&EPA
Office of Air and Radiation April 21, 2022
United States
Environmental Protection
Agency
AVAILABLE AND EMERGING TECHNOLOGIES
FOR REDUCING GREENHOUSE GAS EMISSIONS
FROM COMBUSTION TURBINE
ELECTRIC GENERATING UNITS
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Available and Emerging Technologies for Reducing
Greenhouse Gas Emissions from Combustion Turbine
Electric Generating Units
Prepared by the
Sector Policies and Programs Division
Office of Air Quality Planning and Standards
U.S. Environmental Protection Agency
Research Triangle Park, North Carolina 27711
April 21, 2022
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Table of Contents
List of Exhibits iii
Acronyms and Abbreviations iv
1.0 Introduction 6
2.0 Clean Air Act Requirements 7
2.1 Regulation of GHG Emissions from Combustion Turbines Under CAA Section
111 7
2.2 Regulation of GHG Emissions from Combustion Turbines Under the CAA PSD
Permitting Program 7
2.3 Reducing GHG Emissions through Non-CAA Programs 8
3.0 Combustion Turbine Technology 10
3.1 Electric Power Generation Using Combustion Turbines 10
3.2 Simple Cycle EGUs and the Brayton Cycle 11
3.3 Combined Cycle EGUs and the Rankine Cycle 12
4.0 GHG Emissions from Combustion Turbine EGUs 14
5.0 Combustion Turbine EGU GHG Control Approaches 18
5.1 Impact of EGU Efficiency on CO2 Emissions 18
5.2 Efficiency Improvements 20
5.2.1 Selection of the Type of Combustion Turbine 21
5.3 Simple Cycle Combustion Turbines 21
5.3.1 Maximum Theoretical Combustion Turbine Efficiency 22
5.3.2 Impact of Ambient Conditions on Simple Cycle Combustion Turbines...24
5.4 Combined Cycle Combustion Turbines 24
5.4.1 Fast Start/Flexible Combined Cycle EGUs 26
5.4.2 Duct Burner/Supplemental Firing 27
5.4.3 Cooling Technology for Rankine Cycle 27
5.4.4 Impact of Ambient Conditions on Combined Cycle EGUs 28
5.4.5 Potential Efficiency Gains in the Bottoming Cycle 29
5.5 Combined Heat and Power (CHP) Plant 30
5.6 Integrated Non-Emitting Generation 31
5.6.1 Steam-Cycle Integrated Renewables 32
5.6.2 Energy-Output Integrated Renewables 33
5.6.3 Integrated Energy Storage 36
5.7 Post-Combustion Carbon Capture, Utilization, and Storage (CCUS) 39
5.8 Oxygen Combustion 40
5.8.1 The Allam-Fetvedt Cycle 41
5.9 Hydrogen 42
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5.9.1 Ammonia 45
6.0 Fuels Burned in Combustion Turbine EGUs and Overall GHG Considerations 46
6.1 Methane Emissions 47
6.2 Conventional and Unconventional Natural Gas 48
6.2.1 Avoided Methane Emissions Associated with Natural Gas 50
6.3 Methane Emissions from Abandoned Oil and Gas Wells 51
6.4 Coal Mine Methane (CMM) 52
6.5 Biogas and Biomethane 52
6.5.1 Upstream Biogas GHG Emissions 53
6.6 Industrial Byproduct Fuels 55
6.7 Liquid Fuels 55
7.0 Embodied Carbon of a Combustion Turbine EGU 56
8.0 Alternative to Combustion Turbines 57
EPA Contacts 58
References 59
ii
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List of Exhibits
Exhibit 3-1. Comparison of annual net generation (MWh) by technology 2010 vs. 2019 11
Exhibit 3-2. Simplified schematic of a simple cycle combustion turbine operating in the
thermodynamic cycle known as the Brayton cycle 12
Exhibit 3-3. Simplified schematic of combustion turbine operating in the thermodynamic
cycle known as the "combined cycle" that converts thermal energy to electrical energy
using the Brayton cycle combined with the Rankine cycle 13
Exhibit 4-1. Fossil fuels compared by lb CO2 perMMBtu of energy produced.' 14
Exhibit 4-2. Share of net electricity generation by source 15
Exhibit 4-3. CO2 emissions by power sector fuel type 15
Exhibit 5-1. Brayton cycle theoretical efficiency (Ginsberg, 2016) 22
Exhibit 5-2. Design efficiency of simple cycle combustion turbines 23
Exhibit 5-3. Comparison of industrial Trent 60 WLN and DLE performance 24
Exhibit 5-4. Combined cycle efficiency 25
Exhibit 5-5. Impact of temperature on combined cycle performance 29
Exhibit 5-6. Hybrid/co-located projects of various configuratons 32
Exhibit 5-7. Co-located hybrid power plants 34
Exhibit 5-9. Energy Storage Technologies 36
Exhibit 5-10. Capacity share of different storage technologies 38
Exhibit 5-11. Simplified schematic of a combustion turbine operating in the thermodynamic
cycle known as the Allam-Fetvedt cycle 41
Exhibit 5-12. Types of Hydrogen Production 44
Exhibit 5-13. Hydrogen to methane fuel blend volume ratios and CO2 reductions 45
Exhibit 6-1. Schematic geology of natural gas resources 49
Exhibit 6-2. U.S. natural gas marketed production 50
111
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Acronyms and Abbreviations
BACT
Best Available Control Technology
BFG
blast furnace gas
Btu
British thermal unit
CAA
Clean Air Act
ecus
carbon capture, utilization, and storage
ch4
methane
CHP
combined heat and power
CO
carbon monoxide
C02
carbon dioxide
DLE
dry low emissions
DLN
dry low-NOx
DOE
Department of Energy
EGU
electric generating unit
EIA
Energy Information Administration
EPA
Environmental Protection Agency
EPRI
Electric Power Research Institute
g/kWh
grams per kilowatt-hour
GHG
greenhouse gas
GW
gigawatt
GWP
Global Warming Potential
HAP
hazardous air pollutant
HFC
hydrofluorocarbon
HHV
higher heating value
HRSG
heat recovery steam generator
IGCC
integrated gasification combined cycle
kg
kilogram
kJ
kilojoule
kW
kilowatt
kWe
kilowatt electrical
kWh
kilowatt-hour
iv
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KV
kilovolt
LCOE
levelized cost of electricity
LHV
lower heating value
Mg
megagram
MMBtu/hr
million British thermal units per hour
MPa
megapascal
MW
megawatt
MWe
megawatt electrical
MWh
megawatt-hour
MSW
municipal solid waste
n2
nitrogen
n2o
nitrous oxide
NETL
National Energy Technology Laboratory
NOx
nitrogen oxides
NREL
National Renewable Energy Laboratory
NSR
New Source Review
02
oxygen
PFC
perfluorocarbon
ppmv
parts per million volume
PSD
prevention of significant deterioration
PV
photovoltaic
RICE
reciprocating internal combustion engine
SCR
selective catalytic reduction
sf6
sulfur hexafluoride
SNCR
selective noncatalytic reduction
U.S.
United States
USD A
U.S. Department of Agriculture
WLE
wet low emissions
WLN
wet low-NOx
V
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1.0 Introduction
This white paper summarizes readily available information on control techniques and measures
with the potential to mitigate greenhouse gas (GHG) emissions from stationary combustion
turbines permitted to operate as electric utility generating units (EGUs).1 A discussion of the
basic types of available stationary combustion turbines is included as well as factors that
influence GHG emission rates from these sources. The subsequent technology discussion
includes information on an array of control technologies and potential reduction measures for
GHG emissions.
The information in this white paper is intended to assist states and local air pollution control
agencies, tribal authorities, and regulated entities in their consideration of technologies and
measures that may be implemented to reduce GHG emissions from stationary combustion
turbines. The discussion of technologies and measures in this paper may also provide context for
permit development under the prevention of significant deterioration (PSD) program of the Clean
Air Act (CAA), including in the assessment of the best available control technology (BACT) for
GHG emissions from stationary combustion turbines. The range of technologies and measures
included is comprehensive enough that this discussion may also inform state programs or
initiatives to further reduce GHG emissions from stationary combustion turbines. Similarly, the
information herein may also be useful to EPA in future development of new source performance
standards (NSPS), which must be based on the "best system of emission reduction ... adequately
demonstrated."2
This white paper focuses on a review of technologies and measures that can reduce the GHG
emissions associated with electricity generation from stationary combustion turbines. This white
paper does not set policy or establish emissions or performance standards, or otherwise establish
any binding requirements. Critically, the information presented in this document does not
represent EPA endorsement of any particular control strategy for any particular purpose. While
some developing technologies are noted as such, inclusion in this white paper generally
represents that a technology or measure is sufficiently well-developed that it could be
constructed and successfully operated to achieve its intended purpose in the identified
applications but not necessarily that it meets the applicable standard for it to be required under
any particular regulatory program, either as a general matter for a class or category of sources or
for any particular application on a case-by-case basis. As such, it should not be construed as EPA
approval of a particular control technology or measure, or of the emissions reductions that could
be achieved by a class or category of sources or a particular unit or source. With regard to
permitting decisions specifically, this white paper does not set forth any requirements for a
permitting authority to consider a process or control technology within the scope of review for an
application to approve a particular stationary combustion turbine project. Finally, this paper does
not necessarily address all potentially available GHG reduction technologies or measures that
may be considered for any given source.
1 While this white paper focuses on GHG mitigation options for stationary combustion turbines that operate as
EGUs, some of the technologies may also be available for GHG mitigation at stationary combustion turbines that
operate in other industrial sectors.
2 See Clean Air Act §111(a)(1).
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2.0 Clean Air Act Requirements
Emissions from stationary combustion turbines are addressed under a variety of federal, state,
and voluntary programs. This section presents a brief, non-exhaustive overview of several
contexts in which the technical information contained in this white paper may be relevant.
2.1 Regulation of GHG Emissions from Combustion Turbines Under CAA Section 111
Under authority of CAA section 111, EPA establishes emissions requirements for categories of
industrial facilities, also called stationary sources, that cause or contribute significantly to air
pollution that may endanger public health or welfare. Under CAA section 111(b), EPA
establishes NSPS for new, reconstructed, and modified stationary sources. To set the NSPS for a
particular source category, EPA determines the best system of emission reduction (BSER) that
has been "adequately demonstrated," taking into account costs and any non-air quality health and
environmental impacts and energy requirements. Under CAA section 111(d), for certain
pollutants EPA establishes emission guidelines for states to use in preparing plans establishing
performance standards for existing sources. These emission guidelines likewise include the
EPA's determination of BSER for the existing sources in the source category.
In 2015, EPA issued the final NSPS to limit emissions of GHG pollution manifested as carbon
dioxide (CO2) from stationary combustion turbines. These standards, codified in 40 CFR part 60,
subpart TTTT, reflect the degree of emission limitation achievable through the application of
BSER to three subcategories of stationary combustion turbines: base load EGUs, non-base load
natural gas-fired EGUs, and non-base load multifuel-fired (i.e., non-natural gas-fired) EGUs. The
emissions standard for new and reconstructed base load combustion turbines is 1,000 pounds of
CO2 emitted per megawatt hour-gross of operation (lb CCh/MWh-gross). The emissions
standards for non-base load natural gas-fired and non-base load multifuel-fired EGUs are based
on the use of natural gas and number 2 fuel oil, respectively.
2.2 Regulation of GHG Emissions from Combustion Turbines Under the CAA PSD
Permitting Program
The CAA sets forth the requirements for a permitting program known as New Source Review
(NSR), which governs the construction of stationary sources of air pollution. NSR requires such
sources emitting above specified levels to obtain permits containing limitations on their air
pollutant emissions before they are first constructed or before they engage in a modification of
an existing facility. The NSR program is composed of the following three principal components:
(1) the PSD program, which sets forth the permitting requirements for new major stationary
sources and major modifications of such sources constructed in areas that meet the National
Ambient Air Quality Standards (NAAQS), known as "attainment" areas, and in areas for which
there is insufficient information to classify an area as either attainment or nonattainment
("unclassifiable" areas); (2) the nonattainment NSR program, which establishes permitting
requirements for major stationary sources and major modifications of such sources in areas that
do not meet the NAAQS; and (3) the minor NSR program, which applies to sources and
modifications that do not emit or increase emissions above "major" levels as defined in the CAA
and EPA regulations. The CAA directs states to implement these programs in the first instance,
but EPA also implements these programs where states fail to do so or in areas of exclusive
federal jurisdiction.
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GHGs are regulated under the CAA's PSD program, but not the other components of the NSR
program.3 For PSD, section 165 of the CAA requires that the permitting authority establish
emissions limitations based on BACT for each new source or modified emissions unit that is
required to obtain a permit under this program. BACT must be assessed on a case-by-case basis,
and the permitting authority, in its analysis of BACT for each pollutant, must evaluate the
emissions reductions that each available emissions-reducing technology or technique would
achieve, as well as the energy, environmental, economic, and other costs associated with each
technology or technique. The CAA also specifies that BACT cannot be less stringent than any
applicable standard of performance under the NSPS.4
In determining BACT, many permitting authorities apply EPA's five-step "top-down" approach,
which is most comprehensively described in EPA's NSR Workshop Manual (U.S. EPA, 1990 -
Draft) and PSD and Title V Permitting Guidance for GHGs (U.S. EPA, 2011). This approach is
not required but is a method that EPA uses to ensure that all the criteria in the CAA's definition
of BACT are considered. The "top-down" approach begins with the permitting authority
identifying all available control options that have the potential for practical application for the
regulated NSR pollutant and emissions unit under evaluation. The analysis then evaluates each
option and eliminates options that are technically infeasible, ranks the remaining options from
most to least effective, evaluates the energy, environmental, economic impacts, and other costs
of the options, eliminates options that are not achievable based on these considerations from the
top of the list down, and ultimately selects the most effective remaining option as BACT. Given
the CAA's direction that BACT be determined on a case-by-case basis, and the discretion
afforded to individual permitting authorities under the applicable criteria, BACT determinations
for similar types of projects can sometimes differ from one permit to another based on particular
circumstances.
2.3 Reducing GHG Emissions Through Non-CAA Programs
Many states have enacted laws and other programs and initiatives that are aimed at reducing
GHG emissions. These GHG reduction programs are independent of any applicable CAA
requirements but may nevertheless influence decisions being made by industry and state
authorities as they evaluate the overall GHG emissions outcomes of new combustion turbine
projects. Such programs include New York's Climate Leadership and Community Protection
Act, the California Global Warming Solutions Act of 2006 ("AB 32"), and a host of state-
specific renewable fuel standards. Permitting and other authorities responsible for implementing
these laws and programs may be subject to different and/or additional requirements and
considerations for potential GHG reduction approaches for new combustion turbines than exist
under the CAA. Examples of some of these potential GHG reduction approaches are contained in
this white paper and are intended to share information that may be helpful under the full range of
relevant contexts, whether under the CAA or not, when evaluating proposed combustion turbine
projects.
In addition, some individual companies have established corporate goals and commitments to
reduce GHG emissions within their own operations, independent of any regulatory or other
3 The PSD program treats GHG as a single air pollutant defined as the aggregate group of the following six gases:
CO2, nitrous oxide (N20), methane (CH4), hydrofluorocarbons (HFCs), perfluorocarbons (PFCs), and sulfur
hexafluoride (SF6).
4 CAA 165(a)(4), 169(3).
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requirement. These efforts may include onsite CO2 reduction measures as well as offsite
measures that consider the overall GHG emissions, including those associated with fuel
production or procurement upstream of the facility (e.g., entities committing to only purchase
natural gas from suppliers that demonstrate they have minimized emissions in the production
supply chain of the gas). As companies continue to make voluntary commitments to reduce GHG
emissions5 both onsite and offsite, EPA believes they may benefit from considering the GHG
reduction strategies discussed in this white paper.
5 See, e.g., https://www.theclimatepledge.com/us/en: https://www.utilitvdive.com/news/xcel-looks-to-gas-suppliers-
with-lower-methane-emissions-in-colorado/600108/: https://www.bloomenergy.com/applications/certified-gas/:
https ://www.bloomenergy .com/applications/bio gas/.
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3.0 Combustion Turbine Technology
This section provides a description of the primary thermodynamic cycles used by combustion
turbines and describes the types of combustion turbines used to generate electricity. Combustion
turbine EGUs meet all types of electrical demand—baseload, intermediate, and peaking—and
can be quickly dispatched (C2ES, n.d.). As solar, wind, and storage capacities increase,
combustion turbines are expected to provide backup power and ancillary services that contribute
to dynamic grid stability.
3.1 Electric Power Generation Using Combustion Turbines
Electricity is generated at most electric power plants using mechanical energy to rotate the shaft
of electromechanical generators. Mechanical work is produced from thermal energy through the
combustion of fossil fuels or nuclear fission; from the kinetic energy harnessed from flowing
water, wind, or tides; or from the thermal energy from geothermal wells or concentrated solar
arrays. Electricity also can be produced directly from sunlight using photovoltaic (PV) cells or
by using a fuel cell to electrochemically convert chemical energy into an electric current.
The combustion of fossil fuel to generate electricity can occur either in a steam generating unit
{i.e., boiler) to feed a steam turbine that, in turn, spins an electric generator, or in a combustion
turbine or reciprocating internal combustion engine (both spark ignition and compression
ignition) that directly drives the generator. A power plant that uses a stationary combustion
turbine to directly generate electricity is often referred to as a "simple cycle" plant. Some power
plants use a "combined cycle" electric power generation process in which a gaseous or liquid
fuel is burned in a combustion turbine that drives an electrical generator and provides heat to
produce steam in a heat recovery steam generator (HRSG).6 The steam produced by the HRSG
is then fed to a steam turbine that drives a second electric generator. The combination of using
the chemical energy released by burning a fuel to drive both a combustion turbine generator and
a steam turbine generator significantly increases the overall efficiency of the electric power
generation process. Combined cycle EGUs generally range in capacity from 40 megawatts (MW)
up to 1.3 gigawatts (GW).7 In the U.S. in 2019, approximately 38 percent of net electricity was
produced using natural gas. Natural gas-fired combined cycle EGUs accounted for about 33
percent and simple cycle generators (all fuels) produced 3.3 percent of total net generation.8
Exhibit 3-1 summarizes the differences in generating technologies used in 2010 compared to
2019 and shows how the use of combustion turbine technologies has increased during the past
decade.
6 As described in more detail in section 5.4.2, duct firing (sometimes referred to supplementary firing) adds
additional thermal energy input to the HRSG.
7 According to the specifications in Gas Turbine World (GTW), the largest combined cycle EGUs available in the
U.S. are comprised of two turbine engines that are rated at 430 MW each combined with a single 440-MW steam
turbine.
8 EIA 923 data can be downloaded from https://www.eia.gov/electricitv/data/eia923/.
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Exhibit 3-1. Comparison of annual net generation (MWh) by technology 2010 vs. 2019.
Generating Technology
2010 Net MWh and
Percentage of Total
2019 Net MWh and
Percentage of Total
Combined Cycle Natural Gas
813,117,886
20%
1,350,891,889
33%
Simple Cycle (all fuels)
92,575,530
2.1%
136,146,724
3.3%
Reciprocating Engine
8,863,272
0.21%
16,092,423
0.39%
Coal Steam Turbine
1,834,372,360
44%
958,047,858
23%
Nuclear
806,968,301
20%
809,409,262
20%
Fuel Cell
11,379
0.0%
1,645,022
0.04%
Hydro
260,203,069
6.3%
287,873,730
7.0%
Wind
94,652,246
2.3%
295,882,949
7.2%
Utility Solar
422,831
0.011%
68,718,894
1.7%
Small-Scale Photovoltaic9
1,281,000
-
34,957,000
-%
Source: U.S. Energy Information Administration (EIA) (2021b)
Among the technologies used as prime movers10 for stationary and mobile energy conversion
applications, combustion turbines can have high power-to-weight ratios with greater than 10
kilowatts (kW) per kilogram (kg). Designs can range from refrigerator-size "microturbines" with
rated outputs as low as 30 kW to utility-scale "heavy frame" units that are more than 30 feet long
and 10 feet in diameter and with rated outputs of approximately 400 MW. These various
characteristics enable designers to incorporate combustion turbines into a wide range of mobile
applications, including propulsion systems for ships, military vehicles, and aircraft. Stationary
applications are also diverse and include mechanical drive systems for industrial compressors
and pumps. This document focuses on control techniques and measures that are available to
mitigate GHG emissions from stationary combustion turbines used as prime movers for EGUs.
3.2 Simple Cycle EGUs and the Brayton Cycle
Combustion turbines operate using the Brayton thermodynamic cycle. Exhibit 3-2 presents a
simple schematic of the three primary components of combustion turbines: compressor (C),
combustion chamber (i.e., combustor), and turbine (T). In the Brayton cycle, a multistage
compressor (1-2) is used to supply large volumes of high-pressure air to a combustion chamber.
The combustion chamber (2-3) ignites fuel to heat and expand the compressed air. By heating the
compressed air, the combustion chamber provides the turbine with a high volume of high-
pressure, high-temperature gas that can be converted to shaft work as the hot gas expands
through the multistage turbine blades. Expansion of the gases through the turbine causes the
blades and shaft to rotate and produce shaft work (Ws). Most of the shaft work produced (55 to
65 percent) is used by the compressor with the remainder available for driving an electric
generator or a mechanical drive system.
9 Estimated using data from the U.S. Energy Information Administration's (EIA) State Energy Data Systems
(SEDS) (https://www.eia.gov/state/seds/seds-data-complete.php?sid=US#CompleteDataFile). EIA Table 1.1. A, Net
Generation from Renewable Sources, and the Solar Energy Industries Association (https://www.seia.org/solar-
industrv-re search-data).
10 A device that converts a non-electrical form of energy to electrical energy.
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Exhibit 3-2. Simplified schematic of a simple cycle combustion turbine operating in the
thermodynamic cycle known as the Brayton cycle.
1 - Ambient air enters the compressor.
2 - Compressed air [pre-mixed with fuel on dry low-nitrogen oxide (NOx) or DLN system] enters combustion
chamber.
3 - High-pressure (up to 30 Bar) hot gases (900 to 1,400 °C) exit combustion chamber and enter gas turbine.
4 - Hot (450 to 650 °C) exhaust gases [including nitrogen (N2), oxygen (O2), CO2, NOx, and carbon monoxide
(CO)] exit turbine:
a. In simple cycle units these gases are vented to the atmosphere through a stack.
b. In combined cycle EGUs these gases are sent through an HRSG before being exhausted to the
atmosphere through a stack. See Exhibit 3-3.
5 - The net work (Wnet) available for turning an electric generator or mechanical drive system is the total energy
extracted from the hot gases (4 minus 3) less the work necessary to operate the compressor.
Combustion turbines that vent the high-temperature exhaust gases directly to the atmosphere
without recovering additional useful output are called simple cycle turbines. Simple cycle
turbines have relatively low capital costs and can start and change load quickly. Therefore, they
are often used to supply electricity during periods of high demand (i.e., peaking EGUs) and act
as backup for intermittent forms of generation such as wind and solar.11
3.3 Combined Cycle EGUs and the Rankine Cycle
As shown in Exhibit 3-2 at 4b, when the exhaust gas (i.e., flue gas) from the Brayton cycle is
routed to an HRSG operating in the Rankine cycle,12 the resulting thermodynamic cycle is called
a "combined cycle." Exhibit 3-3 provides a detailed schematic of a combined cycle EGU.
Combined cycle installations are commonly called power blocks with two leading numbers that
designate the number of combustion turbine generator sets and the number of steam turbine
generator sets, respectively. For example, a "3-on-l combined cycle power block" designates
three combustion turbine generators and one steam turbine generator.
Combined cycle EGUs have higher capital costs and are more efficient, but not as flexible as
simple cycle EGUs. Therefore, combined cycle EGUs have typically been used for base load and
11 The generation from wind and solar EGUs is determined by atmospheric conditions that are not necessarily
related to end user electric demand. As more electricity is generated from these intermittent sources, to continue to
provide reliable power, utilities need to either invest in dispatchable forms of electric generation energy storage, or
demand-side programs where end users agree to curtail demand when generation is not able to keep up with
demand.
12 The Rankine cycle is a thermodynamic cycle that converts heat to mechanical energy—which is then often
converted to electrical energy—using an evaporation and condensation cycle. It is widely used in coal-fired and
nuclear power plants as well as the HRSG in a combined cycle EGU.
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intermediate load generation. However, "flexible" and "fast-start" combined cycle EGUs can
start more quickly than traditional combined cycle designs and are intended to be capable of
supporting intermittent renewable generation. It should be noted that flexible and fast-start
combined cycle EGUs typically have additional capital and operating expenses compared to
combined cycle EGUs intended primarily for base load operation.
Exhibit 3-3. Simplified schematic of combustion turbine operating in the thermodynamic
cycle known as the "combined cycle" that converts thermal energy to electrical energy
using the Brayton cycle combined with the Rankine cycle.
Fuel p—
1^4.
Combustor
c
W,
compressor
Stack
Approximately 30 to 40 percent of thermal energy in combustion
products supplied to gas turbine can be converted to electrical energy.
5
Wnet
HP Steam
Electric
Generator
MWe
to Grid
_r
HRSG
51 - High-pressure feedwater enters the boiler (HRSG).
52 - Superheated, high-pressure steam exits HRSG
and enters steam turbine (ST).
53 - Low-pressure steam exits turbine and enters condenser.
54 - Low-pressure condensate is routed
to high-pressure feedwater pump.
r
S2
Approximately 30 percent of the thermal
enetgvsupplied to HRSG can be converted
to^lectricalenerm.
ST
Electric
Generator
SI
LP Steam
Feedwater
Pump
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4.0 GHG Emissions from Combustion Turbine EGUs
The principal GHGs that accumulate in the Earth's atmosphere above pre-industrial levels
because of human activity are CO2, methane (CH4), nitrous oxide (N2O), hydrofluorocarbons
(HFCs), perfluorocarbons (PFCs), and sulfur hexafluoride (SFr,). Of these, CO2 is the most
abundant, accounting for 80 percent of GHGs present in the atmosphere, largely due to the
combustion of fossil fuels by the transportation, electricity, and industrial sectors (U.S. EPA,
2021c). The amount of CO2 emitted from fossil fuel-fired EGUs depends on the carbon content
of the fuel and the size and efficiency of the EGU.
Different fuels emit different amounts of CO2 in relation to the energy they produce when
combusted. The amount of CO2 produced when a fuel is burned is a function of the carbon
content of the fuel. The heat content, or the amount of energy produced when a fuel is burned, is
mainly determined by the carbon and hydrogen content of the fuel. Exhibit 4-1 shows that, in
terms of pounds of CO2 emitted per million British thermal units of energy produced, when
combusted, natural gas is the lowest compared to other fossil fuels.
Exhibit 4-1. Fossil fuels compared by lb CO2 per MMBtu of energy produced.13'14
Coal (anthracite)
228.6
Coal (lignite)
215.4
Coal (subbituminous)
214.3
Coal (bituminous)
205.7
Diesel fuel and heating oil
161.3
Gasoline (without ethanol)
157.2
Propane
139.0
Natural Gas
117.0
Significant CO2 reductions have occurred in the power sector as generation has transitioned to
less use of coal and greater use of natural gas. In Exhibit 4-2 below, data from the U.S. Energy
Information Administration (EIA) illustrates this transition from 1990 to 2018 in terms of
percent of net electric generation by source. Note the mirrored relationship of the coal (blue) and
natural gas (green) generation trend lines.
13 Values reflect the carbon content on a per unit of energy produced on a higher heating value (HHV) combustion
basis and are not reflective of recovered useful energy from any particular technology.
14 Natural gas is primarily methane (CH4), which has a higher energy content relative to other fuels, and thus, has a
relatively lower CCh-to-energy content. Water and other compounds, such as sulfur and noncombustible elements in
some fuels, reduce their heating values and increase their CCh-to-heat contents.
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Exhibit 4-2. Share of net electricity generation by source.
60%
40%
| 50%
I
20%
10%
1990 1995 2000 2005 2010 2015
—Coal —Natural Gas —Nuclear —Nonhydro Renewables —Hydro —Other
Exhibit 4-3 shows EIA power sector CO2 emissions over time by fuel type. Note the gradual but
steady increase in CO2 emissions from natural gas (pink line) due to the expansion of
combustion turbine capacity since the early 2000s. Power generation from natural gas-fired
combustion turbines is projected to increase as more coal-fired EGUs retire and new combustion
turbines are added to the electric grid—in many instances to respond to demand fluctuations
caused by expanded generation from intermittent solar and wind (Lin, 2019).
Exhibit 4-3. CO2 emissions by power sector fuel type.
2005 2010
— Coal —Natural Gas Petroleum —Non-Biomass Waste —Total
The primary GHG emitted by combustion turbine EGUs is CO2, and that pollutant is the focus of
the onsite control technologies and measures presented in this white paper. Emissions of methane
from the turbine exhaust are typically extremely low. However, during the production,
transportation, and distribution of natural gas, methane can be emitted to the atmosphere. The
Global Warming Potential (GWP) of methane is from 28 to 36 times stronger than that of CO2
15
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over 100 years.15 While methane is relatively short-lived, with an atmosphere lifetime of about a
dozen years, the increase in CO2 concentrations due to CO2 emissions can persist for centuries or
more (U.S. EPA, 2020c).
Nitrous oxide may be formed during the combustion of fossil fuels from a series of reactions.
However, nitrous oxide formation from the combustion of natural gas in a combustion turbine is
generally less than 1 part per million (ppm) during steady state operation but can rise to several
ppm during transient operation (Colorado et al., 2017). Additional nitrous oxide can be formed
by the selective catalytic reduction (SCR) systems that are often used to control emissions of
smog-forming nitrogen oxides {i.e., NOx, which is a mixture of nitric oxide (NO) and nitrogen
dioxide (NO2)). SCR systems using vanadium and vanadium-tungsten catalysts that are designed
for use in combined cycle EGUs typically operate between 260 and 400 degrees Celsius (°C)
(500 to 750 degrees Fahrenheit (°F)). At these temperatures, formation of nitrous oxide is not
expected to be significant; however, at temperatures above 400 °C (750 °F), the reaction kinetics
for nitrous oxide formation become much more favorable, resulting in a potential increase in
emissions. This is especially important for simple cycle EGUs, which can have exhaust
temperatures of up to 600 °C (1,100 °F) and can use a high-temperature SCR operating at 470 to
580 °C (880 to 1,075 °F). Tempered air can be added to the turbine exhaust prior to the SCR to
reduce exhaust gas temperatures. However, this can increase the cost of the SCR system.
Test data from commercial-scale operations are not readily available to confirm if additional
nitrous oxide is formed in high-temperature SCR systems. It is plausible that other factors, such
as the catalyst structure and the amount of ammonia slip16 may also impact nitrous oxide
formation. Companies may be able to provide additional information regarding their specific
SCR system and its anticipated nitrous oxide formation to determine if emissions testing is
required for nitrous oxide.
Hydrofluorocarbons and sulfur hexafluoride are not formed as a byproduct of combustion in a
fossil fuel-fired turbine. However, as with all EGUs, sulfur hexafluoride might be used at a
power plant switchyard to insulate equipment. Sulfur hexafluoride is a strong GHG, and a certain
amount of sulfur hexafluoride used by an insulator is emitted to the atmosphere through leaks
and servicing of the equipment. Several states have initiatives requiring that these GHG
emissions be reduced by maintaining annual sulfur hexafluoride emission rates for new and
existing equipment to 1 percent or less of the sulfur hexafluoride used on the insulating
equipment. Furthermore, alternatives to sulfur hexafluoride are readily available for low and
medium (up to 72.5 kilovolt (kV)) voltage equipment, and, while more limited, sulfur
15 Two factors influence how different GHGs impact the climate: 1) their ability to absorb energy (i.e., "radiative
efficiency") and 2) how long they stay in the atmosphere (i.e., "atmospheric lifetime"). The GWP is a measure of the
global warming impacts of different gases. Specifically, it is a measure of how much energy the emissions of 1 ton
of a gas will absorb over a given period of time, relative to the emissions of 1 ton of CO2. The larger the GWP, the
more that a given gas warms the Earth compared to CO2 over that time period. The United States primarily uses the
100-year GWP as a measure of the relative impact of different GHGs. However, GWP can also be based on different
timeframes. See https://www.epa.gov/ghgemissions/understanding-global-warming-potentials.
16 Ammonia slip is excess ammonia that passes through the SCR system unreacted.
16
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hexafluoride-free options are available for equipment up to 145 kV. EPA's sulfur hexafluoride
partnership programs and state requirements have expanded the use of these technologies.17
17 See https://www.epa.aoy/eps-partnership: California and Massachusetts also have regulatory programs to reduce
emissions of sulfur hexafluoride. Assuming an insulating piece of equipment losses 1 lb of sulfur hexafluoride
annually, this is equivalent to 11 tons of CChe. In 2019, the average combined cycle EGU emitted 600,000 tons of
CO2 and the average simple cycle emitted 30,000 tons of CO2. However, while the atmospheric lifetime of CO2 is
hundreds of years, the atmospheric lifetime of sulfur hexafluoride in 3,200 years. In 2019, sulfur hexafluoride
emissions from electrical power systems and electric equipment manufacturers were 4.2 million metric tons of
carbon dioxide equivalents (MMT C02e) (0.2 kilotons (kt) of sulfur hexafluoride). See Inventory of U.S.
Greenhouse Gas Emissions and Sinks: 1990-2019 (2021). (U.S. EPA, 2021i).
17
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5.0 Combustion Turbine EGU GHG Control Approaches
The development of effective and commercially viable GHG emission control technologies18 and
other approaches for reducing GHG emissions from combustion turbine EGUs is receiving
widespread attention from stakeholders including electric utilities, technology providers,
nongovernmental organizations, and government agencies. Some GHG control technologies are
available at present. Some are still in the research and development phase and are not ready for
commercial application. Yet other GHG control technologies are being demonstrated at larger
scales and are progressing toward commercial viability. This remains an active area of research
and new projects, programs, and technology advances are reported routinely.
In this section, the discussions of direct/onsite GHG control technologies (and/or their
development status) and other mitigation approaches for a given combustion turbine EGU are
based on descriptions in publicly available information as of November 2021. For this white
paper, these technologies and mitigation options are organized as follows and basically cover
four broad topics.
1) Sections 5.1-5.6 discuss the reduction of GHG emissions rates by improving heat rates
and reducing fuel usage (thereby limiting CO2 formation) for both the combustion turbine
engine {i.e., the Brayton cycle) and the HRSG {i.e., the Rankine cycle), combined heat
and power (CHP), and the integration of non-emitting sources {e.g., renewables) and/or
energy storage.
2) Sections 5.7 and 5.8 discuss existing and emerging technologies that focus on the capture
of CO2.
3) Section 5.9 discusses the GHG benefits of the combustion of hydrogen (and ammonia).
5.1 Impact of EGU Efficiency on CO2 Emissions
As the thermal efficiency of a combustion turbine EGU is increased, less fuel is burned per
kilowatt-hour (kWh) generated, and there is a corresponding decrease in CO2 and other air
emissions. EPA's Clean Air Markets Division collects heat input and gross MW output data on
an hourly basis for the majority of fossil fuel-fired EGUs.19 The heat input is derived from
standardized continuous emissions monitors or fuel flow monitors while the owner/operator of
the EGU supplies gross MW output. The electric energy output as a fraction of the fuel energy
input expressed as a percentage is a common practice for reporting the efficiency. The greater the
output of electric energy for a given amount of fuel energy input, the higher the efficiency of the
electric generation process. Heat rate is another common way to express how efficient an EGU is
at converting input energy to electric energy. Heat rate is expressed as units of Btu or the
kilojoules (kJ) required to generate one kWh of electricity. Lower heat rates are associated with
more efficient power generating plants.
Heat rate can be calculated using the higher heating value (HHV) or the lower heating value
(LHV) of the fuel. The HHV is the heating value directly determined by calorimetric
measurement of the fuel in the laboratory. The LHV is calculated using a formula to account for
18 When EPA refers to "GHG control technologies" the Agency is including both technologies that reduce onsite
GHG emissions and other GHG control approaches that reduce offsite GHG emissions.
19 CAMD Power Sector Emissions Data is collected from most fossil fuel-fired EGUs greater than 25 MW.
18
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the moisture in the combustion gas {i.e., subtracting the energy required to vaporize the water in
the flue gas) and is a lower value than the HHV. Consequently, the HHV heat rate for a given
EGU is always lower than the corresponding LHV heat rate because the reported heat input for
the HHV is larger. For natural gas, the HHV heat rate is approximately 10 percent lower than the
corresponding LHV heat rate.20 Manufacturers typically use the LHV to express the heat rate of
combustion turbines.
Similarly, the electric energy output for an EGU can be expressed as either of two measured
values. One value relates to the amount of total electric power generated by the EGU, or gross
output. However, a portion of this electricity must be used by the EGU facility to operate the
unit, including compressors, pumps, fans, electric motors, and pollution control equipment. This
within-facility electrical demand, often referred to as the parasitic load or auxiliary load, reduces
the amount of power that can be delivered to the transmission grid for distribution and sale to
customers. Consequently, electric energy output may also be expressed in terms of net output,
which reflects the EGU gross output minus its parasitic load. It is important to note that this
value represents the net output delivered to the electric grid and not the net output delivered to
the end user. Electricity is lost as it is transmitted from the point of generation to the end user and
these "line losses" increase the farther the power is transmitted.21 Subpart TTTT of the NSPS
currently provides a way to account for the environmental benefit of reduced line losses by
crediting CHP EGUs—which are typically located close to large electric load centers.22
When using efficiency to compare the effectiveness of different combustion turbine EGU
configurations and the applicable GHG emissions control technologies, it is important to ensure
that all efficiencies are calculated using the same type of heating value {i.e., HHV or LHV) and
the same basis of electric energy output {i.e., MWh-gross or MWh-net).
Although for a given fuel there is a direct inverse correlation between combustion turbine EGU
efficiency and CO2 emissions23 {i.e., as efficiency goes up, CO2 emissions go down and vice
versa), other factors must be considered when comparing the effectiveness of GHG control
technologies to improve the efficiency of a given combustion turbine EGU. The actual overall
efficiency that a given combustion turbine EGU achieves is determined by the interaction of a
combination of site-specific factors that impact efficiency to varying degrees. These factors
include:
¦ EGU equipment and components: The design specifications of major EGU components
such as the combustion turbine engine, HRSG, steam turbine, electrical generators,
20 The HHV of natural gas is 1.108 times the LHV of natural gas. Therefore, the HHV heat rate (or efficiency) is
equal to the LHV heat rate (or efficiency) divided by 1.108. For example, an EGU with a LHV heat rate of 5,740
Btu/kWh (59.4 percent LHV efficiency) is equal to a HHV heat rate of 6,360 Btu/kWh (53.6 percent HHV
efficiency).
21 Line losses are the product of the square of the current that passes through the wires multiplied by the resistance
of the wires. The resistance of the wire is the product of the conductivity of the wire (a property of the conductor
used to construct the wire) and the length of the wire divided by the cross-sectional area of the wire. All else equal, a
transmission line that is twice as long will have twice the line losses.
22 The electric transmission and distribution factor (TDF) in subpart TTTT provides a 5 percent credit to account for
the improved delivered net output for EGUs located close to electric load centers (See §60.5540(a)(5)(i) and the
definitions of gross energy output and net energy output in §60.5580).
23 The use of carbon capture technology is an exception. While capturing carbon emissions lowers GHG emissions,
the energy required to run the equipment reduced both the gross and net efficiency of an EGU.
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electric motors, etc., provided by equipment manufacturers can affect overall EGU
efficiency.
¦ EGU plant size: Combustion turbine engines range from approximately 30 kilowatts of
electrical power (kWe) microturbines to 440 megawatts of electrical power (MWe) frame
units. Combustion turbine efficiency generally increases with size because the losses are
lower for larger equipment. However, as equipment size increases, the differences in
these losses start to taper off.
¦ EGU pollution control systems: The electricity and/or steam consumed by air pollution
control equipment reduces the overall efficiency of the EGU.
¦ EGU operating and maintenance practices: The specific operating and equipment
maintenance practices used by the owner/operator of an EGU can affect the overall
efficiency of the source.
¦ EGU cooling system: The temperature of the cooling system impacts the steam turbine
performance of a combined cycle EGU. Recirculating cooling systems (e.g., cooling
towers) have an efficiency advantage over dry cooling systems. While the use of once-
through cooling systems results in the highest efficiencies, the relatively large water-
related ecological concerns limit the use of open cooling system in the United States.
¦ EGU geographic location: The elevation and seasonal ambient temperatures at the
facility location may have a measurable impact on EGU efficiency. At higher elevations,
air pressure is lower, and less oxygen is available for combustion per unit volume of
ambient air than at lower elevations, thereby reducing combustion turbine EGU output
but not impacting other parameters. Cooler ambient temperatures increase the overall
combustion turbine EGU efficiency and output by decreasing the air compressor
workload, increasing the draft pressure of the HRSG flue gases and the condenser
vacuum, and by increasing the efficiency of a condenser cooling system.
¦ EGU load generation flexibility requirements: Operating an EGU as a base load unit is
more efficient than operating an EGU as a non-base load24 (load cycling or peaking) unit
to respond to fluctuations in customer electricity demand.
Because of these factors, combustion turbine EGUs that are identical in design but operated by
different companies in different locations may have different efficiencies and corresponding
GHG emission rates.
5.2 Efficiency Improvements
When the efficiency of the power generation process is increased, less fuel is burned to produce
the same amount of electricity. All else equal, this provides the benefits of lower fuel costs and
reduced air pollutant emissions (including CO2). The EPA notes that this paper does not attempt
to address the emissions impact of any potential rebound effect—that more efficient combustion
turbines would be used more often. Many energy efficiency technologies are available for
application to new combustion turbine EGU projects that can provide incremental improvements
to the overall thermal efficiency. The energy efficiency technologies with the potential to achieve
the greatest improvements in electric power generation efficiency involve EGU design,
24 Base load EGUs operate at high loads most of the time. Peaking EGUs only operate a few hours a year during
periods of high electric demand. Load cycling or intermediate load EGUs are dispatchable EGUs that are neither
base load nor peaking units. There is not a universal definition for the different types of EGUs.
20
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equipment selection, and cost decisions that are typically incorporated during the planning and
engineering design phases for a new EGU project.
5.2.1 Selection of the Type of Combustion Turbine
An early design choice that impacts the emissions rate of a combustion turbine is the
determination to build either a simple cycle EGU or a combined cycle EGU. While simple cycle
EGUs have lower capital costs and generally provide more operational flexibility than combined
cycle EGUs, they are less efficient and have higher fuel costs. Therefore, simple cycle EGUs are
primarily used during periods of peak electric demand {i.e., peaking EGUs that operate at lower
capacity factors25). Due to their higher efficiencies, combined cycle EGUs often operate at
higher capacity factors and can be considered base load EGUs. However, both simple cycle and
combined cycle EGUs can be built with the intention to operate at intermediate capacity factors.
One of the roles of these intermediate load EGUs is to provide backup to intermittent generating
sources such as wind and solar. The decision of whether to build a simple cycle or a combined
cycle EGU to serve intermediate load demand is determined on a case-by-case basis that incudes
consideration of how it is anticipated the combustion turbine will be operated. Based strictly on
the costs and performance for new EGUs included in EIA's Annual Energy Outlook (AEO) for
2021 (U.S. EIA, 2021a), combined cycle EGUs have lower levelized costs of electricity (LCOE)
when annual capacity factors exceed 25 percent.
5.3 Simple Cycle Combustion Turbines
For a given fuel, a primary design choice that impacts the GHG emissions rate of a simple cycle
turbine is selecting an efficient combustion turbine engine. For stationary sources, the most
efficient simple cycle combustion turbines operate at pressure ratios greater than 40 {i.e., the
pressure exiting the compressor is more than 40 times atmospheric pressure) and have relatively
low exhaust temperatures.26 Combustion turbines are often divided into two categories—
aeroderivative and frame turbine engines. Frame combustion turbines are designs that were
always intended to operate in stationary applications while aeroderivative stationary combustion
turbines are derived from designs that were originally intended for aviation. Aeroderivative
combustion turbines typically are limited to approximately 100 MW in output, but start faster,
are smaller, lighter, and have higher efficiencies than frame turbines of comparable size.
However, turbine manufacturers have incorporated design elements of frame turbines into
aeroderivative turbines and vice versa, narrowing any distinctive design or performance
differences (Brooker, 2017).27
25 Capacity factor is the actual amount of fuel consumed divided by the amount of fuel that could theoretically be
consumed if the EGU had operated at full load for the entire year. Capacity factor can also be expressed as the actual
electrical output divided by the theoretical maximum electrical output.
26 The most efficient simple cycle designs are relatively long to accommodate the additional compressor and turbine
stages to optimize pressure ratio and energy extraction.
27_Certain aeroderivative simple cycle combustion turbine designs have incorporated an intercooler between the low-
and high-pressure compression stages and therefore requires a cooling system.
21
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5.3.1 Maximum Theoretical Combustion Turbine Efficiency
The theoretical thermal efficiency28 (t|b) for a combustion turbine that operates using the
Brayton cycle is a function of the ratios of the atmospheric temperature (Ta) and the temperature
at the exit of the compressor (Tb), expressed as:
Ideal BraytOn cycle efficiency. T|B 1 Ta/Tb 1 Tatmospheric/Tcompressorexit
Using thermodynamic relationships between temperature and pressure, efficiency can be
expressed as:
r|B = 1 - 1/TR = 1 - (1 /PR)< Y"1 )/y
Where:
TR = temperature ratio of Tb/Ta
PR = pressure ratio of compressor outlet pressure to inlet pressure
y = the ratio of the specific heat of air at a constant pressure to the specific heat
capacity of air at a constant volume (1.4)
The theoretical operating efficiency of the Brayton cycle is most often plotted as a function of
the pressure ratio (PR) and shown as follows:
Exhibit 5-1. Brayton cycle theoretical efficiency (Ginsberg, 2016).
Ideal Efficiency of Combustion Turbine Engine
80%
70%
80%
>*
CJ
C
QJ
50%
'u
it
UJ
40%
"re
CD
30%
"O
20%
10%
0%
0 10 20 30 40 50 60
Pressure Ratio
28 The maximum theoretical efficiency of any heat engine is the Carnot efficiency.
22
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The efficiency of the Brayton cycle is a function of the pressure ratio, the ambient air
temperature, the turbine inlet air temperature, the efficiency of the compressor and turbine
elements, the turbine blade cooling requirements, and any other performance enhancements (e.g.,
recuperation, intercooling, inlet air cooling, and steam injection). Because combustion turbines
reduce power output by reducing combustion temperature, efficiency at part load can be
substantially below that of full-power efficiency (U.S. EPA, 2015). Exhibit 5-2 shows the design
efficiency (as reported in Gas Turbine World (GTW) for multiple manufacturers) of 60 hertz
simple cycle combustion turbines introduced after 2000. The trend is that efficiency generally
increases with size, and that while certain aeroderivative designs have higher efficiencies than
comparable-sized frame designs, on average comparable-sized aeroderivative and frame
combustion turbines intended for simple cycle operation have similar design efficiencies.
Exhibit 5-2. Design efficiency of simple cycle combustion turbines.
Heat Input Capacity vs. Efficiency
Simple Cycle Combustion Turbines
40.0%
> 39.0%
X
3E. 38.0%
fr
£ 37.0%
U
jj 36.0%
£ 35.0%
tD
S, 34.0%
'«
Q 33.0%
32.0%
0 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000
Heat Input Capacity (MMBtu/h, HHV)
*
~
«
•
~ ~
~
~
•
••
*
% •
~ ~
u
~
4
~
• Aeroderivative
•t
~
~ Frame
~
The choice of NOx emissions control technology can also impact the design efficiency and rated
output of a combustion turbine. There are two primary types of combustion controls used with
combustion turbines—the addition of water or steam, known as wet low-NOx (WLN) or wet low
emissions (WLE) technology, and staged air combustion systems, known as dry low-NOx (DLN)
or dry low emissions (DLE) technology. Both approaches reduce the peak flame temperature to
reduce the formation of thermal NOx. WLN can achieve NOx emissions of approximately 25
parts per million volume (ppmv) for natural gas combustion and 42 ppmv for fuel oil combustion
(NJ DEP, 2021; Schorr and Chalfin, n.d.). Various combustion turbine manufacturers have
developed DLN combustion controls that can reduce NOx emissions to single-digit ppm values
when burning natural gas. However, DLN technology is more challenging for liquid fuels and
WLN is generally used when fuel oils are combusted.
The use of WLN technology increases the power output of the combustion turbine due to
increased mass flow, but the thermal energy required to vaporize the water increases the heat rate
23
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by approximately 3 percent (EPA, 1993). Efficiency and output can be improved if steam is
produced using the thermal energy in the simple cycle turbine exhaust.29 The output gain and
efficiency loss will vary based on the specific turbine design. In Exhibit 5-3, GTW provides a
direct comparison to determine the tradeoff on efficiency and output associated with WLN and
DLN models of the same turbine. This is likely due to the distinct differences between the
designs of combustion zones of engines in gas turbines, causing engine manufacturers to have
different combustion technologies for different model turbines. Information was obtained for the
Siemens Energy Trent 60, which is available in DLE and WLN combustion technologies. A
comparison of key performance information for the Trent 60 is provided below:
Exhibit 5-3. Comparison of industrial Trent 60 WLN and DLE performance.
Model
Hz
ISO Base Load
(kW)
Efficiency
(%)
WLN Efficiency
Impact (%)
WLN Power
Impact (%)
SGT-A65 DLE ISI
60
64,900
43.3
-
-
SGT-A65 WLN ISI
60
78,500
42.5
-0.8
+20.9%
Source: Gas Turbine World (2020), p.16.
5.3.2 Impact of Ambient Conditions on Simple Cycle Combustion Turbines
While ambient conditions impact both combustion turbine engine maximum output and
efficiency, there are strategies owners/operators can take to maximize efficiency, and decrease
GHG emissions, under different ambient conditions. A combustion turbine operates on a fixed
maximum input of air to the compressor. At higher temperatures and elevations, the density of
the air entering the compressor is lower, reducing the mass flow through the turbine and
consequently less air is available for combustion. Since the combustion turbine maximum heat
input is reduced, the combustion turbine engine output is less than the rated output. In addition,
as the air inlet temperature increases, more work is required to accomplish the specified pressure
rise. The increased work is provided by the turbine and less is available to rotate the generator to
produce electricity. At lower temperatures the opposite occurs—output and efficiency increases
compared to design specifications. For every degree °C increase in ambient temperature,
combustion turbine output is decreased 0.5 to 1 percent and the heat rate increases 0.15 to 0.4
percent (Farouk et al., 2013). One approach owners/operators of combustion turbines can take to
reduce the efficiency and capacity losses due to higher ambient temperatures is precooling the
combustion air.30
5.4 Combined Cycle Combustion Turbines
As opposed to the use of high pressure ratios that increase the efficiency of simple cycle EGUs,
combined cycle EGUs often use turbine engines with lower pressure ratios to deliver higher mass
flowrates and higher exhaust temperatures (Gas Turbine World, 2021) to maximize the overall
29 Water/steam injection for NOx control is different than a steam injected gas (STIG™) cycle or the Cheng Cycle®.
These approaches use a HRSG to generate high-pressure, superheated steam and inject that steam into the
combustion turbine to increase both the output and efficiency of the combustion turbine.
30 Combustion air can either be cooled using an evaporative or a chilling system. Evaporative cooling adds liquid
water to the combustion air and the air is cooled as the water evaporates. Evaporative cooling is limited by the wet
bulb temperature and is most effective in areas with low humidity. Chilling systems use either mechanical or
adsorption chillers to lower the temperature of the combustion air. Chilling systems can cool the air below the dew
point temperature but can have significant auxiliary loads.
24
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EGU efficiency (i.e., using Brayton plus Rankine cycles). There are several variables that impact
the theoretical efficiency of a given combined cycle EGU, and consequently, there is not a
straightforward representation for the theoretical efficiency like there is for the Brayton cycle.
Exhibit 5-4 shows that, like simple cycle EGUs, the efficiency of combined cycle EGUs
increases with increasing size, and that combined cycle EGUs based on frame turbine engines
are more efficient than similar-sized aeroderivative combined cycle EGUs.
Exhibit 5-4. Combined cycle efficiency.
Heat Input Capacity vs. Efficiency
Combined Cycle Turbines
0 1,000 2,000 3,000 4,000 5,000 6,000 7,000 8,000
Heat Input Capacity (MMBtu/h, HHV)
Source: Gas Turbine World (2020)
State-of-the-art power blocks achieve design net thermal efficiencies greater than 58 percent on a
HHV basis (64 percent on a LHV basis). The most efficient combined cycle EGUs utilize
HRSGs with a steam reheat cycle and multi-pressure steam. A steam reheat cycle extracts and
reheats steam that has been partially expanded in the steam turbine prior to expansion in the
lower pressure portion of the turbine. A reheat module allows more efficient operation of the
steam turbine and prevents formation of water droplets that can damage the steam turbine's
lower pressure stages. The use of three discrete steam pressures (high pressure (HP),
intermediate pressure (IP), and low pressure (LP)) maximizes efficiency. Each of these three
sections contains separate superheater, evaporator, steam drum, and economizer modules. The
HP steam section is located on the high-temperature end of the HRSG, closest to the combustion
turbine exhaust duct. The LP steam section is located on the low-temperature end of the HRSG,
just before the stack. This arrangement maximizes the degree of superheat (i.e., the quantity of
energy per pound of steam) delivered to the steam turbine. Simpler, low-cost, less-efficient
HRSGs are also available in single-, double-, and triple-pressure designs and without a reheat
cycle. Double-pressure and triple-pressure HRSG without a reheat cycle have efficiencies of
approximately 20 and 26 percent, respectively. A triple-pressure HRSG with a reheat cycle
60.0%
> 58.0% ^
B. 56.0% ~ ~ * ~ ~
5" 54.0% ~ ~~ ~
-------
improves the efficiency of thermal energy to electrical output to approximately 30 percent.31
After the energy has been extracted for steam production, the flue gas enters an economizer,
which preheats the condensed feedwater recycled back to the HRSG. The final heat recovery
section is the fuel preheater, which preheats the fuel used for the combustion turbine. Integrated
fuel gas heating results in higher turbine efficiency due to the reduced fuel flow required to raise
the total gas temperature to firing temperature. Fuel heating reduces the output of the combustion
turbine but improves the efficiency by approximately 0.6 percent.
5.4.1 Fast Start/Flexible Combined Cycle EGUs
Combined cycle EGUs built before the increase in generation from intermittent sources {i.e.,
renewables) were often designed and intended to operate for extended periods of time at steady
loads. Since combined cycle EGUs were not intended to start and stop on a regular basis, they
have relatively long startup times. With increased generation from intermittent sources, more
flexible combined cycle EGU designs were developed. These fast-start, combined cycle EGUs
incorporate multiple techniques to allow the EGU to start and stop faster, cycle output faster, and
maintain higher part load efficiencies than previous designs. These design features include an
HRSG bypass stack that allows the combustion turbine engine to operate independent of the
HRSG. This approach allows the turbine engine to come to full load quickly and operate in
simple cycle mode. The HRSG can then be slowly brought to temperature while the combustion
turbine engine operates at high load.32
Design features have also been incorporated to allow the HRSG to begin operation more rapidly.
These features include the use of stack dampers, purge credits, and an auxiliary boiler. Stack
dampers conserve heat in the HRSG by reducing airflow and the associated heat losses while the
EGU is not operating. Purge credits involve purging the fuel systems during shutdown and
adding isolation valves in the fuel supply system. Previous combined cycle EGUs were required
to purge residual fuel from the combustion system with fresh, ambient air prior to commencing
operation to remove any excess combustible fuels in the unit. However, this increased start
times, reduced efficiency by decreasing the temperature of the HRSG, and increased thermal
fatigue on the units. Generating purge credits during shutdown allows the EGU to start up
without a purge. An auxiliary boiler may also be used to maintain the HRSG temperature,
reducing the time required for an HRSG to begin producing steam.
The design of the HRSG can also impact how long it takes to start producing steam and
generating power. While relatively inefficient, a dual-pressure HRSG without a reheat cycle has
a simpler startup procedure and can start quicker than a more efficient triple-pressure HRSG with
a steam reheat cycle. The use of a once-through HRSG33 can also improve the ability of a
combined cycle EGU to start quickly and maintain efficiency at part load. A once-through
HRSG does not have a steam drum like a more traditional HRSG. Instead, the feedwater is
31 According to Gas Turbine World, all aeroderivative and frame combined cycles with base load ratings of less than
500 MMBtu/h use double-pressure HRSG. Triple-pressure HRSG without a reheat cycle are used for frame
combined cycle EGUs up to 2,000 MMBtu/h, and triple-pressure HRSG with a reheat cycle are used for frame
combined cycle EGUs with base load ratings of greater than 2,000 MMBtu/h.
32 Previous combined cycle designs had to operate the combustion turbine engine at low loads to slowly increase the
HRSG temperature. Configurations with a stack bypass can slowly increase the percentage of the combustion
turbine engine exhaust into the HRSG to increase the HRSG temperature without damage.
33 Once-through HRSG are sometimes referred to as Benson® HRSG.
26
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converted to steam in the HRSG furnace waterwalls and goes directly into the steam turbine.
This allows for the use of higher-pressure steam, which improves design efficiencies, provides
higher part-load efficiencies, allows reduced startup times, and results in more flexible operation.
5.4.2 Duct Burner/Supplemental Firing
The exhaust from combustion turbines contains significant amounts of excess oxygen that can
support additional fuel combustion. Duct burners are optional supplemental burners located in
the HRSG that are used to increase the flue gas temperature and generate additional steam.34 In
theory, heat input to duct burners could be twice that of the combustion turbine engine but are
more often sized at 10 to 30 percent of the heat input to the combustion turbine engine. Duct
burners are often used during periods of high electric demand to generate additional incremental
electricity. While the efficiency of the incremental generation is less than the overall efficiency
of a combined cycle EGU, it can be more efficient than a standalone Rankine cycle or a separate
simple cycle EGU used for peaking applications. Duct burners that are relatively small and only
designed to make up steam turbine capacity lost due to high ambient temperatures do not impact
the efficiency of the combined cycle EGU when they are not operating. However, large duct
burners that are designed to significantly increase the output of the steam turbine can negatively
impact the efficiency of the combined cycle EGU when not operating. To accommodate the
additional steam generated by the duct burners, the steam turbine may need to be oversized
relative to operation without the duct burners. Since steam turbines are less efficient when
operated at part load, this can decrease the overall efficiency of the combined cycle EGU. The
efficiency impacts should be weighed against the anticipated displaced generation when
determining the emissions standard for a new combined cycle EGU.
5.4.3 Cooling Technology for Rankine Cycle
Simple cycle turbines do not include a Rankine cycle and therefore do not require a
cooling/condensing cycle. However, combined cycle EGUs include a Rankine cycle and need a
cooling cycle to condense the generated steam back to liquid water and return it to the HRSG for
reuse through high-pressure feed pumps. Heat from the condensing steam is rejected to the
cooling technology. The lower the temperature that the cooling system can achieve the more
efficient the Rankine cycle. The cooling system can either be a recirculating, hybrid, or dry
cooling system.35
Recirculating cooling systems are closed systems in which the water extracted for cooling is
evaporated in the cooling tower. Cooling towers reduce water impacts compared to once-through
systems but still require water to operate. Dry cooling systems use air heat exchangers to provide
cooling and minimize water impacts. Dry cooling systems eliminate the adverse environmental
impacts caused by cooling tower intake structures. A drawback of dry cooling systems is that the
34 While the common approach is for the duct burners to burn the same fuel as the combustion turbine engine, any
fuel could be used to provide supplemental heat. The Gerstein power plant, unit K, in Germany integrates a natural
gas-fired combustion turbine engine that discharges the exhaust directly into the coal-fired boiler. This essentially
creates a combined cycle EGU with a coal-fired heat recovery steam generator.
35 Open (once-through) cooling systems use an open system that extracts cooling water directly from a waterbody
and returns it to the same waterbody at a higher temperature. This type of cooling results in the lowest temperature
and most efficient operation but has greater adverse environmental impacts. Therefore, new EGUs cannot use open
cooling systems.
27
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EGU is unable to reach as low of a condensing temperature and is, therefore, less efficient. A
hybrid cooling system combines recirculating and dry systems in one integrated system.
Depending on the specific design, the owner/operator can adjust the amount of cooling that is
accomplished by dry and recirculating systems to reduce water use compared to a fully
recirculating system. While the choice of cooling technology has less of an impact on overall
efficiency of a combined cycle EGU than for a coal-fired EGU,36 it is an important factor to
consider when comparing efficiencies and GHG emission rates of EGUs. Approximately a
quarter of combined cycle EGUs that have commenced operations since 2010 use hybrid or dry
cooling.37 A combined cycle EGU using an open cooling system would be expected to have an
emissions rate 0.5 percent lower than a comparable combined cycle EGU with a recirculating
cooling system. Combined cycle EGUs using hybrid and dry cooling systems would be expected
to have emissions rates 0.8 percent and 1.6 percent higher than a comparable combined cycle
EGU using a recirculating cooling system.38
5.4.4 Impact of Ambient Conditions on Combined Cycle EGUs
Like simple cycle EGUs, ambient conditions impact both output and efficiency of combined
cycle EGUs. At higher temperatures, the efficiency and output of the turbine engine decreases
and the temperature of the turbine engine exhaust increases. The higher exhaust temperature
allows additional energy to be recovered in the HRSG and the resultant increase in generation
from the steam turbine partially offsets some of the combustion turbine engine efficiency loss. In
addition, as described in the cooling technology section, the efficiency of the Rankine cycle
decreases with increased ambient temperatures. The overall effect of these parameters is shown
in Exhibit 5-5.
36 A typical coal-fired EGU uses a Rankine cycle to generate all the electrical output, but only approximately one-
third of the output from a combined cycle EGU is from the Rankine cycle.
37 EIA 923 data can be downloaded from https://www.eia.gov/electricitv/data/eia923/.
38 Assumes one-third of the overall output is generated from the steam turbine and that a hybrid system has half the
efficiency impact relative to a dry system. See Coal Industry Advisory Board to the International Energy Agency,
"Power Generation from Coal," (Paris, 2010). (https://iea.blob.core.windows.net/assets/3dcfe688-35cf-46fe-9d80-
27828a56fd80/power generation from coal.pdf).
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Exhibit 5-5. Impact of temperature on combined cycle performance.
Impact of Temperature on Combined Cycle
Performance
1.10
-i-j
S" 1.05
=5
0
"3; 1.00
&
1 °-95
M—
£ 0.90
>
0.85
en
0.80
0 10 20 30 40 50
Ambient Temperature (°C)
•
Relative Efficiency
~
Relative Output
Exhibit 5-5 demonstrates that the impact of ambient temperature on annual emission rates is
relatively minor compared to other factors that influence efficiency but should be accounted for
when comparing emission rates of combined cycle EGUs.
5.4.5 Potential Efficiency Gains in the Bottoming Cycle
Combined cycle EGUs typically have HRSGs that operate at subcritical steam conditions with
pressures of 2,400 pounds per square inch (psi), or 17 megapascal (MPa), and temperatures of
1,112 °F (600 °C). However, once-through HRSGs can be designed to operate using supercritical
steam conditions. "Supercritical" is a thermodynamic term describing the state of a substance in
which there is no clear distinction between the liquid and the gaseous phase (i.e., they are a
homogenous fluid). Supercritical EGUs can be designed to operate at steam pressures higher
than 3,200 psi (22 MPa). A combined cycle EGU designed to use supercritical steam conditions
in the high-pressure portion of the steam turbine would reduce fuel use by 2 percent (Marcin).
In addition, alternate working fluids (i.e., the use of organic fluids or supercritical CO2 rather
than steam) also have the potential to increase the efficiency of combined cycle EGUs. Organic
Rankine cycles are primarily applicable to temperatures lower than combustion turbine engine
exhaust temperatures.39 DOE's National Energy Technology Laboratory (NETL) is working on
improvements to a supercritical CO2 cycle power cycle.40 While the use of supercritical CO2 as
the working fluid in a Rankine cycle (Patel, 2021b) is of most interest for nuclear and coal-fired
EGUs, it also has the potential to improve the overall efficiency of combined cycle EGUs. The
primary efficiency benefit would be for combined cycle EGUs using smaller frame or
aeroderivative combustion turbine engines that typically use a double-pressure HRSG without a
39 The Kalina Cycle® is another cycle that lias the potential for efficiency gains compared to a water-based Rankine
cycle. See http://www.kalinapower.com/teclinology/.
411 See https://netl.doe.gov/proiect-information?p=FE0028979/.
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reheat cycle (Huck et al., 2016). 41 However, a HRSG using supercritical CO2 has the potential
to improve the efficiency of combined cycle EGUs compared to triple-pressure steam with a
reheat cycle as well (Thanganadar et al., 2019).
Combined cycle EGUs generate significant quantities of relatively low-temperature heat {i.e.,
waste or byproduct heat) that cannot be used by the traditional Rankine cycle and is sent to the
power plant cooling system {i.e., cooling tower). If this energy could be recovered to produce
additional electricity, it could reduce the environmental impact of power generation.
Thermoelectric materials {e.g., bismuth telluride (E^Tes), lead telluride (PbTe), silicon-
germanium (SiGe, magnesium antimonide (Mg3Sb2), and magnesium bismuthide (Mg3Bi2)) can
be used to generate electricity due to temperature differences across the material.42 While still in
development, this technology has the potential to recover useful energy from the waste heat from
power plants. However, if a thermoelectric generator were able to convert 5 percent of
combustion turbine waste heat to electric output, the CO2 emissions rate for simple cycle EGUs
would be reduced by approximately 10 percent and combined cycle EGUs by approximately 5
percent.
5.5 Combined Heat and Power (CHP) Plant
Combined cycle EGUs dedicated to electric power generation and using the latest commercially
available advanced technologies can have net design efficiencies of greater than 60 percent on a
LHV basis. Significant amounts of energy are lost during the steam condensation segment of the
Rankine cycle due to heat transfer into the cooling water. CHP, also known as cogeneration, is
the simultaneous production of electricity and/or mechanical energy and useful thermal output
from a single fuel. CHP uses the energy lost during steam condensation of an electric-only EGU.
The temperature of the cooling water is normally not high enough to meet the requirements for
most industrial {i.e., steam) or commercial process {i.e., district heating) applications. Therefore,
steam is often extracted at an elevated pressure and temperature from an intermediate stage of
the steam turbine and then used for the industrial or commercial process. This results in a
decrease in the total electric power generation from the EGU. However, the overall fuel
efficiency of CHP can be 80 percent or higher and requires less fuel overall than if the electricity
and steam were generated separately.43
Because electricity can be transmitted over long distances, EGUs are located in remote as well as
populated areas. However, thermal energy cannot be effectively transported over extended
distances. This limits the practicality of incorporating a CHP mode into many EGU designs. A
CHP EGU needs to be in proximity to either an industrial or commercial facility with a
significant and steady thermal demand. It can be challenging to locate a thermal host with
sufficiently large thermal demands such that the useful thermal output would impact the
41 Using the design HRSG efficiencies listed in Gas Turbine World and the efficiency of the design efficiency of the
Echogen supercritical EPS 100 heat recovery system (24 percent net, https://www.echogen.com/our-
solution/product-series/eps 100A. the median decrease in design heat rates for replacing dual-pressure HRSG with
supercritical CO2 HRSG is 7 percent.
42 Electricity can also be generated from electrochemical reactions at different temperatures and pressures, see
https://\tecenergy.com/technology/. In addition, thermogalvanic cells use temperature differences to generate an
electric current. See e.g., Yuan (2014).
43 According to form EIA-923, in 2019, CHP installations accounted for 10 percent of installed capacity and 15
percent of electricity generated in the U.S.
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emissions rate. However, the refining, chemical manufacturing, pulp and paper, food processing,
and district energy industries tend to have large thermal demands and there are several examples
where co-located combustion turbine CHP EGUs are providing reliable, low-cost thermal energy
to thermal hosts. To the extent that a proposed EGU is in proximity to a thermal host, it may be
possible to investigate if it is economically feasible to design the EGU as a CHP facility.
5.6 Integrated Non-Emitting Generation
The co-location of two or more sources of electricity generation—known as a hybrid power
plant—is another approach that can reduce the onsite output-based emissions rate.44 There are
multiple configurations for how these hybrid systems can be designed, but for the purposes of
this discussion, examples have been categorized as either steam-cycle integrated {i.e., contributes
energy or heat to the steam cycle of a combustion turbine) or energy-output integrated {i.e.,
contributes to the total energy output of the affected facility). There are limited examples of the
co-location of a combustion turbine with integrated renewables, but as energy storage technology
continues to advance, onsite storage is becoming a more common feature.
Hybrid power plants are not new technology. According to an analysis by the Lawrence
Berkeley National Laboratory (LBNL) that mapped hybrid, co-located power plants in the U.S.
based on EIA Form 860 data, there were 125 co-located projects in 2019 with a total output of
almost 13.5 GW (Wiser et al., 2020).
As the following LBNL graphic (Exhibit 5-6) indicates, there are many configurations of
integrated sources of generation that could be considered; but, in terms of the number of projects,
the combination of solar {i.e., photovoltaic or PV) plus storage (40) is the most common
followed by PV plus fossil-fired generation (26) (Wiser et al., 2020). In terms of capacity, PV
plus fossil is by far the largest (6,953 MW), ahead of fossil plus storage (2,414 MW), and wind
plus storage (1,290 MW) (Wiser et al., 2020).
44 The definition of an affected facility in 40 CFR part 60, subpart TTTT includes "any integrated equipment that
provides electricity or useful thermal output to the combustion turbine engine, heat recovery system or auxiliary
equipment."
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Exhibit 5-6. Hybrid/co-located projects of various configuratons.
125 projects, 13.4 GW of generating capacity, 0.9 GW storage capacity
Wind+Storage
13
1,290
0
0
1,290
184
109
14%
0.6
Wind+PV+Storage
2
216
21
0
237
34
15
15%
0.4
Wind+Fossil+Storage
1
5
12
0
17
1
1
7%
0.8
Wind+PV+Fossil+Storage
1
0.1
0.1
1
1
0
1
25%
1.7
Wind+PV
6
535
212
0
747
0
0
0%
n/a
Wind+PV+Fossil
3
6
2
98
106
0
0
0%
n/a
Wind+Fossil
8
27
79
0
106
0
0
0%
n/a
PV+Storage
40
882
0
0
882
169
446
19%
2.6
PV+Fossil
26
77
6,876
0
6,953
0
0
0%
n/a
PV+Fossil+Storage
3
9
10
0
20
5
9
24%
1.9
PV+Biomass
3
4
15
0
19
0
0
0%
n/a
PV+Geothermal
2
18
85
0
103
0
0
0%
n/a
PV+Geothermal+CSP
1
22
47
2
71
0
0
0%
n/a
CSP+Storage
2
390
0
0
390
390
2,780
100%
7.1
Fossil+Storage
10
2,414
0
0
2,414
91
84
4%
0.9
Hydro+Storage
4
71
0
0
71
12
11
17%
0.9
Sources: El A 860 2019 Early Release, Berkeley Lab
Note: Pumped hydro is not considered a hybrid resource for the purpose of this compilation.
The hydro+storage plants noted in the table pair hydropower with batteries.
5.6.1 Steam-Cycle Integrated Renewables
The integrati on of renewable sources of energy into the operation of a combusti on turbine in
such a manner as to augment its performance, efficiency, and/or output is an option for reducing
GHG emissions. An efficient and cost-effective renewable pairing for a combined cycle EGU
has been demonstrated to be concentrated solar thermal, particularly in terms of the capital costs
of the technology and the cost of carbon abatement (Alqahtani and Patino-Echeverri, 2016).
In the U.S., the best example of a steam-cycle integrated, large-scale operating system that
increases combustion turbine efficiency is at the Martin Next Generation Solar Energy Center in
Indiantown, Florida. According to permits made available online by the Florida Department of
Environmental Protection (FDEP), the Florida Power & Light facility operates five EGUs, with
Unit 8 being a 4-on-l combined cycle EGU with a capacity of 1,150 MW and connected to a 75-
MW concentrated parabolic solar thermal array (FDEP, 2021). In this system, called Integrated
Solar Combined Cycle (ISCC), solar energy is concentrated by parabolic polished steel mirrors
onto stainless steel tubes containing specialized heat transfer fluid, and after being heated, the
fluid is pumped to a heat exchanger where the auxiliary heat is integrated into the pre- and post-
combustion steam cycle for the turbine (Neville, 2011). The solar array at Martin, which is
owned by NextEra Energy, came online in 2010 and utilizes a 500-acre area that was originally
permitted to be a coal-fired facility in 1989. The energy from the solar thermal array does not
increase the capacity of the EGU but rather reduces fuel consumption by 1.3 billion cubic feet
per year, saving approximately $180 million in fuel costs and reducing CO2 emissions by 2.75
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million tons over 30 years (Neville, 2011). At the time of construction, Martin was eligible for a
$120 million federal investment tax credit that further reduced capital costs associated with the
project (Neville, 2011).
It should be noted that the steam-cycle integration of non-emitting sources at Martin could not be
achieved if combustion turbines did not operate as base load generators of electricity. As EPA
noted in its 2018 proposed amendments to the NSPS, one of the primary benefits of ISCC is that
by co-locating the solar system with a natural gas-fired combustion turbine, it creates
incremental cost reductions for the solar thermal electricity (83 FR 65446).
Another example of an ISCC facility is the Archimede demonstration power plant in Sicily, Italy.
The plant, which has been in operation since 2010, performs much like the Martin facility in that
thermal energy from a concentrated solar array is integrated into the steam cycle of a combustion
turbine to increase efficiency and achieve fuel and emissions reductions. But Archimede is
unique because it is the first power plant in the world to use molten salt as the heat transfer fluid
and for thermal energy storage (Maccari et al., 2015). According to facility data listed online by
the National Renewable Energy Laboratory (NREL, 2021), the molten salt heat transfer fluid that
passes through the 5-MW, 27-acre parabolic solar array is fed to a "hot" storage tank, which can
store up to 100 MWh of thermal energy for 8 hours. The molten salt transfer fluid (60 percent
sodium nitrate, 40 percent potassium nitrate) can then be drawn into a heat exchanger to generate
steam for the combined cycle system (Maccari et al., 2015). The cooled salt transfer fluid is then
sent to a "cold" tank prior to being recirculated through the concentrated solar array and
reheated. This thermal energy storage system allows Archimede to continue utilizing solar
energy regardless of time of day or weather conditions.
Examples of other power plants where natural gas-fired EGUs are integrated with concentrated
solar thermal arrays include Kuraymat in Egypt, Yazd in Iran, Hassi R'mel in Algeria, and Ain
Beni Mathar in Morocco. There are two recent instances in California of ISCC projects being
canceled, but not due to any limitations of the technology. Those projects are the 570-MW gas
and 50-MW solar plant in Palmdale and the 518-MW gas and 50-MW solar plant in Victorville.
In both situations, following lengthy permitting processes, public opposition, and the inability to
obtain power purchase agreements (PPAs) in California for fossil fuel-based electricity, the
projects were canceled in 2019 and 2018, respectively (Gatlin, 2019; Johnson, 2018).
5.6.2 Energy-Output Integrated Renewables
There are also opportunities for a fossil fuel-fired power plant to add renewables to its onsite
generation mix even though the system operates independently of the steam cycle. This may
include onsite renewables that factor into the total electric output and reduce the total emissions
rate of the fossil fuel EGU(s). Power plants with the physical space for a solar array, wind
turbines, or hydroelectric {i.e., co-located run of river or electric generation from the dam used to
create the lake used for cooling), can achieve emissions reductions and environmental benefits
(Dykes et al., 2020).
One such facility with a diverse, integrated generation mix is the E.W. Brown Generating Station
near Harrodsburg, Kentucky. Operated by Louisville Gas & Electric (LG&E) and Kentucky
Utilities (KU), E.W. Brown operates one 457-MW coal-fired EGU and seven natural gas-fired
combustion turbines with combined capacities of approximately 900 MW. According to
information posted online by LG&E and KU (LG&E-KU, 2021), onsite renewable generation
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includes a 33-MW hydroelectric dam and a 10-MW solar array. The hydroelectric plant is
located adjacent to the facility on Herrington Lake and the 44,000-panel solar array was added in
2016 and is located on 50 acres of plant property.
Exhibit 5-7 below was produced by LBNL and depicts the co-located hybrid projects as of 2019
within the structure of the regional grids in the U.S.
Exhibit 5-7. Co-located hybrid power plants.
PV+Storage
PV+WInd
Pv+Wlnd+Stofage
PV+Fossil
Other PV Hybrids
Sofar Capacity
(MW)
O <5
O 5-50
O 51-150
o
100 200 300 400
Total Solar Capacity tn Hybrid Projects
by Region (MW)
>150
Southeast
(non-ISO)
Advantages of siting renewable projects at new (or existing or former fossil-fired facilities) are
reduced grid interconnection costs and reduced environmental and social impacts. Often worth
hundreds of millions of dollars, an interconnection point to enter a dispatch queue is critical
(Tomich, 2021). For example, in the Midwest and Mid-Atlantic regions there are renewable
projects with PPAs in place that are having to withdraw from interconnection queues because of
market congestion, the cost of required transmission upgrades, and the added years it will take to
get their energy to customers (Tomich, 2021). The transmission costs and the environmental and
social impacts associated with transmission of intermittent renewable generation are higher than
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dispatchable generation. One reason is that dedicated lines for renewable generation can have
relatively low capacity factors that increase the costs, and the environmental and social impacts
of transmission per MWh of electricity transmitted to the end user.45 Co-locating intermittent
generating sources with dispatchable generation decreases these costs and associated
environmental and social impacts.46
Co-location can also reduce the costs and environmental impacts of the land required for electric
generation from renewable sources of power. Large solar arrays and wind farms can require
thousands of acres to produce enough electricity to replace a single fossil fuel-fired plant and
developers often must secure land-use agreements with facility neighbors in addition to the
approval of local zoning boards and public utility commissions (Tomich, 2021). The land-use
challenges of siting large solar and wind projects are considerable and can be controversial. The
co-location of renewables with new combustion turbine EGUs generally can reduce any potential
land use impacts because the renewable generation is located on land that would likely not
otherwise be used for agriculture or wildlife habitat. For example, installing PV panels on the
rooftop and over the parking lot of a new combined cycle facility could add 50 kW of renewable
generation with essentially no land use implications. If that same 50 kW were built as a
standalone facility, the land use impacts from disrupting former forested or agricultural land
would be greater.47 The land-use requirements of solar and wind can be tempered by the
utilization of co-location with agricultural land,48 offshore wind turbines, expanded solar on
45 Renewable generating sources located far from electric demand centers require longer transmission lines than
generation located close to end users. The line losses associated with transmitting the power results in less efficient
delivered net efficiency. Longer transmission lines also have higher costs and greater externalities (i.e., land use
impacts).
46 The capacity factor for transmission lines dedicated for intermittent renewable generation can also be improved by
co-locating energy storage with the intermittent generation. Existing wires can also be replaced with high-
performance conductors capable of transmitting more electricity (See https://www.utilitvdive.com/spons/5-reasons-
utilities-are-switching-to-high-performance-overhead-conductors/568808/ and
https://www.etcglobal.com/efficiencv/'). reducing the land use and social impacts (e.g., impact on property values,
open space, and wildlife habitat) from new transmission lines. High voltage direct current (HVDC) transmission
lines are also able to transmit more power than high voltage alternating current (HCAC) lines with reduced land use
impacts, energy losses, material requirements (less embodied carbon), and noise (reducing audible impacts on
residents) (See https://www.electricaltechnologv.org/2020/06/difference-between-hvac-hvdc.html and
https://www.electricaltechnologv.org/2020/06/advantages-of-hvdc-over-hvac-power-transmission.html). Locating
new transmission lines underground along existing rail lines has also been proposed and this approach would reduce
the environmental and social impacts of new transmission lines (See https://www.soogreenrr.com/direct-connect-
development-companv/ and https://www.utilitvdive.com/news/transmission-troubles-a-solution-could-be-lving-
along-rail-lines-and-next/587703/).
47 PV added to former agricultural or forested land reduces wildlife habit, can increase rainwater runoff, and increase
local temperatures due to heat island impacts. The impacts of large scale solar can be reduced by planting native
plants to create pollinator friendly habits and creating wildlife corridors. See
https://www.renewableenergvmagazine.com/emilv-folk/how-solar-energv-can-coincide-with-crop-20201119:
https://www.nature.org/content/dam/tnc/nature/en/documents/ED TNCNCPrinciplesofSolarSitingandDesignJan201
9.pdf: http://ncpollinatoralliance.org/wp-content/uploads/2018/10/NC-Solar-Technical-Guidance-Qct-2018.pdf: and
https://www.nature.org/en-us/about-us/where-we-work/united-states/north-carolina/stories-in-north-
carolina/making-solar-wildlife-friendlv/
48 Using land for the dual purpose of solar energy and crop and/or animal agriculture is referred to as agrivoltaics.
The panels are elevated 7 to 9 feet and spaced apart to allow sunlight to reach the plants below. While the panels
reduce the available energy for photosynthesis and the ability to use certain mechanized agricultural techniques, the
shading effect can create cooler microclimates that increase the efficiency of the solar panels, reduce water losses
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already disturbed (e.g., rooftops, parking lots), and degraded land (Merrill, 2021; U.S. EPA,
2021a). A disadvantage of integrated renewables is that the location might not be ideal and there
may be limited physical space at a power plant, especially if located in a more urban or industrial
area, that can constrain the size of a solar array or wind farm and thereby limit the potential of
non-emissions generation (Gorman etal., 2020).
5.6.3 Integrated Energy Storage
There are several energy storage options that can provide either short-term and/or long-term
storage capacity. The type of energy storage technology used for a particular application is
dependent upon many variables, such as intended goals, cost, safety, the process receiving
energy, and space constraints. Generally, energy storage that discharges in less than 1 minute is
used for grid support (i.e., voltage and frequency regulation) and short-term storage (2 to 4
hours) is ideal to provide peak power generation. Medium-term storage (4 to 10 hours) is ideal to
normalize daily integrated plant output at renewable energy sources while long-term bulk energy
storage can address seasonal variations in energy generation and demand.
The following table summarizes various integrated storage options, several of which are
discussed in more detail later in this subsection.
Exhibit 5-9. Energy Storage Technologies
Power Quality
Typical Duration
Example Technologies
Ephemeral (power quality)
1-30 seconds
Flywheels, supercapacitors
Short term (peaking support)
0.5 - 4 hours
Lithium-ion battery
Medium term
1-10 hours
Vanadium flow, sodium sulfur, and lead
acid batteries
Long term (bulk storage)
1 - 100+ hours
Pumped hydroelectric, compressed air, and
hydrogen
Co-location of energy storage with new combustion turbine EGUs offers multiple potential
environmental benefits. Combustion turbines are dispatchable, reliable, and can operate on a
continuous basis. However, while combustion turbines can start rapidly, they are not
instantaneous and require power for initial startup. And although they can change load rapidly,
they cannot take advantage of excess renewable generation and store the energy for later use.
Energy storage integrated with combustion turbines can provide power within 1 second and
increase the spinning reserve capacity of the EGU and allow the EGU to balance the grid and
absorb excess grid power. Specifically, energy storage allows combustion turbines to minimize
starts and stops and to operate more continuously at optimal efficiency, both of which reduce
GHG emissions. Co-location of energy storage with power generation can also reduce
transmission constraints by locating close to end users and charge during periods of low demand
by the transmission grid. Like co-located renewables, co-located energy storage shares costs for
that can, in certain circumstances, enhance agricultural productivity. Additional information on the benefits of low-
impact solar is available from The National Renewable Energy Laboratory and the Department of Energy; see
https://www.nrel.gov/news/features/2019/beneath-solar-panels-the-seeds-of-opportunitv-sprout.html and
https://www.energy.gov/eere/solar/farmers-guide-going-solar.
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permitting, siting, infrastructure, and grid interconnections and associated transmission and
distribution capabilities (Gorman et al., 2020).
An example of the successful integration of short-term storage with natural gas-fired combustion
turbines can be seen at two 50-MW peaking plants operated by Southern California Edison
(SCE). In 2017, the utility's stations in Norwalk and Rancho Cucamonga began operating the
world's first Hybrid Enhanced Gas Turbine systems, or Hybrid EGT (Aoyagi-Stom, 2017; Patel,
2017). The plants' energy storage comes from co-located 10-MW/4.3-MWh lithium-ion batteries
that pull excess renewable energy from the grid and then provide energy during peak demand.
The stored energy serves as spinning reserves, giving the turbines time to ramp up, if necessary.
According to SCE and partner General Electric (GE), this system reduces operational and
maintenance costs by reducing the number of starts and reduces onsite GHG emissions because
the turbines no longer need to operate as often (Aoyagi-Stom, 2017; Patel, 2017).49
A significant increase in the number of studies of how battery storage might impact the dispatch
of existing fossil fuel resources has occurred recently. Energy storage charging from
dispatchable generation generally occurs when excess power can be generated more
economically and stored during low demand periods when the cost of electricity is relatively
inexpensive (Goteti et al., 2021; McPherson et al., 2020). Most studies suggest that in electrical
grids where substantial coal and nuclear capacity are available, those technologies will be used to
charge energy storage devices. However, in other markets, electricity to charge energy storage
will likely be generated from combined cycle EGUs. The type of fossil generation displaced
during battery discharge may be dependent on several regional grid variables; however, in
regions dependent upon the use of standby natural gas peaking turbines, battery storage typically
displaces peaking turbine dispatch despite batteries having a roughly 20 percent energy penalty
resulting from charge/discharge and transmission losses.
The following graphic (IRENA, 2019) depicts the capacity share of different storage
technologies over time:
49 Standalone energy storage facilities can be much larger. In August 2021, Vistra Zero began operations at Phase II
of its Moss Landing Energy Storage Facility in Monterey Bay, California. The project includes 100 MW/400 MWh
of lithium-ion batteries that will capture excess energy from the grid during peak solar generation and then sell the
energy during periods of peak demand (Herrera, 2021). This project is an addition to Phase I, completed in
December 2020, and brings the total storage capacity of the Moss Landing facility to 400 MW/1,600 MWh, enough
to power 300,000 homes (Herrera, 2021). The Moss Landing Energy Storage Facility is able to take advantage of the
former plant's active transmission lines and infrastructure (Patel, 2021a).
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Exhibit 5-10. Capacity share of different storage technologies.
U\
2
£
O
£
£
o
T3
~
o
a
a
o
o
S
~
100%
1.00
1.60
I.JO
1.20 c
1.00 =
0.80 f
£•
0 6O
£
O.JO
0.20
2011
2012
2013
2014
2015
2016
I Lt-icm
I Flew batteries
I Supercapacitors
¦Total installed capacity (<3W)
I Leud-adid
Sodium Sulptlur ballerias
I Zirtc oir
I Flywheels
I Compress&d air
I Others
Note: GW = gigawatt
Source: IEA (2018): Sandia Corporation (201G)
Lithium-ion technology, an outgrowth of technology for small electronics, mobile devices, and
cars, currently dominates the energy storage market and provides energy for ancillary services,
capacity reserve, and grid reliability (IRENA, 2019). A principal drawback of lithium-ion
batteries is degradation. Depending on how frequently lithium-ion batteries are cycled between
energy discharge/recharge, the battery will need to be replaced (Rapier, 2020).
Two of the primary competitors to lithium-ion technology are sodium sulfur and vanadium flow
batteries. According to the Energy Storage Association ("Sodium Sulfur (NAS) Batteries,"
2021), sodium sulfur batteries use molten sulfur as the positive electrode and molten sodium as
the negative electrode and have been demonstrated to offer up to 6 hours of duration. The
limitation to sodium sulfur batteries is that they need to be operated at high temperatures (572
°F) and can require independent heaters. Vanadium flow batteries (VFB) offer several potential
advantages to lithium-ion.50 According to one manufacturer, the batteries are safer and have no
fire hazard, which in turn means they can be packed tighter in a smaller footprint (Rapier, 2020).
VFBs also exceed the performance of lithium-ion batteries in long-term duration due to the fact
the batteries do not degrade from repeated discharge/recharge cycles and can last for decades
without needing to be replaced (Rapier, 2020). The drawback, however, is that, although
vanadium is more plentiful than lithium, it is more expensive to extract. This impacts the cost per
MWh compared to lithium-ion but tilts in favor of VFB in terms of the LCOE over time (Rapier,
2020).
511 See https://www.invinitv.com/vanadium-flow-batteries/
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An emerging technology being developed by staff at the Massachusetts Institute of Technology
has the potential to impact the storage market as well. The technology is a liquid metal battery
that involves a combination of molten metals that operate as electrodes with a layer of molten
salt in between that transfers charged ions between the layers (Stauffer, 2016). Low-cost
production has already been demonstrated and the technology is to be field tested with small-
scale grids that include intermittent wind and solar. The promise of these liquid metal batteries is
that there is no degradation over time (Stauffer, 2016). One of the latest emerging technologies is
a long-duration battery that utilizes ambient air and iron in a modular system to create a process
called "reversible rusting."51 The iron rusts during discharge and reverts to iron during recharge.
These iron-air batteries can provide more than 100 hours of storage at a fraction of the cost of
lithium-ion (Plautz, 2021). A 1-acre pilot project that will be the first commercial deployment of
the iron-air technology was announced in June 2020.52 The batteries will be sited adjacent to a
natural gas peaking plant for connection to the grid and the project is scheduled to be completed
in 2023.
5.7 Post-Combustion Carbon Capture, Utilization, and Storage (CCUS)
Carbon capture, utilization, and storage (CCUS) involves the separation and capture of CO2 from
flue gas, the pressurization and transportation via pipeline of the captured CO2 (if necessary), and
utilization or long-term geologic storage (also referred to as geologic sequestration). There are
multiple demonstrations of the separation and capture, transport, and storage and utilization
components of CCUS within the electric generating and industrial sectors. Examples of carbon
capture installed on coal-fired power plants include the slip stream capture facilities AES
Warrior Run in Maryland and AES Shady Point in Oklahoma. In both cases, the captured CO2 is
used in the food processing industry. In addition, the Southern Company and Mitsubishi Heavy
Industries plant Barry in Alabama and AEP's Mountaineer in West Virginia are power plants
that have demonstrated the viability of the capture component of CCUS. Furthermore, the Petra
Nova Parish plant in Washington and Boundary Dam plant in Saskatchewan, Canada, are
projects that have demonstrated the separation and capture, transport, and geologic storage
components of post-combustion carbon capture. In terms of industrial projects, Searles Valley
Minerals in Kansas uses post-combustion amine scrubbing to capture CO2 from a coal-fired
power plant for use in the production of soda ash.53 Examples of CCUS on combined cycle
EGUs include the Bellingham, Massachusetts, power plant and the proposed Peterhead CCUS
Power Station in Scotland. The Bellingham plant used Fluor's Econamine FG PlusSM™ capture
system and demonstrated the commercial viability of carbon capture using first-generation
technology. The 40-MW slipstream capture facility operated from 1991 to 2005 and captured 85
to 95 percent of the CO2 for use in the food industry. In Scotland, the proposed 900-MW
combined cycle EGU with CCUS is in the planning stages of development. It is anticipated that
the power plant will be completed by 2026, and, once operational, the CCUS system will have
the potential to capture up to 1.5 million tons of CO2 annually (Buli, 2021). A storage site being
developed 62 miles off the Scottish North Sea coast might serve as a destination for the captured
CO2 (Buli, 2021). A potential constraint on the use of CCUS on combined cycle EGUs is that
51 See https://www.formenergy. com/technology/batterv-technology/
52 See https://www.greatriverenergv.com/long-duration-batterv-proiect-in-the-works/
53 Several additional industrial sites (e.g., ethanol production facilities and natural gas processing facilities) are also
capturing CO2. See https://www.c2es.org/content/carbon-capture/
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regenerator preheating can lengthen startup times and limit the ability to operate at low loads
(Domenichini, 2013).
While amine-based solvent systems are currently in commercial use, DOE, the utility industry,
and other organizations are developing additional carbon capture technologies that can reduce
the cost and auxiliary energy requirements. These processes typically use solvents, polymeric
membranes, combination solvent/membranes, or solid sorbents for separating and capturing
CO2.54 Fuel cells configured for emissions capture have also emerged as a viable CCUS
technology. Specifically, the flue gas from and EGU is routed through a molten carbonate fuel
cells that concentrates the CO2 as a side reaction during the electric generation process in the fuel
cell (FuelCell Energy, 2018).
A few second-generation systems have been tested in recent years at the National Carbon
Capture Center (NCCC) funded by NETL. While most of the existing capture projects have
focused on coal-fired EGUs, there is increased interest in CCUS for natural gas-fired EGUs. A
natural gas boiler with the capability of simulating CO2 flue gas concentrations55 from combined
cycle facilities was added to the NCCC's test facilities via an installation at Alabama Power's
Plant Gaston, which became operational in January 2021 and will likely allow for more
applicable studies of second-generation capture technologies for combined cycle facilities
(NETL, 2021). Several other solvent capture technologies have reportedly been validated for
potential commercial use on natural gas combustion flue gas at the Test Centre Mongstad facility
in Norway (U.S. DOE, 2017).
5.8 Oxygen Combustion
Oxygen combustion (i.e., oxy-combustion, oxy-firing, or oxy-fuel) is the use of a mixture of
oxygen (or oxygen-enriched air) and recycled flue gas (containing mostly CO2 with some water)
in place of ambient air for combustion. An oxy-combustion power plant consists of an air
separation unit (ASU), an EGU with 02-blown combustion, and a CO2 treatment unit. The most
common ASU is a cryogenic process that has a significant energy requirement. However,
alternative oxygen separation methods are being researched for possible commercial-scale
development. These alternative methods include ion transport membranes (ITM), ceramic
autothermal recovery, oxygen transport membranes, and chemical looping.56 The benefits
offered by this technology are its potential for higher efficiencies, reduced overall costs, reduced
criteria and hazardous air pollutants, and advantages for CO2 emissions control. Because the
oxygen combustion produces a flue gas that contains primarily CO2 and water vapor, minimal
post-combustion cleanup (if necessary) is required prior to compression, transportation, and
injection for use in geological storage, enhanced oil or gas recovery, or some other use. There are
multiple pilot scale projects that have demonstrated the technology.57 A potential constraint of
oxygen combustion is the ability of the air separation unit to respond to variable loads. Air
54 Solid sorbents can be used to capture CO2 through chemical adsorption, physical adsorption, or a combination of
the two effects. Membrane-based capture uses permeable or semi-permeable materials that allow for the selective
transport/separation of CO2.
55 Flue gas from a combined cycle facility is only approximately 4 percent CO2 by volume compared to 12 to 15
percent CO2 in the flue gas from a conventional coal plant (NETL, n.d.a).
56 The energy required to operate a cryogenic ASU offsets at least a portion of the emissions and cost savings.
Newer ASU designs offer the potential to improve the overall environmental benefits of oxygen combustion.
57 See https://netl.doe.gov/node/7477 and https://seauestration.mit.edu/tools/proiects/vattenfall oxvfuel.html/
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separation units can increase startup times, reduce the ability to operate at low loads, and reduce
ramp rates relative to an air-fired combined cycle EGU (Domenichini, 2013).
5.8.1 The Allam-Fetvedt Cycle
The Allam-Fetvedt cycle,58 presented in Exhibit 5-11, is a combustion turbine technology that
incorporates an air separation unit to burn natural gas with pure oxygen. This "oxy-fuel" design
feature precludes formation of NOx compounds inherent in traditional air-fuel technologies.
However, the flame temperature of natural gas burned with pure oxygen is greater than 2,800 °C
(5,000 °F), which is above the melting point of conventional materials used to fabricate
combustor components. To prevent overheating, the Allam-Fetvedt cycle uses recycled CO2 as a
diluent to control temperatures within the combustor. Like an air-fired combined cycle EGU, the
Allam-Fetvedt cycle incorporates a heat exchanger to capture the heat in combustion turbine
exhaust, but instead of transferring the heat to a steam cycle, the Allam-Fetvedt cycle transfers
the heat to the high-pressure CO2 stream that supplies diluent to the combustor. This cycle is
designed to achieve thermal efficiencies of 59 percent (Yellen, 2020). An advantage of this cycle
is the production of a stream of high-purity CO2 that can be delivered by pipeline to a storage or
sequestration site without extensive processing. A test facility with a heat input rating of 50 MW
was completed in 2018 and was synchronized to the grid in 2021. There are several announced
commercial projects proposing to use the Allam-Fetvedt cycle. These include the 280-MW
Broadwing Clean Energy Complex in Illinois, the 280-MW Coyote Clean Power Project on the
Southern Ute Indian Reservation in Colorado, and several international projects. Final
investment decisions on the U.S. projects are expected in 2022 and commercial operations could
commence by 2025.
Exhibit 5-11. Simplified schematic of a combustion turbine operating in the
thermodynamic cycle known as the Allam-Fetvedt cycle.
1 - Low-pressure, low-temperature, dry CO2 exits water separator and enters the compressor pump (CP).
2 - Recycled portion of high-pressure CO2 routed to heat exchanger to use heat from turbine exhaust to preheat diluent.
2'- Excess portion of high-pressure CO2 routed to pipeline for geologic sequestration.
58 https://netpower.com/teclinology/
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3 - High-pressure, pre-heated CO2 routed to combustion chamber to serve as nitrogen-free diluent
for combustion of pure oxygen and natural gas.
4 - High-pressure, high-temperature recycled CO2 + [CO2 & H2O combustion products] to gas turbine (GT) to turn generator shaft.
5 - The gross work (Wgr0ss) available per Btu of fuel fired can be significantly higher than a conventional Brayton Cycle because of
the increase in thermal energy at 4 gained from the recycled thermal energy from 7 to 3.
7 - Hot exhaust gases sent to heat exchanger to increase cycle efficiency using thermal energy in turbine exhaust to pre-heat diluent
supplied to combustion chamber.
8 - Low-pressure, low-temperature CO2 and H2O exit the heat exchanger and are routed for water removal and delivery of dry CO2
to compressor pump (CP).
5.9 Hydrogen
Hydrogen is often included as a component of broad decarbonization goals of the overall
economy, and its potential as a low-GHG alternative to natural gas—especially as a fuel for
combustion turbines—has received much attention of late. This section reviews the ability of
combustion turbine technologies to utilize hydrogen as a fuel. It also provides a basic
comparison of the different types of hydrogen production, notes the GHG emissions attributed to
these different production methods, and highlights a few programs working to address some of
the current challenges with the widespread availability of low-GHG hydrogen. This discussion of
hydrogen as a low-carbon fuel alternative for EGUs and the GHG emissions associated with its
production processes is for informational purposes and does not constitute EPA comment on
whether or how upstream activities or offsite GHG emissions could be considered under any
particular regulatory program.
Industrial combustion turbines have been burning byproduct fuels containing large percentages
of hydrogen for decades, and combustion turbines have been developed to burn syngas from the
gasification of coal in integrated gasification combined cycle EGUs (Goldmeer and Catillaz,
2021). Most combustion turbines currently used for electric generation can burn hydrogen blends
of 5 to 10 percent by volume with blends as high as 20 or 30 percent by volume being utilized in
certain situations. There are several recent examples of combustion turbine installations
proposing to blend up to 30 percent hydrogen with natural gas—with 100 percent capabilities
being developed.59 The Long Ridge Energy Generation Project in southeast Ohio is an example
of the potential to use hydrogen as fuel. Developers of the 485-MW project purchased H-class
GE turbines and plan to combust a blend of 5 percent industrial byproduct hydrogen (McGraw,
2021). Eventually the facility will increase the blend to 15 to 20 percent hydrogen before a
turbine modification is necessary for the plant to combust 100 percent hydrogen (Hering, 2021).
The power plant utilizes only a portion of the 1,600-acre property and is offering other industries
the opportunity to co-locate with eventual access to low-GHG energy as an incentive (McGraw,
2021). Another example is the Intermountain Power Authority (IPA) project in Utah. In March
2021, Siemens Energy announced a partnership with IP A to study the integration of large-scale
hydrogen production and storage with a combustion turbine. IPA's goal is to successfully
combust a blend of 30 percent hydrogen by 2025 to meet the emissions demands of customers of
the California Water and Power Authority. According to IP A, the long-term goal of the
converted 840-MW coal-fired plant is to combust 100 percent hydrogen by 2045 (Hering, 2021).
Additional proposed projects in the U.S. include the Brentwood power plant and the Cricket
Valley Energy Center in New York. The New York Power Authority is planning to demonstrate
the use of blended hydrogen, between 5 and 30 percent, on a simple cycle turbine at the
59 The use of large percentages of hydrogen can result in increased emissions of NOx. For EGUs, investments could
be needed in refinements of combustion controls and potentially in advanced SCRs (Goldmeer and Catillaz, 2021).
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Brentwood station (Palmer & Nelson, 2021; Van Voorhis, 2021). Cricket Valley is planning to
demonstrate a 5-percent blend of hydrogen at a combined cycle facility (GE, 2021). In addition
to other projects in New York, the integration of hydrogen and combustion turbines is planned
for sites in Virginia, Ohio, and Florida (MHI, 2020; Patel, 2020; Stromsta, 2020).
To fully evaluate the potential GHG reductions from using hydrogen as a fuel for combustion
turbines, it is important to consider the different processes of hydrogen production and that each
is associated with different amounts of GHG emissions.60 The different processes and energy
sources for producing hydrogen are listed below in Exhibit 5-12. For example, hydrogen can be
produced from water through a process called electrolysis. The energy intensity of electrolysis is
high, so potential overall GHG emission reductions from the use of hydrogen versus fossil fuels
are dependent on the fuel used to power the production process. If that form of energy is
renewable (e.g., solar) or nuclear, then the overall GHG reductions associated with using
hydrogen as a fuel could be significant.61 To date, the production of hydrogen via electrolysis
remains limited and expensive compared to other production technologies.
For the Long Ridge, IP A, Brentwood, and Cricket Valley projects mentioned above, the
objective is for those facilities to eventually transition to hydrogen produced from renewable
energy and electrolysis as it becomes available. In Europe, several projects have been announced
that will utilize offshore wind energy to power onshore electrolysis. Hydrogen produced in this
manner can be used to produce electricity and for other industries in the area and likely
incorporated into their "low-GHG" products. For example, a Danish energy company has begun
a project called "SeaH2Land" in which 2 gigawatts of offshore wind in the Dutch North Sea will
power the electrolysis of hydrogen.62 The hydrogen will then be utilized by industries in the
North Sea Port areas of the Netherlands and Belgium—home to industries such as ArcelorMittal
(steel), Yara (ammonia), Dow (material sciences), and the Zeeland Refinery (reformed methane)
(Frangoul, 2021; Orsted, 2021).
At the National Wind Technology Center in Boulder, Colorado, NREL has partnered with Xcel
Energy on a wind-to-hydrogen demonstration project. Powered by wind turbines and
60 Hydrogen can be produced through any of several different processes that emit varying amounts of GHGs. When
these varying levels of GHG emissions associated with hydrogen production, including upstream emissions, are
accounted for in an overall system GHG emissions analysis, there is currently no zero-GHG hydrogen. For example,
even electrolysis powered by solar or wind energy includes indirect upstream emissions of GHGs associated with
building the system components and potential land use impacts. To attempt to recognize and differentiate between
these varying levels of upstream emissions associated with hydrogen production, some organizations have
developed a convention for labeling hydrogen according to a color scheme to characterize the production process
(e.g., gray, brown, blue, green, etc.).
61 In addition to using electricity from nuclear energy in electrolysis, there are several other ways nuclear energy
could lower the overall GHG emissions associated with the production of hydrogen. First, nuclear energy could
provide steam for conventional steam methane reforming, replacing the natural gas-fired boilers typically used to
provide the steam. In addition, thermal energy from nuclear reactors could be used for low- and high-temperature
electrolysis, which is more efficient than cold electrolysis. Finally, high-temperature reactors could be used to
decompose water directly to hydrogen (and byproduct oxygen) using a thermochemical process. See
https://www.world-nuclear.org/information-librarv/energv-and-the-environment/hvdrogen-production-and-
uses.aspx.
62 See https://orsted.com/en/media/newsroom/news/2021/04/451073134270788/.
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photovoltaic arrays, hydrogen is produced via electrolysis and then stored63 or converted to
electricity by an internal combustion engine or fuel cell and fed to the grid at peak demand
(NREL, n.d.). The goal of this "Wind2H2" project is to research pathways to improve system
efficiencies, reduce costs, and increase competitiveness with traditional fossil fuels (NREL, n.d.).
The U.S. government is also working to reduce the cost of low-GHG hydrogen. The goal of
DOE's Hydrogen Shot initiative—known as "111"—is to reduce the cost of low-GHG hydrogen
by 80 percent to $1 per 1 kg in one decade (equivalent to $7.40 per MMBtu, DOE, 2020).64
Most of the dedicated hydrogen produced today originates from natural gas using a process
known as steam methane reforming (SMR). When this type of production occurs without CCUS,
it emits relatively large amounts of CO2 (EPRI, 2020). The second-largest source of dedicated
hydrogen production is from the gasification of coal without CCUS. According to analysis by
GE, current global demand for hydrogen is 70 million tons per year and 90 percent of that
demand is met by reforming natural gas or coal. From an overall GHG emissions perspective, the
use of hydrogen from steam methane reforming would increase emissions approximately 50
percent compared to using the natural gas directly to produce electricity from a combustion
turbine (Goldmeer and Catillaz, 2021). With the addition of CCUS, hydrogen produced from
steam methane reforming and coal gasification can have overall GHG emissions reduction
benefits compared to the use of natural gas directly to produce electricity from a combustion
turbine.65
Exhibit 5-12. Types of Hydrogen Production
Power Source
Production Process
Coal
Gasification
Natural Gas
Steam Methane Reforming
Natural Gas or Coal
Steam Methane Reforming/Gasification w/CCUS
Nuclear
Electrolysis, thermochemical, and thermal energy for steam methane
reforming
Renewable
Electrolysis
63 Currently available utility batteries typically have 4 hours or less of storage and are not used for long-term
storage. Longer-term storage is typically done using pumped hydro or compressed air. A potential use of hydrogen
is to serve as long-term energy storage. Electricity generated from renewables or nuclear power during periods of
low electric demand can be converted to hydrogen and stored onsite for long periods. In addition, if this hydrogen is
injected into the existing natural gas distribution network, the distribution system itself can act as the storage device.
Another advantage of injecting low-GHG hydrogen into the existing natural gas distribution network is that the
energy from renewable generation can be transported to end users without using the electric grid—potentially
reducing the need for additional transmission capacity and the associated negative environmental and societal
impacts.
64 Significant projects in the U.S. include the Green Hydrogen Coalition's HyDeal Los Angeles
(https://www.ghcoalition.org/hvdeal-la') and the HY STOR project in Mississippi (https://hvstorenergy.com/').
65 In the SMR process, CO2 can be captured from the shifted syngas, the pressure swing adsorption tail gas, and the
SMR flue gas. In addition, research is ongoing to develop processes that convert methane directly to hydrogen and
carbon solids. See https://www.pnnl.gov/news-media/new-clean-energv-process-converts-methane-hvdrogen-zero-
carbon-dioxide-emissions.
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A noteworthy characteristic of hydrogen used as a fuel and blended into natural gas is the
volume of hydrogen necessary to achieve CO2 reductions at the EGU stack. Since hydrogen and
methane have different volume energy densities, when blending natural gas and hydrogen, the
CO2 emissions reduction is smaller than the volume percent of hydrogen in the mixture
(Goldmeer and Catillaz, 2021). For example, as illustrated below by Exhibit 5-13, to achieve a
50 percent reduction in EGU stack emissions of CO2 requires a fuel blend that is approximately
75 percent hydrogen; a 75 percent CO2 reduction requires a blend of 90 percent hydrogen
(Goldmeer and Catillaz, 2021).
Exhibit 5-13. Hydrogen to methane fuel blend volume ratios and CO2 reductions.
Hydrogen (volume %)
0 10 20 30 40 50 60 70 80 90 100
inn —
3"
£ 80
c
0
VP 60
u
"S 40
OH
0~ 20
U
0
1(
)0 90 80 70 60 50 40 30 20 10 0
Methane (volume %)
Source: Goldmeer & Catillaz (2021)
5.9.1 Ammonia
While hydrogen is a stable and versatile fuel that could potentially reduce GHG emissions across
all sectors of the economy, a disadvantage of hydrogen is the relatively low volume energy
density. Storage of large amounts of hydrogen generally requires high pressures or cryogenic
temperatures. To increase the energy density, hydrogen gas can be converted to ammonia.66
Ammonia is a stable colorless gas that consists of nitrogen and hydrogen. It is a "drop-in ready"
fuel capable of being added or blended directly into existing natural gas infrastructure and could
be combusted in a combustion turbine. A drawback to ammonia is the energy required to convert
hydrogen to ammonia (Boerner, 2019). Siemens has a set up a demonstration plant in the United
Kingdom that utilizes wind power to produce the energy for hydrogen electrolysis, creating
green67 ammonia (Boerner, 2019).
66 Combining hydrogen with CO2 to produce methanol or dimethyl ether (DME) also increases the energy density.
67 The production method of the hydrogen used to create ammonia impacts the carbon intensity of ammonia. Like
hydrogen, ammonia has applications across multiple sectors of the economy.
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6.0 Fuels Burned in Combustion Turbine EGUs and Overall GHG
Considerations
This section provides an overview of the types of fuels that are burned in combustion turbines
and the GHG emissions associated with these fuels, including consideration from an overall
GHG emissions perspective. The discussion of each fuel includes a description of the production
process and the fuel's potential to be burned in a combustion turbine based on existing turbine
technology. The section also includes general discussion of the overall GHG emissions profile
associated with each fuel's production process, including consideration of offsite (i.e., upstream)
emissions, and potential GHG mitigation measures associated with these upstream emissions.68
In particular, this section highlights several regulations, policies, and programs to reduce GHG
emissions, including overall GHG emissions.
The following discussion is intended to facilitate the sharing of information that may assist states
and local air pollution control agencies, tribal authorities, and regulated entities considering
and/or implementing similar technologies and measures as part of a broader GHG reduction
strategy. As described in Section 2.3, many public and private stakeholders have enacted various
programs to reduce GHG emissions. These programs include efforts to reduce onsite GHG
emissions, as well as offsite measures and measures that consider the overall GHG emissions
outcomes of their operations, including emissions that occur upstream of a facility. Although
information and experience gleaned from such existing efforts may or may not be relevant under
any particular CAA program,69 they are nonetheless valuable to the broader discussion of
potential strategies for reducing GHG emissions from new combustion turbines. Thus, we are
sharing the following information for the benefit of a broad group of stakeholders, including
industry and state authorities, as they explore options for addressing GHG emissions associated
with new combustion turbine projects.
Determining the overall GHG emissions associated with the use of various fuels at combustion
turbine EGUs can, where applicable, include emissions beyond just the stack exhaust and could
include upstream GHG emissions associated with the production, processing, and transmission
or transportation of different fuels that can be used to generate electricity. For the purposes of
this discussion, consideration of the overall GHG emissions associated with the production and
use of a fuel could encompass upstream emissions, including avoided emissions. Avoided
emissions in this context generally represent GHG reductions that may result from upstream
processes that are put in place to avoid the release of or to capture and utilize gases that would
otherwise be released into the atmosphere. Examples include: (1) natural gas produced and
delivered in a way that reduces methane emissions from supply chains versus business as usual
and (2) the capture and utilization of certain GHGs by EGUs—such as biogas and industrial
byproduct gases—that would otherwise be released regardless of their use in a combustion
turbine to produce electricity. While use of these types of fuels in combustion turbine EGUs may
68 As a general matter, the fuels that are burned in combustion turbines are produced via different processes that
result in varying amounts of GHG emissions. Consideration of overall GHG emissions in an analysis of a specific
fuel's use could entail recognition of emissions associated with not only the fuel's combustion, but also upstream
activities and systems associated with the production, processing, transport, etc., of the fuel prior to use in a
combustion turbine. The scope of GHGs considered in such an analysis may depend on the program, policy, or other
defining parameter.
69 EPA is providing this discussion for informational purposes only and is making no judgment about whether
upstream or avoided emissions are relevant under any particular regulatory program or scheme.
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not reduce direct CO2 emissions at the stack, consideration of upstream GHG emissions,
including those that are avoided during the fuel production process or utilization of emissions
that would occur anyway and are not already used in a productive application, may contribute to
overall GHG emissions reductions. Specifically, many of the fuels discussed in this section have
the same (or higher) onsite (direct) GHG emissions as natural gas. However, when offsite
(indirect) GHG emissions are considered (e.g., avoided methane emissions) the overall GHG
emissions of the fuel can be lower by virtue of the way in which the fuel or a portion of the fuel
is produced or distributed.70
In this technical paper, the discussion of upstream GHG emissions considerations, including
avoided emissions, is meant to generally acknowledge that there may be some indirect or offsite
emissions that occur during fuel production, transmission, and use, and that approaches to
mitigate some of these associated but indirect GHG emissions (i.e., not emitted directly out the
stack) could be considered under some programs. This document focuses on the potential
technical merits of the fuels and approaches discussed; again, inclusion of upstream GHG
emissions considerations in this white paper does not represent a determination that it is possible
to consider offsite/upstream emissions or activities under any particular regulatory program. It
should also be noted that some input fuels' GHG emissions from production and/or distribution
processes may already or in the future be accounted for by other GHG reduction policies or
programs, which could have the potential to be counted in more than one program.
6.1 Methane Emissions
The U.S. government tracks GHG emissions, including fugitive emissions, through
complementary data collection programs. First, the Inventory of U.S. Greenhouse Gas Emissions
and Sinks provides national-level estimates for all anthropogenic sources of emissions and
provides annual estimates starting in 1990. Second, EPA implements the Greenhouse Gas
Reporting Program under the CAA, in which facilities, including facilities in the oil and gas
sector, that exceed program thresholds report their emissions and other data each year. Estimated
methane emissions from these and other sources can provide an idea of the scale of historic and
current methane emissions relative to overall GHG emissions from EGUs. Total emissions of
methane and CO2 from upstream and onsite sources can be summed as lb CChe/MMBtu, where
"CChe" is a CO2 equivalency that applies a value for the GWP of methane to the quantity of
methane that is released to the atmosphere, and then adds the product to the CO2 released when
natural gas is burned (Simmons, 2020b).71
An example of where equivalency is useful is determining the relative importance of methane
loss. Methane loss is the percent of delivered methane that is released upstream of the delivery
point (Simmons, 2020a). There are multiple studies that estimate the upstream methane
70 Consideration of additionality may be relevant in some policy contexts. Such consideration could entail taking
into account current uses and procurement pathways (e.g., production, processing, and transmission or
transportation) of methane that can potentially be used as fuel in combustion turbines to generate electricity,
including evaluating the GHG emissions profile under current practices (i.e., business as usual). Such an analysis
may be useful in determining the extent to which new systems or utilization pathways, such as using methane to
power combustion turbines in lieu of business-as-usual practices, would result in further GHG reductions relative to
those current practices.
71 In 2019, the electric power sector emitted 1,606 MMT CO2Q. See Inventory of U.S. Greenhouse Gas Emissions
and Sinks: 1990-2019 (2021). (U.S. EPA, 202li)
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emissions from the production and delivery of natural gas (e.g., NW Council, 2021; Rai eta/.,
2021), though it should be noted that comparisons of upstream GHG estimates are only possible
if the same assumptions and assessment parameters are used when conducting the analysis (e.g.,
same boundaries). As previously stated, when combusted, methane emits 117 lb CCh/MMBtu. At
an upstream methane emissions rate of 1.5 percent, assuming no other upstream GHGs are
accounted for, the overall emissions rate of natural gas is 134 lb CChe/MMBtu.72 If the methane
emissions rate is lowered to 1 percent, the overall emissions rate would be 128 lb CChe/MMBtu,
a GHG benefit that is equivalent to a reduction in fuel use of approximately 4 percent. This level
of GHG reduction is similar to the incremental differences in efficiency between new combined
cycle designs. Therefore, actions to avoid upstream methane emissions can be an important
factor in efforts to reduce the overall GHG emissions from a new combustion turbine EGU.
6.2 Conventional and Unconventional Natural Gas
In the lower 48 states, most combustion turbine EGUs burn natural gas with distillate oil backup
for periods when natural gas is not available. Areas of the country without access to natural gas
often use distillate oil or some other locally available fuel. Combustion turbines can burn either
gaseous or liquid fossil fuels, including but not limited to kerosene, naptha, synthetic gas,
biogases, and liquefied natural gas (LNG).
Natural gas consists of primarily methane and can be derived from multiple sources. These
include conventional non-associated and associated natural gas and unconventional shale gas,
tight gas, and coal bed methane. After the raw gas is extracted from the ground, the gas is
processed to remove impurities and to separate methane from other natural gas liquids (NGLs)
and other gases to produce "pipeline quality gas" (C2ES, n.d.). This gas is sent to intermediate
storage facilities prior to being piped through transmission feeder lines to a distribution network
on its path to storage facilities or end users.
72 The calculation uses a GWP of 25 for methane—the 100-year GWP.
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Exhibit 6-1. Schematic geology of natural gas resources.
Non-associated natural gas describes natural gas that is the primary saleable product that results
from drilling activity. Associated natural gas is natural gas that is a byproduct of oil extraction.
During the past 20 years, advances in hydraulic fracturing {i.e., fracking) and horizontal drilling
techniques have opened new regions of the U.S. to gas exploration, such as unconventional shale
and impermeable rock that produce what is known as tight natural gas. Coal bed methane is
unconventional natural gas that is extracted by drilling into underground coal seams and
pumping water out of the coal to release trapped natural gas. These techniques and rapid
expansion have been accompanied by the construction of new infrastructure capable of
processing and delivering reliable supplies of fuel to more customers in more markets. Exhibit 6-
2 shows the increase in natural gas production in the U.S. over time. Note the sharp increase that
begins around 2010.
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Exhibit 6-2. U.S. natural gas marketed production.
Million Cubic Feet
— U.S. Natural Gas Marketed Production
eia' Source: U.S. Energy Information Administration
6.2.1 Avoided Methane Emissions Associated with Natural Gas
This section describes GHG emissions associated with natural gas extraction and distribution. It
also discusses example practices and programs that can assist with mitigating (i.e., avoiding)
GHG emissions from these upstream activities. The following discussion sets forth a range of
different approaches, examples, and estimates of GHG emissions; inclusion here does not
constitute endorsement of any particular approach or estimate in any particular context.
When natural gas is the only fuel produced by a drilling activity (non-associated gas), the
primary sources of upstream GHG emissions (i.e., emissions other than those from ultimate
combustion), are methane emissions that result from recovery and processing activities,
unintentional methane leaks, and co-produced CO2 that is often vented to the atmosphere.
Reductions in intentional methane emissions and leaks and the utilization or sequestration of the
co-produced CO2 reduce the overall GHG emissions from the natural gas production. When
associated natural gas is co-produced during oil extraction, the natural gas can be vented or
flared instead of being used productively either onsite or by being transmitted offsite. Using
associated gas productively, or otherwise limiting flaring and venting, can also reduce overall
GHG emissions from associated gas. Many stakeholders, including federal, state, and local
regulators as well as electricity and oil and gas industry groups, are working on policies and
programs to reduce upstream GHG emissions associated with natural gas production.
On November 15, 2021, EPA published proposed rules, titled "Standards of Performance for
New, Reconstructed, and Modified Sources and Emissions Guidelines for Existing Sources: Oil
and Natural Gas Sector Climate Review," to address emissions of methane from the oil and gas
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sector. The rulemaking proposed to strengthen current national standards for methane emissions
from new, reconstructed, and modified sources involved in the production and processing of
natural gas. The Agency also proposed new guidelines to address emissions from existing
sources.73
In addition, there are other programs that complement EPA regulations. One such effort is EPA's
Natural Gas STAR Methane Challenge Program. This Agency collaboration with the oil and gas
industry recognizes companies that make specific and transparent commitments to reduce
methane emissions. More than 60 companies are program Partners and share the goal of
transparently reporting systematic and comprehensive voluntary actions to reduce methane
emissions. The program requires a partnership agreement with EPA, an implementation plan,
and the collection and submittal of data annually. Partners can participate in one, or both, of the
program's two commitment options: 1) the Best Management Practice commitment option in
which Partners commit to company-wide implementation of best management practices to
reduce methane emissions from key sources, and 2) the ONE Future Commitment Option in
which Partner's commit to achieving a specified emissions intensity rate by a future target date.
Partners in Methane Challenge's ONE Future Commitment Option are also members of the ONE
Future Coalition, a group of more than 45 natural gas companies working to reduce emissions—
specifically methane intensity—across the natural gas supply chain. ONE Future Coalition
members agree to measure their emissions and track their progress using EPA-approved
reporting protocols (ONE Future, 2021). ONE Future Coalition members can choose to also join
the Methane Challenge ONE Future Commitment Option but are not required to do so.
Companies in the oil and gas industry are also collaborating and working toward reductions
through the voluntary Oil and Gas Climate Initiative (OGCI). Comprised of 12 CEOs from some
of the world's largest oil and gas producers, OGCI has stated objectives of achieving net-zero
carbon emissions by taking direct action to reduce upstream, systemwide methane and carbon
intensities, developing low-carbon alternatives, and investing in technologies such as CCUS
(OGCI, n.d.). OGCI supports bringing an end to routine flaring and venting by 2030. In addition,
multiple organizations are working on certification programs for natural gas produced with lower
methane emissions.74
6.3 Methane Emissions from Abandoned Oil and Gas Wells
Unplugged and abandoned (including orphaned) oil and gas wells can emit significant quantities
of methane into the air in addition to leaching toxic substances into the soil and water. The
numbers of these wells are increasing rapidly and pose a serious environmental and health
challenge to many state, tribal, and federal agencies. If these methane emissions were captured,
the release of methane to the atmosphere could be avoided and instead be used productively as
fuel. Alternatively, funding the remediation of wells (e.g., by plugging currently unplugged and
abandoned wells) provides an opportunity to reduce overall GHG emissions associated with
natural gas production (Ehli 2021).
73 See https://www.epa.gov/controlling-air-pollution-oil-and-natural-gas-industrv.
74 See e.g., https://www.rff.org/events/rff-live/greening-gas-creating-market-low-methane-natural-gas/:
https://miq.org/: https://marcellusdrilling.com/2Q21/01/new-methane-certification-scheme-for-green-natural-gas/:
https://marcellusdrilling.com/2018/09/southwestern-sells-lst-certified-responsible-gas-to-ni-resources/: and
http://www.sustainableshale.org/performance-standards/
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According to EPA estimates, there are approximately 3 million abandoned (including orphaned)
wells in the U.S., and in 2019 these wells emitted more than 6.6 million metric tons carbon
dioxide equivalent (MMT CChe).75 Many of these wells date back to drilling operations from
more than 100 years ago when recordkeeping and reporting were not as accurate. In many
instances, these historical wells have been buried; nevertheless, they continue to emit significant
amounts of methane and leach toxic substances, such as arsenic, benzene, hydrogen sulfide, and
chloride into the surrounding soil and water (Groom, 2020). Each year more wells are being
abandoned or orphaned, which occurs when a previous operator or owner cannot be identified or
held liable for remediation and associated costs (Wolf, 2021). The 2021 Infrastructure
Investment and Jobs Act included $4.7 billion in state grants for plugging and remediating
abandoned and orphaned gas wells.76
6.4 Coal Mine Methane (CMM)
Coal mine methane (CMM) is the methane released from coal and the surrounding coal seam due
to mining activities (EPA, 2021). It is primarily generated from underground mines and is
emitted from active mines through degasification systems {i.e., drained methane or drainage
system methane (DSM)) and ventilation systems {i.e., ventilation air methane (VAM)) as well as
from closed (or "abandoned") mines {i.e., abandoned mine methane (AMM)) and from surface
mines {i.e., surface mine methane (SMM). In active mines, degasification systems consisting of
boreholes,77 pipelines to the surface, and a surface pump station, are installed in the coal seam
before or during mining to remove some of the methane and relieve the demand on the
ventilation systems to maintain a safe air quality in the mines. The ventilation systems in
underground mines release VAM emissions, which are typically dilute, consisting of less than 1
percent methane. Abandoned mines release AMM, even though active mining no longer occurs.
SMM emissions are released from surface mining activities. When coal ore is broken up and
transported, the resulting methane emissions are referred to as post-mining emissions. According
to EPA estimates, in 2019, total CMM emissions in the U.S. were 53.3 MMT CChe.78
EPA's Coalbed Methane Outreach Program (CMOP) is a voluntary program that promotes the
profitable recovery, utilization, and mitigation of CMM (U.S. EPA, 2021b). CMM can be
destroyed,79 used to generate useful thermal output and electricity, or upgraded for injection into
the natural gas distribution network. Destruction of CMM can be accomplished through
combustion/flaring or catalytic combustion of VAM. CMM can also be recovered and processed
to produce pipeline quality natural gas for use as a fuel.
6.5 Biogas and Biomethane
Biogas is produced by the anaerobic microbial digestion of organic material from a variety of
sources. Anaerobic digestion occurs or is otherwise deployed at landfills, wastewater treatment
75 264 kiloton (kt) of methane and 6 kt of CO2. See Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-
2019 (2021). (U.S. EPA, 202li)
76 See https://www.doi. gov/sites/doi. gov/files/orphan-well-mou-01 -13 -2022.pdf/
77 Degasification systems can also include a network of pipelines. See
https://www.globalmethane.org/training/CMM module5/storv.html.
78 47.4 MMT CChe from coal mining and 5.9 MMT CChe from abandoned underground mines. 1,895 kt of methane
from coal mining and 237 kt of methane from abandoned underground mines. See Inventory of U.S. Greenhouse
Gas Emissions and Sinks: 1990-2019 (2021). (U.S. EPA, 202li)
79 Depending on the concentration, CMM can be destroyed through catalytic oxidation or by flaring.
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facilities, and in the agricultural sector. The resulting captured biogas primarily consists of a
mixture of methane and CO2, plus other trace gases, and is often used directly for electricity
generation, process heat, or CHP (EPRI, 2020). As a general matter, any form of biomass (e.g.,
wastewater treatment residues; livestock byproducts; food, forest, and crop materials or residues;
yard trimmings) can be anaerobically digested and produce bio-based gases.
In addition to direct onsite use, biogases can be refined/upgraded to remove non-methane
elements to produce biomethane, sometimes called renewable natural gas (RNG), which can be
injected into the natural gas distribution network (DOE, n.d.). Currently, upgrading biogas to
biomethane is energy intensive80 and connecting to a pipeline network is often not economically
viable for small biogas producers (EPRI, 2020). However, more centralized upgrade facilities
with natural gas interconnections can reduce costs.
6.5.1 Upstream Biogas GHG Emissions
To the extent that biogas from any of these sources would be generated anyway (e.g., as a
byproduct) and emitted to the atmosphere, capturing it for use in a combustion turbine to
displace use of fossil-based fuels may result in a lower overall GHG emissions profile of that
turbine. It is important to note that CO2 emissions from the stack resulting from combustion of
biogas in a combustion turbine would not be reduced relative to the use of natural gas. However,
in certain contexts, the overall GHG emissions profile associated with the use of biogas could
potentially be lower than the natural gas profile if avoided emissions are considered (noting that
the upstream overall GHG emissions outcomes depend on a range of factors including business-
as-usual practice applied to the biogas81).
The federal government and state governments have several regulatory and voluntary initiatives
that reduce methane emissions from landfills, the agricultural sector, and wastewater
management. Federal regulatory requirements include subpart XXX of 40 CFR part 60
(Standards of Performance for Municipal Solid Waste Landfills That Commenced Construction,
Reconstruction, or Modification After July 17, 2014) that establishes requirements to collect and
treat landfill gas from certain new municipal solid waste (MSW) landfills and subpart Cf of 40
CFR part 60 (Emission Guidelines and Compliance Times for Municipal Solid Waste Landfills)
that requires states to establish requirements for certain existing MSW landfills to collect and
treat landfill gas. In 2019, methane emissions from U.S. landfills were 114.5 MMT CChe or
approximately 17% of the national total emissions of methane.82 In addition to regulatory
efforts, EPA's Landfill Methane Outreach Program (LMOP) is a voluntary program that works
cooperatively with industry stakeholders and waste officials to reduce or avoid methane
emissions from landfills. LMOP encourages the recovery and beneficial use of biogas generated
from MSW (U.S. EPA, 202Id). The LMOP Landfill and Landfill Gas Energy Database is a data
repository for most MSW landfills in the U.S. that are either accepting MSW or closed in the
past few decades. As of September 2021, approximately 20 percent of MSW landfills provide
80 The additional processing necessary to convert biogas to biomethane can reduce the GHG benefits of the use of
the biofuel.
81 Consideration of current biogas production and biogas end uses/disposal pathways used may be useful in
determining the extent to which employing new systems or utilization pathways would result in further GHG
reductions relative to existing practices.
82 4,580 kt of methane. See Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2019 (2021). (U.S. EPA,
202 li)
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landfill gas to energy projects. EPA estimates that approximately an additional 20 percent of
MSW landfills could economically recover their landfill gas for a useful purpose (U.S. EPA,
202 le).
For the agricultural sector, EPA's and the U.S. Department of Agriculture's AgSTAR initiative
is a collaborative program that promotes the use of biogas recovery systems to reduce methane
emissions from livestock waste (U.S. EPA, 2021f). In 2019, livestock GHG emissions (enteric
fermentation plus manure management) were 260.6 MMT CChe.83 AgSTAR provides
information on current biogas recovery projects (U.S. EPA, 202lg) and market opportunities of
potential additional projects (U.S. EPA, 202 lh). AgSTAR estimates there are more than 300
dairy and swine manure anaerobic digester biogas recovery systems in the U.S. and 8,100
additional operations could support biogas recovery systems. In addition, new technologies may
make biogas systems feasible at poultry and beef lot operations.
In July 2021, the North Carolina Farm Bill included provisions to streamline permitting for the
construction of biogas digester systems to collect methane from livestock waste lagoons for the
purpose of producing electricity. According to North Carolina's Clean Energy Plan (NC DEQ,
2019), there are siting concerns for biogas plants that affect feasibility. These include the long-
term production potential of waste ponds and the pipeline distance to farms. In many cases, RNG
producers will seek to collect biogas from multiple farms in proximity to each other for the
projects to be economically viable.
An example of the use of biomethane in the utility sector is the Optima KV project in eastern
North Carolina (Cavanaugh, 2021). In this project, five hog farms pipe their raw biogas to a
central facility where the biogas is further processed prior to injection into a natural gas pipeline.
Duke Energy uses this biomethane for power production at two combined cycle facilities. While
the project only supplies approximately 9 MMBtu/h of biomethane to Duke Energy, the overall
GHG reductions are potentially substantial. Assuming the biogas Duke Energy uses at its two
facilities would otherwise be emitted to the atmosphere without any treatment, the GHG
emissions would be approximately 42,000 tons of CChe per year. Relative to this assumed
business-as-usual scenario, capturing the biogas through this project and using it to displace
fossil natural gas provides enough GHG reductions to offset approximately 7 percent of the
annual emissions from a typical combined cycle facility.84
Another sector with significant biogas recovery potential is municipal wastewater treatment
plants. In the U.S., there are more than 16,000 wastewater treatment plants, but only about 1,300
use anaerobic digestion to produce biogas (DOE, n.d.). In 2019, wastewater from these facilities
emitted 18.4 MMT C02e85 methane in the U.S.86
83 9.637 kt of methane and 66 kt of nitrous oxide. See Inventory of U.S. Greenhouse Gas Emissions and Sinks:
1990-2019 (2021). (U.S. EPA, 202li)
84 In 2019, the average combined cycle EGU emitted 560,000 tons of CO2. If instead, the business-as-usual baseline
is that the biogas would be flared (and not emitted directly to the atmosphere), the additional reductions from the use
of biomethane for energy would only account for the reduced use of fossil fuel derived natural gas—offsetting
approximately one percent of the emissions of an average combined cycle EGU.
85 736 kt of methane. See Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2019 (2021). (U.S. EPA,
202 li)
86 It should also be noted that producing biogas from wastewater treatment does not have potential additional land
use concerns.
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6.6 Industrial Byproduct Fuels
Other potential fuels for combustion turbines include combustible industrial byproducts. These
fuels are often used on site in boilers but can also be flared or vented directly to the atmosphere.
To the extent industrial byproduct fuels are not already being used to power industrial processes
(meaning that these emissions are currently being released without any productive use
applications), using them to generate electricity in lieu of natural gas could result in minimal
additional overall GHG emissions.87
Blast furnace gas (BFG) is one of these potential fuels. In a typical steel-making process,
metallurgical coal {i.e., coking coal) is used in a blast furnace to both produce the heat necessary
to power a blast furnace and to reduce the iron ore to form molten pig iron. BFG is the byproduct
of the chemical reduction of iron ore and typically contains about 5 percent hydrogen, 50 percent
nitrogen, and 20 percent CO2. BFG has a heating value of about 100 Btu/ft3, or about one-tenth
the heating value of natural gas (Seaman, 2013). With such a low heating value, the byproduct
gas is insufficient for use in high-efficiency gas turbines and needs to be captured, processed
{i.e., particulates removed), and combined with coke oven or natural gas, which have
significantly higher amounts of hydrogen and methane. It is possible to use processed BFG in a
combustion turbine to generate electricity to power the steel-making facility as well as process
heat. In some instances, the electricity can be sold to the grid. Steel mills with heat recovery units
and combustion turbines for power generation not only cite reduced energy costs, increased
efficiency and reliability, and environmental benefits as motivating factors, but also job creation
and preservation (Seaman, 2013).88
6.7 Liquid Fuels
The primary liquid fuel used in combustion turbines is fuel oil that is either used a backup fuel or
in locations where natural gas is not available. For fuel oil, there are two approaches that could
potentially reduce overall GHG emissions. One is to substitute fuels with lower overall GHG
emissions relative to conventional fuel oil derived from petroleum products. Another option
would be conventional fuel oil that has been refined using low carbon hydrogen (IHS Markit,
2021).
87 In general, replacing onsite boilers with a combustion turbine CHP application reduces net GHG emissions
compared to generating the thermal output and electric output separately. If the gas is typically flared or released
untreated to the atmosphere, the overall GHG reductions would be larger.
88 Other possibilities for reduced GHG emissions from the steel-making process include Hydrogen Breakthrough
Ironmaking Technology (HYBRIT), a novel approach being explored by European steel manufacturers. In this
scenario, GHG are reduced by replacing coke and other fossil fuels with hydrogen (Peplow, 2021). Other options for
steel mills to reduce CO2 emissions are syngas (produced from natural gas) or full CCUS.
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7.0 Embodied Carbon of a Combustion Turbine EGU
Multiple states and local governments are taking steps to reduce the embodied carbon in building
materials used for construction projects as part of improving the sustainability of construction
projects.89 Embodied carbon is the total GHG emissions attributed to the materials used in a
construction project. Embodied carbon includes extraction, transportation, manufacture,
construction, maintenance, sequestration, absorption, and end of life/disposal. For fossil fuel-
fired EGUs, the majority of the overall GHG emissions associated with the EGU result from
operation,90 but there are opportunities to reduce the embodied carbon of the EGU. Options to
reduce embodied carbon include construction techniques that reduce the quantity of materials
necessary for construction and the use of materials with reduced embodied carbon (e.g., low
GHG concrete and steel).
For example, if a 250-MW simple cycle facility uses 3,200 cubic yards of structural concrete,
there are various lower-GHG concrete options available to reduce the embodied carbon of the
construction project. Assuming there are 400 lb of embodied carbon91 in each cubic yard of
business-as-usual concrete, the structural concrete alone would include 640 tons of embodied
CChe. Even if the owner/operator used concrete with no embodied carbon, this GHG reduction
would only be equivalent to the emissions from operating the facility at full load for
approximately 4 hours. Therefore, while consideration of embodied carbon may be part of
overall programs and/or initiatives to reduce GHG emissions and could enhance the market for
low-GHG building materials, it is not a primary consideration for the overall GHG emissions for
combustion turbine EGUs.
89 See https://carbonleadershipforum.org/states-act-to-reduce-embodied-carbon/:
https://www.greenbuildingadvisor.com/article/new-state-laws-would-lower-climate-impact-of-concrete: and
https://www.marincountv.org/-/media/files/departments/cd/planning/sustainabilitv/low-carbon-concrete/12172019-
update/low-carbon-concrete-code.pdf?la=en
90 While renewables and nuclear generation have no onsite GHG emissions, the embodied carbon of these
generation technologies is significantly more than fossil fuel-fired EGUs.
91 Embodied carbon is expressed in units of CChe.
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8.0 Alternative to Combustion Turbines
The primary competitors for simple cycle facilities are reciprocating internal combustion engines
(RICE) facilities. Natural gas-fired RICE are currently limited to approximately 20 MW in size,
but multiple RICE installations can effectively create power plants of hundreds of MW (EIA,
2019; Wartsila, 2020a). RICE tend to have higher efficiencies than comparable simple cycle
facilities, but emissions of criteria and hazardous air pollutants (HAPs) can be higher. The
maximum practical brake thermal efficiency92 of a RICE is approximately 60 percent (Edwards
et al., 2011) and the most efficient available models have design efficiencies of 50 percent
(LHV). While recoverable byproduct heat (often called waste heat) from RICE is lower than that
of combustion turbines, the energy can still be used for hot- and low-pressure steam applications.
A RICE CHP can significantly improve the overall efficiency of a RICE EGU. In addition,
newer engine designs and technologies have the potential to further improve the efficiency of
alternatives to combustion turbine EGUs (Bloom Energy, 2021; Mainspring, 2021).
An important consideration when comparing the overall GHG performance of RICE to
combustion turbines is that certain RICE designs have higher methane slip93 than combustion
turbines, reducing the efficiency advantage. Recent studies and AP-42 data show that lean burn
designs yield higher combustion slip, averaging 3 percent of methane feed gas, while rich burn
designs average 0.4 percent of methane feed gas emitted as slip (U.S. EPA, 2020a,b; Vaughn et
al., 2019, 2021; Zimmerle et al., 2019). It appears that after-exhaust controls, such as selective
noncatalytic reduction (SNCR), reduce slip observed in recent field studies. We also note that
RICE manufacturers are developing designs with improvements to turbochargers, design
components, ignition systems, the use of exhaust gas recirculation (EGR), and oxidation
catalysts that can reduce unburned methane. Stationary, land-based RICE can reduce methane
slip to 1 gram per kilowatt hour (g/kWh) (less than 1 percent) (Ewing, 2020; Wartsila, 2020b)
and two-stroke engines can reduce methane slip to less than 0.3 g/kWh (less than 0.2 percent)
(MAN Energy Solutions, n.d.).94
92 Brake thermal efficiency is the ratio of power available at the crankshaft divided by the heat input (i.e., fuel input)
to the engine.
93 Methane slip is unburned methane that passes through the engine and is emitted in the exhaust.
94 A 1 percent methane slip increases onsite stack GHG emissions in CChe by approximately 10 percent, and a 0.2
percent slip increase onsite stack GHG emissions in CChe by approximately 2 percent. In comparison, combustion
turbines methane slip estimates are approximately 0.01 percent and would increase onsite stack CChe emissions by
approximately 0.1 percent.
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EPA Contacts
Christian Fellner
U.S. EPA
OAQPS/SPPD/ESG
Mail Code D243-02
Research Triangle Park, NC 27711
Phone: 919-541-4003
fellner.christian@epa.gov
John Ashley
U.S. EPA
OAQPS/SPPD/ESG
Mail Code D243-02
Research Triangle Park, NC 27711
Phone: 919-541-1458
ashl ev.i ohn@,epa. gov
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