CLIMA TE LEADERS GREENHOUSE GAS INVENTOR Y PROTOCOL
OFFSET PROJECT METHODOLOGY
for
Project Type: Industrial Boiler Efficiency
(Industrial Process Applications)
Climate Protection Partnerships Division/Climate Change Division
Office of Atmospheric Programs
U.S. Environmental Protection Agency
August 2008
Version 1.3
-------
Table of Contents
Introduction 3
Description of Project Type 3
Regulatory Eligibility 7
Determining Additionality - Applying the Performance Threshold 9
Quantifying Emission Reductions 11
Monitoring 15
Appendix I. Development of the Performance Threshold - Data Set 18
Appendix II. Tables for Estimating and Calculating Emissions 25
Climate Leaders August 2008
Industrial Boiler Efficiency - 2 -
-------
Climate Leaders is an EPA industry-government partnership that works with companies to develop
comprehensive climate change strategies. Partner companies commit to reducing their impact on the global
environment by setting aggressive greenhouse gas reduction goals and annually reporting their progress to
EPA.
Introduction
An important objective of the Climate Leaders program is to focus corporate attention on
achieving cost-effective greenhouse gas (GHG) reductions within the boundary of the
organization (i.e., internal projects and reductions). Partners may also use reductions
and/or removals which occur outside their organizational boundary (i.e., external
reductions or "offsets") to help them achieve their goals. To ensure that the GHG emission
reductions from offsets are credible, Partners must ensure that the reductions meet four
key accounting principles:
// The quantified GHG reductions must represent actual emission reductions that
have already occurred.
• Additional: The GHG reductions must be surplus to regulation and beyond what
would have happened in the absence of the project or in a business-as-usual
scenario based on a performance standard methodology.
• Permanent. 'The GHG reductions must be permanent or have guarantees to ensure
that any losses are replaced in the future.
• Verifiable:~t\\e GHG reductions must result from projects whose performance can
be readily and accurately quantified, monitored and verified.
This guidance provides a performance standard (accounting methodology) for greenhouse
gas (GHG) offset projects that introduce more efficient (i.e., lower GHG emitting) boiler
technology for industrial process applications.1 The accounting methodology presented in
this paper addresses the eligibility of industrial boiler efficiency projects as GHG offset
projects and provides measurement and monitoring guidance. Program design issues (e.g.,
project lifetime, project start date) are not within the scope of this guidance and are
addressed in the Climate Leaders offset program overview document: Using Offsets to Help
Climate Leaders Achieve Their GHG Reduction Goals.2
Description of Project Type
Industrial boiler systems are used for heating with hot water or steam in industrial process
applications. There are approximately 43,000 industrial boilers in the United States.3 A
majority of these (71%) are located at facilities in the food, paper, chemicals, refining, and
1 There is no precise regulatory definition for an industrial boiler. An industrial boiler is typically defined by its common
function - a boiler that provides heat in the form of hot water or steam for co-located industrial process applications. The
industrial boiler category does not include utility boilers or commercial boilers as these do not provide the same service
as industrial boilers and are separately defined in Federal regulations.
2 Please visit http://www.epa.gov/climateleaders/resources/optional-module.html to download the overview document.
3 Oak Ridge National Laboratory, Characterization of the U.S. Industrial Commercial Boiler Population, May 2005
Climate Leaders August 2008
Industrial Boiler Efficiency - 3 -
-------
primary metals industries. The major source of GHG emissions from a boiler system is
carbon dioxide (COz) from the combustion of fossil fuels in the boiler. Other minor sources
of GHGs can include methane (CH4) from leaks in the natural gas distribution system and
CH4 and nitrous oxide (N20) as byproducts of combustion processes.
This section provides information on the general parameters that the proposed boiler
project must match to use this performance standard.
Technology/Practice Introduced. This guidance document addresses the improved
efficiency of industrial boilers used for heat for industrial process applications by adding
advanced technologies (such as advanced heat recovery, controls and burners) to the
boiler system. These technology-based efficiency improvements can be achieved when
retrofitting or replacing an existing boiler with new technology, when purchasing a natural
gas boiler to meet new demand, and/or when switching from a fuel oil, coal or electricity-
based boiler to a natural gas boiler.
The performance standard is applicable to retrofits of existing industrial boilers using any
market fuel (e.g., coal, diesel, fuel oil, natural gas, LPG/LNG) and new capacity or early
replacement boilers using natural gas only. Retrofit projects are defined as those that add
technological components to an existing boiler unit to improve overall efficiency. Projects
that involve replacement of the boiler itself are considered new capacity or early
replacement projects.
Projects improving the efficiency of an existing, electricity-fired boiler or introducing new
boilers using coal, diesel, fuel oil or electricity cannot use the same standard. Also
excluded are boilers fired or co-fired with by-product fuels generated by on-site processes
(i.e., pulp liquor, wood chips, refinery gas, residual oil, coke oven gas, and blast furnace
gas) and boilers that are used for electricity generation (i.e., utility boilers) or building
space and water heating.
GHG emission reductions can also be achieved through energy efficiency improvements in
the steam/hot water distribution system, the boiler auxiliaries, or in process efficiency
improvements. This performance standard is not applicable for projects where these are
the primary reason for undertaking the project, or for the decommissioning of boilers. Any
secondary emission increases or decreases resulting from energy efficiency or process
efficiency improvements of the boiler auxiliaries should be accounted for per guidance in
the section on "Physical Boundary."
Project Size/Output. This performance standard may be used for industrial boilers of
any size, including large boilers (often classified as water-tube and fire-tube boilers that
have a capacity greater than 10 million Btu per hour (MMBtu/hour))4 and are regulated by
the Federal Clean Air Act (CAA) and smaller industrial boilers (less than 10 MMBtu/hour)
4
Oak Ridge National Laboratory, Characterization of the U.S. Industrial Commercial Boiler Population, May 2005.
Climate Leaders August 2008
Industrial Boiler Efficiency - 4 -
-------
that are exempt from CM regulations. As a practical matter, the technologies for boiler
efficiency improvement are typically installed on larger water tube boilers greater than 10
MMBtu/hour since the fuel reductions are greater and better support project economics.
However, smaller industrial boiler projects are also eligible to use this performance
standard, provided they meet the specified performance threshold.
Project Boundary. This section provides guidance on which physical components and
associated greenhouse gases must be included in the project boundary for an industrial
boiler project.
Physical Boundary. The physical boundary of the project includes any component
of the industrial boiler that will change between the baseline conditions and
implementation of the project. In most cases, the physical boundary should be
limited to the boiler unit which includes the boiler, burner, flue stack and
economizer (see Figure 1) as the rated thermal efficiency of the boiler unit will
depend on the interaction of these components.
Upstream or downstream adjustments to the physical boundary must be made,
however, to incorporate emissions changes in the following special cases:
projects where the new boiler results in emissions changes in the
steam distribution system;
projects where the electricity use associated with the boiler auxiliaries
(e.g., fans, pumps, conveyors) changes as a result of the new boiler.
In this case, the equipment causing the changes in emissions from
electricity should be included in the physical boundary, either as direct
emissions or indirect emissions (if generated off-site); and,
changes in CH4 leakage from the natural gas distribution system, for
example, from a switch from fuel oil to natural gas in the boiler. A
small section of new natural gas distribution line from a nearby
distribution main line will typically be installed and the leakage from
this incremental section should be accounted for.
Figure 1. Physical Boundary for Industrial Boiler Projects
Climate Leaders August 2008
Industrial Boiler Efficiency - 5 -
-------
Csld Fwd
Greenhouse Gas Accounting Boundary. The GHG accounting boundary for an
industrial boiler efficiency project includes primarily the COz emissions from the
combustion of fossil fuels. Other minor sources of GHGs may be CH4 from leaks in
the natural gas distribution system (generally small), and CH4 and N20 as
byproducts of combustion. The GHG accounting boundary for industrial boiler
projects should, therefore, include all COz, CH4 and NzO emissions. Appendix II,
Table lid provides default emission factors for combustion-related CH4 and N20.
Appendix II, Table Ilf provides default factors for CH4 leaks from natural gas
distribution.
Temporal Boundary. An annual accounting boundary should be used for
industrial boiler projects. Emissions from an industrial boiler can fluctuate over the
course of a year due to changing activity schedules and seasonal climate patterns.
An annual accounting boundary will account for these fluctuations.
Climate Leaders
Industrial Boiler Efficiency
August 2008
-------
Leakage. Leakage is an increase in GHG emissions or decrease in sequestration caused
by the project but not accounted for within the project boundary. The underlying concept
is that a particular project can produce offsetting effects outside of the physical boundary
that fully or partially negate the benefits of the project. Although there are other forms of
leakage, for this performance standard, leakage is limited to activity shifting - the
displacement of activities and their associated GHG emissions outside of the project
boundary.
Potential sources of leakage from a boiler project could result from an increase in GHG
emissions at another site, if the existing higher emitting boiler is retired early before the
end of its useful life and used elsewhere in the facility, or resold for use in another
application. If the old boiler is sold to replace another boiler at the end of its life instead of
buying a more efficient boiler (defined as a boiler with a performance equal to, or better
than, the performance threshold), the difference in GHG emissions between the
replacement boiler and the performance threshold are considered leakage and must be
quantified and subtracted from the emission reductions of the project.
If it is determined that significant emissions that are reasonably attributable to the project
occur outside the project boundary, these emissions must be quantified and included in the
calculation of reductions. No specific quantification methodology is required. All
associated activities determined to contribute to leakage should be monitored.
Regulatory Eligibility
The performance standard subjects greenhouse gas offset projects to a regulatory "screen"
to ensure that the emission reductions achieved would not have occurred in the absence of
the project due to federal, state or local regulations. In order to be eligible as a GHG offset
project, GHG emissions must be reduced below the level effectively required by any
existing federal, state, or local policies, guidance, or regulations. This may also apply to
consent decrees, other legal agreements, or federal and state programs that compensate
voluntary action.
Federal Regulations. There are no federal standards that require any specific
efficiency or GHG limitations at industrial boilers. The Federal Clean Air Act (CAA)
includes emissions standards, however, for large industrial boilers (i.e., steam
generating units with design heat input capacity of more than 10 MMBtu/hour for
which construction, modification, or reconstruction commenced after June 9, 1989)
which should be reviewed by the project developer as they influence the individual
design characteristics of the boiler. The CAA regulations do not apply to units with
less than 10 MMBtu/hour rated input capacity.
The following CAA Titles are pertinent to an industrial boiler and should be
reviewed:
Climate Leaders August 2008
Industrial Boiler Efficiency - 7 -
-------
Title I, excluding Section 112: Attainment/Maintenance of
National Ambient Air Quality Standards (NAAQS) - An industrial
boiler may be subject to the New Source Performance Standards
(NSPS), which fall within this section and are codified in 40 CFR Part
60, subparts Db and Dc.5 Under the NSPS, EPA regulates sulfur
dioxide (SCb), particulate matter (PM), and nitrogen oxide (NOX)
emissions from new boilers (steam generating units). Depending on
the fuel type, throughput, and operational requirements of the boiler,
NSPS may apply, and a control, such as a low-NOx burner, may be
required. Applicable regulations are implemented by the state or local
body and would be covered in the permit process.6
Title I, Section 112: Hazardous Air Pollutants (HAP) - An
industrial boiler may be subject to one or more National Emission
Standards for Hazardous Air Pollutants (NESHAP), for example for
mercury, organic, or total selected metals. NESHAP applies to all
boiler units (existing and new) and fuel types (solid, gaseous, and
liquid), although the requirements differ for each boiler category.
Existing natural gas boilers have only a carbon monoxide (CO)
limitation while new natural gas boilers have no limitations. New and
existing coal (solid fuel) and oil (liquid fuel) units have several
standards that must be met. In its final rule, codified in 40 CFR Part
63, EPA requires industrial boilers to meet HAP emission standards
reflecting the application of the maximum achievable control
technology (MACT).7 The States are required to implement the
Federal rule by evaluating each facility's compliance with MACT, which
is a component of the State Title V CAA permit program for stationary
sources. To comply with NESHAP, the purchaser of a new industrial
boiler must receive a guarantee from the boiler manufacturer that the
unit is in compliance. After the new unit is installed and operating, the
facility must demonstrate compliance by a stack test. Compliance and
reporting details would be covered in the Title V permit.
Title V: Operating Permits - A large industrial boiler is a major
source that would require a Title V permit. All applicable CAA
regulations, including NSPS and NESHAP, would be covered by the
permit process. Facilities with plans to install a new boiler or furnace
for heat or process steam, or to update an existing boiler or furnace
5 40 CFR Part 60/63 FR 49442, Revision of Standards of Performance for Nitrogen Oxide Emissions From New Fossil-
Fuel Fired Steam Generating Units, http://www.epa.gov/ttn/atw/combust/boiler/fr0998.txt
640 CFR Part 60/70 FR 9705, Standards of Performance for Electric Utility Steam Generating Units for Which
Construction Is Commenced After September 18, 1978; Standards of Performance for Industrial-Commercial-
Institutional Steam Generating Units; and Standards of Performance for Small Industrial-Commercial-Institutional Steam
Generating Units; Proposed Rule http://www.epa.gov/ttn/atw/combust/boiler/fr28fe05.html
7 40 CFR Part 63, National Emission Standards for Hazardous Air Pollutants for Industrial, Commercial, and
Institutional Boilers and Process Heaters.
Climate Leaders August 2008
Industrial Boiler Efficiency - 8 -
-------
(e.g., to increase capacity or improve performance) may be required to
file an application for an air pollution construction permit with the
State or local air board. Although there is an exemption for small
boilers, large industrial boilers exceed the maximum heat input
capacity exemption threshold.
To pass the regulatory screen, the project proponent must demonstrate that the
proposed project is not being undertaken to come into compliance with any
mandatory requirements contained in these federal programs. In circumstances
where a proposed project is being undertaken to comply with regulations, but GHG
emission reductions are achieved beyond what would reasonably be expected from
technologies/practices used to meet the regulation, the project could pass the
regulatory screen and the incremental GHG emission reductions may be considered
as the project.
State and Local Regulations. States develop regulations to implement the
Federal CM requirements that the EPA delegates to the States. State air emission
standards must be as stringent as the Federal CAA rules. States have the option to
echo the federal code, to incorporate them by reference into state law, or states
may establish regulations that are more stringent than the federal standards, as is
often the case in California. Some states and local governments have additional
efficiency standards, require periodic audits, or encourage the purchase of certain
types of boilers. The project developer should review any such state and local
standards.
GHG emission reductions resulting from compliance with any federal, state or local
regulations are not eligible as GHG offsets.
Determining Additionality - Applying the Performance Threshold
This section describes the performance threshold (additionality determination) which an
industrial boiler project must meet or exceed in order to be considered as a GHG project
offset.
Additionality Determination. The additionality determination represents a level of
performance that, with respect to emission reductions or removals, or technologies or
practices, is significantly better than average compared with recently undertaken practices
or activities in a relevant geographic area. Any project that meets or exceeds the
performance threshold is considered "additional" or beyond that which would be expected
under a "business-as-usual" scenario.
The type of performance threshold used for an industrial boiler project is a technology-
based standard. The threshold represents a level of performance (technology) that is
beyond that expected of a typical industrial boiler and is based on the suite of current
Climate Leaders August 2008
Industrial Boiler Efficiency - 9 -
-------
technologies available for improving the efficiency of a boiler. The technology-based
threshold was selected because the efficiencies of industrial boiler applications fall within a
range that is dictated by operational and emission requirements making no single
efficiency/emissions performance value applicable for a particular set of industrial boilers.
The performance threshold is defined as the fuel-specific boiler design that meets the
engineer's specifications with a non-condensing economizer integrated into the system.
This combination is already considered standard on industrial boilers and additional
"options" would have to be added to the boiler system to achieve superior efficiency/CCb
emissions performance. To generate reductions, a project developer would have to add at
least one of the other technologies listed below to the boiler system in order to pass the
performance threshold and make the project additional:
Non-condensing economizer (conventional stack heat recovery)
Condensing economizer (condensate heat recovery)
Combustion air pre-heaters
Blowdown waste heat recovery
Turbulators
The engineer's specification to establish the new "nominal thermal efficiency" for the boiler
should include the following performance information, and will depend on whether the
boiler uses coal, fuel oil, or natural gas:
Nominal output capacity
Fuel
Steam delivery pressure
Steam delivery temperature
NOx limitations
An example of the process is presented in Table 1 where the technology threshold results
in a thermal efficiency of 85% (nominal boiler (80%) with non-condensing economizer
(+5%)). With the advanced burner and controls (+1%), condensing economizer (+1%),
combustion pre-heater (+1%) and blowdown heat recovery (+1%) the efficiency is
increased to 89%. Note that the condensing economizer replaces the non-condensing one
with a marginal increase in efficiency of 1%.
Climate Leaders August 2008
Industrial Boiler Efficiency - 10 -
-------
Table 1. Industrial Boiler Efficiency and Emissions with Optional Components
Industrial Boiler and Optional
Components
Nominal Boiler Efficiency
Non-Condensing Economizer
Advanced Burner and Controls
Condensing Economizer
Combustion Pre-heater
Blowdown Heat Recovery
Efficiency Range
and Incremental
Improvement* (%)
75-83
1 -7
1 -2
1 -2
1 -2
1
Manufacturer
Specified Efficiency
Value*
(%)
80
5
1
1
1
1
Resulting Overall
Efficiency*
(%)
SCL
85
86
87
88
89
* Thermal Efficiency
Additional information on the derivation of the performance threshold and other efficiency
improvement options can be found in Appendix I.
Quantifying Emission Reductions
Quantifying emission reductions from an industrial boiler project encompasses four steps:
two are pre-project implementation (selecting the emissions baseline and estimating
project emission reductions) and two are post-project implementation (monitoring and
calculating actual project reductions).
Selecting and Setting an Emission Baseline: The emissions baseline for an industrial
boiler project depends on whether the project involves the retrofit of an existing boiler or
new construction. The emission baselines are presented below:
1. Retrofit or Early Replacement. For projects involving the retrofit of a
coal, fuel oil or natural gas boiler or the early replacement of a coal or fuel oil boiler
with natural gas, the baseline should be equal to the average annual emissions of
the existing boiler (\.e., the boiler prior to retrofit) in KgCCb equivalent.
In cases where a retrofit project also expands capacity, the portion of the project
that is above the baseline fuel consumption should be treated as new capacity. In
this case, the project developer must assume that the additional baseline fuel would
have been natural gas.
2. New Capacity. For projects involving procurement of a natural gas boiler to
meet new capacity, or the replacement of a boiler at the end of its lifetime with a
new natural gas boiler, the thermal efficiency of the technology threshold (i.e.,
Climate Leaders
Industrial Boiler Efficiency
August 2008
- 11-
-------
efficiency of the nominal boiler that meets the engineer's specifications with\.\\Q
non-condensing economizer) is used as the baseline. Boiler efficiency can be
converted to project COz, CH4 and NzO emissions using the EPA emission factors
referenced in Appendix II. The first step in converting to emissions involves
determining the annual quantity of heat required for the specific process in MMBtu.
This is the heat output requirement of the boiler, and is usually calculated through
engineering analysis. COz emissions can then be calculated by multiplying the
annual heat output value by the COz emission factor in Table Ha (Appendix II) that
corresponds to the efficiency of the boiler system in place. In order to calculate CH4
and N20 emissions, the heat output value must first be converted to a heat input
value. This is done by dividing the heat output value by the thermal efficiency of
the boiler (i.e., required heat output/ thermal efficiency = required heat input).
Once this has been done, the project developer should use the appropriate emission
factor in Table lid (Appendix II) to calculate CH4 and NzO emissions.
It is important to note that the performance threshold is based on thermal
efficiency, and thus the direct COz, CH4, and NzO emissions from fuel combusted by
the boiler. When developing the baseline for new construction, indirect emissions
from electricity must be added to the direct emissions in order to estimate total COz
equivalent emissions.
In cases where special adjustments were made to the physical boundary, to address fuel,
pipeline leakage and or electricity changes upstream or downstream from the boiler itself,
the project developer must also include these in the baseline.
Estimating Project Emission Reductions. To estimate the potential GHG emission
reductions from the offset project, the project proponent must compare emissions of the
baseline with the emissions of the proposed project.
Estimating baseline emissions: Separate equations are presented for estimating
baseline emissions from retrofit projects (Equations A,B,C) and new capacity
(Equations D,E). Carbon content coefficients for natural gas, industrial coal and
residual and distillate fuel oils are provided in Table He (Appendix II).
Retrofits
Equation A.
Baseline CO2 emissions retrofits = (F; * CCj) + (EL * EFei )
Where:
i= fuel type
Climate Leaders August 2008
Industrial Boiler Efficiency - 12 -
-------
Fj= fuel consumption, MMBtu (use the average annual fuel consumption for
the past three years)
EFj= emission factor of fuel type i, kg CCb/MMBtu
EL= quantity of electricity consumed, MWh (use the average annual
consumption for the past three years)
= emission factor for electricity, kg CCb/MWh. If the emissions intensity
of the electricity being purchased is known (for example, through contacting
the local power supplier), the corresponding emission factor should be used.
Where the specific emissions profile of the purchased electricity is not known,
the project developer should use the relevant regional electric power
generation emission factors for the electricity component of their emissions
Equation B.
Baseline CH4 and N2O emissions Retrofits= (Fj * EFctu) + (Fj * EFN2o) + (EL *
(EL*EFe|,N2o)
Where:
i= fuel type
F= fuel consumption, MMBtu (use the average annual fuel consumption from
the boiler during the past three years)
EFcH4, EFN2o, = fuel-related CH4 and NzO emission factors, respectively,
kgC02e/MMBtu (see Appendix II, Table lid)
EL= quantity of electricity consumed, MWh (use the average annual
consumption for the past three years)
EFei,cH4, EF ei, N2o= Electricity-related CH4 and NzO emission factors,
respectively, kgC02e/MWh. If the emissions intensity of the electricity being
purchased is known (for example, through contacting the local power
supplier), the corresponding emission factor should be used. Where the
specific emissions profile of the purchased electricity is not known, the
applicant should use default values.
Equation C.
Total Baseline GHG Emissions Retrofits = Equation A + Equation B.
Climate Leaders August 2008
Industrial Boiler Efficiency - 13 -
-------
New Capacity
Total COz equivalent emissions also must be calculated when estimating baseline
emissions from new construction. Baseline CCb emissions for new construction are
based on the technology-specific efficiency threshold for the project fuel type
(Equation D). In order to derive COz emissions from the efficiency threshold, it is
necessary to first multiply the efficiency value of the boiler project by a carbon
content coefficient for natural gas, and then by the carbon dioxide-to-carbon weight
ratio (44/12). Because COz emissions are calculated differently from non-CCb
emissions, the calculation of COz emissions is prepared first (Equation D) and CH4
and NzO emissions are provided separately in Equation E. The calculation for non-
CC>2 emissions follows Equation B above, but uses estimates for project-level fuel
and electricity consumption.
Equation D.
Baseline CO2 Emissions New construction = 1/PT * 14.47 * 44/12 * H;
Where:
PT = performance threshold for the natural gas boiler (efficiency of the
nominal boiler with condenser, as a percentage)
14.47 = carbon content coefficient of natural gas (kg C/MMBtu)
44/12 = conversion from C to CCb
Hi = estimated annual heat output requirement for project, in MMBtu
Equation E.
Total Baseline GHG Emissions New construction = Equation B + Equation D
Estimating project emissions: Project-related emissions are estimated using the
same Equations above. Similar to the baseline calculations outlined above, the
estimated annual fuel consumption of the project boilers is multiplied by the
applicable COz, CH4 and NzO emission factors. Emissions from purchased electricity
also are included to estimate total project-related COz equivalent emissions.
Estimating project-related emission reductions: Emission reductions are
estimated using Equation F.
Equation F.
Climate Leaders August 2008
Industrial Boiler Efficiency - 14 -
-------
Reductions project = Emissions baseline - Emissions project
Monitoring
Four monitoring options are available for monitoring of emissions from boiler systems: (1)
direct fuel volume measurement; (2) steam flow measurement; (3) direct stack COz
measurement; and (4) dealer certified fuel volume measurement.8 The project developer
should, taking into account their specific circumstances, select the most appropriate option.
The project developer should also take into account that monitoring options (1), (2), and
(4) can be used to calculate CH4 and NzO emissions as well as COz. The default factors for
CH4 and N20 can be applied as long as fuel volume or heating value (MMBtu) is known.
Option (3) cannot normally be used to directly determine NzO and CH4 emissions as
continuous emissions monitoring (CEM) equipment to measure these gases is not
commercially available.
Direct Fuel Volume Measurement Approach. This method uses a volume meter
positioned in the fuel line leading directly to the boiler to measure the volume of fuel
burned in the boiler. At the end of each year, or some other designated period, the total
volume of fuel burned is read from the meter and used in Equation G to estimate the
emissions of COz from the boiler over that period. For natural gas-fired boilers, the method
also requires that temperature and pressure gauges be inserted in the fuel line to measure
the temperature and pressure of the fuel gas. The average gas pressure and temperature
over the measurement period is used in the equation to compensate for changes in gas
density due to these two factors. Fuel oil is relatively incompressible and its density does
not change appreciably over the year due to temperature and pressure fluctuations.
Equation G.
Actual CO2 Emissions monitored = V x CF x (44/12) x CE x 520/T x P/14.7
Where:
V = volume of fuel combusted (mscf/yr or mgal/yr)
CF = carbon factor (ton/mscf or ton/mgal)
44/12 = ratio of the weight of COz to carbon
CE = combustion efficiency (assume 0.99)
520/T = ratio of standard temperature to temperature of fuel (oR)
Clinton E. Burklin, Rick Lafleur, and Steve Erickson. "Measurement Methods for Commercial and Institutional Gas-
and Oil-Fired Boilers," U.S. Environmental Protection Agency, December 30, 2004.
Climate Leaders August 2008
Industrial Boiler Efficiency - 15 -
-------
P/14.7 = ratio of fuel pressure to standard pressure (psia)
Steam Flow Measurement Approach. The steam flow measurement method uses the
quantity of steam produced by the boiler and engineering data to calculate the COz
emissions from the boiler. This method is applicable to boilers fired with natural gas and
fuel oil. In this method, the steam produced by the boiler is measured in the steam line
just after it exits the boiler. At the end of a year, or some other designated period, the
quantity of steam produced by the boiler is used to calculate the COz emissions for the
period using Equation H. In addition to the annual steam production, Equation H also
requires the boiler owner to contact the boiler manufacturer to obtain the heat rate of the
boiler, which is usually expressed in terms of million Btu of fuel required to produce a
million Btu of steam. The heat rate is also called the overall thermal efficiency of the
boiler.
Equation H.
Actual CO2 Emissions monitored = Q x HR x 1/HV x CF x (44/12) x CE
Where:
Q = quantity of steam produced (MMBtu/yr)
HR = heat rate of the boiler (MMBtu of fuel/MMBtu of steam)
HV = heating value of the fuel (MMBtu/mgal or MMBtu/mscf)
CF = carbon factor (ton/mscf or ton/mgal)
44/12 = ratio of the weight of COz to carbon
CE = combustion efficiency (assume 0.99)
An orifice meter and an associated digital flow totalizer are used to provide a continuous
digital display of the current steam flow rate and accumulated steam flow. These totalizers
can be programmed to output values in any desired unit, which for this method should be
million Btu of steam flow. The orifice meter is placed in the steam line as it exits the
boiler. The orifice meter is factory calibrated, but should be re-calibrated annually.
Temperature and pressure sensors are used by the totalizer to determine the quantity of
heat conveyed by a unit of steam. These sensors are located in the steam line, adjacent to
the orifice meter. The sensors are factory calibrated and do not require further calibration.
Climate Leaders August 2008
Industrial Boiler Efficiency - 16 -
-------
Direct Stack CO2 Measurement Approach. The direct stack COz measurement
methodology uses a set of three instruments to directly measure the COz emissions from
the boiler stack. A gas analyzer is used to measure the concentration of COz in the boiler
stack. A flow rate meter is used to measure the flow rate of the flue gases in the boiler
stack. And a data integrator is used to integrate the COz concentration and the flue gas
flow rate over a given time period, such as a year, to calculate an annual COz emission rate
from the natural gas boiler.
Dealer Certified Fuel Volume Measurement Approach. An alternative to the direct
fuel volume measurement method is to allow the use of dealer certified fuel volume
measurements that are provided by the fuel dealer as part of their billing records.
Although there is no national standard for the accuracy of retail fuel deliveries, all but one
state (North Dakota) has adopted the guidelines set by the National Conference on
Weights and Measures (NCWM), known as Handbook 44.9 Under this method, the boiler
owner would not be required to install and maintain any fuel metering instrumentation.
The natural gas retail dealers, however, would be required to maintain fuel delivery meters
that meet the accuracy requirements of Handbook 44 and provide documentation that
reported sales volumes comply with these requirements. If there are multiple boilers, the
retail fuel dealer must provide separate fuel use records for each boiler.
To estimate COz emissions, the boiler owner would obtain a certified record of annual fuel
use from the fuel retailer. The owner would use this fuel volume in Equation 1 (Section
6.1) to calculate the tons per year of COz emissions. Equation 1 requires natural gas boiler
owners to obtain the temperature and pressure for which the certified natural gas volume
has been adjusted from the fuel delivery company.
Calculating Actual Project Reductions. Quantifying project GHG emissions reductions
occurs after the project has been implemented and monitored. To quantify project
reductions, apply the equations presented in the section on estimating project emission
reductions, using actual monitored project data rather than estimates, and adjust for any
leakage (Equation I).
Equation I.
Reductions project = Emissions baseline- Emissions monitored (+/- leakage
adjustments)
9 The National Conference on Weights and Measures (NCWM) developed the "Specifications, Tolerances, and Other
Technical Requirements for Weighting and Measuring Devices" in partnership with the Office of Weights and Measures
of the National Institute of Standards and Technology (NIST). This set of guidelines is also known as Handbook 44.
http://ts.nist.gov/ts/htdocs/230/235/hl30 04/PDF/hl30 04all.pdf
Climate Leaders August 2008
Industrial Boiler Efficiency - 17 -
-------
Appendix I. Development of the Performance Threshold - Data Set
The data sources used for developing these performance thresholds include the California
Energy Commission's Non Residential Market Share Tracking Study published in April 2005,
the U.S. Energy Information Administration's (EIA) Manufacturing Energy Consumption
Survey (MECS) last updated in 2002, and Oak Ridge National Laboratory's (ORNL)
Characterization of the U.S. Industrial Commercial Boiler Population published in May 2005.
In addition, information on current engineering practices concerning industrial boilers were
used, focusing on boilers installed in New York, Wisconsin, and California.
The service provided by the industrial boiler is heat to assist a specific industrial process.
Each process has its own desired steam pressure and temperature requirements. This heat
can, in theory, be obtained from the combustion of various types of fuel, or from
electricity. Table la is based on the MECS 2002 survey and includes data on all market
fuels and electricity used by industrial boilers, but excludes by-product fuels. The Table
shows that in 2002 natural gas was the predominant fuel regardless of region or location,
representing 78% of the total fuel consumed by industrial boilers. Coal made up another
15% and fuel oil about 6%.
Table la. End Uses of Fuel Consumption, 2002 (Trillion Btu.)
End Use
TOTAL FUEL
CONSUMPTION
Indirect Uses-Boiler Fuel
Conventional Boiler Use
(% of total fuel use)
CHP and/or Cogeneration
Process
Direct Uses-Total Process
Process Heating
Process Cooling and
Refrigeration
Machine Drive
Electro-Chemical Processes
Other Process Use
Direct Uses-Total
Nonprocess
Facility HVAC (e)
Facility Lighting
Other Facility Support
Net
Demand
for
Electricity
3,297
23
11
0.65
12
2,624
355
213
1,746
295
15
551
280
212
51
Residual
Fuel Oil
208
127
76
4.52
51
60
58
*
2
N/A
*
4
3
N/A
*
Distillate
Fuel Oil
and
Diesel
Fuel
141
35
25
1.49
10
43
24
2
16
N/A
1
50
5
N/A
1
Natural
Gas
5,794
2,162
1,306
77.69
857
2,986
2,742
45
109
N/A
90
513
417
N/A
30
LPG
and
NGL
103
8
8
0.48
*
64
60
*
4
N/A
*
24
5
N/A
*
Coal
(Excl.
Coke
and
Breeze)
1,182
776
255
15.17
521
381
368
*
5
N/A
7
19
5
N/A
*
Total
10,725
3,131
1,681
N/A
1,451
6,158
3,607
260
1,882
295
113
1,161
715
212
82
Climate Leaders
Industrial Boiler Efficiency
-18-
August 2008
-------
Onsite Transportation
Conventional Electricity
Generation
Other Non process Use
End Use Not Reported
Conventional Boiler Use
(% of total fuel use)
Conventional Boiler Use
(% of total fuel use)
Conventional Boiler Use
(% of total fuel use)
Conventional Boiler Use
(% of total fuel use)
4
N/A
4
112
Northeast C
1
0.6
Midwest Ce
3
0.6
South Cens
6
0.7
West Censu
1
0.5
N/A
1
*
17
:ensus Reg
30
18.3
nsus Regie
8
1.6
us Region
33
4.1
s Region
6
3.1
35
Q
Q
12
ion
7
4.3
n
3
0.6
13
1.6
2
1.0
2
55
10
132
117
71.3
358
70.2
660
81.9
171
89.5
18
*
*
6
*
0.0
2
0.4
3
0.4
4
2.1
N/A
14
0
6
10
6.1
139
27.3
97
12.0
8
4.2
59
70
14
285
165
N/A
513
N/A
812
N/A
192
N/A
Notes: * = < 0.5%; Q = number is withheld because the relative standard error is > 50%.
Source: Energy Information Administration, 2002 Manufacturing Energy Consumption Survey.
Recent engineering practices in states such as California, Wisconsin, and New York indicate
that use of natural gas is even more prevalent in industrial boilers that have been installed
within the past 5 years. This is because industry has switched to natural gas in new boilers
to meet the CM and NESHAP regulations and the associated NOx, SOz, and PM standards.
For example, the CEC Non Residential Market Share Tracking Study shows that 100% of
new industrial boiler applications installed in the years 2000-2002 used natural gas as the
primary fuel, although they often had dual fuel burners to burn diesel in the event of a
natural gas supply disruption.10
Certain industries (paper, refining, chemicals, primary metals) also use by-product fuels
generated by on-site processes. For these industries, by-product use in boilers exceeds that
of natural gas. The decision whether to use these by-products is based on different
parameters than those for using a market fuel. The by-product fuels are typically required
to be combusted, recycled or disposed in an environmentally approved manner and for
10 California Energy Commission, Non Residential Market Share Tracking Study, CEC 400-2005-013,
April 2005.
Climate Leaders
Industrial Boiler Efficiency
August 2008
-19-
-------
specific environmental or financial reasons. Their use in a boiler is, therefore, a separate
decision than what market fuel to use.
Cogeneration applications can also provide process heat at the desired rates and quality.
Because they also provide electricity, however, they offer an additional service that is not
relevant for the industrial boilers addressed in this methodology.
There is no known data set describing the various efficiencies of industrial boilers in the
United States. General engineering practices, however, indicate that industrial boilers are
very similar in design efficiency and generate steam within a narrow range of efficiency.
Differences in actual operating efficiency occur as a result of desired load, steam pressure,
temperature requirements, and local emission thresholds which depend on site-specific
parameters. Although there are no "standard" or "high" efficiency industrial boilers, there
is a range of technology modifications, which can increase the operational thermal
efficiency of the boiler's steam production process, once it is designed or after it is
installed. Combinations of these modifications can increase boiler thermal efficiency to
approximately 90%.
Using industry surveys and general engineering practices, a number of potential technology
options for modifying and improving the efficiency of industrial boilers were identified.
These options are described further in Table Ib. Among the technology options available
for improving the efficiency of industrial boilers, non-condensing economizers and
electronic ignitions are considered standard practices. The other options are not commonly
used and could potentially be used for a GHG offset project. The list of technologies in
Table Ib is not exhaustive and other emerging technologies are potentially eligible as well.
Table Ib. Function and Efficiency of Optional Industrial Boiler Components
Technology Option
Non-condensing
Economizer
(Conventional stack
heat recovery)
Condensing
Economizer
(Condensate heat
recovery)
Description
Recovers heat from the boiler exhaust and is
used to pre-heat the boiler feed water. This
reduces the load on the boiler as the
temperature differential of the feed water in the
boiler is reduced. n-12'13
Performs same function as the non-condensing
economizer but it extracts more heat from the
exhaust stream thereby providing for a higher
inlet feed water temperature. By cooling the
Manufacturer
Specified
Thermal
Efficiency
Value
5%
1%15
Efficiency
Range and
Incremental
Improvement
1-7%
1-2%
Common
Practice
Yes
No
11 U.S. Department of Energy Federal Energy Management Program. "Boiler Checklist"
http://www.eere.energy.gov/femp/operations maintenance/technologies/boilers/checklist.cfm Accessed January 26,
2007
12 Interview-December 20, 2005: Aaron Sink, Engineering Support, Cleaver Brooks (402) 434-2017
13 Nebraska Boiler "Boiler Efficiency Impact" http://www.neboiler.com/Economizer.asp. Accessed January 26, 2007
Climate Leaders
Industrial Boiler Efficiency
August 2008
-20-
-------
Combustion Air Pre-
heaters
(Recuperators)
Slowdown Waste
Heat Recovery
Turbulators (Example
of Advanced Burner)
Oxygen Trim Controls
(Example of
Advanced
Combustion Control)
exhaust air to the point of condensation, the
latent heat of exhaust is captured. H
Preheats the incoming combustion air. This
reduces the load on the boiler by reducing the
energy needed to heat the air from ambient.
Heat is recovered from boiler blowdown through
a heat exchanger and a flash tank. Typically
used to pre-heat boiler make-up water and the
flash tank recovery can be used in the
deaeration or other heating process.
Pieces of metal inserted in the tubes of fire-tube
boilers, causing hot gases to travel more slowly
and with more turbulence, resulting in better
heat transfer to the water.
These controls measure stack gas oxygen
concentration and automatically adjust the inlet
air at the burner for optimum efficiency.
1%
1%
1%
1-2%,
1-2%.
1-2%
1%
No
No
No
No
The CEC 2003 Non-residential Market Share Tracking Study confirms the findings from
Table Ib.17 The purpose of the tracking study was to collect data on market shares,
quantities, and prices of energy-efficient versus standard-efficiency technologies in
California. Data collection involved 560 on-site surveys at manufacturing facilities and
telephone interviews with 104 upstream market entities (manufacturers, distributors,
dealers, installers, and designers). Table Ic shows that the boiler efficiency improvement
options with the greatest overall penetration in the California market are electronic
ignitions (31.1%) followed by conventional (non-condensing) stack heat recovery (22.2%).
Both of these features are considered standard practice in new applications. The overall
penetration of condensate heat recovery (20.9%) is higher than expected, but could be the
result of special incentive programs during the 1980s and 1990s in California.
The second part of Table Ic shows common retrofit items in the three-year period from
2000-2002. The most common retrofits were system energy efficiency changes involving
reduced steam pressure and improved insulation. Steam pressure and pipe insulation
improvements are system changes outside of the defined project boundary for industrial
boiler improvements. The next most common retrofits were electronic ignitions and non-
condensing stack heat recovery. The rest of the boiler improvement options (condensate
heat recovery, other heat recovery (e.g., blow down), 02 trim control, advanced burners)
were performed infrequently and back up the determination that these are not standard
practices.
14 U.S. Department of Energy, Energy Efficiency and Renewable Energy. "Improving Steam System Performance.
http://www 1 .eere.energv.gov/industrv/bestpractices/pdfs/steamsourcebook.pdf. Accessed January 26, 2007
15 Alliant Energy. "HVAC Systems: Boilers"
http://www.alliantenergv.com/docs/groups/public/documents/pub/p012392.hcspffP19 1151. Accessed January 26, 2007.
16 Energy. "HVAC Systems: Boilers"
http://www.alliantenergv.com/docs/groups/public/documents/pub/p012392.hcspffP19 1151. Accessed January 26, 2007.
17 California Energy Commission, Non Residential Market Share Tracking Study, April 2005,
CEC 400-2005-013
Climate Leaders
Industrial Boiler Efficiency
August 2008
-21-
-------
Table Ic. Industrial Gas Boiler Energy Efficiency Measures in California, 2003
SICs 21-34, 37-39
Measures on Existing Boilers
Percent (%)
Stack heat recovery
Condensate heat recovery
Other heat recovery
Automated tuning (02 trim control)
Electronic ignition
Turbulators for firetube boilers
22.2
20.9
7.5
13.8
31.1
9.9
Boiler and System Retrofits in Prior 3 Years (2000-2002)
Stack heat recovery
Condensate heat recovery
Other heat recovery
Automated tuning (O2 trim control)
Electronic ignition
Turbulators for firetube boilers
Increased pipe and jacket insulation (system EE)
Reduced boiler blow-down cycle (system EE)
Reduced steam pressure (system EE)
Variable speed drives on fans (system EE)
Automatic flue damper (system EE)
Smaller boiler for low load conditions (system EE)
Other
10.7
3.0
0.0
1.9
11.8
0.7
22.1
3.6
37.6
2.4
4.3
0.7
0.2
Source: California Energy Commission, Non Residential Market Share Tracking Study, CEC 400-2005-013,
April 2005.
Note: EE = energy efficiency
Spatial Area. A national spatial area was used to develop the performance threshold for
retrofit and new capacity industrial boiler efficiency projects. Engineering parameters for
industrial boiler technology designs are constant and do not vary for geographic reasons.
At least 12 states have developed appliance energy efficiency standards using American
Society of Heating, Refrigerating and Air-Conditioning Engineers (ASHRAE) standards,18 but
in all reviewed cases, these do not impose any specific requirements on industrial boilers.
Therefore, a performance threshold based on a technology standard is not expected to
vary regionally for any mandatory reasons.
Voluntary initiatives such as rebates and tax credits do have an influence on the choice of
equipment used. Utility rebate programs for high efficiency industrial boilers are available
in California, Minnesota, Iowa, New York, and some New England States and can amount
to 25% or more of the installed cost. These are voluntary programs, however, and any
differences in technology implementation in these areas are not used as the basis for a
more stringent threshold in these states.
Temporal Range. The temporal range for the performance threshold is based on the
CEC Non Residential Market Share Tracking Study, ORNL's Characterization of the U.S.
http://www.ase.org/conlent/article/detail/2600
Climate Leaders
Industrial Boiler Efficiency
August 2008
-22-
-------
Industrial Commercial Boiler Population, and current engineering practices and trends
concerning industrial boilers experienced in several states, including New York, Wisconsin,
and California.
Figures la and Ib, which are based on the ORNL study, indicate that sales of industrial
boilers have decreased between 1964 and 2003. This slowing rate of inventory turn-over
could mean that a longer temporal range would be appropriate. Decisions related to
efficiency improvements and fuel switching are, however, to a great extent, based on fuel
prices and economics. Fuel costs began their sharp rise in late 1999 and surged higher
again in 2005 thus providing the basis for more rapid payouts for energy efficiency projects
and thus an increasing number of such activities. Moreover, the CEC Non Residential
Market Share Tracking Study and engineering practices in New Jersey, New York and
Wisconsin indicate that, recently, industry has mostly invested in natural gas-fired boilers
rather than coal or fuel oil boilers. Therefore, a temporal range using current engineering
practices (during the past 5 years) is appropriate.
Figure la. Sales of Boilers > 10 MMBtu/Hour 1964-2003
3,500
:.£.:: .
1.5,::
1,0:: •
Watertube 1D-1DO MMBtu.'hr
Watertube 100-250
Watertube >250 MMBiu.'hr
Source: Oak Ridge National Laboratory, Characterization of the U.S. Industrial Commercial
Boiler Population, May 2005.
Climate Leaders
Industrial Boiler Efficiency
August 2008
-23-
-------
Figure Ib. Sales of Boilers > 100 MMBtu/hour 1964-2003
300 m-
250 •
150 i
100 i
Source: Oak Ridge National Laboratory, Characterization of the U.S. Industrial Commercial
Boiler Population, May 2005.
Climate Leaders
Industrial Boiler Efficiency
August 2008
-24-
-------
Appendix II. Tables for Estimating and Calculating Emissions
Tables Ha - Ilf provide default values that may be used by the project developer for
estimating or calculating GHG emissions where project specific data are not available.
Table Ha. Relationship Between Boiler Thermal Efficiency and CO2 Emissions
Boiler Thermal
Efficiency
80%
81%
82%
83%
84%
85%
86%
87%
88%
89%
90%
91%
92%
93%
94%
Emissions per Heat Output (KgCO2/MMBtu)
Natural Gas Distillate Fuel Oil Residual Fuel Oil Coal
66.3
65.5
64.7
63.9
63.2
62.4
61.7
61.0
60.3
59.6
59.0
58.3
57.7
57.1
56.4
91.4
90.3
89.2
88.1
87.1
86.1
85.1
84.1
83.1
82.2
81.3
80.4
79.5
78.7
77.8
98.5
97.3
96.1
94.9
93.8
92.7
91.6
90.6
89.5
88.5
87.6
86.6
85.7
84.7
83.8
117.5
116.0
114.6
113.2
111.9
110.6
109.3
108.0
106.8
105.6
104.4
103.3
102.2
101.1
100.0
Note: The efficiencies were converted to emissions based on the EPA carbon content coefficients
provided in Table He.
Table lib. CO2 Emission Factors for Various Fuels
Fuel Type
Natural Gas
Distillate Fuel Oil
Residual Fuel Oil
Coal
kg CO2/MMBtu
53.06
73.15
78.80
93.98
Note: Industrial coal value based on Year 2006 "Industrial Other Coal" value.
Source: Inventory of U.S. Greenhouse Gas Emissions and Sinks 1990-2006, April 2008. U.S.
Environmental Protection Agency.
Climate Leaders
Industrial Boiler Efficiency
August 2008
-25-
-------
Table He. Default CH4 and N2O Emission Factors for Natural Gas, and Fuel Oil,
Coal
Fuel Type
Natural Gas
Petroleum (Commercial sector)
Petroleum (Industrial sector)
Coal
Greenhouse Gas
CH4
N2O
CH4
N2O
CH4
N2O
CH4
N2O
Emissions per Unit of Fuel Input
(kg CO2e/MMBtu)
0.105
0.031
0.231
0.186
0.063
0.186
0.231
0.496
Source: Inventory of U.S. Greenhouse Gas Emissions and Sinks 1990-2006. U.S.
Environmental Protection Agency, April 2008.
Table lid. Default CH4 and N2O Emission Factors for Electricity
Fuel Type
Natural Gas
Petroleum
Coal
Greenhouse Gas
CH4
N2O
CH4
N2O
CH4
N2O
Emissions per Unit of Fuel Input
(kg CO2e/MMbtu)
0.021
0.031
0.063
0.031
0.021
0.496
Note: Electricity emissions of CH4 and N2O relate to the fuel used to produce the electricity.
Information on fuel type will be needed to estimate CH4 and N2O.
Source: Inventory of U.S. Greenhouse Gas Emissions and Sinks 1990-2006. U.S.
Environmental Protection Agency, April 2008.
Table He. Emission Factors for Electricity Use by Project Equipment by eGRID
Subregion (2004)
eGRID Subregion
AKGD* (Alaska Grid)
AKMS (Alaska Miscellaneous)
AZNM (WECC- Southwest)
CAMX (WECC- California)
ERCT (Texas)
States included in
eGRID Subregion
AK
AK
AZ, CA, NM, NV, TX
CA, NV, UT
TX
NERC
Region
ASCC
ASCC
WECC
WECC
ERGOT
Emission factor
for electricity
used by project
equipment (kg
CO2/kWh)
0.604
0.630
0.634
0.572
0.600
Climate Leaders
Industrial Boiler Efficiency
-26-
August 2008
-------
FRCC (Florida)
HIMS (Hawaii- Miscellaneous)
HIOA* (Hawaii- Oahu)
MORE (Midwest- East)
MROW (Midwest- West)
NEWE (New England)
NWPP (WECC- Northwest)
NYCW (New York- NYC, Westchester)
NYLI (New York- Long Island)
NYUP (New York- Upstate)
RFCE (RFC- East)
RFCM (RFC- Michigan)
RFCW (RFC- West)
RMPA (WECC- Rocky Mountains)
SPNO (SPP- North)
SPSO (SPP- South)
SRMV (SERC- Mississippi Valley)
SRMW (SERC- Midwest)
SRSO (SERC- South)
SRTV (SERC- Tennessee Valley)
SRVC (SERC- Virginia/Carolina)
FL
HI
HI
MI.WI
IA, IL, Ml, MN, MT, ND, NE,
SD, Wl, WY
CT, MA, ME, NH, NY, Rl, VT
CA, CO, ID, MT, NV, OR,
UT, WA, WY
NY
NY
NJ, NY, PA
DC, DE, MD, NJ, PA, VA
Ml
IL, IN, KY, MD, Ml, OH, PA,
TN, VA, WI.WV
AZ, CO, NE, NM, SD, UT,
WY
KS, MO
AR, KS, LA, MO, NM, OK,
TX
AR, LA, MO, MS, TX
IA, IL, MO, OK
AL, FL, GA, MS
AL, GA, KY, MS, NC, TN
GA, NC, SC, VA, WV
FRCC
HICC
HICC
MRO
MRO
NPCC
WECC
NPCC
NPCC
NPCC
RFC
RFC
RFC
WECC
SPP
SPP
SERC
SERC
SERC
SERC
SERC
0.612
0.738
0.783
1.005
1.050
0.641
0.770
0.788
0.686
0.821
0.800
0.880
0.951
0.778
1.007
0.699
0.634
0.979
0.847
0.941
0.890
Note: The emission factors in Table II.e reflect variations in electricity use by project equipment
across regions and load type (i.e., base versus non-baseload). Coincident peak demand factors
from a 2007 ACEEE study were combined with EPA's eGRID emission factors for baseload and non-
baseload power to derive the emission factors presented in this table.19'20
Table I If. Default Fugitive CH4 Emission Factors for Natural Gas Distribution
Systems
Pipeline Leaks
Distribution Mains - Cast Iron
Distribution Mains - Unprotected steel
Distribution Mains - Protected steel
Distribution Mains - Plastic
Services- Unprotected Steel
Services- Protected Steel
Mscf/mile-yr
Mscf/mile-yr
Mscf/mile-yr
Mscf/mile-yr
Mscf/service
Mscf/service
2004
238.70
110.19
3.07
9.91
1.70
0.18
19 York, D. Kushler, M. Witte, P. "Examining the Peak Demand Impacts of Energy Efficiency: A Review of Program
Experience and Industry Practice." American Council for and Energy-Efficient Economy (ACEEE). February 2007.
http://www.aceee.org/pubs/u071.htm.
20 The Emissions & Generation Resource Integrated Database (eGRID) is a comprehensive inventory of environmental
attributes of electric power systems, available at http://www.epa.gov/cleanenergy/energy-resources/egrid/index.html.
Climate Leaders
Industrial Boiler Efficiency
August 2008
-27-
-------
Services- Plastic
Services- Copper
Mscf/service
Mscf/service
0.01
0.25
Source: U.S. Environmental Protection Agency, Inventory of U.S. Greenhouse Gas Emissions and
Sinks 1990-2006, April 2008.
Climate Leaders
Industrial Boiler Efficiency
August 2008
-28-
-------
United States
Environmental Protection
Agency
Office of Air and Radiation (6202J)
EPA400-S-08-001
August 2008
www.epa.gov/climateleaders
Climate Leaders August 2008
Industrial Boiler Efficiency - 29 -
------- |