303.105
rs Offshore
CuNi
Zebra Mussels
$234.204
$327.358
$409.874
S592.754
$808.064
$1.061.071
$1.309.181
$2 474 482
$3.663.837
$4.846.034
Exhibit 3-16. Capital Cost of Installing Very Fine Mesh Passive T-screens at an Existing Submerged Offshore Intake
Design
Flow
ODn1
1.680
3850
6.750
10.700
15.300
20.900
27.500
55.000
82.500
110.000
165,000
Total Co
304 SS
Freshwater
$100.173
$120 156
$154.275
$193.241
$244,023
$291.795
$350.954
$557.781
$788.414
$1.011.641
$1.458.718
sts 20 Mete
316 SS
Saltwater
$102 084
$125350
$160.428
$203.882
$263.866
$315.515
$381.218
$618.309
S879.206
$1.132.697
$1,640.302
rs Offshore
CuNi
Zebra Mussels
S103 690
$132945
$177.774
$227.611
$301,094
$369.168
$451.667
$759.208
$1.090.554
$1.414.495
$2,062.999
Total Co
304 SS
Freshwater
$128 768
$162 783
$205 221
$273.302
$355.275
$443.596
$539.140
• $934.154
$1.352.973
$1 .764.387
$2.587,837
its 125 Mali
316 SS
Saltwater
$134314
S17§ 297
$219 694
$297.975
$403.183
$499.547
$608.915
$1.073.703
$1.562.298
$2.043.486
$3.006.486
rs Offshore
CuNi
Zebra Mussels
$132284
$175 572
$228 721
$307.672
$412.346
$520.970
$639.854
$1.135.580
$1.655.113
$2.167.240
$3,192,117
Total Co
304 SS
Freshwater
$162809
$213 530
$265 872
$368.612
$487.718
$624.313
$763.172
$1.382.216
$2.025.067
$2.660.512
$3.932.025
sts 250 Mete
316 SS
Saltwater
$172683
$236948
$290 250
$409.990
$569.036
$718.632
$879.984
$1.615.840
$2.375.502
$3.127.759
$4,632.895
rs Offshore
CuNi
Zebra Mussels
$166 326
S226 319
$289 372
S402.982
$544.789
S701.686
$863.885
$1.583.643
$2.327.207
S3.063.366
$4,536,305
Total Co
304 SS
Freshwater
S230 891
$315 023
$387 174
$559.232
$752.603
$985.745
$1.211.235
S2.278.342
S3.369.255
S4.452.763
$6.620.401
its 500 Mete
316 SS
Saltwater
$249 421
S358 250
$431 360
$634022
$900.743
$1.156.802
$1.422.120
$2.700.113
$4.001.912
$5.296.305
$7,885.714
rs Offshore
CuNI
Zebra Mussels
S234 408
$327 812
$410 674
$593.603
S809.674
$1.063.118
$1.311.948
$2.479.769
$3.671.395
S4.855.617
$7.224,682
O&M Costs
O&M costs are assumed to be nearly the same as for relocating the intake offshore with passive screens. EPA assumes there are some
offsetting costs associated with the fact that the existing intake should already have periodic inspection/cleaning by divers. The portion
of the costs representing a single annual inspection has therefore been deducted. Exhibits 3-17 and 3-18 presents the annual O&M
costs for fine mesh and very fine mesh screens, respectively. Separate costs are provided for low debris and high debris locations.
Figures 3-16 and 3-17 present the plotted O&M data along with the second-order, best fit equations.
3-77
-------
§ 316(b) Phase III - Technical Development Document
Technology Cost Modules
Exhibit 3-17. Net Intake O&M Costs for Fine Mesh Passive T-screens Installed at Existing Submerged Offshore Intakes
Existing Offshore With New Fine
Mesh Screens
Design
Flow
aom
2.500
5.700
10.000
15.800
22.700
31.000
40.750
81.500
122.250
163.000
-
Total O&M
Costs -
Low
Debris
$11.203
$11.240
$11.300
$13.462
$13.498
$13.558
$13.619
$16.059
$16.361
$16.664
-
Total O&M
Costs -
High
Debris
$30.394
$30.612
$30.975
$35.247
$35.465
$35.828
$36.191
$42.134
$43.949
$47.754
-
Existing Offshore With New
Verv F ne Mesh Screens
Design
Flow
dom
1.680
3.850
6.750
10.700
15.300
20.900
27.500
55.000
82.500
110.000
165000
Total
O&M
Costs -
Low
Debris
$16.805
$16.860
$16.950
$20.192
$20.247
$20.338
$20.428
$24.088
$24.542
$24.996
$25,903
Total
O&M
Costs -
High
Debris
$42.961
$43.288
$43.832
$49.246
$49.573
$50.117
$50.662
$58.581
$61.304
$66.016
$71,462
Construction Downtime
Unlike the cost for relocating the intake from shore-based to submerged offshore, the only construction activities that would require
shutting down the intake is to modify the inlet and install the T-screens. Installing the air supply system and the major portion of the
air blowpipes can be performed while the intake is operating. Downtimes are assumed to be similar to those for adding velocity caps,
which were reported to range from two to seven days. An additional one to two days may be needed to connect the blowpipes to the
T-screens. The total estimated intake downtime of three to nine days can easily be scheduled to coincide with the routine maintenance
period for power plants (which the Agency assumed to be four weeks for typical plants).
Application
Separate capital costs have been developed for freshwater, freshwater with Zebra mussels, and saltwater environments. In selecting
the materials of construction, the same methodology described in section 1.1 is used. Because the retrofit is an addition to an existing
intake, selecting the distance offshore involves matching the existing distance to the nearest or next highest distance costed.
Similarly, the O&M costs are applied using the same method as described in section 1.1.
"T75
-------
§ 316(b) Phase III - Technical Development Document Technology Cost Modules
REFERENCES
Whitaker, J. Hendrick Screen Company. Telephone Contact Report with John Sunda (SAIC) concerning Tscreen cost and design
information. August 2, & September 9,2002a
Whitaker, J. Hendrick Screen Company. Email correspondence with John Sunda (SAIC) concerning Tscreen cost and design
information. August 9,2002b
Johnson Screen - Brochure - "High Capacity Surface Water Intake Screen Technical Data."
Petrovs, H. Johnson Screens. Telephone Contact Report Regarding Answers to Passive Screen Vendor Questions.
Screen Services - Brochure - Static Orb, 2002
Shaw, G. V. & Loomis, A.W. Cameron Hydraulic Data. Ingersoll-Rand Company. 1970
Frey, R. Cinergy. Telephone Contact Report Regarding Retrofit of Passive T-Screens. September 30, 2002.
Doley, T., SAIC. Memorandum to the 316b Record regarding Development of Power Plant Intake Maintenance Personnel hourly
compensation rate. 2002
R.S. Means. R.S. Means Costworks Database, 2001.
Metcalf & Eddy. Wastewater Engineering. Mcgraw-Hill Book Company. 1972
3-79
-------
tin
OJ
ATTACHMENT A3
O&M DEVELOPMENT DATA
Exhibit 3A-1. O&M Development Data - Relocate Offshore with Fine Mesh Screens
B
<»
B
Design
Flow
2.500
5.700
10.000
15.800
22.700
31.000
40.750
81.500
122.250
163,000
Compres
sor
Power
2
5
10
12
15
20
25
25
25
25
Low Debris
Backwash
Freauencv
Events/dav
2
2
2
2
2
2
2
4
6
8
High Debris
Backwash
Freauencv
Events/dav
12
12
12
12
12
12
12
24
36
48
Annual
Power
Required -
Low
Debris
Kwh
605
1.513
3.025
3.631
4.538
6.051
7.564
15.127
22.691
30.254
Annual
Power
Required -
High
Debris
Kwh
3.631
9.076
18.153
21.783
27.229
36.305
45.382
90.763
136.145
181,527
Annual
Power
Costs -
Low
Debris*
$0.04
$24
$61
$121
$145
$182
$242
$303
$605
$908
$1,210
Annual
Power
Costs -
High
Debris*
$0.04
$145
$363
$726
$871
$1.089
$1.452
$1.815
$3.631
$5.446
$7,261
Annual
Labor
Required
- Low
Debris
Hours
272
272
272
324
324
324
324
376
376
376
Annual
Labor
Cost-
Low
Debris
$11.179
$11.179
$11.179
$13.316
$13.316
$13.316
$13.316
$15.454
$15.454
$15,454
Annual
Labor
Required <
High
Debris
Hours
608
608
608
660
660
660
660
712
712
712
Annual
Labor
Cost-
High
Debris
$24.989
$24.989
$24.989
$27.126
$27.126
$27.126
$27.126
$29.263
$29.263
$29,263
Dive
Team
Days
Low
Debris
1
1
1
2
2
2
2
3
3
4
Dive
Team
Costs
Low
Debris
$5.260
$5.260
$5.260
$7.250
$7.250
$7.250
$7.250
$9.240
$9.240
$11,230
Dive
Team
Costs
High
Debris
$10.520
$10,520
$10.520
$14.500
$14.500
$14.500
$14.500
$18.480
$18.480
$22.460
C7
2
5.
o
•a
C7
8
i
-------
I 316(b) Phase III - Technical Development Document
Technology Cost Modules
c
u
£
u
c/5
V
I
2
o
o
V
a
u
o
a
«ri
a>
O.
1
a
^
*4
15
'£
w
IH.&.I
<£5Z|
.1 « g s
° * o x
c (0
1
in
8^1
W
.1
(B *m
o
Q
S
8
O>
8
(0
00
S
(O
S
§
CO
S
0)
CM
§
o>
in
S
o>
SB
S
o>
R
SB
CM
CO
CO
18
CO
CO
3
69
S
in
S
8
S
69
§
CO
«
§
-------
Capital Costs
o
(D
W
(5°
3
TI
i
(a
•a
"
I
n
w
"
O
o
i
a
e
m
n
n
r
90
n
o
a
ts
S'
I
o
O
55°
n
ce
- XII 3St>Hd (Cl)9I£ §
-------
Total Capital Costs
o
CO
o
o
o
o
era
O
89
"O
I
O
e
o
i
3
o
I
o
VI
sr
CL
1
o
n
n
01
-------
Total Capital Costs
9Q
e
o
o
o
o
o
o
o
o
8 8
o o
o
o
o
o
o
o
o
o
o
o
o
o
o ->• ro w *.
§o o o o
o o o o
o o o o o
n
o
a
6S
S.
M
a
o
o
I
o
2
3'
1/2
fii
I
IT
I
o
g
55"
rt
4.uaiudo|3Aag (00^4331 -
-------
Figure 3-4. Capital Costs for Fine Mesh Passive Screen Relocation Offshore in Freshwater with Zebra Mussels at
Selected Offshore Distances
$14,000,000
$13,000,000
$12,000,000
$11,000,000
$10,000,000
« $9,000,000
M
O $8,000,000
a $7,000,000
is
^ $6,000,000
° $5,000,000
$4,000,000
$3,000,000
$2,000,000
$1,000,000
$0
y = 3E-05x" + 66.263x + 841964
V ~ 1E-05xz + 37.69x + 607785
y*2E-06x2+,li.275x +
1203
316335
20,000 40,000 60,000 80,000 100,000 120,000 140,000 160,000 180,000
Design Intake Flow (gpm)
CJ
2
•o
3"
s
I
i*1
C7
o
r>
c
n
* 20 Meter Fine Mesh • 125 Meter Fine Mesh 250 Meter Fine Mesh 500 Meter Fine Mesh
I.
o
-------
Total Capital Costs
•«/»
•«/» •«/»
•«/>
-* NJ CO
O O O Q
8 8
§o
o
cna>^icocoo-^N)co^cno)
o o o o o o o o o o o o
§00000000000
ooooooooooo
e
a
n
t»
•o
I
n
o
re
n
2
C/3
O
n
I
ET
o
p
5*
3
01
I
I
o
rt
i
t/5
- m aSDl|
-------
S 316(b) Phase III - Technical Development Document
Technology Cost Modules
u
I
.2
a
2
o
i
o
0)
o
i
Oi
I
w
CA
4>
'5
v>
a»
4)
VI
1
u
a
A
U
I
.1"
u.
o
o
oo
o
CM
8 3
a
o>
o
o
n
S =
o c
O O)
00 M
0)
a
o
CD
o
••*
o
s
-------
§ 316(b) Phase III - Technical Development Document
Technology Cost Modules
«
"S
I
I
41
SI
JS
s
s
o
I
o
W B
5 «
U
co
« S
ON W
V
o
U
"«
'a,
U
3
E
o o o o
oooo
o o o o
in
§88_____
ooooooooo_o
o o o" o" o o o" c> o" o o" o"
oooooooooooo
o o o o_ o o o_ o o o o o_
c\T ^- o o> oo" t>-" TO in •«* co CNJ" r^
o
o
o
o"
CO
o
o"
(O
o
o
o
9
o
8
8 s
o
o
8 ^
I
3
s
o c
9" f
V
Q
oo
o
(O
§
o
CM
I
1
SJSOQ
-------
Figure 3-8. Total O&M Cost for Fine Mesh Passive Screen Relocated Offshore with Airburst Backwash
en
u
$70,000
$60,000
, -
ftffii- , »»•*£, r <*i „,,
&S«. "VK^*1- ' >• \ •' '
v'''*!*:'' ^m:&'y&^.s£'^ 'iV-:
MSK»Il?r*t ''. Vffcifi < V' * • «i rt •J'Tjffl*1 '? " •Sfe'1*^ w " • *» i'*"'rfP»JfMi'V^ . %>«,
, T^ffcSSm.5""^,**-!;®" JIT'-" '-^v5it'St'M,,1^5'^^^«i«^»s^&in^SI«^H6iiflHK»i(«S«r'l,
20,000
40,000 60,000
80,000 100,000 120,000 140,000 160,000 180,000
Design Intake Flow
+ Low Debris • High Debris
Uj
NJ
-------
Annual O&M Costs
O)
o
I
co
D
-------
§ 316(b) Phase III - Technical Development Document
Technology Cost Modules
1
cs
0)
o
I
O
•2
<**
«
bo
o
2!
-------
§ 316(b) Phase III - Technical Development Document
Technology Cost Modules
09
a>
o
1
.23
O
£
o
JS
.t>
to
O
1
u
M
a>
es
I
es
O
i
O
2J
u
CA
09
09
s
E
t/5
O
-------
CO
c?
s~*
D"
Figure 3-12. Capital Costs for Fine Mesh Passive Screen Existing Offshore in Freshwater with Zebra Mussels at
Selected Offshore Distances
$6,000,000
$5,000,000
-------
Total Capital Costs
(D
•5
NJ
o
o
o
o
§
2. co
(Q O
= 8
3 O
•*»
Dl
o
o
i
i s
1 °
o
o
o
CO
o
o
o
o
ere
i
Ui
n
to
T>
I
n
o
<*>
o
n
C/l
rt
9Q
o
I
o
•t
sr
a
I
o
te
- xil 3SDL|j (q)9i£ §
-------
Total Capital Costs
to
.
CO
w
to
§
I
Tl
(D
I
2-
oT
I
31
(D
IO
O
8
o
O
8
o
o 1
o
o
W 00
(5' P
3 O
= 8
•n
I
S"
•o
O
o
o
o
o
to
o
"o
o
o
o
8
o
05
o
8
CO
o
m
99
n
W
**
.b.
n
65
"H.
(•*•
—
n
P
o
n
<-<
3
n
VI
•0
65
I
W
t/3
65
I
6J
O
I
o
85
I
VI
sainpoyv 4503 A6o|ouMoai
- III ast>Hd (q)9I£
-------
Figure 3-15. Capital Costs for Very Fine Mesh Passive Screen Existing Offshore in Freshwater with Zebra Mussels at
Selected Offshore Distances
an
OJ
$8,000,000
$7,000,000
$6,000,000
w
g $5,000,000
o
"55
a $4,000,000 -
ns
U
I $3,000,000 -
$2,000,000 -
$1,000,000
$0
0
20,000 40,000
60,000 80,000 100,000 120,000
Design Intake Flow (gpm)
140,000 160,000 180,000
I
-8
x 20 Meter Very Fine Mesh • 125 Meter Very Fine Mesh + 250 Meter Very Fine Mesh " 500 Meter Very Fine Mesh
Ui
I
O\
I
I
-------
Annual O&M Costs
TO
n
H
o
n
o
o
3
3*
"S
ts
1
w
x
5-
p«»-
a*
tro
I
o
>
a1
§
- m 3501)4 (q)9i£ g
-------
§ 316(b) Phase HI - Technical Development Document
Technology Cost Modules
W!
«
I
u
«
.0
£
o
i
«
I
wi
OH
£
V)
41
O
O
o
O
O
O
o"
CO
o
(O
O
o"
o
CM
1
§1
O)
'w
§
o
o
o
o
CO
w
.a
&
O)
o
o
o
o"
CM
-------
§ 316(b) Phase III - Technical Development Document Technology Cost Modules
2.0 IMPROVEMENTS TO EXISTING SHORELINE INTAKES WITH TRAVELING SCREENS
2.1 Replace Existing Traveling Screens with New Traveling Screen Equipment
The methodology described below is based on data, where available, from the Detailed Technical Questionnaires. Where certain
facility data are unavailable (e.g., Short Technical Questionnaire facilities), the methodology generally uses statistical values (e.g.,
median values). The costs for traveling screen improvements described below are for installation in an existing or newly built intake
structure. Where the existing intake is of insufficient design or size, construction costs for increasing the intake size are developed in a
separate cost module and the cost for screen modification/installation at both the existing and/or new intake structure(s) are applied
according to the estimated size of each.
Estimating Existing Intake Size
The capital cost of traveling screen equipment is highly dependent on the size and surface area of the screens employed. In developing
compliance costs for existing facilities in Phase I, a single target, through-screen velocity was used. This decision ensured the overall
screen area of the units being costed was a direct function of design flow. Thus, EPA could rely on a cost estimating methodology for
traveling screens that focused primarily on design flow. In the Phase I approach, a single screen width was chosen for a given flow
range. Variations in cost were generally based on differences in screen well depth. Where the flow exceeded the maximum flow for
the largest screen costed, multiples of the largest (14 feet wide) screens were costed. Because, in this instance, EPA was applying it's
cost methodology to hypothetical facilities, screen well depth could be left as a dependent variable. However, for existing facilities
this approach is not tenable because existing screen velocities vary considerably between facilities. Because the size of the screens is
very much dependent on design flow and screen velocity, a different approach — one that first estimates the size of the existing screens
— is warranted.
Estimating Total Screen Width
Available data from the Detailed Questionnaires concerning the physical size of existing intake structures and screens are limited to
vertical dimensions (e.g., water depth, distance of water surface to intake deck, and intake bottom to water surface). Screen width
dimensions (parallel to shore) are not provided. For each model facility EPA has developed data concerning actual and estimated
design flow. Through-screen velocity is available for most facilities-even those that completed only the Short Technical
Questionnaire. Given the water depth, intake flow, and through screen velocity, the aggregate width of the intake screens can be
estimated using the following equation:
Screen Width (Ft) = Design Flow (cfs) / (Screen Velocity (feet per second) x Water Depth (Ft) x Open Area (decimal %))
The variables "design Flow," "screen velocity," and "water depth" can be obtained from the database for most facilities that completed
the Detailed Technical Questionnaire. These database values may not always correspond to the same waterbody conditions. For
example, the screen velocity may correspond to low flow conditions while the water depth may represent average conditions. Thus,
calculated screen widths may differ from actual values, but likely represents a reasonable estimate, especially given the limited
available data. EPA considers the above equation to be a reasonable method for estimating the general size of the existing intake for
cost estimation purposes. Determining the value for water depth at the intake, where no data is available, is described below.
The last variable in the screen width equation is the percent open area, which is not available in the database. However, the majority
of the existing traveling screens are coarse mesh screens (particularly those requiring equipment upgrades). In most cases (at least for
power plants), the typical mesh size is 3/8 inch (Petrovs 2002, Gathright 2002). This mesh size corresponds to an industry standard
that states the mesh size should be half the diameter of the downstream heat exchanger tubes. These tubes are typically around 7/8
inch in diameter for power plant steam condensers. For a mesh size of 3/8 inch, the corresponding percent open area for a square mesh
screen using 14 gauge wire is 68%. This combination was reported as "typical" for coarse mesh screens (Gathright 2002). Thus, EPA
will use an assumed percent open area value of 68% in the above equation.
At facilities where the existing through-screen velocity has been determined to be too high for fine mesh traveling screens to perform
properly, a target velocity of 1.0 feet per second was used in the above equation to estimate the screen width that would correspond to
the larger size intake that would be needed.
3-39
-------
S 316(b) Phase III - Technical Development Document Technology Cost Modules
Screen Well Depth
The costs for traveling screens are also a function of screen well depth, which is not the same as the water depth. The EPA cost
estimates for selected screen widths have been derived for a range of screen well depths ranging from 10 feet to 100 feet. The screen
well depth is the distance from the intake deck to the bottom of the screen well, and includes both water depth and distance from the
water surface to the deck. For those facilities that reported "distance from intake bottom to water surface" and "distance from water
surface to intake top," the sum of these two values can be used to determine actual screen well depth. For those Phase III facilities that
did not report this data, statistical values such as the median were used. The median value of the ratio of the water depth to the screen
well depth for all facilities that reported such data was 0.66. Thus, based on median reported values, the screen well depth can be
estimated by assuming it is 1.5 times the water depth where only water depth is reported. For those Phase III facilities that reported
water depth data, the median water depth at the intake was 18.0 feet.
Based on this discussion, screen well depth and intake water depth are estimated using the following hierarchy:
• If "distance from intake bottom to water surface" plus "distance from water surface to intake top" are reported, then the sum of
these values are used for screen well depth
• If only the "distance from intake bottom to water surface" and/or the "depth of water at intake" are reported, one of these values
(if both are known, the former selected is over the latter) is multiplied by a factor of 1.5
• If no depth data are reported, this factor is applied to the median water depth value of 18 feet (i.e., 27 feet) and this value is used.
This approach leaves open the question of which costing scenario well depth should be used where the calculated or estimated well
depth does not correspond to the depths selected for cost estimates. EPA has selected a factor of 1.2 as the cutoff for using a shallower
costing well depth. Exhibit 3-18 shows the range of estimated well depths that correspond to the specific well depths used for costing.
Exhibit 3-18. Guidance for Selecting Screen Well Depth for Cost Estimation
Calculated or Estimated Screen Well Depth (Ft)
0-12 ft
>12-30 ft
>30-60 ft
>60-90 ft
Well Depth to be Costed
10ft
25ft
50ft
75ft
Traveling Screen Replacement Options
Compliance action requirements developed for each facility may result in one of the following traveling screen improvement options:
• No Action.
• Add Fine Mesh Only (improves entrainment performance).
• Add Fish Handling Only (improves impingement performance).
• Add Fine Mesh and Fish Handling (improves entrainment and impingement performance).
Exhibit 3-19 shows potential combinations of existing screen technology and replacement technologies that are applied to these
traveling screen improvement options. In each case, there are separate costs for freshwater and saltwater environments.
Areas highlighted in grey in Exhibit 3-19 indicate that the compliance scenario is not compatible with the existing technology
combination. The table shows there are three possible technology combination scenarios that for a retrofit involving modifying the
existing intake structure only,. Each scenario is described briefly below:
Scenario A - Add fine mesh only
This scenario involves simply purchasing a separate set of fine mesh screen overlay panels and installing them in front of the existing
coarse mesh screens. This placement may be performed on a seasonal basis. This option is not considered applicable to existing
screens without fish handling and return systems, since the addition of fine mesh will retain additional aquatic organisms that would
require some means for returning them to the waterbody. Corresponding compliance O&M costs include seasonal placement and
removal of fine mesh screen overlay panels.
__
-------
§ 316(b) Phase III - Technical Development Document
Technology Cost Modules
Exhibit 3-19. Compliance Action Scenarios and Corresponding Cost Components
Compliance Action
Add Fine Mesh Only
(Scenario A)
Add Fish Handling Only
(Scenario B)
Add Fine Mesh With Fish
Handling
(Scenario C and Dual-Flow
Traveling Screens)
Cost Component Included in
EPA Cost Estimates
New Screen Unit
Add Fine Mesh Screen
Overlay
Fish Buckets
Add Spray Water Pumps
Add Fish Flume
New Screen Unit1
Add Fine Mesh Screen
Overlay2
Fish Buckets
Add Spray Water Pumps
Add Fish Flume
New Screen Unit
Add Fine Mesh Screen
Overlay
Fish Buckets
Add Spray Water Pumps
Add Fish Flume
Existing Technology
Traveling Screens Without
Fish Return
NA
NA , ,.
NA -'• •'.',''••' •';' "• ••" , "•
^A .:'^f> •'•_".:/""'•' ~
•NA~;, ..--, ••* .- • >-• ,
Yes
No
Yes
Yes
Yes
Yes
Yes3
Yes
Yes
Yes
Traveling Screens With Fish
Return
No
Yes
No
No
No
- ' * < - -* ?
4*A< " , .
i$ "t\ '*" _,:, . ^ .
™ '"- "' : ^^,A'\i*\ '•,*"$• [ '•
"MwA * *"•. " 3*'"*^ >t.i' *'- <* v ,
$$&»;* vI^fevMlvS-X- :; i,
¥£:•>•. J'— '.'..iT'^X
ii33v?T'^f^ •
4^^v/r""\V ';"J\ '
NA x, ''", - - '.
?, ' -
NA
?NA,,,,- , ..-..-.'•
.NA "'•--'
1 Replace entire screen unit, includes one set of smooth top or fine mesh screen.
2 Add fine mesh includes costs for a separate set of overlay fine mesh screen panels that can be placed in front of coarser mesh screens
on a seasonal basis.
3 Does not include initial installation labor for fine mesh overlays. Seasonal deployment and removal of fine mesh overlays is included
in O&M costs.
Scenario B - Add fish handling and return
This scenario requires the replacement of all of the traveling screen units with new ones that include fish handling features, but no
specific mesh requirements are included. Mesh size is assumed to be 1/8-inch by '/2-inch smooth top. A less costly option would be to
retain and retrofit portions of the existing screen units. However, vendors noted that approximately 75% of the existing screen
components would require replacement and it would be more prudent to replace the entire screen unit (Gathright 2002, Petrovs 2002).
Costs for additional spray water pumps and a fish return flume are included. Capital and O&M costs do not include any component
for seasonal placement of fine mesh overlays.
Scenario C - Add fine mesh with fish handling and return
This scenario requires replacement of all screen units with units that include fish handling and return features plus additional spray
water pumps and a fish return flume. Costs for a separate set of fine mesh screen overlay panels with seasonal placement are included.
3-41
-------
§ 316(b) Phase III - Technical Development Document Technology Cost Modules
Double Entry-Single Exit (Dual-Flow) Traveling Screens
The conditions for scenario C also apply to dual-flow traveling screens described separately below.
Fine Mesh Screen Overlay
Several facilities that have installed fine mesh screens found that during certain periods of the year the debris loading created operating
problems. These problems prompted operators to remove fine mesh screens and replace them with coarser screens for the duration of
the period of high and/or troublesome debris. As a high-side approach, when fine mesh screens replace coarse mesh screens
(Scenarios A and C), EPA has decided to include costs for using two sets of screens (one coarser mesh screen such as 1/8-inch by 1/4-
inch smooth top and one fine mesh overlay) with annual placement and removal of the fine mesh overlay. This placement of fine
mesh overlay can occur for short periods when sensitive aquatic organisms are present or for longer periods being removed only
during a the period when troublesome debris is present. Fine mesh screen overlays are also included in the costs for dual-flow
traveling screens described separately below.
Mesh Type
In general three different types of mesh are considered here. One is the coarse mesh which is typical in older installations. Coarse
mesh is considered to be the baseline mesh type and the typical mesh size is 3/8 inch square mesh. When screens are replaced, two
types of mesh are considered. One is fine mesh, which is assumed to have openings in the 1 to 2 mm range. The other mesh type is
the smooth top mesh. Smooth top mesh has smaller openings (at least in one dimension) than coarse mesh (e.g., 1/8-inch by !/2-inch is
a common size) and is manufactured in a way that reduces the roughness that is associated with coarse mesh. Smooth top mesh is used
in conjunction with screens that have fish handling and return systems. The roughness of standard coarse mesh has been blamed for
injuring (descaling) fish as they are washed over the screen surface when they pass from the fish bucket to the return trough during the
fish wash step. Due to the tighter weave of fine mesh screens, roughness is not an issue when using fine mesh.
2.1.1 Traveling Screen Capital Costs
The capital cost of traveling screen equipment is generally based on the size of the screen well (width and depth), construction
materials, type of screen baskets, and ancillary equipment requirements. While EPA has chosen to use the same mix of standard
screen widths and screen well depths as were developed for the new facility Phase I effort, as described above, the corresponding
water depth, design flow, and through-screen velocities in most cases differ. As presented in Exhibit 3-19, cost estimates do not need
to include a compliance scenario where replacement screen units without fish handling and return equipment are installed. Unlike the
cost methodology developed for Phase I, separate costs are developed in Phase III costing for equipment suitable for freshwater and
saltwater environments. Costs for added spray water pumps and fish return flumes are described below, but unlike the screening
equipment are generally a function of screen width only.
Screen Equipment Costs
EPA contacted traveling screen vendors to obtain updated costs for traveling screens with fine mesh screens and fish handling
equipment for comparison to the 1999 costs developed for Phase I. Specifically, costs for single entry-single exit (through-flow)
screens with the following attributes were requested:
-Spray systems
-Fish trough
-Housings and transitions
-Continuous operating features
-Drive unit
-Frame seals
-Engineering
-Freshwater versus saltwater environments.
Only one vendor provided comparable costs (Gathright 2002). The costs for freshwater environments were based on equipment
constructed primarily of epoxy-coated carbon steel with stainless steel mesh and fasteners. Costs for saltwater and brackish water
environments were based on equipment constructed primarily of 316 stainless steel with stainless steel mesh and fasteners.
3-42
-------
316(b) Phase III - Technical Development Document
Technology Cost Modules
EPA compared these newly obtained equipment costs to the costs for similar freshwater equipment developed for Phase I, adjusted for
inflation to July 2002 dollars. EPA found that the newly obtained equipment costs were lower by 10% to 30%. In addition, a
comparison of the newly obtained costs for brackish water and freshwater screens showed that the costs for saltwater equipment were
roughly 2.0 times the costs for freshwater equipment. This factor of approximately 2.0 was also suggested by a separate vendor
(Petrovs 2002). Rather than adjust the Phase I equipment costs downward, EPA chose to conclude that the Phase I freshwater
equipment costs adjusted to 2002 were valid (if not somewhat overestimated), and that a factor of 2.0 would be reasonable for
estimating the cost of comparable saltwater/brackish water equipment. Exhibits 3-20 and 3-21 present the Phase I equipment costs,
adjusted for inflation to July 2002 dollars, for freshwater and saltwater environments respectively.
Exhibit 3-20. Equipment Costs for Traveling Screens with Fish Handling for Freshwater Environments, 2002 Dollars
Well Death
(Ft)
10
25
50
75
100
Basket Screenina Panel Width (Ft)
2
$69.200
$88.600
$133.500
$178.500
$245,300
5
$80.100
$106.300
$166.200
$228.900
$291,600
10
$102.500
$145.000
$237.600
$308.500
$379,300
14
$147.700
$233.800
$348.300
$451.800
$549,900
Exhibit 3-21. Equipment Costs for Traveling Screens with Fish Handling for Saltwater Environments, 2002 Dollars
Well Death
(Ftt
10
25
50
75
100
Basket Screenina Panel Width (Ft)
2
$138.400
$177.200
$267.000
$357.000
$490,600
5
$160.200
$212.600
$332.400
$457,800
$583,200
10
$205.000
$290.000
$475.200
$617.000
$758,600
14
$295.400
$467.600
$696.600
$903.600
$1,099,800
Costs for fine mesh screen overlay panels were cited as approximately 8% to 10% of the total screen unit costs (Gathright 2002). The
EPA cost estimates for fine mesh overlay screen panels are based on a 10% factor applied to the screen equipment costs shown in
Exhibit 3-20 and 3-21. Note that if the entire screen basket required replacement, then the costs would increase to about 25% to 30%
of the screen unit costs (Gathright 2002, Petrovs 2002). However, in the scenarios considered here, basket replacement would occur
only when fish handling is being added. In those scenarios, EPA has chosen to assume that the entire screen unit will require
replacement. The cost of new traveling screen units with smooth top mesh is only about 2% above that for fine mesh (Gathright
2002). EPA has concluded that the cost for traveling screen units with smooth top mesh is nearly indistinguishable from that for fine
mesh. Therefore, EPA has not developed separate costs for each.
Screen Unit Installation Costs
Vendors indicated that the majority of intakes have stop gates or stop log channels that enable the isolation and dewatering of the
screen wells. Thus, EPA assumes, in most cases, screens can be replaced and installed in dewatered screen wells without the use of
divers. When asked whether most screens were accessible by crane, a vendor did note that about 70% to 75% may have problems
accessing the intake screens by crane from overhead. In such cases, the screens are dismantled (screen panels are removed, chains are
removed and screen structure is removed in sections that key into each other). Such overhead access problems may be due to
structural cover or buildings, and access is often through the side wall. According to one vendor, this screen dismantling requirement
may add 30% to the installation costs. For those installations that do not need to dismantle screens, these costs typically are $15,000 to
$30,000 per unit (Petrovs 2002). Another vendor cited screen installation costs as +/- $45,000 per screen giving an example of
$20,000 for a 15-foot screen plus the costs of a crane and forklift ($15,000 - $20,000 divided between screens) (Gathright 2002). Note
that these installation costs are for the typical range of screen sizes; vendors noted that screens in the range of the 100-foot well depth
are rarely encountered.
3-43
-------
S 316(b) Phase III - Technical Development Document
Technology Cost Modules
Exhibit 3-22 presents the installation costs developed from vendor supplied data. These costs include crane and forklift costs and are
presented on a per screen basis. Phase I installation costs included an intake construction component not included in Phase III costs.
The costs shown here assume the intake structure and screen wells are already in-place. Therefore, installation involves removing
existing screens and installing new screens in their place. Any costs for increasing the intake size are developed as a separate module.
Vendors indicated costs for disposing of the existing screens were minimal. The cost of removal and disposal of old screens,
therefore, are assumed to be included in the Exhibit 3-22 estimates.
Exhibit 3-22. Traveling Screen Installation Costs
Well Death
(Ft)
10
25
50
75
100
Baske
2
$15.000
$22.500
$30.000
$37.500
$45,000
Screeninc
5
$18.000
$27.000
$36.000
$45.000
$54,000
Panel Wit
10
$21.000
$31.500
$42.000
$52.500
$63,000
th fFtt
14
$25.000
$37.000
$50.000
$62.500
$75,000
Installation of Fine Mesh Screen Panel Overlays
Screen panel overlay installation and removal costs are based on an estimate of the amount of labor required to replace each screen
panel. Vendors provided the following estimates for labor to replace screen baskets and panels (Petrovs 2002, Gathright 2002):
• 1.0 hours per screen panel overlay (1.5 hours to replace baskets and panel)
• Requires two-man team for small screen widths (assumed to be 2- and 5-foot wide screens)
• Requires three-man team for large screen widths (assumed to be 10- and 14-foot wide screens)
• Number of screen panels is based on 2-foot tall screen panels on front and back extending 6 feet above the deck. Thus, a screen
for a 25-foot screen well is estimated to have 28 panels.
Labor costs are based on a composite labor rate of $41.10/hr (See O&M cost section).
These assumptions apply to installation costs for Scenario A. These same assumptions also apply to O&M costs for fine mesh screen
overlay in Scenarios A and C, where it is applied twice for seasonal placement and removal.
Indirect Costs Associated with Replacement of Traveling Screens
EPA noted that equipment costs (Exhibits 3-20 and 3-21) included the engineering component and that installation costs (Exhibit 3-22)
included costs for contractor overhead and profit. Because the new screens are designed to fit the existing screen well channels and
the existing structure is of a known design, contingency and allowance costs should be minimal. Also, no costs for sitework were
included because existing intakes, in most cases, should already have provisions for equipment access. Because inflation-adjusted
equipment costs exceeded the recently obtained equipment vendor quotation by 10% to 30%, EPA has concluded any indirect costs are
already included in the equipment cost component.
Combining Per Screen Costs with Total Screen Width
As noted above, total screen costs are estimated using a calculated screen width as the independent variable. In many cases, this
calculated width will involve using more than one screen, particularly if the width is greater than 10 to 14 feet. Vendors have
indicated there is a general preference for using 10-foot wide screens over 14-foot screens, but that 14-foot screens are more
economical (reducing civil structure costs) for larger installations. The screen widths and corresponding number and screens used to
plot screen cost data and develop cost equations are as follows:
2ft
5ft
10ft
a single
a single
a single
2-ft screen
5-ft screen
10-ft screen
3-44
-------
i 316(b) Phase III - Technical Development Document Technology Cost Modules
20ft = two 10-ft screens
30ft = three 10-ft screens
40ft = four 10-ft screens
50ft = five 10-ft screens
60ft = six 10-ft screens
70ft = five 14-ft screens
84ft = six 14-ft screens
98 ft = seven 14-ft screens
112ft = eight 14-ft screens
126ft = nine 14-ft screens
140ft = ten 14-ft screens.
Any widths greater than 140 feet are divided and the costs for the divisions are summed.
Ancillary Equipment Costs for Fish Handling and Return System
When adding a screen with a fish handling and return system where no fish handling system existed before, there are additional
requirements for spray water and a fish return flume. The equipment and installation costs for the fish troughs directly adjacent to the
screen and spray system are included in the screen unit and installation costs. However, the costs for pumping additional water for the
new fish spray nozzles and the costs for the fish return flume from the end of the intake structure to the discharge point are not
included. Fish spray and flume volume requirements are based solely on screen width and are independent of depth.
Pumps for Spray Water
Wash water requirements for the debris wash and fish spray were obtained from several sources. Where possible, the water volume
was divided by the total effective screen width to obtain the unit flow requirements (gpm/ft). Total unit flow requirements for both
debris wash and fish spray combined ranged from 26.7 gpm/ft to 74.5 gpm/ft. The only data with a breakdown between the two uses
reported a flow of 17.4 gpm/ft for debris removal and 20.2 gpm/ft for fish spray, with a total of 37.5 gpm/ft (Petrovs 2002). Based on
these data, EPA assumed a total of 60 gpm/ft with each component being equal at 30 gpm/ft. These values are near the high end of the
ranges reported and were selected to account for additional water needed at the upstream end of the fish trough to maintain a minimum
depth.
Because the existing screens already have pumps to provide the necessary debris spray flow, only the costs for pumps sized to deliver
the added fish spray are included in the capital cost totals. Costs for the added fish spray pumps are based on the installed equipment
cost estimates developed for Phase I, adjusted to July 2002 dollars. These costs already include an engineering component. An
additional 10% was added for contingency and allowance. Also, 20% was added to theses costs to account for any necessary
modifications to the existing intake (based on BPJ). Exhibit 3-23 presents the costs for adding pumps for the added fish spray volume.
The costs in Exhibit 3-23 were plotted and a best-fit, second-order equation derived from the data. Pump costs were then projected
from this equation for the total screen widths described earlier.
3-45
-------
§ 316(b) Phase HI - Technical Development Document
Technology Cost Modules
Exhibit 3-23. Fish Spray Pump Equipment and Installation Costs
Centrifug
al Pump
Flow
(gpm)
10
50
75
100
500
1.000
2,000
4,000
Costs for
Centrifugal
Pumps -
Installed (1999
Dollars)
$800
$2.250
$2.500
$2.800
$3.700
$4.400
$9,000
$18.000
Pump Costs
Adjusted to
July 2002
$872
$2.453
$2.725
$3052
$4.033
$4.796
$9,810
$19.620
Retrofit
Cost&
Indirect
Costs
$262
$736
$818
$916
$1.210
$1.439
$2,943
$5.886
Total
Installed
Cost
$1.134
$3.189
$3.543
$3.968
$5.243
$6.235
$12,753
$25,506
Fish Return Flume
In the case of the fish return flume, the total volume of water to be carried was assumed to include both the fish spray water and the
debris wash water. A total unit flow of 60 gpm/ft screen width was assumed as a conservative value for estimating the volume to be
conveyed. Return flumes may take the form of open troughs or closed pipe and are often constructed of reinforced fiberglass
(Gathright 2002, Petrovs 2002). The pipe diameter is based on an assumed velocity of 1.5 feet per second, which is at the low end of
the range of pipe flow velocities. Higher velocities will result in smaller pipes. Actual velocities may be much higher in order to
ensure fish are transported out of the pipe. With lower velocities fish can continually swim upstream. Vendors have noted that the
pipes do not tend to flow full, so basing the cost on a larger pipe sized on the basis of a low velocity is a reasonable approach.
Observed flume return lengths varied considerably. In some cases, where the intake is on a tidal waterbody, two return flumes may be
used alternately to maintain the discharge in the downstream direction of the receiving water flow. A traveling screen vendor
suggested lengths of 75 to 150 feet (Gathright 2002). EPA reviewed facility description data and found example flume lengths ranging
from 30 ft to 300 ft for intakes without canals, and up to several thousand feet for those with canals. For the compliance scenario
typical flume length, EPA chose the upper end of the range of examples for facilities without intake canals (300 ft). For those intakes
located at the end of a canal, the cost for the added flume length to get to the waterway (assumed equal to canal length) is estimated by
multiplying an additional unit cost-per-ft times the canal length. This added length cost is added to the non-canal facility total cost.
To simplify the cost estimation approach, a unit pipe/support structure cost ($/inch-diameter/ft-length) was developed based on the unit
cost of a 12-inch reinforced fiberglass pipe at $70/ft installed (RS Means 2001) and the use of wood pilings at 10-foot intervals as the
support structure. Piling costs assume that the average piling length is 15 feet and unit cost for installed pilings is $15.80/ft (RS Means
2001). The unit costs already include the indirect costs for contractor overhead and profit. Additional costs include 10% for
engineering, 10% for contingency and allowance, and 10% for sitework. Sitework costs are intended to cover preparation and
restoration of the work area adjacent to the flume. Based on these cost applied to an assumed 300-foot flume, a unit cost of $10.15/in
diameter/ft was derived. Flume costs for the specific total screen widths were then derived based on a calculated flume diameter
(using the assumed flow volume of 60 gpm/ft, the 1.5-feet per second velocity when full) times the unit cost and the length.
EPA was initially concerned whether there would be enough vertical head available to provide the needed gradient, particularly for the
longer applications. In a typical application, the upstream end of the flume is located above the intake deck and the water flows down
the flume to the water surface below. A vendor cited a minimum gradient requirement in the range of 0.001 to 0.005 ft drop/ft length.
For a 300-foot pipe, the needed vertical head based on these gradients is only 0.3 feet to 1.5 feet. The longest example fish return
length identified by EPA was 4,600 feet at the Brunswick, SC plant. The head needed for that return, based on the above minimum
gradient range, is 4.6 feet to 23 feet. Based on median values from the industry questionnaire data base, intake decks are often about
half the intake water depth above the water surface, EPA has concluded in most cases there was more than enough gradient available.
Indeed, the data suggest if the return length is too short, there may be a potential problem from too great a gradient producing
velocities that could injure fish.
3-46
-------
§ 316(b) Phase HI - Technical Development Document
Technology Cost Modules
Exhibit 3-24 presents the added spray water pumps costs, 300-foot flume costs and the unit cost for additional flume length above 300
feet. Note that a feasibility study for the Drayton Point power plant cited an estimated flume unit cost of $100/ft which does not
include indirect costs but is still well below comparable costs shown in Exhibit 3-24.
Exhibit 3-24. Spray Pump and Flume Costs
Toa Screen Wdhlftt
Fish Stra/ Rouvdt 30axrVft (
-------
S 316(b) Phase III - Technical Development Document
Technology Cost Modules
Labor Requirements
The basis for estimating the total annual labor cost is based on labor hours as described below. In each baseline and compliance
scenario the estimated number of hours is multiplied times a single hourly rate of $41.10/hour. This rate was derived by first
estimating the hourly rate for a manager and a technician. The estimated management and technician rates were based on Bureau of
Labor Statistics hourly rates for management and electrical equipment technicians. These rates were multiplied by factors that
estimate the additional costs of other compensation (e.g., benefits) to yield estimates of the total labor costs to the employer. These
rates were adjusted for inflation to represent June 2002 dollars (see Doley 2002 for details). The two labor category rates were
combined into one compound rate using the assumption that 90% of the hours applied to the technicians and 10% to management. A
10% management component was considered as reasonable because the majority of the work involves physical labor, with managers
providing oversight and coordination with the operation of the generating units.
A vendor provided general guidelines for estimating basic labor requirements for traveling screens as averaging 200 hours and ranging
from 100 to 300 hours per year per screen for coarse mesh screens without fish handling and double that for fine mesh screens with
fish handling (Gathright 2002). The lower end of the range corresponds to shallow narrow screens and the high end of the range
corresponds to the widest deepest screens. Exhibits 3-31 and 3-32 present the estimated annual number of labor hours required to
operate and maintain a "typical" traveling screen.
Exhibit 3-31. Basic Annual O&M Labor Hours for Coarse Mesh Traveling Screens Without Fish Handling
Well Death
feet
10
25
50
75
100
Basket Screenina Panel Width
2
100
120
130
140
150
5
150
175
200
225
250
10
175
200
225
250
275
14
200
225
250
275
300
Exhibit 3-32. Basic Annual O&M Labor Hours for Traveling Screens With Fish Handling
Well Deoth
feet
10
25
50
75
100
Basket Screenina Panel Width (Ft)
2
78
168
318
468
618
5
78
168
318
468
618
10
117
252
477
702
927
14
117
252
477
702
927
When fine mesh screens are added as part of a compliance option, they are included as a screen overlay. EPA has assumed when
sensitive aquatic organisms are present these fine mesh screens will be in place. EPA also assumes during times when levels of
troublesome debris are present the facility will remove the fine mesh screen panels leaving the coarse mesh screen panels in place.
The labor assumptions for replacing the screen panels are described earlier, but in this application the placement and removal steps
occur once each per year. Exhibit 3-33 presents the estimated annual labor hours for placement and removal of the fine mesh overlay
screens.
3-48
-------
§ 316(b) Phase III - Technical Development Document
Technology Cost Modules
Exhibit 3-33. Total Annual O&M Hours for Fine Mesh Overlay Screen Placement and Removal
Well Deoth
feet
10
25
50
75
100
Basket Screeninq Panel Width
2
78
168
318
468
618
5
78
168
318
468
618
10
117
252
477
702
927
14
117
252
477
702
927
Operating Power Requirement
Power is needed to operate the mechanical equipment, specifically the motor drives for the traveling screens and the pumps that
deliver the spray water for both the debris wash and the fish spray.
Screen Drive Motor Power Requirement
Coarse mesh traveling screens without fish handling are typically operated on an intermittent basis. When debris loading is low the
screens may be operated several times per day for relatively short durations. Traveling screens with fish handling and return systems,
however, must operate continuously if the fish return system is to function properly.
A vendor provided typical values for the horsepower rating for the drive motors for traveling screens which are shown in Exhibit 3-34.
These values were assumed to be similar for all of the traveling screen combinations considered here. Different operating hours are
assumed for screens with and without fish handling. This is due to the fact that screens with fish handling must be operated
continuously. A vendor estimated that coarse mesh screens without fish handling are typically operated for a total of 4 to 6 hrs/day
(Gathright 2002). The following assumptions apply:
• The system will be shut down for four weeks out of the year for routine maintenance
• For fine mesh, operating hours will be continuous (24 hrs/day)
• For coarse mesh, operating hours will be an average of 5 hours/day (range of 4 to 6)
• Electric motor efficiency of 90%
• Power cost of $0.04/kWh for power plants.
Wash Water and Fish Spray Pump Power Requirement
As noted previously, spray water is needed for both washing debris off of the screens (which occurs at all traveling screens) and for a
fish spray (which is needed for screens with fish handling and return systems). The nozzle pressure for the debris spray can range
from 80 to 120 psi. A value of 120 psi was chosen as a high value which would include any static pressure component. The following
assumptions apply:
• Spray water pumps operate for the same duration as the traveling screen drive motors
• Debris wash requires 30 gpm/ft screen length
Fish spray requires 30 gpm/ft screen length
Pumping pressure is 120 psi (277 ft of water) for both
• Combined pump and motor efficiency is 70%
• Electricity cost is $0.04/KWh for power plants.
The pressure needed for fish spray is considerably less than that required for debris, but it is assumed that all wash water is pumped to
the higher pressure and regulators are used to step down the pressure for the fish wash. Exhibits 3-35 and 3-36 present the power costs
for the spray water for traveling screens without and with fish handling, respectively. Spray water requirements depend on the
presence of a fish return system but are assumed to otherwise be the same regardless of the screen mesh size.
3-49
-------
§ 316(b) Phase III - Technical Development Document
Technology Cost Modules
Exhibit 3-34. Screen Drive Motor Power Costs
Screen
Width
Ft
2
2
2
2
2
5
5
5
5
5
10
10
10
10
10
14
14
14
14
14
Well
Death
Ft
10
25
50
75
100
10
25
50
75
100
10
25
50
75
100
10
25
50
75
75
Motor
Power
Ho
0.5
1
2.7
5
6.7
0.75
1.5
4
7.5
10.0
1
3.5
10
15
20.0
2
6.25
15
20
26.6
Electric
Power
Kw
0.414
0.829
2.210
4.144
5.512
0.622
1.243
3.316
6.217
8.268
0.829
2.901
8.289
12.433
16.536
1.658
5.181
12.433
16.578
22.048
Power Costs - Fin
Operating
Hours
8.064
8.064
8.064
8,064
8.064
8.064
8.064
8.064
8.064
8,064
8.064
8.064
8.064
8.064
8,064
8.064
8.064
8.064
8.064
8,064
Annual
Power
Kwh
3.342
6.684
17.824
33.421
44,450
5.013
10.026
26.737
50.131
66.674
6.684
23.395
66.842
100.262
133.349
13.368
41.776
100.262
133.683
177,799
pMesh
Annual
Power
Costs at
S/Kwh of
$0.04
$134
$267
$713
$1.337
$1.778
$201
$401
$1.069
$2.005
$2.667
$267
$936
$2.674
$4.010
$5.334
$535
$1.671
$4.010
$5.347
$7,112
Power Costs - Coa
Operating
Hours
1.680
1.680
1.680
1.680
1.680
1.680
1.680
1 680
1.680
1,680
1.680
1.680
1.680
1.680
1.680
1.680
1.680
1.680
1.680
1,680
Annual
Power
Kwh
696
1.393
3.713
6.963
9.260
1.044
2.089
5570
10.444
13,891
1.393
4.874
13.925
20.888
27,781
2.785
8.703
20.888
27.851
37,041
*se Mesh
Annual
Power
Costs at
$/Kwh of
$0.04
$28
$56
$149
$279
$370
$42
$84
$223
$418
$556
$56
$195
$557
$836
$1,111
$111
$348
$836
$1.114
$1,482
Exhibit 3-35. Wash Water Power Costs Traveling Screens Without Fish Handling
Screen
Width
ft
2
5
10
14
Flow Rate
QDTTI
60
150
300
420
Total Head
ft
277
277
277.1
277
Hydraulic-
HD
HD
4.20
10.49
20.98
29.37
Brake-Ho
HD
6.0
15.0
30.0
42.0
Power
Requirem
ent
Kw
4.5
11.2
224
31.3
Fine Mesh
Annual
Hours
hr
8064
8064
8064
8064
Annual
Power
Kwh
36.072
90.179
180.359
252,502
Total
Costs at
$/Kwhof
S0.04
$1.443
$3.607
$7.214
$10,100
Coarse Mes
Annual
Hours
hr
1680
1680
1680
1680
Annual
Power
Kwh
7.515
18787
37575
52605
h
Total
Costs at
$/Kwh of
$0.04
$301
$751
$1.503
$2,104
Exhibit 3-36. Wash Water and Fish Spray Power Costs Traveling Screens With Fish Handling
Screen
Width
ft
2
5
10
14
Flow Rate
dom
120
300
600
840
Total Head
ft
277
277
277
277
Hydraulic-
HD
Ho
8.39
20.98
41.97
58.76
Brake-Ho
HD
12.0
30.0
60.0
83.9
Power
Requirem
ent
Kw
8.9
224
44.7
62.6
Fine Mesh
Annual
Hours
hr
8064
8064
8064
8064
Annual
Power
Kwh
72.143
180.359
360.717
505,004
Total
Costs at
$/Kwhof
$0.04
$2.886
$7.214
$14.429
$20.200
Coarse Mesh
Annual
Hours
hr
1680
1680
1680
1680
Annual
Power
Kwh
15.030
37575
75149
105209
Total
Costs at
$/Kwhof
$0.04
$601
$1.503
$3.006
$4,208
3-50
-------
S 316(b) Phase HI - Technical Development Document
Technology Cost Modules
Parts Replacement
A vendor estimated that the cost of parts replacement for coarse mesh traveling screens without fish handling would be approximately
15% of the equipment costs every 5 years (Gathright 2002). For traveling screens with fish handling, the same 15% would be replaced
every 2.5 years. EPA has assumed for all screens that the annual parts replacement costs would be 6% of the equipment costs for
those operating continuously and 3% for those operating intermittently. These factors are applied to the equipment costs in Exhibits 3-
20 and 3-21. Traveling screens without fish handling (coarse mesh) operate fewer hours (estimated at 5 hrs/day) and should therefore
experience less wear on the equipment. While the time of operation is nearly five times longer for continuous operation, the screen
speed used is generally lower for continuous operation. Therefore, the wear and tear, hence O&M costs, are not directly proportional.
Baseline and Compliance O&M Scenarios
Exhibit 3-37 presents the six baseline and compliance O&M scenario cost combinations developed by EPA.
For the few baseline operations with fine mesh, nearly all had fish returns and or low screen velocities, indicating that such facilities
will likely not require compliance action. Thus, there is no baseline cost scenario for traveling screens with fine mesh without fish
handling and return. Exhibits 3-38 through 3-43 (at the end of this section) present the O&M costs for the cost scenarios shown in
Exhibit 3-37. Figures 3-24 through 3-29 present the graphic plots of the O&M costs shown in these tables with best-fit, second-order
equations of the plots. These equations are used in the estimation of O&M costs for the various technology applications.
Exhibit 3-37. Mix of O&M Cost Components for Various Scenarios
Mesh Type
Fish Handling
Water Type
Screen Operation
Basic Labor
Screen Overlay Labor
Screen Motor Power
Debris Spray Pump
Power
Fish Spray Pump Power
Parts Replacement - %
Equipment Costs
Baseline
Without
Fish
Handling
Coarse
None
Freshwater
5 hrs/day
1 00-300 hrs
None
5 hrs/day
5 hrs/day
None
3%
Baseline
Without
Fish
Handling
Coarse
None
Saltwater
5 hrs/day
100-300 hrs
None
5 hrs/day
5 hrs/day
None
3%
Baseline with
Fish Handling &
Scenario B
Compliance
Coarse or Smooth
Top
Yes
Freshwater
Continuous
200-600 hrs
None
Continuous
Continuous
Continuous
6%
Baseline with
Fish Handling
& Scenario B
Compliance
Coarse or
Smooth Top
Yes
Saltwater
Continuous
200-600 hrs
None
Continuous
Continuous
Continuous
6%
Scenario
A&C
Compliance
Smooth Top
&Fine
Yes
Freshwater
Continuous
200-600 hrs
Yes
Continuous
Continuous
Continuous
6%
Scenario
A&C
Compliance
Smooth Top
&Fine
Yes
Saltwater
Continuous
200-600 hrs
Yes
Continuous
Continuous
Continuous
6%
O&M for Nuclear Facilities
Unlike the assumption for capital costs, the O&M costs for nuclear facilities consider the differences in the component costs. The
power cost component is assumed to be the same. The equipment replacement cost component uses the same annual percentage of
equipment cost factors, but is increased by the same factor as the capital costs (2.0). A Bureau of Labor Statistics document (BLS
2002) reported that the median annual earnings of a nuclear plant operator were $57,220 in 2002 compared to $46,090 for power plant
operators in general. Thus, nuclear operators earnings were 24% higher than the industry average. No comparable data were available
for maintenance personnel. This factor of 24% is used for estimating the increase in labor costs for nuclear facilities. This factor may
3-57
-------
§ 316(b) Phase HI - Technical Development Document
Technology Cost Modules
be an overestimation: nuclear plant operators require a proportionally greater amount of training and the consequences of their actions
engender greater overall risks than the intake maintenance personnel. EPA recalculated the O&M costs using the revised equipment
replacement and labor costs. EPA found that the ratio of non-nuclear to nuclear O&M costs did not vary much for each scenario and
water depth. Therefore, EPA chose to use the factor derived from the average ratio (across total width values) of estimated nuclear
facility O&M to non-nuclear facility O&M for each scenario and well depth to estimate the nuclear facility O&M costs. Exhibit 3-44
presents the cost factors to be used to estimate nuclear facility O&M costs for each cost scenario and well depth using the non-nuclear
O&M values as the basis.
Exhibit 3-44. Nuclear Facility O&M Cost Factors
Well Deoth
Ft
10
25
50
75
100
Baseline O&M
Traveling Screens
Without Fish Handlina
Freshwater
1.32
1.35
1.39
1.41
1.42
Baseline O&M
Traveling Screens
Without Rsh Handlina
Saltwater
1.41
1.46
1.51
1.53
1.55
Baseline & Scenario
B Compliance O&M
Traveling Screens
With Fish Handlina
Freshwater
1.29
1.33
1.39
1.43
1.45
Baseline & Scenario
B Compliance O&M
Traveling Screens
With Fish Handlina
Saltwater
1.40
1.46
1.53
1.57
1.60
Scenario A & C
Compliance O&M
Traveling Screens
With Fish Handlina
Freshwater
1.28
1.32
1.36
1.38
1.40
Scenario A & C
Compliance O&M
Traveling Screens
With Fish Handlina
Saltwater
1.39
1.44
1.49
1.51
1.53
2.1.4 Double Entry-Single Exit (Dual-flow) Traveling Screens
Another option for replacing coarse mesh single entry-single exit (through-flow) traveling screens is to install double entry-single exit
(dual-flow) traveling screens. Such screens are designed and installed to filter water continuously, using both upward and downward
moving parts of the screen. The interior space between the upward and downward moving screen panels is closed off on one side
(oriented in the upstream direction), while screened water exits towards the pump well through the open end on the other side.
One major advantage of dual-flow screens is that the direction of flow through the screen does not reverse as it does on the back side
of a through-flow screen. As such, there is no opportunity for debris stuck on the screen to dislodge on the downstream side. In
through-flow screens, debris that fails to dislodge as it passes the spray wash can become dislodged on the downstream side
(essentially bypassing the screen). Such debris continues downstream where it can plug condenser tubes or require more frequent
cleaning of fixed screens set downstream of the intake screen to prevent condenser tube plugging. Such maintenance typically
requires the shut down of the generating units. Since dual-flow screens eliminate the opportunity for debris carryover, the spray water
pressure requirements are reduced with dual-flow screens requiring a wash water spray pressure of 30 psi compared to 80 to 120 psi
for through-flow screens (Gathright 2002). Dual-flow screens are oriented such that the screen face is parallel to the direction of flow.
By extending the screen width forward (perpendicular to the flow) to a size greater than one half the screen well width, the total screen
surface area of a dual-flow screen can exceed that of a through-flow screen in the same application. Therefore, if high through-screen
velocities are affecting the survival of impinged organisms in existing through-flow screens, the retrofit of dual-flow screens may help
alleviate this problem. The degree of through-screen velocity reduction will be dependent on the space constraints of the existing
intake configuration. In new intake construction, dual-flow screens can be installed with no walls separating the screens.
Retrofitting existing intakes containing through-flow screens with dual-flow screens can be performed with little or minor
modifications to the existing intake structure. In this application, the dual-flow screens are constructed such that the open outlet side
will align with the previous location of the downstream side of the through-flow screen. The screen is constructed with supports that
slide into the existing screen slots and with "gull wing" baffles that close off the area between the screens downstream end and the
screen well walls. The baffles are curved to better direct the flow. For many existing screen structures, the opening where the screen
passes through the intake deck (including the open space in front of the screen) is limited to a five-foot opening front to back which
limits the equivalent total overall per screen width of just under 10 ft for dual-flow retrofit screens. Because dual-flow screens filter on
both sides the effective width is twice that of one screen panel. However, a vendor indicated, in many instances the screen well
opening can be extended forward by demolishing a portion of the concrete deck at the front end. The feasibility and extent of such a
modification (such as maximum width of the retrofit screen) is dependent on specific design of the existing intake, particularly
concerning the proximity of obstructions upstream of the existing screen units. Certainly, most through-flow screens of less than 10 ft
widths could be retrofitted with dual-flow screens that result in greater effective screen widths. Those 10 ft wide or greater that have
large deck openings and/or available space could also install dual-flow screens with greater effective screen widths.
3-52
-------
§ 316(b) Phase III - Technical Development Document Technology Cost Modules
Capital Cost for Dual-Flow Screens
A screen vendor provided general guidance for both capital and O&M costs for dual-flow screens (Gathright 2002). The cost of dual-
flow screens with fish handling sized to fit in existing intake screen wells could be estimated using the following factors applied to the
costs of a traveling screen with fish handling that fit the existing screen well:
• For a screen well depth of 0 to <20 ft add 15% to the cost of a similarly sized through-flow screen.
For a screen well depth of 20 ft to <40 ft add 10% to the cost of a similarly sized through-flow screen.
For a screen well depth of greater than 40 ft add 5% to the cost of a similarly sized through-flow screen.
Installation costs are assumed to be similar to that for through-flow screens. The above factors were applied to the total installed cost
of similarly sized through-flow screens, however, an additional 5% was added to the above cost factors to account for modifications
that may be necessary to accommodate the new dual-flow screens such as demolition of a portion of the deck area. It is assumed that
dual-flow screens can be installed in place of most through-flow screens but the benefit of lower through screen velocities may be
limited for larger width (e.g., 14-ft) existing screens. The dual-flow screens are assumed to include fine mesh overlays and fish return
systems, so the cost factors are applied to the scenario C through-flow screens only. The costs for dual-flow screens are not presented
here but can be derived by applying the factor shown in Exhibit 3-45 below.
The capital costs for adding fine mesh overlays to existing dual-flow screens (scenario A) is assumed to be the same as for through-
flow screens. This assumption is based on the fact that installation labor is based on the number of screen panels and should be the
nearly the same and that the cost of the screen overlays themselves should be nearly the same. The higher equipment costs for dual-
flow screens is mostly due to the equipment and equipment modifications located above the deck.
Exhibit 3-45. Capital Cost Factors for Dual-Flow Screens
Screen Depth
10 Ft
25 Ft
50 Ft
75 Ft
Capital Cost Factor1
1.2
1.15
1.1
1.1
1 Applied to capital costs for similarly sized through-flow screens derived from equations shown in Figures 3-22 and 3-23 (Scenario C
freshwater and saltwater)
O&M Costs for Dual-Flow Screens
A vendor indicated that a significant benefit of dual-flow screens is reduced O&M costs compared to similarly sized through-flow
screens. O&M labor was reported to be as low as one tenth that for similarly sized through-flow traveling screens (Bracket Green
2002). Also, wash water flow is nearly cut in half and the spray water pressure requirement drops from 80 to 120 psi for through-flow
screens to about 30 psi. Examples were cited where dual-flow retrofits paid for themselves in a two to five year period. Using an
assumption of 90% reduction in routine O&M labor combined with an estimated reduction of 70% in wash water energy requirements
(based on combined reduction in flow and pressure), EPA calculated that the O&M costs for dual-flow screens would be equal
approximately 30% of the O&M costs for similarly sized through-flow screens with fine mesh overlays and fish handling and return
systems. O&M costs for dual-flow screens were calculated as 30% of the O&M costs for similarly sized through-flow screens derived
from the equations shown in Figures 3-26 and 3-27 (Scenario C freshwater and saltwater).
The O&M costs for adding fine mesh overlays to existing dual-flow screens (scenario A) is assumed to be the same as the net
difference between through-flow screens with fish handling with and without fine mesh overlays (net O&M costs for scenario A
versus scenario B). The majority of the net O&M costs are for deployment and removal of the fine mesh overlays.
3-53
-------
§ 316(b) Phase III - Technical Development Document Technology Cost Modules
Downtime for Dual-Flow Screens
As with through-flow screens dual-flow screens can be retrofitted with minimal generating unit downtime and can be scheduled to
occur during routine maintenance downtime. While there may be some additional deck demolition work, this effort should add no
more than one week to the two week estimate for multiple through-flow screens described above.
Technology Application
Capital Costs
The cost scenarios included here assume that the existing intake structure is designed for and includes through-flow (single entry,
single exit) traveling screens, either with or without fish handling and return. For those systems with different types of traveling
screens or fixed screens, the cost estimates derived here may also be applied. However, they should be viewed as a rough estimate for
a retrofit that would result in similar performance enhancement. The cost scenario applied to each facility is based on the compliance
action required and whether or not a fish handling and return system is in place. For those facilities with acceptable through-screen
velocities no modification, other than described above, is considered as necessary. For those with high through-screen velocities that
would result in unacceptable performance, costs for modifications/additions to the existing intake are developed through another cost
module. The costs for new screens to be installed in these new intake structures will be based on the design criteria of the new
structure.
Capital costs are applied based on waterbody type with costs for freshwater environments being applied to facilities in freshwater
rivers/streams, lakes/reservoirs and the Great Lakes, and costs for saltwater environments being applied to facilities in estuaries/tidal
rivers and oceans.
No distinction is being made here for freshwater environments with Zebra mussels. A vendor indicated that the mechanical movement
and spray action of the traveling screens tend to prevent mussel attachment on the screens.
For facilities with intake canals, an added capital cost component for the additional length of the fish return flume (where applicable)
are added. Where the canal length is not reported. The median canal length for other facilities with the same waterbody type are used.
O&M Costs
The compliance O&M costs are calculated as the net difference between the compliance scenario O&M costs and the baseline scenario
O&M costs. For compliance scenarios that start with traveling screens where the traveling screens are then rendered unnecessary
(e.g., relocating a shoreline intake to submerged offshore), the baseline scenario O&M costs presented here can be used to determine
the net O&M cost difference for those technologies.
2.2 New Larger Intake Structure for Decreasing Intake Velocities
The efficacy of traveling screens can be affected by both through-screen and approach velocities. Through-screen velocity affects: the
rate of debris accumulation; the potential for entrainment and impingement of swimming organisms; and the amount of injury that may
occur when organisms become impinged and a fish return system is in use. Performance, with respect to impingement and
entrainment, generally tends to deteriorate as intake velocities increase. For older intake structures, the primary function of the screen
was to ensure downstream cooling system components continued to function without becoming plugged with debris. The design often
did not take into consideration the effect of through-screen velocity on entrainment and impingement of aquatic organisms. For these
older structures, the standard design value for through-screen velocity was in the range of 2.0 to 2.5 feet per second (Gathright 2002).
These design velocities were based on the performance of coarse mesh traveling screens with respect to their ability to remove debris
as quickly as it collected on the screen surface. As demonstrated in the Facility Questionnaire database, actual velocities may be even
higher than standard design values. These higher velocities may result from cost-saving, site-specific designs or from an increased
withdrawal rate compared to the original design.
As described previously, solutions considered for reducing entrainment on traveling screens are to replace the coarse mesh screens
with finer mesh screens or to install fine mesh screen overlays. However, a potential problem with replacing the existing intake
screens with finer mesh screens is that a finer mesh will accumulate larger quantities of debris. Thus, retrofitting existing coarse mesh
screens with fine mesh may affect the ability of screens to remove debris quickly enough to function properly. Exacerbating this
potential problem is finer mesh may result in slightly higher through-screen velocities (Gathright 2002). If the debris problems
——
-------
5 316(b) Phase III - Technical Development Document Technology Cost Modules
associated with using fine mesh occur on a seasonal basis, then one possible solution (see section 2.1, above) is to use fine mesh
overlays during the period when sensitive aquatic organisms are present. This solution is predicated on the assumption that the period
of high debris loading does not substantially coincide with the period when sensitive aquatic organisms are most prevalent. When
such an approach is not feasible, some means of decreasing the intake velocities may be necessary.
The primary intake attributes that determine intake through-screen velocities are the flow volume, effective screen area, and percent
open area of the screen. The primary intake attributes that determine approach velocity are flow volume and cross-sectional area of the
intake. In instances where flow volume cannot be reduced, a reduction in intake velocities can only be obtained in two ways: for
through-screen velocities, an increased screen area and/or percent open area, or for approach velocity, an increased intake cross-
sectional area. In general, there are practical limits regarding screen materials and percent open area. These limits prevent significant
modification of this attribute to reduce through-screen velocities. Thus, an increase in the screen area and/or intake cross-sectional
area generally must be accomplished in order to reduce intake velocities. Passive screen technology (such as T-screens) relies on
lower screen velocities to improve performance with respect to impingement and entrainment and to reduce the rate of debris
accumulation. For technology options that rely on the continued use of traveling screens, a means of increasing the effective area of
the screens is warranted. EPA has researched this problem and has identified the following three approaches to increasing the screen
size:
Replace existing through flow (single entry-single exit) traveling screens with dual-flow (double entry-double exit) traveling
screens. Dual-flow screens can be placed in the same screen well as existing through flow screens. However, they are
oriented perpendicular to the orientation of the original through-flow screens and extend outward towards the front of the
intake. Installation may require some demolition of the existing intake deck. This solution may work where screen velocities
do not need to be reduced appreciably. This technology has a much improved performance with respect to debris carry over
and is often selected based on this attribute alone (Gathright 2002; see also section 2.1.4 above).
Replace the function of the existing intake screen wells with larger wells constructed in front of the existing intake and
hydraulically connected to the intake front opening. This approach retains the use and function of the existing intake pumps
and pump wells with little or no modification to the original structure. A concern with this approach (besides construction
costs) is whether the construction can be performed without significant downtime for the generating units.
Add a new intake structure adjacent to, or in close proximity to, the existing intake. The old intake remains functional, but
with the drive system for the existing pumps modified to reduce the flow rate. The new structure will include new pumps
sized to pump an additional flow. The new structure can be built without a significant shutdown of the existing intake.
Shutdown would only be required at the final construction step, where the pipes from new pumps are connected to the
existing piping and the pumps and/or pump drives for the existing pumps are modified or replaced. In this case, generating
downtime is minimized. However, the need for new pumps, and the modification to existing pumps that reduce their original
flow, entail significant additional costs.
Option 3 is a seemingly simple solution where the addition of new intake bays adjacent or in close proximity to the existing intake
would add to the total intake and screen cross-sectional area. A problem with this approach is that the current pumping capacity needs
to be distributed between the old and new intake bays. Utilizing the existing pump wells and pumps is desirable to help minimize
costs. However, where the existing pumps utilize single speed drives, the distribution of flow to the new intake bays would require
either an upstream hydraulic connection or a pump system modification. Where the existing intake has only one or two pump wells a
hydraulic connection with a new adjacent intake bay could be created through demolition of a sidewall downstream of the traveling
screen. While this approach is certainly feasible in certain instances, the limitations regarding intake configurations prevents EPA
from considering this a viable regulatory compliance alternative for all but a few existing systems. A more widely applicable solution
would be to reduce pump flow rate of the existing pumps either by modifying the pump drive to a multi-speed or variable speed drive
system, or by replacing the existing pumps with smaller ones. The new intake bays would be constructed with new smaller pumps that
produce lower flow rates. The combined flows of the new and older, modified pumps satisfies the existing intake flow requirement.
The costs of modifying existing pumps, plus the new pumps and pump wells, represents a substantial cost component.
Option 2 does not require modifications or additions to the existing pumping equipment. In this approach a new intake structure to
house more and/or larger screen wells would be constructed in front of the existing intake. The old and new intake structures could
then be hydraulically connected by closing off the ends with sheet pile walls or similar structures. EPA is not aware of any
installations that have performed this retrofit but it was proposed as an option in the Demonstration Study for the Salem Nuclear Plant
(PSE&G 2001). In that proposal the new screens were to be dual-flow screens but the driving factor for the new structure was a need
to increase the intake size.
3-55
-------
§ 316(b) Phase III - Technical Development Document Technology Cost Modules
EPA initially developed rough estimates of the comparative costs of applying option 2 versus option 3 (in the hypothetical case the
intake area was doubled in size). The results indicated that adding a new screen well structure in front of the existing intake was less
costly and therefore, this option was selected for consideration as a compliance technology option. This cost efficiency is primarily
due to the reuse of the existing intake in a more cost efficient manner in option 2. However, option 2 has one important drawback: it
may not be feasible where sufficient space is not available in front of the existing intake. To minimize construction downtime, EPA
assumes the new intake structure is placed far enough in front of the existing intake to allow the existing intake to continue functioning
until construction of the structure is completed. As a result of the need for sufficient space in front of the intake, the Agency has
applied the technology in appropriate circumstances in developing model facility costs.
Scenario Description
In this scenario, modeled on option 2 described above, a new reinforced concrete structure is designed for new through-flow or dual-
flow intake screens. This structure will be built directly in front of the existing intake. The structure will be built inside a temporary
sheet pile coffer dam. Upon completion of the concrete structure, the coffer dam will be removed. A permanent sheet pile wall will be
installed at both ends, connecting the rear of the new structure to the front of the old intake structure hydraulically. Such a
configuration has the advantage of providing for flow equalization between multiple new intake screens and multiple existing pumps.
The construction includes costs for site development for equipment access. Capital costs were developed for the same set of screen
widths (2 feet through 140 feet) and depths (10 feet through 100 feet) used in the traveling screen cost methodology. Best-fit, second-
order equations were used to estimated costs for each different screen well depth, using total screen width as the independent variable.
Construction duration is estimated to be nine months.
Capital Costs
Capital costs were derived for different well depths and total screen widths based on the following assumptions.
Design Assumptions - On-shore Activities
Clearing and grabbing: this is based on clearing with a dozer, and clearing light to medium brush to 4" diameter; clearing assumes
a 40 feet width for equipment maneuverability near the shore line and 500 feet accessibility lengthwise at $3,075/acre (RS Means
2001); surveying costs are estimated at $1,673/ acre (RS Means 2001), covering twice the access area.
Earth work costs: these include mobilization, excavation, and hauling, etc., along a water front width, with a 500-foot inland
length; backfill with structural sand and grave (backfill structural based on using a 200 HP bulldozer, 300-foot haul, sand and
gravel; unit earthwork cost is $3957 cu yd (RS Means 2001)
• Paving and surfacing, using concrete 10" thick; assuming a need for a 20-foot wide and 2- foot long equipment staging area at a
unit cost of $33.57 sq yd (RS Means 2001)
• Structural cost is calculated @ S1250/CY (RS Means 2001),assuming two wing walls 1.5 feet thick and 26 feet high, with 10 feet
above ground level, and 36 feet long with 16 feet onshore (these walls are for tying in the connecting sheet pile walls).
• Sheet piling, steel, no wales, 38 psf, left in place; these are assumed to have a width twice the width of the screens + 20 feet, with
onshore construction distance, and be 30 feet deep, at S24.5/ sq ft (RS Means 2001).
Design Assumptions - Offshore Components
• Structure width is 20% greater than total screen width and 20 ft front to back
Structural support consists of the equivalent of four 3-foot by 3-foot reinforced concrete columns at $935/ cu yd RS Means 2001)
plus two additional columns for each additional screen well (a 2-foot wide screen assumes an equivalent of 2-foot by 2 feet
columns)
• Overall structure height is equal to the well depth plus 10%
The elevated concrete deck is 1.5 ft thick at $48/ cu yd RS Means 2001)
Dredging mobilization is $9,925 if total screen width is less than 10 feet; is $25,890 if total screen width is 10 feet to 25 feet; and
is $52,500 if total screen width is greater than 25 ft RS Means 2001)
The cost of dredging in the offshore work area is $23/cu yd to a depth of 10 feet
The cost of the temporary coffer dam for the structure is $22.5/ sq ft RS Means 2001), with total length equal to the structure
perimeter times a factor of 1.5 and the height equal to 1.3 times well depth.
3-56
-------
§ 316(b) Phase III - Technical Development Document
Technology Cost Modules
Field Project Personnel Not Included in Unit Costs:
• Project Field Manager at $2,525 per week RS Means 2001)
• Project Field Superintendent at $2,375 per week RS Means 2001)
• Project Field Clerk at $440 per week RS Means 2001).
The above cost components were estimated and summed and the costs were expanded using the following cost factors.
Add-on and Indirect Costs:
Construction Management is 4.5% of direct costs
• Engineering and Architectural fees for new construction is 17% of direct costs
• Contingency is 10% of direct costs
• Overhead and profit is 15% of direct costs
• Permits are 2% of direct costs
Metalwork is 5% of direct costs
• Performance bond is 2.5% of direct costs
• Insurance is 1.5% of direct costs.
The total capital costs were then adjusted for inflation from 2001 dollars to July 2002 dollars using the ENR Construction Cost Index.
Exhibit 3-46 presents the total capital costs for various screen well depths and total screen widths. No distinction was made between
freshwater and brackish or saltwater environments. Figure 3-30 plots the data in Exhibit 3-46 and presents the best-fit cost equations.
The shape of these curves indicates a need for separate equations for structures with widths less than and greater than 10 feet. In
general, however, the Phase III compliance applications of this technology option included only new structures greater than 10 feet
wide.
Exhibit 3-46. Total Capital Costs for Adding New Larger Intake Screen Well Structure in Front of Existing Shoreline Intake
Well Depth
Width (Ft)
2
5
10
20
30
40
50
60
70
84
98
112
126
140
10 Ft
$ 291.480
$ 333.120
$ 916.080
$ 1.051.410
$ 1.270.020
$ 1.426.170
$ 1.582.320
$ 1.748.880
$ 1.925.850
$ 2.165.280
$ 2.425.530
$ 2.696.190
$ 2.977.260
$ 3,268,740
25 Ft
$ 562.140
$ 624.600
SI. 957.080
$2.175.690
S 2.487.990
$2.727.420
$2.977.260
$3.227.100
$3.487.350
$3.851.700
$4.236.870
$4.622.040
$5.028.030
$5,444,430
50 Ft
$ 1.176.330
$ 1.290.840
$ 4.361.790
$ 4.757.370
$ 5.236.230
$ 5.642.220
$ 6.058.620
$ 6.485.430
S 6.922.650
$ 7.536.840
$ 8.161.440
$ 8.994.240
$ 9.462.690
$ 10,139,340
75ft
$ 1.842.570
$ 1.998.720
$ 6.922.650
$ 7.484.790
$ 8.130.210
$ 8.713.170
$ 9.306.540
$ 9.899.910
$ 10.503.690
$ 11.367.720
$ 12.242.160
$ 13.127.010
$ 14.032.680
$ 14,948,760
100 Ft
$ 2.581.680
$ 2.800.290
$ 9.806.220
$ 10.545.330
$ 11.378.130
$ 12.138.060
$ 12.908.400
$ 13.689.150
$ 14.469.900
$ 15.583.770
$ 16.718.460
$ 17.863.560
$ 19.029.480
$ 20,205,810
O&M Costs
No separate O&M costs were derived for the structure itself since the majority of the O&M activities are covered in the O&M costs
for the traveling screens to be installed in the new structure.
3-57
-------
§ 316(b) Phase III - Technical Development Document Technology Cost Modules
Construction Downtime
As described above, this scenario is modeled after an option described in a 316(b) Demonstration Study for the Salem Nuclear Plant
(PSE&G 2001). In that scenario which applies to a very large nuclear facility, the existing intake continues to operate during the
construction of the offshore intake structure inside the sheet pile cofferdam. Upon completion of the offshore structure and removal of
the cofferdam, the final phase on the construction requires the shut down of the generating units for the placement of the sheet pile end
walls. The feasibility study states that units 1 and 2 would be required to shut down for one month each. Based on this estimate and
the size of the Salem facility (average daily flow of over 2 million gpm), EPA has concluded that a total construction downtime
estimate in the range of 6 to 8 weeks is reasonable. EPA did not select a single downtime for all facilities installing an offshore
structure. Instead, EPA applied a six- to eight-week downtime duration based on variations in project size, using design flow as a
measure of size. EPA assumed a total downtime of six weeks for facilities with intake flow volumes of less than 400,000 gpm; seven
weeks for facilities with intake flow volumes greater than 400,000 gpm but less than 800,000 gpm; and eight weeks for facilities with
intake flow volumes greater than 800,000 gpm.
Application
The input value for the cost equation is the screen well depth and the total screen width (see section 1.1 for a discussion of the
methodology for determining the screen well depth). The width of the new larger screen well intake structure was based on the design
flow, and an assumed through-screen velocity of 1.0 feet per second and a percent open area of 50%. The 50 % open area value used
is consistent with the percent open area of a fine mesh screen. The same well depth and width values are used for estimating the costs
of new screen equipment for the new structure. New screen equipment consisted of fine mesh dual flow (double entry single exit)
traveling screens with fish handling and return system.
3-58
-------
§ 316(b) Phase III - Technical Development Document Technology Cost Modules
REFERENCES
Doley, T. SAIC. Memorandum to the 316b Record regarding Development of Power Plant Intake Maintenance Personnel hourly
compensation rate. 2002.
Gathright, Trent. Bracket Green. Telephone contact with John Sunda (SAIC) regarding estimates for traveling Screen O&M.
September 10, 2002 & October 23, 2002.
Gathright, Trent. Bracket Green. Telephone contact with John Sunda (SAIC) regarding screen velocities and dual-flow screens.
August 21,2002.
Gathright, Trent. Bracket Green. Telephone contact with John Sunda (SAIC) regarding submission of questions and velocity limits.
July 26, 2002
Gathright, Trent. Bracket Green. Answers to questions about traveling screens, submitted by email September 11, 2002.
Gathright, Trent. Bracket Green. Telephone contact with John Sunda (SAIC) regarding capital and O&M costs for dual-flow screens.
November 21, 2002.
Petrovs, Henry. US Filter (US). Telephone contact with John Sunda (SAIC) regarding answers to questions about traveling screens.
July 30,2002
Bureau of Labor Statistics (BLS). Occupational Outlook Handbook. 2002-2003 Edition. Page 531
R.S. Means. 2001. R.S. Means Cost Works Database, 2001.
PS&G. Permit Demonstration Supporting Documentation. Section describing Feasibility Study of Intake Technology Modification.
2001.
5-59
-------
Exhibit 3-25. Total Capital Costs for Scenario A - Adding Fine Mesh Without Fish Handling Freshwater Environments
r
re
a
1
C7
Total Widtt
Well Depth
1ff-0
25-0
SOX)
75'-0
100'-0
2
One2ft
$7.989
$11.162
$17.707
$24.262
$32,997
5
OneSn
$9.079
$12.932
$20.977
$29.302
$37.627
10
One 10ft
$11.853
$17.952
$30.295
$40.467
$50.630
20
Two 10 ft
$23.706
$35.905
$60.590
$80.935
$101.260
30
Three 10 ft
$35.559
$53.857
$90.885
$121.402
$151.890
40
Four 10 ft
$47.412
$71.810
$121.180
$161.870
$202.520
50
Five 10 ft
$59.265
$89.762
$151.475
$202.337
$253,150
60
Six 10 ft
$71.117
$107.714
$181.769
$242.804
$303,779
70
Five 14 ft
$81.865
$134.162
$206.825
$273.987
$338.450
84
Six 14 ft
$98.237
$160.994
$248.189
$328.784
$406.139
98
Seven 14 ft
$114.610
$187.827
$289.554
$383.582
$473.829
112
EiahtUft
$143.806
$242.278
$383.198
$515.318
$643.118
126
Nine 14 ft
$147.356
$241.492
$372.284
$493.177
$609,209
140
Ten 14 ft
$163.729
$268.324
$413.649
$547.974
$676.899
Exhibit 3-26. Total Capital Costs for Scenario A - Adding Fine Mesh Without Fish Handling Saltwater Environments
Total Widtl
Well Depth
10X)
25'-0
50'-0
75-0
IOff-0
2
One2ft
$14.909
$20.022
$31.057
$42.112
$57.527
5
OneSft
$17.089
$23.562
$37.597
$52.192
$66,787
10
One 10ft
$22.103
$32.452
$54.055
$71.317
$88.560
20
Two 10 ft
$44.206
$64.905
$108.110
$142.635
$177,120
30
Three 10 ft
$66.309
$97.357
$162 165
$213.952
$265,680
40
Four 10 ft
$88.412
$129.810
$216220
$285.270
$354.240
50
Five 10 ft
$110.515
$162.262
$270.275
$356.587
$442,800
60
Six 10 ft
$132.617
$194.714
$324.329
$427.904
$531,359
70
Five 14 ft
$155.715
$251.062
$380.975
$499.887
$613,400
84
Six 14 ft
$186.857
$301.274
$457.169
$599.864
$736,079
98
Seven 14 ft
$218.000
$351.487
$533.364
$699.842
$858.759
112
EkJht14ft
$249.143
$401.699
$609.559
$799.819
$981,439
126
Nine 14 ft
$280.286
$451.912
$685.754
$899.797
$1,104,119
140
Ten 14 ft
$311,429
$502.124
$761.949
$999.774
$1,226.799
-------
Exhibit 3-27. Total Capital Costs for Scenario B - Adding Fish Handling and Return Freshwater Environments
Total Width
WellDeothi
10'-0
25'-0
50'-0
75'-0
IOff-0
2
One 2 ft
$105.872
$132.772
$185.172
$237.672
$311.972
5
OneSft
$126.362
$161.562
$230.462
$302.162
$373,862
10
One 10ft
$164.443
$217.443
$320.543
$401.943
$483,243
20
Two 10 ft
$301.224
$407224
$613.424
$776.224
$938,824
30
Three 10 ft
$438.105
$597.105
$906.405
$1.150.605
$1.394,505
40
Four 10 ft
$572.141
$784.141
$1.196.541
$1.522.141
$1,847,341
50
Five 10 ft
$703.131
$968.131
$1.483.631
$1.890.631
$2,297,131
60
Six 10 ft
$837.367
$1.155.367
$1.773.967
$2 262 367
$2,750,167
70
Five 14 ft
$967.658
$1.460.658
$2.095.658
$2.675.658
$3,228.658
84
Six 14 ft
$1.151.993
$1.743.593
$2.505.593
$3.201.593
$3,865,193
98
Seven 14 ft
$1.333,484
$2.023.684
$2.912.684
$3.724,684
$4,498,884
112
Eiaht 14 ft
$1.518.320
$2.307.120
$3.323.120
$4.251.120
$5,135,920
126
Nine 14 ft
$1.700.210
$2.587.610
$3.730.610
$4,774.610
$5,770.010
140
Ten 14 ft
$1.882.401
$2.868.401
$4.138.401
$5.298.401
$6,404,401
o-
/—*
cr
•o
I
5
a
ra
o
-o
Exhibit 3-28. Total Capital Costs for Scenario B - Adding Fish Handling and Return Saltwater Environments
a
o
re
Total Width
Well Death
1CT-0
25'-0
Sff-O
75M)
IOff-0
2
One2ft
$175.072
$221.372
$318.672
$416.172
$557,272
5
OneSft
$206.462
$267.862
$396.662
$531.062
$665,462
10
One 10 ft
$266.943
$362.443
$558.143
$710.443
$862,543
20
Two 10 ft
$506224
$697224
$1.088.624
$1.393.224
$1,697.424
30
Three 10 ft
$745,605
$1 032 105
$1.619.205
$2.076.105
$2,532,405
40
Four 10 ft
$982.141
$1.364.141
$2 146 941
$2.756.141
$3.364,541
50
Five 10 ft
$1.215.631
$1.693.131
$2.671.631
$3.433.131
$4,193,631
60
Six 10 ft
$1.452,367
$2.025,367
$3.199.567
$4.113.367
$5,025,967
70
Five 14 ft
$1.706.158
$2.629.658
$3.837.158
$4.934.658
$5,978,158
84
Six 14 ft
$2.038.193
$3.146.393
$4.595.393
$5.912.393
$7,164,593
98
Seven 14ft
$2.367.384
$3.660.284
$5.350.784
$6.887.284
$8.348,184
112
Eiaht 14 ft
$2.699.920
$4.177.520
$6.109.520
$7.865.520
$9,535,120
126
Nine 14 ft
$3.029.510
$4.691.810
$6.865.310
$8.840.810
$10.719,110
140
Ten 14 ft
$3.359.401
$5.206.401
$7.621.401
$9.816.401
$11,903,401
R
-------
§ 316(b) Phase HI - Technical Development Document
Technology Cost Modules
E
e
2
e
js
1
r
23
73
e
E
2
u
•g
«
u
1/3
1.
S
I
'o.
U
e
JO
X
8
£
CM
s
V»
3
3
3
3
3
S
n
i
T3
ot
1
I.
a
s
v
u
CA
.o
U
"«
«^
'S.
eg
U
3
3
3
3
3
3-62
-------
Exhibit 3-38. Baseline O&M Costs for Traveling Screens Without Fish Handling Freshwater Environments
un
OJ
-o
Total Width
Well Depth (Ft)
10
25
50
75
100
2
One2ft
$5.419
$6.433
$7.591
$8.786
$10,597
5
OneSft
$8.103
$9.499
$11.483
$13.687
$15.833
10
One 10ft
$10.223
$11.880
$14.741
$16.865
$18,985
20
Two 10 ft
$20.445
$23.760
$29482
$33.729
$37,970
30
Three 10f
$30.668
$35.640
$44.223
$50.594
$56,956
40
Four 10 ft
$40.891
$47.520
$58.964
$67.458
$75,941
50
Five 10 ft
$51.113
$59.400
$73.705
$84.323
$94,926
60
Six 10ft
$61.336
$71.280
$88446
$101.187
$113,911
70
Five 14 ft
$62.805
$75.667
$89781
$101.216
$112.279
84
Six 14 ft
$75.367
$90.800
$107.737
$121.459
$134,735
98
Seven 14 ft
$87.928
$105.933
$125.693
$141.702
$157,191
112
Ekiht14ft
$100.489
$121.067
$143.650
$161.946
$179,647
126
Nine 14 ft
$113.050
$136.200
$161.606
$182.189
$202,103
140
Ten 14 ft
$125.611
$151.333
$179.562
$202.432
$224,558
C7
I
o
-o
n
Exhibit 3-39. Baseline O&M Costs for Traveling Screens Without Fish Handling Saltwater Environments
n
Total Width
Well Deoth (Ftt
10
25
50
75
100
2
One 2 ft
$6.400
$7.577
$9.389
$11.238
$14.357
5
OneSft
$9.247
$10.971
$13.772
$16.957
$20,084
10
OnelOtt
$11.694
$13.842
$18.175
$21.116
$24.054
20
Two 10 ft
$23.388
$27.684
$36.349
$42.231
$48.107
30
Three 10 fl
$35.083
$41.526
$54.524
$63.347
$72.161
40
Four 10 ft
$46.777
$55.368
$72.698
$84.462
$96.215
50
Five 10 ft
$58.471
$69.210
$90.873
$105.578
$120,269
60
Six 10 ft
$70.165
$83.052
$109.047
$126.693
$144.322
70
Five 14 ft
$73.433
$92.834
$113,498
$129.829
$144,979
84
Six 14 ft
$88.120
$111.401
$136.186
$155.794
$173,975
98
Seven 14 f
$102.806
$129.968
$158.884
$181.760
$202.971
112
Eioht14ft
$117.493
$148.535
$181.582
$207.726
$231,967
126
Nine 14 ft
$132.179
$167.101
$204.279
$233.691
$260.963
140
Ten 14 ft
$146.866
$185.668
$226.977
$259.657
$289.958
s-
i
-------
en
OJ
Exhibit 3-40. Baseline & Scenario B Compliance O&M Totals for Traveling Screens With Fish Handling Freshwater Environments
Total Width
Well Depth (Ft)
10
25
50
75
100
2
One2ft
$15.391
$18.333
$22295
$26.441
$31,712
5
OneSft
$24.551
$28.378
$34.696
$41.449
$47,927
10
One 10 ft
$35.231
$40.504
$49.853
$57.499
$65,126
20
Two 10 ft
$70.462
$81.009
$99.707
$114.998
$130,251
30
Three 10 f
$105.693
$121.513
$149.560
$172.498
$195,377
40
Four 10 ft
$140.924
$162.018
$199.413
$229.997
$260,503
50
Five 10 ft
$176.155
$202.522
$249.267
$287.496
$325,628
60
Six 10 ft
$211.386
$243.027
$299.120
$344.995
$390,754
70
Five 14 ft
$230.185
$271.971
$328.293
$376.302
$424,831
84
Six 14 ft
$276.221
$326.365
$393.952
$451.563
$509,797
98
Seven 14 ft
$322.258
$380.759
$459.611
$526.823
$594,763
112
E'raht 14 ft
$368.295
$435.154
$525.269
$602.084
$679,729
126
Nine 14 ft
$414.332
$489.548
$590.928
$677.344
$764,695
140
Ten 14 ft
$460.369
$543.942
$656.587
$752.605
$849,661
ra
B
I
-§
Exhibit 3-41. Baseline & Scenario B Compliance O&M Totals for Traveling Screens With Fish Handling Saltwater Environments
C7
o
Total Width
Well Depth (Ft)
10
25
50
75
100
2
One2ft
$19.543
$23.649
$30.305
$37.151
$46,430
5
One5ft
$29.357
$34.756
$44.668
$55.183
$65,423
10
One 10 ft
$41.381
$49.204
$64.109
$76.009
$87,884
20
Two 10 ft
$82.762
$98.409
$128.219
$152.018
$175,767
30
Three 10 fl
$124.143
$147.613
$192.328
$228.028
$263,651
40
Four 10 ft
$165.524
$196.818
$256.437
$304.037
$351,535
50
Five 10 ft
$206.905
$246.022
$320.547
$380.046
$439,418
60
Six 10 ft
$248.286
$295227
$384.656
$456.055
$527,302
70
Five 14 ft
$274.495
$342.111
$432.783
$511.842
$589,801
84
Six 14 ft
$329.393
$410.533
$519.340
$614.211
$707,761
98
Seven 14 ft
$384.292
$478.955
$605.897
$716.579
$825,721
112
Ekiht14ft
$439.191
$547.378
$692.453
$818.948
$943,681
126
Nine 14 ft
$494.090
$615.800
$779.010
$921.316
$1,061,641
140
Ten 14 ft
$548.989
$684.222
$865.567
$1.023.685
$1,179,601
-------
§ 316(b) Phase III - Technical Development Document
Technology Cost Modules
S
s
2
w
_c
T3
«
en
1
H
-------
§ 316(b) Phase IH - Technical Development Document
Technology Cost Modules
a>
v
I
4)
8
.2
"a
0>
£
•a
o
U
n,
U
<
G>
*c
es
I
00
4>
3-66
-------
§ 316(b) Phase III • Technical Development Document
Technology Cost Modules
«
|
"«
VI
i
01
ON
y,
8
i
I
e
S
•o
•e
c
U
"«
•44
'a.
U
4;
o
u
C/}
o\
TH
I
hi
M
8
3-67
-------
on
u
Figure 3-20. Scenario B - Capital Cost -Add Traveling Screen with Fish Handling and Return - Freshwater
8
n
H
7000000
6000000
5000000
4000000
3000000
2000000
1000000
20
40
BO
80
100
120
140
160
10 Ft Well Depth • 25 Ft Well Depth 50 Ft Well Depth 75 Ft Well Depth * 100 Ft Well Depth
D_
C7
o
i
o
!_0
i
oo
-------
S 316(b) Phase HI - Technical Development Document
Technology Cost Modules
I
5
I
e
I
CD
a
en
£
£
B
t/3
W)
a
H
•B
3
O
U
"e3
•«^
'5,
«
U
09
o
•c
U
cc
I
on
8
-------
Figure 3-22. Scenario C - Capital Cost -Add Fine Mesh Traveling Screen With and Fish Handling and Return - Saltwater
an
co
14000000
12000000
10000000
8000000
6000000
4000000
2000000
y = 43.420JC2 + 85779X + 223119
0.9995
8
• 5?
20
40
GO
80
100
120
140
160
10 Ft Well Depth • 25 Ft Well Depth 50 Ft Well Depth 75 Ft Well Depth * 100 Ft Well Depth
g
o
55
i:
-------
S 316(b) Phase III - Technical Development Document
Technology Cost Modules
a
13
C
C3
8
.0
2
u
WD
e
1
H
1
a>
en
O
U
S3.
es
U
OJ
a
8
£
3-77
-------
Figure 3-24. Baseline O&M Costs for Traveling Screens Without Fish Handling - Freshwater Environments
on
oo
250000 -,
200000 -•
*
o
U
a
=
•i :>~' '. • ,'.-. .,.J. i,£ .'• , ^-ijm**+1^9.2*
/*-.v. ' .•:-••'•' •'•"' > '' >^$£.'-~#- - *$?*»*
"•'• v-r'V-;' ;-• -'A''* '^€1% "-': -
: :..:.. %->,"....^.i^ ;...•. ;. .-.i ..'.AA.-^.-.A.-J^^ »./»l.-»>j. • fcl»Ai^g«'<«.i;.-. -<'«»..>%,., i... .^•aB8i!r!i»;/-;.««*»..iitaaaA .
' ^ •:- If- •: ^^H:^'^'-™. ' >?"vCTip^^- .y^v^
* ..-^:^:
'' y-tf&&*'*^ ^ •
. .-/ •,/i:^^SF^ tf- ;«^-MW.
50000
l1i+S7C2i
^r
.• .'• > trwyw.' <.-v''-'--.^':^.»|vJv'j£
=:"W^^;.:'il8|ra
mrmn -'. •'..',, M*,*^*$**.**«to.;..*#&>^ tl^, ,:^f y»ffifti*gW
IUUJJU - ——i aiii..^.-^.^]!) «/y»Mm*f3:ll5f"'" ll»l i*Wl^«"«iKi«BJ!]|*»»,*^t
> ^ - ^'w^jm^'l^^t'^rewSKESsSffis
—^if-ii--fA^Lti^^mM£sitt^tH^-^irA»Skiim&fi^imiiS&
• »---,'-..•.-,' ^';--s-j^«^s. ?y'
:'•-'., 4* SfeE?-,*;]
-. "^
-'* * ' > ,'n
•S^?»V 'S
v^
^ij-^krg
*$»•'
. • - s CP*,OWs
•>•: /, « ^fl- "'
>*" -i*1 -1- •„ *
"K, *
20
40
60 80 100
Total Screen Width (Ft)
120
140
* 10 ft Well depth • 25 Ft Well Depth 50 Ft Well Depth 75 Ft Well Depth * 100 Ft Well Depth
160
a
f
g
5"
!§
-------
an
OJ
Figure 3-25. Baseline O&M Costs for Traveling Screens Without Fish Handling - Saltwater Environments
350000
300000
250000
*
U 200000
1 150000
100000 - -
50000 •-,
" " * j<'1k*"~4"Xi"' »"* *'" "^'••"''"
1»,. - Jf.»^:|jk|^^5'.'y^'f-'?''-^**'
^ i ',
a
n
3
I
BO 80 100
Total Screen Width (Ft)
+ 10 ft Well depth • 25 Ft Well Depth 50 Ft Well Depth 75 Ft Well Depth * 100 Ft Well Depth
9-
-------
an
OJ
Figure 3-26. Scenarios A & C Compliance O&M Total Costs for Traveling Screens With Fish Handling Freshwater Environments
1200000
1000000
*
5
800000
600000 •
400000
200000-
20
40
60 80 100
Total Screen Width (F1)
120
140
410 ft Well depth • 25 Ft Well Depth 50 Ft Well Depth 75 Ft Well Depth * 100 Ft Well Depth
re
I
I
C7
re
e
re
o
-------
an
OJ
Figure 3-27. Scenarios A & C Compliance O&M Total Costs for Traveling Screens With Fish Handling - Saltwater Environments
a
re
1600000
1400000
1200000
1000000
o
"w
I
800000
BOOOOO -
400000
200000
s "'.2w'.'.,., , ", .'"i>,...!..;.'• '«i;
60 80 100
Total Screen Width (Ft)
160
I
£
* 10 ft Well depth • 25 Ft Well Depth 50 Ft Well Depth 75 Ft Well Depth * 100 Ft Well Depth
-------
Figure 3-28. Baseline & Scenarios B Compliance O&M Total Costs for Traveling Screens With Fish Handling
Freshwater Environments
900000
800000
100000
= -Q.B662X2 +6050.4* + 15301
T2541
BO 80 100
Total Screen Width (Ft)
* 10 ft Well depth • 25 Ft Well Depth 50 Ft Well Depth 75 Ft Well Depth * 100 Ft Well Depth
3
B
-§
a
S
S"
-------
Figure 3-29. Baseline & Scenarios B Compliance O&M Total Costs for Traveling Screens With Fish Handling
Saltwater Environments
1400000 -i —
1200000
1000000
ta
o
19
800000
600000
400000
200000
40
60 80 100
Total Screen Width (Ft)
120
140
ft Well depth • 25 Ft Well Depth 50 Ft Well Depth 75 Ft Well Depth * 100 Ft Well Depth
160
a
s
o
3"
o*
S.
g
ll
-------
an
to
Figure 3-30. Total Capital Costs of New Larger Intake Structure
$25,000,000
£ $20
o
D
8
i
a
10 100
Total Effective Traveling Screen Width (Ft)
1000
I
C7
ra
1
o
TJ
O
o
r»
c
n
* well depth 10ft
® well depth 75 ft
+ small screens well depth 25
small screens well depth 100 ft
•well depth 25 ft
* well depth 100 ft
• small screens well depth 50 ft
A well depth 50 ft
• small screens well depth 10 ft
- small screens well depth 75
i?
a.
c
-------
S 316(b) Phase III - Technical Development Document Technology Cost Modules
3.0 EXISTING SUBMERGED OFFSHORE INTAKES - ADD VELOCITY CAPS
Velocity caps are applicable to submerged offshore intakes. Adding velocity caps to facilities with existing or new submerged
offshore intakes can provide appreciable impingement reduction. Therefore, this module may be most applicable when the compliance
option only requires impingement controls and the intake requires upgrading. However depending on site-specific conditions, velocity
caps could conceivably be used in conjunction with onshore screening systems tailored for entrainment reduction.
Research on velocity cap vendors identified only one vendor, which is located in Canada. (A possible reason for this scarcity in
vendors is that many velocity caps are designed and fabricated on a site-specific basis, often called "intake cribs".) This vendor
manufactures a velocity cap called the "Invisihead," and was contacted for cost information (Elarbash 2002a and 2002b). The
Invisihead is designed with a final entrance velocity of 0.3 feet per second and has a curved cross-section that gradually increases the
velocity as water is drawn farther into the head. The manufacturer states the gradual increase in velocity though the velocity cap
minimizes entrainment of sediment and suspended matter and minimizes inlet pressure losses (Elmosa 2002). All costs presented
below are in July 2002 dollars.
3.1 Capital Costs
The vendor provided information for estimating retrofit costs for velocity caps manufactured both from carbon steel and from stainless
steel. Stainless steel construction is recommended for saltwater conditions to minimize corrosion. Carbon steel is recommended for
freshwater systems. Due to the rather large opening, Invisihead performance is not affected by the attachment of Zebra mussels, so no
special materials of construction are required where Zebra mussels are present.
Installation costs include the cost for a support vessel and divers to cut, weld and/or bolt the fitting flange for the velocity cap; make
any needed minor reinforcements of the existing intake; and install the cap itself. Installation was said to take between two and seven
days, depending on the size and number of heads in addition to the retrofit steps listed above. Costs also include mobilization and
demobilization of the installation personnel, barge, and crane. The vendor indicated these costs included engineering and contractor
overhead and profit, but did not provide break-outs or percentages for these cost components. EPA has concluded that the installation
costs for adding a velocity cap on a new intake (relocated offshore) and on an existing offshore intake should be similar because most
of the costs involve similar personnel and equipment. (See the "Application" section below for a discussion of new/existing
submerged offshore intake cost components.)
Exhibit 3-47 presents the component (material, installation, and mobilization/demobilization) and total capital costs for stainless steel
and carbon steel velocity caps provided by the vendor (Elarbash 2002a and 2002b). Data are presented for flows ranging from 5,000
gpm to 350,000 gpm. Figure 3-31 presents a plot of these data. The upper end of this flow range covers existing submerged pipes up
to 15 feet in diameter at pipe velocities of approximately 5 feet per second. Second-order polynomial equations provided the best fit to
the data and were used to produce cost curves. These cost curves serve as the basis for estimating capital costs for installing velocity
caps on existing or new intakes submerged offshore at Phase III facilities. When applying these cost curves, if the intake flow exceeds
350,000 gpm plus 10% (385,000 gpm), the flow is divided into equal increments and these lower flows costed. The costs for these
individual incremental flows are summed to estimate total capital cost. In these cases, costs are assumed to be applied to multiple
intake pipes. If the intake flow is less than 5,000 gpm, the capital cost for 5,000 gpm will be used rather than extrapolating beyond the
bottom end of the cost curve.
3.2 O&M Costs
For velocity caps, O&M costs generally include routine inspection and cleaning of the intake head. As noted above, bibfouling does
not affect velocity cap performance, so rigorous cleaning is not necessary. The vendor stated that their equipment is relatively
maintenance free. However, O&M costs based on an annual inspection and cleaning of offshore intakes by divers were cited by
facilities with existing offshore intakes, including some with velocity caps and especially those with bar racks at the intake. Therefore,
estimated O&M costs are presented for an annual inspection and cleaning by divers because EPA believes this is common practice for
submerged offshore intakes of all types.
Exhibit 3-48 presents the component and total O&M costs for the diver inspection and cleaning, for one to four days (Paroby 1999).
In general, O&M costs are based on less than one day per head for inspection and cleaning of smaller intake heads and one day per
head for the largest intake head. There is a minimum of one day for each inspection event. Inspection and cleaning events are
assumed to occur once per year. Figure 3-32 presents the plot of the O&M costs by flow. A second-order polynomial equation
provided the best fit to this data and serves as the basis for estimating the O&M costs.
- _
-------
§ 316(b) Phase III - Technical Development Document Technology Cost Modules
Figure 3-32 also shows data for two facilities that reported actual O&M costs based on diver inspection and cleaning of submerged
offshore intakes. While these two facilities use different intake technologies (passive screens for the smaller flow and bar rack type
intakes for the larger flow), the inspection and cleaning effort should be similar for all three types of intakes. For both facilities, the
actual reported O&M costs were less than the costs estimated using the cost curves, indicating that the estimated O&M costs should be
considered as high-side estimates.
3.3 Application
As Retrofit of Existing Offshore Intake
Adding velocity caps to facilities with existing offshore intakes will provide impingement reduction only. For facilities withdrawing
from saltwater/brackish waters (ocean and estuarine/tidal rivers), the capital cost curve for stainless steel caps will be applied. For the
remaining facilities withdrawing freshwater (freshwater rivers/streams, reservoirs/lakes, Great Lakes), the capital cost curve for carbon
steel caps will be applied. The same O&M cost curve will be used for both freshwater and saltwater systems. It is assumed that the
existing intake is in a location that will provide sufficient clearance and is away from damaging wave action.
As Component of Relocating Existing Shoreline Intake to Submerged Offshore
These same velocity cap retrofit costs can be incorporated into retrofits where an existing shoreline intake is relocated to submerged
offshore. In this application, some of the same equipment and personnel used in velocity cap installation may also be used to install
other intake components, such as the pipe. Therefore, the mobilization/demobilization component could be reduced if these tasks are
determined to occur close together in time. However, a high-side costing approach would be to cost each step separately, using the
same velocity cap costs for both new and existing offshore intake pipes. In this case, the installation costs for velocity caps at existing
offshore intakes (which include costs for cutting, and welding and/or bolting the velocity cap in place) are assumed to also cover costs
of installing connection flanges at new offshore intakes. Costs for other components of relocating existing shoreline intakes to
submerged offshore are developed as a separate cost module associated with passive screens. The compliance cost estimates did not
include this scenario.
REFERENCES
Elarbash, M. Elmosa Canada, email correspondence with John Sunda, SAIC concerning cost and technical data for Invisihead
velocity caps. August 9,2002a
Elarbash, M. Elmosa Canada, email correspondence with John Sunda, SAIC concerning cost and technical data for Invisihead
velocity caps. August 19,2002b
Elmosa. Website at http://www.imasar.com/elmosa/invisiheaddetails.htm accessed May 9, 2002.
Paroby, Rich. Personal communication between Rich Paroby, District Sales Manager, Water Process Group and Deborah Nagle,
USEPA E-mail dated May 12, 1999.
3-80
-------
Exhibit 3-47. Velocity Cap Retrofit Capital and O&M Costs (2002 $)
an
OJ
Velocity Cap Retrofit Capital and O&M Costs (2002 $)
Flow (pnirO
Water Tvoe
5.000
10.000
25.000
50.000
100.000
200.000
350,000
# Heads
All
1
1
1
2
2
4
4
Material
Costs -
Stainless
Steel /Head
Saltwater
$30.000
$30.000
$40.000
$35.000
$80.000
$80.000
$106,000
Material
Costs -
Stainless
Steel Total
Saltwater
$30.000
$30.000
$40.000
$70.000
$160.000
$320.000
$424,000
Material
Costs -
Carbon
Steel /Head
Freshwater
$22.500
$22.500
$30.000
$26.250
$60.000
$60.000
$79,500
Material
Costs -
Carbon
Steel Total
Freshwater
$22.500
$22.500
$30.000
$52.500
$120.000
$240.000
$318,000
Installation
All
$25.000
$30.000
$35,000
$49.000
$49,000
$98,000
$98,000
Mobilization/
Demobilization
All
$10.000
$15.000
$15.000
$25.000
$25.000
$30.000
$30,000
Total
Capital
Costs -
Stainless
Steel
Saltwater
$65.000
$75.000
$90.000
$144.000
$234.000
$448.000
$552,000
Total
Capital
Costs -
Carbon
Steel
Freshwater
$57.500
$67.500
$80.000
$126.500
$194.000
$368.000
$446,000
Total
O&M
All
$5.260
$5.260
$5,260
$7,250
$7.250
$11,230
$11,230
!
-
Note: Vendor indicated installation took 2 to 7 days
Note: Installation includes retrofit activities such as cutting pipe and & attaching connection flange on intake inlet pipe.
-------
Exhibit 3-48. Installation and Maintenance Diver Team Costs
an
oo
Installation and Maintenance Diver Team Costs
g
Item
Duration
Cost Year
Supervisor
Tender
Diver
Air Packs
Boat
Mob/Demob
Total
Daily
Cost*
$575
$200
$375
$100
$200
One Time
Cost*
$3,000
Total
One Day
1999
$575
$200
$750
$100
$200
$3,000
$4.825
Adjusted Total
One Dav
2002
$627
$218
$818
$109
$218
$3,270
$5.260
Two Day
2002
$1.254
$436
$1.635
$218
$436
$3,270
$7.250
Three Day
2002
$1.880
$654
$2.453
$327
$654
$3,270
$9.240
Four Day
2002
$2.507
$872
$3.270
$436
$872
$3,270
$11.230
I
I
5"
C7
o
*Source: Paroby 1999 (cost adjusted to 2002 dollars).
U,
fe
I
I
I
-------
Figure 3-31. Velocity Cap Capital Costs 2002 Dollars
$600,000
$550,000
$500,000
$450,000
$400,000
8 $350,000
^ $300,000
<3 $250,000
$200,000
$150,000
$100,000
$50,000
$0
Velocity Cap Capital Costs
2002 Dollars
y = -3E-06x + 2.4809X + 38934
R2 = 0.9917
' = -2E-06x + 2.0196X + 38053
R2 = 0.9913
50,000
100,000
150,000
200,000
Flow (gpm)
250,000
300,000
350,000
400,000
Stainless Steel
A Carbon Steel
a
3
i
i?
C7
5
n
o
•
s1
I
-------
Figure 3-32. Velocity Cap O&M Cost 2002 Dollars
an
OJ
,000
$12,000
$10,000
= $8,000
-
O
$6,000
$4,000
Velocity Cap O&M Cost
2002 Dollars
= -7E-08x^ + 0.0424X + 4731.4
R2 = 0.0460
50,000 100,000 150,000 200,000 250,000
Flow (gpm)
300,000 350,000
400,000
* Velociity Cap O&M • Actual Diver Based O&M
O_
C7
-§
re
i
i
o
I
I
I
-------
§ 316(b) Phase III - Technical Development Document
Technology Cost Modules
4.0
FISH BARRIER NETS
Fish barrier net can be used where improvements to impingement performance is needed. Because barrier nets can be installed
independently of intake structures, there is no need to include any costs for modifications to the existing intake or technology
employed. Costs are assumed to be the same for both new and existing facilities. Barrier nets can be installed while the facility is
operating. Thus, there is no need to coordinate barrier net installation with generating unit downtime.
Fish Barrier Net Questionnaire
EPA identified seven facilities from its database that employed fish barrier nets and sent them a brief questionnaire requesting barrier
net design and cost data (EPA 2002). The following four facilities received but did not submit a response:
Bethlehem Steel - Sparrows Point
Consumers Energy Co. - J.R. Whiting Plant
Exelon Corp. (formerly Commonwealth Edison) - LaSalle County Station
Southern Energy - Bowline Generating Station
The following three facilities submitted completed questionnaires:
Entergy Arkansas, Inc. - Arkansas Nuclear One
Potomac Electric Power Co. - Chalk Point
Minnesota Power - Laskin Energy Center
Net Velocity
An important design criterion for determining the size offish barrier nets is the velocity of the water as it passes through the net. Net
velocity (which is similar to the approach velocity for a traveling screen) determines how quickly debris will collect on the nets. Net
velocity also determines the force exerted on the net, especially if it becomes clogged with debris. For facilities that supplied technical
data, Exhibit 3-49 presents the design intake flow (estimated by EPA) and facility data reported in the Barrier Net Questionnaire.
These data include net size, average daily intake flow, and calculated net velocities based on average and design flows. Note that the
Chalk Point net specifications used for purchasing the net, indicated a net width of 27 ft (Langley 2002) while the Net Questionnaire
reported a net width of 30 ft. A net width of 27 ft was used for estimating net velocities and unit net costs. The two larger facilities
have similar design net velocity values that, based on design flow, is equal to 0.06 feet per second. This values are roughly an order of
magnitude lower than compliance velocities used for rigid screens in the Phase I Rule as well as design velocities recommended for
passive screens. There are two reasons for this difference. One difference is rigid screens can withstand greater pressure differentials
because they are firmly held in place. The second is rigid screens can afford to collect debris at a more rapid rate because they have an
active means for removing debris collected on the surface.
Based on the data presented in Exhibit 3-49, EPA has selected a net velocity of 0.06 feet per second (using the design flow) as the
basis for developing compliance costs for fish barrier nets. Nets tested at a high velocity (> 1.3 feet per second) at a power plant in
Monroe Michigan clogged and collapsed. Velocities higher than 0.06 feet per second may be acceptable at locations where the debris
loading is low or where additional measures are taken to remove debris. While tidal locations can have significant water velocities,
the periodic reversal of flow direction can help dislodge some of the debris that collects on the nets. The technology scenario
described below, for tidal waterbodies, is designed to accommodate significant debris loading through the use of dual nets and
frequent replacement with cleaned nets.
Exhibit 3-49. Net Velocity Data Derived from Barrier Net Questionnaire Data
Facility Owner
PEPCO
Enterav
Minn. Power
Facility Name
Chalk Point
Arkansas Nuclear One
Laskin Energy Center
Death*
Ft
27
20
16
Lenath*
Ft
1000
1500
600
Area
soft
27.000
30.000
9.600
EPA Design
Flow
dom
762,500
805.600
101,900
Net Velocity
at Design
Flow
fDS
0.06
0.06
0,02
Average
Daily
Flow*
dom
500,000
593.750
94.250
Net Velocity
at Daily
Flow
fDS
0.04
0.04
0.02
* Source: 2002 EPA Fish Barrier Net Questionnaire and Langley 2002
3-85
-------
§ 316(b) Phase III - Technical Development Document
Technology Cost Modules
Mesh Size
Mesh size determines the fish species and juvenile stages that will be excluded by the net. While smaller mesh size has the ability to
exclude more organisms, it will plug more quickly with debris. The Chalk Point facility tried to use 0.5-inch stretch mesh netting and
found that too much debris collected on the netting; it instead uses 0.75 inch stretch (0.375 inch mesh) netting (Langley 2002). Unlike
rigid screens, fish nets are much more susceptible to lateral forces which can collapse the net.
Mesh size is specified in one of two ways, either as a "bar" or "stretch" dimension. A "stretch" measurement refers to the distance
between two opposing knots in the net openings when they are stretched apart. Thus, assuming a diamond shaped netting, when the
netting is relaxed the distance between two opposing sides of an opening will be roughly 1A the stretch diameter. A "bar" measurement
is the length of one of the four sides of the net opening and would be roughly equal to 1A the stretch measurement. The term "mesh
size" as used in this document refers to either Vi the "stretch" measurement or is equal to the "bar" measurement
Exhibit 3-50 presents reported mesh sizes from several power plant facilities that either now or in the past employed fish barrier nets.
An evaluation report of the use of barrier fish nets at the Bowline Plant in New York cited that 0.374 inch mesh was more effective
than 0.5 inch mesh at reducing the number offish entering the plant intake (Hutcheson 1988). Both fish barrier net cost scenarios
described below are based on nets with a mesh size of 0.375 in. (9.5 mm) and corresponds to the median mesh size of those identified
by EPA.
Exhibit 3-50. Available Barrier Net Mesh Size Data
Facilitv
Chalk Point
Entergy Arkansas
Nuclear One
Laskin Enerqv
Bowline Point
J.P. Pulliam
Descriotion
Inner Net
Outer Net
Low
Hiah (preferred)
More Effective Size
Reported Mesh Size
Inch
0.75
1.25
0.375
0.5
0.25
0.374
0.25
mm
19
32
10
13
6.4
9.5
6.4
Type of
Measurement
and Source
Stretch (1)
Stretch (1)
Mesh (Bar) (1)
Mesh (Bar) (1)
Mesh (Bar) (1)
Bar (3)
Stretch (2)
Median
Effective Mesh Size
Inch
0.375
0.625
0.375
0.5
0.25
0.374
0.126
0.374
mm
9.5
15.9
9.5
12.7
6.4
9.5
3.2
9.5
(1): 2002 EPA Fish Barrier Survey
(2):ASCE 1982
(3): Hutcheson 1988
Twine
Twine size mostly determines the strength and weight of the fish netting. Only the Chalk Point facility reported twine size data (#252)
knotless nylon netting. Netting #252 is a 75-lb test braided nylon twine in which the twine joints are braided together rather than
knotted (Murelle 2002). The netting used at the Bowline Power Plant was cited as multi-filament knotted nylon, chosen because of its
low cost and high strength (Hutcheson 1988).
Support/Anchoring System
In general, two different types of support and anchoring systems have been identified by EPA. In the simplest system the nets are held
in-place and the bottom is sealed with weights running the length of the bottom usually consisting of a chain or a lead line. The
weights may be supplemented with anchors placed at intervals. Vendors indicated the requirement for anchors varies depending on
the application and waterbody conditions. The nets are anchored along the shore and generally placed in a semi-circle or arc in front
of the intake. The Bowline Facility net used a v-shape configuration with an anchor and buoy at the apex and additional anchors
placed midway along the 91 meter length sides. In some applications anchors may not be needed at all. If the nets are moved by
current or waves, they can be set back into the proper position using a boat. The nets are supported along the surface with buoys and
floats. The buoys may support signs warning boaters of the presence of the net. The required spacing and size of the anchors and
buoys is somewhat dependent on the size of the net and lateral water velocities. The majority of facilities investigated used this
3-86
-------
§ 316(b) Phase III - Technical Development Document Technology Cost Modules
float/anchor method of installation. This net support configuration, using weights, anchors, floats, and buoys, is the basis for
compliance scenario A.
A second method is to support nets between evenly spaced pilings. This method is more appropriate for water bodies with currents.
The Chalk Point Power Plant uses this method in a tidal river. The Chalk Point facility uses two concentric nets. Each has a separate
set of support pilings with a spacing between pilings of about 18 feet to 20 feet (Langley 2002). Nets are hung on the outside of the
pilings with spikes and are weighted on the bottom with galvanized chain. During the winter top of the net is suspended below the
water surface to avoid ice damage but generally thick ice does not persist during the winter months at the facility location.
Debris
Debris problems generally come in two forms. In one case large floating debris can get caught in the netting near the surface and
result in tearing of the netting. In the other cases, floating and submerged debris can plug the openings in the net. This increases the
hydraulic gradient across the net, resulting in net being pulled in the downstream direction. The force can become so great that it can
collapse the net, and water flows over the top and/or beneath the bottom. If the net is held in place by only anchors and weights it may
be moved out of place. At the Chalk Point facility, debris that catches on the nets mostly comes in the form of jellyfish and colonial
hydroids (Langley 2002).
Several solutions are described for mitigating problems created by debris. At the Chalk Point Power Plant two concentric nets are
deployed. The outer net has a larger mesh opening designed to capture and deflect larger debris so it does not encounter the inner net,
which catches smaller debris. This configuration reduces the debris buildup on any one net extending the time period before net
cleaning is required. Growth of algae and colonization with other organisms (biofouling) can also increase the drag force on the nets.
Periodic removal and storage out of the water can solve this problem. At Chalk Point both nets are changed out with cleaned nets on a
periodic basis. This approach is considered to be appropriate for high debris locations.
Another solution is to periodically lift the netting and manually remove debris. A solution for floating debris is to place a debris boom
in front of the net (Hutcheson 1988).
Ice
During the wintertime ice can create problems in that the net can become embedded in surface ice with the net subject to tear forces
when the ice breaks up or begins to move. Flowing ice can create similar problems as floating debris. Ice will also affect the ability to
perform net maintenance such as debris removal. Solutions include:
• Removing the nets during winter
• Drop the upper end of the net to a submerged location; can only be used with fixed support, such as pilings and in locations where
thick ice is uncommon
• Installing an air bubbler below the surface. Does not solve problems with flowing ice.
Net Deployment
EPA assumes that barrier nets will be used to augment performance of the existing shore-based intake technology such as traveling
screens. The float/anchor supported nets are assumed to be deployed on a seasonal basis to reduce impingement of fish present during
seasonal migration. The Arkansas Energy Arkansas Nuclear One Plant deploys their net for about 120 days during winter months.
The Minnesota Power Laskin Energy Center, which is located on a lake, deploys the net when ice has broken up in spring and removes
the net in the fall before ice forms. Thus, the actual deployment period will vary depending on presence of ice and seasonal migration
offish. For the compliance scenario that relies upon float/anchor supported nets, a total deployment period of eight months (240 day)
is assumed. This is equal to or greater than most of the deployment periods observed by EPA.
EPA notes that the Chalk Point facility currently uses year round deployment and avoids problems with ice in the winter time by
lowering the net top to a location below the surface. Prior to devising this approach, nets were remove during the winter months. This
option is available because the nets are supported on pilings. Thus, the surface support rope (with floats removed) can be stretched
between the pilings several feet below the surface. Therefore, a scenario where nets are supported by pilings may include year round
deployment as was the case for the Chalk Point Power Plant. However, in northern climates the sustained presence of thick ice during
the winter may prevent net removal and cleaning and therefore, it may still be necessary to remove the nets during this period.
3-87
-------
§ 316(b) Phase III - Technical Development Document Technology Cost Modules
4.1 Capital Cost Development
Compliance costs are developed for the two different net scenarios.
Scenario A Installation at Freshwater Lake Using Anchors and Buoys/Floats
This scenario is intended for application in freshwater waterbodies where low water velocities and low debris levels occur such as
lakes and reservoirs. This scenario is modeled on the barrier net data from the Entergy Arkansas Nuclear One facility but has been
modified to double the annual deployment period from 120 days to 240 days. Along with doubling the deployment period, the labor
costs were increased to include an additional net removal and replacement step midpoint through this period. To facilitate the mid
season net replacement, the initial net capital costs will include purchase of a replacement net.
Scenario B Installation Using Pilings.
This scenario is modeled after the system used at Chalk Point. In this case two nets are deployed in concentric semi-circles with the
inner net having a smaller mesh (0.375 in) and the outer net having a larger mesh. Deployment is assumed to be year round. A marine
contractor performs all O&M, which mostly involves periodically removing and the replacing both nets with nets they have cleaned.
The initial capital net costs will include purchase of a set of replacement nets. This scenario is intended for application in waterbodies
with low or varying currents such as tidal rivers and estuaries. Two different O&M cost estimates are developed for this scenario. In
one the deployment is assumed to be year round as is the case at Chalk Point. In the second, the net is deployed for only 240 days
being taken out during the winter months. This would apply to facilities northern regions where ice formation would make net
maintenance difficult.
Net Costs
The capital costs for each scenario includes two components, the net and the support. The net portion includes a rope and floats
spaced along the top and weights along the bottom consisting of either a "leadline"or chain. If similar netting specifications are used
the cost of the netting is generally proportional to the size of the netting and can be expressed in a unitized manner such as "dollars/sq
ft." Exhibit 3-51 presents the reported net costs and calculated unit costs. While different water depths will change the general ratio
of net area to length of rope/floats and bottom weights, the differences in depth also result in different float and weight requirements.
For example, a shallower net will require more length of surface rope and floats and weights per unit net area but a shallower depth net
will also exert less force and require smaller floats and weights.
EPA is using the cost of nets in the average depth range of 20 to 30 feet as the basis for costing. This approach is consistent with the
median Phase III facility shoreline intake depth of 18 feet and median "average bay depth" of 20 feet. While nets are deployed
offshore in water deeper than a shoreline intake, costs are for average depths, which include the shallow sections at the ends, and net
placement can be configured to minimize depth. To see how shallower depths may affect unit costs, the costs for a shallower 10-foot
net with specifications similar to the Chalk Point net (depth of 27 feet) were obtained from the facility's net supplier. As shown in
Exhibit 3-51, the unit cost per square foot for the shallower net was less than the deeper net. Therefore, EPA has concluded that the
use of shallower nets does not increase unit costs and has chosen to apply the unit costs, based on the 20-foot and 30-foot depth nets,
to shallower depths.
Exhibit 3-51 presents costs obtained for the net portion only from the facilities that completed the Barrier Net Questionnaire. These
costs have been increased by 12% over what was reported to include shipping costs. This 12% value was obtained from the Chalk
Point net supplier who confirmed that the costs reported by Chalk Point did not include shipping. (Murelle 2002) The unit net costs
range from $0.17/sq ft to $0.78/sq ft. Consultation with net vendors indicates that the barrier net specifications vary considerably and
that there is no standard approach. Although no net specification data (besides mesh size) was submitted with the Laskin Energy
Center data, EPA has concluded that the data for this net probably represents lower strength netting which would be suitable for
applications where the netting is not exposed to significant forces. Because the compliance cost scenarios will be applied to facilities
with a variety net strength requirements, EPA has chosen to use the higher net costs that correspond to higher net strength
requirements. As such, EPA has chosen to use the cost data for the Chalk Point and Arkansas Nuclear One facilities as the basis for
each scenario.
3-88
-------
§ 316(b) Phase III - Technical Development Document
Technology Cost Modules
Exhibit 3-51 Net Size and Cost Data
Facilitv
Chalk Point
Chalk Point (equivalenl
Enterav Arkansas
Enterav Arkansas
Laskin Energy Center
Death
ft
27
27
10
20
20
16
Lenath
ft
300
300
300
250
1500
600
Area
sqft
8.100
8.100
3,000
5.000
30.000
9,600
Component
Replacement Net 0.675 in.*
Replacement Net 0.375 in.*
Replacement Net*
Replacement Net*
Net & Support Costs**
Net Costs***
Cost/net
$4.640
$4.410
$1,510
$3.920
$36.620
$1,600
Cost/sa ft
$0.57
$0.54
$0.50
$0.78
$1.22
$0.17
*Costs include floats and lead line or chain and are based on replacement costs plus 12% shipping.
** Costs include replacement net components plus anchors, buoys & cable plus 12% shipping
***Cost based on reported 1980 costs adjusted to 2002 dollars plus 12% for shipping.
Scenario A Net Costs
In this scenario the net and net support components are included in the unit costs. At the Arkansas Nuclear One facility unitized costs
for the net and anchors/buoys are $1.22/sq ft plus $0.78/sq ft for the replacement net, resulting in a total initial unit net costs of
$2.00/sq ft for both nets. Because the data in Exhibit 3-50 indicate that, if anything, unit costs for nets may decrease with shallower
depths, EPA concluded that this unit cost was representative of most of the deeper nets and may slightly overestimate the costs for
shallower nets.
Scenario A Net Installation costs
Installation costs for Arkansas Nuclear One (Scenario A) were reported as $30,000 (in 1999 dollars; $32,700 when adjusted for
inflation to 2002 dollars) for the 30,000 sq ft net. This included placement of anchors and cable including labor. In order to
extrapolate the installation costs for different net sizes, EPA has assumed that approximately 20% ($6,540) of this installation cost
represents fixed costs (e.g., mobilization/demobilization). The remainder ($26,160) divided by the net area results in an installation
unit cost of $0.87/sq ft to be added to the fixed cost.
Scenario A Total Capital Costs
Exhibit 3-52 presents the component and total capital costs for Scenario A. Indirect costs are added for engineering (10%) and
contingency/allowance (10%). Contractor labor and overhead are already included in the component costs. Because most of the
operation occurs offshore no cost for sitework are included.
Exhibit 3-52. Capital Costs for Scenario A Fish Barrier Net With Anchors/Buoys as Support Structure
Flow loom)
Net Area (so m
Net Costs
Installation Costs Fixed
Installation Costs Variable
Total Direct Caoftal Costs
Indirect Costs
Total Capital Costs
2.000
74
$149
$6.540
$65
$6.754
$1.351
$8,104
10.000
371
$744
$6.540
$324
$7.608
$1,522
$9,130
50.000
1.857
$3.722
$6.540
$1.619
$11.881
$2.376
$14,258
100.000
3.714
$7.445
$6.540
$3.238
$17223
$3,445
$20,667
250.000
9.284
$18.611
$6.540
$8.096
$33247
$6.649
$39,896
500.000
18.568
$37.223
$6.540
$16.191
$59.954
$11,991
$71,945
750.000
27.852
$55.834
$6.540
$24.287
$86.661
$17,332
$103,993
1.000.000
37.136
$74.445
$6.540
$32.383
$113.368
$22.674
$136,042
1.250,000
46,420
$93.057
$6.540
$40,478
$140.075
$28,015
$168,090
Scenario B Net Costs
In this scenario the net costs are computed separately from the net support (pilings) costs. In this scenario there are two separate nets
and an extra set of replacement nets for each. This, the unit costs for the nets will be two times the sum of the units net costs for each
of the large and small mesh nets. As shown in Exhibit 3-52, the unit costs for each net was $0.57/sq ft and $0.54/sq ft resulting in a
total cost for all four nets of $2.24/sq ft for the area of a single net.
3-89
-------
S 316(b) Phase III - Technical Development Document
Technology Cost Modules
Scenario B Installation Costs
Installation costs were not provided for the Chalk Point facility. Initial net installation is assumed to be performed by the O&M
contractor and is assumed to be a fixed cost regardless of net size. EPA assumed the initial installation costs to be two-thirds of the
contractor, single net replacement job cost of $1,400 or $933 (See O&M Costs - Scenario B).
Scenario B Piling Costs
The cost for the pilings at the Chalk Point facility were not provided. The piling costs for scenario B is based primarily on the
estimated cost for installing two concentric set of treated wooden pilings with a spacing of 20 ft between pilings. To see how water
depth affects piling costs, separate costs were developed at water depths of 10 feet, 20 feet, and 30 feet. Piling costs are based on the
following assumptions:
Costs for pilings is based on a unit cost of $28.507 ft of piling (RS Means, 2001)
• Piling installation mobilization costs are equal to $2,325 based on a mobilization rate of $46.50/mile for barge mounted
pile driving equipment (RS Means 2001) and an assumed distance of 50 miles
• Each pile length includes the water depth plus a 6-foot extension above the water surface plus a penetration depth (at
two-thirds the water depth); the calculated length was rounded up to the next even whole number
• The two concentric nets are nearly equal in length with one pile for every 20 feet in length and one extra pile to anchor
the end of each net.
Exhibit 3-53 presents the individual pile costs and intake flow for each net section between two pilings (at 0.06 feet per second).
Exhibit 3-53. Pile Costs and Net Section Flow
Water
Death
Ft
10
20
30
Total Pile
Lenath
Ft
24
40
56
Cost Per
Pile
684
1140
1596
Flow Per
20 ft Net
Section
aom
5385.6
10771.2
16156.8
Fixed
Cost
Mobilizati
on
2325
2325
2325
Exhibits 3-54, 3-55, and 3-56 present the total capital costs and cost components for the installed nets and pilings. Indirect costs are
added for engineering (10%) and contingency/allowance (10%). Contractor labor and overhead are already included in the component
costs. Because most of the operation occurs offshore no cost for sitework are included. The costs were derived for nets with multiple
20 ft sections. Because the net costs are derived such that the cost equations are linear with respect to flow, the maximum number of
sections shown are selected so they cover a similar flow range. Values that exceed this range can use the same cost equation.
5-90
-------
§ 316(b) Phase III - Technical Development Document
Technology Cost Modules
Exhibit 3-54. Capital Costs for Fish Barrier Net With Piling Support Structure for 10 Ft Deep Nets
Number of 20 ft Sections
Total Number of Pilinas
Sinale Net Lenath (ftt
Net Area (so. ft)
Flow (aom)
Total Pilina Cost
Net Costs
Total Direct Costs
Indirect Costs
Total Caoital Costs
2
6
40
400
10.771
$6.429
$1.380
$7.809
$1,562
$9,371
4
10
80
800
21.542
$9.165
$1.827
$10.992
$2,198
$13,190
8
18
160
1.600
43.085
$14.637
$2,721
$17,358
$3,472
$20,829
12
26
240
2.400
64.627
$20.109
$3.614
$23.723
$4,745
$28,468
25
52
500
5.000
134.640
$37.893
$6.519
$44.412
$8.882
$53,295
50
102
1000
10.000
269.280
$72.093
$12.106
$84.199
$16.840
$101,039
75
152
1500
15.000
403.920
$106.293
$17.692
$123.985
$24.797
$148.782
100
202
2000
20.000
538.560
$140.493
$23.279
$163.772
$32,754
$196,526
200
402
4000
40.000
1.077.120
$277.293
$45.624
$322.917
$64.583
$387,501
Exhibit 3-55 Capital Costs for Fish Barrier Net With Piling Support Structure for 20 Ft Deep Nets
Number of 20 ft Sections
Total Number of Pilinas
Sinale Net Lenath (ft)
Net Area (so ft)
Flow faom)
Total Pilina Cost
Net Costs
Total Direct Costs
Indirect Costs
Total Caoital Costs
2
6
40
800
21.542
$9.165
$1.827
$10.992
$2.198
$13,190
4
10
80
1600
43.085
$13,725
$2.721
$16.446
$3.289
$19.735
8
18
160
3200
86.170
$22.845
$4.508
$27.353
$5,471
$32.824
12
26
240
4800
129.254
$31.965
$6.296
$38261
$7.652
$45,913
25
52
500
10000
269.280
$61.605
$12.106
$73.711
$14.742
$88.453
50
102
1000
20000
538.560
$118.605
$23.279
$141.884
$28,377
$170,260
75
152
1500
30000
807.840
$175.605
$34.452
$210.057
$42,011
$252.068
100
202
2000
40000
1.077.120
$232.605
$45.624
$278.229
$55.646
$333,875
Exhibit 3-56. Capital Costs for Fish Barrier Net With Piling Support Structure for 30 Ft Deep Nets
Number of 20 ft Sections
Total Number of Pilinas
Sinale Net Lenath (ft)
Net Area (soft)
Flow (cmm)
Total Pilina Cost
Net Costs
Total Direct Costs
Indirect Costs
Total Capital Costs
2
6
40
1.200
32.314
$9.576
$2.274
$11.850
$2.370
$14,220
4
10
80
2.400
64.627
$15.960
$3.614
$19.574
$3,915
$23,489
8
18
160
4.800
129.254
$28.728
$6.296
$35.024
$7,005
$42,029
12
26
240
7.200
193.882
$41.496
$8.977
$50.473
$10,095
$60,568
25
52
500
15.000
403.920
$82.992
$17.692
$100.684
$20,137
$120,821
50
102
1000
30.000
807.840
$162.792
$34.452
$197.244
$39,449
$236,692
75
152
1500
45.000
1.211.760
$242.592
$51.211
$293.803
$58,761
$352,563
Figure 3-33 presents the total capital costs for scenarios A and B from Exhibits 3-52 through 3-56, plotted against design flow. Figure
3-33 also presents the best-fit linear equations used top estimate compliance costs. EPA notes that pilings for shallower depths costed
out more, due to the need for many more pilings. Scenario B costs for 10-foot deep nets will be applied wherever the intake depth is
less than 12 ft. For scenario B applications in water much deeper than 12 feet, EPA will use the cost equation for 20-foot deep nets.
4.2 O&M Costs Development
Scenario A O&M Costs - Float/Anchor Supported Nets
Barrier net O&M costs generally include costs for replacement netting, labor for net inspection, repair, and cleaning, and labor for net
placement and removal. The Arkansas Nuclear One facility supplied data that estimate all three components for its 1500 ft long by 20
ft deep net located on a reservoir. Net deployment, however, was for only a 120-day period. This net is installed in November and
removed in March (in-place for 120 days total). Each year two 250-foot sections of the net (one-third of the total) are replaced due to
normal wear and tear.
3-97
-------
§ 316(b) Phase III - Technical Development Document
Technology Cost Modules
EPA assumes the labor rate is similar to the estimate for traveling screen maintenance labor ($41.10/hr). The reported Arkansas
Nuclear One O&M labor requirements includes 3 hrs per day during the time the net is deployed for inspection & cleaning by
personnel on a boat (calculated at $14,800). This involves lifting and partially cleaning the nets on a periodic basis. Labor to deploy
and remove the net was reported at 240 hrs (calculated at $9,860). Two sections of the six total net sections were replaced annually at
a cost of $7,830 total (including shipping). Total annual O&M costs are calculated to be $32,500.
Because other facilities on lakes reported longer deployment periods (generally when ice is not present), EPA chose to adjust O&M
costs to account for longer deployment. EPA chose to base O&M costs for scenario A on a deployment period of 240 days
(approximately double the Arkansas Nuclear One facility deployment period). EPA also added costs for an additional net removal and
deployment step using the second replacement net midway through the annual deployment period. The result is a calculated annual
O&M cost of $57,200.
Scenario B O&M Costs - Piling Supported Nets
Nearly all of the O&M labor for Chalk Point facility is performed by a marine contractor who charges $1,400 per job to
simultaneously remove the existing net and replace it with a cleaned net. This is done with two boats where one boat removes the
existing net followed quickly by the second that places the cleaned net keeping the open area between nets minimized. The
contractors fee includes cleaning the removed nets between jobs. This net replacement is performed about 52 to 54 times per years. It
is performed about twice per week during the summer and once every two weeks during the winter. The facility relies upon the
contractor to monitor the net. Approximately one third of the nets are replaced each year, resulting in a net replacement cost of
$9,050.
Using an average of 53 contractor jobs per year and a net replacement cost of $9,050 the resulting annual O&M cost was $83,250.
EPA notes that some facilities that employ scenario B technology may choose to remove the nets during the winter. As such, EPA has
also estimated the scenario B O&M costs based on a deployment period of approximately 240 days by reducing the estimated number
of contractor jobs from 53 to 43 (deducting 10 jobs using the winter frequency of roughly 1 job every 2 weeks). The resulting O&M
costs are shown in Exhibits 3-56 and 3-57.
EPA notes that other O&M costs reported in literature are often less than what is shown in Exhibit 3-56. For example, 1985 O&M
cost estimates for the JP Pulliam plant ($7,500/year, adjusted to 2002 dollars) calculate to $11,800 for a design flow roughly half that
of Arkansas Entergy. This suggests the scenario A and B estimates represent the high end of the range of barrier net O&M costs.
Other O&M estimates, however, do not indicate the cost components that are included and may not represent all cost components.
In order to extrapolate costs for other flow rates, EPA has assumed that roughly 20% of the Scenario A and B O&M costs represent
fixed costs. Exhibit 3-57 presents the fixed and unit costs based on this assumption for both scenarios.
Exhibit 3-57. Cost Basis for O&M Costs
Scenario A
Scenario B
Scenario B
Deploym
ent
Days
240
365
240
Net
Replaceme
nt
$7.830
$9.050
$9,050
O&M
Labor
$49.320
$74.200
$60,200
Model
Facility
O&M
$57.150
$83.250
$69,250
Fixed
Cost
$11.430
$16.650
$13,850
Variable
Costs
$45.720
$66.600
$55,400
Unit
Variable
O&M
Costs
$/sqft
$1.52
$2.47
$2.05
Note that Unit Variable O&M Costs are based on a total net area of 30,000 sq ft (Entergy Arkansas) for scenario A and 27,000 sq ft for
scenario B (Chalk Point).
Exhibit 3-58 presents the calculated O&M costs based on the cost factors in Exhibit 3-57 and Figure 3-34 presents the plotted O&M
costs and the linear equations fitted to the cost estimates.
3-92
-------
§ 316(b) Phase III - Technical Development Document
Technology Cost Modules
Exhibit 3-58. Annual O&M Cost Estimates
Flow (cum)
Net Area (so
Scenario A
Scenario B
Scenario B
ft)
240 days
365davs
240 days
2.000
74
$11.543
$16.833
$14,002
10.000
371
$11.996
$17.566
$14,612
50.000
1.857
$14.260
$21.230
$17.660
100.000
3.714
$17,090
$25.810
$21,470
250.000
9.284
$25.579
$39.551
$32.899
500.000
18,568
$39.728
$62.451
$51,949
750.000
27.852
$53.877
$85.352
$70,998
1.000.000
37.136
$68.025
$108.252
$90,048
1.250.000
46.420
$82.174
$131.153
$109,097
4.3
Nuclear Facilities
Even though the scenario A costs are modeled after the barriers nets installed at a nuclear facility, the higher unit net costs cited by the
Arkansas Nuclear One facility include components that are not included with the non-nuclear Chalk Point nets and thus the differences
may be attributed to equipment differences and not differences between nuclear and non-nuclear facilities. In addition, the labor rates
used for scenario A and B O&M were for non-nuclear facilities. Because the function of barrier nets is purely for environmental
benefit, and not critical to the continued function of the cooling system (as would be technologies such as traveling screens). EPA
does not believe that a much more rigorous design is warranted at nuclear facilities. However, higher labor rates plus greater
paperwork and security requirements at nuclear facilities should result in higher costs. As such, EPA has concluded that the capital
costs for nuclear facilities should be increased by a factor of 1.58 (lower end of range cited in passive screen section). Because O&M
costs rely heavily on labor costs, EPA has concluded that the O&M costs should be increased by a factor of 1.24 (based on nuclear vs
non-nuclear operator labor costs).
4.4 Application
Fish barrier net technology will augment, but not replace, the function of any existing technology. Therefore, the calculated net O&M
costs will include the O&M costs described here without any deductions for reduction in existing technology O&M costs. Fish barrier
nets may not be applicable in locations where they would interfere with navigation channels or boat traffic.
Fish barrier nets require low waterbody currents in order to avoid becoming plugged with debris that could collapse the net. Such
conditions can be found in most lakes and reservoirs, as well as some tidal waterbodies such as tidal rivers and estuaries. Placing
barrier nets in a location with sustained lateral currents in one direction may cause problems because the section of net facing the
current will continually collect debris at higher rate than the remainder of the net. In this case, net maintenance cleaning efforts must
be able to keep up with debris accumulation. As such, barrier nets are suitable for intake locations that are sheltered from currents,
e.g., locations within an embayment, bay, or cove. On freshwater rivers and streams only those facilities within an embayment, bay,
or cove will be considered as candidates for barrier nets. The sheltered area needs to be large enough for the net sizes described
above. The fish barrier net designs considered here would not be suitable for waterbodies with the strong wave action typically found
in ocean environments.
Scenario A is most suitable for lakes and reservoirs where water currents are low or almost nonexistent. Scenario B is more suitable
for tidal waterbodies and any other location where higher quantities of debris and light or fluctuating currents may be encountered. In
northern regions where formation of thick ice in winter would prevent access to the nets, and scenario B may be applied, the scenario
B O&M costs for a 240-day deployment should be used. However, because this scenario results in reduced costs, EPA has chose to
apply the scenario B 365 days deployment for all facilities in suitable waterbodies.
EPA notes that nets with net velocities higher than 0.07 feet per second have been successfully employed (EPRI 1985). While such
nets will be smaller than those described here, they will accumulate debris at a faster rate. Because the majority of the O&M costs are
related to cleaning nets, EPA expects the increase in frequency of cleaning smaller nets will be offset by the smaller net size such that
the smaller nets should require similar costs to maintain.
Facilities with Canals
Most facilities with canals have in-canal velocities of between 0.5 and 1 feet per second based on average flow. These velocities are
an order of magnitude greater than the design net velocity used here. If nets with mesh sizes in the range considered here were placed
within the canals they will likely experience problems with debris. Therefore, if barrier nets are used at facilities with canals, the net
would need to be placed in the waterbody just outside the canal entrance.
3-93
-------
§ 316(b) Phase III - Technical Development Document Technology Cost Modules
REFERENCES
EPA. Responses to Fish Barrier Net Questionnaires. 2002.
Taft, E.P. "Fish Protection Technologies: A Status Report." Alden Research laboratory, Inc. 1999.
Hutcheson, J.B. Jr. Matousak, J.A. "Evaluation of a Barrier Net Used to Mitigate Fish Impingement at a Hudson River Power Plant."
American Fisheries Society Monograph 4:208-285. 1988
Murelle, D. Nylon Nets Company. Telephone Contact Report with John Sunda,. SAIC. Regarding cost and design information for fish
barrier nets. November 5, 2002.
Langley, P. Chalk Point Power Station. Telephone Contact Report with John Sunda,. SAIC. Regarding fish barrier net design,
operation, and O&M costs. November 4,2002.
ASCE. Design of Water Intake Structures for Fish Protection. American Society of Civil Engineers. 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.
RS Means. Costworks 2001.
3-94
-------
an
oa
Figure 3-33. Total Capital Costs for Fish Barrier Nets
$450,000
$400,000
$350
$300
o
o
.
(0
7848
200,000
400,000
600,000 800,000
Design Flow (gpm)
1,000,000
1,200,000
1,400,000
a
* Scenario A Barrier Net • Scenario B Net at 10 ft Depth Scenario B Net at 20 ft Depth Scenario B Net at 30 ft
-------
Figure 3-34. Barrier Net Annual O&M Costs
w
8
$140,000
$120,000
$100,000
o
o
ofl
O
15
$80,000
$60,000
$40,000
$20,000
200,000
400,000
600,000 800,000
Design Flow (gpm)
1,000,000 1,200,000
* Scenario A • Scenario B 365 Days Scenario B 240 days
1,400,000
-§
e
to
I
-------
§ 316(b) Phase III - Technical Development Document Technology Cost Modules
5.0 AQUATIC FILTER BARRIERS
Filter Barrier
Aquatic filter barrier systems are barriers that employ a filter fabric designed to allow passage of water into a cooling water intake
structure, while excluding aquatic organisms. One company, Gunderboom, Inc., has a patented system, the Marine/Aquatic Life
Exclusion System (MLES)™ that can be deployed as a full-water-depth filter curtain suspended from floating booms extending out in
the waterway or supported on a fixed structure as described below. The filter fabric material is constructed of matted unwoven
synthetic fibers.
Pore Size and Surface Loading Rate
Filter fabric materials with different pore sizes can be employed depending on performance requirements. In the MLES™ system two
layers of fabric are used. Because the material is a fabric and thus the openings are irregular, the measure of the mesh or pore size is
determined by an ASTM method that relies on a sieve analysis of the passage of tiny glass beads. The results of this analysis is
referred to as apparent opening size. The standard MLES ™ filter fabric material has an apparent opening size (AOS) of 0.15 mm.
(McCusker 2003b). Gunderboom can also provides filter fabric material that has been perforated to increase the apparent opening
size. Available perforation sizes range from 0.4 mm to 2.0 mm AOS. The "apparent opening size" is referred to as the "pore size" in
the discussion below. While smaller pore sizes can protect a greater variety of aquatic organisms, smaller the pore sizes also increase
the proportion of suspended solids collected and thus the rate at which it collects. In addition, smaller pore sizes tend to impede the
flow of water through the filter fabric which becomes even more pronounced as solids collect on the surface. This impedance of flow
results in an increase in the lateral forces acting on the AFB. The filter surface loading rate (gpm/ sq ft) or equivalent approach
velocity (feet per second) determines both the rate at which suspended particles collect on the filter fabric and the intensity of the
lateral forces pushing against the AFB. While the airburst system (see description below) is designed to help dislodge and removed
such suspended particles, there are practical limits regarding pore size and surface loading rate. For filter fabric of any given pore size,
decreasing the surface loading rate will reduce the rate of solids accumulation and the lateral forces acting upon the AFB. Thus, pore
size is an important design parameter in that it determines the types of organisms excluded as well as contributes to the selection of an
acceptable surface loading rate. The surface loading rate combined with the cooling water intake design flow determines the required
AFB surface area. This total filter fabric area requirement when combined with the local bathymetry determines the area that resides
within the AFB.
Since the AFB isolates and essentially restricts the function of a portion of the local ecosystem, anything that increases the AFB total
surface area will also increase the size of the isolated portion of the ecosystem. As such, there is an environmental trade off between
minimizing the pore size to protect small size organisms/lifestages versus minimizing the size of the area being isolated. Additionally,
requirements for large AFB surface areas may preclude its use where conflicts with other waterbody uses (e.g., navigation) or where
the waterbody size or configuration restricts the area that can be impacted. Vendors can employ portable test equipment or pilot scale
installations to test pore size selection and performance which can aid in the selection of the optimal pore size. Acceptable design
filter loading rates will vary with the pore size and the amount of sediment and debris present. An initial target loading rate of 3 to 5
gpm/sq ft have been suggested (EPA 2001). This is equivalent to approach or net face velocities of 0.007 to 0.01 feet per second
which is nearly an order of magnitude lower than the 0.06 feet per second design velocity used by EPA for barrier nets. This
difference is consistent with the fact that barrier net use much greater mesh sizes. Use of larger AFB pore sizes can result in greater
net velocities. Since the cost estimates as presented here are based on design flow, differences in design filter loading rates will affect
the size of the AFB which directly affects the costs. The range between the high and low estimates in capital and O&M costs
presented below account at least in part for the differences associated with variations in pore size as well as other design variations that
result from differences in site conditions.
Floating Boom
For large volume intakes such as once-through systems, an AFB supported at the top by a floating boom that extends out into the
waterbody and anchored onshore at each end is the most likely design configuration to be employed because of the large surface area
required. In this design, a filter fabric curtain is supported by the floating boom at the top and is held against the bottom of the
waterbody by weights such as a heavy chain. The whole thing is held in place by cables attached to fixed anchor points placed at
regular intervals along the bottom. The Gunderboom MLES design employ a two layer filter fabric curtain that is divided vertically
into sections to allow for replacement of an individual sections when necessary. The estimated capital and O&M costs described
below are for an AFB using this floating boom-type construction.
3-97
-------
§ 316(b) Phase HI - Technical Development Document
Technology Cost Modules
Fixed Support
The AFB vendor, Gunderboom Inc., also provides an AFB supported by rigid panels that can be placed across the opening of existing
intake structures. This technology is generally applicable to existing intakes where the intake design flow has been substantially
reduced such as where once-through systems are being converted to recirculating cooling towers. For other installations, Gunderboom
has developed what they refer to as a cartridge-type system which consists of rigid structures surrounded by filter fabric with filtered
water removed from the center (McCusker 2003). Costs for either of these rigid type of installation have not been provided.
Air Backwash
The Gunderboom MLES™ employs an automated air burst technology that periodically discharges air bubbles between the two layers
of fabric at the bottom of each MLES curtain panel. The air bubbles create turbulence and vibrations that help dislodge particulates
that become entrained in the filter fabric. The airburst system can be set to purge individual curtain panels on a sequential basis
automatically or can be operated manually. The airburst technology is included in the both the capital and O&M costs provided by the
vendor.
5.1 Capital Cost Development
Estimated capital costs were provided by the only known aquatic filter barrier manufacturer, Gunderboom, Inc. Cost estimates were
provided for AFBs supported by floating booms representing a range of costs; low, high, and average that may result from differences
in construction requirements that result from different site specific requirements and conditions. Such requirements can include
whether sheetwall piles or other structures are needed and whether dredging is required which can result in substantial disposal costs.
Costs were provided for three design intake flow values: 10,000 gpm, 104,000 gpm, and 347,000 gpm. Theses costs were provided in
1999 dollars and have been adjusted for inflation to July 2002 dollars using the ENR construction cost index. The capital costs are
total project costs including installation. Figure 3-35 presents a plot of the data in Exhibit 3-59 along with the second order equation
fitted to this data.
The vendor recently provided a total capital cost estimate of 8 to 10 million dollars for full scale MLES™ system at the Arthur Kill
Power Station in Staten Island, NY (McCusker 2003a). The vendor is in the process of conducting a pilot study with an estimated cost
of $750,000. The NYDEC reported the permitted cooling water flow rate for the Arthur Kill facility as 713 mgd or 495,000 gpm.
Applying the cost equations in Figure 3-35 results in a total capital cost of $8.7, $10.1 and $12.4 million dollars for low, average and
high costs, respectively. These data indicate that the inflation adjusted cost estimates are consistent with this more recent estimate
provided by the vendor. Note that since the Arthur Kill intake flow exceeded the range of the cost equation input values the cost
estimates presented above for this facility were derived by first dividing the flow by two and then adding the answer.
Exhibit 3-59. Capital Costs for Aquatic Filter Barrier Provided by Vendor
Flow
cmm
10.000
104.000
347,000
Floatina Boom
Caoital Cost (2002
Low
$545.000
$1.961.800
$6,212.500
Hiah
$980.900
$2.724.800
$8,501,300
Dollars)
Averaae
$762.900
$2.343.300
$7,356,900
5.2
O&M Costs
Estimated O&M costs were also provided by Gunderboom Inc., As with the capital costs the O&M costs provided apply to floating
boom type AFBs and include costs to operate an air burst system. Exhibit 3-60 presents a range of O&M costs from low to high and
the average which served as the basis for cost estimates. As with the capital costs, the costs presented in Exhibit 3-60 have been
adjusted for inflation to July 2002 dollars. Figure 3-35 presents a plot of the data in Exhibit 3-60 along with the second order equation
fitted to this data.
3-98
-------
§ 316(b) Phase III - Technical Development Document
Technology Cost Modules
Exhibit 3-60. Estimated AFB Annual O&M Costs
Flow
dom
10.000
104.000
347,000
O&M
Low
$109.000
$163.500
$545,000
O&M
Hiah
$327.000
$327.000
$762,900
O&M
Average
$218.000
$245.200
$653,900
5.3 Application
Aquatic filter barriers (AFBs) can be used where improvements to impingement performance is needed. Because they can be installed
independently of intake structures, there is no need to include any costs for modifications to the existing intake structure or technology
employed. Costs are assumed to be the same for both new and existing facilities. AFBs can be installed while the facility is operating.
Thus, there is no need to coordinate AFB installation with generating unit downtime. Capital cost estimates used in the economic
impact analysis used average costs.
EPA assumed that the existing screen technology would be retained as a backup following the installation of floating boom AFBs.
Therefore, as with barrier nets, the O&M costs of the existing technology was not deducted from the estimated net O&M cost used in
the Phase III economic impact analysis. Upon further consideration, EPA has concluded that at a minimum there should be a
reduction in O&M cost of the existing intake screen technology equivalent to the variable O&M cost component estimated for that
technology.
REFERENCES
EPA, Technology Fact Sheet 316(b) Phase I Technical Development Document. (EPA-821-R-01-036). November 2001.
McCusker, A. Gunderboom, Inc., Telephone contact report with John Sunda, SAIC. Regarding MLES system technology. August, 8,
2003a.
McCusker, A. Gunderboom, Inc. Email correspondence with John Sunda, SAIC. Regarding MLES system technology pore size and
costs. October 2 , 2003b.
3-99
-------
ooi-f
Capital and Annual O&M Costs
8
CD
3
1
i
o
0)
T3
I
O
o
(O
en
o
8
o
o
o
s
o
en
o
o
o
o
p
8
o
K>
cn
o
CO
o
o
8
CO
en
o
o
o
o
era
i
o*
o
o
n
M
•a
M
a
o
I
era
03
i
- m asoi^j (q)9j£ §
-------
S 316(b) Phase III - Technical Development Document Technology Cost Modules
II. TECHNOLOGY COST MODULES FOR SEAFOOD PROCESSING VESSELS
APPLICATION OF THE PROPOSED RULE
Under each of the co-proposed options, no seafood processing vessels would be subject to national performance standards.
INTRODUCTION
EPA has identified a typical 280-foot catcher-processor as an indicative vessel to assemble cost estimates for retrofitting fine mesh
screens for cooling water intake structures. Information gathered during interviews with industry representatives will be used to
characterize the intake structure of a typical 280-foot vessel. It is reasonable to assume that the majority of these vessels use a sea
chest arrangement for cooling water intake.
Four primary fine mesh configurations have been costed:
1. Replace the existing grill with a fine mesh screen, without any other modifications;
2. Enlarge the intake structure internally to achieve 0.5 feet per second through screen velocity. Under this option, the screen
will be in flush with the hull;
3. Install a fine mesh screen intake structure externally to achieve 0.5 feet per second through screen velocity. The screen
protrudes outside of the hull under this option; and
4. Install a horizontal flow modifier externally to the intake structure to achieve 0.5 feet per second through screen velocity.
The flow modifier protrudes outside of the hull. Cost estimates for two configurations, one for vessels with bottom sea chests
and one for side sea chests are presented.
Material costs for both 316 stainless steel and copper-nickel (CuNi) alloy fine mesh screens were obtained from venders. In addition,
material costs for steel fabrication and associated labor rates, including diver team costs were obtained using various vender sources.
The capital costs estimated in this report are incremental costs for a facility. A 10% engineering and 10% contingency sum has been
included in the cost estimates. One of the key assumptions for the development of capital costs is that the vessel is in dry dock for
routine maintenance and that this work does not prolong the dry dock time for the vessel. No allowances have been made for docking
fees.
Inspection frequency for fine mesh screens and horizontal flow modifiers are assumed to be one per year. This is based on typical
inspection frequencies for onshore and coastal facilities. The estimates for inspection and cleaning frequencies are based on vendor
data and data from operators of similar equipment in high marine growth areas. It is assumed that the existing sea chests are inspected
annually with the use of divers. The inspection and maintenance of the proposed enlarged intake structures will take significantly
longer than current practices. An allowance of an additional day per intake has been included for these intake modification options for
divers to inspect and clean the new intake structures. However, for the option where no enlargement of the intake is proposed, a lump
sum cost of $100 is estimated for annual inspection and maintenance. An allowance of 6% of the capital cost has been allowed as
annual replacement costs for parts. Mobilization or demobilization costs are not included in this estimate. The O & M costs estimated
in this report are incremental costs for the facility.
1.0 REPLACE EXISTING GRILL WITH FINE MESH SCREEN
1.1 Capital Cost Development
In this option, the existing grill is replaced with a larger (typically 32" diameter) fine mesh screen. Costs are estimated for replacing
the existing coarse grill with 316 stainless steel and Cu/Ni alloy fine mesh screens. In addition to the material cost of the screen,
installation costs are included in this cost estimate.
3-101
-------
S 316(b) Phase III - Technical Development Document
Technology Cost Modules
1.2 O & M Cost Development
A lump sum cost of $100 is estimated as the annual O & M costs to inspect and clean the fine mesh screen. Exhibit 3-61 below
presents the summary of incremental capital and O & M costs to replace the existing grill with fine mesh screen. These costs are
presented for three design intake flow values.
Exhibit 3-61. Capital and O & M costs for Replacing Existing Coarse Screen with Fine Mesh Screen
Design Flow (MGD)
0.6
6.3
12.7
Stainless Steel Fine Mesh Screen
Capital Cost ($)
404
764
1,190
O&MCost($)
100
100
100
Cu/Ni Fine Mesh Screen
Capital Cost ($)
423
965
1,604
O&MCost($)
100
100
100
Figures 3-47 and 3-48 (at the end of this section) show the cost curves for replacing an existing grill.
3-702
-------
§ 316(b) Phase III - Technical Development Document
Technology Cost Modules
2.0
ENLARGE THE INTAKE STRUCTURE INTERNALLY
2.1 Capital Cost Development
It is proposed to modify the existing 32" intake with a new intake structure that has a large enough surface area to reduce the through
screen velocity to 0.5 feet per second. The primary problem with this type of intake modification is that there is typically very little
room at the intake. As such, a low profile design has been developed to minimize the impacts on surrounding equipment and services
of the vessel. The intake pipe suction is dispersed across the face of a large mesh using a diffuser arrangement. This type of flow
modifier is often used to limit vortex problems on suction lines. It will only marginally increase the head loss through the system, as
the available flow area is still large (but at right angles to the pipe flow). The similarity with a velocity cap is easily noted. This
design also accounts for the structural members of the vessel's hull. The insertion of a large intake will typically require the cutting of
several hull stiffeners. The design presented is intended to transfer the loads directly through the main frame. Figures 3-36 through 3-
40 present the proposed modification for the existing intake.
2.2 O & M Cost Development
The O & M costs are based on the labor cost for a team of divers, including the cost of equipment and boat to inspect and clean the
intake once per year and an allowance of 6 % of the capital cost for parts replacement. The estimates for inspection and cleaning
frequencies are based on vendor data and data from operators of similar equipment in high marine growth areas.
Exhibit 3-62 below presents the summary of incremental capital and O & M costs to enlarge the intake structure internally with fine
mesh screen. These costs are presented for three design intake flow values.
Exhibit 3-62. Capital and O & M Costs for Enlarging Intake Internally
Design Flow (M GD)
0.6
6.3
12.7
Stainless Steel Fine Mesh Screen
Capital Cost ($)
26,882
50,923
70,652
O & M Cost ($)
2,365
3,431
4,332
Cu/Ni Fine Mesh Screen
Capital Cost ($)
27,010
52,218
73,235
O & M Cost (S)
2,371
3,496
4,461
Figure 3-49 through 3-52 (at the end of this section) show the cost curves for enlarging an intake.
3-103
-------
§ 316(b) Phase III - Technical Development Document
Technology Cost Modules
Figure 3-36. Enlarged (Internal) Fine Mesh Sea Water Intake Configuration
10
.«-
'S
f- 7-&*m
:/
|Cr
-** Ls^S"* I
* r •*—*^ * t- r
Figure 3-37. Outer Bar Screen (for Internal and External Intake Modification)
3-104
-------
§ 316(b) Phase III - Technical Development Document
Technology Cost Modules
Figure 3-38. Fine Mesh Inner Screen (for Internal and External
Intake Modification)
3-105
-------
§ 316(b) Phase IH - Technical Development Document
Technology Cost Modules
Figure 3-39. Fine Mesh Frame and Inner Difruser (for Internal and External
Intake Modification)
3-106
-------
§ 316(b) Phase III - Technical Development Document
Technology Cost Modules
Figure 3-40. Main Frame for Internal Intake Modification
3-107
-------
§ 316(b) Phase III - Technical Development Document
Technology Cost Modules
3.0
ENLARGE THE INTAKE STRUCTURE EXTERNALLY
3.1 Capital Cost Development
In this proposed modification, the existing 32" intake is replaced with a new external intake structure that has a large enough surface
area to reduce the through screen velocity to 0.5 feet per second. An external intake does not affect the structure of the vessel and it is
fairly simple and economical to retrofit the proposed intake to an existing vessel. However, with this type of intake modification,
additional drag would be induced by its inclusion on the hull. Consequently, the low profile approach similar to the proposed internal
enlargement is applicable for this configuration as well. Consultation with a naval architect confirmed that the additional drag induced
by this modification would be negligible and that the cost benefit and ease of installation would likely outweigh any detrimental
effects. The naval architect also confirmed that this design was reasonable for the stated purpose. Figures 3-37 through 3-39 and
Figures 3-41 and 3-42 present the proposed modification to enlarge the existing intake externally.
3.2 O&M Cost Development
The O&M costs are based on the labor cost for a team of divers, including the cost of equipment and boat to inspect and clean the
intake once per year, and an allowance of 6 % of the capital cost for parts replacement. The estimates for inspection and cleaning
frequencies are based on vendor data and data from operators of similar equipment in high marine growth areas.
Exhibit 3-63 presents the summary of incremental capital and O&M costs to enlarge the intake structure externally with fine mesh
screen. These costs are presented for three design intake flow values.
Exhibit 3-63. Capital and O&M Costs for Enlarging Intake Externally
Design Flow (MGD)
0.6
6.3
12.7
Stainless Steel Fine Mesh Screen
Capital Cost ($)
12541
28862
43444
O&M Cost ($)
2021
2752
3429
Cu/Ni Fine Mesh Screen
Capital Cost ($)
12669
30157
46027
O&M Cost ($)
2027
2817
3558
Figures 3-53 through 3-56 (at the end of this section) show the cost curves for enlarging an intake externally.
3-108
-------
§ 316(b) Phase III - Technical Development Document
Technology Cost Modules
Figure 3-41. External (Protruding) Fine Mesh Sea Water Intake Configuration
Refer to Figures 3-37 through 3-39 for details of Outer Bar Screen, Fine Mesh Inner Screen and Fine Mesh Frame and Inner Diffuser,
respectively
Figure 3-42. Main Frame for External (Protruding) Intake
Modification
3-109
-------
S 316(b) Phase IH - Technical Development Document Technology Cost Modules
4.0 HORIZONTAL FLOW MODIFIER
4.1 Capital Cost Development
The horizontal flow modifier is a panel that ensures horizontal flow into the intake structure at a velocity of 0.5 feet per second or less.
This is a derivative of the velocity cap technology.
The horizontal flow modifier option is divided up into two basic configurations: one for sea chests located on the bottom of the vessel
and the other for sea chests located on the sidewalls of the vessel. The arrangement on the bottom sea chests closely resembles a
standard velocity cap configuration. A plate is located over the intake opening to direct the flow in the horizontal direction between
the plate and the hull. This arrangement will be suitable for hull angles up to 30' to the horizontal (87% of velocity will still be
horizontal). For hull angles exceeding 30* and up to completely vertical, the side sea chest configuration will be required. This design
includes a flow diffuser to spread the flow over a large area and louvres to direct the flow in the horizontal direction. Both of these
designs are low profile in order to reduce any fluid dynamic effects on the hull of the vessel. The existing coarse grill over the sea
chest will be retained. It is intended that the assembled horizontal flow diverter be attached using hinges to the hull to allow easy
access to the existing intake structure. All materials used for the construction of this item will be mild steel coated in anti-fouling
paint.
4.1.1 Vessels with Bottom Sea Chests
The proposed modification consists of a flow modifier plate that is stiffened using 4" flat bar welded to the under side. These flat bar
stiffeners also assists in tunneling the flow into the existing intake structure. A coarse mesh has been included around the perimeter of
the new intake structure. This is to prevent larger animals (like turtles) getting trapped in the gap between the hull and the flow
modifier plate (looks similar to a reef ledge to some animals). Eight brackets (4" PFC) are permanently welded to the hull as the
primary attachment points. Eight legs off the flow modifier plate (1/2" plate) attach to the brackets on the hull. Three of the bracket to
leg connections use hinge pins, the other 5 legs use bolts. Releasing the bolts allows the flow modifier to swing down for maintenance
or cleaning of the sea chest intake. A lifting lug should be added to the hull to allow lifting equipment can be used to safely open and
close this new structure. A lifting lug has been incorporated in the costs for this item. Figures 3-43 and 3-44 present the proposed
configuration to modify the existing intake with horizontal flow modifiers for vessels with bottom sea chests.
4.1.2 Vessels with Side Sea Chests
The basic assembly consists of a diffuser plate nested in a number of flow louvres. The diffuser ensures that the flow is evenly
distributed across the louvres and the louvres ensure that the flow is horizontal at a velocity of 0.5 feet per second or less. Two
brackets (2" equal angles) are permanently welded to the hull as the primary attachment points. These run the entire width and at each
end of the sea chest modification. The horizontal flow modifier is attached to the brackets on the hull by way of a hinge on one side
and bolts on the other. By releasing the bolts, the horizontal flow modifier may be swung out away from the hull for access to the
existing sea chest. All materials used for the construction of this item will be mild steel coated in anti-fouling paint. The direction of
the flow louvres should be adjusted during the design and construction of this equipment such that they are horizontal. Figures 3-45
and 3-46 present the proposed configuration to modify the existing intake with horizontal flow modifiers for vessels with bottom sea
chests.
4.2 O & M Cost Development
The O & M costs are based on the labor cost for a team of divers, including the cost of equipment and boat to inspect and clean the
intake once per year and an allowance of 6 % of the capital cost for parts replacement. The estimates for inspection and cleaning
frequencies are based on vendor data and data from operators of similar equipment in high marine growth areas.
Exhibits 3-64 and 3-65 below present the summary of incremental capital and O & M costs to enlarge the intake structure with flow
modifier for vessels with bottom sea chests and side sea chests, respectively. These costs are presented for three design intake flow
values.
3-110
-------
§ 316(b) Phase III - Technical Development Document
Technology Cost Modules
Exhibit 3-64. Capital and O & M Costs for Intake Modification Using Flow Modifier for Vessels with Bottom Sea Chests
Design Flow (MGD)
0.6
6.3
12.7
Stainless Steel Fine Mesh Screen
Capital Cost ($)
6221
11437
17048
O & M Cost ($)
1915
2228
2565
Exhibit 3-65. Capital and O & M Costs for Intake Modification Using Flow Modifier for Vessels with Side Sea Chests
Design Flow (MGD)
0.6
6.3
12.7
Stainless Steel Fine Mesh Screen
Capital Cost ($)
5343
13266
22240
O & M Cost ($)
1863
2338
2876
Figures 3-57 through 3-60 (at the end of this section) show the cost curves for using a flow modifier.
3-777
-------
§ 316(b) Phase III - Technical Development Document
Technology Cost Modules
I . .
Figure 3-43. Plan View of Bottom Sea Chest Horizontal Flow Modifier
3-772
-------
§ 316(b) Phase III - Technical Development Document
Technology Cost Modules
L :UVF^i.: :.
£yr
-------
§ 316(b) Phase HI - Technical Development Document
Technology Cost Modules
Figure 3-45. Plan View of Side Sea Chest Horizontal Flow Modifier
3-114
-------
§ 316(b) Phase III - Technical Development Document
Technology Cost Modules
Figure 3-46. Sectional View of Side Sea Chest Horizontal Flow Modifier
3-775
-------
an
CO
Figure 3-47 Capital Cost for Replacing Existing Grill with Fine Mesh Stainless Steel Screen
g
(0
a
1,100
I
Q,
es
U
600
100
0.00
2.00
4.00
6.00 8.00
Flow (mgd)
10.00
12.00
14.00
o
S
C7
o
Uj
o
I
I
I
-------
§ 316(b) Phase III - Technical Development Document
Technology Cost Modules
u
00
O
o
O
q
(N
o
q
o
o
q
CO
o
q
CD
I
o
o
o
q
c\i
o
o
o
o
CD
o
o
O
o
CO
o
o
3-117
-------
§ 316(b) Phase IH - Technical Development Document
Technology Cost Modules
O
O
a
I
i
A
•a
Ed
a
es
u
O
q
c\i
o
q
d
o
q
cd
o
q
CD
o
q
•^
o
q
c\i
o
o
1
E
-------
§ 316(b) Phase HI - Technical Development Document
Technology Cost Modules
.s
to
I
OS
C
C5 »-
*j W
e co
sf "S
CA
-fcJ
Vi
O
o
•
o
I
o
o
o
q
CD
o
o
o
in"
o
o
06 e
60
§,
O
O fe.
q
CD
o
o
o
q
c\i
o
o
o
o
o
o
o
o
CO
o
o
o_
CM"
($) JS03
3-779
-------
§ 316(b) Phase III - Technical Development Document
Technology Cost Modules
I
a»
I
.S
fif
0}
•s
5/3
o
U
"S
U
ox
o
o
o
q
c\i
o
o
o
o
o
o"
oo
o
o
o
o"
o
o
o
o"
(O
o
o
o
o
o
o
o
q
06
o
q
CD
o
o
q
c\i
o
o
o
o
o
o"
00
o
o
o
o"
CN
3-120
-------
§ 316(b) Phase III - Technical Development Document
Technology Cost Modules
o
<«
JS
!
I
§
NH
tf
w
a
o
o
q
cvi
o
o
o
q
CO
o
q
cd
i
o
o
o
q
c\i
o
o
o
o
o
10"
o
o
o
o
o
o_
oo
o
o
o_
CM"
3-121
-------
§ 316(b) Phase III - Technical Development Document
Technology Cost Modules
(*>
CA
a>
cc
os
B
w B
3 8
a E
t- w
5 ^
w> -
.s
I s
W to
o "«
o
u
"33
.ts
a
«
U
.SP
to
o
o
1 *Y;3f - t£r i
. ' X JsT-' " ^ ^ •* *•
*° ***j ^S j *sy-3.
x> <^" "iis4l S -1^ J1
r tf^-tSPS'V**^*.
O
O
o
o"
to
O
p
csi
o
o
o
p
00
o
p
CD
o
o
O
O
c\i
o
o
o
o
o
o"
o
o
o_
o"
CO
o
o
o
o"
CM
o
o
o
OD
E
3-122
-------
§ 316(b) Phase HI - Technical Development Document
Technology Cost Modules
c
£
ai
"3
|
*-
i
x
=
£ s
s
w
I
.2
CA
O
U
9
Ml
CM
3-123
-------
§ 316(b) Phase HI - Technical Development Document
Technology Cost Modules
O>
s
s
es
ts
C
w
Ll
«s
o
u
u
1
ox
''' *$:\
'/£• 4
, aT*
- '-• H:- 'i
I--' 4
^«^ws;*?v "^ '''^^'^s -**,
.% r* - fcN- >, * ,-^i
CM
*
»> ITS ->«o ?
:-^--
%?;ft
-,Wfc (^ *«
y«f^rs
;^ IN.
< ^
o
o
o
o"
in
o
o
o
o
o
o
o"
CO
o
o
o
o"
CM
($) IS03
O
O
O
q
c\i
o
p
o
o
p
06
o
p
CD
o
o
o
o
o
o"
o
p
c\i
o
p
o
3-724
-------
§ 316(b) Phase III - Technical Development Document
Technology Cost Modules
I
^
u
J=
fr
s
IS a
ee
O
U
&JD
f ' '1 J " '
3-725
-------
Capital Cost ($)
p
b
o
b
o
3
o
,^
i
o
o
p>
b
o
po
b
o
o
o
b
o
b
o
a
ere
O
»
f
I
*5
s?l
» rs
C!
<*>
I
f
S1
09
09
re
S3|npoyy 4.503 X6o|oui|33j.
-------
Figure 3-58. O & M Costs for Intake Modification Using Flow Modifier for
Vessels with Side Sea Chest
an
GO
3,000
2,500
V)
o
O
2,000
1,500
0.00
2.00
4.00
6.00 8.00
Flow (mgd)
10.00
12.00
14.00
C7
8
-8
8
§•
fr
8
-------
§ 316(b) Phase III - Technical Development Document
Technology Cost Modules
a
u*
i
I
^
fe
W)
=
•2
-
J-
.0
0*
•*•»
'5,
«
U
•
o\
IT)
fO
I
CD
• M
fa
O
O
o
p
c\i
o
p
c>
o
q
od
CJD
S
O
8 E
CD
O
O
O
O
o
o
o
o
o
o"
CN
o
o
o
o
o
o
o -
o
o
in
3-128
-------
§ 316(b) Phase III - Technical Development Document
Technology Cost Modules
o
a
u.
a>
I
I
jf
s *
= £
•2U
A A
W 0)
C co
1 s
si
II
O V
U >
o
o
W&
'*• - r*'C'^1 Vl.»* A . f ^-r&r
- v^»;T %* '•»„*•• • .*."**"..
o
q
CNJ
o
q
o
O
q
06 <$
o
q
cd
o
o
o
o
in
oo
o
o
m
CM"
o
o
in
o
q
c\i
o
q
d
($)
3-129
-------
§ 316(b) Phase III - Technical Development Document Technology Cost Modules
III. TECHNOLOGY COST MODULES FOR OFFSHORE OIL AND GAS EXTRACTION FACILITIES
APPLICATION OF THE PROPOSED RULE
Under each of the co-proposed options, no existing oil and gas extraction facilities would be subject to national performance standards.
New oil and gas extraction facilities would be subject to the proposed rule, as described in the preamble to today's rule.
INTRODUCTION
EPA did not consider new offshore oil and gas extraction facilities (the definition of "offshore" includes both coastal and offshore
facilities-see the preamble for further details) in the 316(b) Phase I - New Sources rulemaking. Non-contact, once-through water is
used to cool crude oil, produced water, power generators, and various other pieces of machinery at oil and gas extraction facilities.1
The Phase I proposal and its record included no analysis of issues associated with offshore 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. Consequently,
EPA exempted these facilities from the Phase I rule (see December 18,2001; 66 FR 65311). As part of the Phase III rulemaking, EPA
also evaluated potential 316(b) technology options for existing offshore oil and gas extraction facilities.
Since the Phase I 316(b) rulemaking, EPA collected technical and economic information associated with this industry sector. EPA
also received information from industry trade associations to assist its analyses. EPA used this information to assess costs, economic
impact and unique technical issues associated with various technology-based options available to control impingement and
entrainment of aquatic organisms. This chapter provides an overview of the: (1) industrial sector; (2) information EPA collected and
received from industry; (3) facilities in this industrial sector which EPA evaluated for the Phase III rulemaking; (4) technology options
available to control impingement and entrainment of aquatic organisms; and (5) proposed technology options identified in the Phase III
proposal.
1.0 INDUSTRIAL SECTOR PROFILE: OFFSHORE OIL AND GAS EXTRACTION FACILITIES
The oil and gas extraction industry drills wells at 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 approximately 5.7 million barrels of crude oil per day.1 The
U.S. Outer Continental Shelf (OCS) contributes to this energy production and the largest 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).2 The U.S. Department of Interior's Mineral Management Service (MMS) is the Federal agency
responsible for managing OCS mineral resources. The following are summary statistics on OCS oil and gas production:3
• The OCS accounts for about 25% of the Nation's domestic natural gas production and about 30% of its domestic oil
production. On an energy basis (BTU), about 60 percent of the energy currently produced offshore is natural gas.
• The OCS contains about 19% of the Nation's proven natural gas reserves and 18% of its proven oil reserves. The OCS is
estimated to contain more than 60% of the Nation's remaining undiscovered natural gas and oil resources.
• Since 1953, the OCS has produced about 141 trillion cubic feet of natural gas and about 13 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%.
Exhibit 3-66 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
'U.S. DOE, 2004. EIA Quick Stats Pages, http://www.eia.doe.gov/neic/auickstats.html.
2The Federal OCS starts approximately 10 miles from the Florida and Texas shores.
3E-mail from James Cimato, MMS, to Carey Johnston, EPA, April 9,2003.
——
-------
§ 316(b) Phase HI - Technical Development Document
Technology Cost Modules
discovered and delineated. Although the rigs used in exploratory and development drilling 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.
Exhibit 3-66. Number of Wells Drilled Annually, 1995 - 1997, By Geographic Area
Data Source
Gulf of Mexicof
MMS: 1995
1996
1997
Average Annual
RRC
Total Gulf of Mexico
Shallow Water
(<1,000 ft)
Development
Exploration
Deep Water
(> 1,000 ft)
Development
Exploration
Total
Wells
557
617
726
640
5
645
314
348
403
355
3
358
32
42
69
48
NA
48
52
73
104
76
NA
76
975
1,080
1,302
1,119
8
1,127
Offshore California
MMS: 1995
1996
1997
Average Annual
4
15
14
11
0
0
0
0
15
16
14
15
0
0
0
0
19
31
28
26
Coastal Cook Inlet
AOGC: 1995
1996
1997
Average Annual
12
5
5
7
0
1
2
1
0
0
0
0
0
0
0
0
12
6
7
8
Source: U.S. EPA, 2000, EPA-821-B-00-013.
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.
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. As shown in Exhibit 3-66, 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 percent of 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.
3-131
-------
§ 316(b) Phase III - Technical Development Document
Technology Cost Modules
There are numerous different types of offshore 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
oil and gas extraction facilities showed a wide range of cooling water demands (294 - 5,208,000 gal/day).4
1.1
Fixed Oil and Gas Extraction Facilities
Most of these structures (Figure 3-61) use a pipe with a passive screens (strainers) to convey cooling water. There are a number of
cooling water intake structure (CWIS) configurations for fixed facilities including sea chests (Figure 3-62), simple pipe (Figures 3-63
and 3-64), and caisson (Figures 3-66, 3-67, and 3-68). Perforated caissons or simple pipes have been used on some fixed platforms.
For example, the Marathon platform at South Ewing Bank (OCS Block 873) has a design intake flow of 4 MOD and uses a 24 inch
outer diameter simple pipe with square grid 0.5 inch perforations at the intake which translates to an intake velocity of 1 feet per
second. The Aera Energy Ellen (Beta) platform in offshore California withdraws 3.5 MOD and has two cooling water intakes
structures each with a through screen of 0.5 feet per second. This platform uses a simple 20 inch pipe with a 2 inch cone screen with
approximately 0.5 inch openings. This intake uses a 90/10 Cu/Ni alloy pipe for controlling biofouling.
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 GOM in 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 2003 Deepwater
Production Summary by Year. Abandoned platforms and platforms without production equipment were eliminated from the platform
count. The platforms were then categorized by deepwater and shallow water, and 20+ wells and < 20 wells. The counts are presented
in Exhibit 3-66. As the table shows, about 90 percent of platforms in the GOM are small platforms operating in shallow water. Only a
limited number of structures (generally not the typical fixed platforms) are found in the deepwater regions of the GOM. Currently
(2003 data) only 26 are considered build and operational in the MMS database.
Figure 3-61. Fixed Oil and Gas Extraction Facilities
Fixed
Platform
Compliant
Tower
Spar
(Subsea Wells)
Floating
Production
System
(Subsea Wells)
Tension
Platform
4U.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.
3-132
-------
§ 316(b) Phase HI - Technical Development Document
Technology Cost Modules
Figure 3-62. Offshore Seachest Cooling Water Intake Structure Design
TO Heal
Exchangers,
Oil Coolers.
Evaporators,
Rre Pumps and
Anaeitiaiy
Systems
Main Sea Valve
Sea
Cooling Line
Seawater
Inlet Grid
C2000
Electrodes
Seachest
Figure 3-63. Offshore Simple Pipe Cooling Water Intake Structure Design (Schematic)
3-733
-------
S 316(b) Phase III - Technical Development Document
Technology Cost Modules
Figure 3-64. Offshore Simple Pipe Cooling Water Intake Structure Design - Wet Leg
-Platform Leg Platform Leg
-J-Tube
, Sea Water
Seafloor
Note: Another configuration, the "J" Tube configuration, also uses simple pipes as a cooling water intake structure but with no
seawater in the platform leg.
Figure 3-65. Offshore Caisson Cooling Water Intake Structure Design (Thompson Culvert Company)
3-134
-------
§ 316(b) Phase III - Technical Development Document
Technology Cost Modules
Figure 3-66. Offshore Caisson Cooling Water Intake Structure Design - Leg Mounted Well Tower
LEG MOUNTED WELL TOWER
Figure 3-67. Offshore Caisson Cooling Water Intake Structure Design - Conventional Well Tower
CONVENTIONAL WELL TOWER
As built well tower opening
completely through rig
3-135
-------
§ 316(b) Phase HI * Technical Development Document Technology Cost Modules
Exhibit 3-67. Identification of Structures in the Gulf of Mexico OCS
Category
Total Number of Platforms
Removed Platforms
Abandoned Platforms
Platforms without Production Equipment
Producing Platforms - Deepwater
Producing Platforms - Shallow water + 20 slots
Producing Platforms - Shallow water < 20 slots
Total Producing Platforms
Count
6,266
2,229
21
1,587
26
209
2,194
2,429
Source: MMS. 2003. Deepwater production summary by year. U.S. Department of the Interior. Mineral Management Service.
The Offshore Operators Committee (OOC) and the National Oceans Industries Association (NOIA) also noted in their comments to
the 316(b) Phase I NODA (see May 25, 2001; 66 FR 28853) that a typical platform rig for a Tension Leg Platform5 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 required) is 13-21 MM Btu/hr. Assuming continuous once through cooling and a seawater temperature increase of 10 °C
between intake and discharge, the volume of seawater required for cooling these engines at a Tension Leg Platform can roughly be
estimated between 2.0 to 3.3 MOD (see DCN 7-3645).
OOC/NOIA also 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 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.
1.2 Mobile Oil and Gas Extraction Facilities
EPA also estimated the number of mobile offshore drilling units (MODUs) currently in operation (see Figure 3-68 for examples).
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.
Exhibit 3-67 gives a brief summary of each MODU. EPA and MMS could not identify any cases where the environmental impacts of
a MODU cooling water intake structure were considered.
5A Tension Leg Platform (TLP) is a fixed production facilities in deepwater environments (> 1,000 ft).
——
-------
§ 316(b) Phase III - Technical Development Document
Technology Cost Modules
Figure 3-68. Mobile Oil and Gas Extraction Facilities
Tender- Semisubmersible
Barge Assisted Rig Jaclcup (Moored)
<20m
<180m
<180m
Semi*ubmer*ible Drillship
(Dynamically (Dynamically
Positioned) Positioned)
50-1500m
> 1000m
>1000m
Exhibit 3-68. Description of Mobile Offshore Drilling Units and Their Cooling Water Intake Structures
MODU Type
Drill Ships
Semi-submersibles
Jack-ups
Submersibles
Drill Barges
Water Intake*
and Design
16 -20 MOD
Seachest
2 -15+ MOD
Seachest
2 -10+ MOD
Intake Pipe
<2MGD
Intake Pipe
<2MGD
Intake Pipe
Water Depth
Greater than 400 ft
Greater than 400 ft
Less than 400 ft
Shallow Water (Bays and Inlet
Waters)
Shallow Water (Bays and Inlet
Waters)
Estimate of the Number
of Existing MODUs**
11
63
192
47
70
Sources: 1) Johnston, Carey A. U.S. EPA, Memo to File, Notes from April 4,2001 Meeting with US Coast Guard. April 23, 2001,
DCN 2-012A. 2) ODS-Petrodata Group, Offshore Rig Locator, Houston, Texas, Vol. 28, No. 4, April 4, 2001. 3) Spackman, Alan,
International Association of Drilling Contractors, Comments on Phase 1316(b) Proposed Rule, Comment Number 316bNFR.004.001.
4) Spackman, Alan, International Association of Drilling Contractors, Memo to Carey Johnston, U.S. EPA, 316(b), May 8,2001.
* 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.6
** MODU count from DCN 7-3657, Record Section 1.1.3.
'Johnston, Carey A. U.S. EPA, Memo to File, Notes from April 4, 2001 Meeting with US Coast Guard.
April 23, 2001, DCN 2-012A.
3-137
-------
S 316(b) Phase in - Technical Development Document Technology Cost Modules
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.7
a. Drillships and Semi-Submersibles MODUs
Drill ships and semi-submersibles use a "sea chest" as a cooling water intake structure.8 In general there are three pipes for each sea
chest (these include cooling water intake structures 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 (Comment Number 316bNFR.004.001). 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 (DCN 2-012A).
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. For example, the Transocean Deepwater Horizon semi-submersible MODU withdraws 16.0 MGD and
has eight cooling water intakes structures each with a through screen velocity of 0.5 feet per second. This MODU uses sea chests
openings of 24.4 inch by 28.7 inch with single simplex strainers in the sea chest. The sea chest screens are simple passive strainers
with a one inch grid opening. The Transocean Cajun Express semi-submersible MODU withdraws 6.1 MGD and has six cooling
water intakes structures each with a through screen of 0.23 feet per second. This MODU uses sea chests openings of 32 inches in
diameter with 14 inch by 8 inch corrugated basket strainers in the sea chest. The sea chest screens are simple passive strainers with a
one inch grid opening.
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 (DCN
2-012A). Drill ships have their sea chests on the bottom of their hulls and are typically 20 to 40 feet below water at all times.
The International Association of Drilling Contractors (I ADC) notes that one of the earlier semi-submersible designs still in use is the
"victory" class unit (Spackman, May 8, 2001). This unit is provided with two seawater-cooling pumps, each with a design capacity of
2.3 MGD 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 per second.
The more recent semi-submersible designs typically have higher installed power to meet the challenges of operating in deeper water,
harsher environmental conditions, or for propulsion or positioning. I ADC notes that a newly-built unit, of a new design, has a
seawater intake capacity of 34.8 MGD, which includes salt water service pumps and ballast pumps, and averages 10.7 MGD of
seawater intake of which 7.4 MGD is for cooling water.
b. Jack-up MODUs
Jack-up, submersibles, and drill barges use intake pipes for cooling water intake structures. These facilities 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 these facilities (e.g., drawworks brakes).
7Spackman, Alan, International Association of Drilling Contractors, Memo to Carey Johnston, U.S. EPA,
316(b),May8, 2001.
8 A sea chest is an underwater compartment within the vessel's hull through which sea water is drawn in or
discharged. A passive screen (strainer) is set along the flush line of the sea chest. Pumps draw seawater from open
pipes in the sea chest cavity.
__
-------
S 316(b) Phase III - Technical Development Document Technology Cost Modules
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 (Comment Number 316bNFR.004.001). 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 (Spademan May 8,2001). 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 feet per second (Spademan May 8, 2001). Additionally, pre-
loading involves the use of two or three pumps in sequence. Pre-loading is not a cooling water procedure, but a ballast water (which is
later discharged).9 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.
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 (Spademan May 8, 2001). 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. IADC reports that a newly-built jack-up, of a new
design, typically requires 3.17 MGD of cooling water for its drawworks brakes and cooling of six diesel generator units, each rated at
1,845 horsepower (Spademan May 8,2001). 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 MGD.
c. Submersibles and Drill Barge MODUs
The submersible MODU is 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 MGD.
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.
2.0 PHASE III INFORMATION COLLECTION FOR OIL AND GAS EXTRACTION FACILITIES
Numerous researchers and State and Federal regulatory agencies have studied and controlled the discharges from oil and gas extraction
facilities for decades. The technology-based standards for the discharges from these facilities are located in 40 CFR 435. Conversely,
there has been little work done to investigate the environmental impacts or evaluation of the location, design, construction, and
capacity characteristics of cooling water intake structures for offshore oil and gas extraction facilities.
In developing the Phase III proposal, EPA used a variety of sources to identify data on the current status of the oil and gas extraction
industry and the cooling water intake structures associated with these facilities. Sources of data included; consultations with the two
main regulatory entities of this industrial sector (i.e., USCG, MMS), an EPA survey of the industry which collected both economic and
technical data, technical data submittals from industry which were provided either directly or through various trade associations, and
information available from the internet. Each of these sources of information are described in more detail below.
2.1 Consultations with USCG and MMS
The U.S. Coast Guard (USCG) and the Department of Interior's Mineral Management Services (MMS) agency identified no specific
regulatory requirements for this industrial sector with respect to potential environmental impacts associated with cooling water intake
structures. The USCG does not investigate potential environmental impacts of MODU cooling water intake structures but does require
Vlahos, G., Martin, C.M., Cassidy, M.J., 2001. Experimental Investigation of a Model Jack-Up Unit on
Clay, Proceedings of the Eleventh (2001) International Offshore and Polar Engineering Conference, Stavanger;
Norway, June 17-22,2001.
3-139
-------
S 316(b) Phase III - Technical Development Document Technology Cost Modules
operators to inspect sea chests twice in every five year period and conduct at least one cleaning to prevent blockages of firewater lines.
EPA met with Mr. James Magill of USCG, Vessel and Facility Operating Standards Division to collection information on MODU
operations and cooling water intake systems.10
MMS is the Federal agency responsible for managing Outer Continental Shelf (OCS) mineral resources. MMS has authority for
leasing in OCS and therefore has current lists of owner-operators and lessees. EPA used the MMS website, MMS Platform Inspection
System, Complex/Structure database, Lessees/Operators financial information, MMS's environmental impact statements,
environmental assessments, and other MMS sponsored studies to collect information to support the Phase III proposal.
Specifically, EPA used the MMS databases to estimate the number of fixed OCS platforms in the Gulf of Mexico. EPA also used
facility information from the Alaska OCS Region office to determine the number of facilities in the OCS. The Pacific OCS Region
website provided general information on oil and gas production facilities in the Pacific OCS Region. No information on the number of
facilities in State waters and Coastal waters were found. EPA used the MMS environmental impact statements, environmental
assessments, and other MMS sponsored studies to evaluate impact on marine organism assemblages from offshore oil and gas
exploration and production. In general, MMS did not have information on cooling water intake structures for oil and gas extraction
facilities.
EPA identified one case in the MMS files where they evaluated potential environmental impacts from an oil and gas extraction facility
cooling water intake structure as part of their NEPA analyses. This analysis was conducted as part of BP Exploration Inc. (BPXA)
plans to locate a vertical intake pipe for a seawater-treatment plant on the south side of Liberty Island, Beaufort Sea, Alaska. Figure 3-
69 depicts the cooling water intake structure planned for the BPXA sea-water treatment plant. 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. 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.
'"Memorandum: Notes from April 4,2001 Meeting with U.S. Coast Guard. From: Carey A. Johnston,
USEPA/OW/OST, To: File, May 7,2001.
3-140
-------
§ 316(b) Phase HI - Technical Development Document
Technology Cost Modules
Figure 3-69. Liberty Island Cooling Water Intake Structure
DOCK SURFACE
DOCK SURFACE
MLLW
El if
C 36-INLET UNE
'" ~ EL •«••«•
.. r SEAWATER REOHCUIATION PIPES
t'-OW-r SEAWATER RET OPEMNQ
SEAWATER FLOW
BOTTOM OF SCREEN
TRAP
fifi
COMCRETJ: «
KTAKEUOEL10
TOP OF FISH SCREEN
I MU.W
-
, SEAWATER FLOW Kg
-I5S'
EL-I?
SIDE ELEVATION
FRONT ELEVATION
MLLW = Mean Lower Low Water
Source BPXA. 199Bb
ALL DIMENSIONS ARE APPROXIMATE
MMS states in the Liberty Island 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 Island 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. However, essential fish habitat for salmon
will be adversely affected according to MMS because it is expected that prey species of zooplankton and fish in their early life stages
(juveniles, eggs, and larvae) could be killed in the intake.
More recently, MMS assisted EPA by providing an initial annotated bibliography on all available research reported in marine and
coastal waters concerning the impingement and entrainment of estuarine and marine organisms by cooling-water intake systems."
Most of the results obtained through this search were references about studies on fish impingement or entrainment by cooling-water
intakes of nuclear or thermoelectric power plants located on estuarine or marine environments. MMS did not identify any references
specific to fish impingement or entrainment by cooling-water intakes of oil and gas extraction facilities. MMS concluded that studies
"MMS, 2003. "Marine and Coastal Fishes Subject to Impingement by Cooling-Water Intake Systems in the
Northern Gulf of Mexico: An Annotated Bibliography," MMS 2003-040, August 2003.
3-141
-------
§ 316(b) Phase III - Technical Development Document
Technology Cost Modules
of impingement or entrainment by cooling-water intakes of oil and gas extraction facilities are generally unavailable through the
searched databases.
2.2 EPA 316(b) Phase III Survey
In September 2003, EPA sent out a 316(b) Phase III survey to oil and gas extraction facilities to collect technical and economic data
related to these types of facilities and their cooling water intake structures. EPA surveyed 90 facilities as part of this effort and
received responses from 78 facilities. Exhibit 3-69 presents a breakout of the number of surveys mailed and responses by type of
survey.
Exhibit 3-69.316(b) Phase III Survey Statistics
Industry/Type of Survey
Oil & Gas Platforms (Technical
and Economic Survey)
Oil & Gas Platforms (Economic
Survey only)
MODU's (Economic Survey only)
Total
No. of Surveys Mailed
55
5
30
90
No. of Survey Responses
52
3
23
78
Source: Phase III Technical Questionnaire Tracking Report, From: Kelly Meadows, TetraTech, Date: 3/12/2004 (revised 3/23/2004).
EPA identified companies to survey based on a sampling frame of facilities expected to be in-scope. When a facility's eligibility was
unknown, it was retained in the sampling frame. The sampling design selected by EPA included stratification of facilities based on the
type of structure and its location. The stratification categories used in the survey included:
1. Gulf of Mexico Platforms - Deep Water
2. Gulf of Mexico Platforms - More than 20 Slots
3. Gulf of Mexico Platforms - Shallow Waters
4. California Platforms
5. Alaska Platforms
6. MODUs
These strata were chosen because they were expected to correspond to major differences in economic variables and also in the
technology costs of implementing controls on impingement and entrainment. The survey samples were selected from lists for each of
the subpopulations. A systematic sample with a random start was taken.
Exhibit 3-70 presents the number of facilities estimated to be in-scope in each of these strata and the number that were sampled in the
survey.
3-142
-------
§ 316(b) Phase HI - Technical Development Document
Technology Cost Modules
Exhibit 3-70. Number of In-Scope Facilities and Number Sampled by Frame
Sampling Stratification Frame
Gulf of Mexico Platforms - Deep
Water
Gulf of Mexico Platforms - More
than 20 Slots
Gulf of Mexico Platforms -
Shallow Waters
California Platforms
Alaska Platforms
MODUs
All Frames
Number of Facilities
Estimated to be In-Scope
24
206
2,194
20
19
- 404
. 2,867
Number of Facilities
Sampled
4
33
18
3
2
30
90
Source: Memorandum: Sampling Selection for Offshore Oil & Gas - TD#W040917a dated September 17,2003, From: G. Hussain
Choudhry and mho Park, Westat, To: John Fox, EPA, Date: October 7,2003.
Economic and technical data submitted as part of the responses were used by EPA in the economic and costing analyses conducted as
part of the Phase III proposal.
2.3 Technical Data Submittals from Industry
EPA received the majority of its technical cooling water intake structure data from industry either directly or through industry trade
associations. The trade associations supporting and providing data submittals included the:
• International Association of Drilling Contractors (I ADC)
Offshore Operators Committee (OOC)
Western States Petroleum Association (WSPA)
• Louisiana Mid-Continent Oil and Gas Association (LMOGA)
I ADC provided cooling water intake structures information, solicited from its members, for over 140 mobile offshore drilling units
operating in or marketed for operations in areas under the jurisdiction of the U.S. In addition, the 2002IADC membership directory
listed companies that represent a significant portion of the world's exploration and production activity. The directory information
included, names of key personnel, addresses of both headquarter and branch locations, telephone and fax numbers, and internet
addresses. The contractor directory also provided an alphabetical listing of drilling contractors who own and operate the vast majority
of the world's land and offshore drilling units. That listing included the names of key personnel, addresses of both headquarter and
branch locations, telephone and fax numbers, internet addresses, the size of each firm's rig fleet and operating theaters, and for
offshore units, the rig type. The IADC submittals and directories did not include any economic information.
The OOC provided information, compiled on behalf of its members, on cooling water intake structures for offshore oil and gas
extraction facilities in the Gulf of Mexico. Cooling water intake structure data were provided for 21 fixed platforms and no economic
information were included. EPA was able to identify that 16 of the 2,429 fixed facilities and 87 of the 383 MODUs in the GOM
withdrew more than 2 MOD of seawater with more than 25% used for cooling (see Figures 3-70 and 3-71 for display of fixed
facilities).
Operators in Cook Inlet, Alaska, also provided information to EPA on cooling water intake structures for Cook Inlet platforms. The
oil and gas fields in Cook Inlet are considered mature and since 1995 production in the Trading Bay Field, Granite Point Field, Middle
Ground Field, and Tyonek platform declined from 17 to 92 percent. Consequently, fewer wells are being drilled in Cook Inlet and this
means less equipment requires cooling. For example, the Spark and Spurr platforms have not operated their cooling water systems in
over 7 years. These two cooling water system were decommissioned by their operator. Currently these two platforms are unmanned,
remotely operated, gas production facilities without drilling, compression, or fire water suppression systems. Using industry data EPA
3-143
-------
§ 316(b) Phase in - Technical Development Document Technology Cost Modules
was able to identify that five of the 16 fixed platforms in Cook Inlet withdrew more than 2 MGD of seawater with more than 25% used
for cooling (see Figure 3-72).
The WSPA provided information, compiled on behalf of its members, on cooling water intake structures for offshore oil and gas
extraction facilities off the coast of California. Cooling water intake structure data were provided for 18 fixed platforms and no
economic information were included. Using this data EPA was able to identify that six of the 32 fixed platforms withdrew more than 2
MGD of seawater with more than 25% used for cooling (see Figure 3-72).
3-144
-------
S 316(b) Phase III - Technical Development Document
Technology Cost Modules
Figure 3-70. Gulf of Mexico Oil and Gas Extraction Facilities
If!'! ^rcdjfo* 5?!i£?llI£5J
Final Environmental Impact Statement for the Generic Essential Fish Habitat, Gulf of Mexico Fishery Management Council, March 2004.
Source:
3-145
-------
S 316(b) Phase HI - Technical Development Document
Technology Cost Modules
Figure 3-71. Gulf of Mexico Oil and Gas Extraction Facilities That Withdraw More than 2 MGD of Seawater with More than
25% of the Intake Is Used for Cooling
Port Lava ca
G U t f Of
Mexico
Figure 3-72. Cook Inlet, Alaska, Oil and Gas Extraction Facilities
Note^latforms marked in red withdraw more than 2 MGD of seawater with more than 25% of the intake used for cooling.
3-146
-------
§ 316(b) Phase III - Technical development Document
Technology Cost Modules
Figure 3-72. California Oil and Gas Extraction Facilities
Lomi
Pacific Ocean
Channel
Island* Said* CataJin*
Island
San Nicolas Island
B(
oAvaton
GutfofSanti
CstaSna
Note: Platforms marked in red withdraw more than 2 MOD of seawater with more than 25% of the intake used for cooling.
The LMOGA represents facilities located in the state and includes those facilities located in state-waters of the Gulf of Mexico.
LMOGA contacted its trade association members asking for information on water withdrawal rates. All respondents to the LMOGA
data request indicated that they use less than 2 MGD of surface water. Again, no economic information was provided.
All technical information provided by industry and collected as part of the EPA Phase III survey for oil and gas exploration facilities
was compiled into an Excel datasheet for use in costing existing in-scope facilities for cooling water intake structure control. That
database is located in the rulemaking record (see DCN 7-3505, section 8.0).
2.4 Internet Sources
EPA collected pertinent information on the identity, number, and location of oil and gas extraction facilities from five websites:
The California Environmental Resources Evaluation System (http://www.ceres.ca.govX
The Alabama State Oil and Gas Board (http://www.oeb.state.al.us ),
The Texas Railroad Commission (http://www.rrc.state.tx.us/),
World Oil (http://www.worldoil.com/),
Rig Zone (http://www.rigzone.com), and
Drilling Contractor websites.
None of these websites provided technical information on cooling water intake structures or facility economic data. Exhibit 3-72
presents a description of the type of information that was collected from each site.
3-147
-------
S 316(b) Phase III - Technical Development Document
Technology Cost Modules
Exhibit 3-72. Oil & Gas Extraction Facilities - Information Collected from Internet Sources
Source
Information Collected
California Environmental
Resources Evaluation
System Website
This site contained an Oil, Gas, and Mineral Resources Background article. The article states there are
twenty-six production platforms, one processing platform and six artificial oil and gas production
islands located in the waters offshore California. Of the twenty-seven platforms, four are located in
State waters offshore Santa Barbara and Orange Counties, and twenty-three are located in Federal
waters offshore Santa Barbara, Ventura and Los Angeles Counties. Four platforms in State waters off
Santa Barbara County were abandoned and removed in 1966. The site did not include cooling water
intake structure or economic information.
Alabama State Oil and
Gas Board Website
According to the Alabama State Oil and Gas Board website, there are 44 total structures in the state
waters: 14 single well caissons; 11 well platforms; 4 well/production platforms; 4 bridge-connected
well platforms; 1 bridge-connected well/production platform; 8 production platforms; 1 bridge-
connected living quarters platform; and 1 gathering platform. The site does not contain any technical
information on cooling water intake structure or economic information. The Alabama Offshore Fields
database provides field name, county name, operator of the field, producing formation, date
established, total wells, producing wells, monthly production, and cumulative production. The list of
oil and gas operators in Alabama provides operator name, address, telephone and fax number.
Texas Railroad
Commission Website
The Texas Crude Oil Production - Offshore State Waters database contains Railroad Commission
district number, field name, county, gas well, condensate, and cumulative gas production. The Texas
Gas Well Production - Offshore State Waters contains Railroad Commission district number, field
name, county, monthly production for December 2002, year-to-date production January to December
2002, and cumulative oil production. This site does not have information on the number of facilities in
State waters or cooling water intake structures.
World Oil Website
This site includes the World Oil's Marine Drilling Rigs 2002/2003 Directory which lists performance
data for 635 mobile offshore drilling units. Listings are separated into four categories, including
jackups, semisubmersibles, drillships and barges, excluding inland barges, submersibles. Owners and
rigs are listed alphabetically, with rigs grouped by class under a typical photograph. The directory
provided EPA with a list of mobile offshore drilling units in US water. This site did not contain
information on cooling water intake structures for mobile offshore drilling units.
Rig Zone Website
This site includes a search engine which provided the location of drill barges, drillships, inland barges,
jackups, semisubmersibles, and submersibles worldwide. The site provided a list of mobile offshore
drilling units currently in U.S. waters.
Drilling Contractor
Websites
These sites provide information on offshore oil and gas drilling contractors. These sites include:
- ENSCO Website (http://www.enscous.com/RigStatus.asp?Content=AH),
- Noble website (http://www.noblecorp.com/rig/foverviewfrX.html), and
- Rowan Website (http://www.rowancompanies.comA)
- Transocean (http://www.deepwater.com/StatusandSpecs.cfrn)
- Nabors (http://www.nabors.com/offshore/default.asp)
ENSCO has 53 offshore rigs servicing domestic and international markets and two rigs under
construction. Its website includes a listing of ENSCO rigs with drilling equipment specifications (e.g.,
power plant and drawwork brake specifics) including information on available horsepower. Noble has
59 offshore rigs servicing domestic and international markets. Its website includes a listing of Noble
rigs with drilling equipment specifications including information on available horsepower. Rowan has
25 offshore rigs servicing domestic and international markets. Its website identifies the companies rig
utilization rate. Transocean has 95 offshore rigs and 70 shallow and inland water mobile drilling units
servicing domestic and international markets. Its website includes a listing of Transocean rigs with
drilling equipment specifications including information on available horsepower. Nabors markets 26
platform, nine jackup and three barge rigs in the Gulf of Mexico market. These rigs provide
well-servicing, workover and drilling services. Its website identifies the companies rig utilization rate.
3-148
-------
§ 316(b) Phase III - Technical Development Document Technology Cost Modules
2.5 Regulatory Agencies
EPA also contacted State regulatory agencies in Alaska, Florida, Alabama, Mississippi, Louisiana, and Texas to determine if they had
any specific regulatory requirements for this industrial sector with respect to potential environmental impacts associated with cooling
water intake structures. Only Alaska and Alabama provided information to EPA.
The State of Alaska has a standard clause in their oil and gas leasing agreements which controls potential impingement and
entrainment impacts from oil and gas extraction facilities. EPA contacted Alaska Department of Natural Resources (AKDNR) to
confirm that this clause (see below) is standard for all Alaska leasing statements and how the State ensures compliance with this
mitigation measure throughout the duration of the lease.12
Water intake pipes used to remove water from fishbearing waterbodies must be surrounded by a screened enclosure to prevent
fish entrainment and impingement. Screen mesh size shall not exceed 0.04 inches unless another size has been approved by
Alaska Department of Fish and Game. The maximum water velocity at the surface of the screen enclosure may be no greater
than 0.1 foot per second.
AKDNR confirmed that this clause is standard in all Alaska leasing statements in order to control impingement and entrainment
impacts from oil and gas extraction facilities in Alaska state waters. This clause was developed by the Alaska Department of Fish and
Game (AKDFG). Most water withdrawals occur on the North Slope for building ice roads and ice pads.
AKDNR also stated that the impingement and entrainment mitigation measures are first enforced when they review the oil and gas
extraction plan of operations. A facility seeking approval from the State to begin operations must identify in their plans whether it is
proposing any surface water withdrawals. They must also identify the source of the surface water, re-state compliance with the
standard clause, or the need for a variance. The withdrawal will also require water withdrawal permits from AKDNR. As a matter of
practice, unless there was some reason to believe the operator was not meeting the standard, the intake would not be inspected by
AKDNR or AKDFG (Schmitz e-mail).
Alabama state law requires facilities to register water withdrawals (with capacities in excess of 100,000 gallons per day) with the
Office of Water Resources (OWR) within the Alabama Department of Economic and Community Affairs (ADECA). However, OWR
does not track water withdrawal facilities in Alabama by industry specific codes (i.e. SIC).13 They register facilities under one of three
categories: public, non-public and irrigation. Consequently, OWR does not have any useful records on whether oil and gas extraction
facilities in Alabama state waters withdraw more than 100,000 gallons per day. Additionally, the Alabama State Oil and Gas Board
and the Alabama Petroleum Council were contacted by the Alabama Department of Environmental Management on behalf of EPA.
Both Alabama State Oil and Gas Board and the Alabama Petroleum Council estimate that cooling water withdrawals for the oil and
gas extraction industry in Alabama waters should be considered de minus.™ This estimate is also consistent with data provided by
LMOGA.
EPA also contacted a few foreign regulatory agencies who control environmental impacts from oil and gas extraction facilities in their
country's waters. Responses from these foreign regulatory agencies confirm that they have not: (1) investigated any potential
impingement or entrainment impacts of surface water intakes at oil and gas extraction facilities; or (2) established any standards for
controlling impingement or entrainment impacts for the oil and gas extraction industry.15
"2E-mail communication between Steve Schmitz, AKDNR, and Carey A. Johnston, EPA, August 21,2003.
13E-mail communication between Tom Littlepage, ADECA, and Carey A. Johnston, EPA, April 21, 2004.
'"Letter from Glenda L. Dean, ADEM, to Mary T. Smith, EPA, March 30, 2004.
l5Memo to record, C. Johnston, August 17, 2004
___
-------
§ 316(b) Phase III - Technical Development Document Technology Cost Modules
3.0 FACILITIES IN THIS INDUSTRIAL SECTOR WHICH EPA EVALUATED FOR THE PHASE III RULEMAKING
As previously mentioned, EPA did not consider new offshore oil and gas extraction facilities in the 316(b) Phase I - New Sources
rulemaking. Consequently, EPA evaluated as part of the Phase III proposed rule the technology options available to control
impingement and entrainment of aquatic organisms for both existing and new offshore oil and gas extraction facilities.
4.0 TECHNOLOGY OPTIONS AVAILABLE TO CONTROL IMPINGEMENT AND ENTRAINMENT OF AQUATIC
ORGANISMS
4.1 Summary of Technology Options to Control Impingement and Entrainment of Aquatic Organisms
There are three main technologies applicable to the control of impingement and entrainment of aquatic organisms for cooling water
intakes: passive intake screens, velocity caps, and modification of an intake location. Passive intake screens cover a whole range of
static screens that act as a physical barrier to fish entrainment. These barriers include simple mesh over an open pipe end with a
suitably low face velocity to prevent impingement, grille or mesh spanning an opening with a suitably low face velocity to
impingement, and cylindrical and tee wedgewire screens designed for protecting fish stocks (Figure 3-74). A velocity cap is a device
that is placed over vertical inlets at offshore intakes (Figure 3-75). This cover converts vertical flow into horizontal flow at the
entrance of the intake. The device works on the premise that fish will avoid rapid changes in horizontal flow. Beyond design
alternatives, a facility may also be able to locate their cooling water intake structures in areas that minimize entrainment and
impingement. Near shore coastal waters are generally the most biologically productive areas. The zone of photosynthetic available
light typically does not extend beyond the first 328 feet of depth. Modification of an intake location may therefore be implemented by
adding an extension to the bottom of an existing intake to relocate the opening to a low impact area. To identify low impact areas, an
environmental study or assessment is required.
EPA believes that the cost of modifying existing structures with deeper intakes will be significantly greater than the equipment costs
associated with screens and velocity caps. In addition, the need for an environmental assessment to identify a lower impact zone for
modified intakes would result in additional cost and time constraints. Therefore, EPA did not include modification of an intake
location as part of their proposed technology options.
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. However, 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. See
Chapter 6 of the Phase I TDD for additional information.
EPA also considered but did not estimate costs associated with dry cooling options for oil and gas extraction facilities. The following
items are typically direct air cooled at oil and gas extraction facilities: gas coolers on compressors, lubrication oil coolers on
compressors and generators, and hydraulic oil coolers on pumps. However, seawater cooling is necessary in many cases because
space and weight limitations render air cooling for all oil and gas extraction equipment infeasible. This is particularly true for floating
production systems which have strict payload limitations. 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. See
Chapter 6 of the Phase I TDD for additional information.
The technologies EPA evaluated for cooling water intake structures at offshore oil and gas extraction facilities depend on the type of
cooling water intake structure and the rig type (rig types are described in section 1.0). The cooling water intake structure types include
simple pipes, caissons, and submerged pump intakes, and sea chests. The impingement and entrainment control technologies EPA
identified for this sector (passive intake screens, velocity caps, and modification of an intake location) are being used at other
industries with marine intakes and are also being proposed for new LNG import terminals. In particular, the Main Pass Energy Hub
LNG import terminal is converting an existing offshore platform to an LNG import terminal and installing technology (cylindrical
wedgewire screens) that would meet the proposed impingement and entrainment standards for new oil and gas extraction facilities.
Based on similarities in intake structures, EPA is transferring these impingement and entrainment control technologies to this industrial
sector.
A simple intake pipe, as the name suggests, is a pipe that is open ended in the water. A pump will draw water up through the pipe for
distribution as required by the process. These systems generally include a strainer to protect the pump and, if the pump is above water
level, a non-return valve to help keep the system primed. A caisson is a steel pipe attached to a fixed structure that extends from an
operating area down some distance into the water. It is used to provide a protective shroud around another process pipe or pump that
__
-------
§ 316(b) Phase HI - Technical Development Document
Technology Cost Modules
is lowered into the caisson from the operating area. A caisson to house seawater intake equipment is a very common arrangement for
offshore oil and gas extraction facilities. Typical equipment installed in the caisson may be a simple suction pipe, submersible pump
and discharge pipe or a shaft driven borehole/vertical turbine pump. All caisson arrangements have the similarity that seawater is
drawn into a single opening at the bottom of the caisson. Submersible pumps are simply lowered off the deck of a unit into the water
without caissons or shrouds and pump water up through an intake pipe.
A sea chest is a cavity in the hull or pontoon of a MODU and is exposed to the ocean with a passive screen (strainer) often set along
the flush line of the sea chest. In general there are three pipes for each sea chest (these include cooling water intakes and fire pumps).
One of the three intake pipes is used for emergency fire fighting operations and the other pipes for cooling water. These pipes are
usually back on the flush line of the sea chest.
For simple pipes, caissons and submerged pump intakes, cooling water intake structure control technologies include velocity caps or
cylindrical wedgewire screens. Velocity caps result in impingement control and cylindrical wedgewire screens result in both
impingement and entrainment control and are designed to create an intake velocity of equal to or less than 0.5 feet per second.
Additionally, cylindrical wedgewire screens can be fitted with air sparges to physically remove bio matter from a screen face. This is
a suitable technology in most marine environments and is useful for intakes above about 50 foot depth. In situations where there are
prolific marine organisms that may grow on the screen surface (such as mussels, corral, or seaweed growth), alternative materials of
construction may be needed to protect the screen. Alloys of copper and nickel have been found to limit marine growth on a submerged
surface. These alloys are used in the manufacture of screen surfaces to prevent problems with invasive marine growth and cylindrical
wedgewire screens can be costed using this material of construction.
For sea chests, cooling water intake structure control technologies include horizontal flow diverters and/or flat panel wedgewire
screens. Horizontal flow diverters result in impingement control while flat panel wedgewire screens result in entrainment control. To
achieve both impingement and entrainment control on a sea chest, both the flat panel wedgewire screen and a horizontal flow diverter
are required. As in the case with cylindrical wedgewire screens, flat panel screens can also be manufactured using copper-nickel alloy
material.
Exhibit 3-72 presents the Phase III cooling water intake structure control regulatory options and the technologies applicable to each
option. The appropriate control technologies are a function of the cooling water intake structure and rig type.
Figure 3-74. Cylindrical Wedgewire Screen (Johnson Screens)
3-151
-------
§ 316(b) Phase III - Technical Development Document
Technology Cost Modules
Figure 3-75. Schematic of Seabed Mounted Velocity Cap
OUtrtJrction Without C«p Velocity Distribution With Cap
Exhibit 3-72. Regulatory Options and the Technologies Applicable to Each Option
Option
Requirements
Type of Rig
Platforms and
Drill Barges which
use simple pipes
and caissons for
cooling water
intake
Jack Ups
which use sea
chests while in
transport and
simple pipes/
caissons when
stationary for
cooling water
intake
Option A
I&E control for
facilities with >2
MOD
Option A
Cylindrical
Wedgewire
Screens for >2
MOD
Cylindrical
Wedgewire
Screens plus Flat
Panel Wedgewire
Screens and
Horizontal Flow
Diverter for >2
MOD
Option B
I control for
facilities with >2
MOD
Option B
Velocity Caps for
>2MGD
Horizontal Flow
Diverter and
Velocity Caps for
>2MGD
Option C
I&E control for
facilities with > 50
MOD and I control
for facilities with
2-50 MOD
Option C
Cylindrical
Wedgewire
Screens for > 50
MGD and Velocity
Caps for 2-50
MGD
Cylindrical and
Flat Panel
Wedgewire
Screens plus
Horizontal Flow
Diverter for pipes
and sea chests for
>50 MGD and
Velocity Caps and
Horizontal Flow
Diverter for 2-50
MGD
Option D
I&E control for
facilities with > 50
MGD
Option D
Cylindrical
Wedgewire
Screens for >50
MGD
Cylindrical
Wedgewire
Screens plus Flat
Panel Wedgewire
Screens and
Horizontal Flow
Diverter for > 50
MGD
Option E
I control for
facilities with > 50
MGD
Option E
Velocity Caps for
>50 MGD
Horizontal Flow
Diverter and
Velocity Caps for
> 50 MGD
3-152
-------
S 316(b) Phase IH - Technical Development Document
Technology Cost Modules
Exhibit 3-72. Regulatory Options and the Technologies Applicable to Each Option (continued)
Type of Rig
Submersibles,
Semi-submersibles
and Drill Ships
which use sea
chests for cooling
water intake
Option A
Flat Panel
Wedgewire
Screens and
Horizontal Flow
Diverter for >2
MOD
Option B
Horizontal Flow
Diverter for >2
MOD
Option C
Flat Panel
Wedgewire
Screens and
Horizontal Flow
Diverter for >50
MOD and
Horizontal Flow
Diverter for 2-50
MOD
Option D
Flat Panel
Wedgewire
Screens and
Horizontal Flow
Diverter for >50
MOD
Option E
Horizontal Flow
Diverter for >50
MOD
I = Impingement Control (includes velocity caps and horizontal flow diverters)
I&E = Impingement and Entrainment Control (includes cylindrical wedgewire screens and flat panel wedgewire screens with a
horizontal flow diverter)
4.2 Incremental Costs Associated with Technology Options to Control Impingement and Entrainment of Aquatic Organisms
This section documents the costs developed for cooling water intake structure control on existing "in-scope" offshore oil and gas
extraction facilities evaluated for the proposed Phase III rulemaking. This section includes a description of:
• In-Scope Facilities for Costing;
• Source of the Costing Equations and Assumptions; and
Summary of the Capital and Operation and Maintenance (O&M) Costs.
4.2.1 Existing In-Scope Facilities for Costing
EPA developed incremental compliance costs for existing offshore oil and gas extraction facilities if they met two criteria. The first, is
that the facility had design or actual water intake flows of greater than 2 MOD and the second is that there were data (or a documented
assumption) to support a determination that 25 percent or greater of the intake water (on an intake flow weighted basis) is used for
cooling purposes.
Using the Excel datasheet which included all technical information collected on existing oil and gas extraction facilities and their
cooling water intake structures, EPA assessed which facilities had data supporting an "in-scope" determination and sufficient
information to assess costs. In this datasheet, some MODUs did not have cooling water flow data for the 25 percent or greater cooling
water criteria assessment. Based on EPA's data from the USCG, it was assumed that most MODUs use approximately 80% of their
intake water for cooling purposes and therefore meet the second "in-scope" criteria. The facilities identified as "in-scope" for costing
are presented in the proposal record (see DCN 7-3505, section 8.0).
4.2.2 Source of Costing Equations and Assumptions
EPA developed costs for screens, velocity caps, and horizontal flow diverters using capital and operating and maintenance (O&M)
cost data from vendors and the following assumptions: (1) 10% engineering factor; (2) 10% contingency factor; and (3) an allowance
of 6% of the capital cost for annual parts replacement. The capital and O&M equipment costs are summarized by pipe diameter (or by
sea chest flow rate) in the Hatch Report16 which is located in the proposal record (see DCN 7-0010). Using these costs per pipe
diameter (or costs per sea chest flow rate), EPA developed linear costing equations which were then used to develop facility specific
costs.
Exhibits 3-74 through 3-77 present the costing equations and their source for each technology costed. Costs were prepared for both
stainless steel flat panel and cylindrical wedgewire screens and also for copper-nickel (Cu-Ni) flat panel and cylindrical wedgewire
""Hatch Report, "Offshore and Coastal Oil and Gas Extraction Facilities Seawater Intake Structure
Modification Cost Estimate: Mobile Offshore Drilling Units (MODUs)" and "Offshore and Coastal Oil and Gas
Extraction Facilities Seawater Intake Structure Modification Cost Estimate: Caisson and Simple Pipe Intakes",
March 12, 2004.
3-753
-------
§ 316(b) Phase III - Technical Development Document Technology Cost Modules
screens. Costs were also developed for cylindrical wedgewire systems with air sparging and without. Air sparging is used for
cylindrical wedgewire screens installed in waters of shallow to medium depth (pipe depth less than 200 feet) to help prevent biofouling
of the wedgewire screen. Copper-nickel screen material is more expensive than stainless steel but has also been shown to have a
greater resistance to biofouling. In addition, costs were developed for both side and bottom horizontal flow diverters as well as
velocity caps.
3-154
-------
§ 316(b) Phase III - Technical Development Document
Technology Cost Modules
Exhibit 3-73. Installed Capital Cost Equations and Variables for Stationary Platforms
Category
Platform
Platform
Platform
CWIS Type
Simple Pipe or
Caisson
Simple Pipe or
Caisson
Simple Pipe or
Caisson
Description
Stainless steel
wedgewire screen -
no air sparge
cleaning
Stainless steel
wedgewire screen -
with air sparge
cleaning
CuNi wedgewire
screen - no air
sparge cleaning
Cost Equations
$ = 585.1 x dia +1 13,231 Single CWIS <60'
$ = (417.8 x dia + 15,993) x (No. CWIS - 1) Additional CWIS <60'
$ = 585.1 x dia + 161,981 Single CWIS 60-200'
$ = (417.8 x dia + 24,493) x (No. CWIS - 1) Additional CWIS 60-200'
$ = 585.1 x dia + 265,481 Single CWIS 200-350'
$ = (417.8 x dia + 27,993) x (No. CWIS - 1) Additional CWIS 200-350'
$ = 585.1 x dia + 326,981 Single CWIS >350'
$ = (417.8 x dia + 38,493) x (No. CWIS - 1) Additional CWIS >350'
$ = 1 100.1 x dia +122,921 Single CWIS <60'
$ = (623.4 x dia + 12,841) x (No. CWIS - 1) Additional CWIS <60'
$ = 1 1 00. 1 x dia + 1 7 1 ,67 1 Single CWIS 60-200'
$ = (623.4 x dia + 21,341) x (No. CWIS - 1) Additional CWIS 60-200'
$ = 1 100.1 x dia + 275,171 Single CWIS 200-350'
$ = (623.4 x dia + 24;841) x (No. CWIS - 1) Additional CWIS 200-350'
$ = 1 100.1 x dia + 336,671 Single CWIS >350'
$ = (623.4 x dia + 35,341) x (No. CWIS - 1) Additional CWIS >350'
$ = 1036.8 x dia +1 13,231 Single CWIS <60'
$ = (1036.8 x dia + 15,993) x (No. CWIS - 1) Additional CWIS <60'
$ = 1 036.8 x dia + 1 6 1 ,98 1 Single CWIS 60-200'
$ = (1036.8 x dia + 24,493) x (No. CWIS - 1) Additional CWIS 60-200'
$ = 1036.8 x dia + 265,481 Single CWIS 200-350'
$ = (1036.8 x dia + 27,993) x (No. CWIS - 1) Additional CWIS 200-350'
$ = 1036.8 x dia + 326,981 Single CWIS >350'
$ = (1036.8 x dia + 38,493) x (No. CWIS - 1) Additional CWIS >350
Variable
CWIS Pipe
Diameter (inches)
and depth of CWIS
opening
CWIS Pipe
Diameter (inches)
and depth of CWIS
opening
CWIS Pipe
Diameter (inches)
and depth of CWIS
opening
Ref.
1
1
1*
3-755
-------
S 316(b) Phase III - Technical Development Document
Technology Cost Modules
Exhibit 3-73. Installed Capital Cost Equations and Variables for Stationary Platforms (continued)
Category
Platform
Platform
CWIS Type
Simple Pipe or
Caisson
Simple Pipe or
Caisson
Description
CuNi wedgewire
screen - with air
sparge cleaning
Stainless steel and
CuNi velocity caps
Cost Equations
$ = 1551.8 x dia +122,921 Single CWIS <60'
$ = (1075.1 x dia + 12,841) x (No. CWIS - 1) Additional CWIS <60'
$ = 1 55 1 .8 x dia + 1 7 1 ,67 1 Single CWIS 60-200'
$ = (1075.1 x dia + 21,341) x (No. CWIS - 1) Additional CWIS 60-200'
$ = 1551.8 x dia + 275,171 Single CWIS 200-350'
$ = (1075.1 x dia + 24,841) x (No. CWIS - 1) Additional CWIS 200-350'
$ = 1551.8 x dia + 336,671 Single CWIS >350'
$ = (1075.1 x dia + 35,341) x (No. CWIS - 1) Additional CWIS >350'
$ = 482.8 x dia +135,863 Single CWIS <60'
$ = (482.8 x dia + 35,613) x (No. CWIS - 1) Additional CWIS <60'
$ = 482.8 x dia + 184,613 Single CWIS 60-200'
$ = (482.8 x dia + 44,1 13) x (No. CWIS - 1) Additional CWIS 60-200'
$ = 482.8 x dia + 288,1 13 Single CWIS 200-350'
$ = (482.8 x dia + 47,613) x (No. CWIS - 1) Additional CWIS 200-350'
$ = 482.8 x dia + 349,613 Single CWIS >350'
$ = (482.8 x dia + 58,1 13) x (No. CWIS - 1) Additional CWIS >350'
Variable
CWIS Pipe
Diameter (inches)
and depth of CWIS
opening
CWIS Pipe
Diameter (inches)
and depth of CWIS
opening
1*
1
References
1. Hatch Report "Off Shore and Coastal Oil and Gas Extraction Facilities Sea Water Intake Structure Modification Cost Estimate: Caisson and Simple Pipe", March 12, 2004.
* Note: Hatch Cu-Ni costs were < Stainless Steel costs. Since the CuNi screen material is expected to be more expensive than stainless steel, EPA used the Hatch slope for Cu-Ni
+ the Stainless Steel intercept to develop the CuNi wedgewire screen cost equations.
3-156
-------
S 316(b) Phase III - Technical Development Document
iccnnoiogy COST moauies
Exhibit 3-74. Operating and Maintenance (O&M) Cost Equations and Variables Used for Stationary Platforms
Category
Platform
Platform
Platform
Platform
Platform
CWIS Type
Simple Pipe or
Caisson
Simple Pipe or
Caisson
Simple Pipe or
Caisson
Simple Pipe or
Caisson
Simple Pipe or
Caisson
Description
Inspection and cleaning of
stainless steel wedgewire
screens using commercial
divers - no air sparge system
Inspection and cleaning of
stainless steel wedgewire
screens using commercial
divers - with air sparge system
Inspection and cleaning of
CuNi wedgewire screens
using commercial divers - no
air sparge system
Inspection and cleaning of
CuNi wedgewire screens
using commercial divers -
with air sparge system
Inspection and cleaning of
stainless steel or CuNi
velocity caps using
commercial divers
Cost Equations
$ = (45.77 x dia +16,180) x No. CWIS <60'
$ = (45.77 x dia + 19,180) x No. CWIS 60-200'
$ = (45.77 x dia + 24,680) x No. CWIS 200-350'
$ = (45.77 x dia + 28,180) x No. CWIS >350'
Add $ = (50.5 x dia + 9888.8) + ((21.9 x dia + 9229) x No. CWIS
- 1) to each stainless steel screen inspection equation above
$ = (18.63 x dia +16,444) x No. CWIS <60'
$ = (18.63 x dia + 19,444) x No. CWIS 60-200'
$ = (18.63 x dia + 24,944) x No. CWIS 200-350'
$ = (18.63 x dia + 28,444) x No. CWIS >350'
Add $ = (50.5 x dia + 9888.8) + ((21 .9 x dia + 9229) x No. CWIS
- 1) to each CuNi screen inspection equation above
$ = (12.5 x dia +17,802) x No. CWIS <60'
$ = (12.5 x dia + 20,802) x No. CWIS 60-200'
$ = (12.5 x dia + 26,302) x No. CWIS 200-350'
$ = (12.5 x dia + 29,802) x No. CWIS >350'
Variable
CWIS Pipe Diameter
(inches) and depth of
CWIS opening
CWIS Pipe Diameter
(inches) and depth of
CWIS opening
CWIS Pipe Diameter
(inches) and depth of
CWIS opening
CWIS Pipe Diameter
(inches) and depth of
CWIS opening
CWIS Pipe Diameter
(inches) and depth of
CWIS opening
Ref.
1
1
1
1
1
3-757
-------
§ 316(b) Phase III - Technical Development Document
Technology Cost Modules
Exhibit 3-75. Installed Capital Cost Equations and Variables for Jack-Up MODUs
Category
Jackup
Jackup
Jackup
Jackup
Jackup
CWIS Type
Simple Pipe or
Caisson
Simple Pipe or
Caisson
Sea Chest
Sea Chest
Submersible Pumps
Description
Cylindrical
wedgewire screen
over tower inlet
Horizontal Flow
Modifier
Flat panel
wedgewire screen
over sea chest
opening
Horizontal Flow
Diverter for Side
Sea Chests
Cylindrical
wedgewire screen
over suction pipe
inlet
Cost Equations
$ = (684.5 x dia +30,399) x No. CWIS (stainless no air sparge)
$ = (1538.8 x dia + 50,540) x No. CWIS (stainless with air sparge)
$ = (834.96 x dia + 30,389) x No. CWIS (CuNi no air sparge)
$ = (1688.6 x dia + 50,541) x No. CWIS (CuNi with air sparge)
$ = (1 106.1 x dia + 30,400 x No. CWIS)
$ = (4.74 x flow (gpm) +29,700) x No. sea chests (stainless steel)
$ = (5.05 x flow (gpm) + 29,700) x No. sea chests (CuNi)
$ = (2.93 x flow (gpm) + 20,520) x No. sea chests
$ = (349.1 x dia - 1,030) x No. suction pumps (stainless steel)
$ = (564.7 x dia - 1,389) x No. suction pumps (CuNi)
Variable
CWIS Tower
Assembly
Diameter
(inches)
CWIS Tower
Assembly
Diameter
(inches)
Flow through
sea chest (gpm)
Flow through
sea chest (gpm)
Pump suction
diameter
(inches)
Ref.
2
2
2
2
2
3-158
-------
§ 316(b) Phase III - Technical Development Document
Technology Cost Modules
Exhibit 3-76. Installed Capital Cost Equations and Variables for Submersibles, Semi-Submersibles, Drill Ships, and Drill Barge MODUs
Category
Submersibles,
Semi-
Submersibles and
Drill Ships
Submersibles,
Semi-
submersibles and
Drill Ships
Drill Barges
Drill Barges
CWIS Type
Sea Chests
Sea Chests
Simple Pipes
Simple Pipes
Description
Flat panel
wedgewire screen
over sea chest
Horizontal flow
diverter over side
sea chest
Cylindrical
wedgewire screen
over simple pipes
Velocity Cap on
the CWIS
Cost Equations
$ = (6.4621 x flow (gpm) +0.287) x No. CWIS (stainless steel)
$ = (6.773 x flow (gpm) - 0.273) x No. CWIS (CuNi)
$ = (3.4995 x flow (gpm) + 0.014) x No. CWIS
$ = (393.67 x dia - 1208) x No. CWIS (stainless steel - no air sparge)
$ = (908.67 x dia + 8481) x No. CWIS (stainless steel - air sparge)
$ = (845.33 x dia - 5603) x No. CWIS (CuNi - no air sparge)
$ = (1360.3 x dia + 4087) x No. CWIS (CuNi - air sparge)
$ = (291.33 x dia + 21423) x No. CWIS (stainless steel or CuNi)
Variable
Flow through
sea chest
(gpm)
Flow through
sea chest
(gpm)
Diameter of
CWIS
opening
(inches)
Diameter of
CWIS
opening
(inches)
Ref.
2-
2
2
2
References
1. Hatch Report "Off Shore and Coastal Oil and Gas Extraction Facilities Sea Water Intake Structure Modification Cost Estimate: Caisson and Simple Pipe", March 12, 2004.
2. Hatch Report "Off Shore and Coastal Oil and Gas Extraction Facilities Sea Water Intake Structure Modification Cost Estimate: Mobile Off Shore Drilling Units (MODUs)",
March 12, 2004.
3-159
-------
S 316(b) Phase III - Technical Development Document
Technology Cost Modules
Operating and maintenance costs are associated with fixed platforms only. Operators are 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 requirement to drydock MODUs
or perform special examination in lieu of drydocking 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 107.265 and 107.267 and 46 CFR 61.20-5). It was therefore assumed that
MODU's will undergo cooling water intake structure control maintenance as part of their regularly scheduled dry dock service.
Operating and maintenance costs for fixed platform facilities do not include any costs associated with downtime (see section F.3).
For fixed platform facilities using simple pipe and/or caisson intakes, the depth of the water intake is needed to determine maintenance
costs for cooling water intake structure control inspection and cleaning. Since intake depth was not available for many of the fixed
platform facilities costed, an estimate of the intake pipe depth was developed using available data. Based on an assessment of intake
depth performed by Simon, a linear equation was developed to represent intake pipe depth versus total design intake flow. In general,
the greater the design intake flow the deeper the intake depth.
The facility-level option costs (summarized below) include air sparging equipment for biofouling control at intake depths less than 200
feet for both stainless steel and Cu-Ni cylindrical wedgewire screens. According to Linda Cook at Johnson Screens (email
correspondance dated May 20, 2004), the water is typically clean at depths below 40 to 50 feet and biofouling is typically not a
concern, however it depends on the water quality at the actual location. As a conservative estimate, EPA assumed air sparging
systems may be needed at depths up to 200 feet. In addition, for sea chests, costs were developed for both bottom and side horizontal
flow diverters. Since it was unknown in most cases whether specific facilities had bottom or side sea chests, the costs included in the
facility-level option costs used the more expensive option (i.e., assumed side sea chests).
4.2.3 Summary of Technology Option Costs for Existing Oil and Gas Extraction Facilities
Exhibit 3-78 presents a summary of the cooling water intake control costs developed for existing "in-scope" O&G extraction facilities
for cooling water intake structure control options A through E. These costs are broken out by platforms versus MODUs and by
location. These costs do not represent scaled-up costs.
Exhibit 3-77. Summary of Technology Option Costs for Existing Oil and Gas Extraction Facilities
Capital Costs
Platforms, COM
Capital Costs
Platforms, California
Capital Costs
Platforms, Alaska
Capital Costs
MODUs
Total Capital Costs ($)
O&M Costs
Platforms, GOM
O&M Costs
Platforms, California
O&M Costs
Platforms, Alaska
O&M Costs
MODUs
Total O&M Costs ($)
No. of Facilities
Included in Costs
16
6
5
87
114
16
6
5
87
114
Option A
4,047,201
2,546,486
1,543,426
21,653,766
29,790,879
905,315
576,504
573,804
0
2,055,623
Option B
4,187,716
2,598,198
0
11,440,066
18,225,980
675,924
539,340
0
0
1,215,264
Option C
4,187,716
2,598,198
0
14,408,685
21,194,599
675,924
539,340
0
0
1,215,264
Option D
0
0
0
4,502,389
4,502,389
0
0
0
0
0
Option E
0
0
0
1,533,770
1,533,770
0
0
0
0
0
3-160
-------
§ 316(b) Phase III - Technical Development Document
Technology Cost Modules
Option A = I & E control for facilities with > 2 MOD
Option B = I control for facilities with > 2 MOD
Option C = I & E control for facilities with > 50 MOD and I control for facilities with 2-50 MOD
Option D = I & E control for facilities with > 50 MOD
Option E = I control for facilities with >50 MOD
When these costs are scaled-up to include additional facilities believed to be "in-scope" and not costed, the total capital and O&M
costs become:
Total Capital Costs ($)
Total O&M Costs ($)
Option A
48,354,142
3,054,978
Option B
27,766,279
1,257,368
Option C
30,734,897
1,257,368
Option D
4,502,389
0
Option E
1,533,770
0
EPA used these costs for existing facilities to estimate the incremental compliance costs for new facilities. This is a conservative
approach to estimate potential economic impacts as incremental compliance costs for new facilities will be lower than incremental
compliance costs for existing facilities since new facilities will not need to retrofit existing equipment. Economic impacts on new
MODUs and platforms and their associated firms from these incremental compliance costs are expected to be minimal (see DCN 7-
0002). EPA estimates that the costs of the Phase III proposed rule are highly unlikely to have any production effects on new
deepwater platforms, nor are these costs expected to pose a barrier to entry to new oil and gas development. The economic modeling
does not indicate that production is very sensitive to costs estimated at the current order of magnitude.
5.0
PROPOSED TECHNOLOGY OPTIONS IDENTIFIED IN THE PHASE III PROPOSAL
EPA is proposing to require impingement and entrainment control requirements for new offshore oil and gas extraction facilities in the
Phase III 316(b) rulemaking. EPA finds the technology available and affordable. Moreover, the importance of controlling
impingement and entrainment at oil and gas extraction facilities is highlighted by the fact that these structures provide an important
fish habitat. A variety of fish species are known to be attracted to and to aggregate around and directly under offshore oil and gas
extraction facilities, often resulting in densities offish of that are higher than the densities found in adjacent open waters. Both adult
fish and young fish gather around these structures. Young fish may be more susceptible to impingement and entrainment than adult
fish. For example, oil and gas platforms and artificial reefs undoubtedly serve as red snapper habitat, and they may serve as an
important (but not obligate) link in the life history of both juvenile and adult red snapper.17 In general, five to 100 times more fish can
be concentrated near offshore platforms than in the soft mud and clay habitats elsewhere in the Gulf of Mexico.18 As a result, 70
percent of all fishing trips in the Gulf of Mexico head for oil and natural gas platforms. Likewise, 30 percent of the 15 million fish
caught by recreational fishermen every year off the coasts of Texas and Louisiana come from the waters around platforms. The
offshore marine areas in which oil and gas extraction facilities are located contain large numbers of fish and shellfish eggs and larvae
that drift with ambient currents and have minimal swimming ability. These organisms are vulnerable to entrainment by oil and gas
facility cooling water intake structures. Densities of these organisms are variable across offshore marine areas, but they can be as great
as the densities found in estuarine environments. EPA will address potential impingement and entrainment impacts at existing
facilities through NPDES permits on a case-by-case basis, using best professional judgment (see 40 CFR 125.80(c)).
EPA applied different regulatory requirements for new oil and gas extraction facilities depending on whether they are projecting to use
sea chest as their cooling water intake structure. New oil and gas extraction facilities without sea chests as cooling water intake
structures are required to meeting impingement and entrainment requirements while those with are only required to meet impingement
requirements. EPA made this distinction based on the potential lack of technologies to control entrainment impacts for sea chest
cooling water intake structures. Simple pipes, caissons and submersible pumps used for cooling water extraction can be fitted with
pre-manufactured cylindrical wedgewire screens to prevent entrainment and impingement of marine life. Consequently, control
technologies are available for these cooling water intake structures and EPA is proposing impingement and entrainment control
requirements for new offshore oil and gas extraction facilities that do not use sea chests.
17 Reef Fish Stock Assessment Panel, Gulf of Mexico Fishery Management Council, 1996. "Review of
1996 Analysis by Gallaway and Gazey, http://www.gulfcouncil.org/downloads/RFSAP-GG-1996.pdf. August 1996.
18Sandra Fury, ChevronTexaco, statements before U.S. Commission on
Ocean Policy, http://oceancommission.gov/meetings/mar7_8_02/fury_statement.pdf, March 8, 2002.
3-161
-------
§ 316(b) Phase HI - Technical Development Document Technology Cost Modules
EPA had limited information on the effectiveness of flat-paneled wedgewire screens in controlling entrainment impacts. However, in
order to estimate compliance costs associated with this technology, EPA costed flat paneled wedgewire screens for sea chest cooling
water intake structures. EPA solicits data and information on whether this technology can be used to controlling entrainment impacts.
EPA identified in its record that only 'jack up1 type oil and gas extraction facilities use both sea chests and non-sea chest cooling water
intake structures. EPA estimates that the design of the cooling water intake structures for jack up oil and gas extraction facilities will
primarily depend on the operation needs of the facility and will not be influence by reduced regulatory requirements. However, EPA
solicits comment on the major factors influencing the design of cooling water intake structures for 'jack up' oil and gas extraction
facilities and whether reduced regulatory requirements might lead industry to select sea chests to reduce their potential compliance
costs.
6.0 316(b) ISSUES RELATED TO OFFSHORE OIL AND GAS EXTRACTION FACILITIES
EPA investigated several issues related to 316(b) technology options for this industrial sector. These issues included: biofouling; the
definition of new source; potential lost production and downtime associated with proposed technology option impacts; drilling
equipment at production platforms; and current regulatory requirements.
6.1 Biofouling
Industry comments to the 316(b) Phase I proposal assert that operators must maintain a minimum intake velocity of 2 to 5 feet per
second in order to prevent biofouling of the offshore oil and gas extraction facility cooling water intake structure. EPA requested
documentation from industry regarding the relationship between marine growth (biofouling) and intake velocities (Johnston - March
21,2001). Industry was unable to provide any authoritative information to support the assertion that a minimum intake velocity of 2 to
5 feet per second is required in order to prevent biofouling of the facility's cooling water intake structure. IADC asserts that it is
common marine engineering practice to maintain high velocities in the seachest to inhibit attachment of marine biofouling organisms
(Spackman, May 8,2001).
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 the ASCE "Design of Water Intake Structures for Fish Protection" recommends
an approach velocity in the range of 0.5 to 1 feet per second for fish protection and 1 feet per second 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.
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 (Johnston - March 26,2001) & (Johnston - October 9,2001). 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 (Johnston - October 9, 2001). Moreover, as detailed above, operators are required to perform
regular inspection and cleaning of these cooling water intake structures in accordance with USCG regulations.
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
sparging, Ni-Cu alloy materials). See Figure 3-76 for a schematic of air sparging at a cylindrical wedgewire screen. 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.
3-162
-------
S 316(b) Phase III - Technical Development Document
Technology Cost Modules
Figure 3-76. Cylindrical Wedgewire Screen with Air Sparging (Johnson Screens)
Biocide treatment can also be used to minimize biofouling. I ADC 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, but this
variation is not expected to be more than 0.1 pH units.
In another offshore industrial sector, LNG import terminals, industry is proposing intake velocities of 0.5 feet per second. In their
proposals, industry identified the use of sodium hypochlorite to control biofouling and did not identify any concerns over the proposed
intake velocity (0.5 feet per second) and biofouling. Moreover, some of these proposed facilities include in their designs cylindrical
wedgewire screens with air sparging to remove biofouling and clear water intake structures.
In summary, EPA did not identify any relationship between the intake velocity and biofouling of an offshore oil and gas extraction
facility cooling water intake structure. EPA finds that operators can reasonably control biofouling associated with cooling water intake
structures. As previously mentioned, EPA included the costs of controlling biofouling for intakes at depths less than 200 feet as part
of the incremental compliance costs.
6.2
Definition of New Source
Industry claimed in comments to the Phase 1316(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 excluded existing facilities from the Phase III proposed rule and clarified the
regulatory language.
6.3 Potential Lost Production and Downtime Associated with Proposed Technology Option Impacts
6.3.1 Potential Lost Production
EPA estimates that there will be no lost production for new oil and gas extraction fixed platform facilities due to incremental 316(b)
Phase III compliance costs.
Lost production for an oil and gas extraction facility could occur if the operator made a decision to shut in a facility early due to the
incremental costs associated with cooling water intake structure operation and maintenance (O&M.) The decision to shut in a facility
is generally made on an annual, semi-annual, or at most quarterly basis. At the end of a fixed facility production life, the costs of
production would be in the $3.7 million/year range and the incremental cooling water intake structure O&M costs are estimated to be
in the $37,000/year range. Therefore, the incremental cooling water intake structure O&M costs are approximately 0.1 % of the
3-163
-------
§ 316(b) Phase HI - Technical Development Document Technology Cost Modules
production costs and would not impact a quarterly, semi-annual or annual shut in decision. Well shut in decisions will be much more
sensitive to the price of oil and gas.
Preliminary economic analysis shows that the costs of the Phase III rule are highly unlikely to have any production effects on new
deepwater platforms, nor are these costs expected to pose a barrier to entry to new oil and gas development. The economic modeling
does not indicate that production is very sensitive to costs estimated at the current order of magnitude.
6.3.2 Potential Downtime
EPA evaluated the potential for downtime at existing oil and gas extraction facilities to allow for cooling water intake structure control
maintenance. This issue was evaluated for both mobile and fixed oil and gas extraction facilities. EPA gathered information from the
following experts on the topic of maintenance practices for mobile and fixed oil and gas extraction facilities:
April 4, 2001 Meeting with Mr. James M. Magill, U.S. Coast Guard, Vessel and Facility Operating Standards Division.
• June 8, 2004 Email Correspondence with Mr. Elmer Danenberger, Mineral Management Service (MMS).
June 9,2004 Email Correspondence with Mr. Kent Satterlee, Shell Oil Company.
Mobile Oil and Gas Extraction Facilities
Mr. Magill of the U.S. Coast Guard provided information related to cooling water intake structures for MODUs. MODUs typically
draw in intake water through a sea chest. The sea chest is a cavity in the hull or pontoon of the MODU and is exposed to the ocean
with a screen often set along the flush line of the sea chest. There are generally two sea chests for each drill ship or semi-submersible
(port and starboard) for redundancy and ship stability. In general, only one sea chest is required at any given time for drilling
operations. Mr. Magill indicated that there are generally three pipes for each sea chest (including cooling water intakes and fire
pumps). One of the intake pipes is always set aside for use solely for emergency fire fighting operations. Regarding maintenance
downtime, Mr. Magill stated that current Coast Guard requirements are that operators must inspect sea chests twice in five years with
at least one cleaning. These requirements are particularly important to ensure that the separate intake for the fire pump is clear. The
requirement to drydock MODUs or perform special examination in lieu of drydocking twice in five years and inspect and clean their
sea chests and sea valves are found in U.S. Coast Guard regulations (46 CFR 107.261,107.265, and 107.267 and 46 CFR 61.20-5).
The U.S. Coast Guard may require the sea chests to be cleaned twice in 5 years at every drydocking or special examination in lieu of
drydocking if the unit is in an area of high marine growth or has had history of excessive marine growth at the sea chests. Mr. Magill
estimated that the regular cleaning and inspection schedule should be enough to control marine biofouling in the Gulf of Mexico.
Based on this information, EPA assumed that the existing Coast Guard requirements for MODU sea chest maintenance are sufficient
and no downtime or additional maintenance costs were developed for MODUs.
Fixed Oil and Gas Extraction Facilities
Fixed Platforms were costed for cooling water intake structure control maintenance (i.e., annual screen inspection and cleaning using
divers). EPA requested information from Mr. Danenberger and Mr. Satterlee to determine whether regular downtime is typical for
fixed platforms during which cooling water intake structure control maintenance could occur or whether maintenance costs would
need to account for potential downtime lost production. Both Mr. Danenberger and Mr. Satterlee indicated that it is usual for fixed
platforms to experience periodic shut ins for production maintenance purposes. Mr. Danenberger indicated that the frequency and
duration of the production maintenance shut ins is dependent on platform age, complexity, condition of the facility, and company
practices and policy. Newer facilities might only shut in once per year for two to three days, other facilities might average two shut ins
per year, each for up to a week. Mr. Satterlee indicated that for Shell facilities, on average there are one to two scheduled shut ins per
year of varying duration. He estimated that on average a typical shut in would be two to three days depending on the scope of work to
be performed. In addition, there can also be unplanned shut ins to address critical maintenance items.
Based on this information, EPA assumed that for fixed platform facilities, cooling water intake structure control maintenance can
occur during a regularly scheduled downtime and costs beyond the maintenance costs for screen inspection and cleaning were not
required.
6.4 Drilling Equipment at Production Platforms
Drilling equipment is not generally permanently located on offshore fixed production platforms. However, some offshore fixed
production platforms do have permanent on-site drilling equipment and do drill development wells and sidetracks, as well as perform
——
-------
§ 316(b) Phase III - Technical Development Document
Technology Cost Modules
well workovers, throughout the life of a project. EPA estimates that 115 fixed platforms have drilling equipment on the platform out
of roughly 2,500 platforms in the GOM. Some fixed production platforms that require more than 2 MGD of cooling water include
platforms in deepwater, platforms with cooling needs for power equipment and machinery (e.g., winches), and platforms that require
cooling for gas compression and other needs.
Based on data industry submitted to EPA, platforms with permanent drilling equipment are more often found in deepwater. Since
passage of the Deep Water Royalty Relief Act (43 U.S.C. §1337) there has been an overall expansion in all phases of deepwater oil
and gas extraction activity. This legislation provides economic incentives for operators to develop fields in water depths greater than
200 m (656 ft), areas. The number of producing deeperwater projects has dramatically increased from 1992 (6) and 1997 (17) to 2003
(86). Deepwater production rates have risen by well over 100,000 barrels of oil per day and 400 million cubic ft of gas per day,
respectively, each year since 1997." Initial data suggests that while cooling water needs may decrease over the life of some fixed
platforms with drilling equipment, the water intakes for some fixed platforms will stay above 2 MGD for their production needs (e.g.,
gas cooling and compression). High speed reciprocating gas and rotary screw natural gas compressors range up to 8,800 HP.
Assuming continuous once through cooling and a seawater temperature increase of 10 °C between intake and discharge, the volume of
seawater required for cooling these engines can ranges up to 3.5 MGD. As an example, there some production platforms in shallow
waters in mature fields that do very little drilling and withdraw more than 2 MGD of seawater (e.g., Offshore California, Cook Inlet,
AK). Figure 3-77 demonstrates that design intake flows for some existing production platforms do not always fall below the 2 MGD
flow threshold.
Figure 3-77. Design Intake Flow for Production Platforms with Surface Water Intakes Greater than 2 MGD and Installation
Year
CD
re
c.
c Q
to ^
CD fc*
Q £
§ —
re
CL
Design Intake Flow for Production Platforms and
installation Year
40 q
.
30 :
•
20 '-
'•
-
0.
„
•
,.. ... .. . .Jk.
AA * * *»
. »*'**
1965 1970 1975 1980 1985 1990 1995 2000
Platform Installation Year
» Gulf of Mexico Facilities • Offshore California Facilities
A Cook Inlet, AK Facilities
Finally, MODUs also serve fixed production platforms to drill development wells and sidetracks, as well as perform workovers,
throughout the life of a project when the offshore platform does not have a permanent drilling rig. MODUs also have the potential to
impinge and entrain aquatic organisms at these fixed facilities. Consequently, EPA evaluated and selected technology options for
these fixed and mobile oil and gas extraction facilities, including fixed production platforms without drilling equipment, to reduce
potential adverse environmental impacts. Since most fixed production platforms without drilling equipment have seawater intakes
less than 2 MGD, they would not by subject to the 316(b) rule but must meet §316(b) requirements as specified by the NPDES permit
authority on a case-by-case basis, using best professional judgment (BPJ) (see 40 CFR 125.80(c)). EPA also notes that when operators
decommission intake structures and reduce their design intake flow to below 2 MGD, they would no longer be subject to permit
specific BPJ requirements. EPA will request more data on this topic in the proposed rulemaking.
"U.S. Minerals Management Service, 2004. "Deepwater Gulf of Mexico 2004: America's Expanding
Frontier," MMS 2004-021. hrtp://www.gomr.mms.gov/homeDg/whatsnew/techann/2004-021 .pdf. May 2004.
3-165
-------
S 316(b) Phase IH - Technical Development Document Technology Cost Modules
6.5 Current Regulatory Requirements
EPA's discussions with the two main regulatory entities of offshore oil and gas extraction facilities (i.e., MMS, USCG) identified no
Federal regulatory or information collection requirements for these cooling water intake structures. MMS generally does not regulate
or considered the potential environmental impacts of these cooling water intake structures in either NEPA analyses or approval of
drilling and exploratory plans. As previously mentioned, MMS could only identify one case where the environmental impacts of a
new oil and gas extraction facility cooling water intake structure were considered (i.e., Liberty Island). Moreover, MMS does not
collect information on cooling water intake volumes, velocities and durations for any oil and gas extraction facility. The U.S. Coast
Guard does not investigate potential environmental impacts of MODU cooling water intake structures but does require operators to
inspect sea chests twice in five years with at least one cleaning to prevent blockages of firewater lines.
EPA identified one State regulatory requirement for cooling water intake structures at oil and gas extraction facilities. As detailed in
section 2.5, the State of Alaska has a standard clause in their oil and gas leasing agreements which controls potential impingement and
entrainment impacts from oil and gas extraction facilities (screen size and intake velocity).
3-166
-------
S 316(b) Phase III - Technical Development Document
Technology Cost Modules
IV. TECHNOLOGY COST MODULES FOR LIQUEFIED NATURAL GAS FACILITIES
APPLICATION OF THE PROPOSED RULE
Under each of the co-proposed options, no offshore liquefied natural gas facilities would be subject to national performance standards.
New land-based liquefied natural gas facilities may be subject to requirements under the Phase I rule.
INTRODUCTION
Liquefied natural gas (LNG) has become an increasingly important part of the U.S. energy market. Interest in LNG imports has been
rekindled by higher U.S. natural gas prices in recent years, as well as increased competition and technological advances that have
lowered costs for liquefaction, shipping, storing, and re-gasification of LNG.1 LNG is cooled to about minus 260 °F and transported
by vessels to import facilities for re-gasification.
During the re-gasification process, the LNG is warmed from minus 260 °F to 40 °F and experiences a three-fold increase in volume.
Typically, LNG at import terminals is stored only until it can be re-gasified and injected into the pipeline grid or until it can be trucked
directly to customers. In order to minimize wait times for the ships and to avoid congestion, operators of LNG marine terminals
process cargoes quickly. Each U.S. import terminal is equipped with storage tanks capable of holding between two and three tanker
loads of LNG. Some new and expanded facilities in the United States will have a capacity closer to four tanker loads. (DOE 2004)
LNG import terminals may use surface waters for this heat exchange process and may also use surface waters for cooling purposes.
This chapter provides an overview of: (1) the existing and planned LNG import terminals in the U.S., (2) which LNG import terminals
EPA evaluated for the Phase III rulemaking; and (3) the technology options available to control impingement and entrainment of
aquatic organisms.
1.0
EXISTING LNG IMPORT TERMINALS IN THE U.S.
The LNG industry in the United States has experienced periods of prolonged downturns, in part owing to price competition from
domestic sources of natural gas. (DOE 2004) Currently there are five existing onshore LNG import terminals and no existing offshore
LNG import terminals. The five existing onshore LNG import terminals are presented in Exhibit 3-78.
Exhibit 3-78. Five Existing Onshore LNG Import Terminals
Location
Lake Charles, LA
Cove Point, MD
Everett, MA
Elba Island, GA
Guayanilla Bay, Puerto
Rico
2003 LNG Imports, Billion
cubic feet (Bcf)
238.2
66.1
158.3
43.9
ISO2
2004 LNG Storage Capacity,
Billion cubic feet (Bcf)
6.3
5.0
3.5
4.0
N/A
Operator
Southern Union
Dominion
Tractebel
El Paso/Southern LNG
Enron/Edison Mission
(EcoElectrica)
Sources: (DOE 2004), (DOE 1995)
Although LNG imports exceeded historical highs in 2003, even at the current pace they represent only about 2.7 percent of U.S.
consumption and 13 percent of imports. Through expansions at three of the four facilities, the United States will increase its peak re-
gasification capacity by more than 40 percent from the 2002 level (3.2 Bcf/d) to approximately 4.6 Bcf/d in 2005. Additionally,
through recently announced additional expansion projects at Lake Charles and Cove Point, capacity would reach about 6.2 Bcf/d by
2008. (DOE 2004)
'U.S. Department of Energy, Energy Information Administration, 2004. "U.S. LNG Markets and Uses: June
2004 Update," http://www.eia.doe.gov/pub/oil_£as/natural_gas/feature_articles/2004/lng/lng2004.pdf.
2U.S. DOE, Office of Fossil Energy, Order Granting Long-Term Authorization to Import Liquified Natural
Gas, Order No. 1042, http://www.fe.doe.gov/programs/gasregulation/authorizations/orders/ordl042.pdf, April 19,
1995.
3-767
-------
§ 316(b) Phase HI - Technical Development Document Technology Cost Modules
2.0 PLANNED LNG IMPORT TERMINALS IN THE U.S.
A competition to build LNG import terminals is taking place among U.S. and foreign companies in many regions of North America
because of the perceived opportunity in the growing LNG industry.3 Interest in LNG imports has been rekindled by higher U.S.
natural gas prices in recent years and technological advances that have lowered costs for liquefaction, re-gasification, shipping, and
storing of LNG.4'5 Potential investment in re-gasification facilities in the U.S. is estimated at $15 billion.6 Although LNG imports
currently make up a small percentage of total gas supplies, higher natural gas prices and recent expansions of existing LNG import
terminals and the constructions of new terminals will likely boost the net import of LNG from overseas. Net LNG imports are
estimated to increase from 0.2 trillion cubic feet in 2002 to 2.2 and 4.8 trillion cubic feet in 2010 and 2025, respectively, as planned
expansions at the four existing terminals are completed and new terminals are projected to start coming into operation in 2007.7
As shown in Figure 3-78 a number of LNG import terminals have been proposed for development to meet the increased demand for
natural gas. (FERC 2004) There are at least 40 company announcements of proposed terminals targeted for North America. Many of
these projects are already before regulators, and, as of June 2004, some have achieved regulatory success. (DOE, 2004). Many of
these proposed projects are planned for the Gulf of Mexico (GOM) area due to the area's largest demand for natural gas and
significant pipeline infrastructure.8 As shown in Figure 3-79, the Federal Energy Regulatory Commission (FERC) estimates that the
planned and pending LNG import terminals will tripled the U.S. capacity to import LNG.9 However, not all planned LNG import
terminals will be built. It is estimated that in order to provide the needed LNG supply to the U.S. gas system, 10 to 12 LNG import
terminals will be built within the decade with an investment of more than $5 billion.10
'Remarks of Suedeen G. Kelly, Commissioner of Federal Energy Regulatory Commission, to the Natural
Gas Roundtable of Washington, "The Challenge of Natural Gas Interchangeability and Quality," Washington, D.C.,
February 24,2004. See http://www.ferc.gov/press-room/sp-current/02-24-04-kelly.pdf.
4Gaul, Damien, 2001. U.S. Department of Energy, Energy Information Administration, "U.S. LNG Markets
and Uses," See http://www.eia.doe.gov/pub/oil_gas/natural_gas/feature_articles/2003/lng/lng2003.pdf
5 University of Houston, 2003. "Introduction to LNG,"
http://www.energy.uh.edu/LNG/documents/IELE_introduction_to_LNG.pdf, January 2003.
6 Kelly, Edward, 2004. "Factors Limit LNG's Role In U.S. Market," American Oil and Gas Reporter,
March 2004.
7U.S. Department of Energy, 2004. "Annual Energy Outlook 2004 with Projections to 2025,"
DOE/EIA-0383 (2004), January 2004. See http://www.eia.doe.gov/oiaf/aeo/.
8Meyer, Keith, 2004. The Regasification of North America, World Energy, Vol. 7, No. 1,
http://www.worldenergysource.com/articles/pdf/meyer_WE_v7nl.pdf.
'U.S. Federal Energy Regulatory Commission, 2004. "LNG Briefing,"
httD://www.ferc.gov/industries/gas/indus-act/lng-briefing.pps. April 2004.
10 Hall, Wayne F. 2004. "The North American LNG Supply Chain: Strategies for Economic Growth,"
World Energy, Vol. 7, No. 1, http://www.worldenergysource.com/articles/pdf/hall_WE_v7nl.pdf.
3-168
-------
§ 316(b) Phase III - Technical Development Document
Technology Cost Modules
Figure 3-78. Existing and Proposed North American LNG Terminals
• Planned
DPending - Coast Guard
• Pending - FERC
• In-Service and Approved
In-Service Pending - Pending -
and FERC Coast
Approved Guard
Planned
Figure 3-79. Current and Potential Future U.S. LNG Import Capacity
FERC
ExMfcM) Unman: MttlAp;
Existing and Proposed
North American
LNG Terminals
A.[voratt,MAI UUSBcM (TIKUM-OOfMC)
B.Cov«Polirt,MI>: l.Otcfd (Dominion - CM Point INC)
c.nt»iji»«ii,e»i 1.2 add <8rw>- southern IMG)
n laliarlMMfcH. I > - l.7Rrfrt (<*MKh»mllnk»-Tnmkllr*>IM[;)
1. HKfcborry, LA : l.S Bcfd, (Sonpra Energy)
Z. Port Mlcwii 1.0 Odd, (Onvmn Texwo)
>. Bahama*; 044 BeM. (ACSOeMnCxpKM*)*
«,Gu»ofH«j6co:0.5BcM, (B (Wo Entmy BrtOM COM. LLO
S. Bahama! : 043 Wd. (CHyploTrictlM)*
*.FraaBort,TX: 1.5 BdO, (OwMra/FraipatlMSDn.)
September 2004
of Energy Projects
7. Fall Mmr, M*;0«Bc(d. (
«.LM|lMCk,CA:0.7Bcfil, (HtsubWVConocDfMli(»- Sound Ermiv Solutions)
l.CocpmClMM^TX: 24BCM, (Oicnlm LNG PMntn)
ig. saMiM^ ui i 2.6 add (OWMK LNG)
C~T««CWi«tl,TXl 1.0*M(VOUMSal
Tit1— I. T
.
U.U>gm UndUg LNG - BP)
14. late Chute* LA: 0.6 Odd (Southern IMon - TfurUm LNG)
U.MIIHIIM: 0.5 wo, (9>««nr-Di*M/m.)
U.CwpmCkrtMI,TX! LO (eft) (Ooddmal Cmm Venlunz)
17. Pravtdmot, M : as Srfd (Ktwwn » BG LNG)
l«.PDitArtkur,TX: UKAKSangn)
1». Can Point, HDi OJBcW (OanMon)
*: 1.5 laTd (ClMllo Port - 8KB UM»n)
> Btfd (Grff Unang - Sh«fl)
22.Sa.Ullfenii>«MlM*!0.5acftl. (Qryinl Enagy)
U.LMiW>n«Offlllor«! tO BcM (
(H«n tax HcMttan E>p.)
Port-Conoa>Ph»lpi)
25. euir or Mexico : 2.8 BOO (PHrf cnM«ng • GoonMoM)
at.mimnllli.TXi alt. (Chowra LNG Partners)
27. COM lay, OH: O.lJBcM, (Emray PnMgcB DnMopmEnt)
2S.SoM>Mt,HA: 0.6SBcM(SonteC«Mofiil«,MX: l.OBcfd, (SunprakSM)
32. i«J» Ci«lomU - QUO*** ; 1.4 Bdd, (chewon TeocD)
U-CMMnw-omiwrai u./>uOd, (Umran leam)
*». «. Min, N» : l.OOett, (OwoM- Irving On)
IS. ItelKtTuHur, NS LOBnVK (Itar HMI| I NR • Amwt Nnrlhiiacl FnnTy)
1*. nmint Mm, ME : 0.5 W/d (QuodoV Biy, UC)
M. HMfcMll- U>m QC: 0.5 Btfd(C»Doun. Energy - l
40.Ct.H^«K,O«l 0.7 BcM (Port Wm»m. NS
3-769
-------
§ 316(b) Phase III - Technical Development Document Technology Cost Modules
3.0 LNG IMPORT TERMINALS EPA EVALUATED FOR THE PHASE III RULEMAKING
EPA collected data on the re-gasification processes which are used at existing LNG import terminals and those that being proposed for
new facilities. For each facility EPA estimated whether: (1) these facilities are subject to the NPDES Permit Program; (2) these
facilities withdraw more than 2 MGD from surface waters; and (3) 25 percent of the surface water intake is use for cooling purposes.
EPA collected this data in order to determine whether LNG import terminals could potentially be subject to CWA § 316(b) national
technology-based standards to protect aquatic organisms from being killed or injured by impingement (being pinned against screens or
other parts of a cooling water intake structure) or entrainment (being drawn into cooling water systems and subjected to thermal,
physical or chemical stresses).
For many LNG import terminals most or all of the surface water intakes are used for the re-gasification process, an endothermic
process, and are not consider "water withdrawn for cooling purposes." EPA stated in the preamble to the final Phase II rule that
"water withdrawn for non-cooling purposes includes water withdrawn for warming by liquified natural gas facilities and water
withdrawn for public water systems by desalination facilities," (July 9,2004; 69 FR 41581). Consequently, warming waters used by a
LNG import terminal would not be considered "water withdrawn for cooling purposes" in determining whether a LNG import terminal
meets the threshold requirement of using at least 25 percent of water withdrawn for cooling purposes. Also, water used in a
manufacturing process either before or after it is used for cooling is considered process water - not cooling water - for the purposes of
calculating the percentage of a new facility's intake flow that is used for cooling purposes (see the definition of cooling water in 40
CFR 125.83)."
Thus, if an LNG import terminal uses less than 25 percent or none of its water for cooling purposes or does not meet the 2 MGD
intake flow threshold, the new facility rule specifies that the facility must meet § 316(b) requirements as specified by the NPDES
permit authority on a case-by-case basis, using best professional judgment (see 40 CFR 125.80(c)). (EPA, 2004 - clarification memo)
EPA is aware, however, that some new offshore LNG import terminals may use water for warming and cooling purposes. For
example, the draft Environmental Assessment for the Excelerate (formerly El Paso Energy Bridge Gulf of Mexico, LLC) LNG import
terminal notes that the total seawater demand for the vessel is 133 million gallons per day (MGD).12 The sea water intake serves the
following purposes: (1) total demand dedicated to the regasification system (76.1 MGD); (2) vessel's main condenser cooling system
(46.9 MGD); and (3) vessel's other cooling systems (10 MGD). This offshore LNG import terminal is subject to the NPDES Permit
Program13; withdraws more than 2 MGD; and uses more than 25 percent of the seawater intake for cooling purposes.
3.1 Existing Onshore LNG Import Terminals
Since the 1970s, none of the four existing continental U.S. LNG import terminals use surface water for warming or cooling purposes,
only as an emergency backup source to their firewater systems.14'15 For example, at the Dominion Cove Point, Maryland, facility all
water used on site is withdrawn from groundwater wells and is heated in the vaporizers and used to warm the LNG and convert back to
a gaseous state.16 Additionally, the EcoElectrica facility in Puerto Rico does use surface water for makeup and discharges blowdown
for the power plant cooling tower, but does not use surface water intakes directly for the LNG processing (warming or cooling). The
MU.S. EPA, 2004. "Clarification of Technology-based CWA § 316(b) Requirements for Liquified Natural
Gas (LNG) import terminals," Memorandum, April 22, 2004.
12U.S. Coast Guard, 2003. Draft Environmental Assessment of the El Paso Energy Bridge Gulf of Mexico,
L.L.C., Deepwater Port License Application, Docket No. USCG-2003-14294, September 2003.
13U.S. EPA, 2003. Letter from Lawrence E. Starfield, Acting U.S. EPA Region 6 Administrator to U.S.
Coast Guard Commander Mark Prescott, "EPA Authority Over Construction and Operation, El Paso Energy Bridge
Deepwater Port Project," March 28,2003.
14 E-mail communication from James Kelly, CH-IV International, to Carey A. Johnston, U.S. EPA, April
28,2004.
15 Frangesh, Neal, 2004. Memorandum from Neal Frangesh, LGA Engineering, to David Moses, U.S. DOE,
"Existing U.S. LNG Import Terminals: Sources of Cooling Water and Firewater," July 19, 2004.
"E-mail communication from Elizabeth Aldridge, Hutton & Williams, to Carey A. Johnston, U.S. EPA,
June 24, 2004.
5-770
-------
§ 316(b) Phase HI - Technical Development bocument
Technology Cost Modules
EcoElectrica facility integrates LNG vaporization with its power plant operations. Figure 3-80 describes how this facility uses a glycol
re-circulating heat exchanger in combination with a electric power generator to re-gasify the LNG.
Figure 3-80. EcoElectrica Simplified Flow Diagram
3-; 77
-------
§ 316(b) Phase III - Technical Development Document
Technology Cost Modules
3.2 New Onshore LNG Import Terminals
Current information indicates that all new onshore LNG import terminals are proposing to use LNG vaporization systems with no
surface water intakes (e.g., integration with other industrial facilities, ambient air vaporization through heating towers, gas-fired
heaters). Exhibit 3-79 lists proposed new onshore LNG import terminals and their vaporization design.
Exhibit 3-79. Proposed U.S. Onshore LNG Import Terminals17
No.
1
2
3
4
5
6
Project Name/ Operator/
FERC Docket No.
Freeport LNG Project
(Cheniere/Freeport)
CP03-75-000
$400 million facility cost
Sabine Pass LNG and
Pipeline Project
(Cheniere)
CP04-38-000
CP04-47-000
$600 million facility cost
Cheniere Corpus Christi
LNG Terminal and Pipeline
Project
(Cheniere)
CP04-37-000
CP04-44-000
$450 million facility cost
Golden Pass LNG Terminal
and Pipeline Project
(ExxonMobil) PF04- 1-000
$600 million facility cost
Vista del Sol LNG Terminal
Project
(ExxonMobil)
PF04-3-000
PF04-9-000
$600 million facility cost
Ingleside Energy Center
LNG Project
(Occidental)
PF04-9-000
Location
Freeport, TX
Cameron Parish,
LA (across from
Sabine Pass)
Corpus Christi,
TX
Sabine, TX
Corpus Christi,
TX
Corpus Christi,
TX
Storage
Capacity
320,000 m3 (2
tanks each with
160,000m3)
480,000 m3 (3
tanks each with
160,000m3)
480,000 m3 (3
tanks each with
160,000m3)
Phase 1:
480,000 m3 (3
160,000 m3
tanks)
Phase 2:
800,000 m3 (5
160,000m3
tanks)
480,000 m3 (3
tanks each with
160,000m3)
320,000 m3 (2
tanks each with
160,000 m )
Sendout
Capacity
1.5Bcf/d
2.6 Bcf/d
2.6 Bcf/d
Phase 1: 1
Bcf/d
Phase 2: 2
Bcf/d
Phase 1: 1
Bcf/d
1 Bcf/d
Vaporizer Design
Closed-loop:
Air heat exchanger
(heating tower)
Supplemental gas-
fired heater for cold
weather
Closed-loop:
Gas-fired heater
Closed-loop:
Gas-fired heater
Closed-loop:
Gas-fired heater
Closed-loop:
Gas-fired heater
Closed-loop:
Water heat exchanger
(waste water from the
chemical plant)
LNG Ship
Frequency
200 ships/
year
300 ships/
year
300 ships/
year
Phase 1: 1
ship/4 days
(91 ships/
year)
Phase 2: 1
ship/2 days
(183 ships/
year)
1 ship/4 days
(91
ships/year)
1 ship/3 days
17 E-mail communication from James Martin, FERC, to Carey A. Johnston, U.S. EPA, August, 4,2004.
5-772
-------
§ 316(b) Phase III - Technical Development Document
Technology Cost Modules
Exhibit 3-79. Proposed U.S. Onshore LNG Import Terminals (continued)
No.
7
8
9
10
11
12
13
14
15
16
17
18
Project Name/Operator/
FERC Docket No.
Port Arthur LNG Receiving
Terminal Project (Sempra)
Docket No. PF04-1 1-000
Cameron LNG, LLC
(Sempra Energy)
CP02-374-000
CP02-376-000
CP02-377-000
CP02-378-000
$700 million facility cost
Weaver's Cove LNG
CP04-36-000
$250 million facility cost
BP Crown Landing LNG
PF04-2-000
PF04-5-000
$500 million facility cost
Long Beach LNG
(Sound Energy Solutions)
CP04-58-000
$400 million facility cost
Keyspan & BG LNG
CP04-223-000
CP04-293-000
Somerset LNG
Cheniere Mobile
Cherry Point Energy LLC -
online in 2008
Somerset LNG
Waterbury LNG
- online in 2007
Cheniere LNG
Location
Port Arthur, TX
Hackberry, LA
Fall River, MA
Logan Township,
NJ
Long Beach, CA
Providence, RI
Somerset, MA
Mobile, AL
(Pinto Island)
Columbia River,
OR
Somerset, MA
Waterbury, CT
Brownsville. TX
Storage
Capacity
480,000 m3 (3
tanks each with
160,000 m3)
480,000 m3 (3
tanks each with
160,000 m3)
200,000 m3 (1
tank)
450,000 m3
320,000 m3 (2
tanks each with
160,000 m3)
95,000 m3
Sendout
Capacity
1.5Bcf/d
1.5Bcf/d
0.4 Bcf/d
1.2Bcf/d
0.7 Bcf/d
0.5 Bcf/d
l.OBcfd
0.5 Bcf/d
1.2 Bcf/d
2 Bcf/d
Vaporizer Design
Closed-loop:
Gas-fired heater
Closed-loop
Closed-loop:
Gas-fired heater
Closed-loop:
Gas-fired heater
Closed-loop:
Gas-fired heater
Closed-loop:
Gas-fired heater
Closed-loop
LNG Ship
Frequency
150 ships/
year
210 ships/
year
50-70 ships/
year
100 ships/
year
146 ships/
year
50 ships/ year
Note: The FERC docket for each onshore LNG import terminal can be accessed using the docket number and the following website:
http://elibrary.ferc.gov/idmws/docket_search.asp.
The CWA § 316(b) Phase I rule applies to new land-based facilities, including LNG import terminals, that (1) use cooling water
intake structures to withdraw water from waters of the United States; (2) are required to obtain an NPDES permit issued under CWA §
402; (3) have a design intake flow of greater than 2 MOD; and (4) use at least 25 percent of water withdrawn for cooling purposes (see
40 CFR 125.81). (EPA, 2004 - clarification memo). Under the Phase I rule, new facilities include only greenfield or stand alone
facilities. A greenfield facility is one that is constructed at a site at which no other source is located, or that totally replaces the process
or production equipment at an existing facility (see 40 CFR 125.83). A stand alone facility is a new, separate facility that is
constructed on property where an existing facility is located and whose processes are substantially independent of the existing facility
at the same site (see 40 CFR 125.83). In addition to being either a greenfield or stand alone facility, the facility must have commenced
construction after January 17,2002 and must use a newly constructed cooling water intake structure or an existing cooling water
intake structure whose design capacity is increased (see 40 CFR 124.83).
Any land-based facility that meets the applicability criteria is subject to the Phase I rule, even if the facility or industrial sector was
not explicitly listed as a Phase I facility in the record to the Phase I rule. EPA found that the industries it analyzed could serve as
surrogates for other industries to which the new facility rule applies. Therefore, new land-based LNG import terminals that meet the
applicability criteria of the Phase I rule (see 40 CFR 125.81) are subject to the rule. EPA notes that the new facility rule does contain
an alternative requirements provision for situations when a particular facility has costs wholly out of proportion to those considered by
EPA in the rulemaking or when compliance would result in significant adverse impacts on local air quality, local water resources
(other than impingement and entrainment) or local energy markets (see 40 CFR 125.85).
5-775
-------
§ 316(b) Phase III - Technical Development Document
Technology Cost Modules
3.3 New Offshore LNG Import Terminals
The Phase I new facility rule does not apply to offshore facilities. EPA specifically exempted the offshore oil and gas extraction
industry in the Phase I rule (see 40 CFR 125.80(d)) and confirmed the exclusion of new offshore LNG import terminals from the Phase
I new facility rule in a recent memorandum to EPA Regions. (EPA, 2004 - clarification memo) EPA identified eleven company
announcements of proposed U.S. offshore LNG import terminals with one company proposing a pilot study (see Exhibit 3-80). A
large majority of the these facilities are planned for the Federal Outer Continental Shelf 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).18
The U.S. Coast Guard is responsible for developing and maintaining regulations and standards for deepwater ports. Current projects
include regulations for deepwater ports (33 CFR Subchapter NN), specifically updating existing rules and adding provisions for
natural gas. The passage of the Maritime Transportation Security Act of 2002 (MTSA), which added natural gas to the Deepwater
Port Act, heightened interest within the energy industry to develop deepwater ports.
The U.S. Coast Guard has primary authority over construction and siting of offshore LNG facilities, and oversees preparation of
environmental impact statements that examine the potential impact of the new facilities, as required by the National Environmental
Policy Act and the Deepwater Port Act of 1974 (DWPA), as amended (33 USC 1501 et seq). As specified by the Deepwater Port Act,
the environmental review and analysis must be completed within 356 days of the published Notice of Intent. Coast Guard oversight of
the offshore facilities continues as long as the facilities are operational, as the agency has responsibility for the safety and security of
LNG facilities and vessels in U.S. coastal waters. (DOE 2004) Eight deepwater port license applications have been received since the
Maritime Transportation Security Act was signed into law." EPA was able to summarize the most important information of these
eight proposed offshore LNG import terminals.
Exhibit 3-80. Proposed U.S. Offshore LNG Import Terminals
No.
1
2
3
4
5
6
7
Company
(Facility Name)
Excelerate
(GOM Energy Bridge)
ChevronTexaco
(Port Pelican)
Shell
(Gulf Landing)
BMP Billiton
(Cabrillo Port)
ConocoPhillips
(Compass Port)
Freeport McMoRan
(Main Pass Energy Hub)
Crystal Energy
(Clearwater Port)
Offshore Location
West Cameron 603 - GOM
100 miles offshore LA
Vermillion 140 - GOM
37 nautical miles from LA
West Cameron 213 - GOM
38 nautical miles from LA
Offshore Oxnard, CA
13.9 miles from CA
Mobile Block 910
88°12' West, 30°5' North
Main Pass 299 - GOM
16 miles from LA
Offshore Ventura, CA
1 1 miles from CA
EPA NPDES
Permit
Information
Yes
Yes
Yes
No
No
No
No
USCG Deepwater Port
Licensing Information
(Docket No.)
Yes
(14294)
Yes
(14134)
Yes
(16860)
Yes
(16877)
Yes
(17659)
Yes
(17696)
Yes
(TBD)
18The Federal OCS starts approximately 10 miles from the Florida and Texas shores.
19 U.S. Coast Guard, 2004. Deepwater Ports Standards Division Website,
http://www.uscg.mil/hq/gm/mso/mso5.htm.
3-174
-------
§ 316(b) Phase III - Technical Development Document
Technology Cost Modules
Exhibit 3-80. Proposed U.S. Offshore LNG Import Terminals (continued)
No.
8
9
10
11
12
Company
(Facility Name)
ExxonMobil (Pearl
Crossing)
ChevronTexaco
(Port Penguin)
El Paso Global
Excelerate Energy
(Northeast Gateway)
Conversion Gas Imports
Offshore Location
West Cameron 220 - GOM
41 miles offshore LA
Offshore CA
Exact Location: TBD
Offshore Belmar, NJ
Exact Location: TBD
Offshore Boston, MA
Exact Location: TBD
Vermillion 179 - GOM
EPA NPDES
Permit
Information
No
No
No
No
No
USCG Deepwater Port
Licensing Information
(Docket No.)
Yes
(18474)
No
No
No
No
Note: "EPA NPDES Permit Information" indicates whether the company has applied for an NPDES permit application. "USCG
Deepwater Port Licensing Information" indicates whether the company has applied for a deepwater port license. The USCG
docket for each Deepwater Port license application can be accessed using the docket number and the following website:
http://dms.dot.gov/search/searchFormSimple.cfrn.
Excelerate - GOM Energy Bridge
Excelerate is proposing to construct, own, and operate an LNG import terminal 100 miles offshore in the GOM. The Excelerate GOM
Energy Bridge deepwater port will consist of a submerged turret loading (STL) system that is comprised of a submerged turret buoy;
chains, lines and anchors; a flexible riser; and a subsea manifold. Gas will be delivered to the deepwater port by conventional LNG
vessels which incorporate shipboard re-gasification capabilities.20 The vessels that will be used to deliver natural gas to the Excelerate
GOM Energy Bridge deepwater port will have a capacity to hold 138,000 m3 of LNG and, unlike all other LNG vessels currently in
operation, will re-gasify the LNG on-board at the point of delivery so that imports will consist of gas in its vaporous state, rather than
in a liquefied state. The a water depth at this deepwater port is 280 feet.21 This import terminal will vaporize and deliver natural gas
on average approximately 0.55 Bcfd of LNG. A fully loaded LNG vessel will be able to discharge its cargo in about six to eight days,
depending on operating conditions. The approximate cost of the STL subsea system is $50.7 million with a projected completion date
of December 2004. The following information comes from the Excelerate application for deepwater port license and draft
Environmental Assessment. (USCG, 2003 - draft EA El Paso)
When the specially configured LNG vessels reach the location of the deepwater port, they will retrieve and connect to the STL system.
For that purpose, a winch located on the LNG vessel will raise the submerged buoy from its subsurface location, where it is located
when not connected to an LNG vessel. The buoy will be drawn into an opening in the hull of the vessel. After it is secured to the
LNG vessel, the buoy will serve both as the mooring system for the vessel and as the offloading mechanism.
The maximum rate of discharge of the natural gas from an LNG vessel into the STL will be determined by a combination of the
availability of capacity on downstream pipelines and the re-gasification capabilities of the facilities located on-board each specially
configured LNG vessels. Each of the LNG vessels will have six shell-and-tube vaporizers located on-board. During the re-
gasification process, five of the vaporizers will normally be in operation, with the sixth serving as a backup or available for peak
demand. Each of the vaporizers will have a normal send-out capability of 0.1 Bcfd a peak capacity of 0.115 Bcfd.
Each specially configured LNG vessel will integrate complete offshore re-gasification capabilities into its shipboard system. The re-
gasification system can operate in open loop mode, closed loop mode, or together in a combination mode. In the open loop mode, the
LNG vessel will intake seawater from the surrounding area to heat the LNG. The warm seawater will pass through the shell and tube
vaporizer indirectly heating the LNG. Then the LNG vessel will discharge this water through its keel.
20E1 Paso Energy Bridge GOM LLC Application for Deepwater Port License,
http://dmses.dot.gov/docimages/pdf84/219001_web.pdf, December 20,2002.
2IU.S. EPA, 2003. El Paso Energy Bridge Gulf of Mexico, LLC Draft NPDES Permit No. GM0000003,
Fact Sheet, http://www.epa.gov/region6/6wq/npdes/genpermt/gm3factsheet.pdf.
3-775
-------
S 316(b) Phase HI - Technical Development Document Technology Cost Modules
In the closed loop mode, steam from the LNG vessel propulsion boilers will heat water circulated in a closed loop through the shell
and tube vaporizer and a steam heater. After the cycle, the water will be re-circulated through the system. There is no seawater intake
or discharge for the re-gasification process in the closed loop mode. The closed loop mode allows for LNG re-gasification when
surrounding seawater temperatures are too cold for the more efficient open loop mode. In the open loop mode, the system can re-
gasify up to 0.69 Bcfd. However, due to operating constraints related to downstream pipelines, the system for the Excelerate LNG
import terminal will re-gasify a maximum of 0.55 Bcfd in the open loop mode. Closed loop steam operations can re-gasify up to 0.45
Bcfd.
Excelerate is proposing to operate the specially configured LNG vessels in open loop mode exclusively. (USCG, 2003 - draft EA El
Paso) The open loop mode would draw seawater from the surrounding area at approximately 23.0 ft below the water surface. Intake
structures on the LNG vessels are sized to provide seawater for both standard ship operations and the warming water for the LNG
vaporizers. To supply natural gas at a rate of 0.55 Bcfd, the LNG vessel would require a total intake flow of 76.1 MGD. As
previously mentioned, this offshore LNG import terminal is subject to the NPDES Permit Program; withdraws more than 2 MGD in
the open loop mode; and uses more than 25 percent of the seawater intake for cooling purposes in the open loop mode.
Using a single sea chest inlet, the combined cooling water and warming water intake velocities would be approximately 3.9 feet per
second. A sea chest is an underwater compartment within the vessel's hull through which sea water is drawn in or discharged. A
passive screen (strainer) is set along the flush line of the sea chest. Pumps draw seawater from open pipes in the sea chest cavity.
Excelerate is proposing to connect two of the LNG vessels four sea chests internally to increase the intake area and reduce average
intake velocity. Using this scenario, the intake velocity at the two sea chests would be approximately 1.0 feet per second. The sea
chest intakes incorporate metal slotted grating on 21 millimeters spacings to reduce the impingement of aquatic organisms. This mesh
size would not prevent the entrainment of eggs and larvae of marine fish species.
All of the seawater entering the sea chest intakes either for ship operations or for the re-gasification process will pass through a copper
cathode antifouling system. The copper anodes release a small amount of copper into the ships seawater system at the intake to
prevent biota in the seawater from establishing within the seawater flow path. This will also control non-native species. Temperature
of the discharge water will be approximately 13.5 "F less than the temperature of the intake water. A marine growth prevention system
with copper and aluminum anodes will treat seawater to prevent biological build-up in the onboard equipment.
ChevronTexaco - Port Pelican
Port Pelican LLC, a subsidiary of ChevronTexaco, is proposing to construct, own, and operate an LNG import terminal 37 nautical
miles offshore.22 The water depth at the offshore LNG import terminal will be approximately 79 to 86 feet. The Port Pelican import
terminal will consist of two concrete gravity based structure (GBS) units fixed to the seabed, which will include integral LNG storage
tanks, support deck mounted LNG receiving and vaporization equipment and utilities, berthing accommodations for LNG carriers,
facilities for delivery of natural gas to a pipeline transportation system, and personnel accommodations.23 The Port Pelican import
terminal will be constructed in two phases. Phase I includes the installation of two GBS structures with internal storage tanks and
facilities for LNG offloading, send out and vaporization to deliver a peak 1.0 Bcfd of natural gas to pipeline. Phase II will increase the
capacity to 2.0 Bcfd of natural gas to pipeline. The approximate cost for this project is approximately $800 million for both phases.
Phase I is expect to be complete by 2006 with Phase II completed by 2008. The following information comes from the Port Pelican
LLC application for deepwater port license and draft Environmental Impact Statement.24
Sea water will flow through intake screens to eliminate debris and marine life before being pumped to the vaporizers through strainers.
To control biofouling, sodium hypochlorite will be injected into the pump suction to achieve a free chlorine concentration of 0.2 ppm.
In addition, each pump will be shocked for 20 minutes three times per day at a level of 2.0 ppm free chlorine.
Two parallel vaporization trains (average capacity of 0.8 Bcfd and peak capacity of 1.0 Bcfd each) will be provided, one in Phase I and
a second in Phase II, to vaporize LNG and deliver natural gas at a pressure of up to 1,440 psig. Each 1.0 Bcfd train consists of six 0.2
Bcfd, each with an LNG sendout pump, an Open Rack Vaporizer (ORV), and a seawater lift pump. Five of the six trains will be
22U.S. EPA, 2003. Port Pelican LLC Draft NPDES Permit No. GM0000001, Fact Sheet,
http://www.epa.gov/earth 1 r6/6wq/npdes/genpermt/draftgmOOOOOO 1 .pdf.
23Port Pelican LLC Application for Deepwater Port License,
http://dmses.dot.gOV/docimages/pdf84/210833_web.pdf, December 27,2002.
24Draft Environmental Impact Statement for Port Pelican LLC Deepwater Port License Application,
http://dmses.dot.gov/dociniages/pdf86/244607 web.pdf,
3-776
-------
§ 316(b) Phase III - Technical Development Document
Technology Cost Modules
operating during peak sendout rate (1.0 Bcfd each), and one will be used as a spare. The LNG flow rate will be approximately 178
tons/hour to deliver 0.2 Bcfd of gas. The intake water is not used for any cooling purposes.
The LNG sendout pumps will discharge LNG into the ORVs where it is warmed and flashed by seawater heat exchange at a peak
vaporizing capacity of 0.2 Bcfd. ORV technology uses seawater flowing over a series of panel coils to warm the LNG that is flowing
countercurrent within the panels (see Figure 3-81). Sea water flows through intake screens to eliminate debris and marine life, and is
then pumped to ORVs through strainers. Intake screens are designed and operated at intake velocities set to minimize impingement
and entrainment of marine organisms.
Figure 3-81. Open Rack Vaporizer (from Port Pelican LLC Deepwater Port License Application)
Open Rack Vaporizer
Nature I Gas QuIM
\
Heal Exchange
Panel Bbck
Seawater lift pumps bring treated seawater to the top of ORVs. From there it cascades over the ORV panel coils and creates a falling
film of water which exchanges heat with the upward-flowing high pressure LNG from the sendout pumps. This process will warm the
LNG to approximately 35°F and in the process vaporize it; and it will cool the water by approximately 20'F. The cooled water is
collected in a concrete basin and discharged to the GOM after it passes once through the system.
The maximum seawater intake rate is 12,250 gallons per minute (GPM) per pump with an intake velocity of 0.5 feet per second per
pump. Seawater then flows from the bottom of the ORVs into a trench routed to the seawater outfall. At peak capacity, the seawater
lift pumps will circulate 88.2 MGD of water through the ORVs during Phase I (five out of six trains in use), and at the completion of
the Phase II expansion, water circulated would be 176.4 MGD (10 out of 12 trains in use). During normal operations, four trains will
circulate 70.5 MGD of seawater during Phase I, and eight trains will circulate 141 MGD of seawater during Phase II through the
ORVs.
Shell - Gulf Landing
The Shell Gulf Landing LNG terminal facility (Gulf Landing LLC) will receive LNG from marine vessels, store the gas, then re-gasify
the LNG and deliver it to pipelines for distribution and sales to the United States. The facility throughput is planned at 7.7 million
tonnes per annum of LNG. This will be provided by approximately 135 carriers per year, dependent upon the size of the carriers used.
Each LNG carrier will unload its cargo into the terminal storage tanks. This process takes approximately 24 hours from arrival to
departure. The facility will vaporize and deliver natural gas at a rate of approximately 1.0 Bcfd on a continuous basis. The
5-777
-------
§ 316(b) Phase HI - Technical Development Document Technology Cost Modules
approximate cost is $700 million. Installation of the terminal is schedule for the 4th quarter of 2008 with the first deliveries of LNG
schedule for January 2009.25
Gulf Landing LLC has proposed discharges from six outfalls: (1) thermal water for open rack vaporizer (ORV) at 136 MGD; (2) deck
drainage wastewater at 0.0058 MGD; (3) uncontaminated deck water at 0.0209 MGD; (4) desalinization rejected water at 0.0254
MGD; (5) treated sanitary & domestic wastewater at 0.0075 MGD; and (6) firewater bypass at 0.5035 MGD.26 The intake water is not
used for any cooling purposes.
Outfall 001 discharges seawater that is passed through the ORV process system. Seawater from the intake structure is screened and
treated with sodium hypochlorite at the intake pumps to control marine growth in the system. The treated seawater is then distributed
to the ORV system. The ORV serves as the warming energy to gasify the LNG. The water is cooled during this heat exchange to
about 18°F from the ambient intake seawater temperature.
The seawater is treated with sodium hypochlorite, at a continues rate of approximately 2.0 mg/1. Periodically, each pump will be
shocked with 5.0 mg/1 for one hour during every 8-hours of pump run time. At capacity, the facility will have four pumps. The ORV
intake structure is designed to limit intake water velocity to less than 0.5 feet per second. This velocity will help to lessen
impingement of marine aquatic organisms from the intake screens. The intake ports will be covered with a 0.25 inch mesh screen to
lessen entrainment.
As discussed in the draft Environmental Impact Statement for the Gulf Landing LLC deepwater port license application27 and in
responses to EPA questions,28 Gulf Landing LLC is taking the following steps to reduce entrainment and impingement of aquatic
organisms:
• Intakes are located as close as practical to the sea bottom to reduce the potential for entrainment of smaller aquatic organisms
which are more likely to be near the surface.
• The intakes are designed for horizontal flow to minimize the potential for water coning from the surface.
• Intake screens are provided with a 0.25 inch mesh screen to lessen entrainment.
• Intake screens with wedgewire technology to reduce the potential for impingement.
• Minimization of warming water throughput requirements for the installation by using the maximum practical inlet to outlet
seawater temperature change of 18°F.
• Limit water intake velocity to less than 0.5 feet per second. (This is based on 2 x 100% intake systems, which allow for
period cleaning; with the maximum throughput of the facility. In practice velocities during normal operation will significantly
lower.)
• A commitment to monitor impingement and entrapment of marine life during the first two years of operation to establish the
impact of the facility on marine life, and a commitment to implement reasonable and practical improvement measures if
warranted scientifically through the monitoring program.
BHP Billiton - Cabrillo Port
The BHP Billiton proposes to construct, own, and operate an LNG import terminal, Cabrillo Port, approximately 13.9 miles off the
coast of Ventura County in Southern California, in 2,900 feet of water. The permanently moored import facility (floating storage &
re-gasification unit) will include three storage tanks, eight vaporizers, and an underwater, 21.1 mile pipeline that would connect to an
existing onshore pipeline. Maximum water depth at the location of the planned mooring is about 2,900 feet. The floating storage and
re-gasification facility will vaporize and deliver natural gas at a maximum rate of approximately 1.5 billion cubic foot a day, with an
anticipated average rate of 0.6 to 0.9 Bcfd. The BHP Billiton LNG import terminal is designed to accommodate LNG carriers ranging
25Gulf Landing LLC Application for Deepwater Port License,
http://dmses.dot.gov/docimages/pdf88/265164_web.pdf, January 14,2004.
26U.S. EPA, 2003. Gulf Landing LLC Draft NPDES Permit No. GM0000004, Fact Sheet,
http://www.epa.gov/earthlr6/6wq/npdes/gmpn/gm4fact.pdf.
"Draft Environmental Impact Statement for The Gulf Landing LLC Deepwater Port License Application,
http://dmses.dot.eov/docimages/pdf89/286049 web.pdf. June 2004.
28E-mail communication from John Hritcko, Shell US Gas & Power, LLC, to Carey A. Johnston, U.S. EPA,
March 12, 2004, "Shell Responses to EPA Questions Dated October 23, 2003, Regarding Liquefied Natural Gas
Import Terminals."
3-178
-------
§ 316(b) Phase III - Technical Development Document Technology Cost Modules
in capacity from 100,000 m3 to 220,000 m3. LNG carriers typically will be offloaded at a rate of 80,000 gallons per minute of LNG
through the liquid loading arms and stored in the LNG storage tanks at a temperature of approximately minus 260'F. This LNG
import terminal is projected to have 320,000 m3 in storage capacity at the receiving facility. The approximate cost of this project is
$550 million with a projected completion date of 2008. The following information comes from the Cabrillo Port application for
deepwater port license.29
The BHP Billiton LNG import terminal is designed to no use sea water for the re-gasification process. This facility is proposing to use
submerged combustion vaporizers using LNG as the fuel. The LNG is pumped, as liquid, up to the 1,500 psig natural gas send out
pressure and maintained at that pressure through the vaporization process. The vaporization portion of the process re-gasifies the
LNG. The process will consist of eight submerged combustion vaporizers (SCVs). Each will have a maximum capacity of 198 short
tons per hour of LNG vaporized. The SCVs will superheat the resultant natural gas to a temperature of about 41 T at a pressure of
about 1,500 psig. The combustion vaporization process is thermally stabilized by submersion in a water bath. No compression of the
natural gas is required.
BHP Billiton evaluated several options including the intermediate fluid vaporizers (IF) and open rack vaporizers (ORV). IFV and
ORV use seawater as a heat source while SCV uses natural gas combustion. For the BHP Billiton LNG import terminal the IFV and
ORV alternatives would require about 50 MGD of seawater. In these alternatives, seawater would flow through the vaporizers and
then would be returned to the ocean at a lower than ambient temperature. BHP Billiton identified that the primary benefit of IFV and
ORV relative to the proposed SCV is lower air emissions. SCV burns natural gas equivalent to 2% of the LNG throughput to generate
heat. Other industry estimates suggest that this energy penalty is closer to 1.5%. (Hall, 2004) This is similar to the 1.5% energy
penalty identified in the 316(b) Phase I new facility rule for cooling towers at electric power generators. The combustion process
relies on natural gas from LNG, so it is a cleaner fuel. With SCV the exhaust gases also flow directly through a water bath, which acts
as a quench and abatement system. The SCV air emissions will include oxides of nitrogen (NOx), and carbon dioxide. IFV and ORV
would introduce some air emissions, which are of an order of magnitude less than SCVs because of the incremental electricity
necessary to operate the large seawater pumps.
BHP Billiton identified concerns over the potential intake of 50 MGD of seawater associated with the IFV and ORV alternatives.
Specifically, BHP Billiton identified concerns over entrainment and impingement of marine species, thermal plumes, turbidity, treated
water discharge and noise. Impingement could occur when fish and other aquatic life are trapped against the water intake screens.
These screens prevent marine organisms and debris from entering and interfering with the re-gasification process. Entrainment occurs
when aquatic organisms, including eggs and larvae, are drawn into the water intakes, through the facility, and then pumped back out.
Thermal plumes could result from the constant discharge of large quantities of relatively cold, and therefore relatively dense, water.
BHP Billiton identified that the proposed mooring location is of sufficient depth that a thermal plume would not be likely to impact the
sea floor. Turbidity would be a result of a thermal plume disturbing sea floor sediments. Additionally, the IFV and ORV alternatives
would likely use sodium hypochlorite or another oxidizer to control the growth of marine organisms in the IFV and ORV equipment.
BHP Billiton identified that discharge of the residual sodium hypochlorite in IFV and ORV water could impact marine organisms, and
would require a NPDES permit. Noise would be generated by the large seawater pumps required for the seawater intake alternatives.
In general, BHP Billiton identified that the use of IFV and ORV would be difficult to permit and operate because of water discharge
rules and restrictions and impacts to marine biota. The use of SCV would produce air emissions that could be minimized by emission
control technology. BHP Billiton select SCV for the re-gasification process as the re-gasification alternatives to SCV do not provide
clear environmental benefits.
ConocoPhillips - Compass Port
Compass Port LLC, a wholly owned subsidiary of ConocoPhillips Company, proposes to construct, own, and operate an LNG import
terminal 33 miles from the southern city limit of Mobile, Alabama and 11 miles south of Dauphin Island, Alabama, in a water depth of
approximately 70 feet. The facility will vaporize and deliver natural gas at a rate of approximately 1 billion cubic foot a day on a
continuous basis. The maximum unloading period for a ship is designed to be 20 hours at this LNG import terminal. To achieve this
rate, the unloading system will be designed to deliver 255,000 cubic meters of LNG from a ship to the storage tanks within 12 to 14
hours. The expected completion date is 2009.
As shown in Figure 3-82, Compass Port LLC import terminal will incorporate: (1) docking facilities for conventional LNG carriers;
(2) unloading facilities for the unloading of LNG cargo; (3) two full containment tanks for the storage of LNG; (4) re-gasification
facilities to convert LNG into natural gas; (5) an offshore natural gas pipeline; and (6) related facilities to support the operation of
29Cabrillo Port Application for Deepwater Port License, http://dmses.dot.gov/docimages/p77/265927.doc,
January 21,2004.
3-779
-------
§ 316(b) Phase III - Technical Development Document
Technology Cost Modules
Compass Port.30 Construction and installation of the proposed port will take approximately 42 months to complete, beginning in 2005,
providing for approximately 12 months for pre-construction activities. The following information comes from the Compass Port LLC
application for deepwater port license.
The Compass Port LLC import terminal will consist of two concrete gravity-based structures fixed to the seabed that contain the
integral LNG storage tanks, the LNG re-gasification facilities, and other operational equipment including mooring platforms, a
docking platform that contains LNG unloading equipment, and a flare platform. There also will be a separate platform for support
facilities such as personnel quarters, and other auxiliary structures.
The Compass Port LLC import terminal will utilize a total of six water intake structures and ORV for the re-gasification process. Each
intake structure will consist of a hollow steel caisson that will extend from a manifold on the cellar deck of the re-gasification platform
to beneath the water surface. Each steel caisson will be fixed to the re-gasification platform jacket structure by a series of welded
supports. A submersible pump will be located in each intake structure and will have a maximum design pumping capacity of 30.4
MOD. In normal operation only four pumps are working and in cold weather conditions five pumps are working for a total DIP of
152.2 MOD. The sixth pump is a kept and maintained as a spare.
Figure 3-82. Compass Port LLC Proposed LNG Import Terminal
Each intake caisson will be fitted with a cylindrical wedgewire screen with 0.25-inch slot size openings. Preliminary design estimates
are that each intake screen will measure approximately 3.9 feet in diameter and approximately 14.8 feet in length. The center of each
intake screen will be located at the mid-depth of the water column (approximately 36 feet below the water surface). The intake
pumping systems and screens will be designed to maintain a through-slot velocity of no greater than 0.5 feet per second. As needed, a
lifting mechanism will be used to lift the intake screens to the re-gasification platform for cleaning. The intake water is not used for
any cooling purposes.
To minimize biological fouling, seawater will be treated with sodium hypochlorite applied at a continuous rate of approximately 0.2
mg/1. Periodically, each pump will be shocked with 2.0 mg/1 of hypochlorite for 20 minutes during every 8 hours of pump run time.
The facility will not shock any more than one unit at a time. Discharge seawater temperature will be approximately 14.8'F cooler than
the ambient water at the discharge points. The thermal discharge plume at 100 meters from the discharge location is predicted to
approach ambient temperature (less than 1'C below ambient).
Freeport McMoRan - Main Pass Energy Hub
The Main Pass Energy Hub (MPEH) is proposed to deliver an average of 1.0 Bcfd of LNG. The water depth at the LNG import
terminal is approximately 210 feet. The project involves the reuse of four existing platforms and three smaller bridge supports along
30Compass Port Application for Deepwater Port License,
http://dmses.dot.gov/docimages/pdf89/284087 web.pdf. March 29, 2004.
3-180
-------
§ 316(b) Phase III - Technical Development Document Technology Cost Modules
with the interconnecting bridges formerly used in sulphur mining operations at Main Pass 299. This LNG import terminal will use salt
caverns its design and ORVs to re-gasify LNG at a design capacity of 1.6 Bcfd.31 The vaporized natural gas heated to 40' F. The
approximate cost of this project is $500 million with a projected completion date of 2006. The following description of the MPEH is
from the deepwater port license application for the Main Pass Energy Project.
At peak vaporization rate, all the ORVs will be in operation. Nine operating ORVs are required to meet the 1.6 Bcfd design
vaporization capacity with the gas conditioning plant in operation. ORVs utilize seawater as the heating medium for vaporization of
LNG. The heat transfer surface will be vertical, panel-shaped tubes of aluminum-zinc alloy for seawater resistance, and an aluminum
base/tube assembly. LNG will flow upward inside finned heat transfer tubes, with seawater flowing downward along the outside of
the tubes.
Six seawater lift pumps will be provided, each with a design capacity of 33.4 MGD (total of approximately 200 MGD) and a
differential head of 120 psi. Normally, five pumps will be in operation and one will be an installed spare. During winter operations
when seawater temperatures are lower, the sixth seawater lift pump may be operated to obtain adequate heat transfer. Seawater will be
pumped to the top of the ORVs where it will be distributed in overhead troughs to create a water film falling as a sheet in contact with
the vertical tube surface. The seawater temperature will be reduced by approximately 22"F through the ORV and will be collected in a
basin for discharge back to the sea. The intake water is not used for any cooling purposes.
Seawater lift pumps have intake screens to eliminate debris and minimize impacts on marine life. These screens are passive,
cylindrical wedgewire-type screens. They have no moving parts and are easy to maintain. The screens are designed so that the intake
flow is at a uniform low velocity across the entire screen surface and limited to 0.5 feet (0.2 meters) per second. The protective screen
has a slot width of 0.25 inches (0.6 cm). This will minimize impingement and entrainment of marine organisms. Concentrations of
marine organisms are greater near the water surface and decrease with depth. To minimize entrainment of marine organisms such as
ichthyoplankton (fish eggs and larvae), the top of the intake screens will be located deeper than 65 feet (19.8 meters) below MSL.
This location of seawater intake has the advantage of being well below the near-surface concentrations of marine organisms and
shallow enough for routine diver maintenance access. An automated air backwash system will periodically remove impinged debris
from the screen surface. The backwash system will be automated based on a timed sequence or measurement of pressure drop through
the screens.
Waters used in the vaporization of the LNG will be discharged through three outfall pipes at least 120 feet (37 meters) below MSL.
Each outfall pipe will have two 45-degree deflectors at the terminus in order to promote mixing with the surrounding waters. Sodium
hypochlonte will be injected continuously into the suction of the operating seawater lift pumps for bio-fouling control at a rate to attain
a residual chlorine level of 0.5 to 1.0 ppm. The system will be designed to inject up to 2.0 ppm continuously and up to 5.0 ppm on a
"shock" basis into each of the operating pumps and operating ORV inlet branch headers for 20 minutes every 24 hours; these latter
shock injections will be staggered so that no more than one point is shock-dosed at any one time. Operations will monitor the residual
chlorine levels and adjust the dosing rate as needed.
At peak capacity, the seawater lift pumps will circulate approximately 200 MGD of water through the ORVs. ORV maintenance will
consist of occasional cleaning, the frequency of which will depend on the cleanliness of the seawater. Daily observation will ensure
that ice does not build up on the panels.
31Deepwater Port License Application for the Main Pass Energy Project,
http://dmses.dot.gov/docimages/pdf89/284544 web.pdf. February 2004.
3-181
-------
§ 316(b) Phase III - Technical Development Document Technology Cost Modules
Crystal Energy - Clearwater Port
Crystal Energy LLC signed a long-term lease agreement to retrofit an existing offshore oil and gas facility (Platform Grace), located
11 miles offshore of Ventura County in Federal waters, as an LNG import terminal. The water depth at Platform Grace is 318 feet.32
The proposed project is estimated to deliver more than 200 billion cubic feet of natural gas from Alaska annually to California."
Crystal Energy LLC estimates that approximately two to four ships per month will offload at this LNG import terminal. Each ship will
carry approximately 2.75 billion cubic feet of LNG, which will take approximately four days to offload. The peak LNG transmission
capacity for the project is projected to be 1.275 Bcfd with an average LNG transmission capacity of 0.8 Bcfd. This LNG import
terminal will not store any of the offloaded LNG at the receiving facility (Platform Grace). The approximate costs of this project is
$160 million with a projected completion date of 2006.
Use of this platform as a liquefied natural gas receiving and processing facility will require the installation of a cool down tank, four
liquefied natural gas pumps, four liquefied natural gas vaporizers, and reinstalling and upgrading the platform's power production
capability.34 Crystal Energy LLC recently filed its deepwater port application with the U.S. Coast Guard, however, the docket for this
application has not been established. Initial indications are that this facility will use SCVs to re-gasify the LNG and not use an open
loop vaporization process with surface water intakes. This project also identifies that it would supply local jurisdictions with "up to 40
million gallons of clean water annually that are a byproduct of the re-gasification process."35
Construction costs for the Crystal Clearwater Port project, which is anticipated to begin operation in 2007, are estimated at $300
million. The estimated life of the facility is approximately 50 to 100 years. This is based upon the original structural design of the
platform for offshore oil and gas drilling and production operations.
ExxonMobil (Pearl Crossing)
The application plan calls for the proposed deepwater port to be located in the Gulf of Mexico, approximately 41 miles south of the
Louisiana coast in West Cameron Block 220. It will be located in a water depth of approximately 62 feet.36
The proposed Pearl Crossing LNG Terminal is a concrete Gravity Based Structure (GBS). The terminal proposes to install two
integral liquefied natural gas storage tanks and serve as the platform for vessels to offload and regasify LNG. The proposed GBS is a
double-walled concrete structure, rectilinear in shape, that would measure approximately 590 feet long by 295 feet wide. The structure
would rest on the seabed with a total terminal footprint (GBS plus jacket structures) area of approximately 12 acres. T he terminal
would include LNG storage tanks, equipment for receiving and vaporization of LNG, electric power generation, water purification,
nitrogen generation, sewage treatment and accommodations for up to 60 persons. The total net working capacity of the two integral
LNG storage tanks would be 250,000 m3.
Pearl Crossing would have the ability to accommodate two LNG carriers alongside that will have capacities ranging from 125,000 to
250,000 m3 per vessel. This would allow one incoming LNG carrier to be secured to prepare to offload cargo, while another LNG
carrier is completing an offloading cycle. Offloading rates are expected to equal 14,000 m3 per hour of LNG. Peak send out for this
project is projected to average over 2.0 Bcfd with a peak capacity of 2.8 Bcfd.
32Larson, Eric, 2004. Presentation by Eric Larson, California Department of Fish and Game, "Navigational
Safety & Environmental Issues", http://www.energy.ca.gov/lng/documents/2004-02-24_DFG_LARSON.PDF,
February 24,2004.
"Crystal Energy LLC, 2004. Press Release, "Crystal Energy Secures Agreement for Domestic Energy
Supply to Meet Urgent Natural Gas Demand," http://www.crvstalenergvllc.com/pdf/media/AGPA.Ddf. January 28,
2004.
34Seehttp://www.crystalenergyllc.com/faq_operation.php
"Crystal Energy LLC, 2004. Press Release, "Crystal Energy Moves Forward to Bring Needed Natural Gas
to California," http://www.crvstalenergvllc.com/pdf/media/CrvstalFilingPressRelease FINAL.pdf. February 11,
2004.
36Federal Register. 69 FR 43619. July 21.2004.
3-182
-------
S 316(b) Phase in - Technical Development Document Technology Cost Modules
The re-gasification process would be accomplished through thirteen electric pumps that will each supply 19 MOD of seawater for the
ORV. Assuming a inlet to outlet water temperature decrease of 20°F, a volume of 247 MOD of surface water is required for peak
vaporization.37 The surface water intakes will utilize passive, cylindrical wedgewire-type screens with an automated air backwash
system. The slot size would be 0.25 inch or less to minimize impingement or entrainment of marine organisms. Seawater would be
treated with hypochlorite produced by an electrolytic chlorination unit prior to entering the seawater pump intake lines.
ChevronTexaco - Port Penguin
This is an off-shore Gravity Based Structure (GBS) project similar to the Chevron/Texaco project proposed for Baja California,
Mexico. This project is to have an LNG throughput of 0,5 Bcfd. ChevronTexaco has discussed the project publicly but has not
proposed a specific site. The location of this project has yet to be determined but will most likely be in southern California.38
El Paso Global (Belmar. NJ Offshore)
EPA was unable to gather information on this facility.
Excelerate Energy (Northeast Gateway)
This facility is proposed to be sited offshore of Boston, MA. The average vaporization rate is projected to be O.S^Bcfd (see Figure 3-
78). EPA was unable to gather other information on this proposed facility.
Conversion Gas Imports
Conversion Gas Imports (CGI) is conducting a study using salt caverns instead of man-made storage tanks to temporarily store LNG.
The CGI proposed terminal is designed to receive LNG directly from the tanker, pump the liquid stream to cavern injection pressures,
warm it to salt compatible temperatures, and inject the warmed dense phase natural gas into salt caverns for storage. There are no
vaporizer send-out limitations associated with cavern storage. The caverns can receive flow from a ship and redeliver to a pipeline
grid at rates greater than 3 Bcfd. LNG vessels are offloaded at rates comparable to the unloading rates at conventional liquid tank
based terminals.
CGI chose a Gulf of Mexico location in 30 meters of water, 75 kilometers off Louisiana on Vermilion block 179, for the upcoming
study because it is close to existing pipelines and on top of a salt formation starting 300 meters below the seabed.39 As shown in
Figure 3-83, CGI's proposed re-gasification system uses a simple pipe in pipe co-axial flow arrangement (LNG in inner pipe and
seawater between the inner pipe and outer pipe) running a calculated distance (2,500 feet) along the ocean floor from the offshore
underground salt caverns to shore. No gasified LNG is used in the warming process. It is unclear what quantity of seawater is used for
this re-gasification system, system's the intake velocity of seawater, or the change in inlet to outlet seawater temperature. It is clear,
however, that any seawater intakes associated with this system are associated with the re-gasification (warming system).
"Deepwater Port License Application for Pearl Crossing LNG Project, Environmental Report,
http://dmses.dot.gov/docimages/pdf89/288088_web.pdf, May 2004.
38See http://www.energy.ca.gov/lng/projects.html.
"See http://www.conversiongas.com/html/news.html.
3-183
-------
§ 316(b) Phase HI - Technical Development Document
Technology Cost Modules
Figure 3-83. Conversion Gas Imports Re-Gasification Schematic
LNG Process
Platform
Cavern
Platform
Cavern Gas
Storage
_ . Ocean .
U /Floor:
To subsea gas gathering
infrastructure
4.0 TECHNOLOGY OPTIONS AVAILABLE TO CONTROL IMPINGEMENT AND ENTRAINMENT OF AQUATIC
ORGANISMS
4.1 Summary of Technology Options to Control Impingement and Entrainment of Aquatic Organisms
As highlighted in this Chapter, re-gasification process of LNG is an endothermic process and requires a heat source. The LNG would
be pumped through some heating system, where it would absorb heat and vaporize, or re-gasify, into natural gas. Different
impingement and entrainment control options are available for onshore verses offshore LNG import terminals. Offshore LNG import
terminals may have significant space limitations which could significantly increase the costs and economic impacts and affect the
technical feasibility of implementing technology options available for onshore facilities. Moreover, one technology option for onshore
facilities, closed loop re-cycle with waste heat from another industrial facility, is not available for offshore facilities due to their
remoteness.
a.
Onshore LNG Import Terminals
The entrainment or impingement control technologies available for onshore LNG import terminals are similar to other industries.
However, onshore LNG import terminals are better able to design their operations in order to not require surface water withdrawals.
All existing onshore LNG import terminals use LNG vaporization systems with no surface water intakes and current information
indicates that all new onshore LNG import terminals are proposing to use LNG vaporization systems with no surface water intakes.
Existing Onshore LNG Import Terminals
As previous mentioned, EPA identified that none of the four existing continental U.S. LNG import terminals use surface water for
warming or cooling purposes, only as an emergency backup source to their firewater systems. For example, at the Dominion Cove
Point, Maryland, facility all water used on site is withdrawn from groundwater wells and is heated in the vaporizers and used to warm
the LNG and convert back to a gaseous state.
The remaining existing U.S. onshore LNG import terminal, the EcoElectrica facility in Puerto Rico, does use surface water
for makeup and discharges blowdown for the power plant cooling tower, but does not use surface water intakes directly for the LNG
processing (warming or cooling). The EcoElectrica LNG import terminal is a closed-loop facility that is integrated with a 500
megawatt electric power generator. This integration has benefitted the LNG import capabilities and boosted the electric power
generator output by 10% (Hall, 2004).
The fact that all five existing onshore LNG import terminals use LNG vaporization systems with no surface water intakes
demonstrates that this zero-water intake technology is available for this industrial sector.
3-184
-------
S 316(b) Phase III - Technical Development Document Technology Cost Modules
New Onshore LNG Import Terminals
As detailed in Exhibit 3-78, current information shows that all new onshore LNG import terminals are proposing to use LNG
vaporization systems with no surface water intakes (e.g., integration with other industrial facilities, heating towers, gas-fired heaters).
Operating LNG,import terminals in a closed-loop manner (i.e., no surface water withdrawals) is also consistent with recent
recommendations by the Export-Import Bank of the United States and the Gulf of Mexico Fishery Management Council to reduce
effluent discharges and minimize impingement and entrainment of aquatic organisms and the associated damages to recreational and
commercial fisheries and essential fish habitat.40'41 Some new facilities are also proposing to use waste heat from nearby industrial
facilities for their re-gasification (e.g., Ingleside Energy Center LNG Import Terminal, Corpus Christi, TX).
The integration of an LNG import terminal with a nearby or on-site industrial operation is a 'win-win' solution as it provides a
resource (cold water from LNG import terminal) to a nearby or on-site industrial facility. This integration can lead to the following
benefits for the nearby or on-site industrial facility: (1) increase operational efficiency, reduce operating costs, and (2) reduce or
eliminate thermal and chemical pollution and potential entrainment or impingement impacts from heat exchanger surface water
intakes. One estimate suggests that an electric power generator using cold water from an LNG import terminal can boost its efficiency
by 1 to 2%, resulting in cost savings (Hall, 2004). Finally, this integration reduces or eliminates the potential entrainment or
impingement impacts associated with the LNG re-gasification process as well as the thermal and chemical pollution associated with
the water intake LNG re-gasification processes.
b. Offshore Technology Options
As detailed in this chapter, the various re-gasification technologies proposed for offshore LNG import terminals include: (1) open rack
vaporizers (ORV); (2) submerged combustion vaporizers (SCV); (3) shell and tube vaporizers (STV); (4) closed-loop heat exchangers;
and (5) intermediate fluid vaporizers (IFV). Additionally, the CGI re-gasification process detailed above may find use in future LNG
import terminals.
Open Rack Vaporizer (ORV) Technology
It appears likely that six proposed U.S. offshore LNG import terminals will use Open Rack Vaporizer (ORV) technology for re-
gasification of LNG (i.e., Port Pelican, Gulf Landing, Compass Port, Main Pass Energy Hub, Pearl Crossing, Port Penguin). As
describe above and in Figure 3-81, this re-gasification technology uses large quantities of seawater (e.g., 50 to 200 MOD) flowing over
a series of panel coils to warm the LNG that is flowing countercurrent within the panels. Sea water flows through intake screens and
is then pumped to ORVs through strainers. Sodium hypochlorite is often injected into intake pumps as an anti-biofouling agent.
Pumps bring treated seawater to the top of ORVs, where it is released and creates a falling film of water which exchanges heat with
the upward-flowing high pressure LNG. This process will vaporize the LNG into natural gas, and seawater will be cooled by
approximately 10 to 20'F. There is the potential for localized cooling at the ORV topside and generation of fog or mist. Cooled
seawater is collected and discharged after it passes once through the system. The return seawater may contain 1 to 2 mg/L of
hypochlorite.
ORVs do not require combustion and are considered safe, as no moving parts are in contact with flammable fluids. ORVs do not
directly contribute to air emissions, but generate air emissions indirectly because of the electrical pump drives and electrical power
generation requirements.
All LNG import terminals propose to use ORV technology are designing the intakes with a through-screen velocity of 0.5 feet per
second or less in order to reduce impingement. Moreover, most of these LNG import terminals are proposing to use intake screens
with wedgewire technology to reduce the potential for impingement. Some are proposing to use cylindrical wedgewire screen with
0.25- inch slot size openings to reduce impingement and entrainment of aquatic organisms. Finally, some of these import terminals
using ORVs are proposing other control measures to reduce the impingement and entrainment of aquatic organisms:
• Locating the intakes as close as practical to the sea bottom to reduce the potential for entrainment of smaller aquatic
organisms which are more likely to be near the surface;
^Export-Import Bank of the United States, 2004. Environmental Guidelines - Table 10
Liquefied Natural Gas (LNG) Liquefaction Plants And Regasification Facilities,
http://www.exim.gov/products/policies/environment/envtbl 10.html, Revised : July 2,2004.
41 Walker, Bobbi, 2004. Letter from Bobbi Walker, Gulf of Mexico Fishery Management Council, to
Rolland Schmitten, NOAA National Marine Fisheries Service, June 9,2004.
3-185
-------
§ 316(b) Phase III - Technical Development Document Technology Cost Modules
• Designing intakes for horizontal flow to minimize the potential for water coning from the surface; and
• Minimizing warming water throughput requirements for the installation by using the maximum practical inlet to outlet
seawater temperature change of 18°F;
• Automated air backwash system; and
• Committing to monitor impingement and entrapment of marine life during the first two years of operation to establish the
impact of the facility on marine life, and a commitment to implement reasonable and practical improvement measures if
warranted scientifically through the monitoring program.
It should be noted that monitoring may be necessary for proper siting of water intake structures to avoid or minimize entrainment
impacts.
Submerged Combustion Vaporizer (SCV) Technology
It appears likely that two proposed U.S. offshore LNG import terminals will use Submerged Combustion Vaporizer (SCV) technology
for re-gasification of LNG (i.e., Cabrillo Port, Crystal Energy). As describe above, this re-gasification technology uses submerged
combustion vaporizers using LNG as the fuel. The SCVs will superheat the resultant natural gas to a temperature of about 41 T. The
combustion vaporization process is thermally stabilized by submersion in a water bath. No compression of the natural gas is required.
SCV burns natural gas equivalent to 1.5 to 2% of the LNG throughput to generate heat. This is similar to the 1.5% energy penalty
identified in the 316(b) Phase I new facility rule for cooling towers at electric power generators. Moreover, this 1.5% consumption of
LNG can be less than the LNG lost in transit on dedicated LNG tankers. The tanker's LNG cargo is kept cool by evaporating a
fraction of the cargo ("boiloff') and burning it as boiler fuel. Typically, 0.15 to 0.25 percent of the cargo is consumed per day, during
which the tanker will travel about 480 nautical miles.42
The combustion process relies on natural gas from LNG, so it is a cleaner fuel. With SCV the exhaust gases also flow directly through
a water bath, which acts as a quench and abatement system. The SCV air emissions will include oxides of nitrogen (NOx), and carbon
dioxide. The chief environmental benefit of this re-gasification technology is that it eliminates the issues associated with water intakes
(i.e., impingement and entrainment of aquatic organisms) and discharges (i.e., thermal and chemical pollution).
Shell and Tube Vaporizers
It appears likely that one proposed U.S. offshore LNG import terminals will use shell and tube vaporizer (STV) technology for
re-gasification of LNG (i.e., GOM Energy Bridge). This re-gasification technology uses seawater from seachests to provide the
necessary heat. The warming seawater will pass through the shell and tube vaporizer and indirectly heat the LNG. As describe above,
this re-gasification technology uses large quantities of seawater (e.g., approximately 80 MGD). The GOM Energy Bridge will draw
seawater from the surrounding area at approximately 23.0 feet below the water surface. Intake structures on the LNG vessels are sized
to provide seawater for both standard ship operations (including water intakes for cooling purposes) and the warming water for the
LNG vaporizers. As previously mentioned, this offshore LNG import terminal is subject to the NPDES Permit Program; withdraws
more than 2 MGD in the open loop mode; and uses more than 25 percent of the seawater intake for cooling purposes in the open loop
mode.
Using a single sea chest inlet, the combined cooling water and warming water intake velocities would be approximately 3.9 feet per
second. Excelerate is proposing to connect two of the LNG vessels four sea chests internally to increase the intake area and reduce
average intake velocity. Using this scenario, the intake velocity at the two sea chests would be approximately 1.0 feet per second. The
sea chest intakes incorporate metal slotted grating on 21 millimeters spacings to reduce the impingement of aquatic organisms. This
mesh size would not prevent the entrainment of eggs and larvae of marine fish species. It appears that future designs could reduce this
intake velocity to 0.5 feet per second to better control impingement. Other impingement and entrainment controls might include:
• Using intake screens with wedgewire technology to reduce the potential for impingement
• Locating the intakes as close as practical to the sea bottom to reduce the potential for entrainment of smaller aquatic
organisms which are more likely to be near the surface;
• Designing intakes for horizontal flow to minimize the potential for water coning from the surface; and
• Minimizing warming water throughput requirements for the installation by using the maximum practical inlet to outlet
seawater temperature change.
42U.S. DOE/EIA, 2001. U.S. Natural Gas Markets: Mid-Term Prospects for Natural Gas Supply,
SR/OIAF/2001-06, hrrp://www.eia.doe.gov/oiaf/servicerpt/natgas/pdf/sroiaf(2001)06.pdf, December 2001.
3-186
-------
S 316(b) Phase HI - Technical Development Document Technology Cost Modules
Closed-loop Heat Exchangers
It appears likely that one proposed U.S. offshore LNG import terminals has the potential to the use closed-loop heat exchangers for
re-gasification of LNG (i.e., GOM Energy Bridge). In the closed loop mode, steam from the LNG vessel propulsion boilers will heat
water circulated in a closed loop through the shell and tube vaporizer and a steam heater. After the cycle, the water will be re-
circulated through the system. There is no seawater intake or discharge for the re-gasification process in the closed loop mode. The
closed loop mode allows for LNG re-gasification when surrounding seawater temperatures are too cold for the more efficient open
loop mode. The chief environmental benefit of this re-gasification technology is that it eliminates the issues associated with water
intakes (i.e., impingement and entrainment of aquatic organisms) and discharges (i.e., thermal and chemical pollution). The main
disadvantage of this re-gasification system verses the shell and tube vaporizers (open loop) re-gasification system is that decreased rate
of LNG vaporization.
Intermediate Fluid Vaporizer (IFV> Technology
It appears likely that no proposed U.S. offshore LNG import terminals will use Intermediate Fluid Vaporizer (IFV) technology for re-
gasification of LNG. This re-gasification technology uses glycol/water mix to exchange heat with the LNG via a shell and tube
exchanger. The cold glycol mix is circulated continuously in a closed loop. A plate and frame or other type heat exchanger heats the
glycol mix using seawater as the heating medium. The equipment necessary for this system includes common heat exchangers and
pumps. Pumps are required for the seawater and for the circulated glycol mix. The quantity of circulated seawater is identical to that
required for the ORV, given environmental limits between the inlet and return water temperature. The LNG is vaporized from the heat
gained by the glycol and the glycol acquires heat from the seawater. The design must maintain LNG and glycol carefully to avoid
freezing on the glycol side of the vaporizer. In general, LNG import terminals using IFVs can use the same control measures as LNG
import terminals using ORVs to reduce the impingement and entrainment of aquatic organisms.
4.2 Incremental Costs Associated with Technology Options to Control Impingement and Entrainment of Aquatic Organisms
EPA estimated "sensitivity level" incremental technology option costs for new offshore LNG import terminals to control the
impingement and entrainment of aquatic organisms. EPA compared these incremental costs to the total estimated cost for construction
of a new offshore LNG import terminal to determine whether potential impingement and entrainment § 316(b) Phase III technology
options would impact the decision to begin construction of the new facility. EPA used information from USCG deepwater port
licensing applications (e.g., information on the type, size and number of the water intake structures) to estimate these "sensitivity
level" incremental costs for installation of impingement and entrainment equipment for some of the offshore LNG import terminals
identified in Exhibit 3-79.
EPA was unable to estimate "sensitivity level" incremental costs for all facilities in Exhibit 3-79 due to the lack of specific data on
water intake structure (e.g., intake pipe or caisson dimensions). However, these "sensitivity level" incremental costs are representative
for all facilities in Exhibit 3-79 as the facilities EPA used to develop "sensitivity level" incremental costs represent all major types of
vaporization designs (e.g., ORV, STV) and fixed and mobile, deepwater and shallow water LNG import terminals.
4.2.1 Offshore LNG Import Terminal Water Intake Pipe Design
EPA had sufficient water intake structures data for the following five proposed offshore LNG import terminals: Compass Port, GMO
Energy Bridge, Gulf Landing, Port Pelican, and Main Pass. To estimate a "sensitivity level" incremental cost for installation of
impingement and entrainment equipment, EPA determined design information on the type, size and number of the surface water
3-187
-------
§ 316(b) Phase IH - Technical Development Document
Technology Cost Modules
intakes. EPA used design information for the five LNG import terminals from USCG dockets.43'44'45'46'47 Exhibit 3-81 shows the
design flow rate for each facility, the type of surface water intake that will be used, and the number of intake structures.
Exhibit 3-81. Number and Type of Surface Water Intake Structures at Five Proposed Offshore LNG Import Terminals
LNG Project Name
Conoco Phillips
(Compass Port)
Excelerate
(GMO Energy Bridge)
Shell
(Gulf Landing)
Chevron Texaco
(Port Pelican)
Freeport McMoran
(Main Pass Enerev Hub)
Location
Mobile Block 9 10
88°12' West, 30°5' North
LA, 116 miles South of
Cameron
LA (West Cameron Block
213) south of Lake Charles
LA, 36 miles S-SW of
Freshwater City
LA; 1 7 miles east of Pass a
Loutre
Total Design
Intake Flow*
(MGD)
182
133
136
176
200
Intake Structure Type
Caisson with Submersible
Pumps
Sea Chest
Simple Pipes
Simple Pipes
Sea Water Lift Pumps
with Screened Intakes
Number of
Intake
Structures
6
4
16
5
6
* Note: Total design intake flow for the entire LNG terminal
4.2.2 LNG Impingement and Entrainment Equipment Technology Options
EPA evaluated several impingement and entrainment control technology options for the different types of surface water intake
structures. EPA estimated incremental technology costs of velocity caps and screens for caissons, simple pipes, and suction lines
using sea water lift pumps. Velocity caps prevent impingement of marine life against the surface water intake while cylindrical
wedgewire screens prevent both impingement and entrainment of marine life into the surface water intake system. EPA evaluated flat
panel wedgewire screens for the sea chests surface water intake structures in order to prevent entrainment, and horizontal flow
diverters in order to prevent impingement by changing the direction of flow through the sea chest. Typically, stainless steel is used in
the manufacture of these types of water intake equipment, however new copper-nickel (CuNi) alloys are demonstrated technology for
improved bio-fouling control. In addition, air sparging can also be included with screening equipment to remove bio-fouling and clear
water intake structures. EPA costed the following technology options for the proposed offshore LNG import facilities included in the
sensitivity analysis:
• Cylindrical copper-nickel alloy wedgewire screens with air sparging on caissons and simple pipes;
• Cylindrical copper-nickel alloy wedgewire screens on sea water lift pumps; and
• Flat panel copper-nickel wedgewire screens on sea chests.
43 U.S. Coast Guard, 2002. Port Pelican Environmental Report, Version 1.0, Port Pelican L.L.C.
Deepwater Port Licence Application, Docket No. USGS-2002-14134.
44 U.S. Coast Guard, 2003. Draft Environmental Assessment of the El Paso Energy Bridge Gulf of Mexico,
L.L.C., Deepwater Port License Application, Docket No. USCG-2003-14294, September 2003.
45 U.S. Coast Guard, 2004. Draft Environmental Impact Statement Section 2 (Detailed Description of
Proposed Action and Alternatives) for The Gulf Landing LLC Deepwater Port License Application, Docket No.
USCG-2004-16860-30, July 2004.
46 U.S. Coast Guard, 2004. Compass Port Application for Deepwater Port License, Docket No. USCG-
2004-17659, March, 2004.
47 U.S. Coast Guard, 2004. Deepwater Port License Application for the Main Pass Energy
Project, Docket No. USCG-2004-17696, February 2004.
3-188
-------
§ 316(b) Phase HI - Technical Development Document
Technology Cost Modules
EPA estimates that these costs are likely overestimates as only the GMO Energy Bridge LNG terminal will require the installation of
horizontal flow diverters to lessen impingement.
4.2.3 LNG Cost Estimates for Impingement and Entrainment Options
EPA estimated installed capital costs for each technology option for the five LNG import terminals selected for this analysis.
Technology option equipment costs were developed by regression analysis.48 Exhibit 3-82 shows the cost equations for each
technology option and the design variable.
Exhibit 3-82. Cost Equations and Design Variables for Entrainment and Impingement Equipment at LNG Import Terminals
Impingement and
Entrainment Control
Equipment
Cylindrical copper-nickel
alloy wedgewire screens
with air sparging
Cylindrical copper-nickel
alloy wedgewire screens
Flat panel copper-nickel
wedgewire screens
Horizontal Flow Diverter
Surface Water Intake
Structure Type
Simple pipes and caissons
Sea water pump intakes
Sea Chests
Sea Chests
Cost Equation
$ = 1360.3(x)+4087.2 (1s1)
$ = 883.67(x) - 5742.8 (additional)
$ = 564.7 l(x)- 1389
$ = 6.7734(x) - 0.273
$ = 3.4995(x) + 0.001
Variable
Pipe Diameter
(inches)
Pipe Diameter
(inches)
Flow (gpm)
Flow (gpm)
Exhibit 3-83 shows design information and the estimated cost to install impingement and entrainment control equipment at each LNG
import terminal. Exhibit 3-83 shows that the capital costs associated with the installation of impingement and entrainment control
equipment for most new LNG import terminals can reasonably be expected to be between $0.2 million and $0.9 million.
48Hatch Associates, 2004. Draft Offshore and Coastal Oil and Gas Extraction Facilities Seawater Intake
Structure Modification Cost Estimate: Caisson and Simple Pipe. March 12,2004.
3-189
-------
S 316(b) Phase III - Technical Development Document
Technology Cost Modules
Exhibit 3-83. Estimated Total Costs for Impingement and Entrainment Equipment at Five Proposed LNG Import Terminals
Proposed LNG
Conoco Phillips
(Compass Port)
Excelerate .
(GMO Energy
Bridge)
Shell
(Gulf Landing)
Chevron Texaco
(Port Pelican)
Freeport
McMoran
(Main Pass
Energy Hub)
Flow (MGD)
182
133
136
176
200
No. of Intakes
6
4
16
5
6
Intake Type
Caisson
Sea Chest
Simple Pipes
Simple Pipes
Sea Water Lift Pumps with
Screened Inlets
Design Variable*
Intake diameter:
47"
Flow Rate: 23,000
gpm
Intake diameter:
60"
Intake diameter:
90"
Intake
diameter: 52"
Equipment Costed
Cylindrical copper-nickel
alloy wedgewire screens
with air sparging
Flat panel copper-nickel
wedgewire screens and
horizontal flow diverters.
Cylindrical copper-nickel
alloy wedgewire screens
with air sparging
Cylindrical copper-nickel
alloy wedgewire screens
with air sparging
Cylindrical copper-nickel
alloy wedgewire screens
Estimated Installed
Capital Cost
$247,000
$945,000
$795,000
$422,000
$168,000
*Note: USCG docket information for Main Pass Energy Hub did not contain the sea water lift pump intake diameter so diameter was estimated from Compass Port data
3-190
-------
§ 316(b) Phase HI - Technical Development Document Technology Cost Modules
Overall, the costs for installation of impingement and entrainment control equipment at LNG import terminal surface water intakes is
very small relative to the total costs to construct a LNG import terminal. For example, the total construction costs for the Gulf
Landing, Main Pass, and Port Pelican LNG import terminals are estimated at $700 million, $500 million, and $500 million,
respectively (i.e., impingement and entrainment control equipment costs between $0.2 and $0.9 represent less than 0.1 percent of the
overall new facility construction costs).
4.2.4 Options for Closed Loop Water Systems at LNG Import Terminals
EPA examined an additional option for reducing impingement and entrainment of marine life at LNG import terminals. Specifically,
EPA examined the potential technology option of converting the vaporization systems from Open Rack Vaporizers (ORV) to
Submerged Combustion Vaporizers (SCV). In general, the ORV system uses ambient seawater as its sole source of heat in an open,
falling film type arrangement to vaporize LNG passing through tubes. SCV vaporize LNG contained inside stainless steel tubes in a
submerged water bath with a combustion burner and require no sea water intake. The ORV system has a lower operating cost then the
SVC, but normally a higher capital cost because of the larger equipment size, the added seawater intake/outfall system, the pumping
system, the large diameter seawater pipes, and the seawater treating system. The SCV requires fuel for the LNG vaporization, and the
fuel consumption amount is about 1.5% to 2% of the send-out gas. Thus, it has a higher operating cost than the ORV.49
A recent options study prepared for ConocoPhillips Compass Port LNG receiving terminal examined both the capital and operating
costs for an ORV and SCV process. The study indicated the capital cost for the ORV and SCV processes at this 7.5 million tonne per
year (MMTPA) gas send out LNG receiving terminal would be approximately $45.3 million dollars and $34.3 million dollars,
respectively (Foster Wheeler USA, 2003). Operating costs for the ORV and SCV processes at the Compass Port LNG receiving
terminal were estimated to be $2.3 millon/year and $17.1 million/year, respectively. These SCV costs were developed using the
following price of natural gas: $1.9/MMBtu.
EPA used a ratio of the gas send-out capacities to relate the SCV costs derived for the Compass Port LNG receiving terminal to the
Gulf Landing, Port Pelican, and Main Pass Energy Hub LNG receiving terminals. The Compass Port LNG terminal is expected to
have a 7.5 MMTPA gas send-out rate when completed. Predicted peak natural gas send-out rates for Gulf Landing, Port Pelican, and
Main Pass are 9,15, and 22.5 MMTPA, respectively. Exhibit 3-84 presents estimated "screening level" capital and operating costs for
using SCV systems at these facilities.
49 Foster Wheeler USA Corp, 2003. LNG Vaporizer Options Study for ConocoPhillips Compass Port GBS
LNG Receiving Terminal, First Draft. October 25, 2003.
3-191
-------
§ 316(b) Phase HI - Technical Development Document
Technology Cost Modules
Exhibit 3-84. Screening Level Estimates for LNG Import Terminals to Construct and Operate SCV Systems
Gas Send-out Rate
(MMTPA)
Ratio to
Compass Port
Capital Costs
(Million $)
Annual Operating
Costs (Million $)
Compass Port (SCV)
7.5
1
34.3
17.1
Gulf Landing
9
1.2
41.2
20.5
Port Pelican
15
2
68.6
34.2
Main Pass Energy
Hub
22.5
3
102.9
51.3
Overall the SCV system has lower capital costs than ORV systems and quick start-up but has higher operating costs (especially at gas
prices higher than $1.9/MMBtu). However, EPA considers this technology option as potentially viable as two of the proposed
offshore LNG import terminals are projecting to use SCV systems (i.e., Cabrillo Port, Crystal Energy). As previously mentioned, the
chief environmental benefit of this re-gasification technology is that it eliminates the issues associated with water intakes (i.e.,
impingement and entrainment of aquatic organisms) and discharges (i.e., thermal and chemical pollution). Additionally, offshore LNG
import terminals could use a combination of SCV and ORV systems to reduce surface water intakes and impingement and entrainment
impacts. The combination of SCV and ORV systems also provides a benefit of redundant vaporization systems in case of equipment
failure.
5.0 RATIONALE FOR ESTABLISHING IMPINGEMENT AND ENTRAINMENT CONTROLS USING BEST
PROFESSIONAL JUDGMENT
As previously mentioned, all five existing onshore LNG import terminals do not use surface water intakes for warming or cooling
purposes. The fact that all five existing onshore LNG import terminals use LNG vaporization systems with no surface water intakes
demonstrates that this zero-water intake technology is available for this industrial sector. As all existing LNG import terminals are
using zero-water intake technology, EPA decided not to set national technology-based standards for controlling impingement and
entrainment for this industrial sector.
As previously mentioned, EPA excluded new onshore LNG import terminals from the § 316(b) Phase III rulemaking as these facilities
are already regulated by the § 316(b) Phase I rulemaking (EPA, 2004 - clarification memo). If a new LNG import terminal uses less
than 25 percent or none of its water for cooling purposes or does not meet the 2 MOD intake flow threshold, the new facility rule
specifies that the new facility must meet § 316(b) requirements as specified by the NPDES permit authority on a case-by-case basis,
using best professional judgment (see 40 CFR 125.80(c)). Moreover, current information indicates that all new onshore LNG import
terminals are proposing to use LNG vaporization systems with no surface water intakes (e.g., integration with other industrial
facilities, ambient air vaporization through heating towers, gas-fired heaters).
All new offshore LNG import terminals projected to use surface water for their vaporization systems are also designed to use more
than 2 MGD of surface water. However, EPA could only identify one new offshore LNG import terminal (i.e., GOM Energy Bridge)
that is projected to use 25 percent or more of its surface water intake for cooling purposes. This means that there is only one facility
potentially within scope of the Phase III rule. As there is only one facility potentially within scope of the Phase III rule, EPA decided
not to set national technology-based standards for controlling impingement and entrainment for this industrial sector. EPA will use
best professional judgment (see 40 CFR 125.80(c)) to establish technology-based controls for this facility. Additionally, the other new
offshore LNG import terminals must also meet § 316(b) requirements as specified by the NPDES permit authority on a case-by-case
basis, using best professional judgment (see 40 CFR 125.80(c)).
3-192
-------
S 316(b) Phase III - Technical Development Document Technology Cost Modules
V. FIXED AND VARIABLE O&M COSTS
1.0 DETERMINING FIXED VERSUS VARIABLE O&M COSTS
When developing the annual O&M cost estimates, the underlying assumption was that facilities were operating nearly continuously
with the only downtime being periodic routine maintenance. This routine maintenance was assumed to be approximately four weeks
per year. The economic model however, considers variations in capacity utilization. Lower capacity utilization factors result in
additional generating unit shutdown that may result in reduced O&M costs. However, it is not valid to assume that intake technology
O&M costs drop to zero during these additional shutdown periods. Even when the generating unit is shut down, there are some O&M
costs incurred. To account for this, total annual O&M costs were divided into fixed and variable components. Fixed O&M costs
include items that occur even when the unit is periodically shut down, and thus are assumed to occur year round. Variable O&M costs
apply to items that are allocable based on estimated intake operating time. The general assumption behind the fixed and variable
determination is that shutdown periods are relatively short (on the order of several hours to several weeks).
1.1 Overall Approach
The annual O&M cost estimates used in the cost models is the net O&M cost, which is the difference between the estimated baseline
and compliance O&M costs. Therefore, the fixed/variable proportions for each facility may vary depending on the mix of baseline and
compliance technologies. In order to account for this complexity, EPA calculated the fixed O&M costs separately for both the
baseline technology and each compliance technology and then calculated the total net fixed and variable components for each
facility/intake.
In order to simplify the methodology (i.e., avoid developing a whole new set of O&M cost equations), a single fixed O&M component
cost factor was estimated for each technology application represented by a single O&M cost equation. To calculate fixed O&M
factors, EPA first calculated fixed O&M cost factors for the range of data input values, using the assumptions described below, to
develop the cost equation. For baseline technologies, EPA selected the lowest value in the range of fixed component factors for each
technology application. The lowest value was chosen for baseline technologies to yield a high-side net compliance costs for
intermittently operating facilities. Similarly, for compliance technologies, EPA selected the highest value in the range of fixed
component factors for each technology application, again, to provide a high-side estimate.
For each O&M cost equation, a single value (expressed either as a percentage or decimal value) representing the fixed component of
O&M costs, is applied to each baseline and compliance technology O&M cost estimate for each facility. The variable O&M
component is the difference between total O&M costs and the fixed O&M cost component. The fixed and variable cost components
were then separately combined to derive the overall net fixed and overall net variable O&M costs for each facility/intake.
1.2 Estimating the Fixed/variable O&M Cost Mix
Depending on the technology, the O&M cost estimates may generally include components for labor, power, and materials. The cost
breakdown assumes facility downtime will be relatively short (hours to weeks). Thus, EPA assumes any periodic maintenance tasks
(e.g., changing screens, changing nets, or inspection/cleaning by divers) are performed regardless of plant operation, and therefore are
considered fixed costs. Fixed costs associated with episodic cost components are allocated according to whether they would still occur
even if the downtime coincided with the activity. For example, annual labor estimates for passive screens includes increased labor for
several weeks during high debris episodes. This increased labor is considered a 100% variable component because it would not be
performed if the system were not operating during this period. A discussion of the assumptions and rationale for each general
component is described below.
Power Requirements
In most cases, power costs are largely a variable cost. If there is a fixed power cost component, it will generally consists of low
frequency, intermittent operations necessary to maintain equipment in working condition. For example, a 1% fixed factor for this
component would equal roughly 1.0 hours of operation every four days for systems that normally operated continuously. Such a
duration and frequency is considered as reasonable for most applications. For systems already operating intermittently, a factor that
results in the equivalent of one hour of operation or one backwash every four days was used.
3-193
-------
S 316(b) Phase. Ill - Technical Development Document
Technology Cost Modules
Labor Requirements
Labor costs generally have one or more of the following components:
• Routine monitoring and maintenance
• Episodes requiring higher monitoring and maintenance (high debris episodes)
• Equipment deployment and removal
Periodic inspection/cleaning by divers.
Routine Monitoring and Maintenance
This component includes monitoring/adjustment of the equipment operation, maintaining equipment (repairs & preventive O&M), and
cleaning. Of these the monitoring/adjustment and cleaning components will drop significantly when the intakes are not operating. A
range of 30% to 50% will be considered for the fixed component.
Episodes requiring higher monitoring and maintenance
This component is generally associated with equipment that is operating and will be assumed to be 100% variable.
Equipment deployment and removal
This activity is generally seasonal in nature and assumed performed regardless of operation (i.e., 100% fixed).
Periodic Inspection/Cleaning by Divers
This periodic maintenance task is assumed to be performed regardless of plant operation, and therefore is considered as 100% fixed
costs.
Equipment Replacement
The component includes two factors: parts replacement due to wear and tear (and varies with operation) and parts replacement due to
corrosion (and occurs regardless of operation). A range of 50% to 70% of these costs will be considered the fixed component.
Technology-Specific Input Factors
Traveling Screens
To determine the range of calculated total O&M fixed factors, fixed O&M cost factors (Exhibit 3-85) were applied to individual O&M
cost components for the various screen width values that were used to generate the O&M cost curves. As described earlier, the lowest
value of this range was selected for the baseline O&M fixed cost factor and the highest of this range was selected as the compliance
O&M fixed cost factor.
Exhibit 3-85. O&M Cost Component Fixed Factor
All Traveling Screens Without Fish
Handling
All Traveling Screens
With Fish Handling
Routine Labor
0.5
0.3
Parts Replacement
0.7
0.5
Equipment Power
0.05
0.01
Equipment
Deployment
1.0
1.0
Passive Screens
The fixed O&M component was based on the following:
• Seasonal high debris period monitoring labor set equal to 0 hours
• Routine labor set at 50% of full time operation
3-194
-------
S 316(b) Phase III - Technical development Document Technology Cost Modules
• Back washes are performed once every four days
• Dive team costs for new screens at existing offshore for high debris were set at 50% of full time operation
Dive team costs for new screens at existing offshore were set equal to 0 assuming no net additional diver costs over what was
necessary for existing submerged intake without screens.
• The same assumptions are applied to both fine mesh and very fine mesh screens.
Velocity Caps
Because the O&M cost for velocity caps was based on annual inspection and cleaning by divers, the entire velocity cap O&M cost is
assumed to be fixed (100%).
Fish Barrier Nets
Fish barrier net O&M costs are based on deployment and removal of the nets plus periodic replacement of net materials. As described
above, EPA assumes seasonal deployment and removal is a 100% fixed.O&M cost. EPA has assumed that the need for net
maintenance and replacement is a due to its presence in the waterbody and should not vary with the intake operation. Therefore,
entire fish barrier net O&M cost is assumed to be fixed (100%).
Aquatic Filter barriers
The O&M costs for aquatic filter barriers (AFB) includes both periodic maintenance and repair of the filter fabric and equipment plus
energy used in the operation of the airburst system. As with barrier nets the need for net repairs and replacement should not vary with
the intake operation. There may be a reduction in the deposition of sediment during the periods when the intake is not operating and as
a result there may be a reduction in the required frequency of airburst operation. However, the presence of tidal and other waterbody
currents may continue to deposit sediment on the filter fabric requiring periodic operation. Thus, the degree of reduction in the
airburst frequency will be dependent on site conditions. Additionally, the O&M costs provided by the vendor did not break out the
O&M costs by component. Therefore, EPA concluded that an assumption that AFB O&M costs is 100% fixed is reasonable and
represents a conservative estimate in that it will slightly overestimate O&M costs during periods when the intake is not operating.
Recirculating Wet Cooling Towers
Because the cooling tower O&M costs were derived using cost factors that estimate total O&M costs that are based on capital costs, a
detailed analysis is not possible. However, using the pumping and fan energy requirements described in the Proposed Rule
Development Document, EPA was able to estimate that the O&M energy component was under 50% of the total O&M cost. This
energy requirement reduction, coupled with reductions in labor and parts replacement requirements, should result in a fixed cost factor
of approximately 50%.
1.3 O&M Fixed Cost Factors
Exhibits 3-86 and 3-87 present the fixed O&M cost factors for baseline technologies and compliance technologies, respectively,
derived using the above assumptions.
3-195
-------
S 316(b) Phase III - Technical Development Document
Technology Cost Modules
Exhibit 3-86. Baseline Technology Fixed O&M Cost Factors
Technoloav Description
Travelina Screen With Fish Handlina
Travelina Screen With Fish Handlina
Travelina Screen With Fish Handlina
Travelina Screen With Fish Handlina
Travelina Screen With Fish Handlina
Travelina Screen With Fish Handlina
Travelina Screen With Fish Handlina
Travelina Screen With Fish Handlina
Travelina Screen Without Fish Handlina
Travelina Screen Without Fish Handlina
Travelina Screen Without Fish Handlina
Travelina Screen Without Fish Handlina
Travelina Screen Without Fish Handlina
Travelina Screen Without Fish Handlina
Travelina Screen Without Fish Handlina
Travelina Screen Without Fish Handlina
AoDlication
10 Ft Screen Wells
25 Ft Screen Wells
50 Ft Screen Wells
75 Ft Screen Wells
10 Ft Screen Wells
25 Ft Screen Wells
50 Ft Screen Wells
75 Ft Screen Wells
10 Ft Screen Wells
25 Ft Screen Wells
50 Ft Screen Wells
75 Ft Screen Wells
10 Ft Screen Wells
25 Ft Screen Wells
50 Ft Screen Wells
75 Ft Screen Wells
Water Tvoe
Freshwater
Freshwater
Freshwater
Freshwater
Saltwater
Saltwater
Saltwater
Saltwater
Freshwater
Freshwater
Freshwater
Freshwater
Saltwater
Saltwater
Saltwater
Saltwater
Fixed Factor
0.28
0.30
0.32
0.33
0.31
0.34
0.36
0.38
0.45
0.47
0.48
0.49
0.49
0.51
0.53
0.53
3-196
-------
§ 316(b) Phase III - Technical Development Document
Technology Cost Modules
Exhibit 3-87. Compliance Technology Fixed O&M Cost Factors
Technology Description
Aauatic Filter Barrier
Add Fish Barrier Net Using Anchors and Bouys
Add Fish Barrier Net Using Pilings for Support
Add Fish Barrier Net Using Pilings for Support
Add Fine Mesh Passive T-screens to Existing Offshore Intake
Add Fine Mesh Passive T-screens to Existing Offshore Intake
Add Very Fine Mesh Passive T-screens to Existing Offshore Intake
Add Very Fine Mesh Passive T-screens to Existing Offshore Intake
Relocate Intake Offshore with Fine Mesh Passive T-screens
Relocate Intake Offshore with Fine Mesh Passive T-screens
Relocate Intake Offshore with Very Fine Mesh Passive T-screens
Relocate Intake Offshore with Very Fine Mesh Passive T-screens
Traveling Screen With Fish Handlinq and Fine Mesh
Traveling Screen With Fish Handling and Fine Mesh
Traveling Screen With Fish Handling and Fine Mesh
Traveling Screen With Fish Handling and Fine Mesh
Traveling Screen With Fish Handling and Fine Mesh
Traveling Screen With Fish Handling and Fine Mesh
Traveling Screen With Fish Handling and Fine Mesh
Traveling Screen With Fish Handling and Fine Mesh
Traveling Screen With Fish Handling
Traveling Screen With Fish Handling
Traveling Screen With Fish Handling
Traveling Screen With Fish Handling
Traveling Screen With Fish Handling
Traveling Screen With Fish Handling
Traveling Screen With Fish Handling
Traveling Screen With Fish Handling
Traveling Screen Dual-Flow
Traveling Screen Dual-Flow
Traveling Screen Dual-Flow
Traveling Screen Dual-Flow
Traveling Screen Dual-Flow
Traveling Screen Dual-Flow
Traveling Screen Dual-Flow
Traveling Screen Dual-Flow
Velocity Cap
Cooling Towers
Application
All
All
10 Ft Net Depth
20 Ft Net Depth
High Debris
Low Debris
High Debris
Low Debris
High Debris
Low Debris
High Debris
Low Debris
10 Ft Screen Wells
25 Ft Screen Wells
50 Ft Screen Wells
75 Ft Screen Wells
10 Ft Screen Wells
25 Ft Screen Wells
50 Ft Screen Wells
75 Ft Screen Wells
10 Ft Screen Wells
25 Ft Screen Wells
50 Ft Screen Wells
75 Ft Screen Wells
10 Ft Screen Wells
25 Ft Screen Wells
50 Ft Screen Wells
75 Ft Screen Wells
10 Ft Screen Wells
25 Ft Screen Wells
50 Ft Screen Wells
75 Ft Screen Wells
10 Ft Screen Wells
25 Ft Screen Wells
50 Ft Screen Wells
75 Ft Screen Wells
All
All
Water Type
All
Freshwater
Saltwater
Saltwater
All
All
All
All
All
All
All
All
Freshwater
Freshwater
Freshwater
Freshwater
Saltwater
Saltwater
Saltwater
Saltwater
Freshwater
Freshwater
Freshwater
Freshwater
Saltwater
Saltwater
Saltwater
Saltwater
Freshwater
Freshwater
Freshwater
Freshwater
Saltwater
Saltwater
Saltwater
Saltwater
All
All
Fixed Factor
1.0
1.0
1.0
1.0
0.21
0.27
0.19
0.27
0.46
0.56
0.38
0.49
0.38
0.35
0.37
0.39
0.41
0.38
0.40
0.41
0.40
0.42
0.42
0.42
0.42
0.43
0.44
0.44
0.40
0.40
0.40
0.40
0.44
0.44
0.44
0.44
1.0
0.5
3-197
-------
-------
§ 316(b) Phase in - Technical Development Document Impingement and Entrapment Controls
Chapter 4: Impingement and Entrainment Controls
INTRODUCTION
This section provides a summary of the effects of impingement and entrainment, the development of the performance standards, and
the regulatory options that EPA considered for today's proposed rule.
1.0 IMPINGEMENT AND ENTRAINMENT EFFECTS
The withdrawal of cooling water removes trillions of aquatic organisms from waters of the United States each year, including plankton
(small aquatic animals, including fish eggs and larvae), fish, crustaceans, shellfish, sea turtles, marine mammals, and many other forms
of aquatic life. Most impacts are to early life stages offish and shellfish.
Aquatic organisms drawn into cooling water intake structures (CWIS) are either impinged on components of the intake structure or
entrained in the cooling water system itself. Impingement takes place when organisms are trapped on the outer part of an intake
structure or against a screening device during periods of intake water withdrawal. Impingement is caused primarily by hydraulic
forces in the intake stream. Impingement can result in (1) starvation and exhaustion; (2) asphyxiation when the fish are forced against
a screen by velocity forces that prevent proper gill movement or when organisms are removed from the water for prolonged periods;
and (3) descaling and abrasion by screen wash spray and other forms of physical damage.
Entrainment occurs when organisms are drawn into the intake water flow entering and passing through a cooling water intake structure
and into a cooling water system. Organisms that become entrained are those organisms that are small enough to pass through the
intake screens, primarily eggs and larval stages offish and shellfish. As entrained organisms pass through a plant's cooling water
system, they are subject to mechanical, thermal, and/or toxic stress. Sources of such stress include physical impacts in the pumps and
condenser tubing, pressure changes caused by diversion of the cooling water into the plant or by the hydraulic effects of the
condensers, sheer stress, thermal shock in the condenser and discharge tunnel, and chemical toxemia induced by antifouling agents
such as chlorine.
For a more detailed discussion of impingement and entrainment and the effects on aquatic organisms, refer to the preamble to the
proposed rule and The Regional Benefits Assessment for the Proposed Section 316(b) Rule for Phase III Facilities (EPA-821-R-04-
017).
2.0 PERFORMANCE STANDARDS
The performance standards for today's proposed rule are similar to those required in the final Phase II regulations. Overall, the
performance standards that reflect best technology available under today's proposed rule are not based on a single technology but,
rather, are based on consideration of a range of technologies that EPA has determined to be commercially available for the industries
affected as a whole and have acceptable non-water quality environmental impacts. Because the requirements implementing section
316(b) are applied in a variety of settings and to Phase III facilities of different types and sizes, no single technology is most effective
at all existing facilities, and a range of available technologies has been used to derive the performance standards.
EPA developed the performance standards for impingement mortality reduction based on an analysis of the efficacy of the following
technologies: (1) design and construction technologies such as fine and wide-mesh wedgewire screens, as well as aquatic filter barrier
systems, that can reduce mortality from impingement by up to 99 percent or greater compared with conventional once-through
systems; (2) barrier nets that may achieve reductions of 80 to 90 percent; and (3) modified screens and fish return systems, fish
diversion systems, and fine mesh traveling screens and fish return systems that have achieved reductions in impingement mortality
ranging from 60 to 90 percent as compared to conventional once-through systems.
Available performance data for entrainment reduction are not as comprehensive as impingement data. However, aquatic filter barrier
systems, fine mesh wedgewire screens, and fine mesh traveling screens with fish return systems have been shown to achieve 80 to 90
percent or greater reduction in entrainment compared with conventional once-through systems. EPA notes that screening to prevent
organism entrainment may cause impingement of those organisms instead.
4-1
-------
§ 316(b) Phase HI - Technical Development Document Impingement and Entrapment Controls
Based on the review of performance data, EPA continues to believe that an 80-95% reduction in impingement mortality and a 60-90%
reduction in entrainment are appropriate and technologically achievable. In Phase II EPA provided examples of facilities in different
areas of the country sited on different waterbody types that are currently meeting or exceeding the performance standards (69 FR
41602). Some examples of potential Phase III facilities include the Sherburne County Generating Plant and the Tosco Refinery, as
described in the preamble. Possible examples of offshore oil and gas extraction facilities that also meet the performance standards
(using a combination of intake technologies and/or reduced through-screen intake velocity) are the drillship Transocean Deepwater
Discovery, the MODU Transocean Deepwater Horizon, the MODU Transocean Cajun Express, and the platform Aera Energy Ellen.
The ability of these facilities to meet the performance requirements suggests that while site-specific factors can influence the
performance of a given technology, it is the exceptional situation where no design or construction technology is capable of meeting the
performance .standards. EPA opted for performance ranges instead of specific compliance thresholds to allow both the permittee and
the permitting authority a certain degree of flexibility in meeting the obligations under the final Phase II rule. Further, EPA recognizes
that precise results may not be able to replicated in different waterbody types in different areas of the country.
3.0 REGULATORY OPTIONS CONSIDERED
In today's proposed rule, EPA co-proposes three regulatory options based on design intake flow and source waterbody type that define
which facilities are Phase III existing facilities subject to uniform national requirements. These co-proposed options are:
• The facility has a total design intake flow of 50 MGD or more, and is located on any source waterbody type;
• The facility has a total design intake flow of 200 MGD or more, and is located on any source waterbody type;
• The facility withdraws water from an ocean, estuary, tidal river or stream, or Great Lake and has a total design intake flow of 100
MGD or more.
The proposed rule would require Phase III existing facilities to meet performance standards similar to those required in the final Phase
II rule, including a 80-95% reduction in impingement mortality and a 60-90% reduction in entrainment. The proposed rule also
provides for the same five compliance alternatives specified in the final Phase II rule. If a facility is a point source that uses a cooling
water intake structure and has, or is required to have, an NPDES permit, but does not meet the definition of Phase III existing facility
under the corresponding regulatory option (e.g., the intake is below the specified MGD design intake flow threshold or does not meet
the 25% cooling purposes threshold) it would continue to be subject to permit conditions implementing section 316(b) of the Clean
Water Act set by the permit director on a case-by-case basis, using best professional judgment.
In developing the proposed Phase III rule, EPA considered several regulatory options based on varying flow regimes and waterbody
type. These options are based on applying the same performance standards and compliance alternatives as those being proposed (i.e.
the final Phase II performance standards and requirements including the use of case-by-case permit determinations based on best
professional judgment for facilities below the applicable thresholds) but using different design intake flow applicability thresholds. In
addition, EPA considered a number of options (specifically options 2,3,4, and 7 below) that would establish different performance
standards for certain groups or subcategories of Phase III existing facilities. Under these options, EPA would apply the proposed
performance standards and compliance alternatives (i.e. the Phase II requirements) to the higher threshold facilities, apply the less-
stringent requirements as specified below to the middle flow threshold category, and would apply best professional judgment below
the lower threshold.
Each of the options considered for this proposal is described in detail below:
Option 1: Facilities with a design intake flow of 20 MGD or greater would be subject to the performance standards and compliance
alternatives proposed in today's rule and discussed above. Under this option, section 316(b) permit conditions for Phase III facilities
with a design intake flow of less than 20 MGD would be established on a case-by-case, best professional judgment, basis.
Option 2: Facilities with a design intake flow of 50 MGD or greater, as well as facilities with a design intake flow between 20 and 50
MGD (20 MGD inclusive) when located on estuaries, oceans, or the Great Lakes would be subject to the performance standards and
compliance alternatives proposed in today's rule. Facilities with a design intake flow between 20 and 50 MGD (20 MGD inclusive)
that withdraw from freshwater rivers and lakes would have to meet the performance standards for impingement mortality only and not
for entrainment. Under this option, section 316(b) requiremtns for Phase III facilities with a design intake flow of less than 20 MGD
would be established on a case-by-case, best professional judgment, basis.
Option 3: Facilities with a design intake flow of 50 MGD or greater would be subject to the performance standards and compliance
alternatives proposed in today's rule. Facilities with a design intake flow between 20 and 50 MGD (20 MGD inclusive) would have to
4-2
-------
§ 316(b) Phase III - Technical Development Document
Impingement and Entrapment Controls
meet the performance standards for impingement mortality only and not for entrainment. Under this option, section 316(b)
requirements for Phase III facilities with a design intake flow of less than 20 MOD would be established on a case-by-case, best
professional judgment, basis.
Option 4: Facilities with a design intake flow of 50 MOD or greater, as well as facilities with a DIP between 20 and 50 MGD (20
MGD inclusive) when located on estuaries, oceans, or the Great Lakes would be subject to the performance standards and compliance
alternatives proposed in today's rule and discussed above. Facilities that withdraw from freshwater rivers and lakes and all facilities
with a design intake flow of less than 20 MGD would have requirements established on a case-by-case, best professional judgment,
basis.
Option 5 (Co-proposed Option): Facilities with a design intake flow of 50 MGD or greater would be subject to the performance
standards and compliance alternatives proposed in today's rule and discussed above. Under this option, section 316(b) requirements
for Phase III facilities with a design intake flow of less than 50 MGD would be established on a case-by-case, best professional
judgment, basis.
Option 6: Facilities with a design intake flow of greater than 2 MGD would be subject to the proposed performance standards and
compliance alternatives. Under this option, section 316(b) requirements for Phase III facilities with a design intake flow of 2 MGD or
less would be established on a case-by-case, best professional judgment, basis.
Option 7: Facilities with a design intake flow of 50 MGD or greater would be subject to the performance standards and compliance
alternatives proposed in today's rule and discussed above. Facilities with a design intake flow between 30 and 50 MGD (30 MGD
inclusive) would have to meet the performance standards for impingement mortality only and not for entrainment. Under this option,
section 316(b) requirements for Phase III facilities with a design intake flow of less than 30 MGD would be established on a case-by-
case, best professional judgment, basis.
Option 8 (Co-proposed Option): Facilities with a design intake flow of 200 MGD or greater would be subject to the performance
standards and compliance alternatives proposed in today's rule and discussed above. Under this option, section 316(b) requirements
for Phase III facilities with a design intake flow of less than 200 MGD would be established on a case-by-case, best professional
judgment, basis.
Option 9 (Co-proposed Option): Facilities with a design intake flow of 100 MGD or greater and located on oceans, estuaries, and the
Great Lakes would be subject to the performance standards and compliance alternatives proposed in today's rule and discussed above.
Under this regulatory option, section 316(b) requirements for Phase III facilities with a design intake flow of less than 100 MGD
would be established on a case-by-case, best professional judgment, basis.
Exhibit 4-1 summarizes which facilities would be defined as existing Phase III facilities and which performance standards would apply
under each of the above options:
Exhibit 4-1. Performance Standards for the Regulatory Options Considered
Option
1
2
3
4
5
Minimum Design Intake Flow Defining Facilities as Existing Phase in Facilities
2 MGD
BPJ
BPJ
BPJ
BPJ
20 MGD 30 MGD
50 MGD 100 MGD 200 MGD
I&E
Freshwater rivers and lakes: I only
All other waterbodies: I&E
I only
Estuaries, oceans, Great Lakes: I&E
All other waterbodies: BPJ
BPJ
I&E
I&E
I&E
I&E
4-3
-------
S 316(b) Phase III - Technical Development Document
Impingement and Entrainment Controls
Exhibit 4-1. Performance Standards for the Regulatory Options Considered (continued)
Option
6
7
8
9
Minimum Design Intake Flow Defining Facilities as Existing Phase III Facilities
2MGD
BPJ
20 M GD 30 Ml
I&E
I only
BPJ
BPJ
SO 50 MGD
100 MGD
I&E
I&E
Estuaries, oceans, Great Lakes: I&E
All other waterbodies: BPJ
Key:
BPJ - Best Professional Judgment
I&E - 80-95% reduction in impingement mortality and a 60-90% reduction in entrainment
I only - 80-95% reduction in impingement mortality
Estuaries - includes tidal rivers and streams
Lakes - includes lakes and reservoirs
4.0
OTHER CONSIDERATIONS
EPA considered a number of other issues relating to performance standards for Phase III facilities, including closed-cycle cooling and
the use of sea chests.
4.1 Closed Cycle Cooling
EPA based the Phase I (new facility) final rule performance standards on closed-cycle, recirculating systems (see 66 FR 65274).
Available data suggest that closed- cycle, recirculating cooling systems (e.g., cooling towers or ponds) can reduce mortality from
impingement by up to 98 percent and entrainment by up to 98 percent when compared with conventional once-through systems (see 69
FR 41601). In the final Phase II rule, EPA did not select a regulatory scheme based on closed- cycle, recirculating cooling systems at
existing facilities based on (1) its generally high costs (due to conversions); (2) the fact that other technologies approach the
performance of this option, (3) concerns for potential energy impacts due to retrofitting existing facilities, and (4) other considerations
(see 69 FR 41605). For individual high-flow facilities to convert to wet towers the capital costs range from $130 to $200 million with
annual operating costs in the range of $4 to $20 million (see Phase II final TDD, DCN 6-0004). Thus, basing the Phase III existing
facility proposed rule on closed- cycle, recirculating cooling systems would cost more than $2 billion, a more than four-fold increase in
total national pre-tax annualized costs compared to today's proposed option of $125 million, without proportionally greater benefits
than the proposed option. Therefore, EPA did not further consider closed- cycle, recirculating cooling systems as a basis for today's
proposed performance standards for existing facilities.
4.2 Entrainment Reductions for Offshore Oil and Gas Facilities Using Sea Chests
Facilities using seachests may have limited opportunities to control entrainment as required by the Phase I rule. A 2003 literature
survey by Mineral Management Services (DCN 7-0012) identified no studies of impingement and entrainment impacts by oil and gas
extraction facilities with seachests, or evidence of entrainment controls successfully fitted to offshore oil and gas extraction facilities
such as drill ships, jack-ups, MODUs, and barges. EPA's data suggests the only physical technology controls for entrainment at
facilities with seachests would entail installation of equipment projecting beyond the hull of the vessel. Such controls may not be
feasible, even for new facilities that could avoid the challenges of retrofitting control technologies.
4-4
-------
S 316(b) Phase III - Technical Development Document Costing Methodology for Model Facilities
Chapter 5: Costing Methodology for Model Facilities
INTRODUCTION
This chapter describes the methodology used to estimate engineering compliance costs associated with implementing the regulatory
options proposed for section 316(b) Phase III facilities. Chapter 3 of this document describes in detail the technologies and practices
used as the basis for the regulatory options. Section 1.0 of this chapter describes the regulatory control options considered by the
Agency. To assess the economic impact of these control options, EPA estimates the costs associated with regulatory compliance. The
methodology for technology and control costs for electric power generators and manufacturers is in section 2.0 of this chapter. The
full economic burden is a function of these costs of compliance, which may include initial fixed and capital costs, annual operating and
maintenance (O&M) costs, downtime costs, recordkeeping, monitoring, studies, and reporting costs. The results of the economic
impact analysis for the proposed regulation is found in the Economic Analysis (DCN 7-0002).
For the purpose of estimating incremental compliance costs attributable to the proposed rules, EPA traditionally develops either
facility-specific or model facility costs. Facility-specific compliance costs require detailed process information about many, if not all,
facilities in the industry. These data typically include production, capacity, water use, wastewater generation, overall management,
monitoring data, geographic location, financial conditions, and other industry-specific data that may be required for the analyses. EPA
used a detailed technical survey of electric power and manufacturing facilities' to determine how each regulatory option will impact
that facility, and to estimate the cost of installing new or additional controls. The cost and basis for each control is described in section
1 of this chapter.
When facility-specific data are not available, EPA develops model facilities to provide a reasonable representation of the industry.
EPA then determines the number of facilities that are represented by each model. Industry level costs are then calculated by
multiplying the model-specific costs by the number of facilities that are represented by each particular model.
For the section 316(b) Phase III proposed rule, EPA used the model facility approach. EPA primarily used facility-specific data,
supplemented where necessary by industry supplied data and follow-up interviews to clarify a facility's responses. However, EPA did
not have sufficient data for all facilities potentially subject to the proposed Phase III rule. Therefore, EPA first calculated the facility-
specific costs for 346 facilities, and applied the model facility approach to each facility-specific cost to calculate the industry level
costs for 650 manufacturing and electric power producing facilities. EPA used the Cost Test Tool described in section 2.0 to calculate
the model-facility costs. Section 3.0 provides some examples. Section 4.0 provides an analysis of the confidence in accuracy of the
316(b) compliance cost modules. Section 5.0 provides an estimate of facility downtime.
1.0 REGULATORY OPTIONS
EPA proposed requirements for the location, design, construction, and capacity of cooling water intakes based on the waterbody type
and the volume of water withdrawn by a Phase III facility. The proposed rule describes three regulatory options based on design
intake flow and source waterbody type that define which facilities are Phase III existing facilities subject to uniform national
requirements:
• The facility has a total design intake flow of 50 MGD or more, and located on any waterbody type;
• The facility has a total design intake flow of 200 MGD or more, and located on any waterbody type;
• The facility withdraws water from an ocean, estuary, tidal river or stream, or Great Lake and has a total design intake flow of 100
MGD or more.
If a facility is a point source that uses a cooling water intake structure and has, or is required to have, an NPDES permit, but does not
meet the appropriate flow/source waterbody type threshold or the 25% cooling purposes threshold, it would be subject to permit
conditions implementing section 316(b) of the Clean Water Act set by the permit director on a case-by-case basis, using best
1 EPA focused its survey and data collection efforts on six industrial categories that, as a whole, were
estimated to account for over 99 percent of all cooling water withdrawals: Utility Steam Electric, Nonutility Steam
Electric, Chemicals & Allied Products, Primary Metals Industries, Petroleum & Coal Products, and Paper & Allied
Products.
5-1
-------
§ 316(b) Phase III - Technical Development Document Costing Methodology for Model Facilities
professional judgment. For example, under the 100 MOD coastal and Great Lakes option, facilities withdrawing from a freshwater
river or stream would not be subject to national requirements.
Under the proposed rule, these facilities would be subject to the same requirements as under the final 316(b) rule for Phase II, with
Phase III requirements specified in Part 125, Subpart K. Data analyzed from EPA's detailed technical survey shows cooling water
intake structures at Phase II electric power generating facilities are, in general, no different than those intake structures employed by
Phase III facilities, particularly manufacturing facilities and lower flow electric power generating facilities. These factors, plus EPA's
additional experiences in section 316(b) Phase I and Phase II rulemakings (see EPA's Final Response to Comments Document DCN 6-
5049A and the Phase II Final Preamble 69 FR 41575), as well as Phase III stakeholders (such as small business concerns) led EPA to
develop the regulatory options described above. Facilities that would be subject to requirements on a case-by-case, best professional
judgment (BPJ) basis were assigned no costs.
The proposed Phase III rule also would make new offshore oil and gas extraction facilities subject to requirements similar to those
under the final Phase I new facility regulation (40 CFR 125 Subpart I). Requirements for new offshore oil and gas extraction facilities
are proposed in a new Subpart N. For purposes of this proposed rule, new offshore oil and gas extraction facilities are those facilities
that are subject to the Oil and Gas Extraction Point Source Category Effluent Guidelines (i.e., 435.10 Offshore Subcategory or 435.40
Coastal Subcategory), and meet the definition of "new offshore oil and gas extraction facility" in proposed Subpart N, § 125.133.
1.1 Analysis of Capacity Utilization Rate
The final Phase II rule includes a provision that allows facilities that have either a historic capacity utilization rate of less than 15
percent or those agreeing to limit their future utilization rate to less than 15 percent to comply with impingement reduction
requirements only. For Detailed Questionnaire facilities expected to upgrade technologies as a result of the rule, the Agency
determined that 1.0 percent of the total actual annual intake of these facilities would be associated with those facilities falling below
the 15 percent capacity utilization threshold. Furthermore, 0.7 percent of the total actual annual intake of the Detailed Questionnaire
facilities expected to upgrade technologies could be attributed to those receiving relief from entrainment requirements due to the
threshold. For this small number of facilities and negligible percentage of affected intake flow, the Agency concludes that the capacity
utilization threshold will have no measurable national effect on the entrainment reduction of the final rule.
There is a potential for facilities to choose to operate at a lower capacity utilization rate in order to avoid entrainment requirements,
forego electricity production as a result, and thereby have an impact on local or regional energy markets. EPA examined the electricity
generation implications of the capacity utilization rate threshold at those facilities that are within close range of the capacity utilization
rate (i.e., those between 15 and 20 % historic capacity utilization) to determine if the facilities would economically benefit from
reduced entrainment requirements. EPA conducted a break-even analysis of the net revenue from electricity production foregone
compared against the savings of removing entrainment requirements for those facilities between 15 and 20 % historic capacity
utilization rates. Exhibit 5-1 presents the results of the break-even analysis. The median and average break-even capacity utilization
rates are less than 15.1 %. The Agency found one facility in its database of Phase II facilities that might fall between 15 and 15.1 %
capacity utilization. The amount of electricity production foregone as a result of this facility's change to avoid entrainment controls
would be on the order of 3,000 MWh per year. This is a negligible amount of electricity generation in any local or regional market.
The Agency analyzed all facilities projected under the threshold and examined the likely operating periods for these facilities. Of the
42 facilities projected to fall under the threshold 17 of these facilities would be subject to impingement only requirements regardless of
the existence of the utilization threshold. Further, of the 25 facilities (5 percent of Phase II facilities) that would receive reduced
entrainment requirements under the capacity threshold, the total median operation period per year would be 28 days. Considering that
this operational period is broken about in two likely periods in winter and summer, the approximate 2-week period in each season
would likely overlap only a small portion of potential spawning periods. The operational flow of the facilities receiving reduced
entrainment requirements over the typical 28 days per year would be 1 % of the total annual intake of facilities within the scope of the
rule that are subject to entrainment reduction requirements. Therefore, the capacity utilization rate threshold will not appreciably
decrease the entrainment efficacy of the final rule.
EPA analyzed the cost to revenue ratios of facilities above and below the capacity utilization threshold. In addition, the Agency
analyzed cost to revenue ratios for facilities in absence of the capacity utilization threshold relief. The Agency determined that
facilities falling below the capacity utilization rate threshold of 15 percent would experience average cost to revenue ratios of 4.4 %
(median of 1.2 %) with the threshold relief from entrainment and approximately 6 % (median of 2.4 %) without the presence of the
utilization threshold. The Agency determined that facilities above the threshold would experience far lower average cost to revenue
ratios of 1.2 % (median of 0.4 %).
5-2
-------
§ 316(b) Phase III - Technical Development Document
Costing Methodology for Model Facilities
As can be seen from the results of the cost to revenue, operating period, and flow analysis in Exhibit 5-2, the Agency's capacity
utilization rate of 15 percent for the final rule balances the competing factors of providing needed compliance relief while providing
environmental protection. The Agency notes that the possible environmental improvement in the average operating periods in the 10
percent compared to the 15 percent capacity utilization rate is very small (one week per year). Further, the difference in the amount of
flow subject to entrainment requirements between the 10 and 15 percent rates is also very small. Therefore, the Agency concludes that
the improvement in average cost to revenue relief between the lower thresholds is sufficient to warrant the 15 percent rate. On the
higher side, the Agency notes that both the operating periods and the percentage of flow receiving entrainment relief under the 20 and
30 % rates are considerably higher than for 15 percent. In addition, the improvement in cost to revenue relief is not as great between
15 and 30 percent (and 20 percent, for that matter) as the difference improvement between 10 and 15 percent. The Agency concludes
that its selection of the 15 % rate is the most reasonable balance for all four threshold factors analyzed in Exhibit 5-2.
Exhibit 5-1. Break-Even Analysis for Facilities that Might Reduce Capacity Utilization Rates To Avoid Entrainment Controls
Average
Capacity
Utilization Rate
(1995-1999)
15.8%
16.4%
16.6%
16.7%
17.1%
18.4%
19.2%
19.4%
19.7%
Average
Annual
Generation
(MWh)
2,478,619
128,032
1,202,511
200,024
620,453
574,367
2,319,433
6,406,991
708,553
Annual
Costs of
Entrainment
Reduction
$ 2,434,420
$510,945
$ 358,071
$704,805
$ 684,882
$ 1,073,438
$ 1,636,977
$ 94,825
$ 610,068
Annual
Costs of
Impingemen
tOnly
Reduction
$ 78,065
$ 62,589
$ 100,591
$ 59,781
$ 33,398
$ 149,075
$ 69,723
$ 81,322
$ 47,283
Annual Cost
Ditt. Between
Entrainment and
Impingement
Reduction
$ 2,356,355
$ 448,356
$ 257,480
$ 645,025
$651,484
$ 924,364
$ 1,567,254
$ 13,503
$ 562,785
Annual Generation
Loss (MWh / year)
to Meet 15 %
Capacity
Utilization
829,440
72,620
770,455
134,919
502,939
708,362
3,413,875
9,712,022
1,129,631
Cost of Annual
Generation
Foregone ($ /
year) to meet 15
%
$ 25,712,628
. $2,251,210
$ 23,884,099
$4,182,475
$15,591,113
$ 21,959,212
$ 105,830,123
$ 301,072,695
$35,018,568
Capacity
Utilization
Break-even
Solver
Value
15.0693%
15.2586%
15.0061%
15.2378%
15.0766%
15.1177%
15.0492%
15.0002%
15.0579%
Exhibit 5-2. Threshold Comparison Analysis
Threshold
10 percent
15 percent
20 percent
30 percent
Average CTR below
threshold w/
entrainment relief
5.7%
4.4%
3.8%
3.4%
Average CTK
below threshold if
no entrainment
relief
7.3%
6:0%
4.7%
3.3%
Average CTR of
all facilities
1.5%
1 1:5%
1.5%
1.5%
Average operating
days per year of
facilities w/
entrainment relief
21
'-', ^28" " '• '"
40
62
Percent of total flow
subject to entrainment
requirements receiving
relief
0.3%
10)%,
2.6%
7.8%
CTR = Cost-to-revenue ratio.
1.2 Analysis of Cooling System Type for Electric Power Generating Facilities
Combination Cooling Systems
Fifty facilities reported combination-cooling systems in the 316(b) survey (in the short-technical or detailed questionnaire). EPA
analyzed the intake-level and cooling system-level information reported in the survey for each of these facilities. The Agency found
that the median percentage of overall facility flow associated with the recirculating intake feed was 5.3 percent. Therefore, 95 percent
of the facility's flow would be associated with the once-through intakes.
EPA attempted to gauge the degree to which national costs may be overstated by examining these facilities with combination cooling
systems and adjusting their technology upgrade costs to reflect the fact that a recirculating intake at the facility may have lesser
requirements than as assumed. Because the Agency determined that 5 percent of the total facility intake would be typically associated
with the recirculating intake, to which the Agency assigned costs for reducing entrainment and/or impingement mortality through
technology upgrades, the Agency adjusted those annual cost items that are primarily a function of flow by multiplying by - 5 %. The
cost items that are primarily a function of flow include capital cost, operating and maintenance (O&M) cost, and pilot study costs. For
adjustments to downtime costs the Agency necessarily examined the portion of the plant's intakes associated with the recirculating
system. Typically, the recirculating portion of the cooling system corresponded to one of several intakes at the facility. The most
5-3
-------
§ 316(b) Phase III - Technical Development Document Costing Methodology for Model Facilities
common occurrence was for one of two intakes to be dedicated to a recirculating system and the other to a once-through configuration.
The average number of intakes at each of the facilities with combination cooling systems was close to three intakes. A frequent
occurrence also was for one of three intakes to be dedicated to the recirculating system. Rarely was more than three intakes reported,
and in these cases multiple intakes were generally associated with a recirculating system. Based on these facts, the Agency believes
that a reasonable characterization for the "typical" combination cooling system in the data base was for one of three intakes to
correspond to a recirculating system and the others to be dedicated as once-through. Hence, for the case of downtime costs, the
Agency considered a reasonable adjustment to be one-third of the cost of the downtime at the facility-level. The logic is that should a
generating unit with a unique intake not require a downtime, yet the Agency assign one, then the cost of the downtime for the facility
would be overestimated. Because the typical configuration for the combination cooling system if one facility of three dedicated to the
recirculating system, then a facility-wide downtime assumption would potentially overstate downtimes by one-third, provided all units
roughly generate equivalent amounts of electricity. This is a relatively conservative assumption due to the fact that in the cases the
Agency is familiar with, the recirculating systems typically are associated with the newest generating units at the plant. Therefore,
significantly more than one-third of the plant-wide generation may come from the recirculating portion.
For the purposes of determining the extent to which costs may be overstated for these facilities, the Agency calculated for each of the
SO combination cooling system facilities an annualized adjustment cost. These costs totaled approximately $3.7 million annually (in
2002 $).
Facilities Utilizing Strategic Flow Reductions
Eleven facilities reported in the detailed questionnaire that they utilize strategic flow reduction. The Agency examined the assumed
entrainment and/or impingement mortality requirements it utilized for the technology cost development and found that five of the
strategic flow reduction facilities utilize significant strategic flow reductions and were assigned entrainment technology upgrades. The
Agency considers that this may overstate costs for this portion of facilities given that the median flow reduction percentage was 40
percent. Strategically implemented, an annual flow reduction of 40 percent (targeted to periods of spawning and the presence of large
numbers or high density of organisms) could assist a facility in achieving entrainment reductions comparable to the entrainment
reduction targets of the final rule. Overall, the fact that the Agency identified only five such facilities reinforces the Agency's
assumption that costs for these facilities with strategic flow reduction are relatively accurate in the record. Nonetheless, the Agency
analyzed the difference in costs attributable to the entrainment technology upgrades assigned for these facilities to the cost of
impingement controls.
For the purposes of determining the extent to which costs may be overstated for these facilities, the Agency calculated an annualized
adjustment cost for each of the 5 entrainment-upgrade facilities already utilizing strategic flow reduction. These costs totaled
approximately $4.7 million annually (in 2002 $).
1.3 Regulatory Options for Offshore Oil and Gas Facilities
Using the cost modules developed as described in Chapter 1, two compliance alternatives, impingement mortality reduction and
impingement mortality and entrainment reduction were costed. Exhibit 5-3 below presents the different technology options for the two
compliance options costed for offshore oil and gas extraction facilities.
5-4
-------
§ 316(b) Phase HI - Technical Development Document
Costing Methodology for Model Facilities
Exhibit 5-3. Proposed Regulatory Options for Offshore Oil and Gas Extraction Facilities
Option
Requirements
Type of Rig
Platforms and
Drill Barges which
use simple pipes
and caissons for
cooling water
intake
Jack Ups
which use sea
chests while in
transport and
simple pipes/
caissons when
stationary for
cooling water
intake
Submersibles,
Semi-submersibles
and Drill Ships
which use sea
chests for cooling
water intake
Option A
I&E control for
facilities with >2
MOD
Option A
Cylindrical
Wedgewire
Screens for >2
MOD
Cylindrical
Wedgewire
Screens plus Flat
Panel Wedgewire
Screens and
Horizontal Flow
Diverter for >2
MOD
Flat Panel
Wedgewire
Screens and
Horizontal Flow
Diverter for >2
MOD
Option B
I control for
facilities with >2
MOD
Option B
Velocity Caps for
>2MGD
Horizontal Flow
Diverter and
Velocity Caps for
>2MGD
Horizontal Flow
Diverter for >2
MOD
Option C
I&E control for
facilities with > 50
MOD and I control
for facilities with
2-50 MOD
Option C
Cylindrical
Wedgewire
Screens for > 50
MOD and Velocity
Caps for 2-50
MOD
Cylindrical and
Flat Panel
Wedgewire
Screens plus
Horizontal Flow
Diverter for pipes
and sea chests for
>50MGDand
Velocity Caps and
Horizontal Flow
Diverter for 2-50
MOD
Flat Panel
Wedgewire
Screens and
Horizontal Flow
Diverter for >50
MGD and
Horizontal Flow
Diverter for 2-50
MGD
Option D
I&E control for
facilities with > 50
MGD
Option D
Cylindrical
Wedgewire
Screens for >50
MGD
Cylindrical
Wedgewire
Screens plus Flat
Panel Wedgewire
Screens and
Horizontal Flow
Diverter for > 50
MGD
Flat Panel
Wedgewire
Screens and
Horizontal Flow
Diverter for >50
MGD
Option E
I control for
facilities with > 50
MGD
Option E
Velocity Caps for
>50 MGD
Horizontal Flow
Diverter and
Velocity Caps for
> 50 MGD
Horizontal Flow
Diverter for >50
MGD
I = Impingement Control (includes velocity caps and horizontal flow diverters)
I&E = Impingement and Entrainment Control (includes cylindrical wedgewire screens and flat panel wedgewire screens with a
horizontal flow diverter)
Based on interviews with technical personnel, it was concluded that most of the offshore oil and gas extraction facilities employing
cooling water intake structures have minimal to no technologies in place in order to reduce impingement mortality and/or entrainment.
Further, as discussed in this document, entrainment controls were generally found to be infeasible for offshore oil and gas extraction
facilities.
1.4 Regulatory Options for Seafood Processing Vessels
Using the cost modules developed as described in Chapter 3, two compliance alternatives, impingement reduction and impingement
and entrainment reduction were costed. Exhibit 5-4 below presents the different technology options for the two compliance options
costed for seafood processing vessels.
5-5
-------
§ 316(b) Phase III - Technical Development Document
Costing Methodology for Model. Facilities
Exhibit 5-4. Proposed Technology Options for Seafood Processing Vessels
Type of
CWIS
Sea chest
intake
Compliance
Alternatives
Impingement
Impingement &
Entrainment
Proposed Technology
Replace Grill with fine mesh
screen
Horizontal Flow Diverter
Enlarged Intake Structure
(Internal)
Enlarged Intake Structure
(External)
Comments
Two options, stainless steel and Cu/Ni fine
mesh screens were costed
Similar mechanism as a velocity cap. Two
configurations for sea chests were costed; (1)
located at the bottom of the vessel and (2) on the
sides of the vessel.
Two options, stainless steel and Cu/Ni fine
mesh screens were costed
Two options, stainless steel and Cu/Ni fine
mesh screens were costed
Based on site visits to shipyards and interviews with technical personnel, it was concluded that most of the seafood processing vessels
employing cooling water intake structures have minimal to no technologies in place in order to reduce impingement mortality and/or
entrainment. Further, as discussed in this document, entrainment controls were generally found to be infeasible for seafood processing
vessels.
2.0
COST TEST TOOL APPLIED TO MODEL FACILITIES
The cost-test tool is a spreadsheet program that creates facility-specific or model-specifiq compliance costs. The cost-test tool (version
4.1) was developed to predict facility-specific costs needed to implement the cost-cost compliance alternative of the final Phase II rule.
The tool accepts site-specific intake data for an electric power generating facility, executes the methodology and analyses that EPA
used to derive the costs of the Phase II final rule, and then outputs a set of costs for use in a cost-to-cost comparison. Data analyzed
from EPA's detailed technical survey shows cooling water intake structures at electric power generating facilities are, in general, no
different than those intake structures employed by manufacturing facilities. Therefore the Phase II technologies and costs attributed to
control technologies were applied to Phase III manufacturers and electric power generators.
Exhibit 5-5 lists the technology modules EPA used to cost potential Phase III existing facilities to comply with the regulatory options
described in section 1.0. Section 2.1 describes how technology modules were assigned to each facility. See Chapter 3 for detailed
descriptions of each technology.
Exhibit 5-5. Technology Codes and Descriptions
Technology Codes
1
2
3
4
5
6
7
Technology Description
Addition offish handling and return system to an existing traveling screen system
Addition of fine-mesh screens to an existing traveling screen system
Addition of a new, larger intake with fine-mesh and fish handling and return system in
front of an existing intake system
Addition of passive fine-mesh screen system (cylindrical wedgewire) near shoreline
with mesh width of 1 .75 mm
Addition of a fish net barrier system
Addition of an aquatic filter barrier system
Relocation of an existing intake to a submerged offshore location with passive fine-
mesh screen inlet with mesh width of 1 .75 mm
5-6
-------
§ 316(b) Phase HI - Technical Development Document
Costing Methodology for Model Facilities
Exhibit 5-5. Technology Codes and Descriptions (continued)
Technology Codes
8
9
10
11
12
13
14
Technology Description
Addition of a velocity cap inlet to an existing offshore intake
Addition of passive fine-mesh screen to an existing offshore intake with mesh width of
1.75mm
[Module 10 not used]
Addition of dual-entry, single-exit traveling screens (with fine- mesh) to a shoreline
intake system
Addition of passive fine-mesh screen system (cylindrical wedgewire) near shoreline
with mesh width of 0.76 mm
Addition of passive fine-mesh screen to an existing offshore intake with mesh width
0.76 mm
of
Relocation of an existing intake to a submerged offshore location with passive fine-
mesh screen inlet with mesh width of 0.76 mm
2.1
The Cost-Test Tool Structure
The cost test tool program makes use of basic database retrieval functions and logical statements to mirror the costing methodology
hierarchy used by EPA for development of the final Phase II rule costs. (This costing methodology was published in the Phase II
Notice of Data Availability and was, in rum, available for public comment. The cost-test tool makes no changes to the methodology in
its approach.)
The cost model described here modifies the cost-test tool to version 5.1 to calculate the costs the Agency developed and considered for
the proposed Phase III. The cost-tool combines the varied analyses and data presented in Chapter 1 into an automated decision tree
that ultimately assigns a technology cost to each facility. In the "User Inputs" sheet of the cost-test tool, the user supplies data on the
facility level, or the user may choose to input information at the intake level where multiple intakes at a single facility have different
features that might affect which technology modules are feasible for that intake. Once the "user inputs" have been entered, the cost-
test tool determines one of two possible performance expectations: impingement requirements only or both impingement and
entrainment requirements. The cost-tool then determines a compliance response for the facility/intake by accounting for existing
technologies (such as wedgewire screens) and conditions (such as a shoreline intake location or the through-screen velocity). Next the
cost-test tool applies EPA's decision tree for assigning site-specific cost modules; see Figure 5-1 for a schematic of this decision tree.
Finally, the costing methodology is performed through a combination of calculations and functions (that is, an algorithm). This work
is mostly carried out in the sheet titled "Calc. and Data" and is supplemented by a few logical functions and data retrieval in the
"Output" sheet. The cost outputs include capital costs, incremental operating and maintenance (O&M) costs, and downtime (in
weeks).
5-7
-------
S 316(b) Phase. Ill - Technical Development Document
Costing Methodology for Model Facilities
Figure 5-1. Flow Chart for Assigning Cost Modules
Intake velocity 3.5 feet
per second or less?
NO
YES
NO
Intake Module Assigned
shoreline (flush, recessed) 4
Intake canal 3
embayment, bay or cove 3 (5)*
submerged offshore 8
near-shore submerged 4
shoreline submerged 4
Withdrawals from
estuary or ocean?
YES
Intake velocity higher
than 3.5 feet per second?
YES
NO
Intake velocity 1.2 feet
per second or less?
YES
NO
Intake Module Assigned
shoreline (flush, recessed) 3
Intake canal 11
embayment, bay or cove 3
submerged offshore 9
near-shore submerged 4
shoreline submerged 4
Intake velocity higher
than 3.5 feet per second?
YES
NO-
Intake velocity 1.2 feet
per second or less?
YES
Intake
shoreline (flush, recessed)
intake canal
embayment, bay or cove
submerged offshore
near-shore submerged
shoreline submerged
Module Assigned
3
3
3
13
12
12
Intake Module Assigned
shoreline (flush, recessed) 1
intake canal 1
embayment, bay or cove 2 (5)*
submerged offshore 8
near-shore submerged 9
shoreline submerged 1
"The second cost modulo is assigned when
navigational considerations apply to the intake.
Intake Module Assigned
shoreline (flush, recessed) 3 (4)*
intake canal 3
embayment, bay or cove 7
submerged offshore 9
near-shore submerged 4
shoreline submerged 4
Intake Module Assigned
shoreline (flush, recessed) 2
intake canal 2
embayment, bay or cove 2
submerged offshore 9
near-shore submerged 4
shoreline submerged 2
Intake.
shoreline (flush, recessed)
Intake canal
embayment, bay or cove
submerged offshore
near-shore submerged
shoreline submerged
Module Assigned
3 (12)*
3
14
13
12
12
Intake
shoreline (flush, recessed)
intake canal
embayment, bay or cove
submerged offshore
near-shore submerged
shoreline submerged
Module Assigned
2
2
2 (12)*
13
12
2
Cost Module Legend
Module Technology Description
1 Addition of fish handling and return system to en existing trevsling screen system
2 Addition of fish-mesh screens to an existing traveling screen system
3 Addition of a new. larger intake with fine-mesh and fish handling and return system
4 Addition of passive tine-mesh screen system (cylindrical wedgewiral
5 Addition af a fish net barrier system
7 Relocation of an existing intake to a submerged offshore location with passive fine-mesh screen
8 Addition of a velocity cap inlet to en existing offshore intake
9 Addition of passive fine-mash screen to an existing offshore intake
11 Addition of dual-entry, single-exit traveling screens to a shoreline intake system
12 Addition of passive fine-mesh screen system (cylindrical wedgewire) near shoreline
13 Addition of passive fine-mesh screen to an existing offshore intake
14 Relocation of an existing intake to a submerged offshore location with passive fine-mesh screen
The Agency used the costing equations it developed for the Phase IINODA, the cost-methodology published in the Phase IINODA,
and the data obtained from the surveys in the same way it did for developing the costs of the final rule in putting together this cost-test
tool. Every effort has been made to utilize the original methodology published in the Phase II NODA (accounting for comments
5-8
-------
§ 316(b) Phase III - Technical Development Document
Costing Methodology for Model Facilities
received from the public), to account for the judgment determinations (through empirical data analysis when possible), to combine the
varied analyses conducted for development of the costs, and to ensure that the final program outputs reflect the costs developed by
EPA.
The data fields requested in the "User Inputs" sheet (see Figure 5-2) come from questions in the surveys plus a few basic observations
about the intake (such as a judgment about the degree of debris loading at the intake: "high" or "low", or whether there are navigational
considerations for the location of the intake based on GIS maps). The program reproduces the methodology the Agency utilized to
develop final costing decisions in order to determine what technology would best suit a particular intake.
Figure 5-2. Screen Capture of Cost-Test Tool User Inputs
User Inputs -At The Intake Level
Facility Womatkm-lnoUlnUti»SpecHic Data In Boxes
Cooling SystemType =|__J (1« Full Retira***, 0=AH Oners)
State Abbreviatbn =
Wafcrtody Type H | (1=Ocean, 2=Estuary, 3=Great Lake, 4=Fresh River, 5=Late/Res.)
Fuel Type =r 10' Nuclear, O'NnvNudear)
Capacity Uttaafcn (1996-99) =\ |%
Intake Location/Desoiplionl [(choose (ran tescripliontabte at right)
Narigatan/WatBtody
Mean Intake Wafr Depth
Intake Wei Depth'
Rw Proportional Flow
Design Intake Flow
Through Screen Velocity
Water Type =
Debris Loading
hrpnguiieiit Tech In-Place
Qualified ImpmgBrnent?
EntraJnrnent Tech ItvPlace
Qualified Enlrantrent?
avg annual generation 'SB
(1 = boat/barge navigation near intake, 0=dear intake area)
ft
ft
(If intake > 5%of mean annual river flow* 1, otters=0)
(1 = marine, 0=tesh)
(1 = high, 0=normal)
(choose from Inpngmsnt Tech list at right)
(1 = Qualified, 0 • none; see impingement reducBon table to tight)
(choose from Enlrainrnent Tech 1st at right
(1 = Qualified, 0=none; see ertrainment reduction table to right)
(I**, reported data, exducing outliers)
Fadity Information Tables/Keys
intake Locdion / Description
1 = Shoreline Intake (fkjsh, recessed)
2=Intake Canal
3=Embayment Bay, or Cove
4=Sunmerged Offshore Intake
5=Near-shore submerged intake
3 - Shoreline Submerged Intake
wpingmftnt Technologies In-place
0=None of tose listed
1= Traveling Screens
2=Passive Intake (Vekxaty Cap, Coarse Wadgewire
Screens, Pcnxis Dam, Leaky Dike, etc.)
; Barrier Net
4=Fish Diversion or Avctoance (Lowers, Acousta, et.)
ivplaceTe^ FA-OjaHiecf tor Inringniert Reductions
rBh Handling and Fatum Systems for Traveling Screens
^assive Intakes (velocrty cap, t-screens, porous dsms, etc.)
BarwNets
Through screen velocity of .5 fps or less
EntralmMnt Tectinologjes In-place
0=None of those listed
1=Traveling Screens W Fine Mesh
2=Far Offshore Intake
3=Passive Screens WFre Mesh
liHilace Tech B>A •CmUeff far Entmnment Reductions
ine Mesh Screens (passive or traveling screens)
Far Offshore Intake vtf Passwe Intake at Inlet
2.2 Cost-Test Tool Inputs
This section describes the inputs to the Cost Test Tool (see Figure 5-2), and defines the default values used for Phase III facility
costing. The default value was used when facility level information was not available from EPA's survey.
Cooling System Type. A value of l(one) indicates the facility was identified in EPA's survey as using a fully recirculating system. A
fully recirculating system uses minimum makeup and blowdown flows to withdraw cooling water, where the heat is dissipated by a
cooling canal or channel, lake, pond, or tower. A facility identified as having a fully recirculating system does not receive any further
5-9
-------
§ 316(b) Phase III - Technical Development Document Costing Methodology for Model Facilities
technology costs, but still receives permit costs. A value of 0 (zero) indicates the facility was identified in EPA's survey as using one
of the following systems: once-through, combination, other, or unknown.
For the development of compliance technology costs, the Agency considered facilities with recirculating systems in-place to need no
technology upgrades. For the purposes of the cost analysis the Agency defined facilities with recirculating systems as only those
facilities with recirculating cooling systems for the facility's entire intake system. If a facility had a combination of intakes that
utilized once-through and recirculating systems, the Agency treated the facility as a full once-through facility. In addition, if a facility
had a once-through or combination system and exercised strategic flow reductions (as reported in questions 26 of the detailed
questionnaire), the Agency still treated the facility as a full once-through facility.
State Abbreviation. The two letter state abbreviation is used to identify the state where the intakes are located. The state is used to
assign state-specific capital cost factors from the "location cost factor database" in RS Means Cost Works 2001. The state also is used
to identify whether zebra mussels are a potential problem at a facility. Where zebra mussels are a potential problem, the costs include
using CuNi alloys for intake upgrades located in freshwater.
Waterbody Type. The numeric values 1 through 5 represent the waterbody type for each intake's location. These values are
l=Ocean, 2=Estuary, 3=Great Lake, 4=Fresh River, 5=Lake/Reservoir. A facility located on a waterbody with unobstructed access to
a Great Lake, and located within 30 miles of a Great Lake shoreline is classified as Great Lake.
Criteria for delineating/defining tidal rivers and estuaries. EPA uses salinity as the principle criterion (EPA, 2001). From the final
Phase I and final Phase II regulatory language (§ 125.83 and § 125.93, respectively):
"Estuary means a semi-enclosed body of water that has a free connection with open seas and within which the seawater is measurably
diluted with fresh water derived from land drainage. The salinity of an estuary exceeds 0.5 parts per thousand (by mass) but is
typically less than 30 parts per thousand (by mass)."
EPA reviewed all of the waterbody types supplied by facilities in their survey using data from NOAA and other sources to plot the
facilities in GIS and confirm the waterbody type. EPA also used NOAA data on tidal movements to cross-check the designations.
Fuel Type. A value of 1 (one) indicates the intake is part of a nuclear facility, and results in additional cost factors. A value of 0
(zero) indicates the intakes is non-nuclear. Construction and material costs tend to be substantially greater for nuclear facilities due to
burden of increased security and to the requirements for more robust system design. Therefore, nuclear facilities in freshwater are
assigned cost factor of 1.33 and those in saltwater 1.45. See Phase II Technical Development Document for further discussion.
Capacity Utilization Rate (CUR). This percentage value reflects the ratio between the average net annual net generation of power by
the facility (in MWh) and the total net capability of the facility to generate power (in MW) multiplied by the number of hours during a
year. EPA used the year 2008 CUR as projected by the IPM model as the base case. See Preamble to Phase II (69 FR 41650) for a
discussion of the sensitivity of costs to this assumption. Facilities with a CUR of 15 percent or higher and making cooling water
withdrawals from tidal rivers, estuaries, oceans, or one of the Great Lakes (see waterbodv type) are subject to entrainment
requirements under the Phase 2 rule. The default CUR is 20 percent. Manufacturing facilities do not have a CUR, and are assigned
the default value of 20.
Intake Location. The numeric values 1 through 6 represent the location and description for each intake. These values are l=shoreline
intake (flushed, recessed), 2= intake canal, 3=embayment, bank, or cove, 4=submerged offshore intake, 5=near-shore submerged
intake, 6=shoreline submerged intake. Several facilities did not provide their intake location information in their industry
questionnaire and EPA used data from other parts of the facility's survey to determine the intake location. For example, a facility that
gives no intake location but states that it has a vertical traveling screen likely has a shoreline intake. Other facilities might give
information on the length of an intake canal or the presence of a wedgewire screen, indicating an intake canal and a submerged intake,
respectively.
Navigation/Waterbody Use. A value of l(one) indicates the intake is located where boat/barge navigation near the intake is a
consideration when making any modifications to the intake. A value of 0 (zero) indicates navigation does not occur in the vicinity of
the intake. Navigational considerations affect which technology modules may be used by intakes located in embayments, banks, or
coves (see intake location'). EPA used maps and satellite imagery obtained from mapquest to identify which intakes were located in
areas of boa^arge traffic. The default value is 1.
Design Intake Flow (DIF). The DIP is the numerical value assigned during the facility's design to the total volume of water
withdrawn. For facilities reporting one intake, the reported DIF was used. If a facility reports multiple intakes, all intakes were used
-------
§ 316(b) Phase III - Technical Development Document
Costing Methodology for Model Facilities
for purposes of the facility's total DIP. For costing purposes, only those intakes with a screen velocity greater than 0.5 feet per second
were costed for impingement controls (i.e. the DIP for the total facility is greater than the DIP used for costing; this occurs in 12
cases.) If an intake is for a hydroelectric station, the flows are not used for exchange of waste heat and therefore do not meet the
definition of cooling water. Furthermore, intakes at Phase III facilities with hydro plants do not meet the 25% of water use criterion
for defining a CWIS, and these flows are not included for purposes of calculating costs; this occurs in 2 cases.
Canal Length and Distance to Submerged Offshore Intake. Though these values are not direct inputs, they are a function of
waterbody type. The default constructed canal length is the median of all reported values from Phase II facilities. This is used to
determine how long the fish return system is, and the default ranges from 683 feet (fresh water river) to 3668 feet (for oceans).
Submerged offshore intake distance affects construction and civil costs as well as O&M costs, and is a critical parameter for relocating
intakes. The default distance of submerged offshore intakes is the median of all reported values from Phase 2 facilities by waterbody
type. The default value ranges from 100 feet (tidal river) to 2773 feet (Great Lakes). These defaults were not revised for Phase III
facilities.
Mean Intake Water Depth and Intake Well Depth. The screen well depth is the distance from the intake deck to the bottom of the
screen well, and includes both water depth and distance from the water surface to the deck. The default value used in Phase III costing
is the mean of all reported values by Phase III facilities as shown in the following table. Gray denotes the default values used in
Phase II.
Exhibit 5-6. Mean Intake Water Depth and Well Depth at Phase HI Facilities
Industry
manufacturing
(n>22)
electric generating
(n>46)
Design Capacfr
Mean Intake
Water Depth (ft)
19
15
f = or>50MGD
Mean Intake Well
Depth (ft)
22
18
Design Cai
Mean Intake Water
Depth (ft)
16
12
jacity < 50 MGD
Mean Intake Well Depth
(ft)
17
14
River Proportional Flow. A value of 1 (one) indicates the design intake flow is greater than 5 percent of the mean annual flow of a
freshwater river or stream. A value of 0 (zero) indicates the design intake flow is equal or less than 5 percent of the mean annual flow
of a freshwater river or stream.
Through-Screen Velocity. A through screen velocity of 0.5 feet per second or less meets the performance standards for impingement
mortality and does not incur any capital costs to meet impingement requirements. The Phase II default value is the mean reported
value for all electric generators with greater than 50 MGD design intake flow, shown in gray in the table below. For Phase III
facilities not reporting a through-screen velocity, EPA used mean reported values of Phase III facilities as shown in the following
table:
Exhibit 5-7. Through-Screen Velocity at Phase III Facilities
Industry
manufacturing
(n>22)
electric generating
(n>46)
Design Capacity = or > 50 MGD
Screen Velocity (feet per second)
1.2
1.5
Design Capacity < 50 MGD
Screen Velocity (feet per second)
0.8
0.6
Fourteen Phase III facilities had multiple intakes. EPA used the weighted average through-screen velocity for all intakes reported
provided the screen velocity was greater than 0.5 feet per second. If the through-screen velocity for a particular intake was 0.5 feet
per second or less, the intake meets impingement requirements and EPA did not assign technology controls to that particular intake.
EPA assigned weights according to the design intake flow of each reported intake.
5-71
-------
§ 316(b) Phase HI - Technical Development Document
Costing Methodology for Model Facilities
Water Type. A value of 1 (one) indicates the water is marine. A value of 0 (zero) indicates the water is fresh water. The default is
0 (zero).
Debris Loading. A value of l(one) indicates high levels of debris and trash near the intake. A value of 0 (zero) indicates debris is
low or negligible. The default is 1 (one). A facility reporting use of a trash rack in the survey is assumed to have high debris
loading.
Impingement Tech In-PIace. A numerical value of 0 through 4 is used to indicate the intake has impingement technologies
reported as in-place by the facility. A value of 1= Traveling Screens, 2= Passive Intake (Velocity Cap, Coarse Wedgewire Screens,
Porous Dam, Leaky Dike, etc.), 3= Barrier net, and 4 = Fish Diversion or Avoidance (Louvers, Acoustics, etc.). A facility is treated
as having a traveling screen if the facility reported having both an intake screen and shoreline intake location. A value of zero
means no controls or none of the above identified controls. The default is 0 (no controls).
Exhibit 5-8. Data Sources for Baseline Impingement and Entrainment Technologies In-place
TYPE OF TECHNOLOGY
SOURCE OF INFORMATION
Detailed Questionnaire
Short Technical Questionnaire
Impingement & Entrainment Technology
Passive Intake Systems
Wedgewire Screen *
Perforated Pipe
Porous Dike
Leaky Dams
Artificial Filter Bed
> < „.*, " v 'f'f 'f* ",'! - «
21(b)G
21(b)H
21(b)I
21(b)J
21(b)K
14(b)
' '•;,;.? ; '*%?''*- -;-s
*^«,"ji{-\ * ^
%* ' •*•*"•'» ,..»*
1 ^ .4 '• " >
Impingement Technology
Fish Diversion or Avoidance Systems
Velocity Cap
Louver Barrier
Fish Net Barrier
Fish Handling and bypass Systems with any
Traveling Screen
Fish Pump
Fish Conveyance
Systemftroughs of pipes)
Fish Elevator/Lift baskets
Fish Bypass System
' ' -• -•-.-, -„" •/:-,:.-- ,-C
22(b)M
22(b)N
22(b)P
19(b)A, B, E1-E6 & 23(b)W
19(b)A, B, E1-E6 & 23(b)X
19(b)A, B, E1-E6 & 23(b)Y
19(b)A,B,El-E6&23(b)Z
14(a)
~ ' ^
•__-,. _ « •- ":..- .
14(c) and 14(d)
, ' - " ' '' *
5-12
-------
§ 316(b) Phase III - Technical Development Document Costing Methodology for Model Facilities
Exhibit 5-8. Data Sources for Baseline Impingement and Entrainment Technologies In-place (continued)
TYPE OF TECHNOLOGY
Aquatic Filter Barrier Systems or
"Gunderboom "
Traveling fine mesh screens**
***
19(b)El-E6&19(c)(3)-(2)
SOURCE OF INFORMATION
Detailed Questionnaire
***
* Only a Wedgewire with a Fine Mesh Screen meets requirement for entrainment.
** Fine Mesh is 5mm or less
*** Not implemented at Phase III cooling water intake structures.
Qualified Impingement. Facilities with Impingement Tech In-Place = 2 (Passive Intake) receive a numerical value of 1 (one). All
other facilities receive a value of 0 (zero). The default is 0 (zero).
Entrainment Tech in-Place. A numerical value of 0 through 3 is used to indicate the intake has entrainment technologies reported
as in-place by the facility. A value of 1= Traveling Screens w/ Fine Mesh, 2= Far Offshore Intake, and 3 =Passive Screens w/ Fine
Mesh. A value of zero means no controls or none of the above identified controls. The default is 0 (no controls).
Qualified Entrainment. Facilities with qualified entrainment controls receive a numerical value of 1 (one) and receive no further
capital costs for entrainment controls. Entrainment Tech in-Place = 1 or 3 are qualified as meeting the entrainment controls.
Facilities with Entrainment Tech in-Place=2 (far offshore) AND also with Impingement Tech In-Place = 2 (Passive Intake) are
qualified, and receive a value of 1 (one). All other facilities receive a value of 0 (zero). The default is 0 (zero).
2.3 Limitations of the Cost Test Tool
In Phase II, EPA allocated less than a dozen intakes to install more than one intake technology. The cost-test tool does not account
for this fact, but rather assumes that a single best technology available can be prescribed for each intake. The end effect of this
might be such that a few intakes that actually require multiple technologies to meet the rule would compare the costs of these to the
individual technology cost derived in this tool. Additionally, technology Module 6 (Gunderboom) and Module 10 (for submerged
offshore intakes) are used sparingly in practice. To simplify the decision tree for assigning a compliance technology, these two
technology modules are not included in the cost-test tool.
In Phase II, facilities have 5 compliance alternatives for meeting the final requirements. Under each regulatory option evaluated for
Phase III facilities, the facility would have the same compliance alternatives described in the final Phase II rule. These compliance
alternatives are not addressed by the cost-test tool. All facilities are costed for one of the technology modules, which does not
reflect the most cost-effective compliance option for certain facilities.
Costs for permitting, monitoring, and recordkeeping are not included in the cost-test tool. Costs for these activities were developed
separately, and may be found in the Information Collection Request for the Phase III proposed rule (ICR 2169.01, DCN 7-0001).
2.4 Fixed and Variable Costs
The annual O&M cost estimates used in the cost modules is the net O&M cost, which is the difference between the estimated
baseline O&M and the incremental compliance O&M costs. Therefore, the fixed or variable proportions for each facility may vary
depending on the mix of baseline and compliance technologies. When a facility has baseline O&M costs, and incurs no additional
O&M costs as a result of new technology, the incremental O&M cost is 0 (zero). To calculate fixed and variable costs, EPA used
the following equations and baseline cost factors:
Eqn 2.41 Fixed baseline O&M = (baseline O&M) * (baseline cost factor)
Eqn 2.42 Fixed compliance O&M = (compliance O&M) * (technology cost factor)
Eqn 2.43 Net Total O&M = (Compliance O&M) - (Baseline O&M)
Eqn 2.44 Net Fixed O&M = (Fixed baseline O&M) + (Fixed compliance O&M)
Eqn 2.45 Net Variable O&M = (Net Total O&M) - (Net Fixed O&M)
5-73
-------
§ 316(b) Phase III - Technical development Document
Costing Methodology for Model Facilities
Exhibit 5-9. Baseline Cost Factors for Control Technologies
Technology
Baseline Technology Fixed O&M Cost Factors
Add Fish Handling and Return System
Add Fine Mesh Traveling Screens with Fish Handling and Return
Add New Larger Intake Structure with Fine Mesh, Handling and Return
Add Passive Fine Mesh Screens (1.75 mm mesh) at Shoreline
Add Velocity Cap at Inlet
Add Passive Fine Mesh Screen (1 .75 mm mesh) at Inlet of Offshore Submerged
Add Double-Entry, Single-Exit with Fine Mesh, Handling and Return
Add 0.75 mm Passive Fine Mesh Screen at Shoreline for Estuary & Ocean only
Add 0.75 mm Passive Fine Mesh Screen at Inlet of Offshore Submerged for Estuary & Ocean
only
COST FACTOR
0.41
0.40
0.40
0.24
0.24
1.0
0.24
0.385
0.24
0.24
Exhibit 5-10. Baseline Technology Fixed O&M Cost Factors
Technoloav Descriotion
Travelina Screen With Fish Handlina
Travelina Screen With Fish Handlina
Travelina Screen With Fish Handlina
Travelina Screen With Fish Handlina
Travelina Screen With Fish Handlina
Travelina Screen With Fish Handlina
Travelina Screen With Fish Handlina
Travelina Screen With Fish Handlina
Travelina Screen Without Fish Handlina
Travelina Screen Without Fish Handling
Travelina Screen Without Fish Handlina
Travelina Screen Without Fish Handlina
Travelina Screen Without Fish Handlina
Travelina Screen Without Fish Handlina
Travelina Screen Without Fish Handlina
Traveling Screen Without Fish Handling
AoDlication
10 Ft Screen Wells
25 Ft Screen Wells
50 Ft Screen Wells
75 Ft Screen Wells
10 Ft Screen Wells
25 Ft Screen Wells
50 Ft Screen Wells
75 Ft Screen Wells
10 Ft Screen Wells
25 Ft Screen Wells
50 Ft Screen Wells
75 Ft Screen Wells
10 Ft Screen Wells
25 Ft Screen Wells
50 Ft Screen Wells
75 Ft Screen Wells
Water Tvoe
Freshwater
Freshwater
Freshwater
Freshwater
Saltwater
Saltwater
Saltwater
Saltwater
Freshwater
Freshwater
Freshwater
Freshwater
Saltwater
Saltwater
Saltwater
Saltwater
Fixed Factor
0.28
0.30
0.32
0.33
0.31
0.34
0.36
0.38
0.45
0.47
0.48
0.49
0.49
0.51
0.53
0.53
5-14
-------
§ 316(b) Phase HI - Technical Development Document
Costing Methodology for AAodel Facilities
Exhibit 5-11. Compliance Technology Fixed O&M Cost Factors
Technology Description
Aauatic Filter Barrier
Add Fish Barrier Net Using Anchors and Bouys
Add Fish Barrier Net Using Pilings for Support
Add Fish Barrier Net Using Pilings for Support
Add Fine Mesh Passive T-screens to Existing Offshore Intake
Add Fine Mesh Passive T-screens to Existing Offshore Intake
Add Very Fine Mesh Passive T-screens to Existing Offshore Intake
Add Very Fine Mesh Passive T-screens to Existing Offshore Intake
Relocate Intake Offshore with Fine Mesh Passive T-screens
Relocate Intake Offshore with Fine Mesh Passive T-screens
Relocate Intake Offshore with Very Fine Mesh Passive T-screens
Relocate Intake Offshore with Very Fine Mesh Passive T-screens
Traveling Screen With Fish Handling and Fine Mesh
Traveling Screen With Fish Handling and Fine Mesh
Traveling Screen With Fish Handling and Fine Mesh
Traveling Screen With Fish Handling and Fine Mesh
Traveling Screen With Fish Handling and Fine Mesh
Traveling Screen With Fish Handling and Fine Mesh
Traveling Screen With Fish Handling and Fine Mesh
Traveling Screen With Fish Handling and Fine Mesh
Traveling Screen With Fish Handling
Traveling Screen With Fish Handling
Traveling Screen With Fish Handling
Traveling Screen With Fish Handling
Traveling Screen With Fish Handling
Traveling Screen With Fish Handling
Traveling Screen With Fish Handling
Traveling Screen With Fish Handling
Traveling Screen Dual-Flow
Traveling Screen Dual-Flow
Traveling Screen Dual-Flow
Traveling Screen Dual-Flow
Traveling Screen Dual-Flow
Traveling Screen Dual-Flow
Traveling Screen Dual-Flow
Traveling Screen Dual-Flow
Velocity Cap
Cooling Towers
Application
All
All
10 Ft Net Depth
20 Ft Net Depth
High Debris
Low Debris
High Debris
Low Debris
High Debris
Low Debris
High Debris
Low Debris
10 Ft Screen Wells
25 Ft Screen Wells
50 Ft Screen Wells
75 Ft Screen Wells
10 Ft Screen Wells
25 Ft Screen Wells
50 Ft Screen Wells
75 Ft Screen Wells
10 Ft Screen Wells
25 Ft Screen Wells
50 Ft Screen Wells
75 Ft Screen Wells
10 Ft Screen Wells
25 Ft Screen Wells
50 Ft Screen Wells
75 Ft Screen Wells
10 Ft Screen Wells
25 Ft Screen Wells
50 Ft Screen Wells
75 Ft Screen Wells
10 Ft Screen Wells
25 Ft Screen Wells
50 Ft Screen Wells
75 Ft Screen Wells
All
All
Water Type
All
Freshwater
Saltwater
Saltwater
All
All
All
All
All
All
All
All
Freshwater
Freshwater
Freshwater
Freshwater
Saltwater
Saltwater
Saltwater
Saltwater
Freshwater
Freshwater
Freshwater
Freshwater
Saltwater
Saltwater
Saltwater
Saltwater
Freshwater
Freshwater
Freshwater
Freshwater
Saltwater
Saltwater
Saltwater
Saltwater
All
All
Fixed Factor
1.0
1.0
1.0
1.0
0.21
0.27
0.19
0.27
0.46
0.56
0.38
0.49
0.38
0.35
0.37
0.39
0.41
0.38
0.40
0.41
0.40
0.42
0.42
0.42
0.42
0.43
0.44
0.44
0.40
0.40
0.40
0.40
0.44
0.44
0.44
0.44
1.0
0.5
3.0 EXAMPLES OF APPLICATION OF TECHNOLOGY COST MODULES TO MODEL FACILITIES
Exhibit 5-12. Initial Capital-Cost Equations for Phase III Technology Upgrades
Technology Upgrade
Module 1 (freshwater):
Add Fish Handling and/or
Return System
Well Depth
Range (ft)
10
25
50
75
100
Capital Cost Equation
Y= 1.5111WA2+ 12863W + 56372
Y = 1 3 .296WA2 + 1 85 1 7W + 48889
Y = 8.5055WA2 + 27952W + 76555
Y = 12.91 WA2 + 35525W + 97459
Y = 16.308WA2 + 42746W + 129320
Equation
1-1
1-2
1-3
1-4
1-5
5-75
-------
S 316(b) Phase HI - Technical Development Document
Costing Methodology for Model Facilities
Exhibit 5-12. Initial Capital-Cost Equations for Phase III Technology Upgrades (continued)
Technology Upgrade
Module 1 (saltwater):
Add Fish Handling and/or
Return System
Technology Upgrade
Module 1 2 (freshwater w/o zebra
mussels):
Add 0.75 mm Passive Fine Mesh
Screen at Shoreline
Module 12 (freshwater w/ zebra
mussels):
Add 0.75 mm Passive Fine Mesh
Screen at Shoreline
Module 12 (saltwater):
Add 0.75 mm Passive Fine Mesh
Screen at Shoreline
Well Depth
Range (ft)
10
25
50
75
100
Distance Offshore
(m)
20
125
250
500
20
125
250
500
20
125
250
500
Capital Cost Equation
Y = 7.4491 WA2 + 22493W + 79504
Y = 31 .476WA2 + 32889W + 60070
Y = 22.351WA2 + 50846W + 1 10933
Y = 31. 616WA2 + 65080W+ 148273
Y = 38.869WA2 + 7861 1W + 207527
Capital Cost Equation
Y = -0.000002XA2 + 8.6127X + 99538
Y = -0.000001XA2 + 15.183X+ 1 1 1563
Y = -0.000003XA2 + 23.006X+125879
Y = 0.000003XA2 + 38.65X+ 15451 1
Y = -0.000003XA2 + 12.322X+ 97733
Y = -0.000001XA2 + 18.893X+ 109758
Y = -0.0000001XA2 + 26.715X+ 124074
Y = 0.000003XA2 + 42.359X + 152706
Y = -0.000002XA2 +9.7123X + 99830
Y = -0.000001XA2 + 17.696X+ 1 13409
Y = -0.0000005XA2 + 27.201X+ 129575
Y = 0.000004XA2 + 46.21 1X+ 161906
Equation
1-6
1-7
1-8
1-9
1-10
Equation
12-1
12-2
12-3
12-4
12-5
12-6
12-7
12-8
12-9
12-10
12-11
12-12
Note: The costing equations presented in this table do not include the cost factors to correct for different plant type and regional
location.
Note: W is the screen width per costing unit in feet. X is the total design intake flow per costing unit in gallons per minute.
Exhibit 5-13. Plant Type Cost Factors
Plant Type
Non-nuclear
Nuclear in freshwater
Nuclear in saltwater
Capital Cost Factor
1
1.8
1.8
O&M Cost Factor
1
1.33
1.45
5-16
-------
§ 316(b) Phase IH - Technical Development Document
Costing Methodology for Model Facilities
Exhibit 5-14. Regional Cost Factors and List of States with Freshwater Zebra Mussels as of 2001
STATE
AK
AL
AR
AZ
CA
CO
CT
DE
FL
GA
HI
IA
IL
IN
KS
KY
LA
MA
MD
ME
MI
MN
MO
MS
MT
STATE MEDIAN
1.264
0.823
0.811
0.905
1.108
0.926
1.0695
1
0.84
0.828
1.257
0.942
1.028
0.955
0.96
0.908
0.832
1.1075
0.931
0.952
1.0125
1.093
0.9765
0.783
0.932
Zebra Mussels?
No
Zebra
No
No
No
No
Zebra
No
No
No
No
Zebra
Zebra
Zebra
No
Zebra
Zebra
No
No
No
Zebra
Zebra
Zebra
Zebra
No
STATE
NC
ND
NE
NH
NJ
NM
NV
NY
OH
OK
OR
PA
RI
SC
SD
TN
TX
VA
VI
VT
WA
WI
VW
WY
STATE MEDIAN
0.766
0.864
0.853
0.94
1.11
0.927
1.018
1.039
0.9885
0.8305
1
1.008
1.063
0.763
0.796
0.828
0.807
0.861
1
0.749
1
0.989
0.963
0.841
Zebra Mussels?
No
No.
No
No
No
No
No
Zebra
Zebra
Zebra
No
Zebra
No
No
No
Zebra
No
No
Zebra
No
Zebra
Zebra
No
5-17
-------
S 316(b) Phase IH - Technical Development Document
Costing Methodology for Model Facilities
Exhibit 5-15. Baseline O&M Cost Equations for Phase II Technology Upgrades
Existing Technology
(Freshwater):
Traveling Screens w/o Fish Handling
and/or Return System
(Freshwater):
Traveling Screens with Fish
Handling and/or Return System
(Saltwater):
Traveling Screens w/o Fish
Handling and/or Return System
(Saltwater):
Traveling Screens with Fish
Handling and/or Return System
Well Depth
Range (ft)
10
25
50
75
100
10
25
50
75
100
10
25
50
75
100
10
25
50
75
100
Baseline O&M Cost Equation
B = -0.4155WA2 + 921.84W + 3239.8
B = -0.2419WA2 + 1082.2W + 3489.7
B = -0.6885WA2 + 1329.4W + 4633.2
B = -0.8842WA2 + 1508.1W + 5702.5
B = -1.0776WA2 + 1679.2W + 7012.9
B = -0.6031WA2 + 3303.7W + 7189.7
B = -0.0221 WA2 + 3826W + 7582
B = -0.6059WA2 + 4682.6W + 1 0003
B = -0.79WA2 + 5370.4W +12541
B = -0.8662WA2 + 6050.4W + 15301
B = -0.329WA2 + 1060.4W+ 3562.6
B = 0.1 181WA2 + 1283.4W + 3457.4
B = -0.6261WA2 + 1655.4W + 5238.8
B = -0.8367WA2 + 1902.3W +6763.2
B = -1.0778WA2 + 2131.2W + 8860.3
B = -0.2468WA2 + 3881.6W + 8577.6
B = 1.0687WA2 + 4688.4W + 8252.8
B = 0.2248WA2 + 6056.3 W + 12066
B = 0.3324WA2 + 7143.7W + 15590
B = 0.4874WA2 + 8202.3W+ 19994
Equation
B-l
B-2
B-3
B-4
B-5
B-6
B-7
B-8
B-9
B-10
B-ll
B-12
B-13
B-14
B-l 5
B-16
B-17
B-18
B-19
B-20
Note: Only facility with existing traveling screens have baseline O&M cost.
Exhibit 5-16. Initial Gross Compliance O&M Cost Equations for Phase III Technology Upgrades
Technology Upgrade
Module 1 (freshwater):
Add Fish Handling and/or Return
System
Well Depth
Range (ft)
10
25
50
75
100
Gross Compliance O&M Cost Equation
G = -0.6031WA2 + 3303.7W + 7189.7
G = -0.0221 WA2 + 3826W + 7582
G = -0.6059WA2 + 4682.6W + 10003
G = -0.79WA2 + 5370.4W +12541
G = -0.8662WA2 + 6050.4W + 15301
Equation
Gl-1
Gl-2
Gl-3
Gl-4
Gl-5
5-18
-------
§ 316(b) Phase IH - Technical Development Document
Costing Methodology for Model Facilities
Exhibit 5-16. Initial Gross Compliance O&M Cost Equations for Phase III Technology Upgrades (continued)
Technology Upgrade
Module 12 :
Add 0.75 mm Passive Fine Mesh
Screen at Shoreline
Debris Loading
low debris
high debris
Capital Cost Equation
G = -0.0000005XA2 + 0.1381X+ 17229
G = -0.0000008XA2 + 0.2952X+ 43574
Equation
G12-1
G12-2
Note: W is screen width per costing unit in feet. X is total design intake flow per costing unit in gallons per minute.
Exhibit 5-17. Information Collection Request Cost for Facility A and Facility B
Average per Facility Costs for each Information Collection Request Activities
NPDES Permit Application Activities*
Start-up Activities
Permit Application Activities
Proposal for Collection of Information for
Comprehensive Demonstration Study
Source Waterbody Flow Information
Design and Construction Technology Plan
Freshwater Impingement Mortality and
Entrainment Characterization Study
Marine Impingement Mortality and
Entrainment Characterization Study
Freshwater Pilot Study for Impingement
Only Technology
Freshwater Pilot Study for Impingement
& Entrainment Technology
Marine Pilot Study for Impingement Only
Technology
Marine Pilot Study for Impingement &
Entrainment Technology
Verification Monitoring Plan
Labor
Cost
(2002$)
$449
$2,121
$2,598
$732
$1,027
$87,454
$159,68
$10,488
$16,200
$12,043
$18,796
$1,253
Capital"
(2002$)
$0
$0
$0
$0
$0
$0
$0
$0
$23,538
$34,580
$66,787
$0
O&M
(2002$)
$10
$100
$150
$40
$80
$16,641
$33,020
$200
$1,400
$200
$1,760
$80
Facility A
(Example 1)
$459
$2,221
$2,748
$772
$1,107
n/a
n/a
$10,688
n/a
n/a
n/a
$1,333
Facility B
(Example 2)
$459
$2,221
$2,748
$772
$1,107
n/a
$192,700
n/a
n/a
n/a
$87,343
$1,333
Annual Monitoring and Reporting Activities
Biological Monitoring (Impingement,
Freshwater)
Biological Monitoring (Impingement,
Marine)
Biological Monitoring (Entrainment,
Freshwater)
$18,727
$23,837
$30,724
$500
$650
$8,800
$19,227
n/a
n/a
n/a
$24,487
n/a
5-79
-------
§ 316(b) Phase III - Technical Development Document
Costing Methodology for Model Facilities
Exhibit 5-17. Information Collection Request Cost for Facility A and Facility B (continued)
Average per Facility Costs for each Information Collection Request Activities
NPDES Permit Application Activities'
Yearly Status Report Activities
Verification Study8
Labor
Cost
(2002$)
$17,402
$1,391
Capital11
(2002$)
O&M
(2002$)
$750
$100
TOTAL
Facility A
(Example 1)
$18,152
$1,491
$58,198
Facility B
(Example 2)
$18,152
$1,491
$382,620
a: Average per facility labor and O&M costs for each NPDES Permit Application activity and Verification Study were distributed
over a five year period to reflect the permit term using Phase III 316b Information Collection Request costs.
b: Capital costs were annualized using 7% discount rate and 10 year amortization period.
Example 1. Facility Requires Upgrade to Add Fish Handling and/or Return System to Existing Traveling Screen System
Facility A is an imaginary coal-fired steam electric facility located on a freshwater river in Tennessee. The facility has a design
intake flow of 25 million gallons per day (mgd), a shoreline intake, and an existing traveling screen system with 3/8 inch mesh
(coarse mesh). In addition, Facility A produces electricity at near-full capacity and its intake flow is less than 5% of the river annual
flow. It has been determined that to comply with the example Phase III regulatory requirements ("Example A"), Facility A would
be required to meet impingement performance standards.
Assumptions
Facility A's existing through-screen velocity is 0.9 feet per second.
• Facility A's mean intake water depth is 12 feet.
• Facility A's intake well depth is 14 feet.
There is no significant navigation or waterbody use near the intake entrance.
• There is normal debris loading.
Step 1: Select the appropriate costing module from Exhibit 5-11.
Using the through-screen velocity, the intake location, and regulatory requirements, you can determine which technology best suits
the application. Since Facility A would be required to reduce impingement only, has low-range through-screen velocity, and has a
shoreline intake, the appropriate costing module is module number 1.
Module 1 = Add fish handling and return system.
Step 2: Select the appropriate equation from Exhibit 5-121.
Using the intake well depth and the costing module identified in Step 1, you can select the appropriate equation from Exhibit 5-12.
to use in determining the "Initial Capital Costs." Since Facility A has an intake well depth of 14 feet, the appropriate equation to
use from Exhibit 5-12. is Equation 1-2 because it is for costing module one and corresponds to intake well depth that range between
11 and 25 feet.
Y = (13.296W2 + 18517W + 48889) [See Eqn 1 - 2, Exhibit 5-12]
Where: W is the screen width per costing unit (in feet) which is calculated by dividing the total design intake flow by the
through-screen velocity; mean intake water depth; and open area factor, and Y is the Initial Capital Costs (in 2002 U.S.
dollars)
Step 3: Determine the total design intake flow for the facility.
The records indicate that the design intake flow for Facility A is 25 mgd. The Phase III rule would define design intake flow as "the
value assigned during the facility's design to the total volume withdrawn from the source waterbody over a specific time period."
5-20
-------
S 316(b) Phase IH - Technical Development Document Costing Methodology for Model Facilities
Facility may have the design intake flow value available in their records or it can be estimated based on the size of the intake pumps.
The design intake flow must be in the units "cubic feet per second (cfs)" for use with the equation in Step 4. Therefore, to convert
the design intake flow from mgd to cfs you can perform a dimensional analysis using the following equation.
1,000,000 gallons \cubicfeet Iday \hour Iminwte
' *•' x-
I million gallons IAS gallons 24 hours 60 minutes 60 seconds
Convert the 25 mgd to cfs as follows:
^/ y-x ~r , 1,000,000 gallons Icubicfeet Iday I hour 1 minute
X(cfs) = 25mgd x • x J- x £— x x
^ •* ' *^ -t •!!« II n A n II ^ A i s" /\ * j
I million gallons 7.48 gallons 24 hours 60 minutes 60 seconds
X = 38.68 cfs
Step 4: Determine the screen width per costing unit (feet), W.
The screen width per costing unit is calculated from the following equation:
W(ft) = [X(cfs)] H- [Through -screen Velocity (fps)] -*• [Mean Intake Water Depth (ft)] - [open area factor]
„„ ... 38.68 cubic feet second 1 1
W(ft} = x x x
second 0.9 feet 12 feet 0.68
W = 5.267 feet
Note: Flat per traveling screen unit width should not exceed 140 feet.
Step 5: Calculate the "Initial Capital Costs."
Using the screen width per costing unit in Step 4 and the equation identified in Step 2, the Initial Capital Cost is calculated as
follows:
Y = (13.296(5.267)2 + 18517(5.267) + 48889)
Y = $146,787
Step 6: Identify the appropriate cost factors from Exhibits 5-12 and 5-14.
Plant type cost factors are listed in Exhibit 5-13. Since Facility A is a non-nuclear facility, the plant type cost factor is one (1).
Regional cost factors are listed in Exhibit 5-14. Since Facility A is located in Tennessee, the regional cost factor is 0.828.
Step 7: Calculate the Total Estimated Capital Costs (TECC)
To calculate the total estimated capital costs (TECC) use the following equation:
TECC = (Initial Capital Cost) x (Plant Type Cost Factor) x (Regional Cost Factor)
Entering the initial capital cost calculated in Step 5 and cost factors identified in Step 6, the total cost can be calculated as follows:
TECC = ($146,787) x (1) x (0.828)
TECC = $121,540
5-27
-------
§ 316(b) Phase III - Technical Development Document Costing Methodology for Model Facilities
Step 8: Select the appropriate equations from Exhibits 5-15 and 5-16 to use in determining the "Baseline Operation and
Maintenance Costs", if applicable, and the "Gross Compliance Operation and Maintenance Costs."
To calculate the annual operation and maintenance (O&M) costs, you need to determine the gross compliance O&M costs (GCOM)
and the baseline O&M costs, if applicable. Only facilities with existing traveling screens have baseline O&M costs.
BASELINE O&M COSTS (E)
Using the intake well depth (ft) you can select the appropriate equation from Exhibit 5-15 to use in
determining the "Baseline Operation and Maintenance Costs." Since Facility A has an existing traveling screen without fish
handling system and an intake well depth of 14 feet, the appropriate equation to use from Table 5 is Equation B-2 because it
corresponds to well depth range between 11 and 25 feet.
B = (-0.2419W2 + 1082.2W + 3489.7) [See Eqn B - 2, Exhibit 5-15]
Where: W is the screen width per costing unit (in feet), and B is the Baseline Operation and Maintenance Costs (in 2002 U.S.
dollars)
INITIAL GROSS COMPLIANCE O&M COSTS (G)
Using the intake well depth (ft) and the cost module identified in Step 1, you can select the appropriate equation from Exhibit 16 to
use in determining the "Initial Gross Compliance Operation and Maintenance Costs." Since Facility A has an intake well depth of
14 fee t, the appropriate equation to use from Exhibit 5-16 is Equation Gl-2 because it is for costing module one and corresponds to
well depth range between 11 and 25 feet.
G = (-0.0221 W2 + 3826W + 7582) [See Eqn Gl - 2, Exhibit 5-16]
Where: W is the screen width per costing unit (in feet), and G is the Initial Gross Compliance Operation and Maintenance Costs (in
2002 U.S. dollars)
GROSS COMPLIANCE O&M COSTS (GCOM)
To determine the Gross Compliance Operation and Maintenance Costs (GCOM), you need the plant type cost factor from Exhibit 5-
13 and the following equation:
GCOM = (Initial Gross Compliance O&M) x (Plant Type Cost Factor)
Step 9: Calculate the Yearly Operation and Maintenance Costs.
To calculate the yearly operation and maintenance costs, use the following equation:
Net Annual O&M Cost = (GCOM) - (Baseline O&M)
BASELINE O&M COSTS (B)
Entering the screen width per costing unit calculated in Step 4, W=5.267, the baseline operation and maintenance costs can be
calculated as follows:
B = (-0.2419W2 + 1082.2W + 3489.7)
B = $ 9,183
INITIAL GROSS COMPLIANCE O&M COSTS (G)
Entering the screen width per costing unit calculated in Step 4, W=5.267, the initial gross compliance operation and maintenance
cost can be calculated as follows:
G = (-0.0221 (5.267)2 + 3826(5.267) + 7582)
G = $ 27,733
5-22
-------
§ 316(b) Phase. HI - Technical Development Document
Costing Methodology for Model Facilities
GROSS COMPLIANCE O&M COSTS (GCOINf)
Entering the plant type cost factor from Exhibit 5-13, plant type cost factor is 1, the gross compliance operation and maintenance
cost can be calculated as follows:
GCOM = (G) x (Plant Type Cost Factor)
GCOM = ($27,733) x (1)
GCOM = $27,733
NET ANNUAL O&M COSTS
Entering the calculated gross^compliance operation and maintenance cost and the baseline operation and maintenance cost from
above, the yearly operational and maintenance cost can be determined as follows:
Net Annual O&M Cost = (GCOM) - (Baseline O&M)
Net Annual O&M Cost = ($27,733) - ($9,183)
Net Annual O&M Cost = $ 18,550
Summary of Costs for Facility A at Different Design Intake Flow (DIF)
Total Estimated Capital
Costs
Annualized TECC
Net Annual O&M Costs
ICR Costs
TOTAL
DIF= 2 mgd
$46,943
$6,684
$5,249
$58,198
$70,131
DIF= 10 mgd
$72,833
$10,370
$9,874
$58,198
$78,442
DIF= 25 mgd
$121,540
$17,305
$18,551
$58,198
$94,054
DIF= 30 mgd
$137,831
$19,624
$21,444
$58,198
$99,266
DIF= 40 mgd
$170,477
$24,272
$27,232
$58,198
$109,702
Note: Annualized TECC is calculated using 7% discount rate and 10 years amortization period.
Note: See Table 7 for additional information on the ICR costs.
Example 2. Facility Requires Upgrade to Add Passive Fine Mesh Screen
Facility B is an imaginary manufacturer located on an estuary in Massachusetts. The facility has a design intake flow of 100 million
gallons per day (mgd), a near-shore submerged intake with a coarse mesh. It has been determined that to comply with the example
Phase III regulatory requirements ("Example A"), Facility B would be required to meet impingement and entrainment performance
standards.
Assumptions
• Facility B's existing through-screen velocity is 1.5 feet per second.
Facility B's mean intake water depth is 19 feet.
Facility B's intake well depth is 22 feet.
• Facility B's existing intake entrance is approximately 50 feet (15.3 meter) offshore.
There is no significant navigation or waterbody use near the intake entrance.
• There is norm al debris loading.
5-23
-------
§ 316(b) Phase III - Technical Development Document Costing Methodology for Model Facilities
Step 1: Select the appropriate costing module from Exhibit 5-11.
Using the through-screen velocity, the intake location, and regulatory requirements, you can determine which technology best suits
the application. Since Facility B would be required to reduce impingement and entrainment, has mid-range through-screen velocity,
and has a near-shore submerged intake, the appropriate costing module is module number 12.
Module 12 = Add Passive Fine Mesh Screen (0.75 mm).
Step 2: Select the appropriate equation from Exhibit 5-12.
Using the existing intake distance offshore and the costing module identified in Step 1, you can select the appropriate equation from
Exhibit 5-12 to use in determining the "Initial Capital Costs." Since Facility B intake is 50 feet offshore the appropriate equation to
use from Exhibit 5-12 is Equation 12-9 because it is for costing module 12 and corresponds to distance offshore that is less than 20
meter.
Y = (-0.000002X2 + 9.7123X + 99830) [See Eqn 12 - 9, Exhibit 5-12]
Where: X is the total design intake flow per costing unit in gallons per minute (gpm), and Y is the Initial Capital Costs (in 2002
U.S. dollars)
Step 3: Determine the total design intake flow for the facility.
The records indicate that the design intake flow for Facility B is mgd. The Phase III rule would define design intake flow as "the
value assigned during the facility's design to the total volume withdrawn from the source waterbody over a specific time period."
Facility may have the design intake flow value available in their records or it can be estimated based on the size of the intake pumps.
The design intake flow must be in the units "gallons per m inute (gpm)" for use with the equation in Step 4. Therefore, to convert
the design intake flow from mgd to gpm you can perform a dimensional analysis using the following equation.
1,000,000 gallons I day I hour
X(gpm) = X(mgd} x —— x —— x ——;
Imillion gallons 24 hours 60 minutes
Convert the 100 mgd to gpm as follows:
1,000,000gallons Iday I hour
X(gprri) = IQQmgd x — x —— x ——:
I million gallons 24 hours 60 minutes
X = 69,444 gpm
Note: Flow per screen unit must stay below 165,000 gpm for passive intake technology.
Step 4: Calculate the "Initial Capital Costs."
Using the total design intake flow in Step 3 and the equation identified in Step 2, the Initial Capital Cost is calculated as follows:
Y = (-0.000002(69444)2 + 9.7123(69444) + 99830)
Y = $764,646
Step 5: Identify the appropriate cost factors from Exhibit 5-13 and Exhibit 5-14.
Plant type cost factors are listed in Exhibit 5-13. Since Facility B is a non-nuclear facility, the plant type cost factor is one (1).
Regional cost factors are listed in Exhibit 5-14. Since Facility B is located in Massachusetts, the regional cost factor is 1.1075.
5-24
-------
§ 316(b) Phase III - Technical Development Document Costing Methodology for Model Facilities
Step 6: Calculate the Total Estimated Capital Costs (TECC)
To calculate the total estimated capital costs (TECC) use the following equation:
TECC = (Initial Capital Cost) x (Plant Type Cost Factor) x (Regional Cost Factor)
Entering the initial capital cost calculated in Step 4 and cost factors identified in Step 5, the total cost can be calculated as follows:
TECC = ($764,646) x (1) x (1.1075)
TECC=$ 121,540
Step 7: Select the appropriate equations from Exhibits 5-15 and 5-16 to use in determining the "Baseline Operation and
Maintenance Costs", if applicable, and the "Gross Compliance Operation and Maintenance Costs."
To calculate the annual operation and maintenance (O&M) costs, you need to determine the gross compliance O&M costs (GCOM)
and the baseline O&M costs, if applicable. Only facilities with existing traveling screens have baseline O&M costs.
BASELINE O&M COSTS (B)
There is no baseline O&M cost for Facility B because it does not have existing traveling screens.
INITIAL GROSS COMPLIANCE O&M COSTS (G)
Using the debris loading information and the cost module identified in Step 1, you can select the appropriate equation from Exhibit
5-16 to use in determining the "Initial Gross Compliance Operation and Maintenance Costs." Since Facility B has low debris
loading, the appropriate equation to use from Exhibit 5-16 is Equation G12-1.
G = (-0.0000005X2 + 0.1381X + 17229) [See Eqn G12 -1, Exhibit 5-16]
Where: X is the total design intake flow per costing unit (in gpm), and G is the Initial Gross Compliance Operation and
Maintenance Costs (in 2002 U.S. dollars)
GROSS COMPLIANCE O&M COSTS fGCOM)
To determine the Gross Compliance Operation and Maintenance Costs (GCOM), you need the plant type cost factor from the
following equation:
GCOM = (Initial Gross Compliance O&M) x (Plant Type Cost Factor)
Step 8: Calculate the Yearly Operation and Maintenance Costs.
To calculate the yearly operation and maintenance costs, use the following equation:
Net Annual O&M Cost = (GCOM) - (Baseline O&M)
BASELINE O&M COSTS (B)
There is no baseline O&M cost for Facility B because it does not have existing traveling screens.
INITIAL GROSS COMPLIANCE O&M COSTS (G)
Entering the total design intake flow from Step 3, X=69444 gpm, the initial gross compliance operation and maintenance cost can be
calculated as follows:
G = (-0.0000005(69444)2 + 0.1381(69444) + 17229)
G = $ 24,408
GROSS COMPLIANCE O&M COSTS (GCOM^
Entering the plant type cost factor from Exhibit 5-13, for Facility B it is 1, the gross compliance operation and maintenance cost can
be calculated as follows:
5-25
-------
§ 316(b) Phase III - Technical Development Document
Costing Methodology for Model Facilities
GCOM + (G) x (Plant Type Cost Factor)
GCOM = ($24,408)x(l)
GCOM = $24, 408
NET ANNUAL O&M COSTS
Entering the calculated gross compliance operation and maintenance cost and the baseline operation and maintenance cost from
above, the yearly operational and maintenance cost can be determined as follows:
Net Annual O&M Cost = (GCOM) - (Baseline O&M)
Net Annual O&M Cost = ($24,408) - ($0)
Net Annual O&M Cost = $24,408
Summary of Costs for Facility B at Different Design Intake Flow (DIP)
Total Estimated Capital
Costs
Annualized TECC
Net Annual O&M Costs
ICR Costs
TOTAL
DIF= 2 mgd
$125,497
$17,868
$17,420
$382,620
$417,908
DIF=10mgd
$185,152
$26,361
$18,164
$382,620
$427,145
DIF= 30 mgd
$333,691
$47,510
$19,889
$382,620
$450,019
DIF= 40 mgd
$407,641
$58,039
$20,679
$382,620
$461,338
DIF=100mgd
$846,845
$120,571
$24,408
$382,620
$527,599
Note: Annualized TECC is calculated using 7% discount rate and 10 years amortization period.
Note: See Table 7 for additional information on the ICR costs.
4.0
ANALYSIS OF THE CONFIDENCE IN ACCURACY OF THE COMPLIANCE COST MODULES
This section provides an overview of the confidence in the accuracy of the compliance capital and O&M costs developed using the
316(b) Phase II Compliance Technology Cost Modules. A key element in cost estimation is the available data and information
about site conditions. Some site conditions are favorable to design and construction works while others may involve higher degrees
of uncertainty. In sites with favorable conditions design and construction costs are expected to be lower than the cost of the same
project designed and constructed under "typical" or "normal" site conditions. On the other end of the spectrum, the costs are
expected to be significantly higher than that for the "typical" job site. The cost estimates developed for the compliance technologies
assume a "typical" rather than the exceptional job site, except where noted below.
In every design and construction endeavor a level of confidence is developed based on many factors. These factors include factual
or data attributes and non-factual or information attributes. The data attributes have to do with level of detail that is available to the
designer, the estimator, and the contractor. Also important is the information about the end product function and architectural
features of the job site where construction or installation of equipment needs to take place. The confidence also has to do with the
confidence in the source data and how the data was used to generate the information and confidence in the experience that is often
used by engineers and cost estimators to bridge gaps in the available data. As such, many professional organizations and authorities
in the engineering and construction arena have developed scales to identify necessary confidence levels at every stage of a project in
order to keep a project within the realm and context of reasonableness within budget and execution potential limits.
For example, the American Association of Cost Engineers International (AACE) recommends the following three construction cost
estimating categories with the corresponding different levels of accuracy shown in Exhibit 5-18. EPA generally develops budgetary
level cost estimates to forecast compliance cost estimates for a regulation. However, for the compliance technology cost estimates,
EPA took an additional step in developing costs that were closer to definitive or preliminary design costs estimates.
5-26
-------
§ 316(b) Phase III - Technical Development Document
Costing Methodology for Model Facilities
Exhibit S-18. Construction Cost Estimating Categories
Category
Purpose
Timing
Expected
Accuracy
1) Conceptual
Estimate
-Preliminary estimates for proposed
projects
-Generally used for screening of
alternatives
-Major equipment is sized and
specified
-Process flow is approved
-Utility requirements are specified
-Preliminary plot layout
+50% to
-30%
2) Budget Estimate
-To commit engineering budget
-To commit purchase of critical delivery
of equipment
-Appropriation request
-Check contractor's bids
Same as above except:
-process design basis is approved
-selection of alternatives has been
made
+30% to
-15%
4) Definitive
Estimate
-Detailed control budget
-Cost control and reporting
-Finalize contract structure
-Fee: adjust or convert
-Plot plan finalized or approved
-Equipment size and specs firm
-Flow diagrams complete
-Complete set of specifications
-Production engineering may be
completed up to 40%
+15% to
-5%
Source: (AACE 1996)
As described below some of the cost components such as equipment costs and technologies available from a limited number of
providers have an accuracy level that is much higher than a budgetary cost estimate. In general, given the context of the 316b
developed cost estimates, the accuracy of any module is not expected to be less than that of a "budget estimate."
The discussion below attempts to generally assess in more detail the accuracy of elements of the cost modules. For clarification
purposes, examples concerning the selection of assumed values used in the technology design or input variables are presented
below. In order to ensure that the national totals are reasonably accurate or exceed median values high-side design values were
assumed where noted.
In some modules, median values of the data provided by the detailed questionnaire facilities are assumed for facilities where specific
data input are not available (e.g., short technical questionnaire facilities). In some cases the overall median is used and in others
waterbody specific medians are used. The use of medians is intended to produce the best estimate of costs at the national level by
equally over- and under-estimating individual facility costs as a result of the assumed median value being higher or lower than the
actual value. A select set of modules were designed to err on the high side (i.e., overestimating the costs) because of the known
unpredictability of job sites and technology performance.
Inaccuracies due to regional differences in labor and materials costs are accounted for where necessary through the use of regional
cost factors. Where unit costs are based on RS Means data, the unit costs should be considered as having an accuracy of a definitive
estimate as these costs are derived and routinely updated using numerous national construction project data sources.
The Agency also considered the elevated costs for capital and operation and maintenance costs at nuclear stations. These costs were
applied as numerical multipliers to the costs discussed below. As such, the analysis of confidence levels discussed below for fossil-
fuel facilities will apply to nuclear facilities as well.
PASSIVE SCREENS
Cost Modules Covered:
• Module #4: Add Passive Fine Mesh Screens (1.75 mm mesh) at Shoreline
• Module #7: Relocate Intake to Submerged Offshore with Fine Mesh Passive Screen (1.75 mm mesh)
Module #9: Add Passive Fine Mesh Screen (1.75 mm) at Inlet of Offshore Submerged
Module #12: Add Very Fine Mesh (0.75 mm) Passive Screen at Shoreline
• Module #13: Add Very Fine Mesh (0.75 mm) Passive Screen at Inlet of Offshore Submerged
Module #14: Relocate Intake to Submerged Offshore with Very Fine Mesh (0-.75 mm) Passive Screen.
5-27
-------
§ 316(b) Phase III - Technical Development Document
Costing Methodology for Model Facilities
The differences between the fine mesh (1.75 mm) and very fine mesh (0.75 mm) screens were that the "per screen" flow rate was set
lower for finer mesh similar sized screens based on vendor recommendations. The per screen cost was slightly higher for similar
sized screens, and O&M cost were adjusted upward for finer mesh due to higher retention of debris with finer mesh. The analysis
below focuses on fine mesh screens but should also apply to the very fine mesh screen modules.
Passive Screen Capital Costs
Input Variables
The primary input variable was the intake design flow. Other variables included saltwater versus freshwater, and distance offshore.
To reduce inaccuracy due to differences in distance offshore, costs are developed for 4 distances offshore; 20 meters (which
corresponds to the "near shoreline" modules #4 and #12), 125 meters, 250 meters, and 500 meters. As can be seen in Exhibit 5-19
the distance offshore has a significant effect on the costs. Inevitably some inaccuracy will exist due to the potential mismatch of the
module distance and the actual distance. For adding passive screens to existing offshore intakes at facilities where the distance was
known, the next highest module distance was selected with a maximum of 500 meters. In general, this tended to bias the capital
costs upward but increased the confidence that the costs would not be underestimated. However, for those with existing distances
greater than 500 meters the costs were biased downward. For the short technical questionnaire facilities, the distance offshore for
existing submerged intakes was assumed to be equal to the median value for the data provided in the detailed questionnaires for
each waterbody category. This value was then rounded up to the next of the four module distances to increase the confidence that
the costs would not be underestimated. The assumption that there would be sufficient depth for larger size screens, provides a
potential bias of costs towards the low side where high design flows require large screens to be installed near shore in shallow
water. For larger flows, shallow water requires multiple smaller screens which would tend to increase screen and piping costs. To
limit this potential bias, facilities requiring multiple large screens were rarely considered as candidates for near shore applications.
Capital Cost Components:
The total estimated capital costs for adding passive wedgewire t-screens consists of the following cost components:
• Screens
• Backwash Equipment
• Backwash Air Piping
Steel Pipe
• Connecting Wall
The proportion and significance of each to the total capital cost depends on the specific application. The proportion of the total for
each component varies most with distance offshore. Exhibit 5-19 presents the proportion of each component calculated as an
average of those for each of the 10 input flow values ranging from 2,500 to 163,000 gallons per minute (gpm) for the shortest (20
meters) and longest (500 meters) submerged intake pipes in freshwater applications. Each component cost includes installation
costs and is discussed separately below.
Exhibit 5-19. Relative Proportion of Each Capital Cost Component for Freshwater Applications for Adding Screens to
Existing Submerged Intakes and Relocating Submerged Offshore for 20 Meters and 500 Meters Offshore
Relocate Passive Screens
Offshore Components
Screens
Backwash Equipment
Backwash Air Piping
Steel Pipe
Connecting Wall
Add to Existing Submerged Intake
20 Meters Offshore
64%
17%
20%
0%
0%
500 Meters Offshore
20%
6%
74%
0%
0%
Relocate Offshore
20 Meters
Offshore
29%
7%
9%
28%
27%
500 Meters
Offshore
6%
2%
24%
62%
6%
5-28
-------
§ 316(b) Phase IH - Technical Development Document Costing Methodology for Model Facilities
Screen Costs
The screen cost component includes the sum of the cost of the screens, installation, mobilization, and steel fittings. Installation and
mobilization can comprise from 80% of the screen costs for low flow operations to about 20% for high flow operations. The screen
costs were obtained from a vendor who reported that the accuracy of the screen costs as that of a detailed estimate (+15% to -5%)
(Whitaker 2004). The installation and mobilization costs are based on the BPJ application of vendor-provided cost estimates for
velocity caps. While the equipment costs were reported be relatively accurate, vendors of nearly all of the technologies have noted
that installation costs are much more variable and dependent on site-specific conditions making a "typical" estimate potentially less
accurate. As such, the installation and mobilization component costs (20% to 80% of total screen costs) should be viewed as having
the accuracy of a budget estimate.
Actual project screen costs were obtained for six-48 in. screens installed at the Zimmer Power Plant on the Ohio River. The
reported screen equipment cost when adjusted to 2002 dollars for inflation was $204,680. Comparable total screen costs using the
cost module component data was $190,000 for Cu Ni screens. In this example the actual screen costs were 8% higher than the
Module Cost and are well within the estimated accuracy range.
Backwash Equipment
The backwash equipment costs were also obtained from a vendor. This backwash equipment cost data came with the caveats that
"the Air Burst system is very custom, based upon distance from screen, multiple compressors, receiver size, controls, etc." Thus,
the accuracy of this cost component is difficult to quantify and the costs provided by the vendor should be viewed as having the
accuracy of a budget estimate since it included variation due to differences in equipment sizes.
Backwash Air Piping
The costs for backwash air piping is based on unit costs reported in RS Means Costworks 2001 for installed stainless steel pipe (in
an above ground application) multiplied by an underwater installation factor of 2 which was derived from looking at similar data for
the steel pipe installation costs. While the cost of materials for the stainless steel pipe should have the accuracy of a definitive
estimate, the installation factor was developed using BPJ and should be viewed as having the accuracy of a budget estimate.
Steel Pipe
The steel pipe costs were derived from the submerged steel pipe cost estimating methodology as described in Economic and
Engineering Analyses of the Proposed Section 316(b) New Facility Rule. Appendix A, but modified based on a design pipe velocity
of 5 feet per second. The pipe cost estimate is the result of a detailed engineering estimate and should have the accuracy of a budget
estimate. The actual methodology used in the installation of the manifold piping may differ from the method used in developing the
module costs.
The use of different pipe installation methods, however, does not necessarily indicate costs will vary widely. For example, a
comparison of the bid costs provided for installation (using a coffer dam in this instance) of a 220 meter 10 ft diameter steel pipe on
a submerged drinking water intake on the Potomac River for the Fairfax County Water Authority was $2,856,000 for the wining low
bid. The comparable Module component for a 250 meter pipe was $2,818,000. Note that the module pipe length was 14% greater
than the example, but the cost of the accepted bid was within nearly one percent of the cost predicted by the module. While the
installation method was different the costs were very similar.
Connecting Wall
The connecting wall design is based on the use of a sheet pile using sheet pile cost from RS Means. The primary independent
variable used to develop costs for different flow values was the cross-sectional area of the front of the intakes to be covered.
Several general assumptions were made that tended to bias the costs of this component upward, including assuming an existing
through screen velocity of 1.0 feet per second (whereas the median was around 1.5 feet per second) and a percent open area of 50%
(rather than 68% for "typical" coarse mesh screens cited by traveling screen vendors). The cost was developed using a detailed
engineering estimate and should have an accuracy of a budget estimate but biased somewhat on the high side.
Relocate to Submerged at Shoreline or Offshore
As described above the screen equipment costs have the greatest accuracy (approximately +15% to -10%) but this only comprises
20% to 80% of the installed screen cost which itself is 29% to 6% of the total capital cost depending on distance offshore.
5-29
-------
§ 316(b) Phase III - Technical Development Document
Costing Methodology for Model Facilities
Combined, the screen equipment costs component (accuracy of+15% to -10%) constitutes roughly 25% to 1.2% of the total capital
cost. The remaining components are considered as having an accuracy of a budget estimate (+30% to -15%). In addition, as noted
above several of the assumed engineering values were selected such that, on average, the capital costs would be biased towards the
high side.
Add to Existing Submerged Offshore
In this option the installed screen cost represent a greater portion of the total costs (64% to 20%) and therefore the total capital cost
will have a greater overall accuracy. Combined together, the screen equipment costs component (accuracy of+15% to -10%)
constitutes roughly 51% to 4% of the total capital cost. The remaining components are considered as having an accuracy of a
budget estimate (+30% to -15%). As with the relocate offshore option, the non-screen costs increase as the distance offshore
increases. In addition, as noted above several of the assumed engineering values were selected such that, on average, the capital
costs would be biased towards the high side.
Passive Screen O&M Costs
O&M Input Variables
The primary independent variable was the intake design flow. High and low debris was selected as a secondary variable to increase
confidence that the costs would be accurate for different environments. Distance offshore and saltwater versus freshwater were not
considered as additional sources of variation in O&M costs. However, freshwater and saltwater determinations did play a role in
designation of the debris level.
O&M Cost Components
O&M costs consist of labor, power requirements and periodic underwater inspection and cleaning. A high debris and low debris
option was developed for each scenario to increase the confidence of the estimates by accounting for the differences in backwash
frequency and underwater inspection and cleaning frequency that would be expected for waterbodies with higher and lower amounts
of debris. Costs for existing submerged intakes do not include any additional dive team costs above that which is already being
performed prior to the installation of the screens. Exhibit 5-20 presents the average proportion of each component over the range of
flow values costed for fine mesh screens. As can be seen the power cost component represents a very minor proportion and
therefore will not be discussed further.
Exhibit 5-20. Relative Proportion of Each O&M Cost Component for Freshwater Applications for Adding Screens to
Existing Submerged Intakes and Relocating Submerged Offshore
Relocate Passive Screens
Offshore O&M Component
Power
Labor
Dive Team Inspection &
Cleaning
Add to Existing Submerged Intake
Low Debris
1.6%
64%
35%
High Debris
4.5%
62%
33%
Relocate Offshore
Low Debris
2%
98%
0%
High Debris
5%
75%
20%
Labor
The O&M labor rate per hour is $41.10/hr. The rate is based on Bureau of Labor Statistics (BLS) Data using the median labor rates
for electrical equipment maintenance technical labor (SOC 49-2095) and managerial labor (SOC 11-1021); benefits and other
compensation are added using factors based on SIC 29 data for blue collar and white collar labor. The two values were combined
into a single rate assuming 90% technical labor and 10% managerial. This labor rate is fairly accurate being based on national
average BLS data and is used in other module O&M cost development as well. The number of hours applied is based on vendor
quotes of several hours per week with a notation that during certain periods some systems must be manned 24 hours/day for a week
or more during seasonal high debris. The selected rates of 2-4 hours per week plus one week at 24 hours per day for low debris or 3
weeks 24 hours per day for high debris are based on BPJ interpretation of the vendor supplied information for "typical" operations.
It is expected that the actual labor annual total will be quite variable. Therefore, while the labor dollar per hour rate is very accurate,
5-30
-------
S 316(b) Phase HI - Technical Development bocument Costing Methodology for Model Facilities
the labor hours are considered to have a moderate accuracy with a wide range resulting in the derived costs being that of a budget
estimate.
Dive Team Inspection and Cleaning
The dive team costs are based on a vendor quote for a supervisor, tender and diver, including equipment, boat, and
mobilization/demobilizations. Costs are calculated in single day increments. These costs should be considered as fairly accurate for
typical diver costs. However, as with the labor hourly requirements, the frequency and duration of the dive team requirements are
based on general vendor quotes with caveats that actual frequencies and durations may vary greatly from site to site. As such, the
dive team costs are considered as having an accuracy of a budget estimate.
Several facilities with submerged intakes were surveyed and annual underwater inspection and cleaning costs were reported by three
facilities, the total annual costs were $3,800, $10,000, and $30,000. The first value is below the minimum one day module dive
team cost of $5,260 (-28%) and the $30,000 value is greater than the high debris annual cost of $ 18,480 (+62%) for a comparable
flow. This reported range confirms that such costs do vary considerably on a site-specific basis. However, it does show that EPA's
estimates do represent a middle or "typical" value. Note that the higher value was for a facility experiencing zebra mussel problems
that may have not been designed to prevent this problem. The EPA module technology applied to such situations include higher up
front costs for screen materials (CuNi) that tend to inhibit mussel colonization.
Overall O&M
Considering the above discussion, the O&M costs for passive screens should be considered as having the accuracy a budget estimate
without any bias.
TRAVELING SCREENS
Cost Modules Covered:
• Module #1: Add Fish Handling and Return System
• Module #2: Add Fine Mesh Traveling Screens with Fish Handling and Return
• Module #11: Add Double-Entry, Single-Exit with Fine Mesh, Handling and Return
Based on the advise of traveling screen vendors, facilities receiving technology Module #1 received costs for replacement of the
traveling screen units as well as the addition of a fish return sluice. The alternative was to replace only the baskets and screens and
add fish spray equipment. This was based on vendor advise that a partial retrofit that would retain a portion of the original
equipment would cost approximately 75% of the cost of replacement units saving only about 25% but possibly compromising
system effectiveness and longevity. Thus, this was a conservative (high cost side) assumption that could offset future costs that
would be difficult to quantify. This increases the confidence in the O&M cost estimates for module #1 by eliminating any
uncertainty with regard to future performance and the need for corrective measures.
Facilities where module 2 was specified, received different costs depending on whether the data available indicated they a fish
handling and return system already in-place. If they did not, then the compliance costs included replacing the traveling screens as
well as adding a fish return sluice. If they did, then only the costs for adding fine mesh overlays applied. With the exception of
Module #3 (add new larger intake), the screen equipment size for traveling screens is limited to the size of the existing intake.
In general, the above approach increased confidence in the accuracy of the capital and O&M costs by tailoring the cost estimates to
the known technology in-place.
Traveling Screen Capital Costs
Input Variables
The cost of traveling screens are dependent on both the height (well depth) and width of screen unit. Screen cost data indicates that
two screens with the same effective screen area but with different size height and width will have different costs. To increase the
confidence in the cost estimates for this final rule applying to existing facilities, the design flow was combined with other data such
as intake water depth and through-screen velocity to determine the calculated total effective screen width of the existing intake
screens. Since the size of replacement screens is limited to the size of the existing intake structure, the estimated total screen width
was considered a much better variable for estimating screen equipment costs compared to design flow alone. For all facilities the
5-37
-------
§ 316(b) Phase HI - Technical Development Document
Costing Methodology for Model Facilities
percent open area (POA) of screens already in-place was assumed to be 68% which was identified by screen vendors as the
prevalent POA for coarse mesh screens. One vendor said that approximately 97% of existing intake screens use coarse mesh with
3/8 inch mesh upon which this value is based. Flow data and through-screen velocity data were available for most facilities, while
intake water depth was only available for detailed questionnaire facilities. Median values from the detailed questionnaire facility
data were assumed for those without data. Well depth was another important screen sizing variable. In order to simplify the effort
but still retain confidence in the costs over a range of sizes, costing scenarios for five different well depths were developed (10 feet,
25 feet, 50 feet, 75 feet, 100 feet). One of these five costing well depths was then applied to each facility based upon the actual or
calculated well depth. Calculated or actual intake well depths that exceeded approximately 20% greater than any category was
assigned to the next highest category. In general, this tended to bias this portion of costs slightly upward as the majority of those
falling in-between the well depth categories were costed for deeper wells. In many cases well depth data was available but if not,
the well depth was assumed to be 1.5 times intake water depth which was the median value for those facilities that had provided
both water and well depth data. Other variables include saltwater versus freshwater, which primarily affected screen costs due to
differences in material costs, and the presence of a canal or intake channel. Where a canal or intake channel was present, cost for
the added fish return flume length was added.
Capital Cost Components:
The total estimated capital costs for modifying and/or adding traveling screens consists of the following cost components:
Traveling Screens
Screen Installation
• Fine Mesh Overlays
• Spray Water Pumps
• Fish Flume
• Added Fish Flume Length for Those with Canals
Exhibit 5-21 presents the cost components and the percent of total cost of each component for a single 10 feet wide 25 feet deep
through-flow traveling screen. A 10 feet wide screen was selected as an example because it represents a commonly used standard
screen size and the 25 feet depth was selected based on the median values from the detailed data. Dual-flow screens would present
a similar cost mix as shown in Exhibit 5-21 but with slightly higher costs for the screen equipment component. Note that the
proportions given are for facilities without canals. For those with canals, the fish flume component would be a higher proportion
depending on the canal length.
Exhibit 5-21. Compliance Module Scenarios and Corresponding Cost Component Relative Proportions for 10 ft Wide and
25 ft Deep Screen Well
Compliance Action
Module 2 - Add Fine
Mesh Only
(Scenario A)
Cost Component Included
in EPA Cost Estimates
New Screen Unit
Screen Installation
Add Fine Mesh Screen
Overlay
Add Spray Water Pumps
Add Fish Flume
Existing Technology
Traveling Screens
Without Fish Return
. JNA /•:>;/, , >." -ff; -.;;-.W ,_ ?> -
;.N& .:.£" ./>-:vX > :'
NA •- - r -\ ''I,-'
,NA '"
NA
Traveling Screens With
Fish Return
0%
0%
100%
0%
0%
5-32
-------
§ 316(b) Phase III - Technical Development Document
Costing Methodology for Model Facilities
Exhibit 5-21. Compliance Module Scenarios and Corresponding Cost Component Relative Proportions for 10 ft Wide
and 25 ft Deep Screen Well (continued)
Compliance Action
Module 1 - Add Fish
Handling Only
(Scenario B)
Module 2 - Add Fine
Mesh With Fish Handling
(Scenario C and Dual-
Flow Traveling Screens)
Cost Component Included
in EPA Cost Estimates
New Screen Unit1
Screen Installation
Add Fine Mesh Screen
Overlay2
Add Spray Water Pumps
Add Fish Flume
New Screen Unit
Add Fine Mesh Screen
Overlay
Add Spray Water Pumps
Add Fish Flume
Existing Technology
Traveling Screens
Without Fish Return
Freshwater 67%
Saltwater 80%
Freshwater 14%
Saltwater 9%
0%
Freshwater 2%
Saltwater 1%
Freshwater 17%
Saltwater 10%
Freshwater 63%
Saltwater 74%
Freshwater 6%
Saltwater 7%
Freshwater 2%
Saltwater 1%
Freshwater 16%
Saltwater 9%
Traveling Screens With
Fish Return
NA
NA
NA », ,v. - , ,
•'^jffM^'^i-*'-.
4NJr:v^, ---<-• -
-m '..
NA
'''.jw£«-'« ' '*. •-•
NA '
1 Replace entire screen unit, includes one set of smooth top or fine mesh screen.
2 Add fine mesh includes costs for a separate set of overlay fine mesh screen panels that can be placed in front of coarser mesh
screens on a seasonal basis.
3 Does not include initial installation labor for fine mesh overlays. Seasonal deployment and removal of fine mesh overlays is
included in O&M costs.
Screen Equipment
As can be seen in Exhibit 5-21 the majority of the screen costs are for the screen units. Screen equipment costs were obtained from
vendors, one set for freshwater only in 1999 and one set for freshwater and saltwater in 2002. EPA found that the 2002 costs for
freshwater screens were about 10% to 30% less than the 1999 cost even after adjusting for inflation. The screen cost data were
reported by the vendors as "budget" level estimates (i.e.,+30% to -15%). EPA chose the higher 1999 costs (adjusted to 2001)
because they were most suited for application to the selected screen size scenarios and as a conservative (high cost side) approach.
The ratio of saltwater to freshwater screens from the 2002 data was used to derive corresponding saltwater screen costs. Thus, the
screen equipment costs for both freshwater and saltwater have an accuracy equivalent to budget level estimates and may be biased
on the high side by 10% to 30%.
Screen Installation Costs
Screen installation costs are much more variable than the equipment costs and can increase by 30% if screens must be installed in
sections due to overhead obstructions. Two vendors provided values that differed by about 50% but all noted that site-specific
situations made estimating "typical" installation costs was difficult. The installation costs were adjusted for screen size and selected
to span the range of costs cited. Thus, the installation costs should be considered as having the accuracy of a budget estimate.
5-33
-------
§ 316(b) Phase III - Technical development Document Costing Methodology for Model Facilities
Fine Mesh Overlays
Fine mesh overlays are calculated as a percent of screen costs. A vendor quoted that the cost would be 8 to 10% of the screen
equipment costs and EPA chose to use a 10% factor resulting in a slight bias on the high side. Otherwise these costs should have
the same accuracy as the cost of the screen equipment alone. The assumption of using fine mesh overlays rather than permanent
fine mesh screens for scenario C would be a conservative assumption for locations that do not have seasonal debris problems. This
assumption increases the confidence that the module would not underestimate costs where seasonal debris problems exist.
Spray Water Pump Costs
As show in Exhibit 5-13, the spray pump costs only contribute around 1% to 2% of the total costs and thus will not contribute
significantly to variations in the data accuracy. However, as noted in the O&M discussion below the estimated volume of spray
water has a significant effect on the O&M costs. Spray water pump costs are derived based on a vendor supplied water use factor
per ft of total screen width. Only the additional volume needed for the low pressure fish spray component is costed for additional
pumps. A range of 26.6 to 74.5 gpm/ft total flow was cited by vendors. Only one vendor gave a breakdown between the two
requirements as 17.4 gpm for debris and 20.2 for the fish spray. EPA chose a 30 gpm rate for the fish spray as a conservative (high
end) rate, which when compared to the single 20.2 gpm/ft example may bias the flow upward by nearly 50%. The pump equipment
and installation costs are based on flow and engineering unit costs for similar equipment and thus should be viewed as having the
accuracy of a budget estimate but biased towards the high side.
Fish Flume
The cost offish return flumes will vary with flow volume and length, and other site-specific factors. All facilities that did not
already have a fish return in-place received costs for a fish flume. The flumes are sized to return the entire flow generated (60 gpm/
ft screen width) which as noted above may be biased toward the high side. A screen vendor cited flume lengths of 75 feet to 150
feet and survey data for facilities without canals reported a length of 30 feet to 300 feet. EPA chose the high end of this range of
300 feet as a conservative estimate of a "typical" installation. Thus, the flume length chosen by EPA may be biased upward by up
to 100%. EPA notes that in some tidal applications two return flumes are used to ensure that the debris is deposited downstream
and this assumption ensures that such situations are accounted for.
For those facilities that reported the intake was at the end of a canal, an additional costs was added to account for the added distance
needed to reach the main waterbody. This additional length was set equal to the canal length and was an additional cost above the
300 feet length. Note that the 300 feet length provides for placement of the debris discharge away from the intake. Flume costs
include costs for PVC pipe and support pilings spaced at 10 ft. Costs for a 12 inch diameter PVC pipe were developed from RS
Means data and then converted to a rate of $10.15/ inch dia.-ft length including site work and indirect costs. Flume diameter was
calculated based on an assumed velocity when full of 1.5 feet per second. As such, the flume costs are based on engineering design
assumptions that are conservative (high side) for the "typical" site to increase confidence that this component will not be
underestimated. Therefore, the cost estimates should be viewed as having the accuracy of a budget estimate and may be biased
towards the high side.
Module 2 Scenario A
The relative accuracy of these cost estimates should be equal to that of the screen equipment (+30% to -15%) and the cost factor
(10%) which could be biased toward the high side by an additional 10% (the Agency used the 10% factor as opposed to the 9%
midpoint between 8% and 10%).
Module 1 Scenario B
The screen equipment costs which have an estimated accuracy of+30% to -15% accounts for 67% to 80% and may be biased
toward the high side by 10% to 30% for the example screen. The remaining components are considered as also having an accuracy
of a budget estimate and also may be biased toward the high side for spray water pumps and flume length.
Module 2 Scenario C
The screen equipment costs which have an estimated accuracy of+30% to -15% accounts for 63% to 74% of the costs and may be
biased toward the high side by 10% to 30% for the example screen. The remaining components are also considered as having an
accuracy of a budget estimate and also may be biased toward the high side for spray water pumps and flume length.
5-34
-------
§ 316(b) Phase HI - Technical Development Document Costing Methodology for Model Facilities
Module 11 Scenario C (Dual-flow)
The capital costs for dual-flow screens were developed by multiplying the through-flow screen total costs by factors recommended
by a vendor. Thus, the component proportions and relative accuracy should be similar to that for through-flow screens.
Traveling Screen O&M Costs
Baseline O&M Costs
O&M costs for facilities that have traveling screens in-place are calculated on a net basis. In other words a cost estimate is
calculated for the existing intake screens and then subtracted from the compliance technology O&M cost estimate. As such, there is
an additional O&M cost option for traveling screens without fish returns. In general, this option involves less operating time, no
extra fish spray pumping and as a result labor, power, and parts replacement costs (less wear and tear) are lower. All assumption for
this baseline option are based on vendor estimates of "typical" operations. In addition, the costs derived under Module 2 Scenario B
also served as the basis for baseline O&M costs for facilities with existing traveling screens with fish returns.
Net cost calculations were limited to facilities where the compliance technology was an upgraded version of the traveling screen
technology or where the existing traveling screen technology was being replaced in function and would no longer be required. An
example is where fine mesh passive screens replaced traveling screens. An example where baseline costs were not deducted is the
addition of fish barrier nets. The accuracy of the net O&M costs are therefore, a combination of the accuracies of the positive and
negative components. When deviations of the module results from the actual costs of both components (baseline and compliance)
have the same sign (+ or -), the differences will tend to cancel each other out somewhat. But when they have different signs, the
accuracy of the net value will be reduced.
For facilities with fixed screens or other non-traveling type screen technologies, no baseline costs were deducted because there was
no reliable way to estimate baseline O&M costs. This results in a bias toward the high side of net O&M costs for these facilities
since even for fixed screens there would be certain amount of labor associated with periodically inspecting and cleaning the screens.
O&M Input Variables
The O&M costs use the same input variables, total screen width, well depth and saltwater versus freshwater as the capital costs (see
discussion above).
O&M Cost Components
O&M costs consist of labor, power requirements, and parts replacement. Exhibit 5-22 presents the corresponding O&M cost
component relative proportions for 10 feet wide and 25 feet deep screen well.
5-35
-------
S 316(b) Phase III - Technical Development Document
Costing Methodology for Model Facilities
Exhibit 5-22. Compliance Module Scenarios and Corresponding O&M Cost Component Relative Proportions for 10 ft Wide
and 25 ft Deep Screen Well
Compliance Action
Module 2 - Add Fine
Mesh Only(First Column)
and Add Fine Mesh With
Fish Handling(Second
Column)
(Scenarios A and C)*
Module 1 - Add Fish
Handling Only
(Scenario B)
Cost Component Included
in EPA Cost Estimates
Basic Labor
Overlay Labor
Motor Power
Pump Power
Parts
Basic Labor
Overlay Labor
Motor Power
Pump Power
Parts
Existing Technology
Traveling Screens
Without Fish Return
Freshwater 35%
Saltwater 29%
Freshwater 15%
Saltwater 12%
Freshwater 2%
Saltwater 2%
Freshwater 30%
Saltwater 26%
Freshwater 18%
Saltwater 31%
Freshwater 41%
Saltwater 33%
0%
Freshwater 2%
Saltwater 2%
Freshwater36 %
Saltwater 29%
Freshwater 21%
Saltwater 35%
Traveling Screens With
Fish Return
Freshwater 35%
Saltwater 29%
Freshwater 15%
Saltwater 12%
Freshwater 2%
Saltwater 2%
Freshwater 30%
Saltwater 26%
Freshwater 18%
Saltwater 31%
NA
NA
:>%•• - , . v
-. - , '•- \ •
&»'-* ^ ;-..,- . .
I' ' -," '> ' „ ^" £
•NA :"-
* The O&M costs are assumed to be he same for compliance scenarios A and C but the net costs will be different for each since the
baseline technologies are different.
Basic Labor
A vendor provided general guidelines for estimating basic labor requirements for traveling screens as averaging 200 hours and
ranging from 100 to 300 hours per year per screen for coarse mesh screens without fish handling and double that for fine mesh
screens with fish handling (Sunda 2002a, 2002b). If the range shown represented a single screen size then the accuracy would be
roughly +50% to -50%, however a good portion of this variation in hours is related to intake size. Estimates for various screen sizes
were scaled to span these ranges. Thus, the accuracy of the basic labor cost estimates should be considered as having the accuracy
of a budget estimate because it included estimated hours. The hourly wage rate is fairly accurate as discussed under passive screens
above.
Overlay labor
Overlay labor is based on recommended screen change-out times per screen panel. The number of screen panels is very accurate for
each screen and so the accuracy of the labor estimate is associated with the accuracy of the estimated time for placing each screen
overlay and whether the annual frequency estimate of once per year was correct. As such, it is reasonable to consider the overlay
labor estimate as having an accuracy of a definitive estimate.
Motor and Pump Power
Power requirements for the motors comprises only 2% of the total and therefore will not be discussed. The spray water pump
requirements, however, could be significant. Several aspects of the pump power requirements tend to bias these costs upward. The
first as described in the pump capital costs above is that the flow rate chosen was somewhat biased toward the high side. Secondly,
5-36
-------
S 316(b) Phase HI - Technical Development Document Costing Methodology for Model Facilities
the pump power requirements are based on the entire flow being pumped to the high pressure needed for debris removal. If the low
pressure stream results from passing through a regulator from a high pressure pump then this is a valid assumption. However, if a
separate set of low and high pressure pumps are used, then this assumption will result in an overestimation of the pump energy and
therefore power requirements. As the flow requirements are based on engineering estimates, it is reasonable to consider the pump
power estimate as having the accuracy of a budget estimate but potentially biased toward the high side.
Parts replacement
These costs are based entirely on proportions of the screen equipment costs using rough estimates provided by a vendor. As such, it
is reasonable to consider the pump power estimate as having the accuracy of a budget estimate but potentially biased on the high
side since it is based on a factor multiplied by the screen equipment costs.
Overall O&M Costs for Through-flow Screens
In general, the Agency views the best way to quantify the accuracy of the components as being on the order of a conceptual estimate
with bias towards the high side for the components as noted.
Dual-flow Screens
The O&M costs for dual flow screens (Scenario C only) were calculated as a fixed proportion of through-flow screen costs reported
by a vendor as the typical values they have observed. As this factor itself is a rough estimate, the dual-flow screen O&M estimates
will reflect similar accuracies as the through-flow screens.
LARGER INTAKES
Cost Module Covered:
• Module #3: Add New Larger Intake Structure with Fine Mesh, Handling and Return
Larger Intake Capital Costs
Input Variables
In this case the independent variable was the estimated "compliance total screen width" which was calculated in a similar manner as
the baseline total screen width used in the traveling screen cost estimates. As with the traveling screens, use of screen sizes, rather
than flow alone, increases the confidence in the accuracy of the estimates. Differences in calculating the compliance screen width
include using a through-screen velocity of 1.0 feet per second (instead of the actual velocity or data median of 1.5 feet per second
that was used for the baseline) and a percent open area (POA) of 50% instead of 68% that was used for baseline total screen width.
The 50% POA is consistent with use of fine mesh screens. In this case the independent variable may be biased toward the low side
if facilities select a lower through-screen velocity than 1.0 feet per second. This same independent variable was used for estimating
the capital and O&M costs for dual-flow traveling screens installed in the new larger intake.
Overall Accuracy
The new larger intake costs are based on a detailed engineering estimate of costs for a larger intake located just in front of the
existing intake. A review of the construction components, component quantities and indirect costs does not indicate any items that
may have been estimated in a way that would tend to bias the cost estimates either high or lower. Unit costs are based on costs
reported in RS Means Costworks 2001. Considering the detailed nature of the estimation method, the cost estimate should be
viewed as having the accuracy of a budget estimate.
Larger Intake O&M Costs
No separate O&M costs were derived for the structure itself since the majority of the O&M activities are covered in the O&M costs
for the traveling screens to be installed in the new structure.
5-37
-------
§ 316(b) Phase III - Technical Development Document Costing Methodology for Model Facilities
FISH BARRIER NETS
Cost Module Covered:
Module #5: Add Fish Barrier Net
Barrier Net Capital Costs
Input Variables
In this case the independent variable was the design intake flow. A secondary variable was freshwater versus saltwater. Water
depth was considered in the development of saltwater barrier nets but a single depth close to the median value reported by facilities
was used in the application. Different support and anchor strategies were used in freshwater and saltwater. These different
approaches to freshwater and saltwater applications increases the confidence in the cost estimates by accounting for differences in
design due to the presence of tidal currents in saltwater environments. Research indicated that nets are designed on a site-specific
basis and that limited engineering guidelines to follow exist. Therefore, the barrier net costs are based on design and cost data from
two facilities with barrier nets that had similar net velocities. The estimates were not just simple scaled costs but rather an
evaluation of each cost component was performed and then scaled for different sizes. Barrier net costs are primarily based on the
required net size and support structures/equipment. Two facilities, one on a lake and another on an estuary, reported essentially the
same velocity of 0.06 feet per second. Lacking more detailed engineering guidelines, use of actual reported net velocities was
determined to be the best method to develop relatively accurate net costs.
Freshwater Barrier Nets (Scenario A)
Net costs are based on the unit costs in dollars/sq ft for both the installed net and a back-up replacement for the example facility.
The freshwater unit costs include costs for shipping, floats and anchors. The freshwater facility cost data indicated that the unit
costs used may be biased slightly toward the high side if shallower nets are used (e.g., 10 feet or less). The example facility had a
net depth of 20 feet. The total reported installation cost was split into a fixed component of 20% (based on BPJ) and a variable
dollar/sq ft component. While this module will provide a definitive estimate quality estimates of the net costs at facilities similar to
the example facilities, the fact that there are limited guidelines indicates that actual designs may vary considerably tending to temper
the accuracy of this module to an accuracy of a conceptual design estimate.
Saltwater Barrier Nets (Scenario B^
In this scenario, net costs are based on using two concentric nets, supported on pilings as is the case with the example facility. The
costs for the nets are base on the costs cited by both the facility and its supplier. Costs for the pilings are based on engineering
design using the 20 feet spacing at the example facility and RS Means unit costs for barge driven piles. Costs were derived for
depths of 10 feet, 20 feet, and 30 feet. However, in developing the compliance cost estimates, only the 20 feet depth was used. In
the case of this saltwater net design, shallower depths will tend to drive costs upward due to the requirement for more pilings.
While this module will provide definitive estimate quality estimates of the net costs at facilities similar to the example facilities, the
fact that there are no guidelines indicates that actual designs may vary considerably tending to temper the accuracy of this module to
an accuracy of a conceptual design estimate.
Barrier Net O&M Costs
Input Variables
O&M costs use the same independent variables as capital costs. Duration of deployment was also considered.
Freshwater Barrier Nets
The O&M costs are based on reported labor requirements and net replacement rates. The period of deployment is also important.
The example facility reported a deployment period of 120 but others reported longer periods. EPA chose to base the costs on a
deployment period of 240 days as a conservative (high side) estimate. EPA scaled up the labor hours cited by the facility and added
an additional net section replacement step. Costs for the example facility were developed and then converted to a straight line cost
curve by assuming 20% of costs were fixed. While this module will provide a definitive estimate quality estimates of the net O&M
costs at facilities similar to the example facilities, as with the O&M costs, the fact that there are no guidelines indicates that actual
5-38
-------
S 316(b) Phase III - Technical Development Document Costing Methodology for Model Facilities
operations may vary considerably tending to temper the accuracy of this module to an accuracy of a budget estimate with a
potentially biased toward the high side.
EPA notes that other O&M costs reported in literature are often less than what results from the cost module. For example, 1985
O&M cost estimates for the JP Pulliam plant ($7,500/year, adjusted to 2002 dollars) calculate to $11,800 (compared to $57,000 for
the example facility) for a design flow roughly half that of example facility. This suggests the scenario A estimates represent the
high end of the range of freshwater barrier net O&M costs (biased upward as noted above). Other O&M estimates that also were
lower, however, do not describe the cost components that are included and can not be used for comparison since they may not
represent all cost components.
Saltwater Barrier Nets
The saltwater barrier net O&M costs are based on the net maintenance contractor costs plus replacement net costs. Nearly all of the
O&M labor for Chalk Point facility is performed by a marine contractor who charges $1,400 per job to simultaneously remove the
existing net and replace it with a cleaned net. The reported annual job frequency was used along with the reported net replacement
rate. As with the capital costs, while this module will provide a accuracy of a definitive estimate at the example facility, the fact that
actual designs may vary considerably indicates that the accuracy of this module can be considered as having the accuracy of a
budget estimate
VELOCITY CAPS
Cost Module Covered:
• Module #8: Add Velocity Cap at Submerged Inlet
EPA identified only one vendor that supplied preconstructed velocity caps. This appears to be primarily due the fact that, for many
installations, velocity caps are custom designed and constructed.
Velocity Cap Capital Costs
Input Variables
The primary input variable was design intake flow. Freshwater versus saltwater was an additional variable that affected equipment
costs.
Capital Cost Components:
Capital costs consist of equipment, installation, and mobilization/demobilization. For higher flows, multiple heads are used with the
costs including inlet piping modifications. The saltwater/freshwater differences are due to use of different materials. The vendor
was very confident about the equipment, installation, and mobilization/demobilization costs as they had performed numerous recent
jobs. The mobilization/demobilization costs were reported as a range of $15,000 to $30,000. This was applied such that the range
spanned the range of flow rates costed.
The proportion of the total for equipment costs ranged from 39% for a 5,000 gpm freshwater intake to 71% for a 350,000 gpm
freshwater intake and were roughly 7% less for saltwater. Due to the apparent limited number of prefabricated cap suppliers and the
confidence expressed by the vendor the equipment portion should be considered as having an accuracy of a definitive estimate and
the remainder having an accuracy of a budget estimate. This estimate of accuracy should be limited to the use of prefabricated
velocity caps. As noted above many are custom designed built onsite and in those instances costs may vary considerably. This will
tend to temper the accuracy of this module to an accuracy somewhere between a budget and a conceptual estimate when multiple
methods of construction are considered.
Velocity Cap O&M Costs
Input Variables
The primary input variable was design intake flow. Freshwater versus saltwater was not considered as significant source of valiance
in the O&M costs.
5-39
-------
§ 316(b) Phase III - Technical Development Document Costing Methodology for Model Facilities
O&M Cost Components
Since this was a passive technology, O&M costs were limited to periodic inspection and cleaning by a dive team. The same per day
dive team costs that were applied to the passive screen O&M costs are applied to the velocity cap O&M costs. As such, the dive
team costs are considered as fairly accurate but the duration and frequency estimates are considered as less accurate resulting in an
overall accuracy of a budget estimate.
AQUATIC FILTER BARRIERS
Cost Module Covered:
• Module #6: Add Aquatic Filter Barrier Net (Gunderboom)
Currently only one vendor (Gunderboom Inc.) is available to design install this technology. The technology has been demonstrated
but is still somewhat in the developmental stage.
Aquatic Filter Barrier Capital Costs
Input Variables
Design intake flow was the primary variable.
Capital Costs
The cost data was provided for three flow values by the vendor in 1999 prior to any full scale installations. Three different capital
costs representing low, average and high costs were provided. These costs have been adjusted for inflation. The average costs were
selected to served as the basis for compliance costs for this module. No updated costs based on recent experience were made
available. Given the lack of recent experience input the cost estimates should be considered as having an accuracy somewhere
between a budget ands a conceptual estimate. Also note that additional filter fabric grades with different (mostly larger) pore sizes
are now available. An increase in pore size can reduce the lateral forces acting on the barrier resulting in the ability to reduce the
required barrier total effective area. This in turn can result in reduced costs.
The vendor recently provided a total capital cost estimate of 8 to 10 million dollars for full scale MLES™ system at the Arthur Kill
Power Station in Staten Island, NY. The vendor is in the process of conducting a pilot study with an estimated cost of $750,000.
The NYDEC reported the permitted cooling water flow rate for the Arthur Kill facility as 713 mgd or 495,000 gpm. Applying the
cost equations results in a total capital cost of $8.7, $10.1 and $12.4 million dollars for low, average and high costs, respectively.
These data indicate that the inflation adjusted cost for an average cost estimate in this application are within the accuracy range of a
budget estimate. However, the cost estimates provided by Gunderboom are themselves estimates and may or may not accurately
reflect project costs after completion. The vendor estimate for this project do however, indicate the vendors confidence in the
module estimates at least in this flow range. The vendor had expressed a concern that for low flow applications the module costs
may be too high. The range of module results (low and high) shown for the above example are consistent with budget estimate
accuracy when compared to the average.
O&M Costs
Input Variables
Design intake flow was the primary variable.
O&M Costs
O&M costs are for the operation of the airburst system and fabric curtain maintenance. The cost estimates were obtained in a
similar manner as the capital costs but in this case there was no recent corroboration of the original estimates. The range between
the low, average, and high cost estimates indicate that the average O&M cost estimates should be considered as having an accuracy
of a conceptual estimate and the cost estimates may be somewhat more accurate for higher flows.
5-40
-------
S 316(b) Phase III - Technical Development Document
Costing Methodology for Model Facilities
5.0 FACILITY DOWNTIME ESTIMATES
In addition to the capital and annual operating and maintenance costs of the selected technology module, approximately 15%
existing Phase III facilities will incur downtime costs. The basic approach to estimating downtime costs uses the same data and
methodology used in the Phase II rulemaking (see the final Phase II Development Document). Downtime costs generally reflect
decreased revenues due to lost production, or costs of supplemental power purchases incurred during the retrofit of existing cooling
water intake structures. The length of downtime, when incurred, is a function of which technology is being retrofitted and the size
of the intakes. Exhibit 5-23 provides this downtime in weeks. Facilities assigned technology modules 3,4,7,12, or 14 were
assessed downtime, except for four unique facilities as described below.
Exhibit S-23. Weeks of Downtime Included in Costs of Technology Modules
Technology Module Description
New, larger intake with fine-mesh and fish
handling and return system (module 3)
Addition of passive fine-mesh screen
(modules 4 and 12)
Relocation to a submerged offshore location
with passive fine-mesh screen (module 7)
Relocation of coastal to a submerged offshore
location with passive fine-mesh screen
(module 14)
Downtime in Weeks
DIF<576MGD
2 weeks
9 weeks
9 weeks
9 weeks
DIP between 576 MGD
and 1152 MGD
3 weeks
10 weeks
10 weeks
10 weeks
DIF> 1152 MGD
4 weeks
1 1 weeks
10 weeks
1 1 weeks
Based on a review of the detailed technical surveys submitted by potential Phase III facilities, EPA has determined 7 facilities have
more than a 50 MGD design intake flow and have multiple intakes. EPA examined flow diagrams and facility-level survey data
describing the function of each intake, such as whether the intakes are dedicated intakes, or whether an intake has a small design
intake flow and is labeled for non-routine use such as emergency back-up or fire suppression. EPA has concluded 4 of these
facilities have multiple intakes where the intakes are not dedicated intakes. In other words, these four facilities could shut off any
one intake and still meet their average intake flow without exceeding the total design intake flow of the remaining intakes.
Furthermore, these facilities all have shoreline intakes (technology module 4), negating the need to maintain costly offshore
equipment for the longer period of time necessary when conducting a retrofit one intake at a time. EPA assumes these four facilities
with shoreline intakes could retrofit one intake at a time, thereby avoiding downtime costs. The retrofit costs for these four facilities
still includes capital costs, equipment mobilization, labor, and contingency.
The average downtime costs for potential Phase III facilities is $10,650 per MGD of design intake flow. In Phase II, 18% of
facilities incurred average downtime costs of $882 per MGD of design intake flow. The downtime cost (in dollars) varies for each
individual facility; see the EA for more information.
5-41
-------
S 316(b) Phase HI - Technical Development Document Costing Methodology for Model Facilities
REFERENCES
AACE. American Association of Cost Engineers. Certification Study Guide. AACE International. 1996.
EPA. 2001. Phase I Notice of Data Availability (NODA), 66 CFR 28858, including DCNs 2-015A through G.
Sunda, J., SAIC. 2002a. Telephone contact with T. Gathright, Bracket Green, re: estimates for traveling screen O&M costs.
September 10, 2002. DCN 5-2513.
Sunda, J., SAIC. 2002b. Telephone contact with T. Gathright, Bracket Green, re: answers to questions about traveling screens.
September 11, 2002. DCN 5-2516.
Whitaker, J. Hendrick Screens. Telephone contact report with John Sunda, SAIC regarding accuracy of Passive Screen Costs.
February 3, 2004.
5-42
-------
§ 316(b) Phase III - Technical Development Document Impingement Mortality and Entrapment Reduction Estimates
Chapter 6: Impingement Mortality and Entrainment Reduction
Estimates
INTRODUCTION
In order to quantify the benefits derived from compliance with the proposed rule, estimates of the reduction in impingement mortality
and entrainment for each facility must be calculated. This process is described in this chapter. A detailed example is included in
Appendix 6A.
1.0 REQUIRED INFORMATION
The process of determining the estimated reduction in impingement mortality and entrainment as a result of the proposed rule
(sometimes referred to as "benefits reduction") requires two components: 1) the results of the costing exercise and 2) a description of
the regulatory options.
The costing exercise determines the costs for each facility to comply with the rule. This process is further described in the Economic
and Benefit Analysis document. As a result of this exercise, specific performance standards are determined for each facility (based on
the requirements of the rule) and a technology module is assigned to each facility (to meet those performance standards). Performance
standards will either be "impingement mortality only" or "impingement mortality and entrainment," depending on what is required of
the facility. One of 13 technology modules is then assigned to simulate the facility installing additional technology(ies) to meet the
performance standards. If a facility is shown to already meet the performance standards, then no technology module is assigned.
The second piece of necessary information is a description of the regulatory options. In preparing the proposed rale, EPA analyzes
several options for compliance. Under each option, a given facility may have different requirements. For more detail on the options
considered by EPA for the proposed rale, see the preamble for today's rale.
2.0 ASSIGNING A REDUCTION
Once a compliance response has been determined for each facility, the benefit derived by installing a new technology can be assigned.
The first step in calculating the benefits is to assign a reduction in impingement mortality and/or entrainment that is a direct result of
compliance with the rale. As discussed in Chapter 4, impingement mortality and entrainment rates can be reduced by 80% and 60%
respectively by installing new technology(ies). Once the impingement mortality and entrainment reduction has been determined, this
information is used in calculating the benefits associated with a facility's compliance with the regulation. For details on the process of
calculating the benefits associated with these reductions, see the Regional Benefit Assessment.
Assigning reductions in impingement mortality or entrainment to a facility depends on what reductions are required by the proposed
rale and the technology module applied to the facility. In general, the process is to 1) determine what performance standards are
required (impingement mortality only or impingement mortality and entrainment), 2) determine if the facility already meets either the
impingement mortality or entrainment standards (via existing intake technologies), and 3) assign the appropriate reduction1 of 80% or
0% (for impingement mortality) and 60% or 0% (for entrainment). For example, if a facility is required to meet impingement mortality
standards and has no suitable technology to fulfill the requirements, a technology module will be assigned. The "new" technology will
reduce the impingement mortality at the facility by the standard reduction of 80% (and possibly reduce entrainment as well).
On a larger scale, one can assign impingement mortality and entrainment reductions to the entire set of facilities in a few steps. This
process is an exercise in sorting the data set by the appropriate data field and assigning a reduction based on what is required of the
facility. Usually, the first data field by which to sort is the cost module that is applied to a facility. For facilities with no requirements,
no compliance action is required by the facility and no benefit reductions (0% reduction for both impingement mortality and
entrainment) are assigned to all of these facilities. Subsequent sort terms may include waterbody type, design intake flow, and the
reduction requirements for a facility. For example, if all facilities with a design intake flow of less than 50 MOD located on a
1 The I&E reductions assigned to a facility are a fixed value-80% for impingement mortality and/or 60%
for entrainment. These values represent the lower end of the performance ranges (80 to 95% for impingement
mortality and 60 to 80% for entrainment) established by EPA.
6-1
-------
§ 316(b) Phase III - Technical Development Document Impingement Mortality and Entrainment Reduction Estimates
freshwater lake have only impingement mortality requirements, then these data fields can be used to identify all such facilities and the
appropriate benefit reduction can be assigned to the entire set.
Again, the process is largely an exercise in sorting the data according to the data elements required to interpret and implement the
regulatory option. Once the data is sorted, reductions are assigned accordingly with the reductions required from the costing exercise.
Appendix A to this chapter contains a more detailed, step-by-step description of the entire process.
3.0 CONSIDERATIONS
The process of assigning impingement mortality and entrainment reductions carries several considerations, assumptions, and caveats.
1) A facility may qualify for "incidental benefits." If a facility has only impingement mortality compliance requirements but is
assigned a cost module that corresponds to a technology that reduces both impingement mortality and entrainment, the incidental (or
"extra") benefits are also assigned to the facility. Even though the reduction in entrainment is not explicitly required by the
requirements for the given facility, site characteristics may dictate that a technology designed to reduce only impingement mortality
may be impractical or less cost-efficient. In these cases, a technology designed to reduce both impingement mortality and entrainment
may be assigned. Both the facility-level costs and benefits reflect this change.
2) Facilities that are to be regulated under best professional judgment (BPJ) under a given regulatory option are not assigned a
reduction to impingement mortality or entrainment in this exercise, as there is no compliance action as a result of any national
requirements. EPA does not, however, intend for these facilities to be exempt from any/all requirements as determined by the Director
on a facility-specific basis.
3) EPA also conducted a sensitivity analysis by examining an adaptive management option. As stated above, any facility that is to be
regulated under best professional judgment (BPJ) is not assigned a reduction in impingement mortality or entrainment. However,
under the two adaptive management options, a facility regulated under BPJ is assigned a 5% or 15% reduction to both impingement
mortality and entrainment reductions. EPA selected 5% and 15% reductions to reflect a reasonable estimate of the reductions
attainable through optimization and proper operation and maintenance (O&M) of existing technologies by these facilities.
Under the co-proposed 50 MGD option, 262 facilities (of a total of 348 facilities) were assigned a reduction as a result of adaptive
management (5% in one option, 15% in the second). When the 5% increase in the efficacy of operation and maintenance at these
facilities is applied, the total national reduction in age 1 equivalent impingement and entrainment would increase by approximately
1.25%. For the 15% increase in efficacy, the reduction in age 1 equivalents would increase by approximately 3.8%.
6-2
-------
S 316(b) Phase III - Technical Development Document
Appendix 6A
Appendix 6A: Detailed Description of Impingement Mortality and
Entrainment Reduction Estimates
INTRODUCTION
This appendix supplements Chapter 6 by providing a more detailed, step-by-step description of the process used to assign
impingement mortality and entrainment reductions. This appendix uses a set of 10 fictional facilities with a variety of requirements,
intake technologies, design intake flows (DIP), and waterbody types.
1.0 REQUIRED INFORMATION
1.1 Technology Costing Information
The technology costing exercise produces the first of the necessary components by determining what requirements are to be applied to
each facility and assigning a technology module to meet those requirements. These results are used to determine both the facility-level
costs and the facility-level benefits associated with compliance. These results are shown in Exhibit 6A-1 below.
Exhibit 6A-1. Results of Technology Costing
Facility
ID
1
2
3
4
5
6
7
8
9
10
Waterbody
Type
Freshwater
River
Freshwater
River
Freshwater
River
Estuary/
Tidal River
Freshwater
River
Freshwater
River
Great Lakes
Great Lakes
Lake/
Reservoir
Great Lakes
DIF
(MGD)
10
8
11
113
73
126
17
88
8
22
Perf.
Standards
Required
I&E
I only
I only
I&E
I&E
I only
I&E
I only
I only
I only
Meets
Imp.
Standard?
TRUE
FALSE
TRUE
TRUE
FALSE
TRUE
TRUE
TRUE
TRUE
FALSE
Meets
Ent.
Standard?
FALSE
TRUE
TRUE
TRUE
FALSE
TRUE
FALSE
TRUE
TRUE
TRUE
No New
Tech.
Needed?
FALSE
FALSE
TRUE
TRUE
FALSE
TRUE
FALSE
TRUE
TRUE
FALSE
Tech.
Cost
Module
4
1
0
0
2a
0
3
0
0
9
Incidental
Benefit?
NO
NO
NO
NO
NO
NO
NO
NO
NO
YES
Imp.
Reduction
Ent.
Reduction
Description of the Data Fields
Facility ID: Unique identifier.
Waterbody Type: Type of waterbody upon which the facility is located.
Design Intake Flow: Design intake flow for the facility.
Performance Standards Required: Under the requirements of the proposed rule, what performance standards is the facility required
to meet? Note that this is irrespective of what technologies may already be in place at a facility.
Meets Impingement Standard: Does the facility qualify as having met the requirements for impingement? This may be accomplished
by existing technologies, closed-cycle cooling, or a low intake velocity (less than 0.5 feet per second).
6A-1
-------
§ 316(b) Phase III - Technical Development Document Appendix 6A
Meets Entrapment Standard: Does the facility qualify as having met the requirements for entrainment? This may be accomplished
by existing technologies or closed-cycle cooling.
No New Technology Needed: Based on the performance standards the facility is required to meet and the existing technologies, will
the facility be required to install any new technologies to meet the standards?
Technology Cost Module: The technology module assigned by EPA to the facility in order to comply with the rule. (This does not
necessarily reflect the technology the facility may ultimately install. See Chapter 5 in this Technical Development Document for more
details.)
Incidental Benefit: If a facility has only impingement compliance requirements but is assigned a cost module that corresponds to a
technology that reduces both impingement mortality and entrainment, the incidental (or "extra") benefits are also assigned to the
facility. See section 6 in this Technical Development Document for more details.
Impingement Reduction: The reduction in impingement mortality assigned to a facility as a result of compliance with the proposed
rule.
Entrainment Reduction: The reduction in entrainment assigned to a facility as a result of compliance with the proposed rule.
1.2 Regulatory Options Considered
The second component is a description of the regulatory options considered. Interpretation of these options will guide the process of
assigning impingement mortality and entrainment reductions.
Option 1: Facilities with a design intake flow of 20 MOD or greater would be subject to the performance standards and compliance
alternatives proposed in today's rule and discussed above. Under this option, section 316(b) requirements Phase III facilities with a
design intake flow of less than 20 MOD would be established on a case-by-case, best professional judgment, basis.
Option 2: Facilities with a design intake flow of 50 MOD or greater, as well as facilities with a design intake flow between 20 and 50
MOD (20 MOD inclusive) when located on estuaries, oceans, or the Great Lakes would be subject to the performance standards and
compliance alternatives proposed in today's rule. Facilities with a design intake flow between 20 and 50 MOD (20 MGD inclusive)
that withdraw from freshwater rivers and lakes would have to meet the performance standards for impingement only and not for
entrainment. Under this option, section 316(b) requirements for Phase III facilities with a design intake flow of less than 20 MGD
would be established on a case-by-case, best professional judgment, basis.
Option 3: Facilities with a design intake flow of 50 MGD or greater would be subject to the performance standards and compliance
alternatives proposed in today's rule. Facilities with a design intake flow between 20 and 50 MGD (20 MGD inclusive) would have to
meet the performance standards for impingement only and not for entrainment. Under this option, section 316(b) requirements for
Phase III facilities with a design intake flow of less than 20 MGD would be established on a case-by-case, best professional judgment,
basis.
Option 4: Facilities with a design intake flow of 50 MGD or greater, as well as facilities with a design intake flow between 20 and 50
MGD (20 MGD inclusive) when located on estuaries, oceans, or the Great Lakes would be subject to the performance standards and
compliance alternatives proposed in today's rule and discussed above. Facilities that withdraw from freshwater rivers and lakes and all
facilities with a design intake flow of less than 20 MGD would have requirements established on a case-by-case, best professional
judgment, basis.
Option 5 (Co-proposed Option): Facilities with a design intake flow of 50 MGD or greater would be subject to the performance
standards and compliance alternatives proposed in today's rule and discussed above. Under this option, section 316(b) requirements
for Phase III facilities with a design intake flow of less than 50 MGD would be established on a case-by-case, best professional
judgment, basis.
Option 6: Facilities with a design intake flow of greater than 2 MGD would be subject to the proposed performance standards and
compliance alternatives. Under this option, section 316(b) requirements for Phase III facilities with a design intake flow of 2 MGD or
less would be established on a case-by-case, best professional judgment, basis.
Option 7: Facilities with a design intake flow of 50 MGD or greater would be subject to the performance standards and compliance
alternatives proposed in today's rule and discussed above. Facilities with a design intake flow between 30 and 50 MGD (30 MGD
inclusive) would have to meet the performance standards for impingement only and not for entrainment. Under this option, section
316(b) requirements for Phase III facilities with a design intake flow of less than 30 MGD would be established on a case-by-case,
best professional judgment, basis.
6A-2
-------
S 316(b) Phase III - Technical Development Document
Appendix 6A
Option 8 (Co-proposed Option): Facilities with a design intake flow of 200 MGD or greater would be subject to the performance
standards and compliance alternatives proposed in today's rule and discussed above. Under this option,,section 316(b) requirements
for Phase III facilities with a design intake flow of less than 200 MGD would be established on a case-by-case, best professional
judgment, basis.
Option 9 (Co-proposed Option): Facilities with a design intake flow of 100 MGD or greater and located on oceans, estuaries, and the
Great Lakes would be subject to the performance standards and compliance alternatives proposed in today's rule and discussed above.
Under this regulatory option, section 316(b) requirements for Phase III facilities with a design intake flow of less than 100 MGD
would be established on a case-by-case, best professional judgment, basis.
2.0
ASSIGNING A THRESHOLD
As described in Chapter 6, assigning the reductions is essentially an exercise in interpreting the compliance alternative and
categorizing facilities by the appropriate data field. Several examples will be used to illustrate this process.
2.1 Facilities With No Requirements
Assigning a 0% reduction for both impingement mortality and entrainment to those facilities that are not required to add any new
technologies is often the simplest first step. In this case, sort the data by the "No New Technology Needed" or the "Technology Cost
Module" field and assign a 0% / 0% for each facility with a "TRUE" or a "0" as the assigned technology cost module. In other words,
a facility with no new technology (a 0 module) is assigned no reduction for impingement mortality or entrainment. Section 2.2 will
begin to address assigning reductions to facilities with non-zero requirements (those with no reductions in the table below).
Exhibit 6A-2. Assigning Zero Reductions
Facility
ID
3
4
6
8
9
1
2
5
7
10
Waterbody
Type
Freshwater
River
Estuary/
Tidal River
Freshwater
River
Great Lakes
Lake/
Reservoir
Freshwater
River
Freshwater
River
Freshwater
River
Great Lakes
Great Lakes
DIP
(MGD)
11
113
126
88
8
10
8
73
17
22
Perf.
Standards
Required
I only
I&E
I only
I only
I only
I&E
I only
I&E
I&E
I only
Meets
Imp.
Standard?
TRUE
TRUE
TRUE
TRUE
TRUE
TRUE
FALSE
FALSE
TRUE
FALSE
Meets
Ent.
Standard?
TRUE
TRUE
TRUE
TRUE
TRUE
FALSE
TRUE
FALSE
FALSE
TRUE
No New
Tech.
Needed?
TRUE
TRUE
TRUE
TRUE
TRUE
FALSE
FALSE
FALSE
FALSE
FALSE
Tech.
Cost
Module
0
0
0
0
0
4
1
2a
3
9
Incidental
Benefit?
NO
NO
NO
NO
NO
NO
NO
NO
NO
YES
Imp.
Reduction
0%
0%
0%
0%
0%
Ent.
Reduction
0%
0%
0%
0%
0%
2.2 Example of A Co-Proposed Threshold (Option 5)
The co-proposed 50 MGD option is relatively straightforward to interpret and assign impingement mortality and entrainment
reductions. Beginning with the data from section 2.1 above, sort the remaining facilities by the design intake flow, as it is the primary
criterion for the proposed option. Since only Facility 5 falls above the 50 MGD threshold, it is the only facility for which a reduction
6A-3
-------
§ 316(b) Phase III - Technical Development Document
Appendix 6A
will be assigned. Under the proposed rule, Facility 5 is required to meet both impingement mortality and entrainment requirements
and it does not meet either standard. Therefore, it will install a new technology to meet both performance standards. As a result,
impingement mortality and entrainment will be reduced by the introduction of this new technology and the standard reduction (80% /
60%) is assigned.
Facilities 2,1, 7 and 10 fall below the 50 MOD threshold and would be regulated on a best professional judgment basis. Since these
facilities may not install any new technologies to comply with the rule, it is assumed they will not be assigned a reduction.
Exhibit 6A-3. Assigning Reductions Under Option S
Facility
ID
3
4
6
8
9
2
1
7
10
5
Waterbody
Type
Freshwater
River
Estuary/
Tidal River
Freshwater
River
Great Lakes
Lake/
Reservoir
Freshwater
River
Freshwater
River
Great Lakes
Great Lakes
Freshwater
River
DIF
(MOD)
11
113
126
88
8
8
10
17
22
73
Perf.
Standards
Required
I only
I&E
1 only
I only
I only
I only
I&E
I&E
I only
I&E
Meets
Imp.
Standard?
TRUE
TRUE
TRUE
TRUE
TRUE
FALSE
TRUE
TRUE
FALSE
FALSE
Meets
Ent.
Standard?
TRUE
TRUE
TRUE
TRUE
TRUE
TRUE
FALSE
FALSE
TRUE
FALSE
No New
Tech.
Needed?
TRUE
TRUE
TRUE
TRUE
TRUE
FALSE
FALSE
FALSE
FALSE
FALSE
Tech.
Cost
Module
0
0
0
0
0
1
4
3
9
2a
Incidental
Benefit?
NO
NO
NO
NO
NO
NO
NO
NO
YES
NO
Imp.
Reduction
0%
0%
0%
0%
0%
0% (BPJ)
0% (BPJ)
0% (BPJ)
0% (BPJ)
80%
Ent.
Reduction
0%
0%
0%
0%
0%
0% (BPJ)
0% (BPJ)
0% (BPJ)
0% (BPJ)
60%
The benefit reductions for the example co-proposed option are now complete.
2.2.1 Adaptive Management
As an illustration of the adaptive management sensitivity analysis noted in Chapter 6 of this Technical Development Document, the
data from section 2.2 would appear as follows in a scenario where facilities regulated by best professional judgment are assigned a 5%
reduction for impingement mortality and entrainment.
6A-4
-------
§ 316(b) Phase III - Technical Development Document
Appendix 6A
Exhibit 6A-4. Assigning Reductions Under the Proposed Option, with 5% Adaptive Management
Facility
ID
3
4
6
8
9
2
1
7
10
5
Waterbody
Type
Freshwater
River
Estuary/
Tidal River
Freshwater
River
Great Lakes
Lake/
Reservoir
Freshwater
River
Freshwater
River
Great Lakes
Great Lakes
Freshwater
River
DIP
(MOD)
11
113
126
88
8
8
10
17
22
73
Perf.
Standards
Required
I only
I&E
I only
I only
I only
I only
I&E
I&E
I only
I&E
Meets
Imp.
Standard?
TRUE
TRUE
TRUE
TRUE
TRUE
FALSE
TRUE
TRUE
FALSE
FALSE
Meets
Ent.
Standard?
TRUE
TRUE
TRUE
TRUE
TRUE
TRUE
FALSE
FALSE
TRUE
FALSE
No New
Tech.
Needed?
TRUE
TRUE
TRUE
TRUE
TRUE
FALSE
FALSE
FALSE
FALSE
FALSE
Tech.
Cost
Module
0
0
0
0
0
1
4
3
9
2a
Incidental
Benefit?
NO
NO
NO
NO
NO
NO
NO
NO
YES
NO
Imp.
Reduction
0%
0%
0%
0%
0%
5% (BPJ)
5% (BPJ)
5% (BPJ)
5% (BPJ)
80%
Ent.
Reduction
0%
0%
0%
0%
0%
5% (BPJ)
5% (BPJ)
5% (BPJ)
5% (BPJ)
60%
2.3 Option 2
Option 2 (which is not one of today's co-proposed options) provides another, more complex example scenario. Beginning with the
initial data set from section 1.1, identify the facilities with no reductions, as in section 2.1. The requirements for the remaining
facilities is dependent upon two factors: design intake flow and waterbody type. Sort the data for the facilities with no reduction,
assign those 0% reductions, and assign a reduction for Facility 5, as the benefits reductions for these facilities is the same as in the
example in section 2.2.
It happens that the data is already sorted by waterbody type and then design intake flow, serving to group similar facilities together.
Under Option 2, facilities located on freshwater rivers and having a design intake flow between 20 and 50 MOD are required to meet
only impingement requirements. Facility 2 would be assigned an 80% reduction for impingement mortality, as it is required to meet
the impingement standard and does not presently do so. Facility 1, on the other hand, does currently meet the impingement standard
and therefore is assigned no reduction in impingement mortality. Both Facility 2 and lare assigned 0% for an entrainment reduction as
it is no longer required, even if the performance standards of the rule indicate otherwise. Option 2 relaxes those performance standards
for these facilities.
Under Option 2, facilities located on one of the Great Lakes and having a design intake flow between 20 and 50 MGD are required to
meet both impingement and entrainment requirements. Facility 7 already meets the impingement standard and is assigned only a 60%
reduction for entrainment. Facility 10 already meets the entrainment standard and would normally be assigned an 80% / 0% reduction
to reflect the addition of a technology to meet only the impingement requirements. However, due to site-specific characteristics, it is
more efficient to install a technology that reduces both impingement mortality and entrainment. As a result, this facility is assigned an
incidental benefit of a 60% reduction for entrainment.
6A-5
-------
§ 316(b) Phase HI - Technical Development Document
Appendix 6A
Exhibit 6A-5. Assigning Reductions Under Option 2, Including Incidental Benefits
Facility
ID
3
4
6
8
9
2
1
7
10
5
Waterbody
Type
Freshwater
River
Estuary/
Tidal River
Freshwater
River
Great Lakes
Lake/
Reservoir
Freshwater
River
Freshwater
River
Great Lakes
Great Lakes
Freshwater
River
DIF
(MOD)
11
113
126
88
8
8
10
17
22
73
Perf.
Standards
Required
I only
I&E
I only
I only
I only
I only
I&E
I&E
I only
I&E
Meets
Imp.
Standard?
TRUE
TRUE
TRUE
TRUE
TRUE
FALSE
TRUE
TRUE
FALSE
FALSE
Meets
Ent.
Standard?
TRUE
TRUE
TRUE
TRUE
TRUE
TRUE
FALSE
FALSE
TRUE
FALSE
No New
Tech.
Needed?
TRUE
TRUE
TRUE
TRUE
TRUE
FALSE
FALSE
FALSE
FALSE
FALSE
Tech.
Cost
Module
0
0
0
0
0
1
4
3
9
2a
Incidental
Benefit?
NO
NO
NO
NO
NO
NO
NO
NO
YES
NO
Imp.
Reduction
0%
0%
0%
0%
0%
80%
0%
0%
80%
80%
Ent.
Reduction
0%
0%
0%
0%
0%
0%
0%
60%
60%
60%
2.4 Conclusion
The above examples illustrate the range of data manipulation involved in assigning impingement mortality and entrainment reductions.
The reductions for the other options follow similar logic and require no further illustration.
6A-6
-------
§ 316(b) Phase HI - Technical Development Document Cost-Cost Test
Chapter 7: Cost-Cost Test
INTRODUCTION
This chapter presents the cost-cost test for alternative site-specific requirements. The first two sections present the requirements of the
cost-cost test and the data needs to carry out the test. Section 3.0 presents the step-by-step instructions for carrying out the cost-cost
test and the tabular data to be used with the cost-cost test. Section 4.0 presents the background information that supports the cost
correction equations.
Note that the costs presented in this chapter reference costs developed for year 2002 dollars, which were used to develop Phase II
facility costs. However, all costs for Phase III facilities presented in the preamble of today's proposed rule reflect costs that were
adjusted to year 2003 dollars. Additionally, the applications of the cost-cost test discussed in this chapter also reflect similarities to the
cost-cost test for Phase II.
1.0 SITE-SPECIFIC REQUIREMENTS - THE COST TO COST TEST
The proposed rule in § 125.103(a) (2) through (4) allows for a comparison between the projected costs of compliance of a facility
(based on data specific to the facility) to the costs considered by the Agency for a facility like yours. A facility requesting a cost-cost
determination must submit a Comprehensive Cost Evaluation Study and a Site Specific Technology Plan, the requirements of each can
be found at § 125.104(b)(6)(i) and 125.104(b)(6)(iii), respectively. The Comprehensive Cost Evaluation Study must include
engineering cost estimates in sufficient detail to document the costs of implementing design and construction technologies, operational
measures, and/or restoration measures at the facility that would be needed to meet the applicable performance standards of the final
rule; a demonstration that the documented costs significantly exceed the costs considered by EPA for a facility like yours in
establishing the applicable performance standards; and engineering cost estimates in sufficient detail to document the costs of
implementing alternative design and construction technologies, operational measures, and/or restoration measures in the facility's Site-
Specific Technology Plan. If the facility's costs are significantly greater than the costs considered by the Agency for a facility like
yours, then the Director may make a site specific determination of the best technology available for minimizing adverse environmental
impact.
2.0 DETERMINING A FACILITY'S COSTS
To make the demonstration that compliance costs are significantly greater than those considered by EPA, the facility must first
determine its actual compliance costs. To do this, the facility first should determine the costs for any new design and construction
technologies, operational measures, and/or restoration measures that would be needed to comply with the requirements of § 125.103
(a)(2) through (4), which may include the following cost categories: the installed capital cost of the technologies or measures, the net
operation and maintenance (O&M) costs for the technologies or measures (that is, the O&M costs for the final suite of technologies
and measures once all new technologies and measures have been installed less the O&M costs of any existing technologies and
measures), the net revenue losses (lost revenues minus saved variable costs) associated with net construction downtime (actual
construction downtime minus that portion which would have been needed anyway for repair, overhaul or maintenance) and any pilot
study costs associated with on-site verification and/or optimization of the technologies or measures.
Costs should be annualized using a 7 percent discount rate, with an amortization period of 10 years for capital costs and 30 years for
pilot study costs and construction downtime net revenue losses. Annualized costs should be converted to 2002 dollars ($2002), using
the engineering news record construction cost index (see Engineering News-Record. New York: McGraw Hill. Annual average value
is 6538 for year 2002). Costs for permitting and post-construction monitoring should not be included in this estimate, as these are not
included in the EPA-estimated costs against which they will be compared, as described below. Because existing facilities already
incur monitoring and permitting costs, and these are largely independent of the specific performance standards adopted and
technologies selected to meet them, it is both simpler and more appropriate to conduct the cost comparison required in this provision
using direct compliance costs (capital, net O&M, net construction downtime, and pilot study) only. Adding permitting and monitoring
costs to both sides of the comparison would complicate the methodology without substantially changing the results.
To calculate the costs that the Administrator considered for a like facility in establishing the applicable performance standards, the
facility must follow the steps laid out below, based on the information in Exhibit 7-2 provided in section 3.0 of this chapter. Note that
those facilities that claimed the flow data that they submitted to EPA, and which EPA used to calculate compliance costs, as
confidential business information (CBI), are not listed in the table provided in Exhibit 7-2, unless the total calculated compliance costs
were zero. If these facilities wish to request a site-specific determination of best technology available based on significantly greater
__
-------
S 316(b) Phase HI - Technical Development Document Cost-Cost Test
compliance costs, they will need to waive their claim of confidentiality prior to submitting the Comprehensive Cost Evaluation Study
so that EPA can make the necessary flow data available to the facility, Director, and public.
Cost Categories Considered Bv The Agency
The installed capital cost of the technology (suite) represents the material, equipment, and labor costs of the technology and retrofit,
the civil and site work costs, instrumentation and controls, electrical (installed), construction management, engineering and
architectural fees, contingency, overhead and profit, non-316(b) related permits, metalwork, performance bond, and insurance. Once
determined by the facility, the capital costs for comparison to the Agency's estimates must be amortized with a 7 percent discount
factor and a 10 year amortization period. The dollar years of the capital costs must be expressed in 2002 average dollars. The Agency
used the Engineering News-Record Construction Cost Index (McGraw-Hill, New York, NY) for estimating dollar year values. The
capital costs are presented in pre-tax form for the cost to cost comparison.
The net operation and maintenance costs of the technology or technology suite is the projected operation and maintenance costs of
the upgraded intake technology, post-construction and start-up, less the operation and maintenance costs of the cooling water intake
structures(s) in-place at the facility prior to enacting the technology upgrade. The Agency considered the periodic replacement of
parts, the periodic and intermittent maintenance of the technology (such as debris clearing, parts changeout, etc.), the periodic and
intermittent inspection of the technology, the energy usage of screen motors and spray wash and fish return pumps, and
management/technician labor. Additional factors may apply for special intakes located far offshore, such as diver inspections, or for
net systems or wedgewire screens, such as energy and maintenance costs associated with self-cleaning airburst systems. The Agency
notes that for the technologies considered for meeting the requirements of the final rule that cooling water intake flows did not change
from baseline to the technology upgrade. As a result the operation and maintenance of the main cooling water intake pumps would
typically not be considered a component of a net operation and maintenance cost for the purposes of the cost to cost test. Some
facilities may choose to comply with the requirements of the rule by adopting strategic flow reduction activities. As such, reduced
O&M costs associated with reduced intake flows for strategic plant operation should not be factored into the compliance comparison
of costs, as the Agency did not account for these savings in its cost estimates. Similarly, if dredging of canals or screen areas was a
typical portion of the maintenance activities of the site at baseline, then the net operation and maintenance costs for the purposes of the
cost to cost test may not include these costs. The Agency represented O&M costs on an annual basis. The O&M costs are presented
in pre-tax form for the cost to cost comparison.
The Agency determined the cost of the technology connection outage downtime as the revenue loss during the downtime less the
variable expenses that would normally be incurred during that period. The duration of the connection outage should be the total
construction outage less any concurrent outages due to planned maintenance. The Agency notes that with the flexible compliance
scheduling allowed with the final rule that facilities will have opportunities to plan construction schedules to take advantage of
concurrent downtime periods (such as period inspections and maintenance outages). The following formulas were used to calculate '
the net loss due to downtime:
Cost of Connection Outage = Revenue Loss - Variable Production Costs
where
Variable Production Cost = Fuel Cost + Variable OperatingA Maintenance Cost.
The Agency amortized net construction downtime costs using a discount rate of 7 percent and an amortization period of 30 years. The
downtime costs are presented in pre-tax form for the cost to cost comparison.
The technology pilot study costs associated with site verification of the technology estimated by the Agency included the total capital
and total operation and maintenance costs associated with a technology pilot study. Because pilot studies, by their nature, are short
term activities, the Agency represented the total cost of the study as a one-time capital cost, even though the actual study may be
extend out over a half-year to two-years; the total cost of the study was represented as a single one-time cost. Therefore, facilities
enacting pilot studies should represent the total costs of the pilot study in a similar manner. Similar to a construction project lasting
several months to years, some minor correction for dollar years may be necessary. The Agency amortized total capital costs using a
discount rate of 7 percent and an amortization period of 30 years. The pilot study costs are presented in pre-tax form for the cost to
cost comparison.
7-2
-------
§ 316(b) Phase III - Technical Development Document Cost-Cost Test
Site-specific Technology Plan
The Site-Specific Technology Plan is developed based on the results of the Comprehensive Cost Evaluation Study and must contain
the following information:
A narrative description of the design and operation of all existing and proposed design and construction
technologies, operational measures, and/or restoration measures that you have selected;
An engineering estimate of the efficacy of the proposed and/or implemented design and construction technologies or
operational measures, and/or restoration measures. This estimate must include a site-specific evaluation of the
suitability of the technologies or operational measures for reducing impingement mortality and/or entrainment (as
applicable) of all life stages offish and shellfish based on representative studies (e.g., studies that have been
conducted at cooling water intake structures located in the same waterbody type with similar biological
characteristics) and, if applicable, site-specific technology prototype or pilot studies. If restoration measures will be
used, you must provide a Restoration Plan (see § 125.104 (b)(5));
• A demonstration that the proposed and/or implemented design and construction technologies, operational measures,
and/or restoration measures achieve an efficacy that is as close as practicable to the applicable performance
standards of § 125.103(b) without resulting in costs significantly greater than either the costs considered by the
Administrator for a facility like yours in establishing the applicable performance standards, or as appropriate, the
benefits of complying with the applicable performance standards at your facility; and,
• Design and engineering calculations, drawings, and estimates prepared by a qualified professional to support the
elements of the Plan.
3.0 COST TO COST TEST
The data in Exhibit 7-2 is keyed to survey ID number. Exhibit 7-3 presents a crosswalk between survey ID number and facility name.
Facilities should also be able to determine their ID number from the survey they submitted to EPA during the rule development
process.
Step 1: Determine which technology EPA modeled as the most appropriate compliance technology for your facility. To do this, use
the code in column 12 of Exhibit 7-2 to look up the modeled technology in Exhibit 7-1 below.
Exhibit 7-1. Technology Codes and Descriptions
Technology
1
2
3
4
5
6
7
8
9
11
12
13
14
Code [Technology Description
[Addition offish handling and return system to an existing traveling screen system
[Addition of fine-mesh screens to an existing traveling screen system
[Addition of a new, larger intake with fine-mesh and fish handling and return system in front of an
'[existing intake system
[Addition of passive fine-mesh screen system (cylindrical wedgewire) near shoreline with mesh
[width of 1.75mm
[Addition of a fish net barrier system
[Addition of an aquatic filter barrier system
[Relocation of an existing intake to a submerged offshore location with passive fine-mesh screen
[inlet with mesh width of 1 .75 mm
[Addition of a velocity cap inlet to an existing offshore intake
[Addition of passive fine-mesh screen to an existing offshore intake with mesh width of 1.75 mm
[Addition of dual-entry, single-exit traveling screens (with fine- mesh) to a shoreline intake system
[Addition of passive fine-mesh screen system (cylindrical wedgewire) near shoreline with mesh
Kvidth of 0.76 mm
[Addition of passive fine-mesh screen to an existing offshore intake with mesh width of 0.76 mm
[Relocation of an existing intake to a submerged offshore location with passive fine-mesh screen
[inlet with mesh width of 0.76 mm
7-3
-------
§ 316(b) Phase III - Technical Development Document Cost-Cost Test
Step 2: Using EPA's costing equations, calculate the annualized capital and net operation and maintenance costs for a facility with
your design flow using this technology. To do this, you should use the following formula, which is derived from the results of EPA's
costing equations (see section 4.0 of this chapter for more discussion) for a facility like yours using the selected technology:
Yf =yepa+ «n*(Xf
where:
yf = annualized capital and net O&M costs using actual facility design intake flow,
xf = actual facility design intake flow (in gallons per minute),
x^ = EPA assumed facility design intake flow (in gallons per minute) (column 3),
y^ = Annualized capital and net O&M costs using EPA design intake flow (column 7), and
m = design flow adjustment slope (column 13).
EPA has provided some additional information in Exhibit 7-2, beyond that which is needed to perform the calculations, to facilitate
comparison of the results obtained using formula 1 to the detailed costing equations presented in Chapter 1 of this document, for those
who wish to do so. EPA does not expect facilities or permit writers to do this, and has in fact provided the simplified formula to
preclude the need for doing so, but is providing the additional information to increase transparency. Thus, for informational purposes,
the total capital cost (not annualized), baseline O&M cost, and post construction O&M cost from which the annualized capital and net
O&M costs using EPA design intake flow (y,^ in column 7) are derived are listed separately in columns 4 through 6. To calculate y^,
EPA annualized the total capital cost using a 7 percent discount rate and 10 year amortization period, and added the result to the
difference between the post construction O&M costs and the baseline O&M costs.
Note that some entries in Exhibit 7-2 have "n/a" indicated for the EPA assumed design intake flow in column 2. These are facilities
for which EPA projected that they would already meet otherwise applicable performance standards based on existing technologies and
measures. EPA projected zero compliance costs for these facilities, irrespective of design intake flow, so no flow adjustment is
needed. These facilities should use $0 as their value for the costs considered by EPA for a like facility in establishing the applicable
performance standards. EPA recognizes that these facilities will still incur permitting and monitoring costs, but these are not included
in the cost comparison for the reasons stated above.
Step 3: Determine the annualized net revenue loss associated with net construction downtime that EPA modeled for the facility to
install the technology and the annualized pilot study costs that EPA modeled for the facility to test and optimize the technology. The
sum of these two figures is listed in column 10. For informational purposes, the total (not annualized) net revenue losses from
construction downtime, and total (not annualized) pilot study costs are listed separately in columns 8 and 9. These two figures were
annualized using a 7% discount rate and 30 year amortization period and the results added together to get the annualized facility
downtime and pilot study costs in column 10.
Step 4: Add the annualized capital and O&M costs using actual facility design intake flow (yf from step 2), and the annualized facility
downtime and pilot study costs (column 10 from step 3) to get the preliminary costs considered by EPA for a facility like yours.
Step 5: Determine which performance standards in 125.103(b)(l) and (2) (i.e., impingement mortality only, or impingement mortality
and entrainment) are applicable to your facility, and compare these to the performance standards on which EPA's cost estimates are
based, listed in column 11. If the applicable performance standards and those on which EPA's cost estimates are based are the same,
then the preliminary costs considered by EPA for a facility like yours are the final costs considered by EPA for a facility like yours. If
only the impingement mortality performance standards are applicable to your facility, but EPA based its cost estimates on
impingement mortality and entrainment performance standards, then you should divide the preliminary costs by a factor of 2.148 to get
the final costs. If impingement mortality and entrainment performance standards are applicable to your facility, but EPA based its cost
estimates on impingement mortality performance standards only, then you should multiply the preliminary costs by 2.148 to get the
final costs. See section 4.0 of this chapter for more discussion of the performance standard correction factor.
Survey IDs
The survey ID for a facility was that assigned to the recipients of either the short technical questionnaire (STQ) or the detailed
questionnaire (DQ). The Agency assigned short technical questionnaire recipients questionnaire IDs in the form of "AUT0001",
where the "AUT" prefix was constant and the four number suffix varies for each facility. The Agency assigned detailed questionnaire
recipient questionnaire IDs dependent on the type of recipient. Utilities received IDs in the form of "DUT1000", where the "DUT"
prefix was constant and the four number suffix varied in the "1000" range for each recipient. Nonutilities received IDs in the form of
"DNU2000", where the "DNU" prefix was constant and the four number suffix varied in the "2000" range for each recipient.
—
-------
§ 316(b) Phase III - Technical Development Document
Cost-Cost Test
Municipality operated facilities received IDs in the form of "DMU3000", where the "DMU" prefix was constant and the four number
suffix varied in the "3000" range for each recipient.
Exhibit 7-2 presents costs for individual cooling water intake structures only for the case of detailed questionnaire recipients. For short
technical questionnaire recipients, the Agency necessarily estimated costs on the facility-level by assuming that the entire set of intakes
at the facility would have the intake characteristics reported at the facility level. Short technical questionnaire recipients would make
the potential corrections to EPA's estimated costs at the facility-level only (as outlined in Steps 2, 3, and 4 below).
In completing the questionnaire, the detailed questionnaire respondents assigned each cooling water intake structure at their plant a
designating number or name (through part 2, question la). The Agency has included these reported intake descriptors in Exhibit 7-2 to
allow the detailed questionnaire recipients to identify individual intake structures. Even though the cost to cost test is evaluated on the
facility level, detailed questionnaire recipients would make potential corrections to EPA's estimated capital and O&M costs as
outlined in Step 2 for each cooling water intake structure and then aggregate at the facility-level.
If a facility within the scope of the rule completed and returned a questionnaire but is not included in Exhibit 7-1, then the facility may
have claimed cooling water intake flow information pertaining to their facility to be confidential business information (CBI). If these
facilities wish to request a site-specific determination of best technology available based on significantly greater compliance costs,
they will need to waive their claim of confidentiality prior to submitting the Comprehensive Cost Evaluation Study so that EPA can
make the necessary flow data available to the facility, Director, and public.
Because the Agency has based its list of facilities projected to be within the scope of the rule on information collected through a
survey that is subject to some degree of uncertainty, there could be a small set of facilities that are subject to this rule that may not be
included in Exhibit 7-2. Exhibit 7-2 is the Agency's best estimate of the facilities that it projects to fall within the scope of the final
rule (less those claiming flow information as CBI). However, Exhibit 7-2 is not a definitive list of the inscope population of facilities
for the final rule. Therefore, a complying facility may discover when attempting to conduct a cost to cost test that the Agency did not
include costs for the particular facility in Exhibit 7-2. This is not to say that the Agency has not considered costs for the facility, as the
Agency scaled its national costs to represent weighted a population of facilities not receiving the survey. In the case of a facility not
included in Exhibit 7-2, the method for determining the representative costs that EPA considered for a similar facility should be
conducted by assessing the projected annual capital cost + net annual O&M cost of the intake technology determined by a facility like
that facility. Figures 7-1 through 7-13 provide estimated equations for calculating annual capital cost + net annual O&M cost for each
technology module considered by the Agency. In addition, the facility should find in Exhibit 7-2 facilities with the same cost-
correction equation slope (m) and could utilize the median annualized facility-level downtime and pilot study costs for that technology
in the comparison.
Exhibit 7-2. Costs Considered by EPA in Establishing Performance Standards ($2002)
Note: Exhibits 7-2 and 7-3 are taken from Phase II and serve as placeholders only.]
:olumn 1 column 2 column 3
Facility ID Intake ID EPA
Assumed
Design Intake
Flow, gpm
column 4
Capital Cost
column 5
column 6
Baseline O&M Post
Annual Cost Construction
O&M Annual
Cost
column /
Annualized
Capital3 + Net
O&M Using
EPA Design
(XjpJ Intake Flow2
AUT0001
AUT0002
AUT0004
AUT0011
AUT0012
AUT0014
AUT0015
AUT0016
AUT0019
Airrnn?n
401,881
549,533
239,107
453,758
2,018,917
572,383
1,296,872
301,127
848,784
907 S14
$
$
$
S
$
$
$
$
$
ft
322,884
5,750,259
528,427
967,675
48,835,329
2,732,729
510,784
41,613
11,094,343
1 S17 77Q
S
$
S
S
$
$
$
S
$
«K
699,866
68,489
30,725
55,545
360,813
91,057
-
-
271,045
14 8SQ
$
$
$
$
$
$
$
$
$
ffi
795,393
104,063
104,458
193,660
989,876
110,893
134,070
28,195
994,876
47 08Q
$
$
$
$
$
$
$
$
$
ft
141,498
854,282
148,969
275,890
7,582,115
408,915
206,794
34,120
2,303,416
•m 197
7-5
-------
§ 316(b) Phase III - Technical Development Document Cost-Cost Test
Exhibit 7-3. Facility ID and Facility Name for All Facilities Not Claiming Survey Information CBI
Facility ID Facility Name
AUT0001 Cane Run
AUT0002 Chesapeake
AUT0004 Hennepin
AUT0010 Bowen
AUT0011 Shawville
AUTOO12 Diablo Canyon Nuclear
AUT0013 Montville
AUT0014 Williams
AUT0015 Northport
AUTQ016 Cholla
4.0 COST CORRECTION
Derivation of the cost correction equation and technology module slopes.
Rather than providing the detailed costing equations that EPA used to calculate annualized capital and net O&M costs for facilities to
use each of the modeled technologies, EPA has provided the simplified formula (equation 1), which collapses the results of those
equations for the particular facility and technology into a single result (y^J and then allows the facility to adjust this result to reflect its
actual design intake flow, using a technology specific slope for a facility like yours that is derived from the costing equations. This
allows facilities to perform the flow adjustment in a straightforward and transparent manner. The Agency analyzed each of the cooling
water intake structures (facilities) predicted to implement each technology module with respect to its annual capital plus net O&M
costs, normalized by design intake flow. The Agency then performed a best-fit for each technology, as presented in Figures 7-1
through 7-13.
Derivation of the correction factor for impingement mortality and/or entrainment requirements.
In calculating compliance costs, EPA projected what performance standards would be applicable to the facility based on available
data. However, because of both variability and uncertainty in the underlying parameters that determine which performance standards
apply (e.g., capacity utilization rate, mean annual flow), it is possible that in some cases the performance standards that EPA projected
are not correct. The adjustment factor of 2.148 was determined by taking the ratio of median compliance costs for facilities to meet
impingement mortality and entrainment performance standards over median compliance costs for facilities to meet impingement
mortality performance standards only. While using this adjustment factor will not necessarily yield the exact compliance costs that
EPA would have calculated had it had current information, EPA believes the results are reasonable for determining whether a facility's
actual compliance costs are "significantly greater than" the costs considered by EPA for a like facility in establishing the applicable
performance standards. EPA believes it is preferable to provide a simple and transparent methodology for making this adjustment that
yields reasonably accurate results, rather than a much more complex methodology that would be difficult to use and understand (for
the facility, permit writer, and public), even if the more complex methodology would yield slightly more accurate results. DCN 6-3588
in the confidential business information docket provides the calculations upon which the correction factor is based.
7-6
-------
§ 316(b) Phase III - Technical Development Document
Cost-Cost Test
Figure 7-1. Module 1: Add fish handling and return system to traveling screens
$3,000,000
2 $2,500,000 -
03
S
"8
.M
500,000 1,000,000 1,500,000 2,000,000 2,500,000 3,000,000
Design Intake Flow (gpm)
Figure 7-2. Module 2: Add fine-mesh screens to traveling screens
$4,500,000
| $4,000,000 -
1 $3,500,000 -
c
2 $3,000,000 -
3
$2,500,000
$2,000,000 -
$1,500,000 -
$1,000,000 -
$500,000
$-
+
8
500,000 1,000,000 1,500,000
Design Intake Flow (gpm)
2,000,000
2,500,000
7-7
-------
§ 316(b) Phase III - Technical Development Document
Cost-Cost Test
Figure 7-3. Module 3: Add new, larger intake in front of existing intake
$7,000,000
o $6,000,000 -
1
| $5,000,000 -
f $4,000,000 -
I $3,000,000
•Q.
<3 $2,000,000
I $1,000,000 -
c
$-
400,000 800,000 1,200,000 1,600,000 2,000,000
Design Intake Flow (gpm)
Figure 7-4. Module 4: Add passive fine-mesh screen near shoreline w/1.75 mm mesh
$7,000,000
o $6,000,000
§
| $5,000,000 -
f $4,000,000 -
? $3,000,000 -
™ $2,000,000 -
I $1,000,000 -
I
500,000 1,000,000 1,500,000 2,000,000 2,500,000
Design Intake Flow (gpm)
7-8
-------
§ 316(b) Phase III - Technical Development Document
Cost-Cost Test
Figure 7-5. Module 5: Add fish net barrier system
$600,000
500,000 1,000,000 1,500,000 2,000,000 2,500,000 3,000,000
Design Intake Flow (gpm)
Figure 7-6. Module 6: Add aquatic filter barrier system
2
s
3
1
"55
+
"OT
O
s
<§"
•0
35
.Cd
CO
3
1
$1 400 000
$1,200,000 -
$1,000,000 -
$800,000 -
$600,000 -
$400,000 -
$200,000 -
$-
, y = 5,0065x , ;
..N- '^MJjl- /, '*j#!9l£'£ •'.
£" ^ -' ' . '*""" rf V4^^ '* '^~ - '
:' • :• '^ "'-/ -'^^^f^^T^'^ ••
'* %^^' " ' •» &" *
'" ' f'^^^^ ' '^'j ' *^" *' T'^'- ^
,? "^ i ^$ji^^ \* — * "*
•^ ^^^
:+^^'
I •.
A " " - " i ' *" ' ^
*- , "£" * "
50,000 100,000 150,000 200,000 250,000 300,000
(Design Intake Flow (gpm)
7-9
-------
S 316(b) Phase III - Technical Development Document
Cost-Cost Test
Figure 7-7. Module 7: Relocate to submerged offshore w/passive fine-mesh screen inlet & 1.75 mm mesh
$3,500,000
1
$3,000,000 -
8
< $2,500,000 -
" $2,000,000 -
$1,500,000 -
8 $1,000,000 -
=2 $500,000
I $-
y=2.504x
0.2881
200,000 400,000 600,000 800,000 1,000,000 1,200,000 1,400,000
Design Intake Flow (gpm)
Figure 7-8. Module 8: Add velocity cap inlet to offshore intake
$180,000
| $160,000 -
1 $140,000 -
| $120,000 -
i $100,000 -
8 $80,000
g- $60,000 -
| $40,000
1 $20,000 -
4 ,.
100,000 200,000 300,000
Design Intake Flow (gpm)
400,000
500,000
7-70
-------
S 316(b) Phase III - Technical Development Document
Cost-Cost Test
Figure 7-9. Module 9: Add passive fine-mesh screen to offshore intake w/1.75 mm mesh
$18,000,000
2 $16,000,000 -
2 $14,000,000 -
| $12,000,000 -
| $10,000,000
8 $8,000,000 -
o
1 $6,000,000 -
8-
$4,000,000 -
1
$2,000,000 -
y =5.973x
500,000 1,000,000 1,500,000
Design Intake Flow (gpm)
2,000,000 2,500,000
Figure 7-10. Module 11: Add dual-entry, single-exit traveling screens (with fine-mesh)
$3,000,000
2 $2,500,000
|
| $2,000,000
+
8 $1,500,000
'§- $1,000,000
o
$500,000
500,000 1,000,000 1,500,000 2,000,000
Design Intake Flow (gpm)
2,500,000
7-11
-------
§ 316(b) Phase m - Technical Development Document
Cost-Cost Test
Figure 7-11. Module 12: Add passive fine-mesh screen near shoreline w/ 0.76 mm mesh
o
1
I
$12,000,000
$10,000,000 -
$8,000,000
$6,000,000 -
$4,000,000 -
$2,000,000 -
500,000 1,000,000 1,500,000 2,000,000 2,500,000
Design Intake Flow (gpm)
Figure 7-12. Module 13: Add passive fine-mesh screen to offshore intake w/ 0.76 mm mesh
$1,600,000
§ $1,400,000 -
To
1 $1,200,000 -
£ $1,000,000 -
g $800,000 -
1 $600,000 -
^ $400,000 -
Q>
5 $200,000 -
1 $-
40,000 80,000 120,000 160,000 200,000
Design Intake Flow (gpm)
7-72
-------
S 316(6) Phase III - Technical Development Document
Cost-Cost Test
Figure 7-13. Module 14: Relocate to submerged offshore w/ passive fine-mesh screen inlet & 0.76 mm mesh
$8,000,000
g $7,000,000 -
" $6,000,000
$5,000,000 -
I $4,000,000
1. $3,000,000 -
S
1 $2,000,000 -
| $1,000,000 -
$-
150,000 300,000 450,000 600,000 750,000 900,000
Design Intake Flow (gpm)
7-73
-------
-------
§ 316(b) Phase HI - Technical Development Document Efficacy of Cooling Water Intake Structure Technologies
Chapter 8: Efficacy of Cooling Water Intake Structure Technologies
INTRODUCTION
This chapter presents the data compiled by the Agency on the performance of the range of technologies currently used to minimize
impingement mortality and entrainment (I&E) at existing manufacturing facilities and offshore oil and gas extraction facilities
nationwide.
Although uniform national requirements under the proposed rule would only apply to manufacturing facilities, based on the co-
proposed thresholds, the technologies described for Phase III facilities are the same as those used by Phase II electricity generation
facilities to meet section 316(b) requirements. EPA considers the types of intakes and the technologies available to address
impingement and entrainment at Phase II facilities to be consistent with the intakes and technologies at Phase III existing facilities.
I. EXISTING MANUFACTURING FACILITIES
1.0 DATA COLLECTION OVERVIEW
To support the section 316(b) proposed rule for existing facilities, the Agency compiled data on the performance of the range of
technologies currently used to minimize impingement and entrainment (I&E) at power plants nationwide. The goal of this data
collection and analysis effort was to determine whether specific technologies could be shown to provide a consistent level of proven
performance. The information compiled was used to compare specific regulatory options and their associated costs and benefits, as
well as provide stakeholders with a comprehensive summary of previous studies designed to assess the efficacy of the various
technologies. It provided the supporting information for the rule and alternative regulatory options considered during the development
process and final action by the Administrator.
Throughout this chapter, baseline technology performance refers to the performance of conventional, wide-mesh traveling screens that
are not intended to prevent impingement and/or entrainment. The term alternative technologies generally refer to those technologies,
other than closed-cycle recirculating cooling systems, that can be used to minimize impingement and/or entrainment. Overall, the
Agency has found that performance and applicability vary to some degree based on site-specific and seasonal conditions. The Agency
has also determined, however, that alternative technologies can be used effectively on a widespread basis if properly designed,
operated, and maintained.
1.1 Scope of Data Collection Efforts
The Agency has compiled readily available information on the nationwide performance of I&E-reduction technologies. This
information has been obtained through the following:
• Literature searches and associated collection of relevant documents on facility-specific performance.
Contacts with governmental (e.g., Tennessee Valley Authority (TVA)) and non-governmental entities (e.g., Electric Power
Research Institute (EPRI)) that have undertaken national or regional data collection efforts/performance studies.
• Meetings with and visits to the offices of EPA regional and State agency staff as well as site visits to operating power plants.
It is important to recognize that the Agency did not use a systematic approach to data collection; that is, the Agency did not obtain all
the facility performance data available nor did it obtain the same amount and detail of information for every facility. The Agency is not
aware of such an evaluation ever being performed nationally. The most recent national data compilation was conducted by EPRI in
2000; see Fish Protection at Cooling Water Intakes, Status Report. The findings of that report are cited extensively in the following
subsections. EPRI's analysis, however, was primarily a literature collection and review effort and was not intended to be an
exhaustive compilation and analysis of all available data. Through this evaluation, EPA worked to build on the EPRI review by
reviewing primary study documents cited by EPRI as well as through the collection and reviewing of additional data.
8-1
-------
S 316(b) Phase III - Technical Development Document Efficacy of Cooling Water Intake Structure Technologies
1.2 Technology Database
In an effort to document and further assess the performance of various technologies and operational measures designed to minimize the
impacts of cooling water withdrawals, EPA compiled a database of documents to allow analyses of the efficacy of a specific
technology or suite of technologies. The data collected and entered into this database came from materials ranging from brief journal
articles to the more intensive analyses found in historical section 316(b) demonstration reports and technology evaluations. In
preparing this database, EPA assembled as much documentation as possible within the available timeframe to support future Agency
decisions. It should be noted that the data may be of varying quality. EPA did not validate all database entries. However, EPA did
evaluate the general quality and thoroughness of the study. Information entered into the database includes some notation of the
limitations the individual studies might have for use in further analyses (e.g., no biological data or conclusions).
EPA's intent in assembling this information was fourfold. First, the Agency sought to develop a categorized database containing a
comprehensive collection of available literature regarding technology performance. The database is intended to allow, to the extent
possible, a rigorous compilation of data supporting the determination that the proposed performance standards are considered best
technology available. Second, EPA used the data to demonstrate that the technologies chosen as compliance technologies for costing
purposes are reasonable and can meet the performance standards. Third, the availability of a user-friendly database will allow EPA,
state permit writers, and the public to more easily evaluate potential compliance options and facility compliance with performance
standards. Fourth, EPA attempted to evaluate the technology efficacy data against objective criteria to assess the general quality and
thoroughness of each study. This evaluation might assist in further analysis of conclusions made using the data.
Basic information from each document was recorded in the database (e.g., type of technology evaluated, facility at which it was
tested). In addition to basic document information, the database contains two types of information: (1) general facility information and
(2) detailed study information.
For those documents that refer to a specific facility (or facilities), basic technical information was included to enable EPA to classify
facilities according to general categories. EPA collected locational data (e.g., waterbody type, name, state), as well as basic cooling
water intake structure configuration information. Each technology evaluated in the study is also recorded, along with specific details
regarding its design and operation. Major categories of technologies include modified traveling screens, wedgewire screens, fine-mesh
screens, velocity caps, barrier nets, and behavioral barriers. (Data identifying the technologies present at a facility, as well as the
configuration of the intake structure, refer to the configuration when the study was conducted and do not necessarily reflect the present
facility configuration).
Information on the type of study, along with any study results, is recorded in the second part of the database. EPA identifies whether
the study evaluates the technology with respect to impingement mortality reduction (or avoidance), entrainment survival, or
entrainment exclusion (or avoidance). Some studies address more than one area of concern, and that is noted. EPA records basic
biological data used to evaluate the technology, if such data are provided. These data include target or commercially/recreationally
valuable species, species type, life history stage, size, sample size, and raw numbers of impinged and/or entrained organisms. Finally,
EPA records any overall conclusions reached by the study, usually presented as a percentage reduction or increase, depending on the
area of focus. Including this information for each document allows EPA and others to readily locate and compare documents
addressing similar technologies. Each document is reviewed according to five areas of data quality where possible: (1) applicability
and utility, (2) soundness, (3) clarity and completeness, (4) uncertainty and variability, and (5) evaluation and review. Because the
compiled literature comes from many different sources and was developed under widely varying standards, EPA reviewed all
documents in the database against all five criteria.
To date, EPA has collected 153 documents for inclusion in the database. The Agency did not exclude from the database any document
that addressed technology performance in relation to impingement mortality and entrainment, regardless of the overall quality of the
data.
1.3 Data Limitations
Because EPA 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 variability leads to the following data limitations:
Some facility data include all the major species and associated life stages present at an individual facility, whereas others include
only data for selected species and/or life stages. The identification of important species can be a valid method for determining the
overall effectiveness of a technology if the criteria used for selection are valid. In some studies, target species are identified but
no reason for their selection is given.
—
-------
S 316(b) Phase IH - Technical Development Document Efficacy of Cooling Water Intake Structure Technologies
• Many of the data were collected in the 1970s and early 1980s when existing facilities were required to complete their initial
316(b) demonstrations. In addition, the focus of these studies was not the effectiveness of a particular technology but rather the
overall performance of a facility in terms of rates of impingement and entrainment.
Some facility data includes only initial survival results, whereas other facilities have 48- to 96-hour survival data. These longer-
term survival data are relevant because some technologies can exhibit significant latent mortality after initial survival.
• Analytical methods and collection procedures, including quality assurance/quality control protocols, are not always present or
discussed in summary documentation. Where possible, EPA has reviewed study methods and parameters to determine
qualifications, if any, that must be applied to the final results.
• Some data come from laboratory and pilot-scale testing rather than full-scale evaluations. Laboratory studies offer unique
opportunities to control and alter the various inputs to the study but might not be able to mimic the real-world variables that could
be present at an actual site. Although EPA recognizes the value of laboratory studies and does not discount their results, in situ
evaluations remain the preferred method for gauging the effectiveness of a technology.
• Survival rates calculated in individual studies can vary as to their true meaning. In some instances, the survival rate for a given
species (initial or latent) has been corrected to account for the mortality rate observed in a control group. Other studies explicitly
note that no control groups have been used. These data are important because overall mortality, especially for younger and more
fragile species, can be adversely affected by the collection and observation process-factors that would not affect mortality under
unobserved conditions.
EPA recognizes that the practicality or effectiveness of alternative technologies might not be uniform under all conditions. The
chemical and physical nature of the waterbody, facility intake requirements, climatic conditions, and biology of the area all affect
feasibility and performance. Despite the above limitations, however, EPA has concluded that significant general performance
expectations can be inferred for the range of technologies and that one or more technologies (or groups of technologies) can provide
significant impingement mortality and/or entrainment protection at most sites. In addition, in EPA's view many of the technologies
have the potential for even greater applicability and higher performance when facilities optimize their use.
The remainder of this chapter is organized by groups of technologies. A brief description of conventional, once-through traveling
screens is provided for comparison purposes. Fact sheets describing each technology, available performance data, and design
requirements and limitations are provided in Attachment A. It is important to note that this chapter does not provide descriptions of all
potential cooling water intake structure (CWIS) technologies. (ASCE 1982 generally provides such an all-inclusive discussion.)
Instead, EPA has focused on those technologies that have shown significant promise at the laboratory, pilot-scale, or full-scale levels
in consistently minimizing impingement mortality 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) can also be used to limit potential impingement mortality and/or entrainment effects. Habitat restoration projects are an
additional means to comply with this rule. Such projects, however, have not had widespread application at existing facilities. Because
the nature, feasibility, and likely effectiveness of such projects would be highly site-specific, EPA has not attempted to quantify their
expected performance level in this document.
1.4 Conventional Traveling Screens
For impingement control technologies, performance is compared to conventional (unmodified) traveling screens, the baseline
technology. These screens are the most commonly used intake technology 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 the system. The traveling screens 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. Approximately 89 percent of all existing facilities
within the scope of this rule use conventional traveling screens.
8-3
-------
§ 316(b) Phase III - Technical Development Document Efficacy of Cooling Water Intake Structure Technologies
1.5 Closed-cycle Wet Cooling System Performance
Although flow reduction serves the purpose of reducing both impingement and entrainment, flow reduction requirements function
foremost as a reliable entrainment reduction technology. Throughout this chapter, EPA compares the performance of entrainment-
reducing technologies to that of recirculating wet cooling towers. To evaluate the feasibility of regulatory options with flow reduction
requirements and to allow comparison of costs and benefits of alternatives, EPA determined the likely range in flow reductions
between wet, closed-cycle cooling systems and 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's performance. Therefore, some water (blowdown) must be discharged and make-up water added periodically to the system.
An additional question that EPA has considered is the feasibility of constructing salt-water make-up cooling towers. For the
development of the New Facility 316(b) rule, EPA contacted Marley Cooling Tower (Marley), which is one of the largest cooling
tower manufacturers in the world. Marley provided a list of facilities (Marley 2001) that have installed cooling towers that use marine
or otherwise high total dissolved solids/brackish make-up water. It is important to recognize the facilities listed represent only a
selected group of facilities for which Marley has constructed cooling towers worldwide.
2.0 ALTERNATIVE TECHNOLOGIES
2.1 Modified Traveling Screens and Fish Handling and Return Systems
Technology Overview
Conventional traveling screens can be modified so that fish impinged on the screens can be removed with minimal stress and mortality.
Ristroph screens have water-filled lifting buckets that 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 at which the fish
are spilled onto a bypass, trough, or other protected area (Mussalli, Taft, and Hoffman 1978). Fish baskets are another modification of
a conventional traveling screen and may be used in conjunction with fish buckets. Fish baskets are separate framed screen panels
attached to vertical traveling screens. An essential feature of modified traveling screens is continuous operation during periods when
fish are being impinged. Conventional traveling screens typically operate intermittently. (EPRJ2000,1989; Fritz 1980). Removed
fish are typically returned to the source waterbody by sluiceway or pipeline. ASCE (1982) provides guidance on the design and
operation offish return systems.
Technology Performance
A wide range of facilities nationwide have used modified screens and fish handling and return systems to minimize impingement
mortality. Although many factors influence the overall performance of a given technology, modified screens with a fish return
capability have been deployed with success under varying waterbody conditions. In recent years, some researchers, primarily Fletcher
(1996), have evaluated the factors that affect 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 or baskets to minimize hydrodynamic turbulence within the bucket or basket.
• Using smooth-woven screen mesh to minimize fish descaling.
• Using fish rails to keep fish from escaping the buckets or baskets.
• Performing fish removal prior to high-pressure washing for debris removal.
• Optimizing the location of spray systems to provide a more gentle fish transfer to sloughs.
• Ensuring proper sizing and design of return troughs, sluiceways, and pipes to minimize harm.
2.1.1 Example Studies
Although uniform national requirements under the proposed rule would only apply to manufacturing facilities, based on the co-
proposed thresholds, the technologies described for Phase III facilities are the same as those used by Phase II electricity generation
facilities to meet section 316(b) requirements. EPA considers the types of intakes and the technologies available to address
impingement and entrainment at Phase II facilities to be consistent with the intakes and technologies at Phase III existing facilities.
Salem Generating Station
Salem Generating Station, on the Delaware Bay estuary in New Jersey, converted 6 of its 12 conventional traveling screen assemblies
to a modified design that incorporated improved fish buckets constructed of a lighter composite material (which improved screen
—
-------
S 316(b) Phase IH - Technical Development Document Efficacy of Cooling Water Intake Structure Technologies
rotation efficiency), smooth-woven mesh material, an improved spray wash system (both low- and high-pressure), and flap seals to
improve the delivery of impinged fish from the fish buckets to the fish return trough.
The initial study period consisted of 19 separate collection events during mid-summer 1996. The configuration of the facility at the
time of the study (half of the screens had been modified) allowed for a direct comparison of the effectiveness of the modified and
unmodified screens on impingement mortality rates. The limited sampling timeframe enabled the analysis of only the species present
in numbers sufficient to support any statistical conclusions. 1,082 juvenile weakfish were collected from the unmodified screens while
1,559 were collected from the modified structure. Analysts held each sample group separately for 48 hours to assess overall mortality
due to impingement on the screens. Results showed that use of the modified screens had increased overall survival by as much as 20
percent over the use of the unmodified screens. Approximately 58 percent of the weakfish impinged on the unmodified screens
survived, whereas the new screens had a survival rate-approaching 80 percent. Both rates were based on 48-hour survival and not
adjusted for the mortality of control samples.
Water temperature arid fish length are two independent factors cited in the study as affecting overall survival. Researchers noted that
survival rates decreased somewhat as the water temperature increased, possibly as a result of lower levels of dissolved oxygen.
Survival rates decreased to a low of 56 percent for the modified screens when the water temperature reached its maximum of 80°F. At
the same temperature, the survival rate on the unmodified screens were 35 percent. Differences in survival rates were also attributable
to the size of the fish impinged. In general, small fish (< 50 mm) fared better on both the modified and unmodified screens than large
fish (> 50 mm). The survival rates of the two size categories did not differ significantly for the modified screens (85 percent survival
for small, 82 percent for large), although a more pronounced difference was evident on the unmodified screens (74 percent survival for
small, 58 percent for large).
Salem Generating Station conducted a second series of impingement sampling from 1997 to 1998. By that time all screen assemblies
had been modified to include fish buckets and a fish return system as described above. Additional modifications to the system sought
to enhance the chances of survival offish impinged against the screens. One modification altered the fish return slide to reduce the
stress on fish being delivered to the collection pool. Flap seals were improved to better seal gaps between the fish return and debris
trough, thus preventing debris from affecting returning fish. Researchers used a smaller mesh screen in the collection pools during the
1997-1998 sampling events than had been used during the 1995 studies. The study notes that the larger mesh used in 1995 might have
enabled smaller fish to escape the collection pool. Since smaller fish typically have a higher mortality rate due to physical stress than
larger fish, the actual mortality rates may have been greater than those found in the 1995 study.
The second impingement survival study analyzed samples collected from October through December 1997 and April through
September 1998. Samples were collected twice per week and analyzed for survival at 24- and 48-hour intervals. Six principal species
were identified as constituting the majority of the impinged fish during the sampling periods: weakfish, white perch, bay anchovy,
Atlantic croaker, spot, and Alosa spp. Fish were sorted by species and size, classified by their condition, and placed in holding tanks.
For most species, survival rates varied noticeably depending on the season. For white perch, survival was above 90 percent
throughout the sample period (as high as 98 percent in December). Survival rates for weakfish varied from a low of 18 percent in July
to a high of 88 percent in September. Although the number of weakfish collected in September was approximately one-fifth of the
number collected in July, a possible explanation for the variation in survival rates is the modifications to the collection system
described above, which were implemented during the study period. Similarly, bay anchovy fared worst during the warmer months,
dropping to a 20 percent survival rate in July while achieving a 72 percent rate during November. Rates for Atlantic croaker varied
from 58 percent in April to 98 percent in November. Spot were collected in only one month (November) and had a survival rate of 93
percent. The survival rate for the Alosa spp. (alewife, blueback herring, and American shad) remained relatively consistent, ranging
from 82 percent in April to 78 percent in November.
For all species in the study, with the exception of weakfish, survival rates improved markedly with the use of the modified screen
system when compared to data from 1978-1982, when the unmodified system was still in use.
Mystic Station
Mystic Station, on the Mystic River in Massachusetts, converted one of its two conventional traveling screen assemblies to a modified
system incorporating fish collection buckets and a return system in 1981 to enable a side-by-side comparison of impingement survival.
Fish buckets were attached to each of the screen panels. Low-pressure spray (10 psi) nozzles were installed to remove fish from the
buckets and into the collection trough. The screen system was modified to include a two-speed motor with a four-speed transmission
to enable various rotation speeds for the traveling screens.
The goal of the study was to determine the optimal screen rotation speed and rotation interval that could achieve the greatest survival
rate without affecting the screen performance. The study analyzes 2-, 4- and 8-hour rotation intervals as well as continuous rotation.
_
-------
S 316(b) Phase IH - Technical Development Document Efficacy of Cooling Water Intake Structure Technologies
Samples were collected from October 7,1980 to April 27,1981. Fish collected from the screens were sorted several times per week,
classified, and placed into holding tanks for 96 hours to observe latent mortality.
Results from the study indicated that impingement of the various species was highly seasonal in nature. Data from Unit 7 during the
sample period indicate that in terms of both biomass and raw numbers, the majority offish are present in the vicinity, and thus
susceptible to impingement, during the fall and early winter. Almost 50 percent of the Alosa spp. were collected during one week in
November, while 75 percent of the smelt were collected in a 5-week period in late fall. Likewise, nearly 60 percent of the winter
flounder were collected in January. These data suggest that optimal rotation speeds and intervals, whatever they might be, might not
be necessary throughout the year.
Continuous rotation of the screens, regardless of speed, resulted in a virtual elimination of impingement mortality for winter flounder.
For all other species, survival generally increased with screen speed and rotation interval, with the best 96-hour survival rate (50
percent) occurring at a continuous rotation at 15 feet per second. The overall survival rate is affected by the high latent mortality of
Alosa spp. in the sample. The study speculates that the overall survival rates would be markedly higher under actual (unobserved)
operating conditions, given the high initial survival for large Alosa spp. Fragile species such as Alosa can be adversely affected by the
stresses of collection and monitoring and might exhibit an abnormally higher mortality rate as a result.
Indian Point Unit 2
Indian Point is located on the eastern shore of the Hudson River in New York. In 1985, the facility modified the intake for Unit 2 to
include a fish lifting trough fitted to the face of the screen panels. Two low-pressure (10 psi) spray nozzles removed collected fish into
a separate fish return sluiceway. A high-pressure spray flushed other debris into a debris trough. The new screen also incorporated a
variable speed transmission, enabling the rotation of the screen panels at speeds of up to 20 feet per minute. For the study period,
screens were continuously rotated at a speed of 10 feet per minute.
The sampling period lasted from August 15,1985 to December 7,1985. Fish were collected from both the fish trough and the debris
trough, though survival rates are presented for the fish collected from the fish trough only. The number offish collected from the
debris trough was approximately 45 percent of the total collected from the fish trough; the survival rate of these fish is unknown.
Control groups were not used to monitor the mortality associated with natural environmental factors such as salinity, temperature, and
dissolved oxygen. Collected fish were held in observation tanks for 96 hours to determine a latent survival rate.
White perch composed the majority (71 percent) of the overall sample population. Survival rates ranged from 63 percent in November
to 90 percent in August. It should be noted that during the month with the greatest abundance (December), the survival rate was 67
percent. This generally represents the overall survival rate for this species because 75 percent of white perch collected during the
sample period were collected during December. Weakfish were the next most abundant species, with an overall survival rate of 94
percent. A statistically significant number of weakfish were collected only during the month of August. Atlantic tomcod and blueback
herring were reported to have survival rates of 73 percent and 65 percent, respectively. Additional species present in small numbers
had widely varying survival rates, from a low of 27 percent for alewife to a high of over 95 percent for bluegill and hogchoker.
A facility-wide performance level is not presented for Indian Point, but a general inference can be obtained from the survival rates of
the predominant species. A concern is raised, however, by the exclusion offish collected from the debris trough. Their significant
number might affect the overall mortality of each species. Because the fish in the debris trough have been subjected to high-pressure
spray washes as well as any large debris removed from the screens, mortality rates for these fish are likely to be higher, thereby
reducing the overall effectiveness of the technology as deployed. The experiences of other facilities suggest that modifications to the
system might be able to increase the efficiency of moving impinged fish to the fish trough. In general, species survival appeared
greater during late summer than in early winter. Samples were collected during one 5-month period. It is not known from the study
how the technology would perform in other seasons.
Roseton Generating Station
Roseton Generating Station is located on the eastern shore of the Hudson River in New York. In 1990, the facility replaced two of
eight conventional traveling screens with dual-flow screens that included water-retaining fish buckets, a low-pressure (10 psi) spray
system, smooth-woven mesh screen panels, and a separate fish return trough. The dual-flow screens were also equipped with variable
speed motors to achieve faster rotational speeds. For the study period, screens were continuously rotated at a speed of 10.2 feet per
minute.
Impingement samples were collected during two periods in 1990: May 9 to August 30 and September 30 to November 29. A total of
529 paired samples were collected for the first period and 246 paired samples for the second period. Initial mortality was recorded at
the Roseton facility. Collected samples were not held on site but rather transported to the fish laboratory at Danskammer Point, where
—
-------
S 316(b) Phase III - Technical Development Document Efficacy of Cooling Water Intake Structure Technologies
they were observed for latent mortality. Latent mortality observations were made at 48- and 96-hour intervals. A control study using a
mark-recapture method was conducted simultaneously to measure the influence, if any, that water quality factors and collection and
handling procedures might have had on overall mortality rates. Based on the results of this study, the post-impingement survival rates
did not need to be adjusted for a deviation from the control mortality.
Blueback herring, bay anchovy, American shad, and alewife composed the majority of the sample population in both sampling periods.
Latent survival rates ranged from 0 percent to 6 percent during the summer and were somewhat worse during the fall. The other two
predominant species, white perch and striped bass, fared better, having survival rates as high as 53 percent. Other species that
composed less than 2 percent of the sample population survived at considerably higher rates (98 percent for hogchoker).
It is unclear why the more fragile species (alewife, blueback herring, American shad, and bay anchovy) had such high mortality rates.
The study notes that debris had been collecting in the fish return trough and was disrupting the flow of water and fish to the collection
tanks. Water flow was increased through the trough to prevent accumulation of debris. No information is presented to indicate the
effect of this modification. Also noted is the effect of temperature on initial survival. An overall initial survival rate of 90 percent was
achieved when the ambient water temperature was 54°F. Survival rates decreased markedly as water temperature increased, and the
lowest initial survival rate (6 percent) was recorded at the highest temperature.
Surry Power Station
Surry Power Station is located on the James River in Virginia. Each of the two units has 3/8-inch mesh Ristroph screens with a fish
return trough. A combined spray system removes impinged organisms and debris from the screens. Spray nozzle pressures range
from 15 to 20 psi. During the first several months of testing, the system was modified to improve fish transfer to the sluiceway and
increase the likelihood of post-impingement survival. A flap seal was added to prevent fish from falling between the screen and return
trough during screen washing. Water volume in the return trough was increased to facilitate the transfer of fish to the river, and a
velocity-reduction system was added to the trough to reduce the speed of water and fish entering the sample collecting pools.
Samples were collected daily during a 6-month period from May to November 1975. Initial mortality was observed and recorded after
a 15-minute period during which the water and fish in the collection pools were allowed to settle. The average survival rate for the 58
different species collected was 93 percent, although how this average was calculated was not noted. Bay anchovy and the Alosa spp.
constituted the majority of the sample population and generally had the lowest initial survival rates at 83 percent. The study does not
indicate whether control samples were used and whether mortality rates were adjusted accordingly. A noticeable deficiency of the
study is the lack of latent mortality analysis. Consideration of latent mortality, which could be high for the fragile species typically
impinged at Surry Power Station, might significantly reduce the overall impingement survival rate.
Arthur Kill Station
The Arthur Kill Station is located on the Arthur Kill estuary in New York. To fulfill the terms of a consent order, Consolidated Edison
modified two of the station's dual-flow intake screens to include smooth mesh panels, fish-retention buckets, flap seals to prevent fish
from falling between screen panels, a low-pressure spray wash system (10 psi), and a separate fish return sluiceway. One of the
modified screens had mesh of 1/8-inch by 1/2-inch while the other had 1/4-inch by 1/2-inch while the six unmodified screens all had
1/8-inch by 1/8-inch mesh. Screens were continuously rotated at 20 feet per minute during the sampling events.
The sampling period lasted from September 1991 to September 1992. Weekly samples were collected simultaneously from all
screens, with the exception of 2 weeks when the facility was shut down. Each screen sample was held separately in a collection tank
where initial mortality was observed. A 24-hour survival rate was calculated based on the percentage of fish alive after 24 hours
versus the total number collected. Because a control study was not performed, final survival rates have not been adjusted for any
water quality or collection factors. The study did not evaluate latent survival beyond the 24-hour period.
Atlantic herring, blueback herring and bay anchovy typically composed the majority (> 90 percent) of impinged species during the
course of the study period. Bay anchovy alone accounted for more than 72 percent of the sample population. Overall performance
numbers for the modified screens are greatly influenced by the survival rates for these three species. In general, the unmodified
screens demonstrated a substantially lower impingement survival rate when compared to the modified screens. The average 24-hour
survival for fish impinged on the unmodified screens was 15 percent. Fish impinged on the larger mesh (1/4") and smaller mesh (1/8")
modified screens had survival average 24-hour survival rates of 92 percent and 79 percent, respectively. Most species with low
survival rates on the unmodified screens showed a marked improvement on the modified screens. Bay anchovy showed a 24-hour
survival rate increase from 1 percent on the unmodified screens to 50 percent on the modified screens.
8-7
-------
S 316(b) Phase HI - Technical Development Document Efficacy of Cooling Water Intake Structure Technologies
The study period at the Arthur Kill station offered a unique opportunity to conduct a side-by-side evaluation of modified and
unmodified intake structures. The results for 24-hour post-impingement survival clearly show a marked improvement for all species
that had fared poorly on the conventional screens. The study notes that lower survival rates for fragile species such as Atlantic herring
might have been adversely affected by the collection tanks and protocols. Larger holding tanks appeared to improve the survival of
these species, suggesting that the reported survival rates may underrepresent the rate that would be achieved under normal
(unobserved) conditions, though by how much is unclear.
Dunkirk Steam Station
Dunkirk Steam Station is located on the southern shore of Lake Erie in New York. In 1998 a modified dual-flow traveling screen
system was installed on Unit 1 for an impingement mortality reduction study. The new system incorporated an improved fish bucket
design to minimize turbulence caused by flow through the screen face, as well as a nose cone on the upstream wall of the screen
assembly. The nose cone was installed to reduce the flow and velocity variations that had been observed across the screen face.
Samples were collected during the winter months of 1998/1999 and evaluated for 24-hour survival. Four species (emerald shiner,
juvenile gizzard shad, rainbow smelt, and spottail shiner) compose nearly 95 percent of the sample population during this period. All
species exhibited high 24-hour survival rates; rainbow smelt fared worst at 83 percent. The other three species had survival rates of
better than 94 percent. Other species were collected during the sampling period but were not present in numbers significant enough to
warrant a statistical analysis.
The results presented above represent one season of impingement sampling. Species not in abundance during cooler months might be
affected differently by the intake structure. Sampling continued beyond the winter months, but EPA has not yet been reviewed by
EPA.
Kintigh Station
Kintigh Station is located on the southern shore of Lake Ontario in New York. The facility operates an offshore intake in the lake with
traveling screens and a fiberglass fish return trough. Fish are removed from the screens and deposited in the return trough by a low-
pressure spray wash (10 psi). It is noted that the facility also operates with an offshore velocity cap. This does not directly affect the
survival rate offish impinged against the screen but might alter the distribution of species subject to impingement on the screen.
Samples were collected seasonally and held for observation at multiple intervals up to 96 hours. Most species exhibited a high
variability in their rate of survival depending on the season. Rainbow smelt had a 96-hour survival rate of 95 percent in the spring and
a 22 percent rate in the fall. (The rate was 1.5 percent in summer but the number of samples was small.) Alewife composed the
largest number among the species in the sample population. Survival rates were generally poor (0 percent to 19 percent) for spring and
summer sampling before the system was modified 1989. After the screen assembly had been modified to minimize stress associated
with removal from the screen and return to the waterbody, alewife survival rates increased to 45 percent. Survival rates were not
adjusted for possible influence from handling and observation stresses because no control study was performed.
Culvert Cliffs Nuclear Power Plant
Calvert Cliffs Nuclear Power Plant is located on the eastern shore of the Chesapeake Bay in Maryland. The facility used to have
conventional traveling screens on its intake screen assemblies. Screens were rotated for 10 minutes every hour or when triggered by a
set pressure differential across the screen surface. A spray wash system removed impinged fish and debris into a discharge trough.
The original screens have since been converted to a dual-flow design. The data discussed in the 1975-1981 study period are related to
the older conventional screen systems.
Sampling periods were determined to account for the varying conditions that might exist due to tides and time of day. Impingement
and survival rates were estimated monthly based on the number and weights of the individual species in the sample collection. No
control studies accompanied the impingement survival evaluation although total impingement data and estimated mortalities were
provided for comparative purposes. Latent survival rates were not evaluated for this study; only initial survival was included.
Five species typically constituted over 90 percent of the sample population in the study years. Spot, Atlantic menhaden, Atlantic
silverside, bay anchovy, and hogchoker had composite initial survival rates of 84, 52, 54, 68 and 99 percent, respectively. Other
species generally had survival rates greater than 75 percent, but these data are less significant to the facility-wide survival rate given
their low percentage of the overall sample population (< 8 percent). Overall, the facility showed an initial survival rate of 73 percent
for all species.
8-8
-------
§ 316(b) Phase III - Technical Development Document Efficacy of Cooling Water Intake Structure Technologies
It is notable that the volume of impingement data collected by Calvert Cliffs NPP (over 21 years) has enabled the facility to anticipate
possible large impingement events by monitoring fluctuations in the thermal and salinity stratification of the surrounding portion of the
Chesapeake Bay. When possible, operational changes during these periods (typically mid to late summer) might allow the facility to
reduce cooling water intake volume, thereby reducing the potential for impingement losses. The facility has also studied ways to
maintain adequate dissolved oxygen levels in the intake canal to assist fish viability and better enable post-impingement survival and
escape.
Huntley Steam Station
Huntley Steam Station is located on the Niagara River in New York. The facility recently replaced four older conventional traveling
screens with modified Ristroph screens on Units 67 and 68. The modified screens are fitted with smoothly woven coarse mesh panels
on a rotating belt. A fish collection basket is attached to the screen face of each screen panel. Bucket contents are removed by low-
pressure spray nozzles into a fish return trough. High-pressure sprays remove remaining fish and debris into a separate debris trough.
The study does not contain the rotation interval of the screen or the screen speed at the time of the study.
Samples were collected over five nights in January 1999 from the modified-screen fish return troughs. All collected fish were sorted
according to initial mortality. Four targeted species (rainbow smelt, emerald shiner, gizzard shad, and alewife) were sorted according
to species and size and held to evaluate 24-hour survival rates. Together, the target species accounted for less than 50 percent of all
fish impinged on the screens. (An additional 6,364 fish were not held for latent survival evaluation.) Of the target species, rainbow
smelt and emerald shiners composed the greatest percentage with 57 and 37 percent, respectively.
Overall, the 24-hour survival rate for rainbow smelt was 84 percent; some variation was evident for juveniles (74 percent) and adults
(94 percent). Emerald shiner were present in the same general life stage and had a 24-hour survival rate of 98 percent. Gizzard shad,
both juvenile and adult, fared poorly, with an overall survival of 5 percent for juveniles and 0 percent for adults. Alewife were not
present in large numbers (n = 30) and had an overall survival rate of 0 percent.
The study notes the low survival rates for alewife and gizzard shad and posits the low water temperature as the principal factor. At the
Huntley facility, both species are near the northern extreme of their natural ranges and are more susceptible to stresses associated with
extremes in water conditions. The water temperatures at the time of collection were among the coldest of the year. Laboratory
evaluations conducted on these species at the same temperatures showed high degrees of impairment that would likely adversely affect
post-impingement survival. A control evaluation was performed to determine whether mortality rates from the screens would need to
be adjusted for waterbody or collection and handling factors. No discrepancies were observed, and therefore no corrections were made
to the final results. Also of note in the study is the inclusion of a spray wash collection efficiency evaluation. The spray wash and fish
return system were evaluated to determine the proportion of impinged fish that were removed from the buckets and deposited in the
fish trough instead of the debris trough. All species had suitable removal efficiencies.
2.7.2 Summary
Studies conducted at steam electric power generating facilities over the past three decades have built a sizable record demonstrating
the performance potential for modified traveling screens that include some form offish return. Comprehensive studies, such as those
cited above, have shown that modified screens can achieve an increase in the post-impingement survival of aquatic organisms that
come under the influence of cooling water intake structures. Hardier species, as might be expected, have exhibited survival rates as
high as 100 percent. More fragile species, which are typically smaller and more numerous in the source waterbody, understandably
have lower survival rates. Data indicates, however, that with fine tuning, modified screen systems can increase survival rates for even
the most susceptible species and bring them closer to the performance standards established under the final rule.
2.2 Cylindrical Wedgewire Screens
Technology Overview
Wedgewire screens are designed to reduce entrainment and impingement by physical exclusion and by exploitation of hydrodynamics
and the natural flushing action of currents present in the source waterbody. Physical exclusion occurs when the mesh size of the
screen is smaller than the organisms susceptible to entrainment. Screen mesh sizes range from 0.5 to 10 mm, with the most common
slot sizes in the 1.0 to 2.0 mm range. Hydrodynamic exclusion results from maintenance of a low through-slot velocity, which,
because of the screen's cylindrical configuration, is quickly dissipated. This allows organisms to escape the flow field (Weisberd et al.
1984). The name of these screens arises from the triangular or wedge-shaped 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
_
-------
S 316(b) Phase III - Technical Development Document Efficacy of Cooling Water Intake Structure Technologies
of the cross section to the incoming flow (Pagano et al. 1977). Wedgewire screens are also referred to as profile screens, Johnson
screens, or "vee wire".
General understanding of the efficacy of cylindrical wedgewire screens holds that in order to achieve the optimal reduction in
impingement mortality and entrainment, certain conditions must be met. First, the slot size must be small enough to physically prevent
the entrainment of the organisms identified as warranting protection. Larger slot sizes might be feasible in areas where eggs, larvae,
and some classes of juveniles are not present in significant numbers. Second, a low through-slot velocity must be maintained to
minimize the hydraulic zone of influence surrounding the screen assembly. A general rule of thumb holds that a lower through-slot
velocity, when combined with other optimal factors, will achieve significant reductions in entrainment and impingement mortality.
Third, a sufficient ambient current must be present in the source waterbody to aid organisms in bypassing the structure and to remove
other debris from the screen face. A constant current also aids the automated cleaning systems that are now common to cylindrical
wedgewire screen assemblies.
2.2.7 Example Studies
Although uniform national requirements under the proposed rule would only apply to manufacturing facilities, based on the co-
proposed thresholds, the technologies described for Phase III facilities are the same as those used by Phase II electricity generation
facilities to meet section 316(b) requirements. EPA considers the types of intakes and the technologies available to address
impingement and entrainment at Phase II facilities to be consistent with the intakes and technologies at Phase III existing facilities.
Laboratory Evaluation (EPRI2003)
EPRI recently published (May 2003) the results of a laboratory evaluation of wedgewire screens under controlled conditions in the
Alden Research Laboratory Fish Testing Facility. A principal aim of the study was to identify the important factors that influence the
relative rates of impingement and entrainment associated with wedgewire screens. The study evaluated characteristics such as slot
size, through-slot velocity, and the velocity of ambient currents that could best carry organisms and debris past the screen. When each
of the characteristics was optimized, wedgewire screen use became increasingly effective as an impingement reduction technology; in
certain circumstances it could be used to reduce the entrainment of eggs and larvae. EPRI notes that large reductions in impingement
and entrainment might occur even when all characteristics are not optimized. Localized conditions unique to a particular facility,
which were not represented in laboratory testing, might also enable successful deployment. The study cautions that the available data
are not sufficient to determine the biological and engineering factors that would need to be optimized, and in what manner, for future
applications of wedgewire screens.
Slot sizes of 0.5, 1.0, and 2.0 mm were each evaluated at two different through-slot velocities (0.15 and 0.30 m/s) and three different
channel velocities (0.08,0.15, and 0.30 m/s) to determine the impingement and entrainment rates offish eggs and larvae. Screen
porosities increase from 24.7 percent for the 0.5 mm screens to 56.8 percent for 2.0 mm screens. The study evaluated eight species
(striped bass, winter flounder, yellow perch, rainbow smelt, common carp, white sucker, alewife, and bluegill) because of their
presence in a variety of waterbody types and their history of entrainment and impingement at many facilities. Larvae were studied for
all species except alewife, while eggs were studied for striped bass, white sucker, and alewife. (Surrogate, or artificial, eggs of a
similar size and buoyancy substituted for live striped bass eggs.)
Individual tests followed a rigorous protocol to count and label all fish eggs and larvae prior to their introduction into the testing
facility. Approach and through-screen velocities in the flume were verified, and the collection nets used to recapture organisms that
bypassed the structure or were entrained were cleaned and secured. Fish and eggs were released at a point upstream of the wedgewire
screen selected to deliver the organisms at the centerline of the screens, which maximized the exposure of the eggs and larvae to the
influence of the screen. The number of entrained organisms was estimated by counting all eggs and larvae captured on the entrainment
collection net. Impinged organisms were counted by way of a plexiglass window and video camera setup.
In addition to the evaluations conducted with biological samples, Alden Laboratories developed a Computational Fluid Dynamics
(CFD) model to evaluate the hydrodynamic characteristics associated with wedgewire screens. The CFD model analyzed the effects
of approach velocity and through-screen velocities on the velocity distributions around the screen assemblies. Using the data gathered
from the CFD evaluation, engineers were able to approximate the "zone of influence" around the wedgewire screen assembly under
different flow conditions and estimate any influence on flow patterns exerted by multiple screen assemblies located in close proximity
to each other.
The results of both the biological evaluation and the CFD model evaluation support many of the conclusions reached by other
wedgewire screen studies, as well as in situ anecdotal evidence. In general, the lower impingement rates were achieved with larger
slot sizes (1.0 to 2.0 mm), lower through-screen velocities, and higher channel velocities. Similarly, the lowest entrainment rates were
—
-------
S 316(b) Phase III - Technical Development Document Efficacy of Cooling Water Intake Structure Technologies
seen with low through-screen velocities and higher channel velocities, although the lowest entrainment rates were achieved with
smaller slot sizes (0.5 mm). Overall impingement reductions reached as high as 100 percent under optimal conditions, and
entrainment reductions approached 90 percent. It should be noted that the highest reductions for impingement and entrainment were
not achieved under the same conditions. Results from the biological evaluation generally agree with the predictions from the CFD
model: the higher channel velocities, when coupled with lower through-screen velocities, would result in the highest rate of protection
for the target organisms.
JH Campbell
JH Campbell is located on Lake Michigan in Michigan, with the intake for Unit 3 located approximately 1,000 meters from shore at a
depth of 10.7 meters. The cylindrical intake structure has 9.5-mm mesh wedgewire screens and withdraws approximately 400 MOD.
Raw impingement data are not available, and EPA is not aware of a comprehensive study evaluating the impingement reduction
associated with the wedgewire screen system. Comparative analyses using the impingement rates at the two other intake structures (on
shore intakes with conventional traveling screens) have shown that impingement of emerald shiner, gizzard shad, smelt, yellow perch,
and alewife associated with the wedgewire screen intake has been effectively reduced to insignificant levels. Maintenance issues have
not been shown to be problematic at JH Campbell because of the far offshore location in deep water and the periodic manual cleaning
using water jets to reduce biofouling. Entrainment has not been shown to be of concern at the intake structure because of the low
abundance of entrainable organisms in the immediate vicinity of the wedgewire screens.
Eddystone Generating Station
Eddystone Generating Station is located on the tidal portion of the Delaware River in Pennsylvania. Units 1 and 2 were retrofitted to
include wide-mesh wedgewire screens and currently withdraw approximately 500 MGD from the Delaware River. Pre-deployment
data showed that over 3 million fish were impinged on the unmodified intake structures during a single 20-month period. An
automatic air burst system has been installed to prevent biofouling and debris clogging from affecting the performance of the screens.
EPA has not been able to obtain biological data for the Eddystone wedgewire screens but EPRI indicates that fish impingement has
been eliminate.
2.2.2 Other Facilities
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 than 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
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) facilities, 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 or 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. In 1982 and 1983 the State of Maryland conducted testing 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 were observed during the tests. In the late 1970s, Delmarva Power and Light conducted laboratory testing of fine-mesh
wedgewire screens for the proposed 1,540 MW Summit Power Plant. This testing showed that entrainment offish eggs (including
striped bass eggs) 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 3 weeks.
Applicability to Large-Capacity Facilities
EPA believes that cylindrical wedgewire screens can be successfully employed by large intake facilities under certain circumstances.
Although many of the current installations of this technology have been at smaller-capacity facilities, EPA does not believe that the
increased capacity demand of a large intake facility, in and of itself, is a barrier to deployment of this technology. Large water
withdrawals can be accommodated by multiple screen assemblies in the source waterbody. The limiting factor for a larger facility may
be the availability of sufficient accessible space near the facility itself because additional screen assemblies obviously consume more
8-11
-------
S 316(b) Phase HI - Technical Development Document Efficacy of Cooling Water Intake Structure Technologies
space on the waterbody floor and might interfere with navigation or other uses of the waterbody. Consideration of the impacts in
terms of space and placement must be evaluated before selecting wedgewire screens for deployment.
Applicability in High-Debris Waterbodies
As with any intake structure, the presence of large debris poses a risk of damage to the structure if not properly managed. Cylindrical
wedgewire screens, because of their need to be submerged in the water current away from shore, might be more susceptible to debris
interaction than other onshore technologies. Vendor engineers indicated that large debris has been a concern at several of their
existing installations, but the risk associated with it has been effectively minimized by selecting the optimal site and constructing
debris diversion structures. Significant damage to a wedgewire screen is most likely to occur from fast-moving submerged debris.
Because wedgewire screens do not need to be sited in the area with the fastest current, a less damage-prone area closer to shore or in a
cove or constructed embayment can be selected, provided it maintains a minimum ambient current around the screen assembly. If
placement in the main channel is unavoidable, deflecting structures can be employed to prevent free-floating debris from contacting
the screen assembly. Typical installations of cylindrical wedgewire place them roughly parallel to the direction of the current,
exposing only the upstream nose to direct impacts with debris traveling downstream. EPA has noted several installations where
debris-deflecting nose cones have been installed to effectively eliminate the damage risk associated with large debris.
Apart from the damage that large debris can cause, smaller debris, such as household trash or organic matter, can build up on the
screen surface, altering the through-slot velocity of the screen face and increasing the risk of entrainment and/or impingement of target
organisms. Again, selection of the optimal location in the waterbody might be able to reduce the collection of debris on the structure.
Ideally, cylindrical wedgewire is located away from areas with high submerged aquatic vegetation (SAV) and out of known debris
channels. Proper placement alone may achieve the desired effect, although technological solutions also exist to physically remove
small debris and silt. Automated air-burst systems can be built into the screen assembly and set to deliver a short burst of air from
inside and below the structure. Debris is removed from the screen face by the air burst and carried downstream and away from the
influence of the intake structure. Improvements to the air burst system have eliminated the timed cleaning cycle and replaced it with
one tied to a pressure differential monitoring system.
Applicability in High Navigation Waterbodies
Wedgewire screens are more likely to be placed closer to navigation channels than other onshore technologies, thereby increasing the
possibility of damage to the structure itself or to a passing commercial ship or recreational boat. Because cylindrical wedgewire
screens need to be submerged at all times during operation, they are typically installed closer to the waterbody floor than the surface.
In a waterbody of sufficient depth, direct contact with recreational watercraft or small commercial vessels is unlikely. EPA notes that
other submerged structures (e.g., pipes, transmission lines) operate in many different Waterbodies and are properly delineated with
acceptable navigational markers to prevent accidents associated with trawling, dropping anchor, and similar activities. Such
precautions would likely be taken for a submerged wedgewire screen as well.
2.2.3 Summary
Cylindrical wedgewire screens have been effectively used to mitigate impingement and, under certain conditions, entrainment impacts
at many different types of facilities over the past three decades. Although not yet widely used at steam electric power plants, 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 at 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
(closed-cycle systems). Nevertheless, 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. For example, there are no full-scale data available specifically for
marine environments where biofouling and clogging are significant concerns. Technological advances have been made to address
such concerns. Automated cleaning systems can now be built into screen assemblies to reduce the disruptions debris buildup can
cause. Likewise, vendors have been experimenting with different screen materials and coatings to reduce the on-screen growth of
vegetation and other organisms (zebra mussels).
Fine-mesh wedgewire screens (0.5 -1 mm) also have the potential for use to control both impingement and entrainment. EPA is not
aware of the installation of any fine-mesh wedgewire screens at any power plants with high intake flows (> 100 MOD). However,
such screens have been used at some power plants with lower intake flow requirements (25 to 50 MGD), which would be comparable
to a very large power plant with a closed-cycle cooling system. With the exception of Logan, EPA has not identified any full-scale
performance data for these systems. They could be even more susceptible to clogging than wide-mesh wedgewire screens (especially
in marine environments). It is unclear whether clogging would simply necessitate more intensive maintenance or preclude their day-
to-day use at many sites. Their successful application at Logan and Cope and the historical test data from Florida, Maryland, and
Delaware at least suggest promise for addressing both fish impingement and entrainment of eggs and larvae. However, based on the
_—
-------
S 316(b) Phase IH - Technical Development Document Efficacy of Cooling Water Intake Structure Technologies
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 (readily accessible).
Manual cleaning needs might be reduced or eliminated through use of an automated flushing (e.g., microburst) system.
2.3 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 of
fish 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 control of both
impingement and entrainment. However, they have not been installed, maintained, and optimized at many facilities.
2.3.1 Example Facilities
Although uniform national requirements under the proposed rule would only apply to manufacturing facilities, based on the co-
proposed thresholds, the technologies described for Phase III facilities are the same as those used by Phase II electricity generation
facilities to meet section 316(b) requirements. EPA considers the types of intakes and the technologies available to address
impingement and entrainment at Phase II facilities to be consistent with the intakes and technologies at Phase III existing facilities.
Big Bend
The most significant example of long-term use of fine-mesh screens 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 drums 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.
2.3.2 Other Facilities
Although egg and larvae entrainment performance data 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 an overall 86 percent initial survival rate 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 or study at several sites and from laboratory and pilot-scale tests. Seasonal use of fine mesh on two of
four screens at the Brunswick Power Plant in North Carolina has shown 84 percent reduction in entrainment compared to the
conventional screen systems. Similar results were obtained during pilot testing of 1-mm screens at the Chalk Point Generating Station
in Maryland. At the Kintigh Generating Station in New Jersey, pilot testing indicated that 1-mm screens provided 2 to 35 times the
reduction 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 of up to 99 percent for 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 with 1- and 2-mm screens combined.
8-13
-------
§ 316(b) Phase III - Technical Development Document Efficacy of Cooling Water Intake Structure Technologies
2.3.3 Summary
Despite the lack of fall-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 reduction is contingent on optimized operation and intensive maintenance to avoid biofouling
and clogging, especially in marine environments. It might also be appropriate to use removable fine mesh that is installed only during
periods of egg and larval abundance, thereby reducing the potential for clogging and wear and tear on the systems.
2.4 Fish Net Barriers
Technology Overview
Fish net barriers are wide-mesh nets that are placed in front of the entrance to intake structures. The size of the mesh needed is a
function of the species present at a particular site and varies from 4 mm to 32 mm (EPRI2000). The mesh must be sized to prevent
fish from passing through the net, which could cause them to be 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 offish and other organisms requires fish diversion facilities at only specific times of the year.
Technology Performance
Barrier nets can provide a high degree of impingement reduction by preventing large fish from entering the vicinity of the intake
structure. Because of typically wide openings, they do not reduce entrainment of eggs and larvae. A number of barrier net systems
have been used or studied at large power plants.
2.4.1 Example Studies
Although uniform national requirements under the proposed rule would only apply to manufacturing facilities, based on the co-
proposed thresholds, the technologies described for Phase III facilities are the same as those used by Phase II electricity generation
facilities to meet section 316(b) requirements. EPA considers the types of intakes and the technologies available to address
impingement and entrainment at Phase II facilities to be consistent with the intakes and technologies at Phase III existing facilities.
JP Pulliam Station
The JP Pulliam Station is located on the Fox River in Wisconsin. Two separate nets with 6-mm mesh are deployed on opposite sides
of a steel grid supporting structure. The operation of a dual net system facilitates the cleaning and maintenance of the nets without
affecting the overall performance of the system. Under normal operations, nets are rotated at least two times per week to facilitate
cleaning and repair. The nets are typically deployed when the ambient temperature of the intake canal exceeds 37°F. This usually
occurs between April 1 and December 1.
Studies undertaken during the first 2 years after deployment showed an overall net deterrence rate of 36 percent for targeted species
(noted as commercially or recreationally important, or forage species). Improvements to the system in subsequent years consisted of a
new bulkhead to ensure a better seal along the vertical edge of the net and additional riprap along the base of the net to maintain the
integrity of the seal along the bottom of the net. The improvements resulted in a deterrence rate of 98 percent for some species; no
species performed at less than 85 percent. The overall effectiveness for game species was better than 90 percent while forage species
were deterred at a rate of 97 percent or better.
JR Whiting Plant
The JR Whiting Plant is located on Maumee Bay of Lake Erie in Michigan. A 3/8-inch mesh barrier net was deployed in 1980 as part
of a best technology available determination by the Michigan Water Resources Commission. Estimates of impingement reductions
were based on counts of fish impinged on the traveling screens inside the barrier net. Counts in years after the deployment were
compared to data from the year immediately prior to the installation of the net when over 17 million fish were impinged. Four years
after deployment, annual impingement totals had fallen by 98 percent.
Bowline Point
Bowline Point is located on the Hudson River in New York. A 150-foot long, 0.95-cm mesh net has been deployed in a V-shaped
configuration around the intake pump house. The area of the river in which the intake is located has currents that are relatively
stagnant, thus limiting the stresses to which the net might be subjected. Relatively low through-net velocities (0.5 feet per second)
have been maintained across a large portion of the net because of low debris loadings. Debris loads directly affecting the net were
reduced by including a debris boom outside the main net. An air bubbler was also added to the system to reduce the buildup of ice
during cold months.
_—
-------
§ 316(b) Phase III - Technical Development Document Efficacy of Cooling Water Intake Structure Technologies
The facility has attempted to evaluate the reduction in the rate of impingement by conducting various studies of the fish populations
inside and outside the barrier net. Initial data were used to compare impingement rates from before and after deployment of the net
and showed a deterrence of 91 percent for targeted species (white perch, striped bass, rainbow smelt, alewife, blueback herring, and
American shad). In 1982 a population estimate determined that approximately 230,000 striped bass were present in the embayment
outside the net area, A temporary mesh net was deployed across the embayment to prevent fish from leaving the area. A 9-day study
found that only 1.6 percent of the estimated 230,000 fish were ultimately impinged on the traveling screens. A mark-recapture study
that released individual fish inside and outside the barrier net showed similar results, with more than 99 percent offish inside the net
impinged and less than 3 percent offish outside the net impinged. Gill net capture studies sought to estimate the relative population
densities offish species inside and outside the net. The results agreed with those of previous studies, showing that the net was
maintaining a relatively low density offish inside the net as compared to the outside.
2.4.2 Summary
Barrier nets have clearly proven effective for controlling impingement (i.e., more than 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 can also be a concern but it can be addressed through frequent maintenance. In addition, barrier nets are also
often used only 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 might be further
limited by the physical constraints and other uses of the waterbody.
2.5 Aquatic Microfiltration Barriers
Technology Overview
Aquatic microfiltration barrier systems are barriers that employ a filter fabric designed to allow water to pass 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 the cooling water system. These systems can be
floating, flexible, or fixed. Because these systems usually have such a large surface area, the velocities maintained at the face of the
permeable curtain are very low. One company, Gunderboom, Inc., has a patented full-water-depth filter curtain composed 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 off of sediment buildup and release any other material back into the water column.
Technology Performance
EPA has determined that microfiltration barriers, including the Gunderboom, show significant promise for minimizing entrainment.
EPA acknowledges, however, that the 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 that facility showed significant potential for reducing entrainment.
Entrainment reductions of up to 82 percent were observed for eggs and larvae, and these levels were maintained for extended month-
to-month periods during 1999 through 2001. At Lovett, some operational difficulties 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 participates. Each of
the challenges encountered at Lovett could be of 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 5 feet. The Gunderboom system is 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 gpm intakes would require filter systems 500
and 1,000 feet long (assuming a 20-foot depth). In some locations, this may preclude the successful deployment of the system because
of space limitations or conflicts with other waterbody uses.
8-15
-------
§ 316(b) Phase in - Technical Development Document Efficacy of Cooling Water Intake Structure Technologies
2.6 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 both 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 that 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. Because eggs
and early stages of larvae cannot swim away, they are not affected by the diversions and there is no associated reduction in
entrainment.
Although 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; 306,200 were
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, was 50 percent or less. The facility has also
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 to 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. These findings are generally consistent with the American Society of Civil Engineers' (ASCE) findings from the
late 1970s, which showed that 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). The overall guidance
efficiency was found to be 75 to 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 along the San Joaquin River in California, testing was
performed from 1993 and 1995 to determine the guidance efficiency of a system with primary and secondary louvers. The results for
green and white sturgeon, American shad, splittail, white catfish, delta smelt, chinook salmon, and striped bass showed mean diversion
efficiencies ranging from 63 percent (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 (more than 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.
2.7 Angled and Modular Inclined Screens
Technology Overview
Angled traveling screens use standard through-flow traveling screens in which the screens are set at an angle to the incoming flow.
Angling the screens improves the fish protection effectiveness because 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, in which 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).
8-16
-------
§ 316(b) Phase III - Technical Development Document Efficacy of Cooling Water Intake Structure Technologies
Technology Performance
Angled traveling screens with fish bypass and return systems work similarly to louver systems. They also provide only potential
reductions in impingement mortality because eggs and larvae will not generally detect the factors that influence diversion. Like 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 to 70 percent) for northern anchovies and
moderate to good guidance (60 to 90 percent) for other species. Latent survival varied by species: fragile species had only 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 at 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 that evaluated the angled screens from 1984 through 1986 showed a diversion
efficiency of 76 percent with a latent survival of 63 percent. Much higher results were observed excluding bay anchovy.
Finally, 1981 full-scale studies of an angled screen system at the Danskammer Station along the Hudson River in New York showed
diversion efficiencies of 95 to 100 percent with a mean of 99 percent. Diversion efficiency combined with latent survival yielded a
total effectiveness of 84 percent. Species included bay anchovy, blueback herring, white perch, spottail shiner, alewife, Atlantic
tomcod, pumpkinseed, and American shad.
During the late 1970s and early 1980s, Alden Research Laboratories 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. Followup tests for Niagara Mohawk confirmed 100 percent
diversion efficiency for alewife with mortalities only 4 percent higher than those in 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 1-week mean mortality was only 3 percent. Alden performed further tests during 1978 to 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-mm screens can provide post larvae
diversion efficiencies of greater than 80 percent. The tests found, however, that latent mortality for diverted species was also high.
Finally, EPRI tested 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 the mortalities were comparable to control mortalities. Based on the laboratory data, an 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 were also observed for largemouth and
smallmouth bass, yellow perch, and bluegill. Lower diversion efficiency and survival were found for herring.
In October 2002, EPRI published the results of a combined louver/angled screen assembly study that evaluated the diversion
efficiencies of various configurations of the system. In 1999, fish guidance efficiency was evaluated with two bar rack configurations
(25- and 50-mm spacings) and one louver configuration (50-mm clearance), with each angled at 45 degrees to the approach flow. In
2000, the same species were evaluated with the 50-mm bar racks and louvers angled at 15 degrees to the approach flow. Diversion
efficiencies were evaluated at various approach velocities ranging from 0.3 to 0.9 m/s.
Guidance efficiency was lowest, generally lower than 50 percent, for the 45 degree louver/bar rack array, with efficiencies distributed
along a bell shaped curve according to approach velocity. For the 45 degree array, diversion efficiency was best at 0.6 m/s, with most
species approaching 50 percent. All species except one (lake sturgeon) experienced higher diversion efficiencies with the louver/bar
rack array set at 15 degrees to the approach flow. With the exception of lake sturgeon, species were diverted at 70 percent or better at
most approach velocities.
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.
8-17
-------
S 316(b) Phase III - Technical Development Document Efficacy of Cooling Water Intake Structure Technologies
2.8 Velocity Caps
Technology Description
A velocity cap is a device that is placed over a vertical inlet at an offshore intake. This cover converts vertical flow into horizontal
flow at the entrance to the intake. The device works on the premise that fish will avoid rapid changes in horizontal flow but are less
able to detect and avoid vertical velocity vectors. Velocity caps have been installed at many offshore intakes and have usually been
successful in minimizing impingement.
Technology Performance
Velocity caps can reduce the number offish drawn into intakes based on the concept that they tend to avoid rapid changes in
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, such as screens with fish returns.
Therefore, there are somewhat limited data on their performance when used alone. Facilities that have velocity caps include the
following:
• Oswego Steam Units 5 and 6 in New York (combined with angled screens on Unit 6).
• San Onofre Units 2 and 3 in California (combined with louver system).
• El Segundo Station in California
• Huntington Beach Station in California
Edgewater Power Plant Unit 5 in Wisconsin (combined with 9.5-mm wedgewire screen)
Nanticoke Power Plant in Ontario, Canada
• Nine Mile Point in New York
Redondo Beach Station in California
• Kintigh Generation Station in New York (combined with modified traveling screens)
• Seabrook Power Plant in New Hampshire
St. Lucie Power Plant in Florida
• Palisades Nuclear Plant in Michigan
At the Huntington Beach and Segundo stations in California, velocity caps have been found to provide 80 to 90 percent reductions in
fish entrapment. At Seabrook, the velocity cap on the offshore intake has minimized the number of pelagic fish entrained except for
pollock. Finally, two facilities in England each have velocity caps on one of 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 by 62 percent compared to intake A.
2.9 Porous Dikes and Leaky Dams
Technology Overview
Porous dikes, also known as leaky dams or dikes, are filters that resemble 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 as both a physical and a 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 buildup, and colonization by fish 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. They will not, however, prevent
entrainment by nonmotile 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, and the Agency is not aware of any full-scale porous dike or leaky
dam systems currently used at power plants in the United States. 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 those for 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.
8-18
-------
§ 316(b) Phase HI - Technical Development Document Efficacy of Cooling Water Intake Structure Technologies
• Testing at the Brayton Point Station 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 the 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.
2.10 Behavioral Systems
Technology Overview
Behavioral devices are designed to enhance fish avoidance of intake structures or to 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 species avoid light; however, it is also known that some species are attracted by light.
• Sound Barriers: Sound barriers are noncontact 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 sectional area. The general purpose of air bubble barriers is to repel fish that might 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, for example,
EPRI2000. For the most part, these studies have been inconclusive or have shown no significant 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 might 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 impingement reductions were observed for rainbow smelt and gizzard shad.
Testing of sound systems in 1993 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 those for Fitzpatrick and Pickering. Impingement of gizzard shad was also three times lower
than that 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 toward an individual species (e.g.,
alewife).
2.11 Other Technology Alternatives
Use of variable speed pumps can provide for greater system efficiency and have reduced flow requirements (and associated
entrainment) by 10 to 30 percent. EPA Region 4 estimated that use of variable speed pumps at the Canaveral and Indian River stations
in the Indian River estuary would reduce entrainment by 20 percent. Presumably, such pumps could be used in conjunction with other
technologies to meet the performance standards.
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 the pipes were specifically designed to screen out detritus, not to
protect fish (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, but I&E performance data for these facilities are unavailable. In general, EPA projects that perforated pipe system
performance should be comparable to that of wide mesh wedgewire screens (e.g., at Eddystone Units 1 and 2 and Campbell Unit 3).
8-19
-------
S 316(b) Phase HI - Technical Development Document Efficacy of Cooling Water Intake Structure Technologies
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;
there was, however, a substantial increase in impingement survival for surrperch and rockfish.
Facilities might be able to use recycled cooling water to reduce their intake flow needs. The Brayton Point Station has a "piggyback"
system in which 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 it reduces the make-up water needs (and thereby entrainment) by 29 percent.
2.12 Intake Location
Beyond design alternatives for CWISs, an operator might be able to relocate CWISs offshore or in others areas that minimize I&E
(compared to conventional onshore locations). In conjunction with offshore inlet technologies such as cylindrical wedgewire t-screens
or velocity caps, the relocated offshore intake could be quite effective at reducing impingement and/or entrainment effects. However,
the action of relocating at existing facilities is costly due to significant civil engineering works. 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 (the shore zone areas where light penetrates to the bottom) 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, 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 and 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 and rivers). Use of the deepest open water region of a lake or 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 and reservoirs, rivers are managed for numerous benefits, which include sustainable and robust fisheries. Unlike lakes
and reservoirs, the hydrodynamics of rivers typically result in a mixed water column and overall unidirectional flow. There are many
similarities in the reproductive strategies of shoreline fish populations in rivers and the reproductive strategies offish within the littoral
zone of lakes and reservoirs. Planktonic movement of eggs, larvae, post larvae, and early juvenile organisms along the shore zone is
generally limited to relatively short distances. As a result, the shore zone placement of CWISs in rivers might potentially impact local
spawning populations offish. The impact potential associated with entrainment might 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 shore zone eggs and larvae, as well as the near-surface drift community of ichthyoplankton, is minimized. Impacts
could also be minimized by controlling the timing and frequency of withdrawals from rivers. In temperate regions, the number of
entrainable or 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 can 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. With local knowledge of these characteristics, however, the entrainment effects of a CWIS could be minimized
by adjusting the intake design to areas (e.g., depths) least likely to affect concentrated numbers and species of organisms.
In oceans, nearshore coastal waters are typically the most biologically productive areas. The euphotic zone (zone light available for
photosynthesis) typically does not extend beyond the first 100 meters (328 feet) of depth. Therefore, inshore waters are generally
more productive due to photosynthetic activity and due to the input from estuaries and runoff of nutrients from land.
There are only limited published data quantifying the locational differences in I&E rates at individual power plants. Some
information, however, 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 feet offshore (with a velocity cap) in the Atlantic Ocean. This approach avoided impacts on
the biologically sensitive Indian River estuary.
——
-------
§ 316(b) Phase III - Technical Development Document Efficacy of Cooling Water Intake Structure Technologies
• 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 the area from 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 finding 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.
II. Offshore Oil and Gas Extraction Facilities
INTRODUCTION
To identify suitable technologies to minimize impingement mortality and entrainment of fish in typical seawater intake structures for
offshore oil and gas extraction facilities, the Agency evaluated currently known technologies and other possible technologies. Known
technologies include standard screens, velocity caps and barrier nets. Other technologies identified include acoustic barriers, air
curtains and electric barriers. Technologies such as acoustic or electric barriers may be particularly valuable to limit impingement on
difficult to modify systems, such as sea chests. This evaluation also includes technologies for anti bio-fouling systems. Current anti
bio-fouling technology includes chemical injection at the intake, air sparging of screens and the use of Cu-Ni alloys on the intake
screen surfaces.
An alternative technology must prove to be practical before progressing it as a viable alternative to current technology. The primary
criteria for a practical/acceptable alternative configuration/technology is that it is successfully implemented at one or more facilities,
including other manufacturing industries with a similar seawater intake structure, anywhere around the world.
In addition to identifying appropriate fish barrier technologies, this section characterize typical seawater intake structures used by
offshore oil and gas extraction facilities.
1.0 AVAILABLE TECHNOLOGIES
1.1 Known Technologies
Known technologies evaluated include standard screens, velocity caps, and barrier nets as discussed in the previous section. Each
technology is discussed below with respect to its potential use with offshore oil and gas extraction facilities.
1.1.1 Passive Intake Screens
Passive intake screens covers the whole range of static screens that act as a physical barrier to fish entrainment. These barriers
include:
• Simple mesh over an open pipe end (caisson or simple intake pipe) with a suitably low face velocity to prevent impingement,
• Grill or mesh spanning an opening (as used on sea chest) with a suitably low face velocity to prevent impingement, and
• Cylindrical and wedgewire T-screens designed for the purpose of protecting fish stocks (suitable for caissons or simple intake
pipes but not sea chests). Passive intake screens are very commonly used throughout industry and are readily available.
Fine mesh wedgewire screens (0.5-1mm) have been identified as having potential to prevent both entrainment and impingement. (See
the Phase I Technical Development Document (EPA-821-R-01-036), DCN 3-0002). The main drawback practical with this fish
barrier solution is that the screens are prone to blockages as a result of bio-fouling. Since this type of equipment is so common, an
investigation into anti bio-fouling technology is presented below.
The use of a passive intake screen on a sea chest (as used by some mobile offshore drilling units (MODUs)) may be prone to
impingement issues. This is because the size of the opening of a sea chest into the ocean is essentially fixed. To increase the size of a
sea chest would be very costly due to significant works at a dry dock. A passive screen that has a suitably low face velocity may
therefore have to protrude outside the hull of the vessel. This would have a negative impact on the hydrodynamics of the vessel and
create a catch point under the waterline. Alternatively, the passive screen may be used in conjunction with another technology such as
an acoustic or electro barrier to reduce impingement. Due to the success of passive intake screens at many installations around the
world, this type of technology is a suitable fish barrier for use/retrofit on offshore oil and gas extraction facilities.
__
-------
§ 316(b) Phase III - Technical Development Document Efficacy of Cooling Water Intake Structure Technologies
7.7.2 Velocity Caps
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. 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 (1982), velocity caps are often used in conjunction with
other fish protection devices. Therefore, there is somewhat limited data on their performance when used alone.
In the case of offshore oil and gas extraction facilities, velocity caps may be used in conjunction with a passive intake screen (as
described above). However, the bio-fouling drawback of a passive intake screen would also be present. Other possible barriers to use
in conjunction with a velocity cap may include the "other" technologies noted below (such as acoustic barriers). Velocity caps, when
used in conjunction with another barrier may be a suitable fish barrier technology for offshore oil and gas extraction facilities that use
a simple pipe intake or a caisson. The use of a velocity cap on a sea chest (as used by some MODUs) is unlikely to be a practical
technology. This is because the size of the opening of a sea chest into the ocean is essentially fixed. To increase the size of a sea chest
would very costly due to significant works at a dry dock. A velocity cap over the inlet would therefore have to protrude outside the
hull of the vessel. This would have a negative impact on the hydrodynamics of the vessel and create a catch point under the waterline.
7.7.3 Barrier Nets
Barrier nets are typically utilized in locations where impingement is a problem. In these situations, a net is used to keep relatively large
fish away from an intake screen. 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. A number of
barrier net systems have been used/studied at large onshore power plants. 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.
Bio-fouling can also be a concern but this can be addressed through frequent maintenance. Barrier nets are also often only used
seasonally, where the source water body 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 water body. Barrier nets are not suitable for use on MODUs since the net would be a major hindrance
to the operation of the vessel. Fixed platforms may potentially use barrier nets to reduce impingement problems. The configuration
that may be practical is to set the nets up in removable panels around the intake. At this stage, an example of this type of paneled net
configuration is not available.
1.1.4 Perforated Intake Pipe
A perforated pipe arrangement draws water through perforations or elongated slots in a cylindrical section placed in the water body.
Early designs of this technology were not efficient, velocity distribution was poor, and they were specifically designed to screen out
debris and not for the protection of aquatic organisms. Perforated caissons or simple pipes have been used on some fixed platforms.
For example: Marathon South Pass (Block 86) use a 20" inner diameter simple pipe with bottom at 59' below water level. The lower
8' pipe section is slotted with bottom open, slots are 1"W x 4"L, slots spaced 3" apart along circumference and 8" apart vertically.
Since impingement and entrainment performance data for perforated pipe arrangements are unavailable, the use of this technology is
questionable. 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).
7.7.5 Traveling Screens (Includes Angular and Modular Screens)
Traveling screens are generally used on onshore facilities that incorporate large stilling and pump pits. The traveling screen installation
requires a significant amount of specifically designed structure to be included in the intake design. Retrofitting a structure to accept a
traveling screen on offshore oil and gas extraction facilities would be impractical and extremely costly. Furthermore, the maintenance
of a sub-sea traveling screen retrofitted to an existing structure would also be impractical and very costly. The design of traveling
intake screens is not suited to offshore oil and gas extraction facilities. As such, this technology has been deemed to be unsuitable for
these facilities.
8-22
-------
§ 316(b) Phase HI - Technical Development Document Efficacy of Cooling Water Intake Structure Technologies
1.1.6 Porous Dikes and Leaky Dams
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. Clearly the construction of a fixed major civil installation such as a porous dam or leaky dike is not possible for MODUs. The
use of this type of equipment on fixed platforms may also be rejected due to the fact that if one were constructed in the middle of the
ocean it would be extremely impractical and costly and result in the death or dislocation of a large number of marine wildlife. As
such, this technology has been deemed to be unsuitable for the facilities evaluated here.
2.0 OTHER TECHNOLOGIES
Other technologies reviewed include acoustic barriers, air curtains, electro fish barriers, intake location, keel cooling, and strobe lights
and illumination. Each technology is discussed below with respect to its potential use in minimizing impingement and entrainment at
offshore oil and gas extraction facilities.
2.1 Acoustic Barriers
Although there is simplicity in the concept of an acoustic fish deterrent, it is apparent that the use of sound for fish repulsion is not a
simple task. The use of sound has been established as an effective means of repelling many species offish. The major problems with
acoustic barriers are that some sounds repel some fish yet have no effect or attract others, and fish may, over time, become
desensitized to a sound that would otherwise scare them away. There have been a number of studies undertaken on specific fish
entrainment issues at specific locations. However, from a commercial perspective, supply of acoustic barrier equipment is not
commonly available. Fish Guidance Systems Limited (FGS) from Southampton in the United Kingdom design and manufacture a
range of acoustic barriers for large industrial water intakes.
For fish to be repelled by a sound, a number of criteria must be met (derived from www.fish-guide.com):
• The fish must be able to detect the frequencies used to compose the deterrent signal.
• The sound signal composition must be of a type that is repellent to fish (some sounds attract, others have no effect);
• The level of the sound must be high enough to elicit a reaction, taking account of background noise.
The issue of background noise is important, especially where acoustic systems are deployed near underwater machinery such as pumps
and turbines. In such cases, it may be necessary to measure the underwater noise spectra under typical operating conditions.
Underwater noise may be repellent to fish if:
• Noise of any type having frequencies that lie within the fish hearing range is emitted at very high audio levels (but this is very
expensive and may impact other biota);
• The characteristics of the noise have any special biological meaning to the fish (e.g., mimicking the approach of a predator);
• The noise is designed by experimentation to cause particularly strong avoidance.
The biological approach may offer good possibilities for individual species, but the empirical approach has yielded a number of signal
types that are effective against a wide range of species. The signal types that have proved most effective in all applications are based
on artificially generated waveforms that rapidly cycle in amplitude and frequency content, thus reducing habituation. A human
equivalent would be being made to stand near to a wailing police or ambulance siren. It simply gets uncomfortable, so you move
away. In practice, considerable attention needs to be given to the design and specification of a system to ensure it achieves high fish
deflection efficiencies. Key variables include the type offish, background noise, hydraulic conditions (eg. intake velocities, attraction
flow to the fish pass) and acoustic design. Acoustic systems may be designed primarily either to block or to deflect fish movement.
Deflection is usually the best course of action, as the fish are moved swiftly from the source of danger (e.g., water intake) into a safe
flow. Blocking can be more difficult if the fish are not moved away from the area, as the risk of habituation to the sound signals
becomes increased. This can be overcome to some extent by changing the signal pattern at intervals but acoustic deterrents are
essentially a mild form of stimulus less effective than electric barriers purely for blocking. For this reason it is advised that a well-
designed and suitably placed bypass facility be provided.
Sound projectors are electro-mechanical devices and regular maintenance of them is required to ensure optimum performance. This
involves removing the underwater units to replace perished seals and to check moving components. Also, it is desirable to raise and
_
-------
§ 316(b) Phase HI - Technical Development Document Efficacy of Cooling Water Intake Structure Technologies
clean the units occasionally to remove any build-up of silt or fouling. It is necessary to provide a deployment system to bring sound
projectors to the surface for maintenance, without the need to use divers.
As it is difficult to check the performance of submerged equipment, diagnostic units can be attached to the control electronics to
monitor performance of the sound projectors.
2.1.1 Example Installations
It must be noted that the examples of Acoustic Barriers did not include any facilities that fall into the category of offshore oil and gas
extraction facilities. However, the following installations share similarities with fixed offshore structures. The use of this equipment
on sea chests or mobile equipment may be possible but is not proven by example.
Doel Power Station - SPA System
Doel nuclear power station operated by Electrabel responded to concerns expressed by environmental regulators and fishermen to
reduce the numbers offish that were being drawn into their cooling water intake each year. The main species being affected were
herring and sprat (clupeid family).
In 1997, a SPA fish deterrent system was designed and installed on the offshore intake. In total, 20 large FGS Mk II30-600 sound
projectors were installed to create a repellent sound field close to the water intake openings causing passing fish to veer away. A
multiple signal generator was used to avoid resident species habituating to any one sound signal. To allow servicing of the fish
deterrent system while the station is still operating, a deployment frame has been installed to lower sound projectors into their optimum
position and to allow them to be raised for routine inspections and maintenance.
The acoustic installation has subsequently undergone a number of evaluation trials by researchers from Belgium's Leuven University.
Independent trials have shown a reduction in the target species by 98%. In addition, the catch of other non-target species has been
reduced with the overall reduction being 81%.
Foss Flood Relief Pumping Station SPA System
The Environment Agency responded to a fish kill at the River Foss Flood Alleviation Pumping Scheme in York (UK). The scheme
consists of a barrier gate to prevent floodwater from the River Ouse flowing up the River Foss. Water flowing down the Foss is
pumped from the upstream side of the floodgate by eight vertical, axial flow propeller pumps, and discharged below the gate. Fish
damage was attributable to contact with moving machinery and rapid pressure changes during passage through the pumps.
In 1994, an acoustic fish deflection system was installed to deflect fish away from pumps prior to and during operation. As the pump
inlets formed a popular shelter for resident fish, the acoustic system was designed to start operating 15 minutes prior to the pumps
operating. The SPA installation also provided important protection to resident fish while the pumps were operating by creating a
gradient of deterrent sound, increasing towards the intake openings. The installation comprised six FGS Mk I Model 30-600 sound
projectors.
A series of independent trials were performed to test the effectiveness of an acoustic fish deterrent system in 1994. Coarse fish
representing 12 species were captured during the trial. The most abundant species were bleak, dace, chub, perch and common bream.
Prior to the trial, it was previously considered that the sudden commencement of pumping accounted for a larger proportion of the fish
entrained through the pumps, as the enclosed environment of the pump channels provided a potential refuge for fish. It was found that
the majority offish were drawn into the Foss Basin during pumping. The acoustic system was found to reduce overall fish
entrainment by 80% with the system deflecting fish in the pumpwells and outside the Foss Basin during operation.
Other Installations
Central Hidroelectrica de Allones, Spain: Four 15-100 Sound Projector Array system supplied to deflect fish away from a head
race channel entrance. (August 2000)
Blackdyke Water Transfer Pumping Station, UK: Eight 15-100 Sound Projector Array system supplied to deflect fish out of
pumping station chambers, prior to and during water transfers. (July 2000)
Great Yarmouth CCGT, UK: Eight 30-600 Sound Projector Array system supplied for cooling water system to new CCGT power
station. (July 2000)
__
-------
S 316(b) Phase III - Technical Development Document Efficacy of Cooling Water Intake Structure Technologies
• Shoreham CCGT, UK: Six 30-600 Sound Projector Array system supplied for cooling water intake to new CCGT power station.
(June 2000)
Drinking Water Abstraction, River Stour, UK: Six 15-100 Sound Projector Array system supplied for drinking water abstraction.
(April 2000)
2.1.2 A caustic Barrier Conclusions
Acoustic barriers have proven to be effective as fish impingement and entrainment barriers. Since there is no fine mesh covering the
intake, this type of barrier is not prone to issues with bio-fouling.
This type of equipment is commercially available and has been proven effective at a number of locations.
The typical application of this technology has been onshore-based intake structures rather than offshore oil and gas extraction
facilities. The transfer of this technology to offshore oil and gas extraction facility intake structures may be possible with further
development. It is particularly interesting for fitting to sea chest intake structures.
2.2 Air Curtains
Air curtains are simply a screen of bubbles used to guide fish away from an intake structure. Air bubbles have proven to have some
effect for herding and guiding fish or as a barrier to their normal activity (Bibko et al. 1973). However, the effectiveness of air bubble
curtains at water intakes varies greatly (NEST 1996). Northeast Science and Technology (NEST) undertook a detailed study into the
effectiveness of many different types of technology for preventing lake Sturgeon impingement and entrainment for the Little Long
Generating Station Facilities (NEST 1996). This facility is located in Northeastern Ontario on the Mattagami River and represents one
of the last refuges for lake Sturgeon.
Overall, air curtains on their own do not effectively deter fish or substantially reduce impingement (Zweiacker et al. 1977; Lieberman
and Muessig 1978; Patrick et al. 1988: NEST 1996). Factors that reduce the effectiveness of an air curtain include:
water temperature (Bibko et al. 1973),
• fish crowding (Smith 1961),
• the presence of predators (Smith 1961), and
• levels of light (Alevras 1973).
The effectiveness of an air curtain may be improved when used in combination with acoustic deterrents. When a pneumatic popper is
used in combination with an air curtain, there is an improved overall effectiveness. This same effect is not observed with use of strobe
lights (Patrick et al. 1988). Supply of air curtain and acoustic barrier equipment is not commonly available. Fish Guidance Systems
Limited (FGS) from Southampton in the United Kingdom design and manufacture a device that utilizes both a bubble curtain and an
acoustic deterrent for large industrial water intakes.
The BAFF is used to divert fish from a major flow, e.g., entering a turbine, into the minor flow of a fish pass channel. It may be
regarded as analogous to a conventional angled fish screen. It uses an air bubble curtain to contain a sound signal that is generated
pneumatically. Effectively, this creates a "wall of sound" (an evanescent sound field) field that can be used to guide fish around river
structures by deflection into fish passes.
Physically, the BAFF comprises a pneumatic sound transducer coupled to a bubble-sheet generator, causing sound waves to propagate
within the rising curtain of bubbles. The sound is contained within the bubble curtain as a result of refraction, since the velocity of
sound in a bubble-water mixture differs from that in either water or air alone. The sound level inside the bubble curtain may be as high
as 170 dB re ImPa, typically decaying to 5% of this value within 0.5-1 m from the bubble sheet. It can be deployed in much the same
way as a standard bubble curtain, but its effectiveness as a fish barrier is greatly enhanced by the addition of a repellent sound signal.
The characteristics of the sound signals are similar to those used in SPA systems, i.e., within the 20-500 Hz frequency range and using
frequency or amplitude sweeps.
8-25
-------
S 316(b) Phase. Ill - Technical Development Document Efficacy of Cooling Water Intake Structure Technologies
FGS acoustic BAFF systems comprise the following components:
• BAFF Unit: The BAFF system comprises of modular sections, each 2.4 m long, which are linked together to form the required
length. The acoustic signal is entrapped in the bubbles by a driver unit and the resulting 'wall of sound' produces an uninterrupted
guidance system.
• Air Blower or Compressor: The BAFF uses an air blower or compressor to supply pressurised air to create a continuous bubble
curtain.
• Air Blower/Compressor Pipe: A temperature / pressure resistant pipe delivers air from the air blower or compressor to the BAFF
control equipment.
• BAFF Control Equipment and Control Lines: The BAFF control equipment is used to operate the BAFF system. A main air
supply and two control lines feed driver units fitted on each of the BAFF units. Solenoids located in the returning control line
regulate the airflow to the driver units. Pressure feedback lines run from the BAFF units back to the control panel to allow
pressure within the BAFF to be monitored. An alarm system indicates a sudden drop in pressure resulting from a failure in air
supply.
2.2.7 Example Installations
It must be noted that the examples found did not include any facilities that fall into the category of offshore oil and gas extraction
facilities. However, the following installations share similarities with fixed offshore structures. The use of this equipment on sea
chests or mobile equipment may be possible but is not proven by example.
Beeston Hydro-electric Station
• Beeston Weir Hydro Scheme, a 1.3MW station was commissioned in May 2000. The £3 million ($ 5.5 million USD) Beeston
Hydro Scheme was installed at an existing weir on the River Trent near Nottingham in the UK. A prime objective of the new
hydro was to make the scheme fit the environment, and not the other way around.
• The river supports a mixed population of resident coarse fish and migratory eels. Owing to a history of poor water quality, the
river currently has a very small population of salmonoid fish. However, the Environment Agency has a program underway of
continuous improvement of water quality, with the goal of restoring the salmonoid population.
• To divert downstream migrating fish away from the headrace channel, a 80m long BAFF system was installed. It is located
diagonally upstream of the weir to guide juvenile salmon and other fish moving downstream to the fish ladder. A new vertical
single slot fish pass was added to facilitate upstream and downstream passage of both salmonoid and coarse fish, prior to
construction of the hydro facility.
• The BAFF system produces a "wall of underwater sound" by using compressed air to generate a continuous bubble curtain into
which low frequency sound (varying between 50 and 500 Hertz) is injected and entrapped. Although well-defined lines of high
level sound (at least 160 decibels) are generated within the bubble curtain, the noise levels are negligible a few meters away from
it. By restricting the sound curtain to a small area, the system allows fish to act normally throughout the remainder of the
reservoir or river.
• A Smith-Root graduated electric barrier is located just below the power plant to divert adult salmon migrating upstream away
from the tailrace and into the fish ladder.
Other Installations
Backbarrow Hydro, UK: Eleven units BAFF system supplied to guide fish in headrace channel to a purpose built by wash.
(August 2000)
• Blantyre, Hydro Station, Scotland, UK: Combined Sound Projector Array and BAFF system installed on low-head hydro-electric
power station for evaluation trials. Results published in ETSU report H/01/00046/REP
www.dti.gov.uk/NewReview/nr32/html/fish.htmHSpring 1996)
• Northampton, Inland Waterway Pumping Station, UK: Two bubble curtain system installed on canal pumping station intake to
reduce transfer of zander. (January 1999)
8-26
-------
§ 316(b) Phase III - Technical Development Document Efficacy of Cooling Water Intake Structure Technologies
2.2.2 Air Curtain Conclusions
Air curtains have proven to be ineffective barriers to impingement and entrairanent offish stocks when they are use on their own.
When used in combination with other acoustic deterrent systems, their effectiveness is greatly increased. This equipment type of
equipment is commercially available and has been proven effective at a number of locations.
The typical application of this technology has been on hydro-electric power station intake structures rather than offshore oil and gas
extraction facilities. The transfer of this technology to offshore oil and gas extraction facility intake structures may be possible with
further development. As such, this technology has the potential to become suitable after further development.
2.3 Electro Fish Barriers
Electrical fields are frequently used to frighten, attract, stun or kill fish. On approaching the field, many fish exhibit a fright reaction
and may be repelled (NEST, 1996).
The following information was obtained from the Smith-Root web page (www.smith-root.com). Smith-Root is a leading supplier of
Electro Fish barriers:
Electric current passing between the electrodes, via the water medium, produces an electric field. When fish are within the field, they
become part of the electrical circuit with some of the current flowing through their body. The electric current passing through fish can
evoke reactions ranging from a slight twitch to full paralysis, depending on the current level and shock duration they receive. (Smith-
Root.com)
One of the most important advantages of the parallel field orientation is that when a fish is crosswise to the electric field it receives
almost no electric shock. Fish learn very quickly that by turning side ways to the flow they can minimize the effects of the electric
field.
2.3.1 Example Installations
Great Lakes Division - 80" Mill, Pump House #2 (1994)
Ecorse, Michigan
Barrier Type: Smith-Root Concrete weir with bottom mounted electrodes.
Keeps gizzard shad and other river fish from entering the pumping systems used for steel mill cooling. Previously, dense fish runs
caused several shutdowns each year. Since installation in 1994, they have not had single shutdown attributed to fish runs.
Shields Lake
Forest Lake, Minnesota 1996
Barrier Type: Smith-Root Plastic culvert with stainless steel electrodes. Keeps carp from entering Shields Lake.
Heron Lake
Worthington, Minnesota 1993
Barrier Type: Smith-Root Concrete weir with bottom mounted electrodes.
Keeps carp from entering Heron Lake. Barrier is very effective and currently in operation. This once sterile lake is now restored to a
bird and game fish habitat.
2.3.2 Electro Fish Barrier Conclusions
Electro Fish Barriers have proven to be effective as fish impingement and entrainment barriers. The main limitation is that the high
conductivity of seawater limits the size of a practical electro barrier. Discussions with a supplier of this type of equipment (Smith-
Root) stated that a practical installation would be possible at a caisson or sea chest opening. Electro Fish Barriers are commercially
available and have been shown to be effective at a number of locations. The most common location for this technology to be used is
on river or lake intake locations for power stations where local fish stocks are to be protected.
8-27
-------
§ 316(b) Phase III - Technical Development Document Efficacy of Cooling Water Intake Structure Technologies
The typical application of this technology has been onshore-based intake structures rather than offshore oil and gas extraction
facilities. The transfer of this technology to offshore oil and gas extraction facility intake structures may be possible with further
development. As such, this technology has the potential to become suitable after further development. It is particularly interesting for
fitting to sea chest intake structures.
2.4 Intake Location
Beyond technology design alternatives, an operator may able to locate cooling water intake structures offshore or otherwise in areas
that minimize entrainment and impingement (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 entrainment and
impingement of organisms is higher (Phase I Technical Development Document (EPA-821-R-01-036), DCN 3-0002)).
In oceans, nearshore coastal waters are generally the most biologically productive areas. The euphotic zone (zone of photosynthetic
available light) typically does not extend beyond the first 100 meters (328 feet) of depth. Therefore, nearshore waters are generally
more productive due to photosynthetic activity, and due to the input from estuaries and run-off of nutrients from land (Phase I
Technical Development Document (EPA-821-R-01-036), DCN 3-0002)).
Woodside Energy Limited in Western Australia indicated that the depth of the intake structure may be used as a method of controlling
fish entrainment in offshore oil and gas extraction facility seawater intake structures. Unfortunately, no further details on the systems
that are employed by Woodside are currently known.
2.4.1 Intake Location Conclusions
Intake location appears to offer potential in reducing entrainment and impingement of marine organisms. This type of technology may
be implemented on fixed platforms that are located in deep water. A detailed marine study into the density of organisms would be
required for this approach to be successful. This type of technology is not suitable for MODUs since they would operate in various
locations, depths and environments. Furthermore, a variable depth sea chest would be impractical.
2.5 Keel Cooling
Keel cooling is a process which bypasses the need to draw cooling water on board a vessel. This is achieved by installing a heat
exchanger in the waterbody and pumping cooling water through a closed loop system. This technology was developed during the
Second World War and is commonly used on many vessels today. The Shine Fisheries Factory Trawlers operating out of Fremantle in
Western Australia use keel cooling for all cooling water on all of their vessels.
Fernstram Company has confirmed that this system is suitable for retrofitting to an existing on-board cooling water system.
Furthermore, it is not limited to mobile vessels. The coolers may be designed using natural convection (fixed structure) rather than
forced convection (moving structure) to meet a heat transfer requirement. Therefore, this equipment could be used on the cooling
water systems of stationary or mobile offshore oil and gas extraction facilities. It is believed that Brown and Root installed one of the
Fernstram systems on a new offshore oil and gas extraction facility approximately 20 years ago. Unfortunately details of this system
are currently unavailable. Bio-fouling of keel coolers is limited with the use of Cu-Ni alloys for fabrication. See Anti Bio-fouling
Technologies below.
2.5.1 Keel Cooling Conclusions
Keel cooling is a suitable technology for MODUs. Stationary offshore oil and gas extraction facilities may also be able to benefit from
this technology.
2.6 Strobe Lights and Illumination
The reaction offish to light is not consistent. It changes with the type of light, intensity, angular distribution, polarization and duration
(Hocutt 1980). Some fish may exhibit a positive response to a light source while the same light may repel others. Also, the reaction of
a fish to a light source may vary depending on the life stage of the particular species (Fore 1969). Studies have been undertaken into
the use of strobe lights. The effectiveness of a strobe has been found to vary with species, time of day and fish size (Taft et al 1987).
Compared with other behavioral barriers, strobe lights and other illumination generally appear to be the least effective. A combination
of strobe lights and air curtains are more effective for repelling fish than either on their own but were less effective than the air curtain
8-28
-------
S 316(b) Phase III - Technical Development Document Efficacy of Cooling Water Intake Structure Technologies
/ acoustic deterrents (NEST 1996). Based on this research, strobe lights and illumination may be rejected as a suitable technology on
their own. However, their use in combination with other technologies may prove to be successful.
3.0 ANTI BIO FOULING TECHNOLOGIES
Several anti bio-fouling technologies are available including air sparges, copper-nickel (Cu-Ni) alloys, chemical injection, and hot kill.
Each technology and its potential application to offshore oil and gas extraction facilities is discussed below.
3.1 Air Sparges
The use of compressed air (air sparges) to physically remove bio matter from a screen face is commonly used in the industry. It is
particularly useful when drifting seaweed or trash (such as plastic bags) impinges on the screen face.
This is a suitable technology in most marine areas. In the case that there are prolific marine organisms that may grow on the screen
surface such as molluscs (zebra mussel), corral or seaweed growth, further methods may need to be taken to protect the screen, such as
use of specific materials or "hot kill" which are described later in this section.
3.2 Cu-Ni Alloys
Alloys of copper and nickel have been found to limit marine growth on a submerged surface. These alloys are used in the manufacture
of screen surfaces to prevent problems with invasive marine growth.
Johnson Screens offer screens manufactured from "Z Alloy" (90/10 CuNi). This material is commonly used for other sea water
equipment (such as in plate types heat exchangers). This technology has proven to be suitable for seawater fabricated screen
applications.
3.3 Chemical Injection
There are many chemicals that may be used to prevent bio-fouling of sea water systems. These include solutions of chlorine, copper
and many other possible biocides. These systems are generally designed to mix in with the intake flow and protect the down stream
process rather than the screen face. It would be very difficult and expensive to design a chemical system to protect an entire intake
screen from bio-fouling. Furthermore, there would be a significant impact to the environment around the intake structure. Therefore,
chemical injection for the protection of an intake barrier is considered impractical and not a suitable technology for this purpose.
3.4 Hot Kill
The Hot Kill process involves recirculating hot water back through the intake structure to kill any marine growth than may have
attached to the intake pipe or screen.
Kwinana Power Station is a medium sized multi fuel (gas, oil and coal) power station that has operated in Cockburn Sound Western
Australia for more than 40 years. The Sound is the natural habitat of the Blue Mussel, which grows prolifically throughout the area.
The power station was designed with two separate intake systems (one unit on line, the other offline). The intake systems include a
sub sea screened intake (mesh size unknown), inlet pipe of approximately 500m and an onshore concrete stilling sump with travelling
(rotatory) screens. Auto chlorination (electrolysis) is used to treat the water after the rotating screens before the cooling water pumps.
The mussels in the intake system have been controlled by recirculating the hot water return back through the offline intake unit. This
is done for 2 hours at a temperature of 46-48'C (115-118'F). After the 2 hour kill has been achieved, the discharge flow is sent back to
the main discharge channel. This system has worked well for a number of years in an environment of prolific mussel growth.
Unfortunately retrofitting offshore oil and gas extraction facilities with additional intakes (if required), cross over piping, and hot water
return is very expensive. This type of solution is best incorporated during the design phase of a facility.
III. CONCLUSION
As suggested by the technology studies evaluated in this chapter, the technologies presented can substantially reduce impingement
mortality and entrainment. With proper design, installation, and operation and maintenance, a facility can realize marked reductions.
However, EPA recognizes that there is a high degree of variability in the performance of each technology, which is in part due to the
_
-------
S 316(b) Phase HI - Technical Development Document Efficacy of Cooling Water Intake Structure Technologies
site-specific environmental conditions at a given facility. EPA also recognizes that much of the data cited in this document was
collected under a variety of performance standards and study protocols that have arisen over the years since EPA promulgated its last
guidance in 1977.
EPA believes that these technologies can meet the performance standards established in today's final rule. While EPA acknowledges
that site-specific factors may affect the efficacy of impingement and entrainment reduction technologies, EPA believes that there are a
reasonable number of options available from which most facilities may choose to meet the performance standards. EPA also believes
that, in cases where one technology can not meet the performance standards alone, a combination of additional intake technologies,
operational measures and/or restoration measures can be employed to meet the performance standards.
8-30
-------
S 316(b) Phase III - Technical Development Document Efficacy of Cooling Water Intake Structure Technologies
REFERENCES
Alevras, R.A. 1973. Status of air bubble fish protection system at Indian Point Station on the Hudson River, pp. 289-291. In
Entrainment and Intake Screening Workshop, Johns Hopkins University.
American Electric Power Corporation. March, 1980. Philip Sporn Plant 316(bt Demonstration Document.
American Society of Civil Engineers. 1982. Design of Water Intake Structures for Fish Protection. Task Committee on Fish-Handling
Capability of Intake Structures of the Committee on Hydraulic Structures of the Hydraulic Division of the American Society of Civil
Engineers.
Bailey et. al. Undated. Studies of Cooling Water Intake Structure Effects at PEPCO Generating Stations.
Bibko, P.N., L. Wirtenan, and P.E. Kueser. 1973. Preliminary studies on the effects of air bubbles and intense illumination on the
swimming behavior of the striped bass (Morone saxitalis) and the gizzard shad (Dorosoma cepedianum). pp. 293-304. In Entrainment
and Intake Screening Workshop, Johns Hopkins University.
CK Environmental. June, 2000. Letter from Charles Kaplan, CK Environmental, to Martha Segall, Terra Tech, Inc. June 26, 2000.
Duke Energy, Inc. April, 2000. Moss Landing Power Plant Modernization Project. 316(¥) Resource Assessment.
Ecological Analysts, Inc. 1979. Evaluation of the Effectiveness of a Continuously Operating Fine Mesh Traveling Screen for
Reducing Ichthvoplankton Entrainment at the Indian Point Generating Station. Prepared for Consolidated Edison, Inc.
Edison Electric Institute (EEI). 1993. EEI Power Statistics Database. Prepared by the Utility Data Institute for the Edison Electric
Institute.
Ehrler, C. and Raifsnider, C. April, 1999. "Evaluation of the Effectiveness of Intake Wedgewire Screens." Presented at EPRI Power
Generation Impacts on Aquatic Resources Conference.
Electric Power Research Institute (EPRI). 1999. Fish Protection at Cooling Water Intakes: Status Report.
EPA, 2003. Oil and Gas Platform Data: IADC Industry Survey
EPA, 2003. Cooling Water Use by Offshore Seafood Processing Vessels.
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.
Fish Guidance Systems Limited (FGS): Designer and supplier of a range of acoustic barriers for large industrial water intakes.
www.fish-guide.com.
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.
Fore, P.L. 1969. Responses of freshwater fishes to artificial light. Ph.D. Disser., South. IL. Univ., 86pp. (cited from Hocutt, 1980).
Fournier P. 1983. Passive Screening at Surface Water Intakes. Johnson Screen Division.
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).
_
-------
S 316(b) Phase HI - Technical Development Document Efficacy of Cooling Water Intake Structure Technologies
Hocutt, C.H. 1980. Behavioral barriers and guidance systems, pp. 183-205. In Hocutt et at. (ed.) Power Plants: Effects on fish and
shellfish behavior. Academic Press. New York.
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.
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.
Lieberman, J.T. and P.H. Muessig. 1978. Evaluation of an air bubble to mitigate fish impingement at an electric generating plant.
Estuaries. 1:129-132.
Lifton, W.S. Undated. Biological Aspects of Screen Testing on the St. John's River. Palatka. Florida.
Loeffelman, P.H., J.H. Van Hassel, and D.A. Klinect. 1991. Using sound to divert fish from turbine intakes. Hydro rev. 10(6):30-37.
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 Hermann, P. February, 1978. "Biological and Engineering Considerations in the Fine Screening of
Small Organisms from Cooling Water Intakes." In: Proceedings of the Workshop on Larval Exclusion Systems for Power Plant
Cooling Water Intakes, Sponsored by Argonne National Laboratory (ANL Publication No. ANL/ES-66).
Mussalli, Y.G., Taft, E.P, and Larsen, J. November, 1980. "Offshore Water Intakes Designated to Protect Fish." In: Journal of the
Hydraulics Division, Proceedings of the America Society of Civil Engineers. Vol. 106, No HY11.
Northeast Science & Technology (NEST) Technical Report TR-031 May 1996: Mattagami River Lake Sturgeon Entrainment: Little
Long Generating Facilities. J. Seyler, J. Evers, Dr. S. McKinley, R. Evans, G. Prevost, R. Carson, D. Phoenix, eds.
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.
Patrick, P.H., R.S. McKinley, and W.C. Micheletti. 1988. Field testing of behavioral barriers for cooling water intake structures - Test
Site 1 - Pickering Nuclear Generating Station, pp. 4-13-25. In Proceedings: fish protection at steam and hydro-electric power plants.
EPRI/AP-5663. Electric Power Research Institute. Palo Alto, CA.
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.
8-32
-------
§ 316(b) Phase HI - Technical Development Document Efficacy of Cooling Water Intake Structure Technologies
Ringger, T.J. April, 1999. "Baltimore Gas and Electric, Investigations of Impingement of Aquatic Organisms at the Calvert Cliffs
Nuclear Power Plant, 1975-1999." Presented at EPRI Power Generation Impacts on Aquatic Resources Conference.
Sharma, R.K. February, 1978. "A Synthesis of Views Presented at the Workshop." In: Larval Exclusion Systems For Power Plant
Cooling Water Intakes.
Smith, K.A. 1961. Air-curtain fishing for marine sardines. Comm. Fish. Rev., 23(3):1 14. (cited from Hocutt, 1980).
Taft, E.P. April, 1999. "Alden Research Laboratory, Fish Protection Technologies: A Status Report." Presented at EPRI Power
Generation Impacts on Aquatic Resources Conference.
Taft, E.P. March, 1999. PSE&G Renewal Application. Appendix F. Salem Generation Station.
Taft, E.P. et. al. 1981. "Laboratory Evaluation of the Larval Fish Impingement and Diversion Systems." In: Proceedings of Advanced
Intake Technology.
Taft, E.P., J.K. Downing, and C.W. Sullivan. 1987. Studies offish protection methods at hydro-electric plants, pp. 512-521. in
Waterpower '87.
Tennessee Valley Authority (TVA). 1976. A State of the Art Report on Intake Technologies.
U.S. Environmental Protection Agency (EPA), Region 4. May, 1983. 316a and 316b Finding for Cape Canaveral/Orlando Utilities
Plants at Canaveral Pool.
U.S. Environmental Protection Agency (EPA), Region 4. September, 1979. Brunswick Nuclear Steam Electric Generating Plant.
Historical Summary and Review of Section 316(fr) Issues.
U.S. Environmental Protection Agency (EPA). November 2001. Technical Development Document for the Final Regulations
Addressing Cooling Water Intake Structures for New Facilities. EPA -821-R-01-036.
University of Michigan. 1985. Impingement Losses at the D.C. Cook Nuclear Power Plant During 1975-1982 with a Discussion of
Factors Responsible and Possible Impact on Local Populations.
Versar, Inc. April, 1990. Evaluation of the Section 316 Status of Delaware Facilities with Cooling Water Discharges. Prepared for
State of Delaware Department of Natural Resources.
Weisberg, S.B., Jacobs, F., Burton, W.H., and Ross, R.N. 1983. Report on Preliminary Studies Using the Wedge Wire Screen Model
Intake Facility. Prepared for State of Maryland, Power Plant Siting Program.
Zweiacker, P.J., J.R. Gaw, E. Green, and C. Adams. 1977. Evaluation of air-bubble curtain to reduce impingement at an electric
generating station. Proceedings of the Thirty-First Annual Conference Southeastern Association of Fish and Wildlife Agencies. 31:
343-356.
8-33
-------
-------
S 316(b) Phase HI - Technical Development Document Attachment A to Chapter 8
Attachment A to Chapter 8
COOLING WATER INTAKE STRUCTURE TECHNOLOGY FACT SHEETS
-------
; III - Technical Development Document
Attachment A to Chapter 8
-------
§ 316(b) Phase HI - Technical Development Document ....... Attachment A to Chapter 8
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).
8A-3
-------
S 316(b) Phase HI - Technical Development Document
Attachment A to Chapter 8
Intake Screening Systems
Fact Sheet No. 1: Single-Entry, Single-Exit
Vertical Traveling Screens (Conventional
Traveling Screens)
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:
Limitations:
Conventional traveling screens are a proven "off-the-shelf technology that is readily
available.
Impingement and entrainment are both major problems in this unmodified standard
screen installation, which is designed for debris removal not fish protection.
References:
ASCE. Design of Water Intake Structures for Fish Protection. Task Committee on Fish-Handling
Capability of Intake Structures of the Committee on Hydraulic Structures of the Hydraulic Division of
the American Society of Civil Engineers, New York, NY. 1982.
EEI Power Statistics Database. Prepared by the Utility Data Institute for the Edison Electric Institute.
8A-4
-------
§ 316(b) Phase III - Technical Development Document Attachment A to Chapter 8
Intake Screening Systems
Fact Sheet No. 1: Single-Entry, Single-Exit
Vertical Traveling Screens (Conventional
Traveling Screens)
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.
Pagano R. and W.H.B. Smith. Recent Developments in Techniques to Protect Aauatic Organisms at the
Intakes of Steam-Electric Power Plants. MITRE Co
U S EPA Development Document for Best T
rporation Technical Report 767 1 . November 1 977.
echnologv 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 -76/0 15-a. April 1976.
8A-5
-------
S 316(b) Phase IH - Technical Development Document Attachment A to CKapter 8
Intake Screening Systems
Fact Sheet No. 2: Modified Vertical
Traveling Screens
Description:
Modified vertical traveling screens are conventional traveling screens fitted with a collection
"bucket" beneath the screen panel. This intake screening system is also called a bucket screen,
Ristroph screen, or a Surry Type screen. The screens are modified to achieve maximum
recovery of impinged fish by maintaining them in water while they are lifted to a release point.
The buckets run along the entire width of the screen panels and retain water while in upward
motion. At the uppermost point of travel, water drains from the bucket but impinged organisms
and debris are retained in the screen panel by a deflector plate. Two material removal systems
are often provided instead of the usual single high pressure one. The first uses low-pressure
spray that gently washes fish into a recovery trough. The second system uses the typical high-
pressure spray that blasts debris into a second trough. Typically, an essential feature of this
screening device is continuous operation which keeps impingement times relatively short
(Richards, 1977; Mussalli, 1977; Pagano et al., 1977; EPA, 1976).
Testing Facilities and/or Facilities Using the Technology:
Facilities which have tested the screens include: the Surry Power Station in Virginia (White
et al, 1976) (the screens have been in operation since 1974), the Madgett Generating Station in
, Wisconsin, the Indian Point Nuclear Generating Station Unit 2 in New York, the Kintigh
(formerly Somerset) Generating Station in New Jersey, the Bowline Point Generating Station
(King et al, 1977), the Roseton Generating Station in New York, the Danskammer Generating
Station in New York (King et al, 1977), the Hanford Generating Plant on the Columbia River
in Washington (Page et al, 1975; Fritz, 1980), the Salem Genereating on the Delaware River
in New Jersey, and the Monroe Power Plant on the Raisin River in Michigan.
Research/Operation Findings:
Modified traveling screens have been shown to have good potential for alleviating impingement
mortality. Some information is available on initial and long-term survival of impinged fish
(EPRI, 1999; ASCE, 1982; Fritz, 1980). Specific research and operation findings are listed
below:
• In 1986, the operator of the Indian Point Station redesigned fish troughs on the Unit
2 intake to enhance survival. Impingement injuries and mortality were reduced from
53 to 9 percent for striped bass, 64 to 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
8A-6
-------
S 316(b) Phase HI - Technical Development Document Attachment A to Chapter 8
Intake Screening Systems
Fact Sheet No. 2: Modified Vertical
Traveling Screens
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).
Design Considerations:
Advantages:
The same design considerations as for Fact Sheet No. 1: Conventional Vertical
Traveling Screens apply (ASCE, 1982).
Traveling screens are a proven "off-the-shelf technology that is readily available. An
essential feature of such screens is continuous operation during periods where fish are
being impinged compared to conventional traveling screens which operate on an
intermittent basis
Limitations:
• The continuous operation can result in undesirable maintenance problems (Mussalli,
1977).
• Velocity distribution across the face of the screen is generally very poor.
Latent mortality can be high, especially where fragile species are present.
References:
ASCE. Design of Water Intake Structures for Fish Protection. Task Committee on Fish-Handling
Capability of Intake Structures of the Committee on Hydraulic Structures of the Hydraulic
Division of the American Society of Civil Engineers, New York, NY. 1982.
8A-7
-------
S 316(b) Phase HI - Technical Development Document Attachment A to Chapter 8
Intake Screening Systems
Fact Sheet No. 2: Modified Vertical
Traveling Screens
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.
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) Ecolbgical 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.
8A-8
-------
§ 316(b) Phase III - Technical Development Document Attachment A to Chapter 8
Intake Screening Systems
Sheet No. 3: Inclined Single-Entry, Single-
Exit Traveling Screens (Angled
Screens)
Description:
Inclined traveling screens utilize standard through-flow traveling screens where the screens are
set at an angle to the incoming flow as shown in the figure below. Angling the screens improves
the fish protection effectiveness of the flush mounted vertical screens since the fish tend to
avoid the screen face and move toward the end of the screen line, assisted by a component of
the inflow velocity. A fish bypass facility with independently induced flow must be provided.
The fish have to be lifted by fish pump, elevator, or conveyor and discharged to a point of
safety away from the main water intake (Richards, 1977).
Testing Facilities and/or Facilities Using the Technology:
Angled screens have been tested/used at the following facilities: the Brayton Point Station Unit
4 in Massachusetts; the San Onofre Station in California; and at power plants on Lake Ontario
and the Hudson River (ASCE, 1982; EPRI, 1999).
Research/operation Findings:
• Angled traveling screens with a fish return system have been used on the intake for
Brayton Point Unit 4. Studies from 1984 through 1986 that evaluated the angled
screens showed a diversion efficiency of 76 percent with latent survival of 63 percent.
Much higher results were observed excluding bay anchovy. Survival efficiency for the
major taxa exhibited an extremely wide range, from 0.1 percent for bay anchovy to 97
percent for tautog. Generally, the taxa fell into two groups: a hardy group with
efficiency greater than 65 percent and a sensitive group with efficiency less than 25
percent (EPRI, 1999).
• Southern California Edison at its San Onofre steam power plant had more success with
angled louvers than with angled screens. The angled screen was rejected for full-scale
use because of the large bypass flow required to yield good guidance efficiencies in the
test facility.
Design Considerations:
Many variables influence the performance of angled screens. The following recommended
preliminary design criteria were developed in the studies for the Lake Ontario and Hudson
River intakes (ASCE, 1982):
• Angle of screen to the waterway: 25 degrees
• Average velocity of approach in the waterway upstream of the screens: 1 foot per
8A-9
-------
S 316(b) Phase HI - Technical Development Document
Attachment A to Chapter 8
Intake Screening Systems
Sheet No. 3: Inclined Single-Entry, Single-
Exit Traveling Screens (Angled
Screens)
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).
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.
8 A-10
-------
§ 316(b) Phase III - Technical Development Document Attachment A to Chapter 8
Intake Screening Systems
Fact Sheet No.4: Fine Mesh Screens
Mounted on Traveling Screens
Description:
Fine mesh screens are used for screening eggs, larvae, and juvenile fish from cooling water
intake systems. The concept of using fine mesh screens for exclusion of larvae relies on gentle
impingement on the screen surface or retention of larvae within the screening basket, washing
of screen panels or baskets to transfer organisms into a sluiceway, and then sluicing the
organisms back to the source waterbody (Sharma, 1978). Fine mesh with openings as small as
0.5 millimeters (mm) has been used depending on the size of the organisms to be protected.
Fine mesh screens have been used on conventional traveling screens and single-entry, double-
exit screens. The ultimate success of an installation using fine mesh screens is contingent on the
application of satisfactory handling and recovery facilities to allow the safe return of impinged
organisms to the aquatic environment (Pagano et al, 1977).
Testing Facilities and/or Facilities Using the Technology:
The Big Bend Power Plant along Tampa Bay area has an intake canal with 0.5-mm mesh
Ristroph screens that are used seasonally on the intakes for Units 3 and 4. At the Brunswick
Power Plant in North Carolina, fine mesh used seasonally on two of four screens has shown
84 percent reduction in entrainment compared to the conventional screen systems.
Research/Operation Findings:
During the mid-1980s when the screens were initially installed at Big Bend, their
efficiency in reducing impingement and entrainment mortality was highly variable.
The operator evaluated different approach velocities and screen rotational speeds.
In addition, the operator recognized that frequent maintenance (manual cleaning)
was necessary to avoid biofouling. By 1988, system performance had improved
greatly. The system's efficiency in screening fish eggs (primarily drums and bay
anchovy) exceeded 95 percent with 80 percent latent survival for drum and 93
percent for bay anchovy. For larvae (primarily drums, bay anchovies, blennies,
and gobies), screening efficiency was 86 percent with 65 percent latent survival for
drum and 66 percent for bay anchovy. Note that latent survival in control samples
was also approximately 60 percent (EPRI, 1999).
At the Brunswick Power Plant in North Carolina, fine mesh screen has led to 84
percent reduction in entrainment compared to the conventional screen systems.
Similar results were obtained during pilot testing of 1-mm screens at the Chalk
Point Generating Station hi 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
8 A-11
-------
S 316(b) Phase HI - Technical Development Document Attachment A to Chopter 8
Intake Screening Systems
Fact Sheet No.4: Fine Mesh Screens
Mounted on Traveling Screens
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 low so that if there is any impingement of larvae on
the screens, it is gentle enough not to result in damage or mortality.
• The wash spray for the screen panels or the baskets should be low-pressure so as not
to result in mortality.
• The sluiceway should provide smooth flow so that there are no areas of high
turbulence; enough flow should be maintained so that the sluiceway is not dry at any
time.
• The species life stage, size and body shape and the ability of the organisms to
withstand impingement should be considered with time and flow velocities.
• The type of screen mesh material used is important. For instance, synthetic meshes
may be smooth and have a low coefficient of friction, features that might help to
minimize abrasion of small organisms. However, they also may be more susceptible
to puncture than metallic meshes (Mussalli, 1977).
Advantages:
• There are indications that fine mesh screens reduce entrainment.
8 A-12
-------
S 316(b) Phase III - Technical Development Document Attachment A to Chapter 8
Intake Screening Systems
Fact Sheet No.4: Fine Mesh Screens
Mounted on Traveling Screens
Limitations:
Fine mesh screens may increase the impingement offish, i.e., they need to be used
in conjunction with properly designed and operated fish collection and return
systems.
Due to the small screen openings, these screens will clog much faster than those
with conventional 3/8-inch mesh. Frequent maintenance is required, especially in
marine 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. EPRICS/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. Hofrnann. "Engineering Implications of New Fish Screening
Concepts". In Fourth Workshop on Larval Exclusion Systems For Power Plant Cooling Water
Intakes. San-Diego, California, February 1978, pp 367-376.
Sharma, R.K.,"A Synthesis of Views Presented at the Workshop". In Larval Exclusion Systems For
Power Plant Cooling Water Intakes.San-Diego. California, February 1978, pp 235-237.
Tennessee Valley Authority (TVAXA State of the Art Report on Intake Technologies. 1976.
8 A-13
-------
§ 316(b) Phase III - Technical Development Document Attachment A to Chapter 8
Passive Intake Systems I Fact Sheet No. 5:Wedgewire Screens
Description:
Wedgewire screens are designed to reduce entrainment by physical exclusion and by exploiting
hydrodynamics.Physical exclusion occurs when the mesh size of the screen is smaller than the
organisms susceptible to entrainment. Hydrodynamic exclusion results from maintenance of a
low through-slot velocity, which, because of the screen's cylindrical configuration, is quickly
dissipated, thereby allowing organisms to escape the flow field (Weisberd et al, 1984). The
screens can be fine or wide mesh. The name of these screens arise from the triangular or
"wedge" cross section of the wire that makes up the screen. The screen is composed of
wedgewire loops welded at the apex of their triangular cross section to supporting axial rods
presenting the base of the cross section to the incoming flow (Pagano et al, 1977). A cylindrical
wedgewire screen is shown in the figure below. Wedgewire screens are also called profile
screens or Johnson screens.
Testing Facilities and/or Facilities Using the Technology:
Wide mesh wedgewire screens are used at two large power plants, Eddystone and
Campbell.Smaller facilities with wedgewire screens include Logan and Cope with fine mesh
and Jeffrey with wide mesh (EPRI1999).
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 periodThe 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 etal, 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
8A-14
-------
S 316(b) Phase HI - Technical Development Document
Attachment A to Chapter 8
Passive Intake Systems
Fact Sheet No. 5:Wedgewire Screens
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 of 1 and 2-rnm wedgewire screens was performed
in the St. John River for the Seminole Generating Station Units 1 and 2 in Florida in
the late 1970s.This testing showed virtually no impingement and 99 and 62 percent
reductions in larvae entrainment for the 1-mm and 2-mm screens, respectively, over
conventional screen (9.5 mm) systems (EPRI, 1999).
Design Considerations:
Advantages:
Limitations:
To minimize clogging, the screen should be located in an ambient current of at least 1
feet per second (ft/sec).
A uniform velocity distribution along the screen face is required to minimize the
entrapment of motile organisms and to minimize the need of debris backfiushing.
In northern latitudes, provisions for the prevention of frazil ice formation on the screens
must be considered.
Allowance should be provided below the screens for silt accumulation to avoid
blockage of the water flow (Mussalli et al, 1980).
Wedgewire screens have been demonstrated to reduce impingement and entrainment
in laboratory and prototype field studies.
The physical size of the screening device is limiting in most passive systems, thus,
requiring the clustering of a number of screening units. Siltation, biofouling and frazil
ice also limit areas where passive screens such as wedgewire can be utilized.
Because of these limitations, wedgewire screens may be more suitable for closed-cycle
make-up intakes than once-through systems. Closed-cycle systems require less flow
and fewer screens than once-through intakes; back-up conventional screens can
therefore be used during maintenance work on the wedge-wire screens (Mussalli et al,
1980).
References:
8 A-15
-------
§ 316(b) Phase IH - Technical Development Document Attachment A to Chapter 8
Passive Intake Systems I Fact Sheet No. 5:Wedgewire Screens
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 (EPRD.Fish Protection at Cooling Water Intakes:Status Report.
1999.
Hanson, B.N., W.H. Bason, B.E. Beitz and K.E. Charles. "A Practical Intake Screen which
Substantially Reduces the Entrainment and Impingement of Early Life stages of Fish". In Fourth
National Workshop on Entrainment and Impingement. L.D. Jensen (Editor).Ecological Analysts,
Inc., Melville, NY. Chicago, December 1977, pp 393-407.
Heuer, J.H. and D.A. Tomljanovitch. "A Study on the Protection of Fish Larvae at Water Intakes
Using Wedge-Wire Screening". In Larval Exclusion Systems For Power Plant Cooling Water
Intakes. R.K. Sharmer and J.B. Palmer, eds, Argonne National Lab., Argonne, IL. February 1978, pp
169-194.
Lifton, W.S. "Biological Aspects of Screen Testing on the St. Johns River, Palatka, Florida". In
Passive Screen Intake Workshop. Johnson Division UOP Inc., St. Paul, MN. 1979.
Mussalli, Y.G., E.P. Taft III, and J. Larsen. "Offshore Water Intakes Designated to Protect Fish".
Journal of the Hydraulics Division. Proceedings of the America Society of Civil Engineers. Vol.
106, No HY11, November 1980,pp 1885-1901.
Pagano R. and W.H.B. Smith. Recent Developments in Techniques to Protect Aquatic Organisms
at the Intakes Steam-Electric Power Plants. MITRE Corporation Technical Report 7671. November
1977.
Weisberg, S.B., F. Jacobs, W.H. Burton, and R.N. Ross. Report on Preliminary Studies Using the
Wedee Wire ScreenModel Intake Facility. Prepared for State of Maryland, Power Plant Siting
Program.Prepared by Martin Marietta Environmental Center, Baltimore, MD.1983.
Weisberg, S.B., W.H. Burton, E.A., Ross, and F. Jacobs. The effects od Screen Slot Size. Screen
Diameter, and Through-Slot Velocity on Entrainment of Estuarine Ichthvoplankton Through
Wedge-Wire Screens. Martin Marrietta Environmental Studies, Columbia MD. August 1984.
8 A-16
-------
S 316(b) Phase III - Technical Development Document Attachment A to Chapter 8
Passive Intake Systems |Fact Sheet No. 6;Perforated Pipes
Description:
Perforated pipes draw water through perforations or slots in a cylindrical section placed in the
waterway. The term "perforated" is applied to round perforations and elongated slots as shown in
the figure below.The early technology was not efficient:velocity distribution was poor, it served
specifically to screen out detritus, and was not used for fish protection (ASCE, 1982). Inner sleeves
have been added to perforated pipes to equalize the velocities entering the outer perforations. Water
entering a single perforated pipe intake without an internal sleeve will have a wide range of entrance
velocities and the highest will be concentrated at the supply pipe end. These systems have been used
at locations requiring small amounts of water such as make-up water. However, experience at steam
electric plants is very limited (Sharma, 1978).
Testing Facilities And/or Facilities Using the Technology:
Nine steam electric units in the U.S. use perforated pipes.Each of these units uses closed-cycle
cooling systems with relatively low make-up intake flow ranging from 7 to 36 MGD (EEI,
1993).
Research/Operation Findings:
• Maintenance of perforated pipe systems requires control of biofouling and removal of
debris from clogged screens.
• For withdrawal of relatively small quantities of water, up to 50,000 gpm, the perforated
pipe inlet with an internal perforated sleeve offers substantial protection for fish. This
particular design serves the Washington Public Power Supply System on the Columbia
River (Richards, 1977).
• No information is available on the fate of the organisms impinged at the face of such
screens.
Design Considerations:
The design of these systems is fairly well established for various water intakes (ASCE, 1982).
Advantages:
The primary advantage is the absence of a confined channel in which fish might become trapped.
Limitations:
Clogging, frazil ice formation, biofouling and removal of debris limit this technology to small
flow withdrawals.
8 A-17
-------
S 316(b) Phase IH - Technical Development Document Attachment A to Chapter 8
Passive Intake Systems | Fact Sheet No. 6:Perforated Pipes
REFERENCES:
American Society of Civil Engineers. Task Committee on Fish-handling of Intake Structures of the
Committee of Hydraulic Structures. Design of Water Intake Structures for Fish Protection. ASCE, New
York, N.Y. 1982.
EEI Power Statistics Database. Prepared by the Utility Data Institute for the Edison Electric Institute.
Washington, D.C., 1993.
Richards, R.T. 1977. "Present Engineering Limitations to the Protection of Fish at Water Intakes".In
Fourth National Workshop on Entrainment and Impingement L.D. Jensen Editor,Chicago, December
1977, pp 415-424.
Sharma, R.K. "A Synthesis of Views Presented at the Workshop". In Larval Exclusion Systems For
Power Plant Cooling Water Intakes. San-Diego, California, February 1978, pp 235-237.
8 A-18
-------
§ 316(b) Phase III - Technical Development Document Attachment A to Chapter 8
Passive intake Systems I Fact Sheet No. 7:Porous Dikes/Leaky Dams
Description:
Porous dikes, also known as leaky dams or leaky dikes, are filters resembling a breakwater
surrounding a cooling water intake.The core of the dike consists of cobble or gravel, which
permits free passage of water.The dike acts both as a physical and a behavioral barrier to aquatic
organisms and is depicted in the figure below.The filtering mechanism includes a breakwater
or some other type of barrier and the filtering core (Fritz, 1980).Tests conducted to date have
indicated that the technology is effective in excluding juvenile and adult fish.However, its
effectiveness in screening fish eggs and larvae is not established (ASCE, 1982).
Testing Facilities and/or Facilities Using the Technology:
• Two facilities which are both testing facilities and have used the technology are:
thePoint Beach Nuclear Plant in Wisconsin and the Baily Generating Station in Indiana
(EPRI, 1985). The Brayton Point Generating Station in Massachusetts has also tested
the technology.
Research/Operation Findings:
Schrader and Ketschke (1978) studied a porous dike system atthe 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.
8 A-19
-------
§ 316(b) Phose HI - Technical Development Document
Attachment A to Chapter 8
Passive intake Systems
Fact Sheet No. 7:Porous Dikes/Leaky Dams
Advantages:
• Dikes can be used at marine, fresh water, and estuarine locations.
Limitations:
• The major problem with porous dikes comes from clogging by debris and silt, and from
fouling by colonization offish and plant life.
• Backflushing, which is often used by other systems for debris removal, is not feasible
at a dike installation.
• Predation of organisms screened at these dikes may offset any biological effectiveness
(Sharma, 1978).
REFERENCES:
American Society of Civil Engineers. Task Committee on Fish-handling of Intake Structures of the
Committee of Hydraulic Structures. Design of Water Intake Structures for Fish Protection. ASCE, New
York, N.Y. 1982.
EPRUntake Research Facilities Manual.Preparedbv 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.
8A-20
-------
§ 316(b) Phase III - Technical Development Document Attachment A to Chapter 8
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.lt appears that this
technology has, in general, become accepted as a viable option to divert juvenile and adult fish.
Testing Facilities and/or Facilities Using the Technology:
Louver barrier devices have been tested and/or are in use at the followingfacilitiesrthe California
Department of Water Resource's Tracy Pumping Plant; the California Department of Fish and
Game's Delta Fish Protective Facility in Bryon; the Conte Anadromous Fish Research Center in
Massachusetts, and the San Onofre Nuclear Generating Station in California (EPA, 1976; EPRI,
1985; EPRI, 1999).In addition, three other plants also have louvers at their facilities: the Ruth Falls
Power Plant in Nova Scotia, the Nine Mile Point Nuclear Power Station on Lake Erie, and T.W.
Sullivan Hydroelectric Plant in Oregon.Louvers have also been tested at the Ontario Hydro
Laboratories in Ontario, Canada (Ray et al, 1976).
Research/Operation Findings:
Research has shown the following generalizations to be true regarding louver barriers:
1) the fish separation performance of the louver barrier decreases with an increase in the velocity
of the flow through the barrier;2) efficiency increases with fish size (EPA, 1976; Hadderingh,
1979);3) individual louver misalignment has a beneficial effect on the efficiency of the barrier;4)
the use of center walls provides the fish with a guide wall to swim along thereby improving
efficiency (EPA, 1976); and 5) the most effective slat spacing and array angle to flow depends upon
the size, species and ability of the fish to be diverted (Ray et al, 1976).
In addition, the following conclusions were drawn during specific studies:
• Testing of louvered intake structures offshore was performed at a New York facility. The louvers
were spaced 10 inches apart to minimize clogging.The array was angled at 11.5 percent to the flow.Center
walls were provided for fish guidance to the bypass.Test species included alewife and rainbow smelt.The
8A-21
-------
§ 316(b) Phase IH - Technical Development Document Attachment A to Chapter 8
Fish Diversion or Avoidance Systems | Fact Sheet No. 8:Louver Systems
Atth
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).
Tracy Fish Collection Facility located along the San Joaquin River in California, testing was performed
from 1993 and 1995 to determine the guidance efficiency of a system with primary and secondary
louvers.The results for green and white sturgeon, American shad, splittail, white catfish, delta smelt,
Chinook salmon, and striped bass showed mean diversion efficiencies ranging from 63 (splittail) to 89
percent (white catfish)(EPRI, 1999).
• In 1984 at the San Onofre Station, a total of 196,978 fish entered the louver system with 188,583 returned
to the waterbody and 8,395 impinged.In 1985, 407,755 entered the louver system with 306,200
returned and 101,555 impinged-Therefore, the guidance efficiencies in 1984 and 1985 were 96 and
75 percent, respectively .However, 96-hour survival rates for some species, i.e., anchovies and
croakers, were 50 percent or less.Louvers were originally considered for use at San Onofre because
of 1970s pilot testing at the Redondo Beach Station in California where maximum guidance
efficiencies of 96-100 percent were observed.(EPRI, 1999)
• At the Maxwell Irrigation Canal in Oregon, louver spacing was 5.0 cm with a 98 percent efficiency of
deflecting immature steelhead and above 90 percent efficiency for the same species with a louver
spacing of 10.8 cm.
• At the Ruth Falls Power Plant in Nova Scotia, the results of a five-year evaluation for guiding salmon
smelts showed that the optimum spacing was to have wide bar spacing at the widest part of the
louver with a gradual reduction in the spacing approaching the bypass.The site used a
bypass:approach velocity ratio of 1.0 : 1.5 (Ray et al, 1976).
• Coastal species in California were deflected optimally (Schuler and Larson, 1974 in Ray et al,
1976) with 2.5 cm spacing of the louvers, 20 degree louver array to the direction of flow and
approach velocities of 0.6 cm per second.
» At the T.W. Sullivan Hydroelectric Plant along the Williamette River in Oregon, the louver
8A-22
-------
§ 316(b) Phase HI - Technical Development Document Attachment A to Chapter 8
Fish Diversion or Avoidance Systems | Fact Sheet No. 8;Louver Systems
system is estimated to be 92 percent effective in diverting spring Chinook, 82 percent for all
Chinook, and 85 percent for steelhead.The system has been optimized to reduce fish injuries such
that the average injury occurrence is only 0.44 percent (EPRI, 1999).
Design Considerations:
The most important parameters of the design of louver barriers include the following:
« The angle of the louver vanes in relation to the channel velocity ,
• The spacing between the louvers which is related to the size of the fish,
• Ratio of bypass velocity to channel velocity,
• Shape of guide walls,
• Louver array angles, and
• Approach velocities.
Site-specific modeling may be needed to take into account species-specific considerations and
optimize the design efficiency (EPA, 1976; O'Keefe, 1978).
Advantages:
• Louver designs have been shown to be very effective in diverting fish (EPA, 1976).
Limitations:
• The costs of installing intakes with louvers may be substantially higher than other technologies
due to design costs and the precision required during construction.
• Extensive species-specific field testing may be required.
• The shallow angles required for the efficient design of a louver system require a long line of louvers
increasing the cost as compared to other systems (Ray et al, 1976).
1 Water level changes must be kept to a minimum to maintain the most efficient flow velocity.
8A-23
-------
S 316(b) Phase III - Technical Development Document Attachment A to Chapter 8
Fish Diversion or Avoidance Systems | Fact Sheet No. 8:Louver Systems
• 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 PlantCooling
Systems."Literature Review.Journal Water Pollution Control Federation.53 (6)(1981):965-973.
U.S. EPA.Development Document for Best Technology Available for the Location. Design. Construction.
and Capacity of Cooling Water Intake Structures for Minimizing Adverse Environmental Impact.U.S.
Environmental Protection Agency, Effluent Guidelines Division, Office of Water and Hazardous
Materials. April 1976.
Electric Power Research Institute (EPRH.Fish Protection at Cooling Water Intakes:Status Report. 1999.
EPRI.Intake Research Facilities Manual.Preparedbv 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,
Amheem, Netherlands.Hvdrological Bulletin 13(2-3) (1979): 83-93.
Mussalli, Y.G., E.P. Taft, and P. Hoffman/'Engineering Implications of New Fish Screening Concepts," In
Fourth National Workshop on Entrainment and impingement. L.D. Jensen (Ed.), Ecological Analysts, Inc.
Melville, NY.Chicago, Dec. 1977.
Mussalli, Y.G., E.P Taft III and J. Larson."Offshore Water Intakes Designed to Protect Fish."Journal of the
Hydraulics Division Proceedings of the American Society of Civil Engineers.Vol. 106Hyll (1980): 1885-
1901.
O'Keefe, W., Intake Technology Moves Ahead.Powgr.January 1978.
Ray, S.S. and R.L. Snipes and D.A. Tomlianovich.A State-of-the-Art Report on Intake
Technologies.Prepared for Office of Energy, Minerals, and Industry, Office of Research and
DevelopmentU.S. Environmental Protection Agency, Washington, D.C. by the Tennessee Valley
Authority.EPA 600/7-76-020.October 1976.
8A-24
-------
§ 316(b) Phase HI - Technical Development Document Attachment A to Chapter 8
Fish Diversion or Avoidance Systems | Fact Sheet No. 8:Louver Systems
Uziel, Mary S."Entrainment and Impingement at Cooling Water Intakes."Literature Review.Joumal Water
Pollution Control Federation.52 (61 (198(T): 1616-1630.
Additional References:
Adams, S.M. et aLAnalvsis 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.'ln 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.'Tish Protection at Steam Electric Power Plants:Altemative Screening
Devices."ORAL/TM-6473.Oak Ridge Nat'l. Lab.Oak Ridge, TN (1979).
Downs, D.I., andK.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.
iallock, R. J., R.A. Iselin, and D.H.J. Frv.Efficiencv Tests of the Primary Louver Systems. Tracv 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 Passaee.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).
vlarcy, B.C., and M.D. Dahlberg.Review of Best Technology Available for Cooling Water Intakes.NUS
Corporation-Pittsburgh, PA (1978).
8A-25
-------
S 316(b) Phase III - Technical Development Document Attachment A to Chapter 8
Fish Diversion or Avoidance Systems | Fact Sheet No. 8;Louver Systems
NUS Corp., "Review of Best Technology Available for Cooling Water Intakes."Los Angeles Dept. of Water
& Power Report. Los Angeles CA (1978).
Schuler, V.J., "Experimental Studies In Guiding Marine Fishes of Southern California with Screens and
Louvers/'Ichthvol. Assoc.. Bulletin 8 (1973).
Skinner, J.E."A Functional Evaluation of Large Louver Screen Installation and Fish Facilities Research on
California Water Diversion Projects."In: L.D. Jensen, ed.Entrainment and Intake Screening.Proceedings of
the Second Entrainment and Intake Screening Workshop.The John Hopkins University, Baltimore,
Maryland-February 5-9,1973.pp 225-249 (Edison Electric Institute and Electric Power Research Institute,
EPRI Publication No. 74-049-00-5 (1974).
Stone and Webster Engineering Corporation.Studies to Alleviate Potential Fish Entrapment Problems - Final
Report. Nine Mile Point Nuclear Station - Unit 2.Preoared for Niagara Mohawk Power Corporation,
Syracuse, New York, May 1972.
Stone and Webster Engineering Corporation.Final Report. Indian Point Flume Studv.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 Mavfield Dam in West Washington. Washington Department of Fisheries, Olympia,
Washington (1967).
Watts, F.J., "Design of Culvert Fishwavs."Universitv of Idaho Water Resources Research Institute Report.
Moscow, Idaho (1974).
8A-26
-------
S 316(b) Phase HI - Technical Development Document Attachment A to Chapter 8
Fish Diversion or Avoidance Systems I Fact Sheet No. 9: Velocity Cap
Description:
A velocity cap is a device that is placed over vertical inlets at offshore intakes (see figure
below). This cover converts vertical flow into horizontal flow at the entrance into the intake.
The device works on the premise that fish will avoid rapid changes in horizontal flow. Fish do
not exhibit this same avoidance behavior to the vertical flow that occurs without the use of such
a device. Velocity caps have been implemented at many offshore intakes and have been
successful in decreasing the impingement of fish.
Testing Facilities And/or Facilities Using the Technology:
The available literature (EPA, 1976; Hanson, 1979; and 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).
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 hi 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).
8A-27
-------
§ 316(b) Phase III - Technical Development Document Attachment A to Chapter 8
Fish Diversion or Avoidance Systems I Fact Sheet No. 9: Velocity Cap
Design Considerations:
Advantages:
Designs with rims around the cap edge prevent water from sweeping around the
edge causing turbulence and high velocities, thereby providing more uniform
horizontal flows (EPA, 1976; Mussalli, 1980).
Site-specific testing should be conducted to determine appropriate velocities to
minimize entrainment of particular species in the intake (ASCE, 1982).
Most structures are sized to achieve a low intake velocity between 0.5 and 1.5 ft/sec
to lessen the chances of entrainment (ASCE, 1982).
Design criteria developed for a model test conducted by Southern California Edison
Company used a velocity through the cap of 0.5 to 1.5 ft/sec; the ratio of the
dimension of the rim to the height of the intake areas was 1.5 to 1 (ASCE, 1982;
Schuler, 1975).
Efficiencies of velocity caps on West Coast offshore intakes have exceeded 90
percent (ASCE, 1982).
Limitations:
Velocity caps are difficult to inspect due to their location under water (EPA, 1976).
In some studies, the velocity cap only minimized the entrainment offish 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.Preparedbv 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.Qctober 1977.
8A-28
-------
§ 316(b) Phase III - Technical Development Document Attachment A to Chapter 8
Fish Diversion or Avoidance Systems I Fact Sheet No. 9: Velocity Cap
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 Hyl 1
(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."!. Power Div.. Proc. Am. Soc.
Civil Ener. 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 ReportPrepared 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.
8A-29
-------
S 316(b) Phase HI - Technical Development Document . Attachment A to Chapter 8
Fish Diversion or Avoidance Systems
Fact Sheet No. 10:Fish Barrier Nets
Description:
Fish barrier nets are wide mesh nets, which are placed in front of the entrance to an intake
structure (see figure below).The size of the mesh needed is a function of the species that are
present at a particular site. Fish barrier nets have been used at numerous facilities and lend
themselves to intakes where the seasonal migration of fish and other organisms require fish
diversion facilities for only specific times of the year.
Testing Facilities And/or Facilities Using the Technology:
The Bowline Point Generating Station, the J.P. Pulliam Power Plant in Wisconsin, the
Ludington Storage Plant in Michigan, and the Nanticoke Thermal Generating Station in Ontario
use barrier nets (EPRI, 1999).
Barrier Nets have been tested at the Detroit Edison Monroe Plant on Lake Erie and the Chalk
Point Station on the Patuxent River in Maryland (ASCE, 1982; EPRI, 1985).The Chalk Point
Station now uses barrier nets seasonally to reduce fish and Blue Crab entry into the intake canal
(EPRI, 1985).The Pickering Generation Station in Ontario evaluated rope nets in 1981
illuminated by strobe lights (EPRI, 1985).
Research/Operation Findings:
At the Bowline Point Generating Station in New York, good results (91 percent
impingement reductions) have been realized with a net placed in a V arrangement
around the intake structure (ASCE, 1982; EPRI, 1999).
In 1980, a barrier net was installed at the J.R. Whiting Plant (Michigan) to protect
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).
8A-30
-------
§ 316(b) Phase III - Technical Development Document
Attachment A to Chapter 8
Fish Diversion or Avoidance Systems
Fact Sheet No. 10:Fish Barrier Nets
The Chalk Point Station in Maryland realized operational costs of $5,000-10,000 per
year with the nets being replaced every two years (EPRI, 1985).However, crab
impingement has been reduced by 84 percent and overall impingrment liability has
been reduced from $2 million to $140,000 (EPRI, 1999).
The Ludington Storage Plant (Michigan) provides water from Lake Michigan to a
number of power plant facilities.The plant has a 2.5-mile long barrier net that has
successfully reduced impingement and entrainment.The overall net effectiveness for
target species (five salmonids, yellow perch, rainbow smelt, alewife, and chub) has
been over 80 percent since 1991 and 96 percent since 1995.The net is deployed from
mid-April to mid-October, with storms and icing preventing use during the remainder
of the year (EPRI, 1999).
Design Considerations:
Advantages:
Limitations:
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).
Net barriers, if operating properly, should require very little maintenance.
Net barriers have relatively little cost associated with them.
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.
8A-31
-------
S 316(b) Phase III - Technical Development Document Attachment A to Chapter 8
Fish Diversion or Avoidance Systems
Fact Sheet No. 10:Fish Barrier Nets
Lawler, Matusky, and Skelly Engineers. 1977 Hudson River Aquatic Ecology Studies at the Bowline
Point Generating Stations.Prepared for Orange and Rockland Utilities, Inc.Pearl River, NY. 1978.
8A-32
-------
S 316(b) Phase III - Technical Development Document
Attachment A to Chapter 8
Fish Diversion or Avoidance Systems
Fact Sheet No. 11: Aquatic Filter Barrier
Systems
Description:
Aquatic filter barrier systems are barriers that employ a filter fabric designed to allow for
passage of water into a cooling water intake structure, but exclude aquatic organisms. These
systems are designed to be placed some distance from the cooling water intake structure within
the source waterbody and act as a filter for the water that enters into the cooling water system.
These systems may be floating, flexible, or fixed. Since these systems generally have such a
large surface area, the velocities that are maintained at the face of the permeable curtain are very
low. One company, Gunderboom, Inc., has a patented full-water-depth filter curtain comprised
of polyethylene or polypropylene fabric that is suspended by flotation billets at the surface of
the water and anchored to the substrate below. The curtain fabric is manufactured as a matting
of minute unwoven fibers with an apparent opening size of 20 microns. The Gunderboom
Marine/Aquatic Life Exclusion System (MLES)™ also employs an automated "air burst"™
technology to periodically shake the material and pass air bubbles through the curtain system
to clean it of sediment buildup and release any other material back in to the water column.
Testing Facilities and/or Facilities Using the Technology:
Gunderboom MLES ™have been tested and are currently installed on a seasonal
basis at Unit 3 of the Lovett Station in New York. Prototype testing of the
Gunderboom system began in 1994 as a means of lowering ichthyoplankton
entrainment at Unit 3.This was the first use of the technology at a cooling water
intake structure.The Gunderboom tested was a single layer fabric.Material clogging
resulted in loss of filtration capacity and boom submergence within 12 hours of
deployment. Ichthyoplankton monitoring while the boom was intact indicated an 80
percent reduction in entrainable organisms (Lawler, Matusky, and Skelly
Engineers, 1996).
A Gunderboom MLES ™ was effectively deployed at the Lovett Station for 43
days in June and July of 1998 using an Air-Burst cleaning system and newly
designed deadweight anchoring system.The cleaning system coupled with a
perforated material proved effective at limiting sediment on the boom, however it
required an intensive operational schedule (Lawler, Matusky, and Skelly Engineers,
1998).
A 1999 study was performed on the Gunderboom MLES ™ at the Lovett Station in
New York to qualitatively determine the characteristics of the fabric with respect to
the impingement of ichthyoplankton at various flow regimes.Conclusions were that
the viability of striped bass eggs and larvae were not affected (Lawler, Matusky,
and Skelly Engineers, 1999).
Ichthyoplankton sampling at Unit 3 (with Gunderboom MLES ™ deployed) and
Unit 4 (without Gunderboom) in May through August 2000 showed an overall
8A-33
-------
S 316(b) Phase HI - Technical Development Document
Attachment A to Chapter 8
Fish Diversion or Avoidance Systems
Fact Sheet No. ll:Aquatic Filter Barrier
Systems
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 percentlower (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.lt is also
being evaluated for use at the Contre Costa Power Plant in California.
Design Considerations:
The most important parameters in the design of a Gunderboom ®Marine/Aquatic Life
Exclusion System include the following (Gunderboom, Inc. 1999):
Size of booms designed for 3-5 gpm per square foot of submerged fabric.Flows
greater than 10-12 gallons per minute.
Flow-through velocity is approximately 0.02 ft/s.
Performance monitoring and regular maintenance.
Advantages:
Can be used in all waterbody types.
All larger and nearly all other organisms can swim away from the barrier because
of low velocities.
Little damage is caused to fish eggs and larvae if they are drawn up against the
fabric.
Modulized panels may easily be replaced.
Easily deployed for seasonal use.
Biofouling appears to be controllable through use of the sparging system.
Impinged organisms released back into the waterbody.
8A-34
-------
S 316(b) Phase HI - Technical Development Document
Attachment A to Chapter 8
Fish Diversion or Avoidance Systems
Fact Sheet No. 11: Aquatic Filter Barrier
Systems
Limitations:
Benefits relative to cost appear to be very promising, but remain unproven to date.
Installation can occur with no or minimal plant shutdown.
Currently only a proven technology for this application at one facility.
Extensive waterbody-specific field testing may be required.
May not be appropriate for conditions with large fluctuations in ambient flow and
heavy currents and wave action.
High level of maintenance and monitoring required.
Recent studies have asserted that biofouling can be significant
Higher flow facilities may require very large surface areas; could interfere with
other waterbody uses.
References:
Lawler, Matusky & Skelly Engineers, "Lovett Generating Station Gunderboom Evaluation
Program - 1995"Prepared for Orange and Rockland Utilities, Inc.Pearl River, New York,June 1996.
Lawler, Matusky & Skelly Engineers, "Lovett Generating Station Gunderboom System Evaluation
Program - 1998"Prepared for Orange and Rockland Utilities, Inc.Pearl River, New York, December
1998.
Lawler, Matusky & Skelly Engineers, " Lovett Gunderboom Fabric Ichthyoplankton Bench Scale
Testing" Southern Energy Lovett.New York, November 1999.
Lawler, Matusky & Skelly Engineers, "Lovett 2000 Report'Trepared for Orange and Rockland
Utilities, Inc.Pearl River, New York, 2000.
8A-35
-------
S 316(b) Phase IH - Technical Development Document Attachment A to Chapter 8
Fish Diversion or Avoidance Systems I 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,
et al., 1988; ASCE, 1992).
Researchers have generally been unable to demonstrate or apply acoustic barriers as fish
deterrents, even though fish studies showed that fish respond to sound, because the
response varies as a function of fish species, age, and size as well as environmental factors
at specific locations. Fish may also acclimate to the sound patterns used (EPA, 1976; Taft
et al., 1988; EPRI, 1995; Ray at al., 1976; Hadderingh, 1979; Hanson et al., 1977; ASCE,
1982).
Since about 1989, the application of highly refined sound generation equipment originally
developed for military use (e.g., sonar in submarines) has greatly advanced acoustic barrier
technology. Ibis technology has the ability to generate a wide array of frequencies, patterns,
and volumes, which are monitored and controlled by computer. Video and computer
monitoring provide immediate feedback on the effectiveness of an experimental sound
pattern at a given location. In a particular environment, background sounds can be
accounted for, target fish species or fish populations can quickly be characterized, and the
most effective sound pattern can be selected (Menezes, at al., 1991; Sonalysts, Inc.).
Testing Facilities and/or Facilities with Technology in Use:
No fishpulsers and pneumatic air guns are currently in use at power plant water intakes.
Research facilities that have completed studies or have on-going testing involving
fishpulsers or pneumatic air guns include the Ludington Storage Plant on Lake Michigan;
Nova Scotia Power; the Hells Gate Hydroelectric Station on the Black River; the Annapolis
Generating Station on the Bay of Fundy; Ontario Hydro's Pickering Nuclear Generating
station; the Roseton Generating Station in New York; the Seton Hydroelectric Station in
British Columbia; the Surry Power Plant in Virginia; the Indian Point Nuclear Generating
Station Unit 3 in New York; and the U.S. Army Corps of Engineers on the Savannah River
(EPRI, 1985; EPRI, 1989; EPRI, 1988; and Taft, et al., 1998).
Updated acoustic technology developed by Sonalysts, Inc. has been applied at the James A.
Fitzpatrick Nuclear Power Plant in New York on Lake Ontario; the Vernon Hydroelectric
8A-36
-------
§ 316(b) Phase HI - Technical Development Document Attachment A to Chapter 8
Fish Diversion or Avoidance Systems I Fact Sheet No. 12:Sound Barriers
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,
et al., 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, et al., 1991; EPRI, 1999).
In tests at the Pickering Station in Ontario, poppers were found to be effective in
reducing alewife impingement and entrainment by 73 percent in 1985 and 76
percent in 1986.No benefits were observed for rainbow smelt and gizzard shad.
Sound provided little or no deterrence for any species at the Roseton Generating
Station in New York.
During marine construction of Boston's third Harbor Tunnel in 1992, the Sonalysts,
Inc. FishStartle System was used to prevent shad, blueback herring, and alewives
from entering underwater blasting areas during the fishes' annual spring migration.
The portable system was used prior to each blast to temporarily deter fish and
allow periods of blastmg as necessary for the construction of the tunnel (personal
communication to SAIC from M. Curtin, Sonalysts, Inc., September 17, 1993).
In fall 1992, the Sonalysts, Inc. FishStartle System was tested in a series of
experiments conducted at the Vernon Hydroelectric plant on the Connecticut River.
Caged juvenile shad were exposed to various acoustical signals to see which signals
elicited the strongest reactions. Successful in situ tests involved applying the signals
with a transducer system to divert juvenile shad from the forebay to a bypass pipe.
Shad exhibited consistent avoidance reactions to the signals and did not show
8A-37
-------
§ 316(b) Phase III - Technical Development Document
Attachment A to Chapter 8
Fish Diversion or Avoidance Systems
Fact Sheet No. 12:Sound Barriers
evidence of acclimation to the source (New England Power Company, 1993).
Design Considerations:
• Sonalysts Inc.'s FishStartle system uses frequencies between 15 hertz to!30
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:
Limitations:
The pneumatic air gun, hammer, and fishpulser are easily implemented at low
costs.
Behavioral barriers do not require physical handling of the fish.
The pneumatic air gun, hammer, and fishpulser are not considered reliable.
Sophisticated acoustic sound generating system require relatively expensive
8A-38
-------
§ 316(b) Phase III - Technical Development Document Attachment A to Chapter 8
Fish Diversion or Avoidance Systems 1 Fact Sheet No. 12: Sound Barriers
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 (EPRD.Fish Protection at Cooling Water Intakes:Status Report.
1999.
EPRI. Field Testing of Behavioral Barriers for Fish Exclusion at Cooling Water Intake Svtems:
Ontario Hvdro 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 CoManv. 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 Hvdrobiological Bulletin . 13(2-3), 83-93, 1979.
Hanson, C. H., J.R. White, and H.W. Li. "Entrapment and Impingement of Fishes by Power Plant
Cooling Water Intakes: An Overview." from Fisheries Review. MFR Paper 1266. October 1977.
McKinley, R.S. and P.M. 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. T'iller, and Peter J. Dolan. Sonalysts, Inc. Waterford,
8A-39
-------
§ 316(b) Phase III - Technical Development Document Attachment A to Chapter 8
Fish Diversion or Avoidance Systems I Fact Sheet No. 12:Sound Barriers
Connecticut.The Electronic FishStartle System. 1991.
New England.Power Company. Effect of Ensonification on Juvenile American Shad Movement
and Behavior at Vernon Hydroelectric Station, 1992. March 1993.
Patrick, P.H., R.S. McKinley, and W.C. Micheletti. "Field Testing of Behavioral Barriers for
Cooling Water Intake Structures-Test Site 1-Pickering Nuclear Generating Station, 1985/96.* In
the Electric Power Research Institute Proceedings Fish Protection at Steam and Hvdroelectri Power
Plants. March 1988.
Personal Communication, September 17, 1993, letter and enclosure from MJ. Curtin (Sonalysts,
Inc.) to D. Benelmouffok (SAIC).
Ray, S.S., R.L. Snipes, and D. A Tomljanovich. *A State-of-the-Art Report on Intake
Technologies.- TVA PRS-16 and EPA 6OOn-76-020. October 1976.
Sonalysts, Inc. "FishStartle System in Action: Acoustic Solutions to Environmental Problems" (on
video tape). 215 Parkway North, Waterfbrd, CT 06385.
Taft, E. P., and J.K.. Downing. -Comparative Assessment of Fish Protection Alternatives fbr Fossil
and Hydroelectric Facilities.' In the Electric Power Research Institute Proceedingso Fish Protection
at Steam and Hydroelectric Power Plants. March 1998.
Taft, E.P, J. K. Downing, and C. W. Sullivan. "Laboratory and Field Evaluations of Fish Protection
Systems for Use at Hydroelectric Plants Study Update." In the Electric Power Research Institute's
Proceedings: Fish Protection at Stearn and Hydroelectric Power Plants. March 1988.
U.S. EPA. Development Document for Best Technology Available for the Location. D
Construction, and Capacity of Cooling Water Intake Structures fbr Minimizing Adverse
Environmental Impact. U.S. Environmental Protection Agency, Effluent Guidelines Division,
Office of Water and Hazardous Materials. April 1976.
Uziel, Mary S., "Entrainment and Impingement at Cooling Water Intakes." Journal WPCF. Vol. 52,
No.6. June 1980.
ADDITIONAL REFERENCES:
Blaxter, J.H'.S., and D.E. Hoss. "Startle Response in Herring: the Effect of Sound Stimulus
Frequency, Size of Fish and Selective Interference with the Acoustical-lateralis System. " Journal
of the Marine Biolozical Association of the United Kingdom. 61:971-879. 1981.
Blaxter, JJ.S., J.A.B. Gray, and E.J. Denton. "Sound and Startle Response in Herring Shoals."
J.Mar. Biol. Ass. U.K. 61:851-869. 1981.
Burdic, W.S. Underwater Acoustic System Analysis. Englewood Cliffs, New Jersey: PrenticeHall.
8A-40
-------
§ 316(b) Phase III - Technical Development Document Attachment A to Chapter 8
Fish Diversion or Avoidance Systems I Fact Sheet No. 12:Sound Barriers
^M^^^M^M^^M^^^H^^^^^^H^HMM^MH^MH^^^M^MH^HiMMM^^SL^M^^^^^M^H^MMiM^BMWHMBMMMMM^BM^B^nHM
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 Psvchg2-hvsics Data Boo . HUI-Fay Associates. Winnetka,
Illinois. 1988.
Frizzell, L.A., *Biological Effects of Acoustic Cavitation." In Ultrasound Its Chemical. Physical
and Biological Effects. K.S. Suslick (Editor). VCH Publishers, Inc. New York. 1988. pp. 297-319.
Haymes, G.T., and P.H. Patrick. "Exclusion of Adult Alewife (Alosa pseuoharengus), Using
Low-Frequency Sound for Application of Water Intakes.' Can. J. Fish. Aamatics Srd. 43:855862.
1986.
Micheletti, Coal Combustion Systems Division. "Fish Protection at Cooling Water Intake
Systems." EM Journal. September 1987.
Micheletti, Coal Combustion Systems Division. wFish Protection at Cooling Water Intake
Systems." EPRI Journal. September 1997.
Patrick, P.H., R.S. McKinley, A. E. Christie, and J.G. Holsapple. "Fish Protection: Sonic
Deterrents.' In the EPRI Proceeding: Fish Protection at Steam and Hydroelectric Power Plants.
March 1988.
Platt, C., and A.N. Popper."Find Structure and Function of the Ear." In Hearing and Sound
Communication in Fishes. W.N. Tavolga, A.N. Popper and R.R. Ray (Editors). SpringerVerlag.
New York.
Ross, Q.E., D. J. Dunning, R. Thorne, J. Menezes, G. W. Tiller, and J. K. Watson.Response of
Alewives to High Frequency Sound at a Power Plant Intake on Lake Ontario. 1993.
Schwarz, A.L., and G.L. Greer."Responses, of Pacific Herring, Clultea hareneus Rallasi. to Some
Undervrater Sounds." Can. J. Fish. Aquatic Sci. 41:1193-1192. 1984.
8A-41
-------
§ 316(b) Phose III - Technicol Development Document Attachment A to Chapter 8
Fish Diversion or Avoidance Systems I Fact Sheet No. 12:Sound Barriers
Smith, E.J., and J.K. Andersen. "Attempts to Alleviate Fish Losses from Allegheny Reservoir,
Pennsylvania and New York, Using Acoustic." North American Journal of Fisheries Management
vol 4(3), 1994. pp. 300-307.
Thorne, R.E. "Assessment of Population Density by Hydroacoustics." In Journal of Biological
Oceanography^Vol. 2. 1983. pp. 252-262.
8A-42
-------
-------
-------
-------
------- |