EIA Technical Review Guidelines:
Energy Generation and Transmission
Volume II - Appendices
Regional Document prepared under the CAFTA DR Environmental Cooperation
Program to Strengthen Environmental Impact Assessment (EIA) Review
Prepared by CAFTA-DR and U.S. Country EIA and Energy Experts with support from:
USAID
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USAID ENVIRONMENT AND LABOR
EXCELLENCE FOR CAFTA-DR PROGRAM \
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This document is the result of a regional collaboration under the environmental cooperation
agreements undertaken as part of the Central America and Dominican Republic Free Trade Agreements
with the United States. Regional experts participated in the preparation of this document, however, the
guidelines do not necessarily represent the policies, practices or requirements of their governments
and organizations.
Reproduction of this document in whole or in part and in any form for educational or non-profit
purposes may be made without special permission from the United States Environmental Protection
Agency (U.S. EPA), Agency for International Development (U.S. AID), and/or the Central American
Commission on Environment and Development (CCAD) provided acknowledgement of the source is
included.
EPA/315R11001B July 2011
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EIA Technical Review Guidelines:
Energy Generation and Transmission
Volume II Appendices
The EIA Technical Review Guidelines for Power Generation and Transmission were developed as part of
a regional collaboration to better ensure successful identification, avoidance, prevention and/or
mitigation of potential adverse impacts and enhancement of potential beneficial impacts of proposed
energy projects undergoing review by government officials, non-governmental organizations and the
general public throughout the life of the projects. The guidelines are part of a broader program to
strengthen environmental impact assessment (EIA) review under environmental cooperation
agreements associated with the "CAFTA-DR" free trade agreement between the United States and five
countries in Central America and Dominican Republic.
The guidelines were prepared by regional experts from the CAFTA-DR countries and the United States in
both the government organizations responsible for the environment and energy and leading academics
designated by the respective Ministers supported by the U.S. Agency for International Development
(U.S. AID) contract for the Environment and Labor Excellence Program and grant with the Central
America Commission for Environment and Development (CCAD). The guidelines draw upon existing
materials from within and outside these countries and from international organizations and do not
represent the policies, practices or requirements of any one country or organization.
The guidelines are available in English and Spanish on the international websites of U.S. Environmental
Protection Agency (U.S. EPA), the International Network for Environmental Compliance and
Enforcement (INECE), and the Central American Commission on Environment and Development (CCAD):
www.epa.gov/oita/ www.inece.org/ www.sica.int/ccad/ Volume I contains the guidelines with a
glossary and references which track with internationally recognized elements of environmental impact
assessment; Volume 2 contains Appendices with detailed information on energy generation and
transmission, requirements and standards, and predictive tools; and Volume 1 Part 2 contains example
Terms of Reference cross-linked to Volumes 1 and 2 for use by the countries as they prepare their own
EIA program requirements.
» USAID
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USAID ENVIRONMENT AND LABOR £
EXCELLENCE FOR CAFTA-DR PROGRAM \\ ^7 f
\ 0*°*
CEMTSOAMEBICANA OE AMBIENT Y OES««OLIQ
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Volume II - Appendices: EIA Technical Review Guidelines: TABLE OF CONTENTS
Energy Generation and Transmission
TABLE OF CONTENTS
APPENDIX A. WHAT IS ENERGY GENERATION AND TRANSMISSION?. 1
1 INTRODUCTION 1
2 ELECTRIC POWER GENERATION 1
2.1 Steam Turbines 2
2.2 Combustion Power Plants 11
2.3 Hydropower 18
2.4 Solar Power 26
2.5 Wind Power 33
2.6 Geothermal Power 36
2.7 Transmission Substation 37
3 ELECTRIC POWER TRANSMISION 37
3.1 Right-of-Ways 38
3.2 Overhead Transmission Lines 38
3.3 Underground Transmission Lines 39
3.4 Distribution Substation 40
APPENDIX B. ENERGY IN CAFTA-DR COUNTRIES. 41
1 REGIONAL OVERVIEW 41
1.1 Fuel and Energy Use Data for CAFTA-DR 41
1.2 Power Transmission 43
2 CAFTA-DR COUNTRY OVERVIEWS 44
2.1 Costa Rica 44
2.2 Dominican Republic 46
2.3 El Salvador 47
2.4 Guatemala 49
2.5 Honduras 50
2.6 Nicaragua 52
APPENDIX C. REQUIREMENTS AND STANDARDS: CAFTA-DR COUNTRIES, OTHER COUNTRIES, AND
INTERNATIONAL ORGANIZATIONS 55
1 INTRODUCTION TO ENVIRONMENTAL LAWS, STANDARDS, AND REQUIREMENTS 55
2 AMBIENT STANDARDS FOR AIR AND WATER QUALITY 59
3 ENERGY-SECTOR SPECIFIC PERFORMANCE STANDARDS 65
3.1 Energy Sector Water Discharge/ Effluent Limits 67
3.2 Supplemental U.S. Water Discharge/ Effluent Limits for the Energy Sector 69
3.3 Air Emission Limits for the Energy Sector 70
4 INTERNATIONAL TREATIES AND AGREEMENTS 84
5 ENERGY SECTOR WEBSITE REFERENCES 85
APPENDIX D. RULES OF THUMB FOR EROSION AND SEDIMENTATION CONTROL 87
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Volume II - Appendices: EIA Technical Review Guidelines: TABLE OF CONTENTS
Energy Generation and Transmission
APPENDIX E. SAMPLING AND ANALYSIS PLAN 101
1 INTRODUCTION 101
1.1 Site Name or Sampling Area 101
1.2 Site or Sampling Area Location 101
1.3 Responsible Organization 101
1.4 Project Organization 101
1.5 Statement of the Specific Problem 102
2 BACKGROUND 102
2.1 Site or Sampling Area Description [Fill in the blanks.] 102
2.2 Operational History 102
2.3 Previous Investigations/Regulatory Involvement 103
2.4 Geological Information 103
2.5 Environmental and/or Human Impact 103
3 PROJECT DATA QUALITY OBJECTIVES 103
3.1 Project Task and Problem Definition 103
3.2 Data Quality Objectives (DQOs) 103
3.3 Data Quality Indicators (DQIs) 103
3.4 Data Review and Validation 104
3.5 Data Management 105
3.6 Assessment Oversight 105
4 SAMPLING RATIONALE 105
4.1 Soil Sampling 105
4.2 Sediment Sampling 105
4.3 Water Sampling 106
4.4 Biological Sampling 106
5 REQUEST FOR ANALYSES 106
5.1 Analyses Narrative 107
5.2 Analytical Laboratory 107
6 FIELD METHODS AND PROCEDURES 107
6.1 Field Equipment 107
6.2 Field Screening 107
6.3 Soil 108
6.4 Sediment Sampling 110
6.5 Water Sampling Ill
6.6 Biological Sampling 114
6.7 Decontamination Procedures 115
7 SAMPLE CONTAINERS, PRESERVATION AND STORAGE 116
7.1 Soil Samples 116
7.2 Sediment Samples 117
7.3 Water Samples 117
7.4 Biological Samples 119
8 DISPOSAL OF RESIDUAL MATERIALS 119
9 SAMPLE DOCUMENTATION AND SHIPMENT 120
9.1 Field Notes 120
9.2 Labeling 122
9.3 Sample Chain-Of-Custody Forms and Custody Seals 122
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9.4 Packaging and Shipment 122
10 QUALITY CONTROL 123
10.1 Field Quality Control Samples 123
10.2 Background Samples 128
10.3 Field Screening and Confirmation Samples 128
10.4 Laboratory Quality Control Samples 129
11 FIELD VARIANCES 130
12 FIELD HEALTH AND SAFETY PROCEDURES 131
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Energy Generation and Transmission
Figure A-1: Energy sources and generation technologies 1
Figure A- 2: Diagram of a generator 2
Figure A- 3: A basic diagram of a steam turbine 3
Figure A- 4: Common components of power plant using a steam turbine 3
Figure A- 5: Multi-pressure steam turbines 4
Figure A- 6: Once-through cooling system diagram 5
Figure A- 7: Once-through cooling system with cooling pond diagram 6
Figure A- 8: Recirculating cooling system with cooling pond diagram 7
Figure A- 9: Cooling tower diagram 8
Figure A-10: Dry cooling tower diagram for direct cooling 9
Figure A-11: Dry cooling tower diagram for indirect cooling 10
Figure A-12: Combustion steam turbine plant diagram 14
Figure A-13: Coal-fired thermal power plant diagram 15
Figure A-14: Gas turbine diagram 16
Figure A-15: Combined-cycle generating unit 17
Figure A-16: Hydroelectric dam diagram 19
Figure A-17: Water turbine 20
Figure A-18: Diversion hydroelectric project 22
Figure A-19: Pumped storage facility operation 23
Figure A- 20: Pumped storage hydroelectric project layout 23
Figure A- 21: Wave energy devices 25
Figure A- 22: Tidal turbines 26
Figure A- 23: Solar power technologies and their environmental requirements 27
Figure A- 24: Solar parabolic trough diagram 28
Figure A- 25: Solar parabolic trough plant diagram with a liquid salt storage unit 29
Figure A- 26: Solar power tower diagram 30
Figure A- 27: Schematic of a dish-engine system with stretched-membrane mirrors 31
Figure A- 28: Schematic of a photovoltaic power generating system 32
Figure A- 29: Horizontal axis wind turbine 33
Figure A- 30: Horizontal axis wind turbine components 34
Figure A- 31: Direct drive wind turbine 35
Figure A- 32: Horizontal axis wind turbine 35
Figure A- 33: Dry steam geothermal power plant 36
Figure A- 34: Binary cycle geothermal power plant (closed-cycle) 37
Figure A- 35: Different transmission tower configurations 39
Figure B-1: Costa Rica energy generation by fuel type 2008 44
Figure B- 2: Dominican Republic energy generation by fuel type 2008 46
Figure B- 3: El Salvador energy generation by fuel type 2008 47
Figure B-4: El Salvador energy generation by fuel type 2008 49
Figure B- 5: Honduras energy generation by fuel type 2008 50
Figure B- 6: Nicaragua energy generation by fuel type 2008 52
Figure C-1: Approaches to environmental management 57
Figure C- 2: Examples of environmental requirements 58
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Table A-1: Average cooling system water use and consumption at a coal-fired thermal plant 5
Table A- 2: Relative costs of cooling systems 10
Table B-1: Electricity generation indicators 42
Table B- 2: Electrical power production and consumption in the CAFTA-DR countries in 2008 43
Table B-3: Costa Rica energy trends 1998-2008 45
Table B-4: Dominican Republic energy trends 1998-2008 46
Table B-5: El Salvador energy trends 1998-2008 48
Table B-6: Guatemala energy trends 1998-2008 50
Table B-7: Honduras energy trends 1998-2008 51
Table B- 8: Generating capacity by type and company for 2009 53
Table B-9: Nicaragua energy trends 1998-2008 54
Table C-1: Freshwater quality guidelines and standards 59
Table C- 2: Drinking water quality guidelines and standards 61
Table C- 3: Ambient air quality guidelines and standards 64
Table C- 4: Environmental impacts from renewable energy sources 66
Table C- 5: Water discharge/effluent limits applicable to steam electric plants 67
Table C- 6: NPDES effluent limitations for steam electric generating facilities 70
Table C- 7: IFC small combustion facilities emissions guidelines (3MWth-50MWth) 71
Table C- 8: IFC emissions guidelines for boiler facilities 72
Table C- 9: IFC emissions guidelines for combustion turbines (units larger than 50 MWh) 72
Table C-10: IFC emissions guidelines for reciprocating engines 73
Table C-11: Particulate matter (PM) emissions limits / reduction requirements 74
Table C-12: Sulfur dioxide (SO2) emissions limits and reduction requirements 74
Table C-13: Oxides of nitrogen (NOX) emissions limits and reduction requirements 75
Table C-14: Sulfur dioxide (SO2) emissions limits 76
Table C-15: Particulate matter (PM) emissions limits 77
Table C-16: Nitrogen oxide (NOX) emissions limits 78
Table C-17: Particulate matter (PM) emissions limits 79
Table C-18: Sulfur dioxide (SO2) emissions limits 80
Table C-19: NOX emissions limits for new stationary combustion turbines 82
Table C- 20: Sulfur dioxide (SO2) emissions limits by options 83
Table C- 21: Multilateral environmental agreements ratified (R) or signed (S) by CAFTA-DR countries ...84
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Volume II-Appendices: EIA Technical Review Guidelines:
Energy Generation and Transmission
APPENDIX A. ENERGY GENERATION/TRANSMISSION
APPENDIX A. WHAT IS ENERGY GENERATION AND TRANSMISSION?
1 INTRODUCTION
The purpose of this appendix is to provide the reviewer of an EIA for an energy generation and/or
transmission project with the basic information he or she needs to understand the technologies that are
used to generate and transmit electrical energy, and thereby understand the potential environmental
impacts of those technologies. The appendix is divided into two sections. The first section presents the
technologies for generation of electrical energy. The second section presents the technologies for
transmission.
2 ELECTRIC POWER GENERATION
There are many ways to generate electric energy, but they can be broadly divided into two groups,
based on the source of the energy used in the system:
Non-renewable, which use fossil fuels (oil, gas, diesel, petrol and coal) that have a limited
source and can be depleted, or
Renewable, which use energy sources that can be constantly renewed, and therefore are
inexhaustible, such as biomass, biofuels, hydroelectric, hydrokinetic, solar, wind and
geothermal.
The technologies used to convert non-renewable and renewable energy into electricity, however, are
not always mutually exclusive. Figure A-l shows how the various sources of renewable and non-
renewable energy can be used by generation technologies to produce electrical energy.
Figure A-1: Energy sources and generation technologies
Non-renewable
Energy Sources
Coal
Natural Gas
Diesel
Generation
Technologies
Steam Turbine
Gas Turbines
Reciprocating Engines
Photovoltaic
Water Turbines
Wind Turbines
Renewable
Energy Sources
Biomass
Solid Waste
Biofuel
Solar
Geothermal
Hydroelectric
Hydrokinetic
Wind
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Volume II-Appendices: EIA Technical Review Guidelines:
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APPENDIX A. ENERGY GENERATION/TRANSMISSION
As can be seen in Figure A-l, some generation technologies can be powered by several different forms
of energy. For instance steam turbines are typically powered by two non-renewable resources (coal and
oil) and four renewable resources (biomass, solid waste, solar power and geothermal energy). Other
technologies are associated with only one or two forms of renewable energy such as photovoltaic (solar
power) and water turbines (hydroelectric and hydrokinetic energy) and wind (wind and hydrokinetic
energy). No generating technologies are exclusively associated with non-renewable energy sources.
With few exceptions1, commercial or public electrical power is F'gure A' 2: Diagram of a generator
produced by generators. Generators are composed of coils of
copper wire (or other conducting material) that spin or rotate
between magnets, thus generating an electric current (Figure A-
2). Alternatively, the coils may surround a spinning magnet, in
which case the generator is called an alternator. In either case,
the electrical current is generated using the principle of
electromagnetic induction, which states that when an electric
conductor is moved through a magnetic field electric current will
flow in the conductor. Thus the mechanical energy of a spinning
rotor is converted into electric energy.
The task of most electrical power generation, then, is to spin the
generator. This is done either by turbines or engines. There are
four basic types of turbines: steam, gas, hydro and wind. As
shown in Figure A-l, steam and gas turbines as well as
reciprocating engines can be powered by both renewable and
nonrenewable energy sources. Hydro and wind turbines are
powered only by renewable energy sources.
This subsection will provide a basic description of each type of
generation power plant. It begins with a generic description of
the steam turbine, which is the most commonly used energy
generation technology for producing commercial or public
electrical energy. It is also the one technology that is common to many forms of renewable and non-
renewable energy sources. This is followed by a subsection on combustion systems, which includes all
sources of energy that are combusted to generate electricity. This is followed by one subsection each
on hydropower power, solar power, wind power and geothermal power.
2.1. Steam Turbines
A steam turbine is a mechanical device that extracts thermal energy from pressurized steam and
converts it into rotary motion. It has almost completely replaced the reciprocating piston steam engine
because of its greater thermal efficiency and higher power to weight ratio. About 80 percent of all
electricity generation in the world is by use of steam turbines. Figure A-3 presents a very basic diagram
of how a steam turbine works. Although it is simplistic, Figure A-3 clearly presents the basic concept:
some form of heat is used to create steam, which is then passed across blades of a turbine causing it to
turn, thus rotating a generator and producing electricity. Of course actual designs are quite
1 The exceptions to using rotary generators to produce electricity are solar photovoltaic systems and fuel cells.
Solar photovoltaic systems are described in this appendix. Fuel cells are not included in these guidelines, as they
are not commonly used for commercial electrical power generation.
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Volume II - Appendices: EIA Technical Review Guidelines: APPENDIX A. ENERGY GENERATION/TRANSMISSION
Energy Generation and Transmission
complicated, with the shape and the size of the turbine as well as the shape and configuration of the
blades being specially designed to insure maximum of conversion of the heat and pressure in the steam
to electrical energy. For instance, steam expands as it works, so the turbine is wider at the end where
the steam exits than it is where it enters.
Figure A- 3: A basic diagram of a steam turbine
GENERATOR
BOfLEfl
HE*T
MAGNET
Source: Based on a figure from
http://cr4.globalspec.com/comment/641909
2.1.1. Common System Components
All power plants that use steam turbines have some common components (Figure A-4). These include
A source of water Figure A-4: Common components of power plant using a
A source of steam steam turbine
Steam turbines
Generators
A steam condenser
A cooling system
Cooling
Water
Source: Based on a figure from the Electropedia website.
http://www.mpoweruk.com/steam turbines.htm
Steam turbines need water and a
means of converting water into steam
to operate. The steam can be
generated by many different
technologies:
Combustion of fuel including
fossil fuels, biomass, biofuels
and solid waste
Solar power
Geothermal energy
The specific ways that each of these technologies generates steam are discussed below in the
subsections on these technologies.
However the steam is generated, it leaves the steam generator at high temperature (up to 900°C) and
high pressure and flows through pipes into the turbine, where it flows across blades causing them to
turn and drive a shaft that is connected to the generator. The speed at which the turbine spins can is
controlled by the rate at which the steam is allowed to enter the turbine. The rate is controlled by the
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Volume II-Appendices: EIA Technical Review Guidelines:
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APPENDIX A. ENERGY GENERATION/TRANSMISSION
steam valve, which in turn is controlled by a feedback loop from the generator which allows the system
to be set up to turn insure that the generator is turned at an optimal speed to produce electricity.
The energy of the steam decreases as it turns the blades, so that it leaves the turbine at a lower
pressure and cooler temperature than when it entered the turbine. Steam turbines can be designed to
work at various pressures, and often different pressure turbines are installed in series to take advantage
of the decreasing pressure of the steam as it moves through the turbines (Figure A-5).
Figure A- 5: Multi-pressure steam turbines
High
Pressure
Turbine
Medium
Pressure
Turbine
Generator
Hie
Steam
Reheat
Source: http://www.mpoweruk.com/steam turbines.htm
Eventually, the steam has too little
energy left to turn a turbine, at
which point it is passed to a
condenser. The condenser has
tubes running through it in which
cool water is flowing. The flowing
cool water removes the heat from
the steam until it condenses back
into water and flows or is pumped
back to the steam generator to be
used again. The condenser cools
the steam to the point where it
has zero volume (i.e., it has moved
back into a liquid phase). This
creates near vacuum conditions in
the condenser, which further "sucks" steam through the low pressure turbine, enabling the maximum
amount of energy to be extracted from the steam and converted into electrical energy.
At some industrial and commercial facilities that have their own power plants, the "spent" steam may
be used for heating or other uses, thus eliminating the need for a condenser. But this is not a common
practice at power plants.
2.1.2. Cooling Systems
The water used in the condenser's coils comes from a cooling system. The water in the cooling system is
separate from the "working" water in the steam system, although they usually come from the same
source. A constant flow of cooling water is required to reduce the temperature of the steam and water
in the condenser. The heat carried away from the condenser is waste heat, and usually accounts for
about 50 percent of the total heat energy that is emitted from the steam generator (the other 50
percent being converted into mechanical energy inside the turbines). Steam turbine electric plants use
either once-through cooling water systems or recirculating cooling water systems.
2.1.2.1. Once-Through Cooling
In once-through cooling water systems, the cooling water is withdrawn from a body of water, flows
through the condenser, and is discharged back to the body of water (Figure A-6). Once-through systems
require a significant amount of water for cooling. For example, a 200 MW coal-fired plant can require
up to 480,000 m3 per day of cooling water (Table A-l). If that water is supplied via a once-through
system, then that full amount of water is needed each day. If, on the other hand, the cooling water is
reused after being cooled by a pond or a tower, the amount of water needed each day can drop to
15,000 m3. However, once-through systems consume less water. That is because the cooling water is
generally not raised to evaporative temperatures in the cooling system, so that almost 100 percent of
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APPENDIX A. ENERGY GENERATION/TRANSMISSION
the withdrawn for cooling is discharged back into the source. At a typical coal-fired 200 MW plant with
a once-through cooling system may only consume 1,000 m3 per day of cooling water, or less than 0.2
percent of the water withdrawn. The same size facility using a cooling pond or cooling tower may only
use 15,000 m3 per day of cooling water, but will consume nearly all of it (14,000 m3) due to evaporation.
Figure A- 6: Once-through cooling system diagram
Low Pressure
Steam
Table A-1: Average cooling system water use and consumption at a coal-fired thermal plant
Type of Cooling Water
System
Once-Through
Recirculating Wet
Water Use
Average
(m3/MWh)
142.7
4.5
200MW Plant
(1,000 m3/day)
480
15
Water Consumption
Average
m3/MWh
0.4
4.2
200MW Plant
(1,000 m3/day)
1
14
Source: Average water use from Feeley 2005.
http://204.154.137.14/technologies/coalpower/ewr/pubs/IEP Power Plant Water R&D Final l.pdf.
Average capacity factor for coal plant from U.S. DOE 2010.
http://www.eia.doe.gov/cneaf/electricity/epa/epa sum.html
Although once-through systems consume very little water, they require large amounts, and the water
they discharge back into the environment is at elevated temperatures, which can have a significant
impact on aquatic ecosystems if the quantity of discharged water exceeds the receiving water's capacity
to dilute the temperature to an acceptable level. Some once-through designs use cooling ponds at the
end of the cooling system to allow the water to cool to an acceptable level before being discharged back
to the source (Figure A-7). Another practice which has had some use in the United States is to build
constructed wetlands to receive cooling water and provide additional cooling before returning water to
the source. Constructed wetlands are not as deep as a cooling pond, so more land is needed to treat the
same volume of water. These systems loose more water to evaporation (one of the primary cooling
mechanisms in the ponds and wetlands) than a simple once-through system, however, rainwater runoff
and direct precipitation will compensate for part of the evaporation losses.
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Figure A- 7: Once-through cooling system with cooling pond diagram
Precipitation
& Runoff
Low Pressure
Steam
Pressure Steam
2.1.2.2. Recirculating Cooling
In a recirculating cooling system the water that passes through the condenser is sent to a cooling pond
or cooling tower to lower its temperature so that it can be reused in the cooling system. At some plants
both ponds and towers are incorporated into the cooling system. Recirculating cooling systems can be
divided into two groups: wet cooling, which relies upon evaporation for cooling, and dry systems, that
use air too cool the turbine steam or cooling water.
Wet Cooling
Wet cooling systems may use either cooling towers or cooling ponds to reduce the temperature of the
cooling water before it is recirculated through the condenser. Ponds are generally less expensive as
they do not required extensive construction and maintenance and generally require lower pumping
costs. Ponds can also create secondary recreational uses such as fishing, swimming, boating, camping
and picnicking and can also been used as fish hatcheries. Ponds, however, require much more space
than towers.
In a recirculating cooling pond system, cooling water is drawn from and discharged to the cooling pond
(Figure A-8). Water in the pond will evaporate, as one of the key cooling mechanisms. The evaporation
will be somewhat compensated by rainwater runoff and direct precipitation, but make up water will
have to be withdrawn from the source to compensate for the remainder of evaporation. If the site
hydrology is favorable, the evaporation losses from the cooling pond could be balanced by rainwater
harvesting, making the cooling pond a "closed system," needing no water from the source. In this way,
pond recirculating systems often consume less water than tower systems.
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Figure A- 8: Recirculating cooling system with cooling pond diagram
Precipitation
& Runoff
Evaporation
tat*
Heated Water
/ ^ 1
\
i
Cooling Pond
Pond /
Cooled Water
/"
Condenser
_^/ Low Pres
Steam
Return^
Water
Pressure Steam
The size of the pond will depend upon the size of the power plant, in that it must be large enough to
provide adequate cooling water during periods of peak production. Depending on the design, it may
also be quite deep, because deep water tends to stay cooler longer.
In a cooling tower, the heated water from the condenser enters at the top and falls down through a fill
material with a high surface area that interrupts the flow of the water (Figure A-9). Depending on the
design of the fill material, the water will either splash or trickle through the tower. In either case, as
water flows downward, air flows upward through the tower, causing some of the water to evaporate.
As water evaporates, the heat required to evaporate the water is transferred from the water to the air,
thus cooling the water. The water that does not evaporate is collected at the bottom of the tower and
pumped back to the condenser. In the process, however, water is lost via evaporation, so that
additional fresh water must be periodically added to the cooling system.
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Figure A- 9: Cooling tower diagram
Condenser
Cooling
Tower
Make-up Water
Recirculated Cooling
Water
Cooling Tower
Slowdown
Source: U.S. EPA 2009, Table 3-4.
http://www.epa.gov/waterscience/guide/steam/finalreport.pdf
As cooling water evaporates in the cooling tower dissolved minerals present in the water remain behind
in the fill material and on the inside of the tower walls. Over time, these minerals will increase in
concentration and can inhibit the effectiveness of the tower. To prevent a build of minerals, a volume of
water must be discharged periodically to purge the minerals from the system, which is referred to as
"cooling tower blowdown."
Cooling towers be hyperboloid or rectangular structures. Hyperboloid structures can be larger than
rectangular structures, up to 200 meters tall and 100 meters in diameter. Rectangular structures can be
over 40 meters tall and 80 meters long.
Cooling towers use two mechanisms to draw air up through the water: natural draft and mechanical
draft. Some plants combine natural and mechanical components in a fan assisted natural draft.
Natural draft towers rely on the difference in air density between the warm air in the tower and the
cooler ambient air outside the tower to draw the air up through the tower. Hyperboloid cooling towers
(as shown in Figure A-9) have become the design standard for natural draft cooling towers because of
their structural strength and minimum usage of material and because their shape aids in accelerating
the upward convective air flow.
Mechanical draft towers utilize fans to move air up through the tower. They may be hyperboloid or
rectangular structures. The fans may be used to create an induced draft with fans at the discharge to
pull air through tower, or a forced draft with a blower type fan at the intake pushing air up through the
tower. Forced draft design has some technical drawbacks as well as usually requiring bigger fans, so
they are less common than induced draft towers.
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Dry Cooling
Dry cooling towers are essentially large radiators hot water flowing down through the tower through
multiple layers of relatively small diameter, finned pipes. Air is passed up through these pipes by large
fans at the top or bottom of the tower (depending on the design), thus cooling the water before it is
used again. Dry cooling towers are usually rectangular or A-frame in shape.
Dry cooling towers can either use direct or indirect cooling. In direct cooling systems, the turbine
exhaust steam flows directly to the tower, where it is cooled and reused in the boiler (Figure A-10). In
an indirect cooling system the hot cooling water flowing out of the condenser is pumped up to the top
of the tower, where it flows down through the tower, cooling on its way, and then is used again in the
condenser (Figure A-ll).
Figure A-10: Dry cooling tower diagram for direct cooling
Low Presssure
Steam
Condensate
Pressure Steam
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Figure A-11: Dry cooling tower diagram for indirect cooling
Heated
Water
* *^_
Air In
^Mi
Water
Condenser
^s Low Pres
Steam
Return
Water
Pressure Steam
Dry cooling is the most expensive form of cooling (Table A-2), but it may be necessary in areas where
there is a water shortage or other limitation on water availability. Because dry cooling systems transfer
heat to the atmosphere without water evaporation, they use very little water.
Table A- 2: Relative costs of cooling systems
Item
Capital Cost
Cooling System Power
(major component of operating costs)
Power Production Cost
Type of Cooling System
Once-Through
Base
Base
Base
Wet Tower
Base + 0.4%
Base + 2.5 MW
Base + 1.9%
Dry Cooling
Base + 12.5
Base + 3.0MW
Base + 4.9%
Source: Bengtson 2010
2.1.2.3. Discharges
In addition to minerals that accumulate on the fill material and are periodically removed with
blowdown, cooling water may contain other chemicals associated with cooling water treatment. As the
cooling water passes through the condenser, microbiological species (e.g., bacterial slimes and algae)
stick to and begin growing on the condenser tubes, which reduces heat transfer, decreases flow, and
accelerates corrosion of the condenser. Various macro-organisms, such as mussels, mollusks, and
clams, can also inhibit condenser performance. Steam electric plants use biocides, such as sodium
hypochlorite, sodium bromide, chlorine gas and antimicrobials to control these biological problems.
As a result, once-through cooling water and cooling tower blowdown may contain the following
pollutants, often in low concentrations: chlorine, iron, copper, nickel, aluminum, boron, chlorinated
organic compounds, suspended solids, brominated compounds, and nonoxidizing biocides. Although
the pollutants present in cooling water-related wastewaters are often at low concentrations, the overall
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pollutant mass discharge may be significant due to the large flow rates of cooling water discharges at
steam electric power plants.
2.2. Combustion Power Plants
In these guidelines, the term combustion or thermal/combustion power plants is used to refer to all
power plants that use the combustion of fuels to either directly or indirectly turn generators or
alternators that produce electrical energy. The fuels may be non-renewable (coal, oil, natural gas, or
diesel) or renewable (biomass, solid waste, or biofuel).
The fuels are combusted to power three different types of electrical power generating technologies:
steam turbines, gas turbines and reciprocating engines. Each technology has its own unique design
characteristics and components, which are described in the following subsections. The technologies can
be divided into two groups: external and internal combustion. External combustion means that
combustion of the fuel is external to the machinery that turns the generator or alternator to produce
electricity. Steam turbines rely upon external combustion. Internal combustion means that the fuel is
combusted internal to the engine, as in a confined chamber or cylinder and that the energy of the
combustion is directly converted into mechanical action that turns generators or alternators. Gas
turbines and reciprocating engines are internal combustion engines.
Fossil fuels include coal, various types of fuel oil, natural gas and diesel. Gasoline may also be used to
fuel generators, but it is generally not used at commercial facilities for this purpose, so it is not discussed
in these guidelines. Two major categories of fuel oil are burned for power generation: distillate oils
(grade Nos. 1 and 2) and residual oils (grade Nos. 5 and 6). Grade No. 4 oil is either distillate oil or a
mixture of distillate and residual oils. No. 6 fuel oil is sometimes referred to as Bunker C.
Biomass and biofuels are a renewable energy source derived from living, or recently living organisms
(i.e., not fossilized carbon), such as wood, waste, plants and algae. Biomass is generally considered solid
fuel such asfuelwood, charcoal, agricultural crops and by-products, forest residues, industrial wood
wastes and solid waste. Biofuels are derived from conversion of biomass (organic material) into a
combustible fuel. Biomass can be converted into biofuels via physical extraction (as in the case of some
oils), decomposition, fermentation, thermal processes, or chemical processes. Biofuels may be gases
such as methane or liquids such as ethanol or biodiesel. Most biofuel production comes from harvesting
organic matter and then converting it to fuel but an alternative approach relies on the fact that some
algae naturally produce ethanol and this can be collected without killing the algae.
2.2.1 Fuel Storage
Different fuels have different storage needs. Solid fuels such as coal and biomass are generally stored in
piles. Runoff from the piles in the case of coal will contain pollutants, and biomass piles may also
generate pollutants in the runoff, so both types of piles need to have run-on and runoff control
structures. Coal piles may also need to be covered to prevent runoff caused by rainfall.
Liquid fuels need to be stored on-site in tanks. The tanks need to be placed on impervious containment
structures to prevent contamination from leaks and spills. Natural gas is generally piped into a facility,
thus requiring no storage.
If biofuels are to be used, they may be generated off site and transported to the site or generated on-
site. Generation may involve digesters, fermenters and distillers.
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Some fuels, like coal, heavy oil and biomass, create ash during combustion. Facilities are required for
handling and disposing of these wastes.
2.2.2 Air Emission Controls
Combustion power plants all emit exhausts that can be significant sources of air emissions with the
potential for significant impacts to ambient air quality. They will nearly always include post-combustion
emission control devices to control emissions of PM, SO2, NOX and CO2.
Post-combustion control of PM emissions from coal-, biomass- and oil-fired plants can be accomplished
by using one or more or the following particulate control devices:
Electrostatic precipitators (ESPs) are commonly used in coal- and oil-fired power plants.
Because of their modular design, ESPs can be applied to a wide range of system sizes.
Fabric filter (or baghouse), a number of filtering elements (bags) along with a bag cleaning
system are contained in a main shell structure incorporating dust hoppers.
Wet scrubber, including Venturi and flooded disc scrubbers, tray or tower units, turbulent
contact absorbers, or high-pressure spray impingement scrubbers. They are applicable for PM
as well as SO2 control on oil-, coal- and biomass fired plants.
Cyclone separators can be installed singly, in series, or grouped as in a multicyclone or
multiclone collector. These devices are referred to as mechanical collectors and are often used
as a pre-collector upstream of an ESP, fabric filter, or wet scrubber so that these devices can be
specified for lower particle loadings to reduce capital and/or operating costs. Although these
devices will reduce PM emissions from coal combustion, they are relatively ineffective for
collection of particles less than 10 micron (PM10). In oil-fired plants, cyclones are primarily
useful in controlling particulate matter generated during soot blowing, during upset conditions,
or when very dirty heavy oil is fired.
Side stream separators combine multicyclones and a small pulse-jet baghouses to more
efficiently collect small-diameter particles that are difficult to capture by a mechanical collector
alone. Most applications to date for side-stream separators have been on small stoker coal-
fired boilers. Atmospheric fluidized bed combustion (AFBC) coal-fired boilers may tax
conventional particulate control systems.
Flue gas desulfurization (FGD) is the post-combustion control technology for SO2 emissions from fossil
fuel-fired power plants. It uses an alkaline reagent to absorb SO2 in the flue gas and produce a sodium
or calcium sulfate compound. These solid sulfate compounds are then removed in downstream
equipment. FGD technologies are categorized as wet, semi-dry, or dry depending on the state of the
reagent as it leaves the absorber vessel. These processes are either regenerable (such that the reagent
material can be treated and reused) or non-regenerable (in which case all waste streams are de-watered
and discarded).
Post-combustion control of NOX emissions are:
Selective non-catalytic reduction (SNCR), which involves injecting ammonia (NH3) or urea into
specific temperature zones in the upper furnace or convective pass. The NH3 or urea reacts with
NOX in the flue gas to produce nitrogen, CO2 and water.
Selective catalytic reduction (SCR), which is an add-on NOX control placed in the exhaust stream
following the engine and involves injecting NH3 into the flue gas. The NH3 reacts with the NOX in
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the presence of a catalyst to form water and nitrogen. The SCR reactor can be located at various
positions in the process including before an air heater and particulate control device, or
downstream of the air heater, particulate control device, and flue gas desulfurization systems.
Carbon capture may involve either pre-combustion or post-combustion separation of CO2 from emission
sources. Pre-combustion CO2 capture typically involves gasification processes, such as integrated
gasification combined cycle (IGCC) technology, where coal or biomass is converted into gaseous
components by applying heat under pressure in the presence of steam. IGCC plants may be designed so
that concentrated CO2 at a high pressure can be captured from the synthesis gas that emerges from the
gasification reactor before it is mixed with air in a combustion turbine. Because CO2 is present at much
higher concentrations in synthesis gas than in post-combustion flue gas, IGCC systems currently appear
to be the economic choice for new plants.
Post-combustion CO2 capture involves physical and chemical processes to separate CO2 from the
exhaust flue gas. These systems might be applicable to retrofits of conventional coal or biomass energy
plants, and also might be applicable to other thermal/combustion energy production technologies.
However, such systems are challenging and, currently, costly because the low pressure and dilute CO2
concentrations dictate a high actual volume of gas to be treated. Further, trace impurities in the flue gas
tend to reduce the effectiveness of the CO2 adsorbing processes, and compressing captured CO2 from
atmospheric pressure to pipeline pressure represents a large parasitic load. One technological option,
oxygen combustion (oxy-combustion), combusts coal in an enriched oxygen environment using pure
oxygen diluted with recycled CO2 or water. This process enables a relatively concentrated stream of CO2
to be captured by condensing the water in the exhaust stream. Oxy-combustion offers several potential
benefits for existing coal- and biomass-fired plants.
After the CO2 emissions have been collected/captured, the CO2 must be sequestered (immobilized or
removed), either geologically (e.g., saline aquifers) or via enhanced oil recovery. In the U.S., significant
research is ongoing to demonstrate the feasibility of geologic sequestration in saline aquifers and to
overcome implementation barriers, such as concerns about safety, effectiveness, liability, and public
acceptance.
Another potential type of CO2 sequestration is CO2-enhanced oil recovery, a commercially proven
technology that has been used extensively in the United States to increase oil production at diminished
wells. In CO2-enhanced oil recovery, compressed CO2 is injected into an oil reservoir near the
production well site, forcing the oil toward the production well and increasing yield. Several planned
IGCC plants in the U.S. expect to derive a substantial economic benefit through the sale of their CO2 for
CO2-enhanced oil recovery.
2.2.3 Combustion Power Plants Using Steam Turbines
Combustion steam turbine power plants may be fueled by coal, oil, natural gas, biomass and biofuel.
Biomass fuels for these types of plants are most often wood, hemp, miscanthus, crop or agricultural
production by-products (straw, field residues, rice husks, corn cobs, bagasse2, etc.) and solid waste. At
least one combustion steam turbine plant in the CAFTA-DR region, the Monte Rosa plant in Nicaragua,
burns biogas made from vinasse, the still bottoms left after distillation of fermented sugarcane. The fuel
is combusted in a combustion chamber. The heat energy generated by the combustion of fuel is
transformed into electrical energy indirectly, usually by means of heating boilers or boiler tubes to
2 The fibrous matter that remains after sugarcane or sorghum stalks are crushed to extract their juice.
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generate steam. The resulting steam is then used to power steam turbines or engines that turn
generators or alternators, thus creating electrical energy. A diagram of a combustion steam turbine
plant is shown in Figure A-12.
Figure A-12: Combustion steam turbine plant diagram
Exhaust
Gases
(Biomass
c
Coal
Oil
Gas
^
r
Condenser
Cooling
System
i
L
Electrical
Power
All of the components of a combustion steam turbine plant to the right of the boiler have been
previously described in subsection 2.1 Steam Turbines. These components are common to any steam
turbine system. Fuel storage and air emission controls, which are common to all combustion power
plants, are discussed in subsections 2.2.1. and 2.2.2. This section, therefore, focuses on the combustion
chamber, boiler and ancillary equipment.
A more detailed diagram of a combustion steam turbine power plant is presented Figure A-13. Although
this diagram is for a coal powered plant, the basic components are similar for any thermal/combustion
steam turbine plant. The key differences among thermal/combustion steam turbine plants are due to
differences in fuel and combustion waste by products, so that components 14 through 16 and 18 in the
diagram may be different for different types of fuels.
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Figure A-13: Coal-fired thermal power plant diagram
1. Cooling system
2. Cooling water pump
3. Transmission line
4. Step-up transformer
5. Electrical generator
6. Low pressure steam turbine
7. Condensate pump
8. Surface condenser
9. Intermediate pressure steam
turbine
10. Steam Control valve
11. High pressure steam turbine
12. Deaerator
13. Feedwater heater
14. Coal conveyor
15. Coal hopper
16. Coal pulverizer
17. Boiler steam drum
18. Bottom ash hopper
19. Superheater
20. Forced draught (draft) fan
21. Reheater
22. Combustion air intake
23. Economiser
24. Air preheater
25. Emissions control
26. Induced draught (draft) fan
27. Flue gas stack
Source: http://en.wikipedia.org/wiki/Thermal_power_station
The combustion chamber is typically an integral component of the boiler as shown in Figure A-13. It
consists of fuel and air inputs as well as a combustion zone. Depending on the design, the fuel and/or
air may have some pre-treatment. For example, Figure A-13 includes a coal pulverizer, which crushes
the coal before it is introduced to the combustion chamber. Fuel is delivered into the boiler's furnace
where it is combusted to heat water in a pressurized vessel in small boilers or in a water-wall tube
system in modern utility boilers. Additional elements within or associated with the boiler, such as the
superheater, reheater, economizer and air heaters, improve the boiler's efficiency.
Apart from the basic steam raising and electricity generating equipment, there are several essential
automatic controls and ancillary systems which are necessary to keep the plant operating safely and at
its optimum capacity. These include:
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Controls for:
o matching the power output to the demand,
o maintaining the system voltage and frequency, and
o keeping the plant components within their operating pressure, temperature and speed
limits.
Lubrication systems.
Systems to prepare and feed the fuel to the combustion chamber and remove the ash.
Pumps and fans for water and air flow.
Cooling the generator.
Overload protection, emergency shut down and load shedding.
2.2.4 Gas Turbine
Gas Turbines, also called combustion turbines, extract energy from the flow of combustion gas across
turbine blades. They consist of a compressor that compresses air, which is fed into a combustion
chamber. Fuel is also introduced into the combustion chamber, where it ignites with the air creating a
high pressure, high velocity exhaust gas, which is then directed to the turbine (Figure A-14). They are
typically fueled by natural gas or oil, but could potentially be fueled by biofuel (e.g., biodiesel or biogas.
They range in size from 500 kW up to 25 MW for distributed electrical power systems and up to 250 MW
for central power generation. Gas turbines can
.,,.,. * -ru i Figure A-14: Gas turbine diagram
provide baseload in a power system. They also
have the advantage of the ability to be turned
on and off within minutes, making them useful
for supplying power during peak demand.
The exhaust gas from a gas turbine is capable of
producing high-temperature steam, so many
power plants use gas turbines in combination
with steam turbines to generate electrical
power. These systems are called combined-
cycle generating units (Figure A-15). In these
units, the exhaust gases from the gas turbines
are fed into the heat recovery steam generator
(HRSG), also known as a boiler, thus reducing
the amount of fuel needed to produce steam
and improving the efficiency of electricity
generation. Most new gas power plants in
North America and Europe are of this type. For
large scale power generation a typical set would be a 400 megawatt (MW) Gas Turbine coupled to a 200
MW Steam Turbine giving 600 MW. A typical power station might comprise of between 2 and 6 such
sets.
Fuel
Combustion
Work
out
Exhaust
gasses
Source: Based on Wikipedia figure.
http://en.wikipedia.org/wiki/Brayton cycle
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Figure A-15: Combined-cycle generating unit
Bypass
Slat*
(Optional)
Sl«ick
Gaseous or
Licurirt Fuel
'1
1
r
COMBUSTOR
»
STEAM
i TURBINE
GENERATOR
PUMP
CONDENSER
Feedwaler
COOLING
GENERATOR
Source: http://wwwl.eere.energy.gov/tribalenergy/guide/images/illust combinedcycle
generating sys.gif
Micro turbines are small gas turbines fueled by natural gas, diesel and biogas that produce between 25
kW and 500 kW of power. Their designs evolved from automotive and truck turbocharger technologies
as well as small jet engines and aircraft auxiliary power units. The earlier models merely released
exhaust gases to the environment, but most new models are using recuperating technologies, which
recover the heat from the exhaust gases to boost the temperature of the combustion and increase
efficiency.
They are still in the development stage for use in electrical power generation, but many micro turbine
installations are currently undergoing field tests, including some that are part of large-scale
demonstrations. Some are also being tested using landfill gases as the fuel. They may become popular
in the future due to their small size, light weight, small number of moving parts, and low emissions.
2.2.5 Reciprocating Engine Generators
A reciprocating engine generator is a combination of an internal combustion engine, a generator and
various ancillary devices such as base, canopy, sound attenuation, control systems, circuit breakers,
jacket water heaters, starting systems etc. Sizes up to about five MW are used for small power stations,
which may use up to 20 units. In these larger sizes the engine and generator are brought to site
separately and assembled along with ancillary equipment.
Only large capacity diesel, natural gas or biofuel reciprocating engine generators are considered in these
guidelines as gasoline powered systems are generally not used in the energy sector. Diesel generators,
sometimes as small as 250 kilovolt amps, are widely used at power plants not only for emergency
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power, but also many have a secondary function of feeding power to utility grids either during peak
periods, or periods when there is a shortage of large power generators.
One or more diesel generators operating without a connection to an electrical grid are said to be
operating in "island" mode. Several parallel generators provide the advantages of redundancy and
better efficiency at partial loads. An island power plant intended for primary power source of an
isolated community will often have at least three diesel generators, any two of which are rated to carry
the required load. Groups of up to 20 are not uncommon.
Diesel engines are often used for back up generation, usually at low voltages. However most large
power grids also use diesel generators, originally provided as emergency back up for a specific facility
such as a hospital, to feed power into the grid during certain circumstances.
2.3. Hydropower
Hydropower refers to any project that produces electricity by using the gravitational force of falling or
flowing water to generate electrical energy. Hydropower is subdivided into two categories:
hydroelectric power and hydrokinetic power. Hydroelectric power generates electricity from the flow of
water, generally using a dam or a diversion, whereas hydrokinetic projects generate electricity from the
movement of waves or currents without the use of a dam or diversion. Micro-hydroelectric refers to
hydroelectric power systems of 100 kW capacity or less and can include technologies that require
neither a dam nor a diversion.
2.3.1 Hydroelectric Power
There are two types of hydroelectric power projects: conventional and pumped storage. Each is
described in its own subsection below. Both types of projects have common components, as can be
seen in Figure A-16:
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Figure A-16: Hydroelectric dam diagram
Substation
Source: Based on a diagram from the Tennessee Valley Authority.
http://www.tva.gov/power/images/hydro.png
Intake - gates on the dam or diversion through which water flows via gravity. Most intakes will
have gates for controlling or stopping flow as well as screens to keep debris and fish out of the
system.
Penstock - a pipeline or tunnel that leads from the intake to the turbine. Water builds up
pressure as it flows through penstock.
Powerhouse - a structure housing the turbine and generator, and often components of the
substation.
o Turbine - a rotary shaft with large blades which turn when the water from the penstock
flows across the blades (Figure A-17).
o Generator - attached to and turned by the turbine. In a large plant, a turbine can weigh as
much as 172 tons and turn at a rate of 90 revolutions per minute (rpm).
Tailrace - a channel, pipeline or tunnel that carries the water from the turbine to the outflow.
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Figure A-17: Water turbine
Generator
Turbine
Generator Shaft
Turbine
Wicket
Gate
Turbine Blades
Source: U.S. Corps of Army Engineers
http://www.nwp.usace.army.mil/HDC/edu genexcit.asp
Outflow - the point where water that has passed through the turbine is returned to the river.
Substation - the facility that prepares the electricity produced by the generator(s) for
transmission by the use of transformers to raising its voltage to transmission levels and switches
and breakers to allow control of electrical flow.
Hydroelectric power is categorized by capacity and hydraulic head. Capacity is expressed in kilowatts
kW or megawatts (MW). Plants with a capacity less than 5 kW are called pico. Between 5 and 100 kW
they are micro. Mini plants have a capacity of lOOkW to 1 MW. Small plants have a capacity of from 1
to 30MW, and large plants have a capacity greater than 30 MW. In the past, most hydroelectric projects
connected to the grid in CAFTA-DR countries were large. But in the past several years, several mini and
small hydroelectric projects have been constructed and put into operation.
Hydraulic head refers to the altitude change between the water surface at the intake to the penstock
and the turbines. Low head is less than 30 meters. Medium head is 30 to 300 meters, and high head is
greater than 300 meters. The energy created by the moving water depends on the volume flowing past
the turbine and the head. As the volume and head increase, so does the electricity generated.
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2.3.1.1. Conventional Hydroelectric
Conventional projects use a dam or diversion. They may operate in a run-of-the-river mode, where
outflow from the project approximates inflow, or peaking, where flows are stored and released on a
daily, monthly, or seasonal basis. Only projects with a dam and reservoir can operate in a peaking
mode. A typical diagram of a dam project is shown in Figure A-16. The water in the reservoir is
considered stored energy. When the gates open, the water flowing through the penstock becomes
kinetic energy because it's in motion, and can be used to turn the turbines and generate electricity on
demand. In dams, the head is determined by the amount of water in the reservoir, with the head being
highest when the reservoir is full. To increase "head" for electrical generation, the developer may
construct the powerhouse downstream from the dam, diverting water from a section of river known as
the bypassed reach.
Project that use diversions may have small dams in the river to create the diversion, or may use other
instream structures to divert the water. Figure A-18 shows a typical diversion hydroelectric project.
Water is usually diverted into a canal that travels at a low gradient until it reaches a point where the
water can be delivered into a high gradient penstock. At this point there is a head works or a forebay
that directs the water into the penstock. The water flowing through the penstock creates the head
necessary to turn the turbines.
The stretch of river between the intake and the outflow is called the bypass reach. Those projects that
use dams for diversion have the potential to divert all of the water in the river, leaving the bypass reach
dry some or all of the time.
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Figure A-18: Diversion hydroelectric project
Source: World Bank. Renewable Energy Toolkit Technology Module. Pg. 3.
http://siteresources.worldbank.org/INTRENENERGYTK/Resources/REToolkit Technologies.pdf
Most micro-hydroelectric projects are diversion and run-of-river projects. Some projects, however, may
have small impoundments. Others may use instream turbines, requiring no dam or diversion. These
systems, however, are for very small projects and generally are not used to provide power to the grid.
2.3.1.2. Pumped Storage Hydroelectric
In a conventional hydroelectric facility, water passes from the intake, through the turbine and out the
outflow one time. In a pumped storage facility, water may pass through the turbine multiple times. This
is accomplished by using two reservoirs, an upper reservoir and a lower reservoir. During periods of
peak demand (during the day when offices and air conditioning are functioning) water flows via gravity
from the upper reservoir, through the turbine to the lower reservoir. During this period, the upper
reservoir level is allowed to drop. During off-peak periods (when people are sleeping), water in the
lower reservoir is pumped back up to the upper reservoir through a reversible turbine. This process is
shown in Figure A-19.
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Figure A- 19: Pumped storage facility operation
D ayti rn e: Wate r fl o ws d o wn h i 11 th ro u g h
turbines, producing electricity
Nightime: Water pumped uphill to
re s e rvo i r fo r to m o rro w' s u s e
Source: http://ga.water.usgs.gov/edu/hyhowworks.html
The energy used to pump the water is excess, off-peak energy. Essentially, the upper reservoir is being
used as a battery that is recharged during off-peak periods by pumping water into it. The recharged
upper reservoir will then have more water in it, ready to generate electricity during periods of peak
consumption. Pumped storage reservoirs can be relatively small, or they can be located to take
advantage of existing lakes or reservoirs (Figure A-20), so construction costs are generally lower
compared with conventional hydropower facilities.
Figure A- 20: Pumped storage hydroelectric project layout
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2.3.2 Hydrokinetic Power
Hydrokinetic power is defined as projects that generate electricity from waves or directly from the flow
of water in ocean currents, tides or inland waterways without use of a dam. Hydrokinetic power is a
newer development and it is estimated that 30% or more of global power needs in nations having
enough coastal access could be generated using hydrokinetic power.
There are four types of wave energy devices: point absorbers, attenuators, overtopping terminators,
and oscillating water column terminators (see Figure A-21). Current and tide energy devices consist of a
rotor and generator, similar to wind turbines (Figure A-22). The two types are axial, which are typically
horizontal and cross flow (either vertical or horizontal).
2.3.2.1. Point Absorbers
Point absorbers are floating structures with one component (generally a buoy) that moves up and down
with wave action and another component that is fixed to the ocean floor or relatively fixed via a
submerged damper. The two components move independently, causing a piston action, which is
converted to energy via electromechanical or hydraulic converters. Point absorbers are not currently
being used anywhere as a major energy source, but experimental versions have proven that they
produce energy.
2.3.2.2. Attenuators
Attenuators are long, multi-segment floating structures oriented parallel to the direction of wave travel.
The motion of the waves moves the segments independently, causing them to flex at the joints where
the segments connect. The flexing action is converted into energy via hydraulic pumps or other
converters. Those connected to hydraulic pumps pressurize hydraulic fluid, which is then used to drive a
generator. The first commercial wave farm using Pelamis attenuators began operation in 2008 off the
coast of Portugal (Agucadoura). But since has shut down; first for technical reasons, then for later for
financial reasons.
2.3.2.3. Overtopping Terminators
Overtopping terminators float at or near the ocean surface, perpendicular to the direction of wave
travel and located near the shore where waves break. They have reservoirs that are filled when waves
overtop the structure. After the device is overtopped, the water in the reservoir is above the average
surrounding sea level. The water is then released through a controlled opening in the reservoir, and
gravity causes it to fall back toward the ocean surface. The energy of the falling water is used to turn
conventional, low-head hydro turbines. No overtopping terminators are currently proposed for use in
the United States; however, projects and prototypes have been demonstrated in the United Kingdom,
Denmark and Portugal.
2.3.2.4. Oscillating Water Column
Oscillating water column (OWC) terminators are built on shore, perpendicular to the direction of wave
travel. When waves break on shore, water enters through a subsurface opening into a chamber with air
trapped above it. The wave action causes the captured water column to move up and down like a
piston, forcing the air though an opening connected to a wind turbine. A full-scale, 500-kW, prototype
OWC designed and built by Energetech is undergoing testing offshore at Port Kembla in Australia. The
technology has also been demonstrated in the United Kingdom and Portugal, and at least two projects
are under development in the United States.
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Figure A- 21: Wave energy devices
Point Absorbers
Attenuators
Overtopping Terminators
overtopping
reservoir
Reinforced concrete
capture chamber set into
the excavated rock face.
The Wells turbines rotate in the same
direction regardless of the direction of the air
flow, thus generating irrespective of upward
or downward movement of the water column.
Oscillating Water Column
Terminators
Air is compressed and decompressed by
the Oscillating Water Column (OWC).
This causes air to be forced out and then
sucked back through the Wells turbine.
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Figure A- 22: Tidal turbines
i
Sea Level
Current
Saatwd
2.4. Solar Power
Solar energy can provide electrical power for distribution by utilities in sizes ranging from 10's of
megawatts to a 1,000 megawatts. Solar power plants can be stand-alone or hybrid plants in which solar
and other power sources are combined. Solar power can be used to generate electricity either directly
through use of photovoltaic cells or by heating a fluid or gas which then drives a steam turbine or a
Stirling or Brayton heat engine.
Solar power is divided into two generic types: concentrating solar power and photovoltaic (PV) (Figure
A-23). The following subsections present basic information on each of these technologies.
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Figure A- 23: Solar power technologies and their environmental requirements
CONCENTRATING SOLAR POWER SYSTEMS
Parabolic Trough
Rows of parabolic mirrors each with an
absorber tube
Thermal power plant
Land requirement-2 hectares/MW
Water - 7,400 to 16,000 m3/yr/MW
Linear Fresnel System
Rows of long narrow mirrors low to
ground focused on an absorber tube
Thermal power plant
Land requirement-2 hectares/MW
Water - 7,400 to 16,000 m3/yr/MW
Power Tower
Central tower (300-450 ft height)/field
of mirrors
Thermal power plant
Land requirement-3.6 hectares/MW
Water - 7,400 to 16,000 m3/yr/MW
Parabolic Dish
Dish shaped mirror/heat piston engine
Sterling or Brayton engine, no thermal plant
Land requirement-3.6 hectares/MW
Water - 62 m3/yr/MW
PHOTOVOLTAIC/CONCENTRATED PHOTOVOLTAIC
Solar cell panels
No thermal plant
Land requirement-4 hectares/MW
Water - 62 m3/yr/MW
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2.4.1 Concentrating Solar Power - Steam Turbines
Concentrating Solar Power (CSP) technologies use mirrors to concentrate or focus the sun's light energy
and convert it into heat to achieve sufficient fluid temperatures to efficiently produce electrical energy.
Higher efficiencies reduce the plant's collector size and total land use per unit power generated,
reducing the environmental impacts of a power plant as well as its expense.
There are two primary types of CSP plants that use the sun's heat to produce steam to turn steam
turbines, those using parabolic troughs or linear Fresnel arrays and those using power towers and those
using parabolic dishes. These systems are described in the following subsections. In both systems the
super heated transfer fluid (usually some form of oil) is used to generate steam to power a turbine,
similar to that used in other steam turbine power plants. As such, a solar thermal plant will have all of
the components described in subsection 2.1 Steam Turbines.
All parabolic trough, linear Fresnel and power tower plants generate heat to convert water to steam,
but many plants also store excess heat for subsequent use. With current technology, storage of heat is
much cheaper and more efficient than storage of electricity. The storage system is shown in the
"Thermal Storage" component in Figure A-25. This design runs a heat transfer fluid through the
parabolic array and to a heat exchanger for the water/steam system, turning the water into steam that
then drives a steam turbine. When the sun is strong enough to provide more energy than is needed for
the direct heat exchanger, a portion of the heated transfer fluid passes through an exchanger for the
liquid salt system, which heats liquid salt from the cold tank and stores it in the hot tank. When the
solar energy is insufficient to provide the necessary energy to transform water into steam, the hot liquid
salt can be pumped through the heat exchanger, thus boosting the temperature of the transfer fluid.
When the sun goes down, the storage system can continue to heat the fluid. In this way, the CSP plant
can produce electricity day and night.
Because both types of systems produce steam for a steam turbine, they can also be hybridized with an
external source of heat, such as a fossil fuel, biomass or biofuel boiler. In this way, when sunlight and
heat storage is not sufficient, the plant can be operated with the boiler, thus improving the reliability of
the system.
2.4.1.1. Parabolic Troughs and Linear Fresnel
System
With a parabolic trough system the sun's
energy is concentrated using parabolically
curved, trough-shaped reflectors (Figure A-24)
onto a receiver pipe running along the focal line
of the curved surface in which there is a heat
transfer fluid. A Fresnel system is similar to a
trough system in that mirrors focus the sun's
energy onto a pipe in which there is a heat
transfer fluid. The mirrors, however, are in long
narrow strips located close to the ground.
Parabolic trough and linear Fresnel plants
consist of a large array (two hectares per MW)
of these reflectors tied into a steam turbine
power system.
Figure A- 24: Solar parabolic trough diagram
Reflector
Absorber tube
Solar field piping
Source: IEA2010. Pg. 11.
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Figure A-25 shows a diagram of parabolic trough solar plant. It shows how the parabolic trough arrays
heat the transfer fluid, which in turn passes through a heat exchanger to generate steam for the
"Power-block." The "Power-block" component of the diagram has the same components as any other
steam turbine power plant. This diagram also includes a heat storage system as discussed above. A
plant using linear Fresnel arrays instead of parabolic trough arrays would have the same diagram, with
only the type of array being different.
Figure A- 25: Solar parabolic trough plant diagram with a liquid salt storage unit
1. Parabolic troughs
2. Transfer fluid piping
3. Oil/salt heat exchange
4. Salt piping
5. Hot salt storage tank
6. Cold salt storage tank
7. Oil/Steam heat exchange
8. Water-Steam piping
9. Steam turbine
10. Generator
11. Substation
12. Heat exchange
13. Cooling Tower
Source: International Energy Agency. 2010. Technology Roadmap: Concentrating Solar Power. Paris. Pg.
13. http://www.iea.org/papers/2010/csp roadmap.pdf
2.4.1.2. Power Towers
Power towers utilize an array of sun-tracking mirrors (heliostats) to focus sunlight on a receiver at the
top of a tower in the center of the array, which contains a heat transfer fluid. Figure A-26 shows a
typical diagram of a power tower generating facility. Although the diagram only shows one array, this is
only an indication of how an array concentrates and reflects and sunlight onto the receiver. An actual
power tower plant would have many arrays completely surrounding the tower, as shown in the photo in
Figure A-23. The arrays require an area of 3.6 hectares per MW. Although the figure is not set up in the
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same format as Figure A-25, it has the same components and would operate in the same way as a
parabolic trough system with heat storage capacity.
Figure A- 26: Solar power tower diagram
Source: http://www.solarpaces.org/CSP Technology/docs/solar tower.pdf
2.4.2 Concentrating Solar Power - Parabolic Dish-Engines
CSP parabolic dish systems use a mirror array (also called concentrators) to reflect and concentrate the
sun's energy on a receiver which transfers the energy to a working fluid or gas that in turn powers an
engine that turns a generator or alternator (Figure A-27). These systems are often referred to as solar
dish-engine systems. A solar dish power plant will have several of these dish- engines. The electrical
energy is generated at each engine, so the fluid or gas does not need to be piped through the facility.
The electrical energy is transported to the collector substation via electrical cabling. To make the arrays
effective, each must track the sun in two axes, so that the reflected energy is always concentrated on
the receiver.
The engines that are generally favored are the Stirling and Brayton engines. The Stirling engine is an
internal combustion piston engine with an inert working fluid, usually either helium or hydrogen. It
requires a cooling system, which is generally a radiator. The linear energy of the pistons is converted
into rotary energy to drive a generator. The Brayton engine is a gas turbine. It discharges most of the
waste heat in the exhaust. Both types of engines can be operated using other sources of external heat,
such as fossil fuel, so that they can function even when solar radiation is too low or non-existent.
Solar-dish systems require about the same area as power tower systems, 3.6 hectares per MW. They
use significantly less water than the other CSP systems because they do not have to condense steam
coming out of turbines. Water use at these facilities is primarily for washing mirror surfaces.
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Figure A- 27: Schematic of a dish-engine system with stretched-membrane mirrors
StMlngEnghe
f Recever
Source: http://www.solarpaces.org/CSP Technology/docs/solar dish.pdf
2.4.3 Solar Photovoltaic
A solar cell is a device that converts sunlight into electric current. The cell is constructed of
semiconductor materials similar to those used in computer chips. When exposed to the sunlight, these
materials absorb photons and release electrons. The free electrons can be captured and converted into
electrical energy. There are fourteen competing types of photovoltaic cells, including monocrystalline
silicon, polycrystalline silicon, and amorphous cells. It is too early to know which technology will
become dominant.
Each solar cell is generally very small and capable of generating only a few watts of electricity. They are
typically combined into modules of about 40 cells, and the modules are assembled into photovoltaic
(PV) arrays up to several meters on a side. A PV generating facility will have hundreds of these arrays
connected together and set at a fixed angle facing south, or mounted on tracking devices that follow the
movement of the sun (Figure A-28). A single-axis array tracks the sun from East to West during the day
and can provide 30%-40% more energy than a fixed array.
The energy collected by the arrays is direct current, so it has to be transformed into alternating current
before it can be delivered to the grid. The conversion is accomplished using inverters. The resulting
energy is than adjusted to the necessary voltage and frequency with the use of transformers, switches
and control circuits.
Concentrating PV (CPV) systems are a relatively new method of electricity generation from the sun. CPV
systems employ lenses and mirrors to focus greater amount of solar energy onto highly efficient solar
cells. This greatly increases the efficiency of the cells. CPV systems must track the sun to keep the light
focused on the PV cells, which generally requires highly sophisticated tracking devices.
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CPV systems require 4 hectares per MW, the largest land requirement of any of the solar power
systems. As with solar-dish systems, the only water requirements at these facilities are for cleaning the
arrays.
Figure A- 28: Schematic of a photovoltaic power generating system
Solar arrays
Sources: U.S. Department of Energy, http://solareis.anl.gov/documents/docs/NREL PV 2.pdf and
http://solareis.anl.gov/guide/solar/pv/index.cfm
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Figure A- 29: Horizontal axis wind turbine
2.5. Wind Power
Wind power converts the movement of air - wind
into electrical energy much in the same way as
hydropower converts moving water into
electricity. Air flows past the blades of the wind
turbine, converting the flowing motion into
rotary energy. That energy is then used to spin
a shaft that leads from the hub of the rotor to a
generator. The generator turns that rotational
energy into electricity.
There are two general types of wind turbine,
horizontal and vertical axis. Horizontal axis wind
turbines (HAWT), the more commonly used
type, are comprised of blades situated
perpendicular to the direction of wind flow and
are typically like a very large two- or three-
bladed aircraft propeller (Figure A-29). All
commercially produced, utility-scale wind
turbines are HAWTs. HAWTs need to constantly
align themselves with the wind (either into the
wind or with the wind, depending upon the
design of the turbine) using a yaw-adjustment
mechanism. HAWTs use a tower to lift the turbine components to an optimum elevation for wind speed
(and so the blades can clear the ground) and take up very little ground space since almost all of the
components are up to 80 meters in the air. The towers require a substantial foundation. HAWTs are
generally described referring to their hub height and rotor diameter (Figure A-29).
Current utility-grade wind turbines are 100 meters or higher at the hub, and typically have capacities of
from 100 kilowatts to as large as five megawatts. Larger wind turbines are grouped together into wind
farms.
Large HAWT have several components, as shown in Figure A-30:
Rotor Blades that capture the wind's energy and sends it to the hub. Most commercial HAWT
turbines have either two or three blades.
Rotor Hub, where the energy from the blades is converted to rotational energy and passed on to
the low speed shaft.
Source: http://ec.europa.eu/research/energy
/nn/nn rt/nn rt wind/images/wind en
1370.gif
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Nacelle, the casing that holds:
o Low Speed Shaft that transfers Figure A-30: Horizontal axis wind turbine
rotational energy into the gear components
box.
o Gearbox that increases the
speed from the low speed
shaft from about 15 to 60 rpm
to about 1000 to 1800 rpm,
the rotational speed required
by most generators to produce
electricity.
o High Speed Shaft that drives
the generator.
o Generator that generates
electricity using
electromagnetism.
o Brakes that stop rotation of
shaft in case of power
overload or system failure.
Yaw Drive and Motor (not shown
in the figure) located at the top of
the tower and below the nacelle
to move rotor to align with
direction of wind. They are
controlled by a controller
connected to a wind vane to sense
the direction of the wind. In some
designs, the yaw motor and
controls are located inside the
nacelle.
Tower that supports the rotor and nacelle and lifts entire setup to higher elevation where blades
can safely clear the ground. Towers are made from tubular steel (shown in figure), concrete or
steel lattice.
Power Line (inside the tower) that carries electricity from the generator down to the
transformer.
Transformer that increases voltage that comes from the generator (from 500 to 1,000 volts) up
to distribution levels (thousands of volts), so that it can be sent via cables to the collection point
where the power from all of the turbines are collected.
In addition to these components, most wind turbines have an anemometer to measure wind speed,
which is connected to a controller inside the nacelle that starts up the machine at wind speeds of about
8 to 16 miles per hour (mph) and shuts off the machine at about 55 mph. Turbines do not operate at
wind speeds above about 55 mph because they might be damaged by the high winds. The controller
also monitors the performance of other components in the system and shuts down the turbine should
something be malfunctioning.
Low-speed High-speed
Shaft S".nft
Brake Brake Generator
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Figure A- 31: Direct drive wind turbine
Generator
Rectifier unit
Excitation control
There is another type of HAWT that is gaining some popularity for electrical power generation, the
direct drive or gearless wind turbine. This design consists of two circular arrays of magnets surrounded
by conductive wire set parallel to each other and to
the rotor blades inside the nacelle (Figure A-31).
One is attached to the shaft of the rotor. The other
is held in a fixed position. The act of spinning the
array attached to the generator over the fixed array
generates electrical power using the principle of
electromagnetism. These types of turbines have
fewer moving parts and thus are easier to maintain
and generate less vibration and noise. However,
they produce direct current, so require the use of
converters to produce electrical current necessary
for commercial production. Direct drive turbines
were initially small capacity units, but some major
wind turbine companies are now investing into
their development and are producing large,
commercial direct drive turbines.
Vertical-axis wind turbines (VAWTs) are rare. The
only one currently in commercial production is the
Darrieus turbine, which looks kind of like an
egg beater (Figure A-32). In a VAWT the shaft
is mounted on a vertical axis perpendicular to
the ground. Because of their design, VAWTs
are always aligned with the wind, so there is
no mechanism required to adjust to wind
direction, it cannot start on its own and needs
a boost from its electrical system to get
started. Instead of a tower, it typically uses
guy wires for support, so the rotor elevation is
lower. Lower elevation means slower wind
due to ground interference which reduces
wind speed, so VAWTs are generally less
efficient than HAWTs. All equipment is at
ground level which improves accessibility for
maintenance and repairs, but it also means
that each turbine has a larger footprint than a
HAWT. VAWT systems are, however, gaining
in popularity due to easier installation and
service, lower visual and sound profile, lower
impact on bat and bird populations, and ability
to collocate on the footprints of existing
HAWT farms thereby generating additional
power at a lower incremental cost per
additional MW installed.
Nacelle
Control cabinet
Source: http://www.eolectric.com/assets/
honeywood/images/techno picl big.jpg
Figure A- 32: Horizontal axis wind turbine
Source: http://science.howstuffworks.com/environ
mental/green-science/wind-power2.htm
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Due to changing meteorological conditions and wind speed variability, wind is an inconsistent source of
energy, thus wind energy requires storage or backup generation systems. This could include demand-
side energy management, but if that is insufficient the project will have to include backup power
generation from hydropower, fossil fuel or other sources.
Figure A- 33: Dry steam geothermal power plant
Generator
2.6. Geothermal Power
Geothermal power plants are steam turbine systems with geothermal heat providing the heat for
producing steam. As such, they have
all of the components described in
subsection 2.1 Steam Turbines. There
are three types of geothermal power
plants: dry steam, flash steam, and
binary cycle. Dry steam power plants
pipe steam directly from underground
wells to the power plant, where it is
directed into a steam
turbine/generator unit (Figure A-33).
These systems require sources of
underground steam, which are not
common.
Flash steam power plants are the
most common. They use geothermal
reservoirs of water with temperatures
greater than 182°C, which flows up
through wells under its own pressure.
As it flows upward, the pressure
decreases and some of the hot water
boils into steam. The steam is then
separated from the water and used to
power a steam turbine/generator.
Source: http://content3.iason.org/common/uploads/
gateduploads/oip curriculum/images/oip m4 mb8 l.jpg
Both dry and flash steam plants are open-cycle systems, meaning that the geothermal water and steam
is not fully contained and can off-gas air emissions.
Binary cycle power plants operate on water at lower temperatures from about 107° to 182°C. These
plants use the heat from the hot water to boil a working fluid, usually an organic compound with a low
boiling point. The working fluid is vaporized in a heat exchanger and used to turn a turbine/generator
unit or a Sterling engine/generator. The water is then injected back into the ground to be reheated
(Figure A-34). The water and the working fluid are kept separated during the whole process, so there
are little or no air emissions. For that reason, these plants are called closed-cycle systems.
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Figure A- 34: Binary cycle geothermal power plant (closed-cycle)
Binary Cycle Power Plant
Turbine Generator
. l I in mi in mil 11
Heat exchanger
with working fluid
I Rock layers
fc Production : 1 Injection 1
*fe v/ell *TJ "
t^^AM^^M^^MM^^^H
Source: http://www.eriding.net/media/photos/environment/power/geothermal/090407
rfoster mp env power geothermal binaryplant.jpg
2.7. Transmission Substation
Up to this point electricity has been produced but it must pass through one more stage before it is ready
to be transmitted somewhere for use. Electric power that leaves generators or photovoltaic cells needs
to be prepared for transmission. This is done at a transmission substation. This substation brings
together energy generated by different points in the plant (different generators or photovoltaic cell
arrays) and uses large transformers to increase voltage to 155,000 to 765,000 volts (depending on the
transmission line design and the distance that the electricity has to travel) in order to reduce line losses
during transmission. The transmission substation also has switches and circuits to control the electricity
and allow power to specific lines to be turned on and off as needed for maintenance and repair. If the
electricity generated is direct current, as from photovoltaic cells and direct drive wind, the substation
also has converters or inverters to convert the current to alternating current.
Geothermal electric plants have until recently been built exclusively on the edges of tectonic plates
where high temperature geothermal resources are available near the surface. The development of
binary cycle power plants and improvements in drilling and extraction technology may enable enhanced
geothermal systems over a much greater geographical range.
3 ELECTRIC POWER TRANSMISION
Electric power transmission is the bulk transfer of electrical energy between the point of generation and
multiple substations near a populated area or load center. Electric power transmission allows distant
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energy sources to be connected to consumers in population centers. Transmission may be via overhead
or underground lines, however, most transmission is done with overhead lines because they are less
costly to construct and easier to maintain. Underground lines are generally restricted to urban areas.
A power transmission network is referred to as a "grid." Multiple redundant lines between points on
the grid are provided so that there are a variety of routes from any power plant to any load center. The
specific routing of electricity on the grid at any time is based on the economics of the transmission path
and the cost of power.
Power plants produce three phase alternating current (AC) electricity, which is boosted to high voltage
by transformers for transmission. For this reason, out of every power plant come three lines and
transmission is done with three lines, one each for the three phases of power being produced. Each
group of three lines is called a circuit. High voltage direct current is sometimes transmitted for long
distance transmission or some undersea cables, or for connecting two different AC networks. Electricity
is usually transmitted at high voltages (110 KV or above) to reduce the energy lost in transmission.
3.1. Right-of-Ways
Every transmission line has right-of-ways, the areas of land over which, or under which, the transmission
line runs. The owner of the transmission line does not own these lands, but has agreements with the
landowners that can restrict uses of the land and access to transmission structures. Overhead lines
generally have right-of-ways with widths of 25 or more meters. The width depends upon the width of
the towers. Sometimes one right-of-way may carry more than one set of towers, in which case the
right-of-way must be wider. In some cases, new circuits can be added to existing towers, so that the
right-of-way can remain the same. Underground lines need a narrower surrounding strip of about 1 to
10 meters.
Right-of-ways have to be managed to ensure that transmission structures are not compromised. In
addition, right-of-ways for overhead lines must be maintained to ensure that vegetation and activities
do not infringe upon the lines.
3.2. Overhead Transmission Lines
Overhead transmission lines are made of bare metal, uninsulated conductors. The conductor material is
nearly always an aluminum alloy, made into several strands and possibly reinforced with steel strands.
The conductors are usually 2 to 3 centimeters in diameter. Improved conductor material and shapes are
regularly used to allow increased capacity and modernize transmission circuits. Because the lines are
uninsulated, minimum clearances must be observed to maintain safety both in terms of access from the
ground and from the airspace.
Power is conducted in circuits, with each circuit being made up of three lines, one each for each phase
of electricity being transmitted. In addition to these three lines, there is usually a fourth, smaller
diameter line that runs above the power conductors called a shield line. The shield line carries no
electricity, and is designed to protect the conductors from lightening strikes. Sometimes towers may
carry two circuits (six power lines) in which case the system is called a double-circuit.
The lines are suspended on towers. Transmission towers can range from 20 to 45 meters in height. The
lines either hang from or are run over towers on insulators to which keep the electrical energy from
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Energy Generation and Transmission
coming in contact with the towers. Transmission towers can be constructed of wood or metal and can
have various shapes. Some typical tower configurations are shown in Figure A-35.
Figure A- 35: Different transmission tower configurations
r<
Single-Circuit
Davit
Single-Ciicuic
H-Fr;u:ie
Double-Circuit
Davit
Sing-le-Circ'jit
Horizontal line Psst
Source: Public Service Commission of Wisconsin, no date, Figure 4.
The spacing of towers depends upon their height, their load capacity limits and the minimum ground
clearance required at the low point in the lines. Single-pole structures may require concrete
foundations in areas with weak or wet soil. Guy wires or other support structures may be required if the
transmission route must make a change in direction.
3.3. Underground Transmission Lines
Although more costly and therefore less used, burying power cables underground can assist the
transmission of power across:
Densely populated urban areas
Areas where land is unavailable or planning consent is difficult
Rivers and other natural obstacles
Land with outstanding natural or environmental heritage
Areas of significant or prestigious infrastructural development
Areas with high risk of damage from severe weather conditions (mainly wind)
Areas with concerns about emission of electromagnetic fields (EMF). (All electric currents
generate EMF, but the shielding provided by the earth surrounding underground cables restricts
their range and power.)
Most high-voltage underground cables for power transmission that are currently sold on the market are
insulated by a sheath of cross-linked polyethylene (XLPE). Some cable may have a lead or aluminum
jacket in conjunction with XLPE insulation to allow for fiber optics to be seamlessly integrated within the
cable.
Instead of towers, underground cables have periodic manholes that allow access to the cables, or at
least some parts of the cables. In addition to higher installation costs, underground lines also have
higher maintenance and operation costs. Whereas finding and repairing overhead wire breaks can be
accomplished in hours, underground repairs can take days or weeks, and for this reason redundant lines
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Energy Generation and Transmission
are run. Operations are more difficult since the high reactive power of underground cables produces
large charging currents and so makes voltage control more difficult.
3.4. Distribution Substation
At the other end of the system, before the power is distributed to consumers, the electrical power must
be stepped-down from the high voltages at which it left the power plant. The place where the voltage is
stepped down is called a distribution substation. A distribution substation typically does several things:
It reduces voltage using transformers that step transmission voltages (in the tens or hundreds of
thousands of volts range) down to distribution voltages (typically less than 10,000 volts).
It stabilizes voltage going into distribution lines via voltage regulators, to prevent under- and
over-voltage conditions.
It has a "bus" that can split the distribution power off in multiple directions.
It often has circuit breakers and switches so that the substation can be disconnected from the
transmission grid or separate distribution lines can be disconnected from the substation when
necessary.
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APPENDIX B. ENERGY IN CAFTA-DR COUNTRIES
1 REGIONAL OVERVIEW
Initially all power generation utilities and transmission companies in the CAFTA-DR area were state-
owned. Over the past several decades, however, independent power producers and private sector
investors began participating in power generation and transmission, so that now only in Costa Rica does
power generation and transmission remain a state-owned concern. Although many multinationals
remain in Latin America with stakes in a few companies, there are now clearly six companies with a
major presence. These are AES from the United States; AEI, a Cayman Islands based fund holding the
former assets of Enron; the three Spanish companies: Endesa, Iberdrola, and Union Fenosa; and Suez
(Hall 2007).
1.1. Fuel and Energy Use Data for CAFTA-DR
Table B-l presents electricity generation indicators for the CAFTA-DR countries. Table B-2 presents data
on production and consumption of electrical energy in each CAFTA-DR country. Production is
disaggregated by type of generation. Consumption is disaggregated by sector.
As can be seen in Table B-l, there is a clear relationship between energy consumption per capita and
GDP per capita in the CAFTA-DR countries. The countries with the highest per capita gross domestic
product (GDP) (Costa Rica, Dominican Republic and El Salvador, respectively) also have the highest
energy consumption per capita (Costa Rica, Dominican Republic and El Salvador, respectively). Costa
Rica, the country with the highest per capita GDP, has a level of energy consumption per capita 4.6
times greater than that of Nicaragua, the country with the lowest per capita GDP. Per capita GDP is also
strongly positively correlated with access. Ninety-nine percent of the population in Costa Rica has
access to electricity, whereas only 70 percent have access in Honduras and 72 percent in Nicaragua. All
countries, however, have made improvements in access over the past 10 years.
The relationship of per capita energy consumption to per capita CO2 emissions, however, is not strong.
This is because the source of the energy is as important of a factor as is the amount of energy
consumed. Costa Rica has lower per capita CO2 emissions than Dominican Republic, even though it
consumes 1.34 times as much energy per capita, because 90 percent of its electrical energy is generated
by hydroelectric and geothermal power, whereby 89 percent of electrical power in Dominican Republic
is generated from the combustion of fossil fuels (Table B-2).
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APPENDIX B. ENERGY IN CAFTA-DR COUNTRIES
Table B-1: Electricity generation indicators
Indicator
Population (million)
GDP (billion 2000 USD)
Per Capita GDP (2000 USD)
Access to Electricity (% of Pop)
Electricity Consumption (GWh)
Per Capita Electricity
Consumption (kWh/person)
CO2 Emissions (Mt of CO2)*
Per Capita CO2 Emissions
(t CO2/person)
Costa Rica
4.53
23.52
5,192
99.1
8,408
1,863
6.58
1.45
Dominican
Republic
9.84
36.07
3,666
95.9
13,113
1,393
19.56
1.99
El Salvador
6.13
16.42
2,679
86.4
5,710
953
5.82
0.95
Guatemala
13.68
26.09
1,907
80.5
7,175
543
10.61
0.78
Honduras
7.24
10.50
1,450
70.3
5,168
715
7.80
1.08
Nicaragua
5.68
5.13
903
72.1
2,282
402
4.14
0.73
Notes:
* CO2 Emissions from fuel combustion only. Emissions are calculated using the International Energy Agency's
energy balances and the Revised 1996 IPCC Guidelines.
Sources: International Energy Agency: http://www.iea.org/country/index nmc.aspfor all but access
http://www.worldenergyoutlook.org/database electricity/electricity access database.htm for access
The other three countries all derive 62 percent or more of their electrical power from the combustion of
fossil fuels. Oil is the most commonly used fossil fuel in the region for electrical energy generation.
Guatemala and Dominican Republic also have coal-fired power plants. Dominican Republic is the only
country in the region that generates electric power using natural gas.
All of the CAFTA-DR countries are importers of fossil fuels. None of the countries have proven reserves
of coal or natural gas, and although Guatemala has small proven reserves of oil, in 2008, it still only
pumped 23 percent of the amount of oil it consumed (for all uses).
Until 2009, Costa Rica was the only country in the region that used wind power to produce commercial
electric power, however, in 2009 a new wind facility began operation in Nicaragua. The potential exists
to expand the use of wind in the region. The central mountainous ridgeline running from Costa Rica
through Nicaragua and Honduras/El Salvador border and in to southeastern Guatemala has potential for
wind development. Coastal wind energy is also attractive on the Atlantic coast, and to a lesser extent on
the Pacific coast of Central America. Wind energy potential has been extensively studied in Dominican
Republic by the National Renewable Energy Laboratory (Elliot 2001), which concluded that
approximately three percent of the land area of Dominican Republic (coastal and high elevation) has
good to excellent wind energy potential that could produce over 24 gigawatt hours (GWh) of electricity,
or 50 percent more than the total amount of production in 2008.
The primary consumers of electrical power in all of the CAFTA-DR countries are residences, industry and
commercial and public services. The distribution among these groups, however, varies among the
countries. In Dominican Republic, El Salvador and Guatemala approximately 40 percent of all
consumption is by industry, whereas in the other countries industry accounts for 23 to 28 percent of
consumption. The largest residential consumption is in Costa Rica and Honduras, accounting for
approximately 40 percent of consumption in each country, while the other residential consumption
ranges from 32 to 34 percent in the other countries. Dominican Republic has the lowest consumption
by commercial and public services (15%), with the other countries ranging from 27 to 35 percent. Only
three countries have consumption by agriculture and forestry, and in all three cases these are the
smallest category of consumers (Costa Rica 4%, Dominican Republic 11%, and Nicaragua 3%).
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APPENDIX B. ENERGY IN CAFTA-DR COUNTRIES
Table B- 2: Electrical power production and consumption in the CAFTA-DR countries in 2008
Production from:
Coal
Oil
Gas
Biomass
Waste
Nuclear
Hydro
Geothermal
Solar PV
Solar Thermal
Wind
Tide
Other Sources
Total Production
Imports
Exports
Domestic Supply
Losses*
Final Consumption
Industry %
Transport %
Residential %
Commercial and Public Services
%
Agriculture / Forestry %
Fishing %
Other Non-Specified %
Notes:
Transmission losses as well as Ic
Source: International Energy Ag
Electricity (Gigawatt hours - GWh)
Costa Rica
0
677
0
82
0
0
7,387
1,131
0
0
198
0
0
9,475
96
-166
9,405
997
8,408
23
0
40
33
4
0
Dominican
Republic
2,133
9,528
1,996
29
0
0
1,728
0
0
0
0
0
0
15,414
0
0
15,414
2,301
13,113
41
0
33
15
11
0
0
El Salvador
0
2,298
0
105
0
0
2,038
1,519
0
0
0
0
0
5,960
83
-89
5,954
244
5,710
39
0
32
30
0
0
0
Guatemala
1,131
2,322
0
1,552
0
0
3,712
0
0
0
0
0
0
8,717
5
-76
8,646
1,471
7,175
39
0
34
27
0
0
0
sses/use at the generating plants.
ency http://www.iea.org/country/index nmc.asp
Honduras
0
4,049
0
197
0
0
2,291
0
0
0
0
0
0
6,537
0
-12
6,525
1,357
5,168
27
0
41
32
0
0
0
Nicaragua
0
2,167
0
338
0
0
534
322
0
0
0
0
0
3,361
28
0
3,389
1,107
2,282
28
0
32
35
3
0
0
1.2. Power Transmission
Currently few electrical transmission interconnections exist in Central America, and those that do are
often old and unreliable. In 2008, distribution losses in Central America ranged from 2 percent in El
Salvador to 23 percent in Nicaragua with an average of 13 percent. Dominican Republic had a
distribution loss in the same year of 13 percent. For all of the countries improvements in transmission
and distribution systems over the past 10 years has resulted decreases in distribution losses.
The proposed Sistema de Interconexion Electrica para America Central (SIEPAC) or Central American
Electrical Interconnection System is a project for a unified electricity transmission grid joining together
all the Central American countries, which when it becomes operational will further reduce distribution
losses and improve the efficiency of electrical energy use in Central America. The project entails the
construction of nearly 1,800 kilometers (km) of transmission lines connecting 37 million consumers in
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Panama (150 km), Costa Rica (490 km), Honduras (270 km), Nicaragua (310 km), El Salvador (290 km),
and Guatemala (280 km). In 2003, SIEPAC was estimated to cost about US$320 million and was
scheduled for completion in 2006. More than 90 percent of the rights of way for the line had been
acquired by May 2007. Construction on the first towers did not begin until 2007. The project is now
estimated to be completed by the end of 2011 at a cost of nearly $500 million.
The funding for the project is primarily coming from the Inter-American Development Bank in US$240
million of hard and soft loans to the six Central American countries and the Central American Bank for
Economic Integration with an US$ 80 million in loans. Also participating in the financing is the Spanish
government, six Central American nations, the Spanish multinational power company Endesa, and the
Colombian firm ISA.
SIEPAC would be owned by Entidad Proprietaria de la Red, a regional operations entity created in 1999
with registration in Panama, and comprising the public utilities and transmission companies of the six
participating countries (75 percent) and private capital (25 percent). In some countries integrated
utilities are shareholders - ENEE of Honduras, ICE and CNFL of Costa Rica - while in others shares are
held by transmission companies - INDE of Guatemala, ETESA of Panama, and ENTE of Nicaragua. In the
case of El Salvador the utility CEL and the transmission company ETESAL own the shares jointly. The
private shareholders are Endesa of Spain and ISA from Colombia. The project is currently managed by a
unit under the Consejo de Electrificacion de America Central.
2 CAFTA-DR COUNTRY OVERVIEWS
2.1. Costa Rica
Costa Rica relies upon hydroelectric power
more than any other country in the CAFTA-DR
region, with hydroelectric power providing 68
percent of the total power generation in the
country (Figure B-l). Geothermal power is the
second largest source of electrical power,
providing 12 percent. The remaining 20
percent is supplied by oil (7%), wind (2%) and
biomass (1%). Costa Rica is the only country in
the CAFTA-DR region that uses wind power to
generate electrical power.
As can be seen in Table B-3, hydroelectric
power and geothermal have been the primary
sources of electric power generation since at
least 1999.
Figure B-1: Costa Rica energy generation by fuel
type 2008
Source of data: Table B-2
The state-run electrical utility Institute Costarricense de Electricidad controls some 80 percent of
installed electricity generating capacity. Twenty-seven privately-owned companies own about 13
percent of total installed capacity, with the remaining seven percent run by cooperatives for rural
electrification. Four cooperatives (Coopelesca, Coope Alfaro Ruiz, Coope Guanacaste and Coope Santos)
operate in rural regions of Costa Rica, all of them organized on a not-for-profit basis.
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APPENDIX B. ENERGY IN CAFTA-DR COUNTRIES
Table B- 3: Costa Rica energy trends 1998-2008
Petroleum Products (1,000 Barrels/Day)
Total Consumption
Fuel Oil Consumption
Proved Reserves (Billion Barrels)
Natural Gas (Billion Cubic Feet)
Consumption
Proved Reserves (Billion Barrels)
Coal (Million Short Tons)
Production
Consumption
Electricity Net Generation (GWh)
Conventional Thermal
Hydroelectric
Geothermal
Wind
Solar, Tidal and Wave
Biomass
Net Consumption* (GWh)
Imports
Exports
Electricity Distribution Losses
Carbon Dioxide Emissions (Million Metric
Tons of C02) Consumption of Fossil Fuels
1999
35.75
19.58
0.0
0.0
0.0
0.0
0.0
6,073
125
5,084
764
96
0.0
4
5,472
1
128
474
5.14
2000
36.28
16.53
0.0
0.0
0.0
0.0
0.0
6,782
56
5,617
927
166
0.0
16
5,834
22
497
473
5.01
2001
37.59
17.66
0.0
0.0
0.0
0.0
0.0
6,813
94
5,597
937
170
0.0
15
6,064
130
379
500
5.22
2002
39.66
16.84
0.0
0.0
0.0
0.0
0.0
7,343
115
5,871
1,065
242
0.0
50
6,185
35
478
715
5.39
2003
41.92
19.28
0.0
0.0
0.0
0.0
0.1
7,352
125
5,864
874
219
0.0
270
6,649
100
273
530
5.95
2004
41.56
18.67
0.0
0.0
0.0
0.0
0.1
8,056
180
6,421
937
243
0.0
275
6,937
202
440
881
5.72
2005
40.61
18.38
0.0
0.0
0.0
0.0
0.0
8,124
278
6,502
1,091
194
0.0
60
7,310
81
70
825
5.65
2006
42.00
23.06
0.0
0.0
0.0
0.0
0.1
8,522
501
6,535
1,154
260
0.0
71
7,746
149
60
865
6.64
2007
44.00
25.36
0.0
0.0
0.0
0.0
0.1
8,861
679
6,701
1,177
229
0.0
75
8,117
203
40
908
7.22
2008
48.00
NA
0.0
0.0
0.0
0.0
1.3
9,290
636
7,313
1,075
188
0.0
78
8,247
96
166
973
7.14
Notes:
NA = Information not available
* Net generation + electricity imports - electricity exports - electricity distribution losses.
Source: U.S. Energy Information Agency http://www.eia.gov/cfapps/ipdbproiect/IEDIndex3.cfm
Governmental authority for energy policy lies with the Ministry for Environment and Energy (MINAE).
MINAE leads the Consejo Subsectoral de Energfa, which is composed of the most important institutions
and state-run enterprises in the energy sector, including the Ministry of Science and Technology, the
Ministry of Planning and Economic Policy, the regulatory authority ARESEP, the national oil company
RECOPE and the national electrical utility ICE. The independent regulatory authority ARESEP was
created in 1996 and is responsible for determining transit fees and electricity prices.
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APPENDIX B. ENERGY IN CAFTA-DR COUNTRIES
2.2. Dominican Republic
Dominican Republic relies heavily upon
thermal power plants fueled by imported
fossil fuels for the generation of electric
power (Figure B-2). Sixty-two percent of its
electricity is generated from burning oil, 14
percent from coal and 13 percent from
natural gas. Only 11 percent is generated
by hydroelectric facilities and less than one
percent by the burning of biomass.
Although the amount of electricity
generated has grown 70 percent in the past
10 years, the contribution from
hydroelectric sources has remained
relatively constant, with the growth being
achieved through the development of
additional conventional thermal capacity
reliant upon imported fossil fuels (Tale B-4).
Figure B- 2: Dominican Republic energy generation
by fuel type 2008
a Coal
Oil
a Gas
a Biomass
D Hydro
Source of data: Table B-2
Table B- 4: Dominican Republic energy trends 1998-2008
Petroleum Products (1,000 Barrels/Day)
Total Consumption
Fuel Oil Consumption
Proved Reserves (Billion Barrels)
Natural Gas (Billion Cubic Feet)
Consumption
Proved Reserves (Billion Barrels)
Coal (Million Short Tons)
Production
Consumption
Electricity Net Generation (GWh)
Conventional Thermal
Hydroelectric
Geothermal
Wind
Solar, Tidal and Wave
Biomass
Net Consumption* (GWh)
Imports
Exports
Electricity Distribution Losses
Carbon Dioxide Emissions (Million Metric
Tons of C02) Consumption of Fossil Fuels
1999
99.24
52.78
0.0
0.0
0.0
0.0
0.3
8,562
7,439
1,088
0.0
0.0
0.0
35
6,459
0.0
0.0
2,103
14.36
2000
110.06
66.23
0.0
0.0
0.0
0.0
0.1
8,064
7,274
754
0.0
0.0
0.0
36
5,784
0.0
0.0
2,280
15.80
2001
113.95
67.80
0.0
0.0
0.0
0.0
0.2
9,717
9,130
551
0.0
0.0
0.0
36
8,480
0.0
0.0
1,237
16.59
2002
116.15
75.97
0.0
0.0
0.0
0.0
0.3
10,863
9,957
869
0.0
0.0
0.0
37
9,482
0.0
0.0
1,381
17.14
2003
115.28
64.37
0.0
10.6
0.0
0.0
1.2
12,740
11,509
1,188
0.0
0.0
0.0
43
11,415
0.0
0.0
1,325
19.54
2004
114.07
59.72
0.0
4.6
0.0
0.0
0.9
13,014
11,381
1,566
0.0
0.0
0.0
67
11,658
0.0
0.0
1,356
18.12
2005
115.41
58.93
0.0
8.8
0.0
0.0
0.5
12,221
10,316
1,877
0.0
0.0
0.0
28
11,419
0.0
0.0
802
17.44
2006
116.73
60.16
0.0
8.8
0.0
0.0
0.9
13,389
11,619
1,742
0.0
0.0
0.0
28
11,823
0.0
0.0
1,566
18.43
2007
118.72
61.96
0.0
0.0
0.0
0.0
0.8
14,036
12,267
1,733
0.0
0.0
0.0
36
12,720
0.0
0.0
1,316
19.16
2008
120.00
NA
0.0
17.0
0.0
0.0
1.0
14,577
12,838
1,711
0.0
0.0
0.0
28
12,866
0.0
0.0
1,711
19.40
Notes:
NA = Information not available
* Net generation + electricity imports - electricity exports - electricity distribution losses.
Source: U.S. Energy Information Agency http://www.eia.gov/cfapps/ipdbproiect/IEDIndex3.cfm
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APPENDIX B. ENERGY IN CAFTA-DR COUNTRIES
The National Energy Commission (Comision Nacional de la Energfa, CNE) is the government agency
responsible for energy policy in Dominican Republic. The Electricity Superintendence (Superintendencia
de Electricidad, SIE) is the regulatory agency, while the Coordination Agency (Organismo Coordinador,
OC) has the responsibility to coordinate the dispatch of electricity.
Dominican Corporation of State Electricity Companies (Corporacion Dominicana de Empresas Electricas
Estatales - CDEEE) is a holding company that brings together all of the electricity generation,
transmission and distribution companies owned or partially owned by the government as well as
government electricity programs. CDEEE consists of:
Empresa de Generacion Hidroelectrica Dominicana (EGEHID - Hydroelectricity Generation
Company)
Empresa deTransmision Electrica Dominicana (ETED - Electricity Transmission Company)
Unidad de Electrificacion Rural y Suburbana (UERS - Rural and Suburban Electrification Unit)
Programa de Reduccion de Apagones (PRA - Blackout Reduction Program)
50 percent of the North Distribution Company, EdeNorte
50 percent of the South Distribution Company, EdeSur
50 percent of the East Distribution Company, EdeEste
EdeNorte and EdeSur are entirely government-owned, the remaining 50 percent shares being held by
the government's Enterprise Trust Fund, Fondo Patrimonial de las Empresas (FONPER). EdeEste is a
mixed private-public company.
Eighty-six percent of the generation capacity is privately owned and 14 percent is publicly owned. All of
the hydroelectric facilities are publicly owned, and all of the other plants are privately owned, by eleven
private companies. The transmission system is owned by ETED, a government-owned company. It
consists of 940 km of 138kV single-line circuit lines that radiate from Santo Domingo to the north, east,
and west. There are three distribution companies, two wholly-owned by the government (EdeNorte and
EdeSur) and another which is a 50/50 private-public enterprise (EdeEste).
2.3. El Salvador
Electric power in El Salvador is generated
primarily by three sources: conventional
thermal plants fueled by oil (39%),
hydroelectric power (34%) and geothermal
energy (25%) (Figure B-3). Biomass provides
only two percent of the total electric power
generated.
In 1999 hydroelectric power generated 48
percent of total electric power (Table B-5).
Since that time, power generation has grown
by 56 percent, with most of the growth
occurring in the development of geothermal
power, which has nearly tripled its
contribution to total generation since 1999,
making El Salvador the largest producer of
Figure B- 3: El Salvador energy generation by fuel
type 2008
Source of data: Table B-2
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geothermal generated electrical power in the CAFTA-DR region. The 2007 National Energy Strategy
determined that potential geothermal capacity in El Salvador is about 450MW, or slightly more than
double the current capacity.
Table B- 5: El Salvador energy trends 1998-2008
Petroleum Products (1,000 Barrels/Day)
Total Consumption
Fuel Oil Consumption
Proved Reserves (Billion Barrels)
Natural Gas (Billion Cubic Feet)
Consumption
Proved Reserves (Billion Barrels)
Coal (Million Short Tons)
Production
Consumption
Electricity Net Generation (GWh)
Conventional Thermal
Hydroelectric
Geothermal
Wind
Solar, Tidal and Wave
Biomass
Net Consumption* (GWh)
Imports
Exports
Electricity Distribution Losses
Carbon Dioxide Emissions (Million Metric
Tons of C02) Consumption of Fossil Fuels
1999
38.31
21.94
0.0
0.0
0.0
0.0
0.0
3,659
1,319
1,749
568
0.0
0.0
23
3,411
460
208
500
5.48
2000
38.06
21.88
0.0
0.0
0.0
0.0
0.0
3,687
1,757
1,163
747
0.0
0.0
20
3,972
900
112
503
5.51
2001
39.41
22.80
0.0
0.0
0.0
0.0
0.0
3,742
1,653
1,152
918
0.0
0.0
19
3,888
700
44
510
5.70
2002
39.01
23.89
0.0
0.0
0.0
0.0
0.0
3,923
1,830
1,128
943
0.0
0.0
22
3,769
430
51
533
5.77
2003
42.36
23.95
0.0
0.0
0.0
0.0
0.0
4,196
1,747
1,451
975
0.0
0.0
23
3,960
433
103
566
6.08
2004
41.93
22.94
0.0
0.0
0.0
0.0
0.0
4,262
1,904
1,374
960
0.0
0.0
24
4,069
466
84
575
6.02
2005
43.36
23.88
0.0
0.0
0.0
0.0
0.0
4,586
1,909
1,652
998
0.0
0.0
26
4,255
322
38
615
6.21
2006
43.80
23.57
0.0
0.0
0.0
0.0
0.0
5,370
2,313
1,942
1,083
0.0
0.0
32
4,648
11
9
724
6.23
2007
44.20
24.38
0.0
0.0
0.0
0.0
0.0
5,560
2,438
1,722
1,313
0.0
0.0
87
5,200
38
7
391
6.32
2008
42.00
NA
0.0
0.0
0.0
0.0
0.0
5,721
2,160
2,018
1,443
0.0
0.0
100
5,608
83
89
107
5.93
Notes:
NA = Information not available
* Net generation + electricity imports - electricity exports - electricity distribution losses.
Source: U.S. Energy Information Agency http://www.eia.gov/cfapps/ipdbproject/IEDIndex3.cfm
Hydroelectric generation is almost totally owned and operated by a public company, the Comision
Hidroelectrica del Rfo Lempa (Lempa River Hydroelectric Commission - CEL). All other forms of electric
power generation are in private hands. In 2006, there were 11 private companies generating electricity
in El Salvador at 18 facilities.
One government-owned company, Empresa Transmisora de El Salvador, is responsible for the
maintenance and expansion of the transmission system. Distribution is controlled by five privately-
owned companies. The market share for each of them in 2006 was:
CAESS: 44 percent
Delsur: 25 percent
CLESA: 18 percent
Empresa Electrica de Oriente (EEO): 10 percent
Distribuidora Electrica de Oriente (Deusem): 2 percent
CAESS, CLESA, EEO and Deusem are controlled by AES Corporation.
The government of El Salvador plans for and regulates electrical power generation and transmission
through three governmental entities. The Direccion de Energfa Electrica (Electrical Energy Directorate is
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the administrative unit within the Ministry of Economy responsible for elaborating, proposing,
coordinating and executing policies, programs, projects and other actions in the electricity sector. The
General Superintendence of Electricity and Telecommunications is in charge of regulating the power
market, the distribution companies and consumer prices. In 2006, the President created the National
Energy Council to analyze the energy situation and Government proposals, recommend new actions and
strategies, and promote the use of renewable energy and efficient use of energy.
2.4. Guatemala
Thermal electric plants fueled by fossil fuels
and hydroelectric power provide most of
Guatemala's electrical power (Figure B-4).
Hydroelectric power generates 42 percent of
the total power, oil 27 percent and coal 13
percent. Although Guatemala is the only
CAFTA-DR country with proven oil reserves
(Table B-6), the amount of the reserves are
insignificant compared to the amount of
petroleum products consumed in the country,
so all of the coal used for energy generation
and nearly all of the oil is imported.
Central America's first coal-fired power plant,
the 120-MW San Jose Power Station, opened
in Guatemala in December 1999. Owners
Figure B- 4: El Salvador energy generation by fuel
type 2008
Source of data: Table B-2
include Teco Power Services, Coastal Power Company and Compania de Centroamerica. The plant
began operations in early 2000, burning low-sulfur South American coal. It is located about 75 miles
south of Guatemala City.
The combustion of biomass provided 18 percent of the total electric power in Guatemala in 2008, the
highest contribution by biomass of all of the CAFTA-DR countries. The amount of electricity generated
by biomass grew by 70 percent in the four years period between 2004 and 2008.
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Table B- 6: Guatemala energy trends 1998-2008
Petroleum Products (1,000 Barrels/Day)
Total Consumption
Fuel Oil Consumption
Proved Reserves (Billion Barrels)
Natural Gas (Billion Cubic Feet)
Consumption
Proved Reserves (Billion Barrels)
Coal (Million Short Tons
Production
Consumption
Electricity Net Generation (GWh)
Conventional Thermal
Hydroelectric
Geothermal
Wind
Solar, Tidal and Wave
Biomass
Net Consumption* (GWh)
Imports
Exports
Electricity Distribution Losses
Carbon Dioxide Emissions (Million Metric
Tons of C02) Consumption of Fossil Fuels
1999
59.16
34.52
0.5
0.0
109.0
0.0
0.0
4,988
2,120
2,061
0.0
0.0
0.0
807
3,974
245
465
794
8.69
2000
59.29
32.01
0.5
0.0
109.0
0.0
0.2
5,808
2,740
2,263
0.0
0.0
0.0
805
3,610
123
827
1,494
9.06
2001
65.90
36.33
0.5
0.0
109.0
0.0
0.2
5,608
2,897
1,906
0.0
0.0
0.0
805
4,020
95
336
1,347
10.01
2002
64.56
35.69
0.5
0.0
109.0
0.0
0.4
5,910
3,423
1,682
0.0
0.0
0.0
805
4,151
55
440
1,374
10.27
2003
64.98
37.52
0.5
0.0
109.0
0.0
0.4
6,328
3,043
2,480
0.0
0.0
0.0
805
5,674
31
428
257
10.25
2004
67.57
38.82
0.5
0.0
109.0
0.0
0.5
6,763
3,483
2,453
0.0
0.0
0.0
827
6,076
41
464
264
10.85
2005
70.29
40.05
0.5
0.0
109.0
0.0
0.4
7,299
3,220
3,228
0.0
0.0
0.0
851
6,379
23
339
604
11.54
2006
71.40
39.11
0.5
0.0
109.0
0.0
0.5
7,643
2,894
3,795
0.0
0.0
0.0
954
6,615
8
90
946
11.22
2007
72.00
42.74
0.1
0.0
NA
0.0
0.7
8,425
3,531
3,590
0.0
0.0
0.0
1,304
7,116
8
132
1,186
12.31
2008
68.00
NA
0.1
0.0
NA
0.0
0.7
8,395
3,246
3,675
0.0
0.0
0.0
1,474
7,108
5
76
1,216
11.56
Notes:
NA = Information not available
* Net generation + electricity imports - electricity exports - electricity distribution losses.
Source: U.S. Energy Information Agency http://www.eia.gov/cfapps/ipdbproject/IEDIndex3.cfm
2.5. Honduras
Thermal power plants fired by oil generated
62 percent of Honduras' total electricity in
2008, with hydroelectric power providing 35
percent and biomass combustion providing
only 2 percent (Figure B-5). Power generated
by hydroelectricity has remained relatively
constant since 1999, so that nearly all of the
100 percent increase in electricity generation
in the past 10 years has been met by
expansion of oil-fueled thermal power (Table
B-7).
The Empresa Nacional de Energfa Electrica
(ENEE) is the national utility in Honduras. It
is the owner of nearly all of the hydroelectric
capacity in the country and about eight
percent of the thermal capacity. ENNEowns
and operates six hydroelectric facilities3:
Figure B- 5: Honduras energy generation by fuel
type 2008
Source of data: Table B-2
These capacity values and those in the following paragraphs come from ENNE (2011).
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Francisco Morazan (also called El Cajon) 300 MW of capacity
Rfo Undo 80 MW of capacity
Nacaome 30 MW of capacity
Canaveral 29 MW of capacity
El Nfspero 22.5 MW of capacity
El Coyolar 1.6 MW of capacity
Santa Marfa del Real 1.3 MW of capacity
It has an additional 124.6 MW of capacity in 6 small fossil-fuel powered plants ranging in size from 5 to
30 MW. In addition to producing energy, it purchases electricity, sells electricity to customers, and is
solely responsible for its transmission and distribution (except in some instances of small isolated
systems).
Table B- 7: Honduras energy trends 1998-2008
Petroleum Products (1,000 Barrels/Day)
Total Consumption
Fuel Oil Consumption
Proved Reserves (Billion Barrels)
Natural Gas (Billion Cubic Feet)
Consumption
Proved Reserves (Billion Barrels)
Coal (Million Short Tons)
Production
Consumption
Electricity Net Generation (GWh)
Conventional Thermal
Hydroelectric
Geothermal
Wind
Solar, Tidal and Wave
Biomass
Net Consumption* (GWh)
Imports
Exports
Electricity Distribution Losses
Carbon Dioxide Emissions (Million Metric
Tons of C02) Consumption of Fossil Fuels
1999
30.63
20.74
0.0
0.0
0.0
0.0
0.1
3,097
987
2,109
0.0
0.0
0.0
1
2,514
150
6
111
4.86
2000
28.11
18.07
0.0
0.0
0.0
0.0
0.1
3,546
1,308
2,237
0.0
0.0
0.0
1
3,139
315
5
111
4.58
2001
33.00
22.67
0.0
0.0
0.0
0.0
0.1
3,747
1,853
1,885
0.0
0.0
0.0
9
3,210
310
0.0
847
5.31
2002
36.34
27.57
0.0
0.0
0.0
0.0
0.2
3,926
2,317
1,595
0.0
0.0
0.0
14
3,411
400
0.0
915
5.96
2003
36.54
26.16
0.0
0.0
0.0
0.0
0.2
4,351
2,593
1,724
0.0
0.0
0.0
34
3,654
331
0.0
1,028
6.00
2004
41.85
31.68
0.0
0.0
0.0
0.0
0.2
4,638
3,199
1,387
0.0
0.0
0.0
52
3,925
408
15
1,107
7.01
2005
44.09
33.04
0.0
0.0
0.0
0.0
0.2
5,318
3,480
1,701
0.0
0.0
0.0
137
4,014
58
2
1,360
7.27
2006
46.10
33.45
0.0
0.0
0.0
0.0
0.3
5,728
3,544
2,049
0.0
0.0
0.0
135
4,208
19
11
1,528
7.82
2007
47.50
36.27
0.0
0.0
0.0
0.0
0.2
6,069
3,717
2,192
0.0
0.0
0.0
160
4,714
12
0.0
1,366
8.63
2008
48.00
NA
0.0
0.0
0.0
0.0
0.3
6,261
3,806
2,268
0.0
0.0
0.0
187
4,903
0.0
12
1,346
8.21
Notes:
NA = Information not available
* Net generation + electricity imports - electricity exports - electricity distribution losses.
Source: U.S. Energy Information Agency http://www.eia.gov/cfapps/ipdbproiect/IEDIndex3.cfm
Agreements that ENEE has signed with Independent Power Producers operating power plants now
account for the majority of energy generation in Honduras. Five large companies generate most of this
electricity:
LUFUSSA 39.5 MW of capacity, gas turbine; 347.4 MW of capacity, diesel
ENERSA con 276.1 MW of capacity, diesel
ELCOSA 80 MW of capacity, diesel
EMCE 55 MW of capacity, diesel
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There are five addition companies that have a total fossil-fuel fired thermal capacity of 69.9 MW at
facilities that range in size from 8 to 21.8 MW of capacity. There are also 13 small privately owned and
operated hydroelectric facilities ranging in size from 0.5 to 12.8 MW of capacity with a total capacity of
62 MW and 11 small privately operated biomass-fueled thermal plants ranging in size from 0.5 to 25.8
MW with a total capacity of 91.4 MW.
The Electricity Law of 1994 assigns the policymaking function for electric power to an Energy Cabinet
chaired by the President of the Republic with the with the Secretarfa de Recursos Naturales y Ambiente
(SERNA) as its secretary and coordinator. A regulatory agency, the Comision Nacional de Energfa (CNE),
was created, among other functions:
Supervise power sales agreements to be signed by distribution companies;
Approve standards related to service quality, reliability and safety;
Monitor and enforce laws and standards;
Approve tariffs and propose Average Short-Term Marginal costs;
Approve system expansion programs;
Submit for approval to the Ministry of Environment power purchase and sales agreements that
ENEE intends to sign.
The Energy Cabinet has met less than once a year since its creation. CNE has had a marginal role due to
lack of political support and resources. As a result, has become the lead government entity in regards to
policymaking and regulation, as well as being the regulated entity. ENEE is governed by a Board of
Directors, which is formed by Minister of Natural Resources and the Environment, who also chairs the
Board; the Minister of Public Works, Transportation and Housing; the Minister of Finance; the Minister
of Industry and Commerce; the Minister of Foreign Cooperation; and a representative of the Honduran
Council of Private Enterprise (COHEP). The Board appoints a General Manager, who acts as its Secretary
but has no vote.
2.6. Nicaragua
Nicaragua, like Dominican Republic and
Honduras, is heavily reliant upon oil-fired
thermal plants to generate electricity (Figure
B-6). In 2008, oil produced 64 percent of the
total electric power. All of the oil is imported
(Table B-8). The other 36 percent is generated
by hydroelectric power (16%), geothermal and
the combustion of biomass (10% each).
As in the rest of the region, the generation of
electricity has grown significantly in Nicaragua
in the past 10 years (65%). Most of the
increase has been met by expanding the
reliance on oil-fired thermal plants; however,
2008 saw an increase in both hydroelectric
power and geothermal which allowed a
decrease in reliance upon oil for electric power
generation.
Figure B- 6: Nicaragua energy generation by fuel
type 2008
Source of data: Table B-2
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Nicaragua is the country in the CAFTA-DR region with the lowest level of electricity generation. It is
more dependent than the other Central American countries on imported oil for electricity generation,
which supplied 64 percent of its electrical power in 2008. This has led to some shortages when oil prices
rise, as was the case in 2006.
Nicaragua's power sector underwent a deep restructuring during the late 1990s, with the new Electricity
Law (April 1998 - Ley No.272) allowing for privatization of the generation and distribution activities
previously controlled by the state-owned Empresa Nicaraguense de Electricidad. As a result, two State-
owned enterprises and 12 private companies operate 23 electrical energy generating facilities in
Nicaragua (Table B-8). Government-owned enterprises maintained control of the large hydroelectric
facilities and two large thermal plants, which no private companies were interested in acquiring. One
company, Dissur-Disnorte, owned by the Spanish Union Fenosa, controls 95 percent of the distribution.
Transmission, however, is owned and managed by the state-owned company, Empresa Nacional de
Transmision Electrica.
Table B- 8: Generating capacity by type and company for 2009
Type
Public
Thermal
Gas Turbine
Hydroelectric
Private
Conventional
Thermal
Gas Turbine
Hydroelectric
Biomass Thermal
Geothermal
Wind
TOTAL
Company Name
Electrica Central S.A. (GECSA)
GECSA
Hidroelectrica S.A. (HIDROGESA)
ALBANISA
Generadora Electrica de Occidente S.A. (GEOSA)
Empresa Energetica Corinto (EEC)
Corporacion Electrica Nicaraguense, S.A. (CENSA)
Tipitapa Power
Generadora San Rafael
GEOSA
Atder-BL
Monte Rosa, SA
Nicaragua Sugar Estates Limited (NSEL)
Ormat Momotombo Power Company
Polaris Energy Nicaragua, S.A. (PENSA)
Consorcio Eolica, S.A. (AMAYO)
Number
of Plants
4
1
1
2
19
7
1
1
1
1
1
1
1
1
1
1
1
1
23
Installed
Capacity
(MW)
226.8
57.4
65.0
104.4
742.3
175.6
106.0
74.0
63.9
52.2
6.4
14.0
0.9
62.5
59.3
77.5
10.0
40.0
969.1
Source: Institute Nicaraguense de Energia website
http://www.ine.gob.ni/DGE/estadisticas/serieHistorica/Capacidad Instalada 2009.pdf
Biomass projects in Nicaragua use by-products from the sugar cane industry to fuel thermal plants. The
NSEL plant began operation in 1998 and burns bagasse, the fibrous matter that remains after sugarcane
or sorghum stalks are crushed to extract their juice. The Monte Rosa plant began operation in and
burns biogas made from vinasse, the still bottoms left after distillation of fermented sugarcane.
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Nicaragua saw the operation of its first wind power generating facility in 2009, the Consorcio Eolica, S.A.
that has the capability of generating 40 MW.
Three government agencies are involved in planning for and regulating the generation, transmission and
distribution of electric power. The Ministerio de Energfa y Minas is in charge of formulating policies and
strategies for the energy sector. The Institute Nicaraguense de Energfa is the regulatory agency,
awarding concessions for transmission and distribution, and approving tariffs. The Centre Nacional de
Despacho de Carga, a division of ENTREL, is in charge of regulating the transmission and distribution of
electricity.
Table B- 9: Nicaragua energy trends 1998-2008
Petroleum Products (1,000 Barrels/Day)
Total Consumption
Fuel Oil Consumption
Proved Reserves (Billion Barrels)
Natural Gas (Billion Cubic Feet)
Consumption
Proved Reserves (Billion Barrels)
Coal (Million Short Tons)
Production
Consumption
Electricity Net Generation (GWh)
Conventional Thermal
Hydroelectric
Geothermal
Wind
Solar, Tidal and Wave
Biomass
Net Consumption* (GWh)
Imports
Exports
Electricity Distribution Losses
Carbon Dioxide Emissions (Million Metric
Tons of C02) Consumption of Fossil Fuels
1999
23.96
17.29
0.0
0.0
0.0
0.0
0.0
2,076
1,538
389
97
0.0
0.0
52
1,577
80
22
557
3.74
2000
24.02
17.29
0.0
0.0
0.0
0.0
0.0
2,156
1,754
208
127
0.0
0.0
67
1,585
114
1
684
3.70
2001
25.58
18.34
0.0
0.0
0.0
0.0
0.0
2,341
1,905
195
196
0.0
0.0
45
1,613
17
0.0
745
3.94
2002
25.42
17.14
0.0
0.0
0.0
0.0
0.0
2,646
2,098
300
200
0.0
0.0
48
1,880
16
7
775
4.05
2003
25.64
16.33
0.0
0.0
0.0
0.0
0.0
2,562
1,913
294
257
0.0
0.0
98
1,759
12
21
794
4.11
2004
27.17
17.49
0.0
0.0
0.0
0.0
0.1
2,673
1,996
318
242
0.0
0.0
117
1,985
23
22
689
4.42
2005
28.60
18.24
0.0
0.0
0.0
0.0
0.1
2,946
2,107
427
258
0.0
0.0
155
2,342
25
8
621
4.60
2006
27.40
19.20
0.0
0.0
0.0
0.0
0.1
3,023
2,293
300
295
0.0
0.0
135
2,424
53
0.0
652
4.76
2007
27.80
19.11
0.0
0.0
0.0
0.0
0.1
3,286
2,393
301
231
0.0
0.0
362
2,570
64
0.0
780
4.71
2008
28.00
NA
0.0
0.0
0.0
0.0
0.1
3,419
2,263
529
306
0.0
0.0
321
2,646
28
0.0
801
4.50
Notes:
NA = Information not available
* Net generation + electricity imports - electricity exports - electricity distribution losses.
Source: U.S. Energy Information Agency http://www.eia.gov/cfapps/ipdbproiect/IEDIndex3.cfm
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Volume II -Appendices: EIATechnical Review Guidelines APPENDIX C. REQUIREMENTS AND STANDARDS
Energy Generation and Transmission
APPENDIX C. REQUIREMENTS AND STANDARDS: CAFTA-DR COUNTRIES,
OTHER COUNTRIES, AND INTERNATIONAL ORGANIZATIONS
This Appendix summarizes a range of quantitative benchmarks for specific environmental requirements
of new energy projects beyond the requirement to develop an EIA and mitigate and avoid adverse
environmental impacts. It does not attempt to capture non-quantitative practice standards. The
benchmark standards contained within this Appendix include ambient quality and sector-specific
performance standards from CAFTA-DR countries, including the United States, other foreign
governments, and international organizations. CAFTA-DR country EIA reviewers and preparers might
use this information in the absence of such standards or to assess the validity and to evaluate the
significance of impacts within ElAs.
The Appendix includes:
Introduction to Environmental Laws, Standards, and Requirements
Ambient Standards for Air and Water Quality
Energy-Sector Specific Performance Standards
o Water Discharge/Effluent Limits
o Storm Water Runoff
o Air Emission Limits
o Solid Waste
International Treaties and Agreements Ratified/Signed
Website References
Section 1 provides a general introduction on the role of environmental regulatory approaches to reduce
or prevent pollution directly or indirectly, Section 2 summarizes ambient freshwater, drinking water, and
air quality standards for the CAFTA-DR countries, including the United States and the International
Finance Corporation/ World Bank Group. Section 3 provides an overview of performance standards
applicable to energy-production-related projects; Section 3.1 summarizes water discharge/effluent
limits; Section 3.2 provides supplemental information about water discharge/effluent limits in the
United States; Section 3.3 summarizes storm water runoff discharge/effluent limits; Section 3.4
summarizes air emission limits; and Section 3.5 summarizes solid waste discharge/effluent limits.
Section 4 summarizes international treaties and agreements ratified or signed by CAFTA DR Countries
and Section 5 provides links to relevant websites. To the extent possible, footnotes provide necessary
caveats but it is strongly recommended that if this information is used, the reviewer or preparer confirm
it is up to date and appropriate for the circumstances.
1 INTRODUCTION TO ENVIRONMENTAL LAWS. STANDARDS. AND REQUIREMENTS
There are many approaches to managing environmental problems (see Figure C-l). Some approaches
are purely voluntary - that is, they encourage and assist change but do not require it. Other approaches
are regulatory - that is, they require change or specific performance expectations. At the heart of
regulatory approaches are environmental requirements-specific practices and procedures required by
law to directly or indirectly reduce or prevent pollution. Figure C-2 lists some examples of the types of
requirements and standards typically used for environmental management, including:
Ambient Standards
Performance Standards (Emissions and Effluents).
Technology Standards
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Volume II -Appendices: EIATechnical Review Guidelines APPENDIX C. REQUIREMENTS AND STANDARDS
Energy Generation and Transmission
Practice Standards
Information Requirements
Product or Use Bans
While wholly regulatory (command-and-control) approaches generally have the most extensive
requirements of all the management options, most of the other options, including market-based
economic incentive, labeling, and liability-based approaches, introduce some form of requirements.
Requirements may be general or facility/activity specific. General requirements are most frequently
implemented in the form of (1) laws, (2) regulations, or (3) general permits or licenses that apply to a
specific class of facilities. General requirements may apply directly to a group of facilities or they may
serve as a basis for developing facility-specific requirements. Facility-specific requirements are usually
implemented in the form of permits or licenses, or, in the case of environmental impact assessment,
may become legally binding commitments if they are a) within the environmental impact assessment
itself, b) within a separate environmental management plan or monitoring/mitigation plan, or c)
incorporated into a separate contract.
Appendix C benchmarks only quantitative limits in a highly summarized format as a useful point of
reference. For additional background on enforceable requirements, see the International Network for
Environmental Compliance and Enforcement Website: http://www.inece.org and specifically the
resource library www.inece.org/library/principles.html. Others references for more details behind the
limits summarized in the Appendix are provided in the last section.
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Volume II -Appendices: EIATechnical Review Guidelines APPENDIX C. REQUIREMENTS AND STANDARDS
Energy Generation and Transmission
Figure C-1: Approaches to environmental management
Voluntary Approaches
Voluntary approaches encourage or assist, but do not require, change. Voluntary approaches include
public education, technical assistance, and the promotion of environmental leadership by industry and
nongovernment organizations. Voluntary approaches may also include some management of natural resources
(e.g., lakes, natural areas, ground water) to maintain environmental quality.
Regulatory (Command-and-Control) Approaches
In command-and-control approaches, the government prescribes the desired changes through detailed
requirements and then promotes and enforces compliance with these requirements. Table 3-2 describes types of
requirements typically used in command-and-control approaches.
Market-based/Economic Incentive Approaches
Market-based/economic incentive approaches use market forces to achieve desired behavior changes.
These approaches can be independent of or build upon and supplement command-and-control approaches. For
example, introducing market forces into a command-and-control approach can encourage greater pollution
prevention and more economic solutions to problems. Market-based/economic incentive approaches include:
Fee systems. In this approach, the government taxes emissions, effluents, and other environmental releases.
Tradeable permits. In this approach,_companies trade permitted emission rights with other companies.
Offset approaches. These approaches allow a facility to propose various approaches to meeting an
environmental goal. For example, a facility may be allowed to emit greater quantities of a substance from one
of its operations if the facility offsets this increase by reducing emissions at another of its operations.
Auctions. In this approach, the government auctions limited rights to produce or release certain
environmental pollutants.
Environmental labeling/public disclosure. In this approach, manufacturers are required to label products so
that consumers can be aware of the environmental impacts of the products. Consumers can then choose
which products to purchase based on the products' environmental performance.
Risk-based Approaches
Risk-based approaches to environmental management are relatively new. These approaches establish
priorities for change based on the potential for reducing the risks posed to public health and/or the environment.
Pollution Prevention
The goal of pollution prevention approaches is to prevent pollution by reducing or eliminating generation
of pollution at the source. The changes needed to prevent pollution can be required, e.g., as part of a command-
and-control approach, or encouraged as voluntary actions.
Liability
Some environmental management approaches are based on laws that make individuals or businesses
liable for the results of certain actions or for damages they cause to another individual or business or to their
property. Liability systems do not have explicit requirements. However, implicit requirements often develop as
cases are brought to court and patterns are established about what activities justify which consequences. To be
effective, liability systems generally need some enforcement by the government, nongovernment organizations, or
individuals to gather evidence and develop legal cases. Examples of liability-based environmental management
systems include nuisance laws, laws requiring compensation for victims of environmental damage, and laws
requiring correction of environmental problems caused by improper disposal of hazardous waste. Liability systems
reduce or prevent pollution only to the extent that individuals or facilities fear the consequences of potential legal
action against them.
Source: Wasserman, Cheryl et. al.. Principles of Environmental Enforcement, U.S. Environmental
Protection Agency, July, 1992.
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Volume II -Appendices: EIATechnical Review Guidelines APPENDIX C. REQUIREMENTS AND STANDARDS
Energy Generation and Transmission
Figure C- 2: Examples of environmental requirements
Ambient Standards
Ambient standards (also called media quality standards) are goals for the quality of the ambient
environment (e.g., air, water). Ambient standards are usually written in units of concentration (e.g., the level of
nitrogen dioxide in the air cannot exceed 0.053 parts per million). In the U.S., ambient standards are used as
environmental quality goals and to plan the level of emissions from individual sources that can be accommodated
while still meeting the area wide goal. Ambient standards may also be used as triggers, e.g., when the standard is
exceeded, monitoring or enforcement efforts are increased. Enforcement of ambient standards usually requires
relating an ambient measurement to emissions or activities at a specific facility. This can be difficult.
Performance Standards (Emissions and Effluents)
These standards are widely used for regulations, permits, and monitoring requirements. Performance
standards limit the amount or rate of particular chemicals or discharges that a facility can release into the
environment in a given period of time. Performance standards provide flexibility because they allow sources to
choose which technologies they will use to meet the standards. Often such standards are based on the output
that can be achieved using the best available control technology. Some requirements introduce additional
flexibility by allowing a source with multiple emissions to vary its emissions from each stack as long as the total
sum of the emissions does not exceed the permitted total. Compliance with emission standards is measured by
sampling and monitoring. Depending on the kind of instruments required, compliance can be difficult and/or
expensive to monitor.
Technology Standards
These standards require the regulated community to use a particular type of technology (e.g., the "best
available technology") to control and/or monitor emissions. Technology standards are particularly appropriate
when the equipment is known to perform well under the range of conditions generally experienced by sources in
the community. It is relatively easy for inspectors to determine whether sources are in compliance with
technology standards: the approved equipment must be in place and operating properly. It may be difficult,
however, to ensure that the equipment is operating properly over a long period of time. Technology standards can
inhibit technological innovation and pollution prevention. In the U.S. many air performance standards are based
on the performance of a particular technology or technologies, but sources are not required to actually use that
technology to meet the performance standards.
Practice Standards
These standards require or prohibit certain work activities that have significant environmental impacts.
For example, a standard might prohibit carrying hazardous liquids in uncovered buckets. Like technology
standards, it is easy for program officials to inspect for compliance and take action against noncomplying sources,
but difficult to ensure ongoing compliance.
Information Requirements
These requirements are different from the standards described above in that they require a source of
potential pollution (e.g., a pesticide manufacturer or facilities involved in generating, transporting, storing,
treating, and disposing of hazardous waste) to develop and submit information to the government. Sources
generating pollution may be required to monitor, report on, and maintain records of the level of pollution
generated and whether or not it exceeds performance standards. Information requirements are often used when
the potential pollution source is a product such as a new chemical or pesticide, rather than a waste. For example,
a manufacturer may be required to test and report on a product's potential to cause harm if released into the
environment.
Product or Use Bans
A ban may prohibit a product outright (e.g., ban the manufacture, sale, and/or use of a product) or may
prohibit particular uses of a product.
Source: Wasserman, Cheryl et. al. Principles of Environmental Enforcement, U.S. Environmental Protection
Agency, July, 1992.
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Volume II-Appendices: EIA Technical Review Guidelines
Energy Generation and Transmission
APPENDIX C. REQUIREMENTS AND STANDARDS
2 AMBIENT STANDARDS FOR AIR AND WATER QUALITY
The following Tables summarize and compare standards across countries and institutions for:
Freshwater Quality Guidelines and Standards
Drinking Water Quality Guidelines and Standards
Ambient Air Quality Guidelines and Standards
Table C-1: Freshwater quality guidelines and standards
Pollutant
Alachlor
Anthracene
Arsenic
Atrazine
Benzene
Benzo(a)pyrene
Brominated diphenylether
Cadmium
C 10-13 Chloralkanes
Chlordane
Chlorfenvinphos
Chloride
Chromium (III)
Chromium (VI)
Chlorpyrifos (Chlorpyrifos-ethyl)
Cyanide
DDT total
Para-para-DDT
1,2-Dichloroethane
Dichloromethane
Dieldrin
Di(2-ethylexyl)-phthalate
(DEPH)
Diuron
United States
National Recommended Water
Quality Criteria1
Maximum
Concentration
(CMC) (ug/l)
340
2
2.4
860,000
570
16
22
0.24
Continuous
Concentration
(CCC) (ug/l)
150
0.25
0.0043
230,000
74
11
5.2
0.056
European Union
Annual Average
Value
(Inland surface
Waters)
(ug/l)
0.3
0.1
0.6
10
0.05
0.0005
< 0.08 (Class I)2
0.08 (Class 2)
0.09 (Class 3)
0.15 (Class 4)
0.25 (Class 5)
0.4
0.1
0.03
0.025
0.01
10
20
1=0.01 3
1.3
0.2
Maximum
Allowable
Concentration
(Inland surface
Waters)
(ug/l)
0.7
0.4
2.0
50
0.1
N/A
< 0.45 (Class 1)
0.45 (Class 2)
0.09 (Class 3)
0.15 (Class 4)
0.25 (Class 5)
1.4
0.3
0.1
N/A
N/A
N/A
N/A
N/A
N/A
1.8
1 In the United States, the federal government issues recommended water quality criteria to provide for the
protection and propagation offish, shellfish, and wildlife and for recreation in and on the water but it is up to the
states, in the first instance, to adopt binding water quality criteria based on designated use categories.
2 For cadmium and its compounds the EQS values vary depending on the hardness of the water as specified in five
class categories (Class 1: < 40 mg CaCO3/l,Class 2: 40 to < 50 mg CaCO3/l, Class 3: 50 to < 100 mg CaCO3/l, Class 4:
100 to < 200 mg CaCO3/l and Class 5: > 200 mg CaCO3/l).
3 Sum for cyclodiene pesticides which include: Aldrin, Dieldrin, Endrin, Isodrin
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APPENDIX C. REQUIREMENTS AND STANDARDS
Pollutant
alpha-Endosulfan
beta-Endosulfan
Endrin
Fluoranthene
Heptachlor
Heptachlor Epoxide
Hexachloro-benzene
Hexachloro-butadiene
Hexachloro-cyclohexane
Isoproturon
Lead
Mercury
Naphthalene
Nickel
Nonylphenol (4-Nonylphenol)
Octylphenol
Pentachloro-benzene
Pentachlorophenol
Polychlorinated Biphenyls
(PCBs)
Selenium
Simazine
Silver
Sulphate
Tetrachloroethylene
Trichloroethylene
Toxaphene
Tributyltin compounds
Trichloro-benzenes
Trichloro-methane
Trifluralin
Zinc
United States
National Recommended Water
Quality Criteria1
Maximum
Concentration
(CMC) (ug/l)
0.22
0.22
0.086
0.52
0.52
65
1.4
470
19
3.2
0.73
120
Continuous
Concentration
(CCC) (ug/l)
0.056
0.056
0.036
0.0038
0.0038
2.5
0.77
52
15
0.014
5
0.0002
120
European Union
Annual Average
Value
(Inland surface
Waters)
(ug/l)
0.005
0.005
I=0.014
20
0.01
0.1
0.02
0.3
7.2
0.05
2.4
20
0.3
0.1
0.007
0.4
1.0
129.75 mg/l
10.0
10
0.0002
0.4
2.5
0.03
Maximum
Allowable
Concentration
(Inland surface
Waters)
(ug/l)
0.01
0.01
N/A
N/A
0.05
0.6
0.04
1.0
N/A
0.07
N/A
N/A
2.0
N/A
N/A
1.0
4.0
4,200 mg/l
N/A
N/A
0.0015
N/A
N/A
N/A
Sources: US: http://www.epa.gov/waterscience/criteria/wqctable/index.htmltfcmc
EU: http://eur-lex.europa.eu/LexUriServ/LexUriServ.do?uri=OJ:L:2008:348:0084:0097:EN
PDF
Sum for cyclodiene pesticides which include: Aldrin, Dieldrin, Endrin, Isodrin
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APPENDIX C. REQUIREMENTS AND STANDARDS
Table C- 2: Drinking water quality guidelines and standards
Pollutant
Acrylamide
Ammonium
Aluminum
Antimony
Arsenic
Asbestos
Barium
Benzene
Benzo(a)pyrene
Beryllium
Boron
Bromate
Bromodichloro-
methane (BDCM)
Cadmium
Chlorate
Chloride
Clostridium
perfringens
United States
Maximum
Contaminant
Level Goal
0.006 mg/l
(6 ug/l)
0
7 million
fibers/liter
3 mg/l
(2000 ug/l)
0.004 mg/l
(4 ug/l)
0
0.005 mg/l
(5 ug/l)
Maximum
Contaminant
Level
0.006 mg/l
0.01 mg/l
7 million
fibers/liter
2 mg/l
(2000 ug/l)
0.004 mg/l
(4 ug/l)
0.010 mg/l
(10 ug/l)
0.005 mg/l
(5 ug/l)
Canada
Maximum
Acceptable
Concentration
0.1/0. 2 mg/l
(100-200 ug/l)
0.006
(6 ug/l)
0.1 mg/l
(10 ug/l)
lmg/1
(1000 ug/l)
0.005 mg/l
(5 ug/l)
0.00001 mg/l
(0.01 ug/l)
5 mg/l
(5000 ug/l)
0.01 mg/l
0.02 (10
Mg/D
0.016 mg/l
(16 ug/l)
0.005 mg/l
(5 ug/l)
lmg/1
(1000 ug/l)
European
Community
Parametric
Value
0.1 ug/l
0.50 mg/l
200 ug/l
5.0 ug/l
10 ug/l
1.0 ug/l
0.010 ug/l
1.0 mg/l
10 ug/l
100 ug/l5
5.0 ug/l
250 mg/l
0 number/
100ml
Czech
Republic
Parametric
Value
0.1 ug/l
0.50 mg/l
200 ug/l
5.0 ug/l
10 ug/l
1.0 ug/l
0.010 ug/l
1.0 mg/l
10 ug/l
5.0 ug/l
100 mg/l
0 number/
100ml
World Health
Organization
Guideline
Value
10 ug/l
0.06 mg/l
(60 ug/l)
Sum of concentrations of specified compounds: chloroform, bromoform, dibromochloromethane,
bromodichloromethane
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Energy Generation and Transmission
APPENDIX C. REQUIREMENTS AND STANDARDS
Pollutant
Conductivity
Chlorite
Chromium (total)
Copper
Cyanide (as free
cyanide)
Cyanobacterial
toxins --
microcystin-LR
1,2-dichloroethane
Epichlorohydrin
Fluoride
Iron
Lead
Manganese
Mercury (inorganic)
Nickel
Nitrate (measured
as Nitrogen)
Nitrite (measured as
Nitrogen)
Nickel
Nitrate
Nitrite
Pesticides
Pesticides -Total
Polycyclic aromatic
hydrocarbons
Selenium
United States
Maximum
Contaminant
Level Goal
0.8 mg/l
(800 ug/l)
0.1 mg/l
0.2 (100
Hg/D
1.3 mg/l
0.2 mg/l
(200 ug/l)
4 mg/l
0
0.03 mg/l
0.04 (2 ug/l)
10 mg/l
lmg/1
0.05 mg/l
(50 ug/l)
Maximum
Contaminant
Level
1.0 mg/l
(1000 ug/l)
0.1 mg/l
(100 ug/l)
1.3 mg/l
0.2 mg/l
(200 ug/l)
4 mg/l
0.015 mg/l
(15 ug/l)
0.002 mg/l
(2 ug/l)
10 mg/l
lmg/1
0.05 mg/l
(50 ug/l)
Canada
Maximum
Acceptable
Concentration
lmg/1
(1000 ug/l)
0.05 mg/l
(50 ug/l)
0.2 mg/l
(200 ug/l)
0.0015 mg/l
(1.5 ug/l)
1.5 mg/l
0.01 mg/l
(10 ug/l)
0.01 mg/l
(1 Hg/D
45 mg/l
3.2 mg/l
0.01 mg/l
(10 ug/l)
European
Community
Parametric
Value
2 500 u.S cm-
1 at 20 C
50 ug/l
2.0 mg/l
50 ug/l
3.0 ug/l
0.10 ug/l
1.5 mg/l
200 ug/l
10 ug/l
50 ug/l
1.0 ug/l
20 ug/l
50 mg/l
0.50 mg/l
20 ug/l
50 mg/l
0.50 mg/l
0.10 ug/l
0.50 ug/l
0.10 ug/l
10 ug/l
Czech
Republic
Parametric
Value
2 500 u.S cm-
1 at 20 C
200 ug/l
50 ug/l
1,0 mg/l
50 ug/l
lug/1
3.0 ug/l
0.10 ug/
1.5 mg/l
200 ug/l
10 ug/l
50 ug/l
1.0 ug/l
20 ug/l
50 mg/l
0.50 mg/l
20 ug/l
50 mg/l
0.50 mg/l
0.10 ug/l
0.50 ug/l
0.10 ug/l
10 ug/l
World Health
Organization
Guideline
Value
0.05 mg/l
(50 ug/l)
2.0 mg/l
1.5 mg/l
0.07 mg/l
(70 ug/l)
50 mg/l
0.2 mg/l
0.07 mg/l
(70 ug/l)
0.01 mg/l
(10 ug/l)
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APPENDIX C. REQUIREMENTS AND STANDARDS
Pollutant
Sulfate
Sodium
Tetrachloroethene
and Trichloroethene
Thallium
Trihalomethanes
(total)
Vinyl Chloride
pH
United States
Maximum
Contaminant
Level Goal
0.0005 mg/l
(0.5 ug/l)
N/A
Maximum
Contaminant
Level
0.002 mg/l
(2 ug/l)
0.080 mg/l
(80 ug/l)
Canada
Maximum
Acceptable
Concentration
6.5-8.5
European
Community
Parametric
Value
250 mg/l
200 mg/l
10 ug/l
100 ug/l
0.50 ug/l
6.5-9.5
Czech
Republic
Parametric
Value
250 mg/l
200 mg/l
10 ug/l
100 ug/l
0.50 ug/l
6.5-9.5
World Health
Organization
Guideline
Value
0.07 mg/l
(70 ug/l)
Sources: US Drinking Water Standards: http://www.epa.gov/ogwdwOOO/contaminants/index.html
WHO Guidelines for Drinking-Water Quality p.186, http://www.who.int/water sanitation health/dwq/fulltext.pdf
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Volume II-Appendices: EIA Technical Review Guidelines
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APPENDIX C. REQUIREMENTS AND STANDARDS
Table C- 3: Ambient air quality guidelines and standards
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ueerters into for
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f! .-
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Sources: European Commission Air Quality Standards: http://ec.europa.eu/environment/air/quality/standards.htm
Canadian National Ambient Air Quality Objectives: http://www.hc-sc.gc.ca/ewh-semt/air/out-ext/reg-eng.php
WHO (quoted in International Finance Corporation Environmental, Health, and Safety General Guidelines):
http://www.ifc.org/ifcext/sustainability.nsf/AttachmentsBvTitle/gui EHSGuidelines2007 GeneralEHS/$FILE/Final+-
+General+EHS+Guidelines.pdf
US National Ambient Air Quality Standards: http://epa.gov/air/criteria.htm
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Volume II -Appendices: EIATechnical Review Guidelines APPENDIX C. REQUIREMENTS AND STANDARDS
Energy Generation and Transmission
3 ENERGY-SECTOR SPECIFIC PERFORMANCE STANDARDS
Quantitative environmental performance standards may be applicable to all or some of the major types
of projects designed to generate electricity: fossil fuel, hydroelectric and non-hydroelectric renewable
energy. However, air emission limits, water discharge and effluent limits and waste standards
developed by countries and international organizations tend to focus on fossil fuel fired steam electric
power plants because they have the most significant potential and generalizable impacts through
contamination of air and water resources.
Water discharge or effluent limits:
Water discharges/effluent limits are summarized for fossil fuel powered, steam electric
generating facilities.
Hydroelectric dams may be subject to effluent limits that are calculated for a specific site taking
into account changes in water flow and the need to control suspended solids for a particular
waterway.
Wastewater treatment standards and effluent limits also may apply to wastewater generated by
employees working and/or living at the site.
Specific water discharge limits have not been set on a national basis for other renewable energy
sources.
Air emission limits:
Emission limits are available and summarized for a range of sizes and types of fossil fuel
powered electricity generating plants including, where available, those fueled either entirely or
partially with renewable biofuels.
Environmental impacts of specific hydropower facilities and other renewable energy sources
should be considered on a case-by-case basis. The lack of emission limits for these other types of
energy production does not mean that there are no impacts on air quality. For example,
although once constructed hydroelectric dams would not generally be a significant source of air
pollution, construction and transportation at such facilities may result in the release of
pollutants into the air. For example, the building of dams to supply hydropower can result in
the formation of lakes, which submerge vegetation growing along riverbanks. The decay of this
vegetation can result in the release of methane, a greenhouse gas.
Waste:
There are no broad based national and/or international performance standards provided for
most electric generation waste, with the exception of coal ash.
In general, fly ash waste, bottom ash waste, boiler slag waste, and flue gas emission control
waste quantitative performance standards are currently under development.
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Volume II-Appendices: EIA Technical Review Guidelines
Energy Generation and Transmission
APPENDIX C. REQUIREMENTS AND STANDARDS
Table C- 4: Environmental impacts from renewable energy sources
Renewable Energy
Source
Solar
Geothermal
Biomass
Wind
Environmental Impacts
Air
Negligible (no fuels
combusted).
Negligible (no fuels
combusted).
Biomass power plants
emit nitrogen oxides,
particulate matter,
carbon monoxide,
carbon dioxide, and
sulfur dioxide.
Negligible (no fuels
combusted).
Water
Solar technologies do
not discharge any water
while creating
electricity.
Can possibly cause
groundwater
contamination when
drilling wells and
extracting hot water or
steam. Re-injecting
used water back into
the ground prevents
underground minerals
from being introduced
into surface waters.
Biomass power plants
have pollutant build-up
in water used in the
boiler and cooling
system. The water used
in cooling can also have
an increased
temperature upon
discharge. Permits
generally required.
Wind turbines do not
discharge any water
while generating
electricity.
Waste Generation
Solar-thermal
technologies do not
produce any substantial
amount of solid waste
while creating electricity.
The production of
photovoltaic wafers
creates very small
amounts of hazardous
materials.
Geothermal technologies
do not produce a
substantial amount of
solid waste when
generating electricity.
The burning of biomass
creates ash, though
biomass ash generally has
a low concentration of
hazardous elements.
Wind technologies do not
produce any substantial
amount of solid waste.
Source: USEPA website, non-hydroelectric renewable energy.
http://www.epa.gov/cleanenergv/energv-and-vou/affect/non-hydro.html
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Volume II-Appendices: EIA Technical Review Guidelines
Energy Generation and Transmission
APPENDIX C. REQUIREMENTS AND STANDARDS
3.1. Energy Sector Water Discharge / Effluent Limits
Table C- 5: Water discharge/effluent limits applicable to steam electric plants
Pollutant
Aluminum
Arsenic
Barium
Boron
Cadmium
Carbamates
(total)
Chemical
Oxygen
Demand-COD
Chlorine
(residual)
Chromium-
(total)
Chromium
(hexavalent)
Color (purity)
Copper
Cyanide (total)
Cyanide (free)
Cyanide (free
but outside
mixing area)
Cyanide (weak
acid
dissociable)
Fluoride
Hydro-carbons
Iron
Costa Rica
Effluent
Limits for
Energy
Activities
5mg/l
O.lmg/l
5mg/l
3mg/l
O.lmg/l
O.lmg/l
lmg/1
1.5 mg/l
15%
0.5 mg/l
lmg/1
O.lmg/l
0.005 mg/l
0.5 mg/l
10 mg/l
10 mg/l
Dominican
Republic
Effluent
Limits for
Energy
0.1 mg/l
0.1 mg/l
150 mg/l
0.1 mg/l
0.5 mg/l
1.0 mg/l
0.1 mg/l
0.5 mg/l
3.5 mg/l
El Salvador
Maximum
Permitted
Release to
Water Body
5 mg/l
0.1 mg/l
5 mg/l
1.5 mg/l
0.1 mg/l
lmg/1
0.1 mg/l
None
lmg/1
.5 mg/l
5 mg/l
10 mg/l
(total)
Nicaragua
Proposed
Effluent Limits
for Energy
2 mg/l
O.lmg/l
lmg/1
0.5 mg/l
0.5 mg/l
lmg/1
United
States
For Steam
Electric
Generating
Facilities
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Volume II-Appendices: EIA Technical Review Guidelines
Energy Generation and Transmission
APPENDIX C. REQUIREMENTS AND STANDARDS
Pollutant
Lead
Mercury
Nickel
Nitrogen
(total)
Oil and Grease
Organo-
phosphorus
Compounds
(total)
Organo-
chlorine
Compounds
(total)
Radium 226
Selenium
Settleable
Solids
Silver
Sulfites
Sulphides
Tin
Total Metals
Total
Suspended
Solids (TSS)
Zinc
Temperature
pH
Costa Rica
Effluent
Limits for
Energy
Activities
0.5 mg/l
0.01 mg/l
lmg/1
50 mg/l
0.1 mg/l
0.05 mg/l
0.05 mg/l
lmg/1
lmg/1
25 mg/l
2 mg/l
5 mg/l
Dominican
Republic
Effluent
Limits for
Energy
0.2 mg/l
0.01 mg/l
0.5 mg/l
10 mg/l
10.0 mg/l
50 mg/l
2.0 mg/l
6.0-9.0
El Salvador
Maximum
Permitted
Release to
Water Body
0.4 mg/l
0.01 mg/l
0.2 mg/l
50 mg/l
0.1 mg/l
0.05 mg/l
0.05 mg/l
0.2 mg/l
?? 1000??
5 mg/l
20-35°C
5.5-9.0
Nicaragua
Proposed
Effluent Limits
for Energy
0.5 mg/l
lmg/1
lml/1
50 mg/l
lmg/1
40 °C
6.0-9.0
United
States
For Steam
Electric
Generating
Facilities
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Volume II -Appendices: EIATechnical Review Guidelines APPENDIX C. REQUIREMENTS AND STANDARDS
Energy Generation and Transmission
have wide-ranging environmental impacts, from the presence of floods when the dam gates are opened
to a disruption of normal water flows downstream.
3.2. Supplemental U.S. Water Discharge / Effluent Limits for the Energy Sector
Discharges of pollutants from any point source into the waters of the U.S. are prohibited except as in
compliance with the Clean Water Act. 33 U.S.C. § 1311. Usually this means that for the discharges to be
lawful they must be authorized by permit (The Clean Water Act section 301). Discharge permits are
issued either by EPA or states with programs approved by EPA administering what is called the National
Pollutant Discharge Elimination System (NPDES), or in the case of dredged or fill material the U.S. Army
Corps of Engineers or a state authorized to administer a permit program for such discharges with EPA
objection rights. 33 U.S.C. §§ 1342, 1344. NPDES permits must contain conditions that, at a minimum,
meet water quality standards and technology-based effluent performance limits, which for the steam-
electric power energy category, are found at 40 CFR 423. EPA takes into account both technological
availability and economic achievability when it promulgates nationwide effluent limits, and the effluent
standards are accessible via the EPA website (http://water.epa.gov/scitech/wastetech/guide/). The
limits listed for reference here are current as of 2011. The EPA plans to update the regulations for the
steam electric power generating industry in July 2012 and take final action by January 2014. The EPA
website will include information on any updates.
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Volume II-Appendices: EIA Technical Review Guidelines
Energy Generation and Transmission
APPENDIX C. REQUIREMENTS AND STANDARDS
Table C- 6: NPDES effluent limitations for steam electric generating facilities
Type of Waste Stream
Low-volume Waste Sources
Chemical Metal Cleaning
Wastes
Non-Chemical Metal Cleaning
Wastes
Bottom Ash Transport Water
Fly Ash Transport Water
Once-through Cooling Water
(facilities with a generating
capacity 25 MW or more)
Once-through Cooling Water
(facilities with a generating
capacity of less than 25 MW)
Chemicals Used in Cooling
Tower Slowdown
Coal Pile Runoff
Pollutant
Total Suspended
Solids (TSS)
Oil and grease
TSS
Oil and grease
Copper, total
Iron, total
Reserved
TSS
Oil and grease
No discharge
Total Residual
Chlorine
Free Available
Chlorine
Free Available
Chlorine
Chromium, total
Zinc, total
Other priority
pollutants
TSS
NSPS Effluent Limitations
1-day Maximum
100.0 mg/l
20.0 mg/l
100.0 mg/l
20.0 mg/l
1.0 mg/l
1.0 mg/l
Reserved
100.0 mg/l
20.0 mg/l
No discharge
0.20 mg/l
0.5 mg/l
0.5 mg/l
0.2 mg/l
1.0 mg/l
No discharge allowed
50 mg/l
Maximum average of
daily values for 30
consecutive days
30.0 mg/l
15.0 mg/l
30.0 mg/l
15.0 mg/l
1.0 mg/l
1.0 mg/l
Reserved
30.0 mg/l
15.0 mg/l
No Discharge
0.20 mg/l
0.2 mg/l
0.2 mg/l
0.2 mg/l
1.0 mg/l
No discharge allowed
50 mg/l
Sources: 40 Code of Federal Regulations Part 423 §423.15 (2011).
http://ecfr.gpoaccess.gov/cgi/t/text/text-
idx?c=ecfr&rgn=div5&view=text&node=40:28.0.1.1.23&idno=40#40:28.0.1.1.23.0.5.6
Sector Notebook Project: Fossil Fuel Electric Power Generation, p. 111-112 (September 1997)
http://www.epa.gov/compliance/resources/publications/assistance/sectors/notebooks
3.3. Air Emission Limits for the Energy Sector
Air emission limits are included from the International Finance Corporation Emission Guidelines and the
U.S. Environmental Protection Agency.
3.3.1. International Finance Corporation (IFC) Emissions Guidelines
The International Finance Corporation's (IFC) Environmental, Health, and Safety (EHS) Guidelines offer
both sector-specific and general requirements for projects and industries. IFC general emission
guidelines apply to any facility or project that produces air emissions during any period of its lifecycle.
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Volume II-Appendices: EIA Technical Review Guidelines
Energy Generation and Transmission
APPENDIX C. REQUIREMENTS AND STANDARDS
Table C- 7: IFC small combustion facilities emissions guidelines (3MWth-50MWth)
Combustion
Technology/
Fuel
Gas
Liquid
Turbine
Natural Gas
=3MWth to
< ISMWth
Natural Gas
=15MWth to
< SOMWth
Fuels other than
Natural Gas
=3MWth to <
ISMWth
Fuels other than
Natural Gas =
ISMWth to <
SOMWth
Boiler
Gas
Liquid
Solid
Particulate Matter
(PM)
N/A
50 mg/Nm3 (or up to
100 if justified by
project specific
considerations)
N/A
N/A
N/A
N/A
N/A
50 mg/Nm or up to
100 (if justified by
environmental
assessment)
50 or up to 100 (if
justified by
environmental
assessment)
Sulfur Dioxide (SO2)
N/A
1.5% (or up to 3.0% if
justified by project
specific considerations)
N/A
N/A
0.5 % or lower (if
commercially available
without significant
excess fuel cost)
0.5% or lower (if
commercially available
without significant
excess fuel cost)
N/A
2000 mg/Nm3
2000 mg/Nm3
Nitrogen Oxides
(NO,)
200 (Spark Ignition)
400 (Dual Fuel) 1,600
Compression Ignition)
1,460 mg/Nm3 (Bore
size diameter <400mm)
1,850 mg/Nm3 (Bore
size diameter > or
=400mm)
42 ppm (Electric
generation)
100 ppm (Mechanical
drive)
25 ppm
96 ppm (Electric
generation)
150 ppm (Mechanical
drive)
74 ppm
320 mg/Nm3
460 mg/Nm3
650 mg/Nm3
Dry Gas,
Excess O2
Content
15%
15%
15%
15%
15%
15%
3%
3%
6%
Source: IFC General EHS Guidelines p.7 (April 30, 2007).
http://www.ifc.org/ifcext/enviro.nsf/AttachmentsByTitle/gui
EHSGuidelines2007 GeneralEHS/$FILE/Fina
l+-+General+EHS+Guidelines.pdf
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Volume II-Appendices: EIA Technical Review Guidelines
Energy Generation and Transmission
APPENDIX C. REQUIREMENTS AND STANDARDS
Table C- 8: IFC emissions guidelines for boiler facilities
Combustion
Technology/
Fuel
Natural Gas
Other Gaseous
Fuels
Liquid Fuels
(50 MWh to 600
MWh)
Liquid Fuels (More
than 600 MWh)
Solid Fuels
(50 MWh to 600
MWh)
Solid Fuels
(More than 600
MWh)
Pollutants (mg/Nm3)
Particulate Matter (PM)
Non-
Degraded
Airshed
(NDA)
N/A
50
50
50
50
50
Degraded
Airshed
(DA)
N/A
30
30
30
30
30
Sulfur Dioxide
(S02)
NDA
N/A
400
900-1,500
200-850
900-1,500
200-850
DA
N/A
400
400
200
400
200
Nitrogen
Oxides (NOX)
NDA
240
240
400
400
510
510
DA
240
240
200
200
200
200
Dry Gas,
Excess O2
Content (%)
3%
3%
3%
3%
6%
6%
Source: IFC EHS Guidelines: THERMAL POWER PLANTS, p. 22.
http://www.ifc.org/ifcext/sustainability.nsf/AttachmentsByTitle/gui EHSGuidelines2007 ThermalPower/
$File/FINAL Thermal+Power.pdf
Table C- 9: IFC emissions guidelines for combustion turbines (units larger than 50 MWh)
Combustion
Technology/
Fuel
Natural Gas
Fuels other
than Natural
Gas
Pollutants (mg/Nm3)
Particulate Matter (PM)
Non-
Degraded
Airshed
(NDA)
N/A
50
Degraded
Airshed
(DA)
N/A
30
Sulfur Dioxide (SO2)
NDA
N/A
Use of 1% or
less S fuel
DA
N/A
Use of 0.5%
or less S fuel
Nitrogen
Oxides
(NOX)
NDA/DA
51(25ppm)
152 (74 ppm)
Dry Gas,
Excess O2
Content (%)
15%
15%
Source: IFC EHS Guidelines: THERMAL POWER PLANTS, p. 21.
http://www.ifc.org/ifcext/sustainability.nsf/AttachmentsByTitle/gui EHSGuidelines2007 ThermalPower/
$File/FINAL Thermal+Power.pdf
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Volume II-Appendices: EIA Technical Review Guidelines
Energy Generation and Transmission
APPENDIX C. REQUIREMENTS AND STANDARDS
Table C-10: IFC emissions guidelines for reciprocating engines
Combustion
Technology/
Fuel
Natural Gas
Liquid Fuels
(More than 50
MWh and less
than SOOMWh)
Liquid Fuels
(More than 300
MWh)
Biofuels/
Gaseous Fuels
other than
Natural Gas
Pollutants
(mg/IMm3)
Particulate Matter (PM)
Non-
Degraded
Airshed
(NDA)
N/A
50
50
50
Degraded
Airshed
(DA)
N/A
30
30
30
Sulfur Dioxide
(S02)
NDA
N/A
1,170 or
use of 2%
or less S
fuel
585 or use
of 1% or
less S fuel
N/A
DA
N/A
0.5% S
0.2% S
N/A
Nitrogen Oxides
(NOJ
NDA
200-400
1,460-
2,000
740
30% above
Natural
Gas/Liquid
Fuel Limits
DA
200-400
400
400
200-400
Dry Gas,
Excess O2
Content
15%
15%
15%
15%
Source: IFC EHS Guidelines: THERMAL POWER PLANTS, p. 20.
http://www.ifc.org/ifcext/sustainability.nsf/AttachmentsByTitle/gui EHSGuidelines2007 ThermalPower/$Fi
le/FINAL Thermal+Power.pdf
3.3.2. United States - New Source Performance Standards (NSPS) Applicable to Fossil Fuel Electric
Power Generation
Tables C-ll through C-22 summarize U.S. EPA's New Source Performance Standards for steam
generating units combusting fossil fuels. The applicable standard for new construction varies based on
the heat input and/or energy output of the unit, the fuel used, and the pollutant in question. All new
facilities and existing facilities undergoing major modification or expansion must meet New Source
Performance Standards, which are based on the use of the best available technology. Found at 40 CFR
Part 60, the standards established for the fossil fuel electric power generation industry vary by facility
size, type, and fuel. In recent years, the EPA has shifted to from input-based (Ib/MMBtu), regulations to
output-based (Ib/MWth) regulations. For more information on the benefits of output-based standards
in air quality regulations, see http://www.epa.gov/chp/documents/obr final 9105.pdf.
The performance standards are divided in the following size categories:
Units generating > 73 MWth (250 MMBtu/hr) heat input of fossil fuels
Units generating > 29 MWth (100 MMBtu/hr) and < 73 MWth
Units generating > 2.9 MWth (10 MMBtu/hr) and < 29 MWth
Stationary Gas Turbines
3.3.2.1. Units with Heat Input > 73 MW (250 MMBtu/hr)
Owners and operators that install, calibrate, maintain, and operate a continuous emissions monitoring
system (CEMS) for measuring PM emissions are exempt from the opacity standard (§ 60.42Da(b)).
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Volume II-Appendices: EIA Technical Review Guidelines
Energy Generation and Transmission
APPENDIX C. REQUIREMENTS AND STANDARDS
Opacity levels are to be based on a 6-minute average and may not exceed the maximum opacity except
for one 6-minute period per hour in which the maximum opacity is 27%.
Table C-11: Particulate matter (PM) emissions limits / reduction requirements
Compliance Alternatives
Alternative
#1
Alternative
#2
Construction,
Reconstruction,
or Modification
Construction or
Reconstruction
Modification
PM Emissions Limit
Gross Energy
Output
18 ng/J
(0.14 Ib/MWh)
Heat Input
6.4 ng/J
(0.015 Ib/MMBtu)
13 ng/J
(0.03 Ib/MMBtu)
13 ng/J
(0.03 Ib/MMBtu)
Percent Reduction
of Potential
Combustion
Concentration
And 99.90%
And 99.80%
Maximum
Opacity
20%
20%
20%
Source: Code of Federal Regulations Title 40 Part 60 Section 60.42Da (Jan. 28, 2009).
http://edocket.access.gpo.gov/cfr 2009/iulqtr/pdf/40cfr60.42Da.pdf
Table C-12: Sulfur dioxide (SO2) emissions limits and reduction requirements
Facility Description / Fuel Type
New construction
Reconstruction
Modification
SO2 Emission Limit
180 ng/J (1.4 Ib/MWh)
Gross energy output
180 ng/J (1.4 Ib/MWh)
Gross energy output OR
65 ng/J (0.15 Ib/MMBtu) Heat
input
Percent Reduction of
Potential Combustion
Concentration
Or 95%
Or 95%
Or 90%
Facilities that burn 75% or more (by heat input) coal refuse for:
New Construction
Reconstruction
Modification
180 ng/J (1.4 Ib/MWh)
Gross energy output
180 ng/J (1.4 Ib/MWh)
Gross energy output OR
65 ng/J (0.15 Ib/MMBtu) Heat
input
Or 94%
Or 94%
Or 90%
Source: Code of Federal Regulations Title 40 Part 60 Section 60.43Da (June 13, 2007)
http://edocket.access.gpo.gov/cfr 2009/iulqtr/pdf/40cfr60.44Da.pdf
When different fuels are combusted simultaneously, the applicable standard is determined by proration
using the formulas that can be found at: Code of Federal Regulations Title 40 Part 60 Section 60.43Da
(June 13, 2007). http://edocket.access.gpo.gov/cfr 2009/iulqtr/pdf/40cfr60.43Da.pdf
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Table C- 13: Oxides of nitrogen (NOX) emissions limits and reduction requirements
Facility Description / Fuel Type
New construction
Reconstruction
Modification
Gross Energy Output
130 ng/J (1.0 Ib/MWh)
130 ng/J (1.0 Ib/MWh)
180 ng/J (1.4 Ib/MWh)
Heat Input
-
47 ng/J (0.11 Ib/MMBtu)
65 ng/J (0.15 Ib/MMBtu)
Source: Code of Federal Regulations Title 40 Part 60 Section 60.44Da (2011).
http://ecfr.gpoaccess.gov/cgi/t/text/textidx?c=ecfr&sid=86668e4fac7clOa6a53edeeOcl9cb9c9&rgn=div8
&view=text&node=40:6.0.1.1.1.10.158.5&idno=40
NOTES to "Oxides of Nitrogen (NOX) Emissions Limits and Reduction Requirements" (40 CFR 60):
1 The owner or operator of an IGCC electric utility steam generating unit shall not cause to be
discharged into the atmosphere any gases that contain NOx(expressed as NO2) in excess of 130
ng/J (1.0 Ib/MWh) gross energy output on a 30-day rolling average basis. §60.44Da(f)
2 When burning liquid fuel exclusively or in combination with solid-derived fuel such that the
liquid fuel contributes 50 percent or more of the total heat input to the combined cycle
combustion turbine, the owner or operator shall not cause to be discharged into the
atmosphere any gases that contain NOx(expressed as NO2) in excess of 190 ng/J (1.5 Ib/MWh)
gross energy output on a 30-day rolling average basis. §60.44Da(f)
3 In cases when during a 30-day rolling average compliance period liquid fuel is burned in such a
manner to meet the conditions in paragraph (f)(2) of this section for only a portion of the clock
hours in the 30-day period, the owner or operator shall not cause to be discharged into the
atmosphere any gases that contain NOx(expressed as NO2) in excess of the computed weighted-
average emissions limit based on the proportion of gross energy output (in MWh) generated
during the compliance period for each of emissions limits in paragraphs (f)(l) and (2) of this
section. §60.44Da(f)
EPA is currently developing air toxics standards for coal- and oil-fired electric generating units. For more
information on the status of EPA proposals, visit http://www.epa.gov/ttn/atw/utilitv/utilitypg.html.
3.3.2.2. Units with Heat Input > 29 MW (100 MMBtu/hr) and < 73 MW
Units firing only very low sulfur oil, gaseous fuel, a mixture of these fuels, or a mixture of these fuels
with any other fuels with a potential SO2 emissions rate of 140 ng/J (0.23 Ib/MMBtu) heat input or less
are exempt from these SO2 emissions limits. §60.42b(k)(2).
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APPENDIX C. REQUIREMENTS AND STANDARDS
Table C-14: Sulfur dioxide (SO2) emissions limits
Facility Description / Fuel Type
Facilities combusting coal, oil, natural
gas, a mixture of these fuels, or a mixture
of these fuels with any other fuels
Facilities located in noncontinental areas
that combust coal
Facilities located in noncontinental areas
that combust oil or natural gas
Option (where
available)
Option #1
Option #2
SO2 Emissions Limit
87 ng/J (0.20 Ib/MMBtu)
heat input
520 ng/J (1.2 Ib/MMBtu)
heat input
520 ng/J (1.2 Ib/MMBtu)
heat input
215 ng/J (0.50 Ib/ MMBtu)
heat input
Percent
Reduction of
Potential
Combustion
Concentration
92%
Source: Code of Federal Regulations Title 40 Part 60 Section 60.42b (Jan. 28, 2009).
http://edocket.access.gpo.gov/cfr 2009/iulqtr/pdf/40cfr60.42b.pdf
NOTE to "Sulfur Dioxide (SO2) Emissions Limits (40 CFR 60)":
1 No owner or operator of an affected facility that combusts coal or oil, either alone or in
combination with any other fuel, and that uses an emerging technology for the control of SO2
emissions, shall cause to be discharged into the atmosphere any gases that contain SO2 in excess
of 50% of the potential SO2 emission rate (50% reduction) and that contains SO2 in excess of the
emission limit determined according to the following formula:
Es = (KcHc + KdHd)/(Hc+Hd)
Where: Es = SO2 emission limit, in ng/J or Ib/MMBtu heat input
Kc = 260 ng/J (or 0.60 Ib/MMBtu)
Kd = 170 ng/J (or 0.40 Ib/MMBtu)
Hc = Heat input from the combustion of coal, in J (MMBtu)
Hd = Heat input from the combustion of oil, in J (MMBtu). §60.42(b).
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APPENDIX C. REQUIREMENTS AND STANDARDS
Table C-15: Particulate matter (PM) emissions limits
Facility Description / Fuel Type
Facilities that combust municipal-type solid waste and/or other
fuels if the annual capacity factor for the other fuels is 10% or less
Facilities that combust coal, oil, wood, a mixture of these fuels, or
a mixture of these fuels with any other fuels
Facilities that combust coal, oil, wood, a mixture of these fuels, or
a mixture of these fuels with any other fuels and for which
modification commenced after Feb. 28, 2005
Facilities that combust over 30% wood (by heat input) on an
annual basis and have a maximum heat input capacity of 73 MW
(250 MMBtu/h) or less, for which modification commenced after
Feb. 28, 2005
Facilities that combust over 30% wood (by heat input) on an
annual basis and have a maximum heat input capacity greater
than 73 MW (250 MMBtu/h)
PM Emissions Limit
43ng/J(0.10
Ib/MMBtu) heat input
13 ng/J (0.030
Ib/MMBtu) heat input
22 ng/J (0.051
Ib/MMBtu) heat input
43 ng/J (0.10
Ib/MMBtu) heat input
37 ng/J (0.085
Ib/MMBtu) heat input
Percent
Reduction of
Potential
Combustion
Concentration
99.80%
Source: Code of Federal Regulations Title 40 Part 60 Section 60.43b (Jan. 28, 2009).
http://edocket.access.gpo.gov/cfr 2009/iulqtr/pdf/40cfr60.43b.pdf
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APPENDIX C. REQUIREMENTS AND STANDARDS
Table C-16: Nitrogen oxide (NOX) emissions limits
Fuel / Steam Generating Unit Type
(1) Natural gas and distillate
oil, except (4)
(2) Residual oil
(3) Coal
(4) Duct burner used in a
combined cycle system
(i) Low heat release rate
(ii) High heat release rate
(i) Low heat release rate
(ii) High heat release rate
(i) Mass-feed stoker
(ii) Spreader stoker and fluidized bed
combustion
(iii) Pulverized coal
(iv) Lignite, except (v)
(v) Lignite mined in North Dakota, South
Dakota, or Montana and combusted in a
slag tap furnace
(vi) Coal-derived synthetic fuels
(i) Natural gas and distillate oil
(ii) Residual oil
Nitrogen Oxide Emission Limits
(Expressed as NOX) Heat Input
ng/J
43
86
130
170
210
260
300
260
340
210
86
170
Ib/MMBtu
0.1
0.2
0.3
0.4
0.5
0.6
0.7
0.6
0.8
0.5
0.2
0.4
Source: Code of Federal Regulations Title 40 Part 60 Section 60.44b (2011).
http://ecfr.gpoaccess.gov/cgi/t/text/text-
idx?c=ecfr&sid=37145391aOa9f83eed8cdad550409621&rgn=div8&view=text&node=40:6.0.1.1.1.11.158.5
&idno=40
NOTES to "Nitrogen Oxide (NCX) Emissions Limits (40 CFR 60)":
1 No owner or operator of an affected facility that simultaneously combusts coal, oil, or natural gas with a
byproduct/waste shall cause to be discharged into the atmosphere any gases that contain NOX in excess
of the following formula unless the affected facility has an annual capacity factor for coal, oil, and natural
gas of 10% or less and is subject to a federally enforceable requirement that limits operation of the
affected facility to an annual capacity factor of 10% or less:
En = [(ELgoHgo) + (ELroHro) + (EUHC)] / (Hgo + Hro+ Hc)
Where:
En = NOX emission limit (expressed as NO2), ng/J (Ib/MMBtu)
ELgo = Appropriate emission limit... for combustion of a natural gas or distillate oil, ng/J (Ib/MMBtu)
Hgo = Heat input from combustion of natural gas, distillate oil, and gaseous byproduct/waste, J (MMBtu)
ELro= Appropriate emission limit... for combustion of residual oil and/or byproduct/waste, ng/J
(Ib/MMBtu)
Hro = Heat input from combustion of residual oil, J (MMBtu)
ELC = Appropriate emission limit... for combustion of coal, ng/J (Ib/MMBtu)
Hc = Heat input from combustion of coal, J (MMBtu). §60.44(b).
2 No owner or operator of an affected facility shall cause to be discharged into the atmosphere from
that affected facility any gases that contain NOX in excess of the following limits:
(1) If the affected facility combusts coal, oil, natural gas, a mixture of these fuels, or a
mixture of these fuels with any other fuels: A limit of 86 ng/J (0.20 Ib/MMBtu) heat
input unless the affected facility has an annual capacity factor for coal, oil, and natural
gas of 10 percent (0.10) or less and is subject to a federally enforceable requirement
that limits operation of the facility to an annual capacity factor of 10 percent (0.10) or
less for coal, oil, and natural gas; or
(2) If the affected facility has a low heat release rate and combusts natural gas or
distillate oil in excess of 30 percent of the heat input on a 30-day rolling average from
the combustion of all fuels, a limit determined by use of the following formula:
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Where:
En= NOX emission limit, (Ib/MMBtu);
Hgo= 30-day heat input from combustion of natural gas or distillate oil; and
Hr= 30-day heat input from combustion of any other fuel.
3 Units where more than 10 percent of total annual output is electrical or mechanical may comply with an
optional limit of 270 ng/J (2.1 Ib/MWh) gross energy output, based on a 30-day rolling average.
3.3.2.3. Units with Heat Input > 2.9 MW (10 MMBtu/hr), < 29 MW (100 MMBtu/hr)
Owners or operators of affected facilities that commence construction, reconstruction, or modification
after Feb. 28, 2005 and that combust only oil that contains no more than 0.50 weight percent sulfur oil
with other fuels not subject to a PM standard under §60.43c and not using a post-combustion
technology (except a wet scrubber) to reduce PM or SO2 emissions are not subject to the PM limit in this
section. §60.43c(e)(4).
Table C-17: Particulate matter (PM) emissions limits
Fuel Type / Facility Description
PM Emissions
Limit
Percent Reduction of
Potential Combustion
Concentration
Facilities that combust coal, oil, wood, a mixture of these
fuels, or a mixture of these fuels with other fuels and have a
heat input capacity of 8.7 MW (30 MMBtu/hr) or greater
13 ng/J
(0.03 Ib/MMBtu)
heat input
Facilities that combust coal, oil, wood, a mixture of these
fuels, or a mixture of these fuels with other fuels and have a
heat input capacity of 8.7 MW (30 MMBtu/hr) or greater
and for which modification commenced after Feb. 28, 2005
22 ng/J
(0.051 Ib/MMBtu)
heat input
99.80%
Facilities that combust over 30% wood (by heat input) on an
annual basis and have a heat input capacity of 8.7 MW (30
MMBtu/hr) or greater and for which modification
commenced after Feb. 28, 2005
43 ng/J
(0.10 Ib/MMBtu)
heat input
Source: Code of Federal Regulations Title 40 Part 60 Section 60.43c (Jan. 28, 2009).
http://edocket.access.gpo.gov/cfr 2009/iulqtr/pdf/40cfr60.43c.pdf
NOTE to "Particulate Matter (PM) Emissions Limits (40 CFR 60)":
1 Percent reduction requirements for SO2 are not applicable to the following affected facilities: (1) affected
facilities that have a heat input capacity of 22 MW (75 MMBtu/hr) or less; (2) affected facilities that have
an annual capacity for coal of 55% or less and are subject to a federally enforceable requirement limiting
operation of the affected facility to an annual capacity factor for coal of 55% or less; (3) affected facilities
located in a noncontinental area; and (4) affected facilities that combust coal in a duct burner as part of a
combined cycle system where 30% or less of the heat entering the steam generating unit is from
combustion of coal in the duct burner and 70% or more of the heat entering the steam generating unit is
from exhaust gases entering the duct burner. §60.42c(c)(l)-(4).
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Table C-18: Sulfur dioxide (SO2) emissions limits
Facility Description / Fuel Type
Facilities combusting only coal
(must meet both standards)
Facilities combusting coal with other fuels
Facilities combusting coal refuse alone in a
fluidized bed combustion steam generating
unit
(must meet both standards)
Facilities combusting oil or other non-coal
fuel with coal refuse
Facilities combusting only coal and using
emerging technology to control SO2
emissions
Facilities combusting coal with other fuels
and using emerging technology to control
SO2 emissions
Facilities combusting oil
SO2 Emissions Limit
87 ng/J (0.20 Ib/MMBtu)
heat input
520 ng/J (1.2 Ib/MMBtu)
heat input
87 ng/J (0.20 Ib/MMBtu)
heat input
87 ng/J (0.20 Ib/MMBtu)
heat input
520 ng/J (1.2 Ib/MMBtu)
heat input
87 ng/J (0.20 Ib/MMBtu)
heat input
See Equation
260 ng/J (0.60 Ib/MMBtu) heat input
See Equation
215 ng/J (0.50 Ib/MMBtu) heat
Percent Reduction of
Potential Combustion
Concentration6
90%
90%
80%
90%
50%
50%
Source: Code of Federal Regulations Title 40 Part 60 Section 60.42c (Jan. 28, 2009).
http://edocket.access.gpo.gov/cfr 2009/iulqtr/pdf/40cfr60.42c.pdf
NOTES to "Sulfur Dioxide (SOZ) Emissions Limits (40 CFR Part 60)":
1 The owner or operator of an affected facility that:
(1) Combusts only coal refuse alone in a fluidized bed combustion steam generating unit shall neither:
(i) Cause to be discharged into the atmosphere from that affected facility any
gases that contain SO2in excess of 87 ng/J (0.20 Ib/MMBtu) heat input or 20
percent (0.20) of the potential SO2emission rate (80 percent reduction); nor
(ii) Cause to be discharged into the atmosphere from that affected facility any
gases that contain SO2in excess of SO2in excess of 520 ng/J (1.2 Ib/MMBtu) heat
input.
(2) Combusts only coal and that uses an emerging technology for the control of SO2emissions shall
neither:
(i) Cause to be discharged into the atmosphere from that affected facility any
gases that contain SO2in excess of 50 percent (0.50) of the potential
SO2emission rate (50 percent reduction); nor
(ii) Cause to be discharged into the atmosphere from that affected facility any
gases that contain SO2in excess of 260 ng/J (0.60 Ib/MMBtu) heat input.
2 As an alternative to meeting this requirement, an owner or operator of an affected facility may choose
instead not to combust oil that contains greater than 0.5 weight percent sulfur. Percent reduction
requirements do not apply to facilities combusting only oil. §60.42c(d).
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3 The SO2 emission limit for any affected facility that combusts coal, oil, or coal and oil with any other fuel is
determined by the following formula:
Es = (KaHa + KbHb + KCHC) / (Ha + Hb + Hc)
Where Es = SO2 emission limit, expressed in ng/J or Ib/MMBtu heat input
Ka = 520ng/J(1.2lb/MMBtu)
Kb = 260 ng/J (0.60 Ib/MMBtu)
Kc = 215 ng/J (0.50 Ib/MMBtu)
Ha = Heat input from combustion of coal, except from facilities that combust coal and use an emerging
technology to control SO2 emissions, in J [MMBtu]
Hb = Heat input from combustion of coal in facilities that combust coal and use an emerging technology to
control SO2 emissions
Hc = Heat input from the combustion of oil, in J (MMBtu). §60.42c(e)(2).
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APPENDIX C. REQUIREMENTS AND STANDARDS
3.3.2.4. Stationary Gas Turbines
The following standards are applicable to all stationary gas turbines with a heat input at peak load equal
to or greater than 10.7 gigajoules (10 million Btu) per hour, based on the higher heating value of the fuel
fired.
Table C-19: NOX emissions limits for new stationary combustion turbines
Combustion Turbine Type
Combustion Turbine Heat
Input at Peak Load
(HHV)
NOX Emission Standard
Natural Gas
Electric generating
Mechanical drive
Firing natural gas
Firing natural gas
< 50 MMBtu/h
< 50 MMBtu/h
> 50 MMBtu/h and < 850
MMBtu/h
> 850 MMBtu/h
042 ppm at 15 percent O2or 290 ng/J of
useful output (2.3 Ib/MWh).
100 ppm at 15 percent O2or 690 ng/J of
useful output (5.5 Ib/MWh).
25 ppm at 15 percent O2or 150 ng/J of
useful output (1.2 Ib/MWh).
15 ppm at 15 percent O2or 54 ng/J of
useful output (0.43 Ib/MWh)
Fuels Other Than Natural Gas
Electric generating
Mechanical drive
Firing fuels other than natural
gas
Firing fuels other than natural
gas
< 50 MMBtu/h
< 50 MMBtu/h
> 50 MMBtu/h and < 850
MMBtu/h
> 850 MMBtu/h
96 ppm at 15 percent O2or 700 ng/J of
useful output (5.5 Ib/MWh).
150 ppm at 15 percent O2or 1,100 ng/J of
useful output (8.7 Ib/MWh).
74 ppm at 15 percent O2or 460 ng/J of
useful output (3.6 Ib/MWh).
42 ppm at 15 percent O2or 160 ng/J of
useful output (1.3 Ib/MWh).
Heat Recovery Units
Heat recovery units operating
independent of the
combustion turbine
All sizes
54 ppm at 15 percent O2or 110 ng/J of
useful output (0.86 Ib/MWh).
Source: Code of Federal Regulations Title 40 Part 60 Section 60.4320 (2011).
http://ecfr.gpoaccess.gov/cgi/t/text/text-idx?c=ecfr;sid=cl3486c8995148442d6538ffd9563539:
rgn=div6:view=text:node=40%3A6.0.1.1.1.101:idno=40;cc=ecfr
Owners or operators of stationary gas turbines have a choice of three options for meeting sulfur dioxide
standards in continental areas and two options in non-continental areas, as shown in table C-21. The
non-continental area standards also apply to continental areas where the EPA determines the area has
no excess to natural gas and that the removal of sulfur compounds would cause more environmental
harm than benefit.
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Table C- 20: Sulfur dioxide (SO2) emissions limits by options
Continental Areas
Option #1: Emissions-based Limit
Option #2: Fuel-based Limit
Option #3: Biogas Option
Discharges into the atmosphere shall not contain SO2 in excess of 110
nanograms per Joule (ng/J) (0.90 pounds per megawatt-hour (Ib/MWh))
gross output.
Fuel burned in a stationary gas turbine shall not contain total potential
sulfur emissions in excess of 26 ng SO2/J (0.060 Ib SO2/MMBtu) heat
input.
For each stationary combustion turbine burning at least 50 percent
biogas on a calendar month basis, as determined based on total heat
input, discharges into the atmosphere shall not contain SO2 in excess of
65 ng SO2/J (0.15 Ib SO2/MMBtu) heat input.
Non Continental Areas
Option #1: Emissions-based Limit
Option #2: Fuel-based Limit
Discharges into the atmosphere shall not contain SO2in excess of 780
ng/J (6.2 Ib/MWh) gross output,
Fuel burned in a stationary gas turbine shall not contain total potential
sulfur emissions in excess of 180 ng SO2/J (0.42 Ib SO2/MMBtu) heat
input. If your turbine simultaneously fires multiple fuels, each fuel must
meet this requirement.
Source: Code of Federal Regulations Title 40 Part 60 Section 60.43330 (2011).
http://ecfr.gpoaccess.gov/cgi/t/text/text-idx?c=ecfr&sid=fllll7950ffbc58cdlc9345904b23117&rgn=
div8&view=text&node=40:6.0.1.1.1.101.280.7&idno=40
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APPENDIX C. REQUIREMENTS AND STANDARDS
4 INTERNATIONAL TREATIES AND AGREEMENTS
CAFTA-DR countries have ratified and/or signed a number of international treaties and agreements which
provide commitments to adopting and implementing a range of environmental protection regimes. Most
do not confer specific quantitative benchmarks for performance and so are not summarized in this
Appendix. However, for convenience they are listed below as of the date of publication.
Table C- 21: Multilateral environmental agreements ratified (R) or signed (S) by CAFTA-DR countries
Multilateral Environmental Agreement
Basel Convention on the Control of Transboundary Movements of Hazardous Wastes
and Their Disposal entered into force - 5 May 1992
Convention on Biological Diversity - abbreviated as Biodiversity entered into force -
29 December 1993
Convention on Wetlands of International Importance Especially as Waterfowl Habitat
(Ramsar) entered into force - 21 December 1975
Convention on the International Trade in Endangered Species of Wild Flora and Fauna
(CITES) entered into force - 1 July 1975
Convention on the Prevention of Marine Pollution by Dumping Wastes and Other
Matter (London Convention) entered into force - 30 August 1975
Convention on the Prohibition of Military or Any Other Hostile Use of Environmental
Modification Techniques entered into force - 5 October 1978
United Nations Framework Convention on Climate Change entered into force - 21
March 1994
Kyoto Protocol to the United Nations Framework Convention on Climate Change
entered into force - 23 February 2005
Montreal Protocol on Substances That Deplete the Ozone Layer entered into force -
1 January 1989
International Convention for the Regulation of Whaling entered into force - 10
November 1948
International Tropical Timber Agreement, 1994 entered into force - 1 January 1997
Protocol of 1978 Relating to the International Convention for the Prevention of
Pollution From Ships, 1973 (MARPOL) entered into force - 2 October 1983
United Nations Convention on the Law of the Sea (LOS) entered into force- 16
November 1994
United Nations Convention to Combat Desertification in Those Countries
Experiencing Serious Drought and/or Desertification, Particularly in Africa entered
into force - 26 December 1996
CD
_u
2
CD
*J
I/)
o
u
R
R
R
R
R
R
R
R
R
R
R
R
Dominican Republic
R
R
R
R
R
R
R
R
R
S
R
El Salvador
R
R
R
R
R
R
R
S
R
Guatemala
R
R
R
R
R
R
R
R
R
R
R
R
R
R
Honduras
R
R
R
R
R
R
R
R
R
R
R
R
Nicaragua
R
R
R
R
R
R
R
R
R
R
R
R
Source: https://www.cia.gov/library/publications/the-world-factbook/appendix/appendix-c.html
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5 ENERGY SECTOR WEBSITE REFERENCES
More information on environmental impacts, mitigation measures, industry best practices, and
quantitative standards for the energy sector can be found at the following websites:
INTERNATIONAL FINANCE ORGANIZATION (www.ifc.org)
Environmental, Health, and Safety Guidelines
English: www.ifc.org/ifcext/sustainability.nsf/Content/EHSGuidelines
Espanol: http://www.ifc.org/ifcext/sustainability.nsf/Content/EHSGuidelines Spanish
UNITED STATES ENVIRONMENTAL PROTECTION AGENCY (www.epa.gov)
Regulatory Information for the Energy Sector
English: www.epa.gov/lawsregs/bizsector/energy.html
Power Generator Compliance Assistance
English: www.epa.gov/compliance/assistance/sectors/power.html
Profile of the Fossil Fuel Electric Power Generation Industry
English:
http://www.epa.gov/compliance/resources/publications/assistance/sectors/notebooks/
fossil.html
Non-Hydroelectric Renewable Energy
English: www.epa.gov/cleanenergv/energv-and-vou/affect/non-hydro.html
Hydroelectricity
English: www.epa.gov/cleanenergy/energy-and-you/affect/hydro.html
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Energy Generation and Transmission
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APPENDIX D. EROSION AND SEDIMENTATION
APPENDIX D. RULES OF THUMB FOR EROSION AND SEDIMENTATION CONTROL
RULES OF THUMB FOR EROSION AND SEDIMENT CONTROL
(Excerpted from Kentucky Erosion Prevention and Sediment Control Field Guide)
TETRA TECH funded by
Kentucky Division of Water (KDOW), Nonpoint Source Section
and the Kentucky Division of Conservation (KDOC) through a grant from USEPA
http://www.epa.gov/region8/water/stormwater/pdf/Kentuckv%20Erosion%20prevention%20field%20
guide.pdf
This Appendix presents illustrations and photographs of Best Management Practices for Erosion and
Sediment Control. This information was excerpted from the US EPA funded Kentucky Erosion
Prevention and Sediment Control Field Guide.
BASIC RULES
Preserve existing Vegetation
Divert upland runoff around exposed soil
Seed/mulch/ cover bare soil immediately
Use sediment barriers to trap soil in runoff
Protect slopes and channels from gullying
Install sediment traps and settling basins
Preserve vegetation near all waterways
NEED FOR EROSION AND SEDIMENT CONTROL MEASURES
Slope Angle
Very Steep (2:1 or more)
Steep (2:1-4:1)
Moderate (5:1-10:1)
Slight (10:1-20:1
Soil Type
Silty
Very high
Very High
High
Moderate
Clays
High
High
Moderate
Moderate
Sandy
High
Moderate
Moderate
Low
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APPENDIX D. EROSION AND SEDIMENTATION
PRIORIZATION OF EROSION AND SEDIMENT CONTROL MEASURES
PRACTICE
Limiting disturbed area through phasing
Protecting disturbed areas with mulch and
revegetation
Installing diversions around disturbed areas
Sediment removal through detention of all site
drainage
Other structural controls to contain sediment laden
drainage
COST
$
$$
$$$
$$$$
$$$$$
EFFECTIVENESS
*****
****
***
**
*
PLAN AHEAD
Identify drainage areas and plan for drainage
ditches and channels, diversions, grassed channels,
sediment traps/basins, down slope sediment
barriers, and rock construction and install before
beginning excavation.
DIVERT RUNOFF AROUND EXCAVATION AND
DISTURBANCE
Berms and ditches diverting clean upland runoff
around construction sites reduce erosion and
sedimentation problems. Seed berms and
ditches after construction.
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APPENDIX D. EROSION AND SEDIMENTATION
Diversion ditches should be lined with grass
at a minimum, and blankets if slopes exceed
10:1
VEGETATIVE BUFFERS
Vegetated buffers above or below your work site are
always a plus.
They trap sediment before it can wash into waterways,
and prevent bank erosion.
Vegetated waterways help move upland
water through or past your site while keeping
it clear of mud. Do not disturb existing
vegetation along banks, and leave a buffer of
tall grass and shrubs between stream bank
trees and disturbed areas.
Good construction, seeding, and stabilization of
diversion berm. Note that diversion ditch is lined with
grass on flatter part of slope, and with rock on steeper
part.
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APPENDIX D. EROSION AND SEDIMENTATION
SOIL COVER VS EROSION PROTECTION
SOIL COVERING
Mulch (hay or straw)
1.2 ton per 0.4 hectare
1 ton per 0.4 hectare
2 tons per 0.4 hectare
Grass (seed or sod)
40 percent cover
60 percent cover
90 percent cover
Bushes and shrubs
25 percent cover
75 percent cover
Trees
25 percent cover
75 percent cover
Erosion control blankets
EROSION REDUCTION
75 percent
87 percent
98 percent
90 percent
96 percent
99 percent
60 percent
72 percent
58 percent
64 percent
95-99 percent
Prepare bare soil for planting by disking across slopes, scarifying, or tilling if soil has been sealed or
crusted over by rain. Seedbed must be dry with loose soil to a depth of 3 to 6 inches.
For slopes steeper than 4:1, walk bulldozer or other tracked vehicle up and down slopes before seeding
to create tread-track depressions for catching and holding seed. Mulch slopes after seeding if possible.
Cover seed with erosion control blankets or turf mats if slopes are 2:1 or greater. Apply more seed to
ditches and berms.
Erosion and sediment loss is virtually eliminated on seeded areas (left side). Rills and small gullies form
quickly on unseeded slopes (right).
BLANKET INSTALLATION (GEOFABRIC)
Install blankets and mats vertically on long
slopes. Unroll from top of hill, staple as you
unroll it. Do not stretch blankets.
Erosion control blankets are thinner and
usually degrade quicker than turf reinforced
mats. Check manufacturer's product
information for degradation rate (life span),
slope limitations, and installation.
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APPENDIX D. EROSION AND SEDIMENTATION
Remember to apply seed,
fertilizer, and lime before
covering with blankets or
mats!
Blankets installed along stream banks or other
short slopes can be laid horizontally. Install
blankets vertically on longer slopes. Ensure 15
cm minimum overlap.
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APPENDIX D. EROSION AND SEDIMENTATION
BLANKET INSTALLATION
SITE CONDITIONS
BLANKET INSTALLATION NOTES
Ditches and
channels
(from high flow
line to ditch
bottom)
Grade, disk, and prepare seedbed.
Seed, lime, and fertilize the area first
Install horizontally (across slope).
Start at ditch bottom.
Staple down blanket center line first.
Staple & bury top in 8" deep trench.
Top staples should be 12" apart.
Uphill layers overlap bottom layers.
Side overlap should be 6"-8".
Side & middle staples = 24" apart.
Staple below the flow level every 12".
Staple thru both blankets at overlaps.
Long slopes,
including
areas above
ditch flow
levels
Grade, disk, and prepare seedbed.
Seed, lime, and fertilize first.
Install vertically (up & down hill).
Unroll from top of hill if possible.
Staple down center line of blanket first.
Staple & bury top in 8" deep trench.
Top staples should be 12" apart.
Side & middle staples = 24" apart.
Uphill layers overlap downhill layers.
Overlaps should be 6"-8".
Staple thru both blankets at overlap.
SEDIMENT BARRIERS (Silt fences and others)
Silt fences should be installed on the contour
below bare soil areas.
Use multiple fences on long slopes 20 to 26
meters a part. Remove accumulated
sediment before it reaches halfway up the
fence.
Each 33-meter section of silt fence can filter
runoff from about 0.6 hectare (about 35
meters uphill). To install a silt fence
correctly, follow these steps:
Note the location & extent of the
bare soil area
Mark silt fence location just below
bare soil area
Make sure fence will catch all flows
from area
Dig trench 15 centimeters deep
across slope
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APPENDIX D. EROSION AND SEDIMENTATION
Unroll silt fence along trench.
Join fencing by rolling the end stakes together.
Make sure stakes are on downhill side of fence.
Drive stakes in against downhill side of trench.
Drive stakes until 20 to 25 centimeters of fabric is
in trench.
Push fabric into trench; spread along bottom.
Fill trench with soil and tamp down.
Stakes go on the downhill side. Dig trench first, install
fence in downhill side of trench, and tuck fabric into
trench, then backfill on the uphill side (the side toward
the bare soil area).
Use J-hooks to trap and pond muddy runoff flowing along uphill side of silt fence. Turn ends of silt fence
toward the uphill side to prevent bypassing. Use multiple J-hooks every 17 to 50 meters for heavier
flows.
Fiber rolls can be used to break up runoff
flows on long slopes. Install on the contour
and trench in slightly. Press rolls firmly into
trench and stake down securely. Consult
manufacturer's instructions for expected
lifespan of product, slope limits, etc. As
always, seed and mulch long slopes as soon
as possible.
Very good installation of multiple silt fences on long slope. Turn ends of
fencing uphill to prevent bypass. Leave silt fences up until grass is well
established on all areas of the slope. Re-seed bare areas as soon as
possible. Remove or spread accumulated sediment and remove silt
fence after all grass is up.
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APPENDIX D. EROSION AND SEDIMENTATION
SLOPE PROTECTION TO PREVENT GULLIES
If soil is:
Compacted and smooth
Tracks across slopes
Tracks up & down slopes
Rough and irregular
Rough & loose to 12" deep
Erosion will be:
30 percent more
20 percent more
10 percent less
10 percent less
20 percent less
Tread-track slopes up and down hill to improve
stability.
Temporary down drain using plastic pipe. Stake
down securely, and install where heavy flows need
to be transported down highly erodible slopes. Note
silt check dam in front of inlet.
,* -
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APPENDIX D. EROSION AND SEDIMENTATION
Temporary or permanent down drain using
geotextile underliner and riprap. All slope
drains must have flow dissipaters at the
outlet to absorb high energy discharges, and
silt checks at the inlet until grass is
established.
,
Steep, long slopes need blankets or mats.
Install blankets and mats up and down long
slopes. For channels below slopes, install
horizontally. Don't forget to apply seed, lime,
and fertilizer (if used) before installing
blanket.
Other methods that could be considered are
breaking up steep slopes with terraces,
ditches along contours, straw bales and other
methods.
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APPENDIX D. EROSION AND SEDIMENTATION
PROTECTING DITCHS AND CULVERTS INLETS/OUTLETS
Low-flow energy dissipaters (above) are
shorter than those for high-flow outlets
(below).
Very good application of mixed rock for culvert inlet
ponding dam. Mixing rock promotes better ponding,
drainage, and settling of sediment.
Excellent placement and construction of rock apron to
dissipate flows from culvert outlet. Area needs seeding
and mulching.
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APPENDIX D. EROSION AND SEDIMENTATION
STABILIZING DRAINAGE DITCHES
Stabilization approaches for drainage ditches
Ditch Slope
Steep >10%
Moderate 10%
Slight 5%
Mostly Flat <3%
Soil Type in Ditch
Sandy
Concrete or riprap
Riprap with filter fabric
Riprap or turf mats
&seeding
Seeding &blankets
Silty
Concrete or riprap
Riprap or turf mats
&seeding
Seeding &turf mats
Seeding &mulching
Clays
Riprap
Riprap or turf mats&
seeding
Seeding &turf mats
Seeding &mulching
Lay in ditch blankets similar to roof shingles;
start at the lowest part of the ditch, then
work your way up. Uphill pieces lap over
downhill sections. Staple through both layers
around edges. Trench, tuck, and tamp down
ends at the top of the slope. Do not stretch
blankets or mats.
Check Dams
Silt check dams of rock, stone-filled bags, or commercial
products must be installed before uphill excavation or fill
activities begin. See table below for correct silt check
spacing for various channel slopes. Tied end of bag goes
on downstream side.
Spacing of Check Dams in Ditches
Ditch Slope
30%
20%
15%
10%
5%
2%
1%
0.5%
Check Dam Spacing
(meters)
3.2
5
7
12
17
33
50
100
200
Additional Information
Calculated for 1 meter high check dam
Center of the dam should be 150 centimeters
lower than the sides
Use 15 to 25 cm rock, stone bags, or
commercial products
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Good installation of temporary rock silt
checks. Remember to tie sides of silt check to
upper banks. Middle section should be lower.
Clean out sediment as it accumulates.
Remove silt checks after site and channel are
stabilized with vegetation.
Good placement and spacing of fiber-roll silt
checks. Coconut fiber rolls and other
commercial products can be used where
ditch slopes do not exceed three percent.
Ditch lined with rock.
Rock Sizing for ditch liners
Flow Velocity
2 m/sec
2.5 m/sec
3.3 m/sec
4 m/sec
Average rock diameter
12.5 cm
25.0 cm
35.0cm
50.0 cm
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APPENDIX D. EROSION AND SEDIMENTATION
SEDIMENT TRAPS AND BASINS
In general, sediment traps are designed to treat runoff from about 1 to 5 acres. Sediment basins are
larger, and serve areas of about 5 to 10 acres. Basins draining areas larger than 10 acres require an
engineered design, and often function as permanent storm water treatment ponds after construction is
complete.
Sediment traps
Any depression, swale, or low-
lying place that receives muddy
flows from exposed soil areas can
serve as a sediment trap.
Installing several small traps at
strategic locations is often better
than building one large basin. The
simplest approach is to dig a hole
or build a dike (berm) of earth or
stone where concentrated flows
are present. This will help to
detain runoff so sediment can
settle out. The outlet can be a
rock lined depression in the
containment berm.
seeded
stable owsiBi
maintained
Sediment basins
Sediment basins are somewhat larger than traps, but the construction approach is the same. Sediment
basins usually have more spillway protection due to their larger flows. Most have risers and outlet
pipes rather than rock spillways to handle the larger flows. Sediment basins are often designed to
serve later as storm water treatment ponds. If this is the case, agreements are required for long-term
sediment removal and general maintenance. Construction of a permanent, stable outlet is key to long-
term performance.
Sizing and design considerations
A minimum storage volume of 130 cubic meters per 0.4 hectare of exposed soil drained is required for
basins and traps. Traps and basins are designed so that flow paths through the trap or basin are as long
as possible, to promote greater settling of soil particles. Sediment basin length must be twice the
width or more if possiblethe longer the flow path through the basin, the better.
Side slopes for the excavation or earthen containment berms are 2:1 or flatter. Berms are made of
well-compacted clayey soil, with a height of 1.5 meters or less. Well mixed rock can also be used as a
containment berm for traps. Place soil fill for the berm or dam in 15 cm layers and compact. The
entire trap or basin, including the ponding area, berms, outlet, and discharge area, must be seeded and
mulched immediately after construction. An overflow outlet can be made by making a notch in the
containment berm and lining it with rock. Rock in the notch must be large enough to handle over-
flows, and the downhill outlet should be stabilized with rock or other flow dissipaters similar to a
culvert outlet. Overflow should be at an elevation so dam will not overtop. Allow at least 0.33 meter
of freeboard. Outlets must be designed to promote sheet flow of discharges onto vegetated areas if
possible. If the discharge will enter a ditch or channel, make sure it is stabilized with vegetation or
lined.
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APPENDIX D. EROSION AND SEDIMENTATION
PROTECTING STREAMS AND STREAM BANKS
Recommended Setbacks of Activities from Streams
Bank Slope
Very Steep (2:1 or more)
Steep (4:1 or more)
Moderate (6:1 or more)
Mostly flat(< 10:1)
Soil Type Along Banks
Sandy
33m
27m
20m
13m
Silty
27m
20m
13m
10m
Clays
20m
13m
10m
6.5m
Vegetated buffers
Preserve existing vegetation near waterways wherever possible. This vegetation is the last chance
barrier to capture sediment runoff before it enters the lake, river, stream, or wetland. Where
vegetation has been removed or where it is absent, plant native species of trees, shrubs, and grasses.
Live hardwood stakes driven through live
wattles or rolls and trenched into slope provide
excellent stream bank protection. Protect toe
of slope with rock or additional rolls or rocks.
STREAM CROSSINGS
Keep equipment away from and out of
streams. If a temporary crossing is needed, put
it where the least stream or bank damage will
occur. Look for:
Hard stream bottom areas
Low or gently sloping banks
Heavy, stable vegetation on both sides
Use one or more culverts, as needed, sized to
carry the two-year 24-hour rain storm. Cover
culverts with at least 27 cm of soil and at least
15 cm inches of mixed rock. An 8.5 meter
long, 15 cm thick pad of rock should extend
down the haul road on each side of the
crossing.
Good use of silt fence, straw, rock and other
practices for temporary stream crossing. Any
work in stream channelssuch as installation
of culverts
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APPENDIX E. SAMPLING AND ANALYSIS PLAN
GUIDANCE AND TEMPLATE
VERSION 2, PRIVATE ANALYTICAL SERVICES USED
R9QA/002.1
April, 2000
UNITED STATES ENVIRONMENTAL PROTECTION AGENCY
REGION 9
This Sampling and Analysis Plan (SAP) guidance and template is based on USEPA guidance as presented
at http://ndep.nv.gov/BCA/file/reid sap.pdf. It is intended assist organization in documenting the
procedural and analytical requirements for baseline and routine monitoring of surface water ground
water, soils, and biological samples. It has originally developed to characterize contaminated land but
has been modified here to address sampling, laboratory analysis, and quality control/quality assurance
for evaluation pre-mining, mining, and post mining hydrologic and biologic conditions. This guide is to
be used as a template. It provides item-by-item instructions for creating a SAP and includes example
language which can be used with or without modification.
1 INTRODUCTION
[This section should include a brief description of the project, including the history, problem to be
investigated, scope of sampling effort, and types of analyses that will be required. These topics will
be covered in depth later so do not include a detailed discussion here.]
1.1. Site Name or Sampling Area
[Provide the most commonly used name of the site or sampling area.]
1.2. Site or Sampling Area Location
[Provide a general description of the region, or district in which the site or sampling area is located.
Detailed sampling location information should be provided later in Section 2.]
1.3. Responsible Organization
[Provide a description of the organization conducting the sampling.]
1.4. Project Organization
[Provide the name and phone number(s) of the person(s) and/or contractor working on the sampling
project as listed in the table. The table can be modified to include titles or positions appropriate to
the specific project. Delete personnel or titles not appropriate to the project.]
Title/Responsibility Name Phone Number
Project Manager
Staff
Quality Assurance Manager
Contractor (Company Name)
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Contractor Staff
1.5. Statement of the Specific Problem
[In describing the problem, include historical, as well as recent, information and data that may be
relevant. List and briefly outline citizens' complaints, public agency inspections, and existing data.
Include sources of information if possible.]
2 BACKGROUND
This section provides an overview of the location of, previous investigations of, and the apparent
problem(s) associated with the site or sampling area. [Provide a brief description of the site or sampling
area, including chemicals used on the site, site history, past and present operations or activities that
may have contributed to the suspected contamination, etc.]
2.1. Site or Sampling Area Description [Fill in the blanks.]
[Two maps of the area should be provided: the first (Figure 2.1), on a larger scale, should place the
area within its geographic region; the second (Figure 2.2), on a smaller scale, should mark the
sampling site or sampling areas within the local area. Additional maps may be provided, as necessary,
for clarity. Maps should include a North arrow, groundwater flow arrow (if appropriate), buildings or
former buildings, project area, area to be disturbed, etc. If longitude or latitude information is
available, such as from a Global Positioning System (GPS), provide it. Sampling locations can be
shown in Figure 2.2.]. Example language is as follows:
The site or sampling area occupies [e.g., hectares or square meters] in a
[e.g., urban, commercial, industrial, residential, agricultural, or undeveloped] area. The site or sampling
area is bordered on the north by , on the west by , on the south by
, and on the east by . The specific location of the site or sampling
area is shown in Figure 2.2.
The second paragraph (or set of paragraphs) should describe historic and current on-site structures
and should be consistent with what is presented in Figure 2.2.
2.2. Operational History
[As applicable, describe in as much detail possible (i.e., use several paragraphs) the past and present
activities at the site or sampling area. The discussion might include the following information:
A description of the owner(s) and/or operator(s) of the site or areas near the site, the
watershed of interest, the sampling area, etc. (present this information chronologically);
A description of past and current operations or activities that may have contributed to
suspected contamination of the sit;
A description of the processes involved in the operation(s) and the environmentally
detrimental substances, if any, used in the processes;
A description of any past and present waste management practices.
If a waste site, were/are hazardous wastes generated by one or more of the processes
described earlier? If so, what were/are they, how and where were/are they stored on the site
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or sampling area, and where were/are they ultimately disposed of? If an ecosystem, what
point and non-point sources which may have affected the river, stream, lake or watershed?]
2.3. Previous Investigations/Regulatory Involvement
[If applicable] [Summarize all previous sampling efforts at the site or sampling area. Include the
sampling date(s); name of the party(ies) that conducted the sampling; local, regional, or federal
government agency for which the sampling was conducted; a rationale for the sampling; the type of
media sampled (e.g., soil, sediment, water); laboratory methods that were used; and a discussion of
what is known about data quality and usability. The summaries should be presented in subsections
according to the media that were sampled (e.g., soil, water, etc.) and chronologically within each
medium. Attach reports or summary tables of results or include in appendices if necessary.]
2.4. Geological Information
[Groundwater sampling only][Provide a description of the hydrogeology of the area. Indicate the
direction of groundwater flow, if known.]
2.5. Environmental and/or Human Impact
[Discuss what is known about the possible and actual impacts of the possible environmental problem
on human health or the environment.]
3 PROJECT DATA QUALITY OBJECTIVES
Data Quality Objectives (DQOs) are qualitative and quantitative statements for establishing criteria for
data quality and for developing data collection designs.
3.1. Project Task and Problem Definition
[Describe the purpose of the environmental investigation in qualitative terms and how the data will
be used. Generally, this discussion will be brief and generic. Include all measurements to be made on
an analyte specific basis in whatever medium (soil, sediment, water, etc.) is to be sampled. This
discussion should relate to how this sampling effort will support the specific decisions described in
Section 3.2.]
3.2. Data Quality Objectives (DQOs)
Data quality objectives (DQOs) are quantitative and qualitative criteria that establish the level of
uncertainty associated with a set of data. This section should describe decisions to be made based on
the data and provide criteria on which these decisions will be made.
[Discuss Data Quality Objectives, action levels, and decisions to be made based on the data here.]
3.3. Data Quality Indicators (DQIs)
Data quality indicators (accuracy, precision, completeness, representativeness, comparability, and
method detection limits) refer to quality control criteria established for various aspects of data
gathering, sampling, or analysis activity. In defining DQIs specifically for the project, the level of
uncertainty associated with each measurement is defined. Definition of the different terms are provided
below:
Accuracy is the degree of agreement of a measurement with a known or true value. To
determine accuracy, a laboratory or field value is compared to a known or true concentration.
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Accuracy is determined by such QC indicators as: matrix spikes, surrogate spikes, laboratory
control samples (blind spikes) and performance samples.
Precision is the degree of mutual agreement between or among independent measurements of a
similar property (usually reported as a standard deviation [SD] or relative percent difference
[RPD]). This indicator relates to the analysis of duplicate laboratory or field samples. An RPD of
<20%for water and <35%for soil, depending upon the chemical being analyzed, is generally
acceptable. Typically field precision is assessed by co-located samples, field duplicates, or field
splits and laboratory precision is assessed using laboratory duplicates, matrix spike duplicates, or
laboratory control sample duplicates).
Completeness is expressed as percent of valid usable data actually obtained compared to the
amount that was expected. Due to a variety of circumstances, sometimes either not all samples
scheduled to be collected can be collected or else the data from samples cannot be used (for
example, samples lost, bottles broken, instrument failures, laboratory mistakes, etc.). The
minimum percent of completed analyses defined in this section depends on how much
information is needed for decision making. Generally, completeness goals rise the fewer the
number of samples taken per event or the more critical the data are for decision making. Goals
in the 75-95% range are typical.
Representativeness is the expression of the degree to which data accurately and precisely
represent a characteristic of an environmental condition or a population. It relates both to the
area of interest and to the method of taking the individual sample. The idea of
representativeness should be incorporated into discussions of sampling design.
Representativeness is best assured by a comprehensive statistical sampling design, but it is
recognized that is usually outside the scope of most one-time events. Most one time SAPs should
focus on issues related to judgmental sampling and why certain areas are included or not
included and the steps being taken to avoid either false positives or false negatives.
Comparability expresses the confidence with which one data set can be compared to another.
The use of methods from EPA or "Standard Methods" or from some other recognized sources
allows the data to be compared facilitating evaluation of trends or changes in a site, a river,
groundwater, etc. Comparability also refers to the reporting of data in comparable units so
direct comparisons are simplified (e.g., this avoids comparison ofmg/Lfor nitrate reported as
nitrogen to mg/L of nitrate reported as nitrate, or ppm vs. mg/L discussions).
Detection Limit(s) (usually expressed as method detection limits for all analytes or compounds of
interest for all analyses requested must be included in this section. These limits should be related
to any decisions that will be made as a result of the data collection effort. A critical element to
be addressed is how these limits relate to any regulatory or action levels that may apply.
DQI tables are available from the QA Office for most routinely ordered methods. These tables can be
attached to the SAP and referenced in this section. If an organization, its contractor, or its laboratory
wish to use different limits or acceptance criteria, the table should be modified accordingly. SOPs should
be included for methods not covered by the DQI tables or they can be submitted in lieu of the tables. Due
to resource constraints, generally only the DQI aspects of these SOPs will be evaluated.
[Provide or reference DQI tables here.]
3.4. Data Review and Validation
This section should discuss data review, including what organizations or individuals will be responsible
for what aspects of data review and what the review will include.
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[Discuss data review and data validation here including what organizations or individuals will be
responsible for what aspects of data review and what the review will include. This section should also
discuss how data that do not meet data quality objectives will be designated, flagged, or otherwise
handled. Possible corrective actions associated with the rejection of data, such as reanalysis,
resampling, no action but monitor the data more closely next quarter, etc., also need to be
addressed.]
3.5. Data Management
[Provide a list of the steps that will be taken to ensure that data are transferred accurately from
collection to analysis to reporting. Discuss the measures that will be taken to review the data
collection processes, including field notes or field data sheets; to obtain and review complete
laboratory reports; and to review the data entry system, including its use in reports. A checklist is
acceptable.]
3.6. Assessment Oversight
[Describe the procedures which will be used to implement the QA Program. This would include
oversight by the Quality Assurance Manager or the person assigned QA responsibilities. Indicate how
often a QA review of the different aspects of the project, including audits of field and laboratory
procedures, use of performance samples, review of laboratory and field data, etc., will take place.
Describe what authority the QA Manager or designated QA person has to ensure that identified field
and analytical problems will be corrected and the mechanism by which this will be accomplished.]
4 SAMPLING RATIONALE
For each sampling event, the SAP must describe the sampling locations, the media to be sampled, and
the analytes of concern at each location. A rationale should then be provided justifying these choices.
The following sections are subdivided on a media specific basis among soil, sediment, water, and
biological media. Other media should be added as needed. This section is crucial to plan approval and
should be closely related to previously discussed DQOs.
4.1. Soil Sampling
[Provide a general overview of the soil sampling event. Present a rationale for choosing each
sampling location at the site or sampling area and the depths at which the samples are to be taken, if
relevant. If decisions will be made in the field, provide details concerning the criteria that will be used
to make these decisions (i.e., the decision tree to be followed). List the analytes of concern at each
location and provide a rationale for why the specific chemical or group of chemicals (e.g., trace metals
etc.) were chosen. Include sampling locations in Figure 2.2 or equivalent.]
4.2. Sediment Sampling
[Provide a general overview of the sediment sampling event. Present a rationale for choosing each
sampling location at the site or sampling area and the depths or area of the river, stream or lake at
which the samples are to be taken, if relevant. If decisions will be made in the field, provide details
concerning the criteria that will be used to make these decisions (i.e., the decision tree to be
followed). List the analytes of concern at each location and provide a rationale for why the specific
chemical or group of chemicals (e.g., trace metals) were chosen. Include sampling locations in Figure
2.2 or equivalent.]
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4.3. Water Sampling
[Provide a general overview of the water sampling event. For groundwater, describe the wells to be
sampled or how the samples will be collected (e.g., hydro punch), including the depths at which the
samples are to be taken. For surface water, describe the depth and nature of the samples to be
collected (fast or slow moving water, stream traverse, etc.). Present a rationale for choosing each
sampling location or sampling area. If decisions will be made in the field, provide details concerning
the criteria that will be used to make these decisions (i.e., the decision tree to be followed). List the
analytes of concern at each location and provide a rationale for why the specific chemical or group of
chemicals (e.g., trace metals) were chosen. For microbiological samples, discuss the types of bacterial
samples being collected. Include sampling locations in Figure 2.2 or equivalent.]
4.4. Biological Sampling
[For each of the two types of events identified, provide a general overview of the biological sampling
event. Present a rationale for choosing each sampling location at the site or sampling area, including
the parameters of interest at each location. If decisions will be made in the field, provide details
concerning the criteria that will be used to make these decisions (i.e., the decision tree to be
followed).
4.4.1. Biological Samples for Chemical Analysis
[For sampling where flora or fauna will be analyzed for the presence of a chemical (e.g. fish collected
for tissue analysis), explain why the specific chemical or group of chemicals (e.g., metals,
organochlorine pesticides, etc.) is included. List the types of samples to be collected (e.g., fish, by
species or size, etc.) and explain how these will be representative. Include sampling locations in
Figure 2.2 or equivalent]
4.4.2. Biological Sample for Species Identification and Habitat Assessment
[If the purpose of the sampling is to collect insects or other invertebrates or to make a habitat
assessment, a rationale for the sampling to take place should be provided. For example: what species
are of interest and why?]
5 REQUEST FOR ANALYSES
This section should discuss analytical support for the project depending on several factors including the
analyses requested, areas of concern, turnaround times, available resources, available laboratories, etc.
If samples will be sent to more than one organization it should be clear which samples go to which
laboratory. Field analyses for pH, conductivity, turbidity, or other field tests should be discussed in the
sampling section. Field measurements in a mobile laboratory should be discussed here and
differentiated from samples to be sent to a fixed laboratory. Field screening tests (for example,
immunoassay tests) should be discussed in the sampling section, but the confirmation tests should be
discussed here and the totals included in the tables.
[Complete the following narrative subsection concerning the analyses for each matrix. In addition, fill
in Tables 5-1 through 5-5, as appropriate. Each table must be completed to list analytical parameters
for each type of sample. Include information on container types, sample volumes, preservatives,
special handling and analytical holding times for each parameter. Quality Control (QC) samples
(blanks, duplicates, splits, and laboratory QC samples, see Section 10 for description) should be
indicated in the column titled "Special Designation." The extra volume needed for laboratory QC
samples (for water samples only) should be noted on the table. The tables provided do not have to be
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used, but the critical information concerning the number of samples, matrix, analyses requested and
QC sample identification should be provided in some form. The selected analyses must be consistent
with earlier discussion concerning DQOs and analytes of concern. DQI information for the methods
should be discussed in Section 8 on quality control requirements.]
5.1. Analyses Narrative
[Fill in the blanks. Provide information for each analysis requested. Delete the information below as
appropriate. Include any special requests, such as fast turn-around time (2 weeks or less), specific QC
requirements, or modified sample preparation techniques in this section.]
5.2. Analytical Laboratory
[A QA Plan from the laboratory or SOPs for the methods to be performed must accompany the SAP.]
6 FIELD METHODS AND PROCEDURES
In the general introductory paragraph to this section, there should be a description of the methods and
procedures that will be used to accomplish the sampling goals, e.g., "...collect soil, sediment and water
samples." It should be noted that personnel involved in sampling must wear clean, disposable gloves of
the appropriate type. The sampling discussion should track the samples identified in Section 4.0 and
Table(s) 5-1, 5-2, 5-3, or 5-4. A general statement should be made that refers to the sections containing
information about sample tracking and shipping (Section 7). Provide a description of sampling
procedures. Example procedures are provided below, but the organization's own procedures can be used
instead. In that case, attach a copy of the applicable SOP.
6.1. Field Equipment
6.1.1. List of Equipment Needed
[List all the equipment that will be used in the field to collect samples, including decontamination
equipment, if required. Discuss the availability of back-up equipment and spare parts.]
6.1.2. Calibration of Field Equipment
[Describe the procedures by which field equipment is prepared for sampling, including calibration
standards used, frequency of calibration and maintenance routines. Indicate where the equipment
maintenance and calibration record(s) for the project will be kept.]
6.2. Field Screening
In some projects a combination of field screening using a less accurate or sensitive method may be used
in conjunction with confirmation samples analyzed in a fixed laboratory. This section should describe
these methods or reference attached SOPs. Analyses such as soil gas or immunoassay kits are two
examples.
[Describe any field screening methods to be used on the project here including how samples will be
collected, prepared, and analyzed in the field. Include in an appendix, as appropriate, SOPs covering
these methods. Confirmation of screening results should also be described. The role of the field
screening in decision making for the site should also be discussed here if it has not been covered
previously.]
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6.3. Soil
6.3.1 Surface Soil Sampling
[Use this subsection to describe the collection of surface soil samples that are to be collected within
15-30 centimeters of the ground surface. Specify the method (e.g., hand trowels) that will be used to
collect the samples and use the language below or reference the appropriate sections of a Soil
Sampling SOP.]
[If exact soil sampling locations will be determined in the field, this should be stated. The criteria that
will be used to determine sampling locations, such as accessibility, visible signs of potential
contamination (e.g., stained soils, location of former fuel storage tank, etc.), and topographical
features which may indicate the location of hazardous substance disposal (e.g., depressions that may
indicate a historic excavation) should be provided.]
Exact soil sampling locations will be determined in the field based on accessibility, visible signs of
potential contamination (e.g., stained soils), and topographical features which may indicate location of
hazardous substance disposal (e.g., depressions that may indicate a historic excavation). Soil sample
locations will be recorded in the field logbook as sampling is completed. A sketch of the sample location
will be entered into the logbook and any physical reference points will be labeled. If possible, distances
to the reference points will be given.
[If surface soil samples are to be analyzed for organic (non volatile compounds and other analytes, use
this paragraph; otherwise delete.]
Surface soil samples will be collected as grab samples (independent, discrete samples) from a depth of 0
to centimeters below ground surface (bgs). Surface soil samples will be collected using a stainless
steel hand trowel. Samples to be analyzed for volatile organic compounds will be collected first (see
below). Samples to be analyzed for [List all analytical methods for soil samples except for
volatile organic compounds] will be placed in a sample-dedicated disposable pail and homogenized with
a trowel. Material in the pail will be transferred with a trowel from the pail to the appropriate sample
containers. Sample containers will be filled to the top, taking care to prevent soil from remaining in the
lid threads prior to being closed to prevent potential contaminant migration to or from the sample.
Sample containers will be closed as soon as they are filled, chilled to 4°C if appropriate, and processed
for shipment to the laboratory.
[If surface soil samples are to be analyzed for volatile organic compounds (VOCs), use this paragraph;
otherwise delete.]
Surface soil samples for VOC analyses will be collected as grab samples (independent, discrete samples)
from a depth of 0 to [centimeters or meters] below ground surface (bgs). Surface soil samples will
be collected using a 5 gram Encore sampling device, and will be collected in triplicate. Samples will be
sealed using the Encore sampler and a zip lock bag or else transferred directly from the sampler into a
VOA vial containing either 10 mLs of methanol or sodium bisulfate solution. Sample containers will be
closed as soon as they are filled, chilled immediately to 4°C before wrapping them in bubble wrap, and
processed them for shipment to the laboratory.
[For surface soil samples which are not to be analyzed for volatile compounds, use this paragraph;
otherwise delete.]
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Surface soil samples will be collected as grab samples (independent, discrete samples) from a depth of 0
to [centimeters or meters] below ground surface (bgs). Surface soil samples will be collected using a
stainless steel hand trowel. Samples will be placed in a sample-dedicated disposable pail and
homogenized with a trowel. Material in the pail will be transferred with a trowel from the pail to the
appropriate sample containers. Sample containers will be filled to the top, taking care to prevent soil
from remaining in the lid threads prior to being closed to prevent potential contaminant migration to or
from the sample. Sample containers will be closed as soon as they are filled, chilled if appropriate, and
processed for shipment to the laboratory.
6.3.2 Subsurface Soil Sampling
[Use this subsection for subsurface soil samples that are to be collected 30 cm or more below the
surface. Specify the method (e.g., hand augers) that will be used to access the appropriate depth and
then state the depth at which samples will be collected and the method to be used to collect and then
transfer samples to the appropriate containers or reference the appropriate sections of a Soil
Sampling SOP. If SOPs are referenced, they should be included in an Appendix.]
[If exact soil sampling locations will be determined in the field, this should be stated. The criteria that
will be used to determine sampling locations, such as accessibility, visible signs of potential
contamination (e.g., stained soils), and topographical features which may indicate the location of
hazardous substance disposal (e.g., depressions that may indicate a historic excavation) should be
provided. There should also be a discussion concerning possible problems, such as subsurface refusal]
[Include this paragraph first if exact sampling locations are to be determined in the field; otherwise
delete.]
Exact soil sampling locations will be determined in the field based on accessibility, visible signs of
potential contamination (e.g., stained soils), and topographical features which may indicate location of
hazardous substance disposal (e.g., depressions that may indicate a historic excavation). Soil sample
locations will be recorded in the field logbook as sampling is completed. A sketch of the sample location
will be entered into the logbook and any physical reference points will be labeled. If possible, distances
to the reference points will be given.
[If subsurface soil samples are to be analyzed for volatile compounds, use this paragraph; otherwise
delete.]
Samples to be analyzed for volatile organic compounds will be collected first. Subsurface samples will
be collected by boring to the desired sample depth using
[whatever method is appropriate or available]. Once the desired sample depth is
reached, soil samples for VOC analyses will be collected as independent, discrete samples. Surface soil
samples will be collected using a 5 gram Encore sampling device, and will be collected in triplicate.
Samples will be sealed using the Encore sampler and a zip lock bag or else transferred directly from the
sampler into a VOA vial containing either 10 mLs of methanol or sodium bisulfate solution. Sample
containers will be closed as soon as they are filled, chilled immediately to 4°C before wrapping them in
bubble wrap, and processed for shipment to the laboratory. [If subsurface soil samples are being
collected for other than volatile organic compounds, use these paragraphs; otherwise delete.]
Subsurface samples will be collected by boring to the desired sample depth using
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[whatever method is appropriate or available]. Once the desired
sample depth is reached, the [hand- or power-operated device,
such as a shovel, hand auger, trier, hollow-stem auger or split-spoon sampler] will be inserted into the
hole and used to collect the sample. Samples will be transferred from the
[sampling device] to a sample-dedicated disposable pail and homogenized with a trowel.
Material in the pail will be transferred with a trowel from the pail to the appropriate sample containers.
Sample containers will be filled to the top taking care to prevent soil from remaining in the lid threads
prior to being sealed to prevent potential contaminant migration to or from the sample. After sample
containers are filled, they will be immediately sealed, chilled if appropriate, and processed for shipment
to the laboratory. [Include this as the final paragraph regardless of the analyses for subsurface soil
samples.] Excess set-aside soil from the above the sampled interval will then be repacked into the hole.
6.4. Sediment Sampling
[Use this subsection if sediment samples are to be collected. Specify the method (e.g., dredges) that
will be used to collect the samples and at what depth samples will be collected. Describe how
samples will be homogenized and the method to be used to transfer samples to the appropriate
containers. If a SOP will be followed rather than the language provided, the SOP should be referenced
and included in the appendix.]
[If exact sediment sampling locations will be determined in the field, this should be stated. Describe
where sediment samples will be collected, e.g., slow moving portions of streams, lake bottoms,
washes, etc.]
Exact sediment sampling locations will be determined in the field, based on
[Describe the criteria to be used to determine sampling
locations]. Care will be taken to obtain as representative a sample as possible. The sample will be taken
from areas likely to collect sediment deposits, such as slow moving portions of streams or from the
bottom of the lake at a minimum depth of .6 meters. Sediment samples will be collected from the well
bottom at a depth of inches using a pre-cleaned sampler.
[The final paragraph describes sample homogenization, especially important if the sample is to be
separated into solid and liquid phases, and container filling. Include this paragraph, or a modified form
of it, for all sediment sampling. It is assumed that sediment samples will not be analyzed for volatile
compounds. If sediment is to be analyzed for volatile organic compounds, the samples to be analyzed
for volatile compounds should not be homogenized, but rather transferred directly from the sampler
into the sample container. If feasible, an Encore sampling device should be used.]
Material in the sampler will be transferred to a sample-dedicated disposable pail and homogenized with
a trowel. Material from the pail will be transferred with a trowel from the bucket to the appropriate
sample containers. Sample containers will be filled to the top taking care to prevent soil from remaining
in the lid groves prior to being sealed in order to prevent potential contamination migration to or from
the sample containers. After sample containers are filled, they will be immediately sealed, chilled if
appropriate, and processed for shipment to the laboratory.
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6.5. Water Sampling
6.5.1 Surface Water Sampling
[Use this subsection if samples are to be collected in rivers, streams, lakes and reservoirs, or from
standing water in runoff collection ponds, gullies, drainage ditches, etc. Describe the sampling
procedure, including the type of sample (grab or composite - see definitions below), sample bottle
preparation, and project-specific directions for taking the sample. State whether samples will be
collected for chemical and/or microbiological analyses. Alternatively, reference the appropriate
sections of attached SOPs.]
Grab: Samples will be collected at one time from one location. The sample should be taken from
flowing, not stagnant water, and the sampler should be facing upstream in the middle of the stream.
Samples will be collected by hand or with a sample bottle holder. For samples taken at a single depth,
the bottle should be uncapped and the cap protected from contamination. The bottle should be
plunged into the water mouth down and filled 15 to 30 centimeters below the surface of the water. If it
is important to take samples at depths, special samplers (e.g., Niskin or Kemmerer Depth Samplers) may
be required. After filling the bottle(s), pour out some sample leaving a headspace of 2.5-5cm. For
microbiological samples, bottles and caps must be sterile. If sampling of chlorinated water is
anticipated, sodium thiosulfate at a concentration of 0.1 mL of a 10% solution for each 125 mL (4 oz) of
sample volume must be put into the bottle before it is sterilized. Time Composite: Samples are collected
over a period of time, usually 24 hours. If a composite sample is required, a flow- and time-proportional
automatic sampler should be positioned to take samples at the appropriate location in a manner such
that the sample can be held at 4oC for the duration of the sampling.
Spatial Composite: Samples are collected from different representative positions in the water body and
combined in equal amounts. A Churn Splitter or equivalent device will be used to ensure that the
sample is homogeneously mixed before the sample bottles are filled. Volatile organic compound
samples will be collected as discrete samples and not composited. [If exact surface water sample
locations will be determined in the field, this should be stated. Describe the criteria that will be used to
determine where surface water samples will be collected.]
6.5.2 Groundwater Sampling
[This subsection contains procedures for water level measurements, well purging, and well sampling.
Relevant procedures should be described under this heading with any necessary site-specific
modifications. Alternatively, reference appropriate SOP(s).]
6.5.2.1. Water-Level Measurements
[The following language may be used as is or modified to meet project needs.]
All field meters will be calibrated according to manufacturer's guidelines and specifications before and
after every day of field use. Field meter probes will be decontaminated before and after use at each
well. If well heads are accessible, all wells will be sounded for depth to water from top of casing and
total well depth prior to purging. An electronic sounder, accurate to the nearest +/- cm, will be used to
measure depth to water in each well. When using an electronic sounder, the probe is lowered down the
casing to the top of the water column; the graduated markings on the probe wire or tape are used to
measure the depth to water from the surveyed point on the rim of the well casing. Typically, the
measuring device emits a constant tone when the probe is submerged in standing water and most
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electronic water level sounders have a visual indicator consisting of a small light bulb or diode that turns
on when the probe encounters water. Total well depth will be sounded from the surveyed top of casing
by lowering the weighted probe to the bottom of the well. The weighted probe will sink into silt, if
present, at the bottom of the well screen. Total well depths will be measured by lowering the weighted
probe to the bottom of the well and recording the depth to the nearest centimeter. Water-level
sounding equipment will be decontaminated before and after use in each well. Water levels will be
measured in wells which have the least amount of known contamination first. Wells with known or
suspected contamination will be measured last.
6.5.2.2. Purging
[Describe the method that will be used for well purging (e.g., dedicated well pump, bailer, hand
pump). Reference the appropriate sections in the Ground Water SOP and state in which Appendix the
SOP is located.]
[VERSION A]
All wells will be purged prior to sampling. If the well casing volume is known, a minimum of three casing
volumes of water will be purged using the dedicated well pump.
[VERSION B]
All wells will be purged prior to sampling. If the well casing volume is known, a minimum of three casing
volumes of water will be purged using a hand pump, submersible pump, or bailer, depending on the
diameter and configuration of the well. When a submersible pump is used for purging, clean flexible
Teflon tubes will be used for groundwater extraction. All tubes will be decontaminated before use in
each well. Pumps will be placed 0.66 to 1 meter from the bottom of the well to permit reasonable
drawdown while preventing cascading conditions.
[VERSION C]
All wells will be purged prior to sampling. If the well casing volume is known, a minimum of three casing
volumes of water will be purged using the dedicated well pump, if present, or a bailer, hand pump, or
submersible pump depending on the diameter and configuration of the well. When a submersible pump
is used for purging, clean flexible Teflon tubes will be used for groundwater extraction. All tubes will be
decontaminated before use in each well. Pumps will be placed 0.66 to 1 meter from the bottom of the
well to permit reasonable draw down while preventing cascading conditions.
[ALL VERSIONS - to be included in all sample plans]
Water will be collected into a measured bucket to record the purge volume. Casing volumes will be
calculated based on total well depth, standing water level, and casing diameter.
It is most important to obtain a representative sample from the well. Stable water quality parameter
(temperature, pH and specific conductance) measurements indicate representative sampling is
obtainable. Water quality is considered stable if for three consecutive readings:
Temperature range is no more than +1/C;
pH varies by no more than 0.2 pH units;
Specific conductance readings are within 10% of the average.
The water in which measurements were taken will not be used to fill sample bottles. If the well casing
volume is known, measurements will be taken before the start of purging, in the middle of purging, and
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at the end of purging each casing volume. If the well casing volume is NOT known, measurements will
be taken every 2.5 minutes after flow starts. If water quality parameters are not stable after 5 casing
volumes or 30 minutes, purging will cease, which will be noted in the logbook, and ground water
samples will be taken. The depth to water, water quality measurements and purge volumes will be
entered in the logbook. If a well dewaters during purging and three casing volumes are not purged, that
well will be allowed to recharge up to 80% of the static water column and dewatered once more. After
water levels have recharged to 80% of the static water column, groundwater samples will be collected.
6.5.2.3. Well Sampling
[Describe the method that will be used to collect samples from wells. (This will probably be the same
method as was used to purge the wells.) Specify the sequence for sample collection (e.g., bottles for
volatile analysis will be filled first, followed by semi-volatiles, etc.). State whether samples for metals
analysis will be filtered or unfiltered. Include the specific conditions, such as turbidity, that will
require samples to be filtered. Alternatively, reference the appropriate sections in the Ground Water
SOP and state in which Appendix the SOP is located.]
ALL VERSIONS - to be included in all sample plans]
At each sampling location, all bottles designated for a particular analysis (e.g., trace metals) will be filled
sequentially before bottles designated for the next analysis are filled. If a duplicate sample is to be
collected at this location, all bottles designated for a particular analysis for both sample designations will
be filled sequentially before bottles for another analysis are filled. Groundwater samples will be
transferred from the tap directly into the appropriate sample containers with preservative, if required,
chilled if appropriate, and processed for shipment to the laboratory. When transferring samples, care
will be taken not to touch the tap to the sample container. [If samples are to be collected for volatiles
analysis, the following paragraph should be added; otherwise delete.]
Samples for volatile organic compound analyses will be collected using a low flow sampling device. A
[specify type of pump] pump will be used at a flow rate of . Vials for volatile organic compound
analysis will be filled first to minimize the effect of aeration on the water sample. A test vial will be filled
with sample, preserved with hydrochloric acid (HCI) and tested with pH paper to determine the amount
of preservative needed to lower the pH to less than 2. The appropriate amount of HCI will then be
added to the sample vials prior to the addition of the sample. The vials will be filled directly from the
tap and capped. The vial will be inverted and checked for air bubbles to ensure zero headspace. If a
bubble appears, the vial will be discarded and a new sample will be collected. [If some samples for
metals (or other) analysis are to be filtered, depending upon sample turbidity, the following paragraph
should be added; otherwise delete.]
After well purging and prior to collecting groundwater samples for metals analyses, the turbidity of the
groundwater extracted from each well will be measured using a portable turbidity meter. A small
quantity of groundwater will be collected from the well using the tap and a small amount of water will
be transferred to a disposable vial and a turbidity measurement will be taken. The results of the
turbidity measurement will be recorded in the field logbook. The water used to measure turbidity will
be discarded after use. If the turbidity of the groundwater from a well is above 5 Nephelometric
Turbidity Units (NTUs), both a filtered and unfiltered sample will be collected. A [specify size]-micron
filter will be used to remove larger particles that have been entrained in the water sample. A sample-
dedicated Teflon tube will be attached to the tap closest to the well head. The filter will be attached to
the outlet of the Teflon tube. A clean, unused filter will be used for each filtered sample collected.
Groundwater samples will be transferred from the filter directly into the appropriate sample containers
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with a preservative and processed for shipment to the laboratory. When transferring samples, care will
be taken not to touch the filter to the sample container. After the filtered sample has been collected,
the Teflon tube and filter will be removed and an unfiltered sample will be collected. A sample number
appended with an "Fl" will represent a sample filtered with a 5-micron filter.
[If samples are to be filtered for metals (or other) analysis regardless of sample turbidity, the
following paragraph should be added; otherwise delete.]
Samples designated for metals analysis will be filtered. A 5-micron filter will be used to remove larger
particles that have been entrained in the water sample. A sample-dedicated Teflon tube will be
attached to the tap closest to the well head. The filter will be attached to the outlet of the Teflon tube.
A clean, unused filter will be used for each filtered sample collected. Groundwater samples will be
transferred from the filter directly into the appropriate sample containers to which preservative has
been added and processed for shipment to the laboratory. When transferring samples, care will be
taken not to touch the filter to the sample container. After the filtered sample has been collected, the
Teflon tube and filter will be removed and an unfiltered sample will be collected. A sample number
appended with an "Fl" will represent a sample filtered with a 5-micron filter.
6.6. Biological Sampling
For the purpose of this guidance, biological sampling falls into two categories. Other types of biological
sampling events should be discussed with the QA Office to determine what type of planning document is
needed. The two types addressed in this guidance are biological samples being collected for chemical
analysis and biological samples for the purpose of assessing species diversity. If the latter type of
sampling is planned, a quality assurance project plan may be a more appropriate document. Samples
collected for microbiological analyses should be discussed under water sampling.
6.6.1 Biological Sampling for Chemical Analysis
[The two most common types of biological samples being collected for chemical analysis are fish and
foliage samples. The following paragraphs are suggested, but field circumstances may dictate
alternative collection procedures; if no biological samples will be collected, put "not applicable" by
these sections. If a SOP will be followed, include it in the appendix.]
6.6.1.1. Fish Sam pies
[Use if collecting fish, otherwise delete. Alternatively, reference appropriate SOPs.] Fish will be collected
using [name method; nets, electro-shocking, lines, etc.]. Three fish of each
type or species [indicate type of fish, e. g., trout, catfish, etc.] will be
collected. Efforts will be made to collect fish of approximately the same size and maturity by checking
to make sure that lengths and weights do not differ by more than 20%. Once collected the
[indicate whether whole fish or filets] will be frozen, wrapped in
aluminum foil and plastic bags and sent to a laboratory.]
[If samples are to be composited by the laboratory, also indicate that in this section.]
6.6.1.2. Foliage Samples
[Use if collecting foliage samples, otherwise delete. This section may require considerable
modification because of the potential diversity of projects involving plants sampling.]
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A representative foliage sample will be collected from the target area. It is recommended that a
statistical approach be used, if possible. The following plants will be collected: ,
, and . These plants are being collected because they are most likely
affected by chemicals used in the area. Only foliage showing visible signs of stress or damage will be
collected. Stems and twigs will be discarded; leaves only will be collected. The same type of leaf
material [Describe material, mature leaves, young shoots, etc.] will be obtained from each plant type.
Provided contamination is uniform, material will be composited from several plants to yield a total of
about [specify quantity] pound(s) of material. Control samples will also be collected from a nearby
unaffected area [Describe area], if available. Latex gloves will be worn during the collection of all
samples. Samples will be stored in [describe container, plastic bags, bottles, etc.] and brought to the
laboratory as soon as possible to prevent sample deterioration.
6.6.2 Biological Sampling for Species Assessment
[Describe the collection of insects, other invertebrates, or other types of biological samples here.
Reference or attach appropriate protocols to support the sampling effort.]
6.7. Decontamination Procedures
[Specify the decontamination procedures that will be followed if non-dedicated sampling equipment
is used. Alternatively, reference the appropriate sections in the organization's Decontamination
Standard Operating Procedure.]
The decontamination procedures that will be followed are in accordance with approved procedures.
Decontamination of sampling equipment must be conducted consistently as to assure the quality of
samples collected. All equipment that comes into contact with potentially contaminated soil or water
will be decontaminated. Disposable equipment intended for one-time use will not be decontaminated,
but will be packaged for appropriate disposal. Decontamination will occur prior to and after each use of
a piece of equipment. All sampling devices used, including trowels and augers, will be steam-cleaned or
decontaminated according to the following decontamination procedures:
[Use the following decontamination procedures, if samples are collected for organic analyses only;
otherwise delete.]
Non-phosphate detergent and tap water wash, using a brush if necessary.
Tap-water rinse.
Deionized/distilled water rinse.
Pesticide-grade solvent (reagent grade hexane) rinse in a decontamination bucket.
Deionized/distilled water rinse (twice).
[Use the following decontamination procedures if samples are collected for inorganic (metals)
analyses only, otherwise delete.]
Non-phosphate detergent and tap water wash, using a brush if necessary.
Tap-water rinse.
0.1 N nitric acid rinse.
Deionized/distilled water rinse (twice).
[Use the following decontamination procedures if samples are collected for both organic and
inorganic analyses, otherwise delete.]
Non-phosphate detergent and tap water wash, using a brush if necessary.
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Tap-water rinse.
0.1 N nitric acid rinse.
Deionized/distilled water rinse.
Pesticide-grade solvent (reagent grade hexane) rinse in a decontamination bucket.
Deionized/distilled water rinse (twice).
Equipment will be decontaminated in a predesignated area on pallets or plastic sheeting, and clean
bulky equipment will be stored on plastic sheeting in uncontaminated areas. Cleaned small equipment
will be stored in plastic bags. Materials to be stored more than a few hours will also be covered.
[NOTE: A different decontamination procedure may be used; but if so, a rationale for using the
different approach should be provided.]
7 SAMPLE CONTAINERS. PRESERVATION AND STORAGE
[This section requires a reference to the types of bottles to be used, preparation and preservatives to
be added. The organization responsible for adding preservatives should be named. If the information
is provided in the request for analyses tables, reference them in the appropriate section below.]
The number of sample containers, volumes, and materials are listed in Section 5.0. The containers are
pre-cleaned and will not be rinsed prior to sample collection. Preservatives, if required, will be added by
[name of agency/organization doing the sampling] to the containers prior to shipment of the
samples to the laboratory.
7.1. Soil Samples
[If soil samples are to be collected, specify the analyses that will be performed. Use the language
below or reference the appropriate sections in the Preservation SOP and state in which Appendix the
SOP is located.]
[Include this subsection if collecting soil samples; otherwise delete.]
[If requested analyses include analyses other than volatile organic compounds or metals, include this
paragraph; otherwise delete.]
Soil samples for [Include all requested analysis(es), e.g., Pesticides, Semi-volatile
Organic Compounds] will be homogenized and transferred from the sample-dedicated homogenization
pail into 8-ounce (oz), wide-mouth glass jars using a trowel. For each sample, one 8-oz wide-mouth
glass jar will be collected for each laboratory. Alternatively, sample will be retained in the brass sleeve
in which collected until sample preparation begins. The samples will be chilled to 4/C immediately upon
collection.
[If requested analyses include volatile organic compounds, include this paragraph; otherwise delete.]
VOLATILE ORGANIC COMPOUNDS. Soil samples to be analyzed for volatile organic compounds will be
stored in their sealed Encore samplers for no more than two days prior to analysis. Frozen Encore
sampler samples will be stored for no more than 4 days prior to analysis. If samples are preserved by
ejecting into either methanol or sodium bisulfate solution the holding time is two weeks. Preserved
samples will be chilled to 4/C immediately upon collection.
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[If requested analyses include metals, include this paragraph; otherwise delete.]
METALS. Surface soil samples to be analyzed for metals will be homogenized and transferred from the
sample-dedicated homogenization pail into 8-oz, wide-mouth glass jars. For each sample, one 8-oz glass
jar will be collected for each laboratory. Samples will not be chilled. Subsurface samples will be
retained in their original brass sleeves or other container unless transferred to bottles.
7.2. Sediment Samples
[If sediment samples are to be collected, specify the analyses that will be performed. Use the
language below or reference the appropriate sections in a Preservation SOP and state in which
Appendix the SOP is located.]
[If requested analyses include analyses other than volatile organic compounds or metals, include this
paragraph; otherwise delete.]
[Include all requested analysis(es), e.g., Pesticides, Semi-volatile Organic Compounds].
Sediment samples will be homogenized and transferred from the sample-dedicated homogenization pail
into 8-oz wide-mouth glass jars. For each sample, one 8-oz glass jar will be collected for each
laboratory.
The samples will be chilled to 4/C immediately upon collection.
[If requested analyses include volatile organic compounds, include this paragraph; otherwise delete.]
VOLATILE ORGANIC COMPOUNDS. Sediment samples to be analyzed for volatile organic compounds
will be stored in their sealed Encore samplers for no more than two days prior to analysis. Frozen
Encore sampler samples will be stored for no more than 4 days prior to analysis. If samples are
preserved by ejecting into either methanol or sodium bisulfate solution the holding time is two weeks.
Preserved samples will be chilled to 4/C immediately upon collection.
[If requested analyses include metals, include this paragraph; otherwise delete.]
METALS. Sediment samples, with rocks and debris removed, which are to be analyzed for metals will be
homogenized and transferred from the sample-dedicated homogenization pail into 8-oz, wide-mouth
glass jars. For each sample, one 8-oz glass jar will be collected for each laboratory. Samples will not be
chilled.
7.3. Water Samples
[If water samples are to be collected, specify the analyses that will be performed. Use the language
below or else reference the appropriate sections in a Preservation SOP and state in which Appendix
the SOP is located.]
[Include this subsection if collecting water samples; otherwise delete.]
Depending on the type of analysis (organic or inorganic) requested, and any other project-specific
analytical requirements, sample bottles should be plastic (inorganics) or glass (organics), pre-cleaned
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(general decontamination procedures) or low-detection level pre-cleaned (extensive decontamination
procedures).
[Describe the type of bottles that will be used for the project, including the cleaning procedures that
will be followed to prepare the bottles for sampling.]
[If requested analyses do not require preservation, include this paragraph; otherwise delete. A
separate paragraph should be included for each bottle type.]
[Include all requested analysis(es), e.g., Anions, Pesticides, Semi-volatile Organic
Compounds]. Low concentration water samples to be analyzed for [Specify
analysis(es), e.g., Semi-volatile Organic Compounds] will be collected in [Specify bottle
type, e. g., 1-liter (L) amber glass bottles]. No preservative is required for these samples. The samples
will be chilled to 4/C immediately upon collection. Two bottles of each water sample are required for
each laboratory.
[If requested analyses include volatile organic compounds, include this paragraph; otherwise delete.]
VOLATILE ORGANIC COMPOUNDS. Low concentration water samples to be analyzed for volatile organic
compounds will be collected in 40-mL glass vials. 1:1 hydrochloric acid (HCI) will be added to the vial
prior to sample collection. During purging, the pH will be measured using a pH meter to test at least one
vial at each sample location to ensure sufficient acid is present to result in a pH of less than 2. The
tested vial will be discarded. If the pH is greater than 2, additional HCI will be added to the sample vials.
Another vial will be pH tested to ensure the pH is less than 2. The tested vial will be discarded. The vials
will be filled so that there is no headspace. The samples will be chilled to 4/C immediately upon
collection. Three vials of each water sample are required for each laboratory.
[If requested analyses include metals, include this paragraph; otherwise delete.]
METALS. Water samples collected for metals analysis will be collected in 1L polyethylene bottles. The
samples will be preserved by adding nitric acid (HNO3) to the sample bottle. The bottle will be capped
and lightly shaken to mix in the acid. A small quantity of sample will be poured into the bottle cap
where the pH will be measured using pH paper. The pH must be <2. The sample in the cap will be
discarded, and the pH of the sample will be adjusted further if necessary. The samples will be chilled to
4/C immediately upon collection. One bottle of each water sample is required for each laboratory.
GENERAL CHEMISTRY (WATER QUALITY) PARAMETERS. Water samples collected for water quality
analysis [Specify what parameters are included. Examples include (but are not limited to) anions
(nitrate-N, nitrite-N, sulfate, phosphate), total phosphorus, ammonia-N, total dissolved solids, total
suspended solids, alkalinity (may include carbonate, and/or bicarbonate), hardness, cyanide, MBAS
(methylene blue active substances), etc.], will be collected in [Specify size of container] polyethylene
bottles. The [Specify analysis] samples will be preserved by adding [Describe preservative appropriate
to each sample type] to the sample bottle. The [Specify analysis] samples will not be preserved. If
preservative is added, the bottle will be capped and lightly shaken to mix in the preservative. Where the
preservative affects the pH, a small quantity of sample will be poured into the bottle cap where the pH
will be measured using pH paper. The pH must be within the appropriate range. The sample in the cap
will be discarded, and the pH of the sample will be adjusted further if necessary. Samples will be chilled
to 4/C immediately upon collection. Samples from each location that require the same preservative will
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be placed in the same bottle if being analyzed by the same laboratory.
7.4. Biological Samples
[If biological samples are to be collected, specify the analyses that will be performed. Use the
language below or reference the appropriate sections in a Preservation SOP and state in which
Appendix the SOP is located.]
7.4.1. Fish Samples
Fish (whole or fillets) will be wrapped in aluminum foil, labeled, and placed in individual zip lock bags.
The samples will be frozen as quickly as possible and shipped using dry ice to maintain the frozen state.
7.4.2. Foliage Samples
[Describe the containers that will be used for the project. Usually foliage samples are collected in
clean zip lock bags, but bottles or other containers can be used. Paper bags are not recommended.]
For foliage samples, samples will be collected in a large zip Lock bag. A self adhesive label will be placed
on each bag and the top sealed with a custody seal
7.4.3. Biological Sampling for Species Assessment
[Describe the containers in which macroinvertebrates, insects and other biological samples will be
stored. If a fixation liquid will be used, it should be described as well. This section should also discuss
any special handling procedures which must be followed to minimize damage to the specimens.]
8 DISPOSAL OF RESIDUAL MATERIALS
[This section should describe the type(s) of investigation- derived wastes (IDW) that will be generated
during this sampling event. IDW may not be generated in all sampling events, in which case this
section would not apply. Use the language below or reference the appropriate sections in a Disposal
of Residual Materials SOP and state in which Appendix the SOP is located. Depending upon site-
specific conditions and applicable federal, state, and local regulations, other provisions for IDW
disposal may be required. If any analyses of IDW are required, these should be discussed. If IDW are
to be placed in drums, labeling for the drums should be discussed in this section.]
In the process of collecting environmental samples at the [site or sampling area name]
during the site investigation (SI) [or name of other investigation]; the [name of your
organization/agency] sampling team will generate different types of potentially contaminated IDW that
include the following:
Used personal protective equipment (PPE).
Disposable sampling equipment.
Decontamination fluids [Include this bullet when sampling soils; otherwise delete.]
Soil cuttings from soil borings [Include this bullet when sampling groundwater; otherwise
delete.]
Purged groundwater and excess groundwater collected for sample container filling.
[The following bullet is generally appropriate for site or sampling areas with low levels of
contamination or for routine monitoring. If higher levels of contamination exist at the site or
sampling area, other disposal methods (such as the drumming of wastes) should be used to dispose of
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used PPE and disposable sampling equipment.]
Used PPE and disposable equipment will be double bagged and placed in a municipal refuse
dumpster. These wastes are not considered hazardous and can be sent to a municipal landfill.
Any PPE and disposable equipment that is to be disposed of which can still be reused will be
rendered inoperable before disposal in the refuse dumpster. [Include this bullet if sampling for
both metals and organics; otherwise delete.]
Decontamination fluids that will be generated in the sampling event will consist of dilute nitric
acid, pesticide-grade solvent, deionized water, residual contaminants, and water with non-
phosphate detergent. The volume and concentration of the decontamination fluid will be
sufficiently low to allow disposal at the site or sampling area. The water (and water with
detergent) will be poured onto the ground or into a storm drain. Pesticide-grade solvents will
be allowed to evaporate from the decontamination bucket. The nitric acid will be diluted
and/or neutralized with sodium hydroxide and tested with pH paper before pouring onto the
ground or into a storm drain. [Include this bullet if sampling for metals but not organics;
otherwise delete.]
Decontamination fluids that will be generated in the sampling event will consist of nitric acid,
deionized water, residual contaminants, and water with non-phosphate detergent. The volume
and concentration of the decontamination fluid will be sufficiently low to allow disposal at the
site or sampling area. The water (and water with detergent) will be poured onto the ground or
into a storm drain. The nitric acid will be diluted and/or neutralized with sodium hydroxide and
tested with pH paper before pouring onto the ground or into a storm drain. [Include this bullet
if sampling for organics but not metals; otherwise delete.]
Decontamination fluids that will be generated in the sampling event will consist of pesticide-
grade solvent, deionized water, residual contaminants, and water with non-phosphate
detergent. The volume and concentration of the decontamination fluid will be sufficiently low
to allow disposal at the site or sampling area. The water (and water with detergent) will be
poured onto the ground or into a storm drain. Pesticide-grade solvents will be allowed to
evaporate from the decontamination bucket. [Include this bullet if sampling soils; otherwise
delete.]
Soil cuttings generated during the subsurface sampling will be disposed of in an appropriate
manner. [Include this bullet if sampling groundwater; otherwise delete.]
Purged groundwater will be [depending upon the degree of groundwater
contamination, site-specific conditions, and applicable federal, state, and local regulations,
disposal methods will vary. Disposal methods can also vary for purge water from different wells
sampled during the same sampling event.]
9 SAMPLE DOCUMENTATION AND SHIPMENT
9.1. Field Notes
This section should discuss record keeping in the field. This may be through a combination of logbooks,
preprinted forms, photographs, or other documentation. Information to be maintained is provided
below.
9.1.1 Field Logbooks
[Describe how field logbooks will be used and maintained.]
Use field logbooks to document where, when, how, and from whom any vital project information was
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obtained. Logbook entries should be complete and accurate enough to permit reconstruction of field
activities. Maintain a separate logbook for each sampling event or project. Logbooks should have
consecutively numbered pages. All entries should be legible, written in black ink, and signed by the
individual making the entries. Use factual, objective language.
At a minimum, the following information will be recorded during the collection of each sample:
[Edit this list as relevant]
Sample location and description;
Site or sampling area sketch showing sample location and measured distances;
Sampler's name(s);
Date and time of sample collection;
Designation of sample as composite or grab;
Type of sample (soil, sediment or water);
Type of sampling equipment used;
Field instrument readings and calibration;
Field observations and details related to analysis or integrity of samples (e.g., weather
conditions, noticeable odors, colors, etc.);
Preliminary sample descriptions (e.g., for soils: clay loam, very wet; for water: clear water with
strong ammonia-like odor);
Sample preservation;
Lot numbers of the sample containers, sample identification numbers and any explanatory
codes, and chain-of-custody form numbers;
Shipping arrangements (overnight air bill number);
Name(s) of recipient laboratory(ies).
In addition to the sampling information, the following specific information will also be recorded in the
field logbook for each day of sampling: [Edit this list as relevant.]
Team members and their responsibilities;
Time of arrival/entry on site and time of site departure;
Other personnel on site;
Summary of any meetings or discussions with contractor, or federal agency personnel;
Deviations from sampling plans, site safety plans, and QAPP procedures;
Changes in personnel and responsibilities with reasons for the changes;
Levels of safety protection;
Calibration readings for any equipment used and equipment model and serial number.
[A checklist of the field notes, following the suggestions above, using only those that are appropriate,
should be developed and included in project field notes.]
9.1.2 Photographs
[If photographs will be taken, the following language may be used as is or modified as appropriate.]
Photographs will be taken at the sampling locations and at other areas of interest on site or sampling
area. They will serve to verify information entered in the field logbook. For each photograph taken, the
following information will be written in the logbook or recorded in a separate field photography log:
Time, date, location, and weather conditions;
Description of the subject photographed;
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Name of person taking the photograph.
9.2. Labeling
[The following paragraph provides a generic explanation and description of the use of labels. It may
be incorporated as is, if appropriate, or modified to meet any project-specific conditions.]
All samples collected will be labeled in a clear and precise way for proper identification in the field and
for tracking in the laboratory. A copy of the sample label is included in Appendix . The samples will
have preassigned, identifiable, and unique numbers. At a minimum, the sample labels will contain the
following information: station location, date of collection, analytical parameter(s), and method of
preservation. Every sample, including samples collected from a single location but going to separate
laboratories, will be assigned a unique sample number.
9.3. Sample Chain-Of-Custody Forms and Custody Seals
[The following paragraphs provide a generic explanation and description of the use of chain-of-
custody forms and custody seals. They may be incorporated as is, if they are appropriate, or modified
to meet any project-specific conditions.]
Organic and inorganic chain-of-custody record/traffic report forms are used to document sample
collection and shipment to laboratories for analysis. All sample shipments for analyses will be
accompanied by a chain-of-custody record. A copy of the form is found in Appendix. Form(s) will be
completed and sent with the samples for each laboratory and each shipment (i.e., each day). If multiple
coolers are sent to a single laboratory on a single day, form(s) will be completed and sent with the
samples for each cooler.
The chain-of-custody form will identify the contents of each shipment and maintain the custodial
integrity of the samples. Generally, a sample is considered to be in someone's custody if it is either in
someone's physical possession, in someone's view, locked up, or kept in a secured area that is restricted
to authorized personnel. Until the samples are shipped, the custody of the samples will be the
responsibility of [name of agency/ organization conducting sampling]. The sampling team leader
or designee will sign the chain-of-custody form in the "relinquished by" box and note date, time, and air
bill number. The sample numbers for all reference samples, laboratory QC samples, and duplicates will
be documented on this form (see Section 10.0). A photocopy will be made for the 's [name of
agency/ organization conducting sampling] master files.
A self-adhesive custody seal will be placed across the lid of each sample. A copy of the seal is found in
Appendix _. For VOC samples, the seal will be wrapped around the cap. The shipping containers in
which samples are stored (usually a sturdy picnic cooler or ice chest) will be sealed with self-adhesive
custody seals any time they are not in someone's possession or view before shipping. All custody seals
will be signed and dated.
9.4. Packaging and Shipment
[The following paragraphs provide a generic explanation and description of how to pack and ship
samples. They may be incorporated as is, if appropriate, or modified to meet any project-specific
conditions.]
All sample containers will be placed in a strong-outside shipping container (a steel-belted cooler). The
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following outlines the packaging procedures that will be followed for low concentration samples.
1. When ice is used, pack it in zip-locked, double plastic bags. Seal the drain plug of the cooler with
fiberglass tape to prevent melting ice from leaking out of the cooler.
2. The bottom of the cooler should be lined with bubble wrap to prevent breakage during
shipment.
3. Check screw caps for tightness and, if not full, mark the sample volume level of liquid samples
on the outside of the sample bottles with indelible ink.
4. Secure bottle/container tops with clear tape and custody seal all container tops.
5. Affix sample labels onto the containers with clear tape.
6. Wrap all glass sample containers in bubble wrap to prevent breakage.
7. Seal all sample containers in heavy duty plastic zip-lock bags. Write the sample numbers on the
outside of the plastic bags with indelible ink.
8. Place samples in a sturdy cooler(s) lined with a large plastic trash bag. Enclose the appropriate
COC(s) in a zip-lock plastic bag affixed to the underside of the cooler lid.
9. Fill empty space in the cooler with bubble wrap or Styrofoam peanuts to prevent movement and
breakage during shipment.
10. Ice used to cool samples will be double sealed in two zip lock plastic bags and placed on top and
around the samples to chill them to the correct temperature.
11. Each ice chest will be securely taped shut with fiberglass strapping tape, and custody seals will
be affixed to the front, right and back of each cooler.
Records will be maintained by the [organization]^ sample custodian of the following information:
Sampling contractor's name (if not the organization itself);
Name and location of the site or sampling area;
Case or Regional Analytical Program (RAP) number;
Total number(s) by estimated concentration and matrix of samples shipped to each laboratory;
Carrier, air bill number(s), method of shipment (priority next day);
Shipment date and when it should be received by lab;
Irregularities or anticipated problems associated with the samples;
Whether additional samples will be shipped or if this is the last shipment.
10 QUALITY CONTROL
This section should discuss the quality control samples that are being collected to support the sampling
activity. This includes field QC samples, confirmation samples, background samples, laboratory QC
samples, and split samples. Wherever possible, the locations at which the samples will be collected
should be identified and a rationale provided for the choice of location. Frequency of collection should be
discussed. All samples, except laboratory QC samples, should be sent to the laboratory blind, wherever
possible. Laboratory QC samples should be identified and additional sample (e.g., a double volume)
collected for that purpose.
10.1. Field Quality Control Samples
Field quality control samples are intended to help evaluate conditions resulting from field activities and
are intended to accomplish two primary goals, assessment of field contamination and assessment of
sampling variability. The former looks for substances introduced in the field due to environmental or
sampling equipment and is assessed using blanks of different types. The latter includes variability due to
sampling technique and instrument performance as well as variability possibly caused by the
heterogeneity of the matrix being sampled and is assessed using replicate sample collection. The
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following sections cover field QC.
10.1.1 Assessment of Field Contamination (Blanks)
Field contamination is usually assessed through the collection of different types of blanks. Equipment
blanks are obtained by passing distilled or deionized water, as appropriate, over or through the
decontaminated equipment used for sampling. They provide the best overall means of assessing
contamination arising from the equipment, ambient conditions, sample containers, transit, and the
laboratory. Field blanks are sample containers filled in the field. They help assess contamination from
ambient conditions, sample containers, transit, and the laboratory. Trip blanks are prepared by the
laboratory and shipped to and from the field. They help assess contamination from shipping and the
laboratory and are for volatile organic compounds only. Equipment blanks should be collected, where
appropriate (e.g., where neither disposable nor dedicated equipment is used). Field blanks are next in
priority, and trip blanks next. Only one type of blank must be collected per event, not all three.
10.1.1.1. Equipment Blanks
In general, equipment (rinsate) blanks should be collected when reusable, non-disposable sampling
equipment (e.g., trowels, hand augers, and non-dedicated groundwater sampling pumps) are being used
for the sampling event. Only one blank sample per matrix per day should be collected. If equipment
blanks are collected, field blanks and trip blanks are not required under normal circumstances.
Equipment blanks can be collected for soil, sediment, and ground water samples. A minimum of one
equipment blank is prepared each day for each matrix when equipment is decontaminated in the field.
These blanks are submitted "blind" to the laboratory, packaged like other samples and each with its own
unique identification number. Note that for samples which may contain VOCs, water for blanks should
be purged prior to use to ensure that it is organic free. HPLC water, which is often used for equipment
and field blanks, can contain VOCs if it is not purged.
[If equipment blanks are to be collected describe how they are to be collected and the analyses that
will be performed. A maximum of one blank sample per matrix per day should be collected, but at a
rate to not exceed one blank per 10 samples. The 1:10 ratio overrides the one per day requirement.
If equipment rinsate blanks are collected, field blanks and trip blanks are not required under normal
circumstances. Use the language below or reference the appropriate sections in a Quality Control SOP
and state in which Appendix the SOP is located.]
[Include this subsection if equipment blanks are to be collected, otherwise, delete.]
[Include this paragraph if blanks will be analyzed for both metals and organic compounds; otherwise
delete.]
Equipment rinsate blanks will be collected to evaluate field sampling and decontamination procedures
by pouring High Performance Liquid Chromatography (HPLC) organic-free (for organics) or deionized
water (for inorganics) over the decontaminated sampling equipment. One equipment rinsate blank will
be collected per matrix each day that sampling equipment is decontaminated in the field. Equipment
rinsate blanks will be obtained by passing water through or over the decontaminated sampling devices
used that day. The rinsate blanks that are collected will be analyzed for [Include names of
target analytes, e.g., metals, total petroleum hydrocarbons, volatile organic compounds, etc.].
[Include this paragraph if blanks will be analyzed only for organic compounds; otherwise delete.]
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Equipment rinsate blanks will be collected to evaluate field sampling and decontamination procedures
by pouring High Performance Liquid Chromatography (HPLC) organic-free water over the
decontaminated sampling equipment. One equipment rinsate blank will be collected per matrix each
day that sampling equipment is decontaminated in the field. Equipment rinsate blanks will be obtained
by passing water through or over the decontaminated sampling devices used that day. The rinsate
blanks that are collected will be analyzed for [Include names of target analytes, e.g., volatile
organic compounds, total petroleum hydrocarbons, etc.] [Include this paragraph if blanks will be
analyzed only for metals; otherwise delete.]
Equipment rinsate blanks will be collected to evaluate field sampling and decontamination procedures
by pouring deionized water over the decontaminated sampling equipment. One equipment rinsate
blank will be collected per matrix each day that sampling equipment is decontaminated in the field.
Equipment rinsate blanks will be obtained by passing deionized water through or over the
decontaminated sampling devices used that day. The insate blanks that are collected will be analyzed
for metals.
[Always include this paragraph.]The equipment rinsate blanks will be preserved, packaged, and sealed
in the manner described for the environmental samples. A separate sample number and station
number will be assigned to each sample, and it will be submitted blind to the laboratory.
10.1.1.2. Field Blanks
Field blanks are collected when sampling water or air and equipment decontamination is not necessary
or sample collection equipment is not used (e.g., dedicated pumps). A minimum of one field blank is
prepared each day sampling occurs in the field, but equipment is not decontaminated. These blanks are
submitted "blind" to the laboratory, packaged like other samples and each with its own unique
identification number. Note that for samples which may contain VOCs, water for blanks should be
purged prior to use to ensure that it is organic free. HPLC water, which is often used for equipment and
field blanks, can contain VOCs if it is not purged.
[Include this subsection if field blanks will be collected; otherwise delete. Only one blank sample per
matrix per day should be collected. If field blanks are prepared, equipment rinsate blanks and trip
blanks are not required under normal circumstances.]
[Include this paragraph if blanks will be analyzed for both metals and organic compounds; otherwise
delete.]
Field blanks will be collected to evaluate whether contaminants have been introduced into the samples
during the sampling due to ambient conditions or from sample containers. Field blank samples will be
obtained by pouring High Performance Liquid Chromatography (HPLC) organic-free water (for organics)
and/or deionized water (for inorganics) into a sampling container at the sampling point. The field blanks
that are collected will be analyzed for [Include names of target analytes, e.g., metals, volatile
organic compounds, etc.].
[Include this paragraph if blanks will be analyzed only for organic compounds; otherwise delete.]
Field blanks will be collected to evaluate whether contaminants have been introduced into the samples
during the sampling due to ambient conditions or from sample containers. Field blank samples will be
obtained by pouring High Performance Liquid Chromatography (HPLC) organic-free water into a
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sampling container at the sampling point. The field blanks that are collected will be analyzed for
[Include names of target analytes, e.g., volatile organic compounds, total petroleum
hydrocarbons, etc.].
[Include this paragraph if blanks will be analyzed only for metals; otherwise delete.]
Field blanks will be collected to evaluate whether contaminants have been introduced into the samples
during the sampling due to contamination from sample containers. Field blank samples will be obtained
by pouring deionized water into a sampling container at the sampling point. The field blanks that are
collected will be analyzed for metals.
[Always include this paragraph.]
The field blanks will be preserved, packaged, and sealed in the manner described for the environmental
samples. A separate sample number and station number will be assigned to each sample, and it will be
submitted blind to the laboratory.
10.1.1.3. Trip Blanks
Trip blanks are required only if no other type of blank will be collected for volatile organic compound
analysis and when air and/or water samples are being collected. If trip blanks are required, one is
submitted to the laboratory for analysis with every shipment of samples for VOC analysis. These blanks
are submitted "blind" to the laboratory, packaged like other samples and each with its own unique
identification number. Note that for samples which may contain VOCs, water for blanks should be
purged prior to use to ensure that it is organic free. Laboratory water, which is used for trip blanks, can
contain VOCs if it is not purged.
[Include this subsection if trip blanks will be collected; otherwise delete. Only one blank sample per
matrix per day should be collected. Trip blanks are only relevant to volatile organic compound (VOC)
sampling efforts.]
Trip blanks will be prepared to evaluate if the shipping and handling procedures are introducing
contaminants into the samples, and if cross contamination in the form of VOC migration has occurred
between the collected samples. A minimum of one trip blank will be submitted to the laboratory for
analysis with every shipment of samples for VOC analysis. Trip blanks are 40 mL vials that have been
filled with HPLC-grade water that has been purged so it is VOC free and shipped with the empty
sampling containers to the site or sampling area prior to sampling. The sealed trip blanks are not
opened in the field and are shipped to the laboratory in the same cooler with the samples collected for
volatile analyses. The trip blanks will be preserved, packaged, and sealed in the manner described for
the environmental samples. A separate sample number and station number will be assigned to each trip
sample and it will be submitted blind to the laboratory.
10.1.1.4. Temperature Blanks
[Include this paragraph with all plans.] For each cooler that is shipped or transported to an analytical
laboratory a 40 ml VOA vial will be included that is marked "temperature blank." This blank will be
used by the sample custodian to check the temperature of samples upon receipt.
10.1.2 Assessment of Field Variability (Field Duplicate or Co-located Samples)
Duplicate samples are collected simultaneously with a standard sample from the same source under
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identical conditions into separate sample containers. Field duplicates will consist of a homogenized
sample divided in two or else a co-located sample. Each duplicate portion should be assigned its own
sample number so that it will be blind to the laboratory. A duplicate sample is treated independently of
its counterpart in order to assess laboratory performance through comparison of the results. At least
10% of samples collected per event should be field duplicates. At least one duplicate should be
collected for each sample matrix, but their collection can be stretched out over more than one day (e.g.,
if it takes more than one day to reach 10 samples). Every group of analytes for which a standard sample
is analyzed will also be tested for in one or more duplicate samples. Duplicate samples should be
collected from areas of known or suspected contamination. Since the objective is to assess variability
due to sampling technique and possible sample heterogeneity, source variability is a good reason to
collect co-located samples, not to avoid their collection.
Duplicate soils samples will be collected at sample locations [identify soil sample locations from which
samples will be collected for duplicate analysis].
Duplicate samples will be collected from these locations because [Add sentence(s) here explaining a
rationale for collecting duplicate samples from these locations; e.g., samples from these locations are
suspected to exhibit moderate concentrations of contaminants or previous sampling events have
detected moderate levels of contamination at the site or sampling area at these locations.]
[Include this paragraph if collecting soil samples and analyzing for compounds other than volatiles;
otherwise delete.]
Soil samples to be analyzed for [List all analytical methods for this sample event
except for volatiles.] will be homogenized with a trowel in a sample-dedicated disposable pail.
Homogenized material from the bucket will then be transferred to the appropriate wide-mouth glass
jars for both the regular and duplicate samples. All jars designated for a particular analysis (e.g., semi-
volatile organic compounds) will be filled sequentially before jars designated for another analysis are
filled (e.g., metals).
[Include this paragraph if collecting soil samples and analyzing for volatiles; otherwise delete.]
Soil samples for volatile organic compound analyses will not be homogenized. Equivalent Encore
samples from a colocated location will be collected identically to the original samples, assigned unique
sample numbers and sent blind to the laboratory.
[Include these paragraphs if collecting sediment samples. If volatile organic compound analysis will
be performed on sediment samples, modify the above paragraph for soil sample volatile analyses by
changing "soil" to "sediment."]
Duplicate sediment samples will be collected at sample locations [Identify sediment
sample locations from which duplicate or colocated samples for duplicate analysis will be obtained].
Duplicate samples will be collected from these locations because [Add sentence(s)
here explaining a rationale for collecting duplicate samples from these locations; e.g., samples from
these locations are suspected to exhibit moderate concentrations of contaminants or previous sampling
events have detected moderate levels of contamination at the site or sampling area at these locations.]
Sediment samples will be homogenized with a trowel in a sample-dedicated 1-gallon disposable pail.
Homogenized material from the bucket will then be transferred to the appropriate wide-mouth glass
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jars for both the regular and duplicate samples. All jars designated for a particular analysis (e.g., semi-
volatile organic compounds) will be filled sequentially before jars designated for another analysis are
filled (e.g., metals).
[Include this paragraph if collecting water samples.]
Duplicate water samples will be collected for water sample numbers [water sample
numbers which will be split for duplicate analysis]. Duplicate samples will be collected from these
locations because [Add sentence(s) here explaining a rationale for collecting
duplicate samples from these locations; e.g. samples from these locations are suspected to exhibit
moderate concentrations of contaminants or previous sampling events have detected moderate levels
of contamination at the site or sampling area at these locations.] When collecting duplicate water
samples, bottles with the two different sample identification numbers will alternate in the filling
sequence (e.g., a typical filling sequence might be, VOCs designation GW-2, VOCs designation GW-4
(duplicate of GW-2); metals, designation GW-2, metals, designation GW-4, (duplicate of GW-2) etc.).
Note that bottles for one type of analysis will be filled before bottles for the next analysis are filled.
Volatiles will always be filled first.
[Always include this paragraph.]
Duplicate samples will be preserved, packaged, and sealed in then same manner as other samples of the
same matrix. A separate sample number and station number will be assigned to each duplicate, and it
will be submitted blind to the laboratory.
10.2. Background Samples
Background samples are collected in situations where the possibility exists that there are native or
ambient levels of one or more target analytes present or where one aim of the sampling event is to
differentiate between on-site and off-site contributions to contamination. One or more locations are
chosen which should be free of contamination from the site or sampling location itself, but have similar
geology, hydrogeology, or other characteristics to the proposed sampling locations that may have been
impacted by site activities. For example, an area adjacent to but removed from the site, upstream from
the sampling points, or up gradient or cross gradient from the groundwater under the site. Not all
sampling events require background samples.
[Specify the sample locations that have been designated as background. Include a rationale for
collecting background samples from these locations and describe or reference the sampling and
analytical procedures which will be followed to collect these samples.]
10.3. Field Screening and Confirmation Samples
For projects where field screening methods are used (typically defined as testing using field test kits,
immunoassay kits, or soil gas measurements or equivalent, but not usually defined as the use of a mobile
laboratory which generates data equivalent to a fixed laboratory), two aspects of the tests should be
described. First, the QC which will be run in conjunction with the field screening method itself, and,
second, any fixed laboratory confirmation tests which will be conducted. QC acceptance criteria for
these tests should be defined in these sections rather than in the DQO section.
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10.3.1. Field Screening Samples
[For projects where field screening methods are used describe the QC, samples which will be run in
the field to ensure that the screening method is working properly. This usually consists of a
combination of field duplicates and background (clean) samples). The discussion should specify
acceptance criteria and corrective action to be taken if results are not within defined limits. Discuss
confirmation tests below.]
10.3.2. Confirmation Samples
If the planned sampling event includes a combination of field screening and fixed laboratory
confirmation, this section should describe the frequency with which the confirmation samples will be
collected and the criteria which will be used to select confirmation locations. These will both be
dependent on the use of the data in decision making. It is recommended that the selection process be at
a minimum of 10% and that a selection criteria include checks for both false positives (i.e., the field
detections are invalid or the concentrations are not accurate) and false negatives (i.e., the analyte was
not detected in the field). Because many field screening techniques are less sensitive than laboratory
methods false negative screening is especially important unless the field method is below the action level
for any decision making. It is recommended that some "hits" be chosen and that other locations be
chosen randomly.
[Describe confirmation sampling. Discuss the frequency with which samples will be confirmed and
how location will be chosen. Define acceptance criteria for the confirmation results (e.g., RPD#25%)
and corrective actions to be taken if samples are not confirmed.]
10.3.3. Split Samples
Split Samples are defined differently by different organizations, but for the purpose of this guidance, s
split samples are samples that are divided among two or more laboratory for the purpose of providing an
inter-laboratory or inter-organization comparison. Usually one organization (for example, a responsible
party) collects the samples and provides sufficient material to the other organization (for example, EPA)
to enable it to perform independent analyses. It is expected that the sampling party will have prepared a
sampling plan which the QA Office has reviewed and approved that describes the sampling locations and
a rationale for their choice, sampling methods, and analyses.
[Describe the purpose of the split sampling. Include references to the approved sampling plan of the
party collecting the samples. Provide a rationale for the sample locations at which split samples will
be obtained and how these locations are representative of the sampling event as a whole. Describe
how results are to be compared and define criteria by which agreement will be measured. Discuss
corrective action to be taken if results are found to not be in agreement.]
10.4. Laboratory Quality Control Samples
Laboratory quality control (QC) samples are analyzed as part of standard laboratory practice. The
laboratory monitors the precision and accuracy of the results of its analytical procedures through
analysis of QC samples. In part, laboratory QC samples consist of matrix spike/matrix spike duplicate
samples for organic analyses, and matrix spike and duplicate samples for inorganic analyses. The term
"matrix" refers to use of the actual media collected in the field (e.g., routine soil and water samples).
Laboratory QC samples are an aliquot (subset) of the field sample. They are not a separate sample, but a
special designation of an existing sample.
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[Include the following language if soil samples are to be collected for other than VOCs. Otherwise
delete.]
A routinely collected soil sample (a full 8-oz sample jar or two 120-mL sample vials) contains sufficient
volume for both routine sample analysis and additional laboratory QC analyses. Therefore, a separate
soil sample for laboratory QC purposes will not be collected. [Include the following language if soil
samples are to be collected for other than VOCs. Otherwise delete.] Soil samples for volatile organic
compound analyses for laboratory QC purposes will be obtained by collecting double the number of
equivalent Encore samples from a colocated location in the same way as the original samples, assigned a
unique sample numbers and sent blind to the laboratory.
[Include the following language if water samples are to be collected. Otherwise delete.]
For water samples, double volumes of samples are supplied to the laboratory for its use for QC
purposes. Two sets of water sample containers are filled and all containers are labeled with a single
sample number.
For VOC samples this would result in 6 vials being collected instead of 3, for pesticides and semi-volatile
samples this would be 4 liters instead of 2, etc.
The laboratory should be alerted as to which sample is to be used for QC analysis by a notation on the
sample container label and the chain-of-custody record or packing list. At a minimum, one laboratory
QC sample is required per 14 days or one per 20 samples (including blanks and duplicates), whichever is
greater. If the sample event lasts longer than 14 days or involves collection of more than 20 samples per
matrix, additional QC samples will be designated.
For this sampling event, samples collected at the following locations will be the designated laboratory
QC samples: [If a matrix is not being sampled, delete the reference to that matrix.]
For soil, samples [List soil sample locations and numbers designated for QA/QC]
For sediment, samples [List sediment sample locations and numbers designated
for QA/QC.]
For water, samples [List water sample locations and numbers designated for
QA/QC.]
[Add a paragraph explaining why these sample locations were chosen for QA/QC samples. QA/QC
samples should be samples expected to contain moderate levels of contamination. A rationale should
justify the selection of QA/QC samples based on previously-detected contamination at the site or
sampling area, historic site or sampling area operations, expected contaminant deposition/migration,
etc.]
11 FIELD VARIANCES
[It is not uncommon to find that, on the actual sampling date, conditions are different from
expectations such that changes must be made to the SAP once the samplers are in the field. The
following paragraph provides a means for documenting those deviations, or variances. Adopt the
paragraph as is, or modify it to project-specific conditions.]
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As conditions in the field may vary, it may become necessary to implement minor modifications to
sampling as presented in this plan. When appropriate, the QA Office will be notified and a verbal
approval will be obtained before implementing the changes. Modifications to the approved plan will be
documented in the sampling project report.
12 FIELD HEALTH AND SAFETY PROCEDURES
[Describe any agency-, program- or project-specific health and safety procedures that must be
followed in the field, including safety equipment and clothing that may be required, explanation of
potential hazards that may be encountered, and location and route to the nearest hospital or medical
treatment facility. A copy of the organization health and safety plan may be included in the Appendix
and referenced in this section.]
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