Can Future Coal Power Plants Meet
CO 2 Emission Standards Without
Carbon Capture & Storage?
October 2015
Insert Photo
Executive Summary
Coal Technologies
The U.S. Environmental Protection Agency (EPA) released its “new
source performance standard” (NSPS) on August 3, 2015, requiring new coal power plants in the United States to emit no more
than 636 kg (1400 lb) of carbon dioxide (CO2) per megawatt-hour
(MWh) of gross power produced. Current state-of-the-art coal-fired
plants, based on operations at ultrasupercritical (USC) steam conditions above 593°C (1100°F), emit approximately 800 kg (1760 lb)
CO2/MWh. To reduce CO2 emissions from new coal power plants
by more than 20%, EPA’s standard is assumed to require carbon
capture and storage (CCS) technology to be applied. Several U.S.
states and a number of countries have announced or are considering
similar restrictions on CO2 emissions from new coal-fired plants.
Current CCS technologies and anticipated near-term commercial
offerings will not only increase capital costs but also impose significant performance penalties, challenging the competitiveness of new
coal generation. Many locations worldwide lack suitable geology
for CO2 storage, one of several factors expected to constrain CCS
deployment. This poses a question: Is technology available or in
development that would enable power plants fueled solely by coal
to operate so efficiently that a CO2 emission standard of 636 kg/
MWh (1400 lb/MWh) or less could be met without partial CCS?
Based on the high-level assessment described in this white paper,
EPRI has determined that the answer is a qualified “yes,” as summarized below and indicated in the figure at right:
• Even with steam temperatures exceeding 800°C (1500°F)—some
200°C (360°F) higher than those currently achievable—USC coal
plants based on the conventional Rankine steam-electric cycle
alone are not capable of meeting the standard.
• USC plants used in high-efficiency combined heat-and-power applications are capable of meeting the standard—but only at sites
with “thermal hosts” capable of using large volumes of steam.
• Gasifying coal then firing the synthesis gas in a conventional
combined-cycle configuration can meet the standard—but only
for certain types of gasifiers, and only when the integrated plant is
fueled by high-quality coal.
• Assuming further technological progress, coal gasification provides multiple pathways for achieving the standard, including
gasifiers integrated with solid oxide fuel cells; with combinedcycle plants having firing temperatures for the combustion turbine approaching 1700°C (3100°F); or with novel cycle designs.
Low-Carbon Coal Technology Assessment
2
EPA
Standard
CO2 Emission Intensity,
kg/MWh (gross)
Advanced Ultrasupercritical (USC) Steam Plant
750
Integrated Gasification Combined-Cycle (IGCC) Plant
700
Advanced USC Plant + 12.5% Steam Utilization
USC Plant + 14% Steam Utilization
636
IGCC Plant + High-Quality Coal
627
Integrated Gasification Supercritical CO2 Brayton Cycle Plant
603
Integrated Gasification Fuel Cell (IGFC) Plant
603
Advanced USC Plant + 25% Steam Utilization
568
IGCC Plant + 1700˚C Combustion Turbine
567
Integrated Gasification Triple-Cycle Plant
527
IGFC Plant + Catalytic Gasifier
501
IGFC Plant + Pressurized Solid Oxide Fuel Cell (SOFC)
498
Advanced USC Plant + 50% Steam Utilization
465
IGFC Plant + Catalytic Gasifier + Pressurized SOFC
430
Power producers interested in new coal plants could explore potential thermal hosts for cogeneration projects or the economics of
gasifying and firing high-quality coal. Greater public-private investment in research and development (R&D) is needed to accelerate
commercialization of gasification-based cycles and component
technologies.
Table of Contents
Introduction... ............................................................................... 3
Worldwide Carbon Standards ........................................................ 3
Carbon Management Challenges ................................................ 4
Rankine Cycle Plants with Higher Steam Temperatures............... 5
Combined Heat and Power Applications......................................... 7
Coal Gasification Integrated with Combined Cycles ..................... 10
Coal Gasification Integrated with Supercritical CO2 Cycles...........11
Coal Gasification Integrated with Solid Oxide Fuel Cells.............. 12
Coal Gasification Integrated with Triple Cycles ........................... 13
Conclusions & Next Steps ............................................................ 13
References .................................................................................. 15
Appendix: Technology Readiness Levels......................................... 15
October 2015
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Introduction
U.S. EPA’s NSPS for greenhouse gas
emissions from power plants1 specifies the
following limits under Section 111 of the
Clean Air Act:
• Coal power plants: 636 kg CO2/MWh
(1400 lb/MWh) of gross power output,
rolling 12-month average.
• Natural gas combustion turbine power
plants: 454 kg CO2/MWh (1000 lb/
MWh) of gross power output—or 468 kg
CO2/MWh (1030 lb/MWh) of net power
output, 12-month average.
According to EPA, electricity generation
represents the single largest U.S. source of
CO2 emissions. Fossil power plants accounted for about 37% of total emissions
in 2013, and more than three-quarters of
these emissions were produced by coal-fired
plants.a However, existing plants are not
subject to the new NSPS, instead being addressed through EPA’s Clean Power Plan.b
From a regulatory perspective, the EPA
standard’s basis on gross power output,
Table 1 - Recent CO 2 Emission Standards
for New C oal Plants
Country or State
Standard
CO2/MWh
United States
636 kg (1400 lb) gross
California
500 kg (1100 lb) net
Maine
500 kg (1100 lb) net
Washington
500 kg (1100 lb) net
New York
420 kg (925 lb) net
United Kingdom
450 kg (992 lb) net
Canada
420 kg (925 lb) net
China
763 kg (1679 lb) net
rather than net power output, is important
because individual coal generation options
offer differing heat rates and auxiliary power
requirements. Gross power output is defined
as follows:
Pgross = Pnet + Paux Where
Pgross = total amount of power produced at
the generator terminals;
Paux = internal (or auxiliary) power consumed within the plant to operate
pumps, motors, fans, and other
equipment; and
Pnet = amount of power that is shipped to
the grid.
State-of-the-art coal power plants operate
at USC steam conditions to increase Pgross
per fuel input, but they are not capable of
meeting EPA’s standard. For example, the
600-MW John W. Turk, Jr. Power Plant—
located in southwestern Arkansas and
majority-owned by Southwestern Electric
Power Company, a subsidiary of American
Electric Power (AEP)—is the first USC
plant built in the United States, with both
main and reheat steam temperatures exceeding 593°C (1100°F). Based on monthly data
filed with the U.S. Department of Energy
(DOE), the Turk plant’s average CO2 emission rate was 823 kg/MWh gross (1811 lb/
MWh) during 2013 and 802 kg/MWh
gross (1765 lb/MWh) during 2014.
New natural gas plants integrating a combustion turbine with a heat-recovery steam
generator (HRSG) should be able to meet
the relevant U.S. CO2 emission standard of
454 kg/MWh gross (1000 lb/MWh) without additional controls. By EPRI’s estimate,
state-of-the-art combined-cycle gas plants
a
See http://www.epa.gov/climatechange/ghgemissions/sources/electricity.html.
b
See http://www2.epa.gov/cleanpowerplan.
Low-Carbon Coal Technology Assessment
(1)
3
have a CO2 emission rate of about 370 kg/
MWh (814 lb/MWh) on a net output basis,2 well below the U.S. limit. (1026656)
Given the inability of state-of-the-art coal
power plants to meet the NSPS, EPA has
specified that partial implementation of
CCS at future coal plants is the “best system
of emission reduction” to be used in achieving a CO2 emission rate at or below 636 kg/
MWh gross (1400 lb/MWh).1 EPA suggests
that the standard could also be met by cofiring natural gas at coal plants.
This white paper focuses on coal-only
technology options. It introduces other CO2
emission standards for coal plants, identifies
key challenges associated with CCS deployment, and provides detailed discussion of
whether future coal-based power plants
could achieve CO2 standards without CCS.
Worldwide Carbon Standards
In the United States and around the world,
governments have established or proposed
CO2 emission performance standards with
similar technological implications to EPA’s
limit of 636 kg/MWh gross (1400 lb/
MWh). Some examples are listed in Table 1.
Typically based on net output delivered to
the grid, they are further described below.
California, Maine, and Washington have
set CO2 emission limits at no more than
500 kg/MWh (1100 lb/MWh). These state
standards are based on net rather than gross
power output, further increasing their stringency relative to EPA’s limit: Output-based
emissions are not only capped at a lower
level but also must be calculated after subtracting auxiliary consumption from gross
production. In the case of a conventional
coal plant, for example, a net standard of
636 kg/MWh (1400 lb/MWh) would allow
October 2015
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Turk Power Plant in Arkansas: First U.S. plant operating at ultrasupercritical steam conditions (Credit: AEP)
about 5% less CO2 emissions than a gross
standard set at that level.
The California and Washington standards
apply to baseload power purchased by
load-serving entities through new long-term
contracts. The standard adopted by New
York includes an output-based CO2 limit
of 420 kg/MWh net (925 lb/MWh) and
an input-based CO2 limit of 55 kg/million
Btu (120 lb/million Btu) of fuel for new or
expanded baseload fossil plants.
The United Kingdom’s Energy Act 2013 set
a CO2 standard of 450 kg/MWh net (992
lb/MWh) for new fossil generation, which
will apply until 2045. In 2012, Canada
passed a standard for coal-fired power plants
limiting the annual average CO2 emission
rate to 420 kg/MWh (925 lb/MWh) based
on net power output, plus the energy used
for CO2 compression in a CCS system. The
Canadian standard applies to new units—
those that begin producing power commercially after July 1, 2015—and also to old
units, generally defined as having reached
an age of 50 years since starting to produce
electricity commercially.
China’s “Action Plan of Upgrade and Renovation of Coal Power for Energy Conservation and Emission Reduction,” issued
in 2014, takes a different approach. The
standard is based on net power output,c but
the CO2 emission rate shown in Table 1 is
calculated based on China’s specified limits
on fuel consumption for new power plants.
Mass-based limits for bituminous coal are
282 kg fuel/MWh (620 lb/MWh) for 1000MW power plants and 285 kg fuel/MWh
(630 lb/MWh) for 600-MW power plants.d
Limits are for a standard bituminous coal
with a lower heating value (LHV) of 7000
kcal/kg (or 29,288 kJ/kg = 12,600 Btu/
lb), equivalent to a high-quality bituminous coal similar to Pittsburgh #8. If this
standard coal is assumed to have carbon
content similar to that of Pittsburgh #8,
then China’s fuel consumption limit for
1000-MW power plants is equivalent to a
CO2 emission rate of 763 kg/MWh (1679
lb/MWh). While this standard will require
the use of USC steam conditions, it appears
to be achievable without CCS.
Carbon Management Challenges
Except in China, existing and proposed
government standards for CO2 emissions
cannot be met solely by building an efficient
coal power plant using current state-of-theart USC technology. To achieve EPA’s limit,
the conventional wisdom is that more than
20% of a new U.S. coal plant’s CO2 emissions would have to be captured for longterm sequestration. Available CCS options
pose significant challenges and limitations
(see box, p. 9).
Carbon capture with underground storage has been deemed by EPA as the “best
system of emission reduction,” but applications are constrained by technology, policy,
and market factors. Power plant developers
Professor Jianxiong Mao, Tsinghua University, personal communication, April 2015.
China’s action plan includes additional limits for power plants burning low-rank coal: 310 kg/MWh for plants between 300 and 600 MW and 303 kg/MWh
for plants ≥600 MW.
c
d
Low-Carbon Coal Technology Assessment
4
October 2015
Some industry executives are beginning
to wonder if an easier path to regulatory compliance might be found through
advanced coal technology. The answer is
clear: Without CCS, a CO2 limit of 636 kg/
MWh (1400 lb/MWh) or lower can only be
achieved by increasing the thermal efficiency
of the energy conversion processes involved
in generating electricity from coal—a challenge more easily stated than accomplished.
This is because the gross CO2 emission
intensity of a power plant without capture is
directly proportional to its gross heat rate:
mCO2 HRg
44
—– = —– x Xc x —–
kWgross ∆H
12
(2)
Where
mCO2= mass flow rate of CO2 emitted in
kg/h or lb/h;
kWgross = gross power output in kW;
HRg = gross heat rate in kJ/kWh or Btu/
kWh;
∆Hc = higher heating value (HHV) of the
coal in kJ/kg or Btu/lb;
Xc =
mass fraction of carbon in coal; and
44/12 = ratio between molecular weights of
CO2 and elemental carbon.
For a best-in-class USC plant like Turk,
EPRI estimates gross heat rates when firing
Powder River Basin (PRB) sub-bituminous
coal or high-quality Pittsburgh #8 bituminous coal are 8860 kJ/kWh (8400 Btu/
kWh) or 8276 kJ/kWh (7845 Btu/kWh),
respectively, on an HHV basis. Per Equation
2, these heat rates yield gross CO2 emission intensities of 802 kg/MWh (1765 lb/
Low-Carbon Coal Technology Assessment
1900
862
1800
817
1700
771
1600
726
1500
680
1400
635
1300
590
1200
544
1100
500
1000
40%
45%
50%
55%
60%
65%
70%
CO2 Emission Intensity,
per Gross Power Output
kg/MWh
evaluating possible investments are reluctant to consider new coal generation due to
uncertainty, the cost of capture, and the difficulty in finding a suitable storage location.
CO2 Emission Intensity,
per Gross Power Output
lb/MWh
Insert Photo
454
75%
Gross Thermal Efficiency, HHV Basis
Figure 1 – Relationship between CO2 emission intensity and gross thermal efficiency for a subbituminous coal power plant
MWh) and 734 kg/MWh (1614 lb/MWh),
respectively. Burning high-quality coal yields
a lower heat rate and, in turn, lower emission intensity, but achieving 636 kg/MWh
(1400 lb/kWh) requires a gross heat rate of
approximately 7042 kJ/kWh (6675 Btu/
kWh). That corresponds to a gross thermal
efficiency of approximately 51% (HHV basis), far above the ~43% reached by today’s
best-in-class USC units.
High-quality bituminous fuel makes up
only about half of the world’s coal resource.
This white paper focuses on possible technology options for meeting EPA’s standard
while firing PRB coal, representative of
widely available lower-rank fuels. Figure 1
plots the approximate relationship between
CO2 emission intensity and thermal efficiency (both on a gross power output basis) for
a plant using PRB coal. While the shape of
the curve is similar for all coals, fuel-specfic
values differ depending on heating value
and carbon content. Regardless, step-change
increases in the gross thermal efficiency of
coal generation will be required to achieve
a CO2 emission intensity of 636 kg/MWh
(1400 lb/kWh) or lower without CCS.
5
Rankine Cycle Plants with
Higher Steam Temperatures
The overwhelming majority of coal-fired
power plants are based on the Rankine
cycle, in which high-pressure steam is
raised from the heat released while burning
pulverized coal. The steam is used to spin
a turbine, which in turn drives an electric
generator. The basic thermodynamics of the
Rankine cycle (and in fact of any heat engine) dictate that efficiency can be improved
by increasing the temperature ratio of the
hottest and coldest points in the cycle.
For the Rankine cycle, this means increasing
the temperature of the steam entering the
turbine and/or decreasing the temperature
in the condenser at the turbine exit. Ambient conditions, along with the efficacy of
the cooling technologies used to condense
steam back into liquid water, determine
how low the condenser temperature can go.
Thermoelectric cooling technology concepts
being pursued by EPRI with support from
the U.S. National Science Foundation offer
modest potential for gross thermal efficiency
gains.3 (3002004334)
October 2015
Insert Photo
1500
760
1400
1300
704
Eddystone 1
1200
649
Philo 6
1100
Temperature, ˚F
1000
538
900
482
800
427
700
371
600
316
500
260
400
Temperature, ˚C
593
Turk
204
1900
‘10
‘20
‘30
‘40
‘50
‘60
‘70
‘80
‘90
2000
‘10
‘20
Year
Figure 2 – Timeline showing maximum steam turbine inlet temperature achieved by power plants
since 1900, featuring the two units achieving the latest milestones plus the Turk plant
Average Temperature for Rupture in 100,000 Hours, ºF
1100
500
1200
1300
Inconel 740
300
70
Nickel-Based
Alloys
50
Haynes 282
Standard 617
30
Stress, ksi
Stress, MPa
CCA 617
1400
100
80
10
60
40
550
600
8
Advanced Austenitic
Alloys (Super 304H,
347HFG, NF709, etc.)
9-12Cr Creep-StrengthEnhanced Ferritic Steels
(Gr. 91, 92, 122)
650
700
6
Haynes 230
750
800
Average Temperature for Rupture in 100,000 Hours, ºC
Figure 3 – Data showing the 100,000-hour rupture strength of various classes of metals versus
temperature 4
Boosting steam turbine inlet temperature
creates opportunity for more significant increases in efficiency. Figure 2 shows the history of how steam turbine inlet temperature
Low-Carbon Coal Technology Assessment
has progressed from the time of Thomas
Edison at the beginning of the 20th century
until today. For 60 years, there was a steady
advance from 260°C (500°F) to 650°C
6
(1200°F), culminating with construction of
Philo Unit #6 in Ohio and then Eddystone
Unit #1 near Philadelphia. However, no
coal-fired power plant built in the past 55
years has exceeded Eddystone’s turbine inlet
temperature because the power industry had
reached a limit in the capabilities of ferriticbased steels.
Since 2001, a DOE-funded R&D consortium has been pursuing advanced materials
for coal-fired boilers and steam turbines,
with EPRI serving as the technical lead.4
(3002001343) Figure 3 shows that all metals lose strength as temperature increases. A
typical stress encountered by boiler steam
tubing is 100 MPa. The ability of ferritic steels to withstand that stress level for
100,000 hours without rupturing ends at
temperatures exceeding 600-620°C (11001150°F). Indeed, materials exposed to
650°C (1200°F) steam at Eddystone experienced failures after a few years of operation.
Additional failures were avoided after plant
operators limited steam temperatures to
610°C (1130°F) in the early 1960s.5
Figure 3 indicates that materials other than
ferritic steels must be used to increase the
thermal efficiency of the Rankine cycle.
In particular, nickel alloys such as Inconel
740 and Haynes 282, both of which have
undergone extensive analysis and testing by
the DOE consortium, show promise of allowing steam temperatures to rise to 760°C
(1400°F).4 That would allow an increase
in gross thermal efficiency of at least 10%,
from the current ~41% for USC plants to
~45% for next-generation advanced USC
plants.
Validation testing of key components
under realistic advanced USC conditions
has brought this higher-efficiency generation option to TRL5 on EPRI’s technol-
October 2015
Insert Photo
Of course, the possibility exists for materials
to be developed that would allow Rankine
cycle coal power plants to reach steam temperatures greater than 760°C (1400°F). Using commercial software, EPRI has carried
out calculations based on thermodynamic
System
Validated
Subsystem
Validated
TRL 6
TRL 4
Proof of Concept
Validated
Concepts
Formulated
TRL
7
TRL
3
TRL
2
TRL
1
Exploratory
Research
Early
Demonstration
TRL 5
TRL
8
Technology
Readiness
Levels
TRL
9
Demonstration
Early
Commercial
Deployment
Commercialization
Figure 4 - EPRI’s Technology Readiness Levels
Low-Carbon Coal Technology Assessment
750
700
650
1760
1650
1540
1430
290BAR/593C/621C + High-Quality Coal
600
1320
550
1210
500
1100
450
990
400
35%
40%
45%
50%
55%
CO2 Emissions, lb/MWh, gross
Would the significant increase in efficiency
be sufficient to meet EPA’s standard? Figure
5 shows that it would not, based on results
from a series of engineering evaluations
EPRI has carried out on current and possible future USC power plant designs.6,7,8
(1017515, 1015699, 3002001788) The plot
shows that the CO2 emission rate ranges
from 789 kg/MWh gross (1736 lb/MWh)
to 715 kg/MWh gross (1573 lb/MWh) depending on steam temperature and pressure,
other design variables, and fuel quality. The
low end of the range represents approximately a 10% decrease in CO2 emission
intensity from today’s USC plants, far from
the ~22% reduction that the EPA standard would require. Deploying advanced
Rankine cycles would, however, significantly
decrease the amount of CO2 that would
have to be captured and stored in order to
achieve compliance.
290BAR/593C/621C
276BAR/593C/616C
276BAR/649C/671C
276BAR/704C/727C
352BAR/680C/700C
276BAR/760C/760C
352BAR/680C/700C/700C
800
CO2 Emissions, kg/MWh, gross
ogy readiness level (TRL) scale, which is
illustrated in Figure 4 and described in the
Appendix on p. 15.
60%
65%
70%
75%
880
80%
Net Thermal Efficiency, HHV Basis
USC
Figure 5 – CO2 emission intensities of USC plants per gross power output as a function of steam
conditions at varying pressures and temperatures
properties for steam valid up to 1371°C
(2500°F). A plant operating at this steam
temperature is predicted to have a CO2
emission intensity of 575 kg/MWh gross
(1266 lb/MWh), assuming materials could
be found that tolerate such conditions. By
extrapolation, a plant capable of meeting the
EPA standard of 636 kg/MWh gross (1400
lb/MWh) would require steam temperatures around 1125°C (2050°F). This is well
beyond current materials technology.
Combined Heat and Power
Applications
Another way to increase the thermal efficiency of pulverized coal power plants is
to utilize the input fuel’s energy to produce
both electric power and useful heat. Combined heat and power (CHP) or cogeneration (cogen) plants—as they are frequently
called in Europe and the United States,
respectively—can approach very high utilization rates. The technology is commercially
mature. Examples of typical “thermal hosts”
for the exported heat from CHP plants are
oil refineries, food processing facilities, and
7
central heating districts for commercial
buildings, large hotels, hospitals, and university campuses. Because exported heat can
displace the burning of fossil fuel that would
otherwise have been used to generate heat at
the thermal host’s location, EPA’s standard
offers CHP plants full credit for any heat
that is exported and put to good use, according to the following formula:
/
Pgross = [(PeST + PeCT + PeIE - PeFW ) T ]
+ (PtHR + PtIE + PtPS )
(3)
Where
Pgross = Gross energy output of affected facility in MWh;
PeST = Electric energy output plus mechanical energy output (if any) of steam
turbine(s) (ST) in MWh;
PeCT = Electric energy output plus mechanical energy output (if any) of combustion turbine(s) (CT) in MWh;
PeIE = Electric energy output plus mechanical energy output (if any) of affected
facility’s integrated equipment (IE)
October 2015
800
1760
750
1650
290BAR/593C/621C + 14% Steam Extraction
700
1540
276BAR/760C/760C + 12.5% Steam Extraction
650
1430
276BAR/760C/760C + 25% Steam Extraction
600
1320
550
1210
276BAR/760C/760C + 50% Steam Extraction
500
1100
450
Pgross = PeST – PeFW / T +
(Qm x H / 3.6 x109)
CO2 Emissions, lb/MWh, gross
CO2 Emissions, kg/MWh, gross
Insert Photo
990
400
35%
40%
45%
50%
55%
60%
65%
70%
75%
880
80%
Net Thermal Efficiency, HHV Basis
USC
USC + CHP
Figure 6 – CO2 emission intensities of CHP plants based on USC technology with various levels of
steam extraction to a thermal host
that provides electricity or mechanical energy to the affected facility or
auxiliary equipment in MWh;
PeFW = Electric energy used to power boiler
feedwater (FW) pumps at steam
generating units in MWh;
T = Electric transmission and distribution
factor, set to 1.0 for most affected facilities and to 0.95 only for a facility
where at least 20% of Pgross consists of
electric or direct mechanical output
on an annual basis and 20% of Pgross
consists of useful thermal energy
output on a rolling 3-year basis;
PtHR = Hourly useful thermal energy output,
measured relative to standard ISO
conditions, from heat recovery (HR)
for applications other than steam
generation or performance enhancement of the affected facility in MWh;
PtIE = Useful thermal energy output relative
to ISO conditions from any integrated equipment that provides thermal
energy to the affected facility or auxiliary equipment in MWh; and
Low-Carbon Coal Technology Assessment
PtPS = Useful thermal energy output of
steam, measured relative to ISO conditions, that is used for applications
that do not generate additional electricity, produce mechanical energy
output, or enhance the performance
of the affected facility.
The term PtPS is calculated in MWh as
Qm x H
Pt PS = ———–
3.6 x 109
(4)
Where
Qm = Measured steam flow in kg (lb) for the
operating hour;
H = Enthalpy of the steam at measured
temperature and pressure relative to
ISO conditions in J/kg (Btu/lb); and
3.6 x 109 = Conversion factor in J/MWh
(3.413 x 106 Btu/MWh).
Assuming that only steam is exported to
a thermal host and that the FW pump is
driven by an electric motor, the formula for
gross power becomes:
8
(5)
To assess the CO2 emission intensity of
cogen applications based on EPA’s formula,
EPRI explored four CHP cases, one based
on current USC steam conditions and the
others starting from an advanced USC plant
design with a main steam pressure of 276
bar (4000 psi) and main and reheat steam
temperature of 760°C (1400°F). The latter
three cases are based on extracting 12.5%,
25%, and 50% of the steam at the crossover between the intermediate- and lowpressure turbine sections.
The results are shown in Figure 6. EPA’s
standard of 636 kg/MWh (1400 lb/MWh)
could be achieved by a new cogen plant
based on current state-of-the-art USC technology like that employed at Turk but also
incorporating at least 14% steam extraction
and utilization. The limit also could be met
by using at least 12.5% of the steam from
an advanced USC plant. Lower standards
set by U.S. states and other nations could be
achieved based on higher CHP fractions.
However, scale is an issue. An advanced
USC plant producing nominally 750 MW
of net electric power with 12.5% steam
extraction would require a thermal load of
approximately 150 MW—about 50 kg/s
(0.4 million lb/h) of steam at 4.7 bara (68
psia) and 367°C (693°F). As a point of
reference, the cogen plant supplying steam
to Total’s Gonfreville refinery in Normandy,
France, has a thermal load of 330 MW.12
Because only a modest number of thermal
loads sized at 150 MW or larger are likely to
be available, smaller advanced USC plants
operating in CHP mode may represent a
more widely applicable approach for achieving a CO2 emission intensity of 636 kg/
MWh (1400 lb/MWh) or lower.
October 2015
Insert Photo
What Comes Up Must Go Down: Carbon Capture & Storage Challenges
Thought leaders and large-scale energy-economy modeling studies generally agree: A growing world’s needs and wants cannot be
met without continued reliance on fossil fuels, for decades into the future. Mitigating CO2 emissions to the atmosphere while generating
bulk quantities of electricity poses both technical and societal challenges. In particular, technologies for capturing carbon and ensuring
long-term sequestration must be commercially feasible, economically viable, and publicly acceptable—and capable of operating at
massive scale.
Present and near-term capture technologies scrub CO2 from flue gas using amine-based processes that impose a parasitic loss of ~20%
on typical coal-fired plants. Compression of captured, concentrated CO2 for pipeline transport adds another ~10% in auxiliary load,
further increasing heat rate. Adding CCS thus is projected to nearly double the levelized cost of electricity from new coal plants. Capture processes with game-changing potential are being pursued by EPRI, but these early-stage innovations are at least a decade away
from commercialization.9 (3002004897)
According to EPRI’s analysis, high cost is not the only obstacle to applying what EPA calls “the best system of emission reduction.”
Something must also be done to prevent the eventual release of captured CO2. Beneficial utilization suffers from the inability to scale:
Other than at fossil fuel extraction sites suitable for enhanced oil and gas recovery, the potential for industrial-scale use of CO2 is
limited because markets are small compared to the scale of CO2 emissions, and most direct utilization options do not provide long-term
sequestration. Converting CO2 into a more useful chemical form requires many times the amount of energy produced by combustion.
Methods such as reacting captured CO2 with minerals to produce limestone have been shown to be feasible but impractical at present.10 Storing captured carbon in the ocean—at depths and temperatures below which the CO2 would persist in liquid or solid depos­its
on the seafloor—is unproven from all standpoints.11
Returning extracted fuel carbon to underground storage has the best near-term potential. Deep saline, depleted fuel reservoir, and other formations potentially amenable to CO2 storage are broadly distributed in the United States and around the world. Integrated CCS
technology has been tested at a number of sites and is being applied at industrial scale but on a limited basis, notably in a pioneering
project at the Boundary Dam Power Station in Saskatchewan, Canada. Captured and compressed CO2 from a 110-MW coal-fired
unit is transported by pipeline and injected underground for enhanced oil recovery then long-term sequestration.
However, several nations with significant coal
fleets—including Japan, South Africa, and Korea—appear to lack on-shore locations with suitable geology for long-term CO2 storage. Even
within the United States, few potentially suitable
formations have been tested with large-scale
injections to prove viability—something power
plant developers and their financial backers
will require before proceeding with multi-billiondollar projects. Also, important institutional
obstacles exist. For example, environmental,
health, and safety concerns have created political barriers to the permitting of underground
carbon storage facilities in Germany, while U.S.
regulations require power producers or other
responsible parties to monitor sequestration sites
for 50 years after CO2 injection has ended.
The path forward for CCS remains uncertain.
Low-Carbon Coal Technology Assessment
CCS Test Facility at Plant Barry in Alabama: Early U.S. demonstration project
(Credit: Southern Company)
9
October 2015
Insert Photo
Coal Gasification Integrated
with Combined Cycles
IGCC deployment continues, placing the
technology at TRL8.
CO2 Emissions, kg/MWh, gross
A simplified process diagram of an integrated gasification combined cycle (IGCC)
power plant is shown in Figure 7. The coal
is converted to syngas, which is cooled
to achieve temperatures that combustion
turbine materials can accommodate. Contaminants, specifically sulfur species and ash
mineral content, are removed. Clean syngas
is then fired in the open Brayton cycle
combustion turbine. The turbine exhaust is
fed to the Rankine cycle HRSG, which also
receives steam from the syngas cooler. Early
State-of-the-art IGCC units have thermal
efficiencies based on net power output that
are similar to those of state-of-the-art, standalone Rankine cycle coal power plants.
However, the auxiliary power consumption
of IGCCs is greater—an important consideration when gross CO2 emission intensity
is the parameter of merit.
EPRI has conducted engineering and
performance analysis studies of several
IGCC plant configurations.13,14 (1015690,
1022034) As indicated in Figure 8, IGCC
plants having net thermal efficiencies
comparable to USC plants—and operating on the same sub-bituminous coal—offer significantly lower gross CO2 emission
intensities. However, carbon emissions are
still well above 636 kg/MWh (1400 lb/
MWh), except in one case with high-quality
bituminous coal and the dry-feed Shell
gasifier. This scenario could increase plant
efficiency to the point that CO2 emissions
would fall just below EPA’s limit at 627 kg/
MWh (1380 lb/MWh).
800
1760
750
1650
700
1540
Siemens/2XGE7FB
E-Gas/GE7FB
650
600
1430
1320
Shell/3XGE7FB
550
1210
Shell/3XGE7FB + High-Quality Coal
500
1100
Shell + 1700C Combustion Turbine
450
CO2 Emissions, lb/MWh, gross
Gasifying coal to produce a synthesis gas
(syngas) opens up additional potential
pathways for meeting CO2 emission limits
without CCS. Syngas, consisting predominantly of carbon monoxide (CO) and
gaseous hydrogen (H2) fuel, can be turned
into electricity by many methods. One is
through a combined-cycle plant, like today’s
workhorse natural gas generators, which
offer gross thermal efficiency of 50-54% on
an HHV basis (typically, their efficiency is
reported at 55-60% on an LHV basis).
990
400
35%
40%
45%
50%
55%
60%
65%
70%
75%
880
80%
Net Thermal Efficiency, HHV Basis
USC
USC + CHP
IGCC
IGCC + HTCT
Figure 8 – CO2 emission intensities of state-of-the-art IGCCs and a future IGCC plant with a highertemperature combustion turbine
Low-Carbon Coal Technology Assessment
10
GAS
CLEANUP
SYNGAS
COOLER
GASIFIER
COAL
O2
GEN
BURNER
AIR
COND
GEN
HRSG
STACK
Figure 7 – Simplified process diagram of an
IGCC plant
While existing IGCC technology could
meet EPA’s standard under certain conditions, more stringent limits in the UK,
Canada, and some U.S. states could not be
achieved. IGCC efficiency gains can be realized by increasing the firing temperature of
the combustion turbine. EPRI’s 2011 IGCC
R&D roadmap concluded that going from
today’s range of 1370°C–1430°C (2500°F–
2600°F) to 1700°C (3100°F) would decrease
heat rate by 16%.15 (1022035) If that holds
true for the PRB coal “Shell” case shown in
Figure 8, then the CO2 emissions intensity
of an IGCC plant with a higher-temperature combustion turbine (HTCT) would
be approximately 567 kg/MWh (1248 lb/
MWh)—well below EPA’s standard. Japan has a national R&D program pursuing a combustion turbine with 1700°C
(3100°F) firing temperature. The focus is
on advancing the necessary materials technology by developing key components, as
steps toward creating a complete turbine.16
U.S. government programs have supported
the development of jet engines for military
aircraft with much higher turbine inlet
temperatures. The Pratt & Whitney jet en-
October 2015
Insert Photo
Closed Brayton cycles using supercritical
CO2 (SCO2) as the working fluid are being
investigated by several organizations as a
way to increase the thermal efficiency of
advanced nuclear, solar, and fossil power
plants, relative to designs based on the Rankine steam cycle. An early demonstration of
this advanced cycle is under development
for natural gas and concentrating solar plant
applications. When completed, this will
advance the technology to TRL6.
The SCO2 cycle can also be integrated with
a coal gasifier. Figure 9 shows a simplified
process diagram of two possible oxy-fired
configurations, one with CCS (a) and the
second with CO2 venting (b). In both cases,
oxygen reacts with syngas in the burner.
SCO2 is introduced to the burner to dilute
the mixture because firing syngas in oxygen
would result in temperatures above 2750°C
(5000°F), far exceeding the level current
turbine technology can tolerate. Recycling a
large flow of CO2, as indicated by the greenshaded portion of Figure 9, moderates the
firing temperature to 1150°C (2100°F).
The stream exiting the burner includes a
small amount of water vapor but consists
mostly of CO2. The ratio of recycled CO2
to that produced by combustion of the
syngas is about 10:1. The flow is expanded
Low-Carbon Coal Technology Assessment
To maintain a mass balance, CO2 equal
to the amount formed by combusting the
syngas must be bled off from the flow. As
shown in Figure 9(a), this CO2 may be
extracted downstream of the pump at a
pressure suitable for pipeline transport and
carbon storage. Figure 9(b) illustrates an
alternative without CCS: Rather than being compressed, the bled CO2 is expanded
through a small letdown turbine then
vented to the atmosphere. This allows about
5% more power to be produced.
A 2014 EPRI report summarizes findings from an analysis of various syngas-fed
oxy-fired SCO2 Brayton plant designs with
100% CCS.18 (3002003734) The configuration illustrated in Figure 9(a) offers
GAS
CLEANUP
GASIFIER
COAL
AIR
SEPARATION
UNIT
OXYGEN
GEN
BURNER
(a)
CO2 TO
STORAGE
HIGHPRESSURE
CO2
RECUPERATOR
CO2
PUMP
COOLER
(b)
GEN
WATER
VENTED CO2
Figure 9 – Simplified process diagram of a coal
gasifier integrated with a semi-closed oxy-fired
SCO2 Brayton cycle and (a) CCS or (b) a CO2
letdown turbine venting to the atmosphere
more than a 25% increase in net thermal
efficiency relative to state-of-the-art IGCC
plants with 90% CCS. For the vented SCO2
cycle illustrated in Figure 9(b), net thermal
efficiency is estimated to be even higher, at
42% (HHV basis), compared with 40.5%
for the SCO2 cycle with CCS. The CO2
emission intensity of the vented process is
603 kg/MWh (1326 lb/MWh), below the
EPA target as illustrated in Figure 10.
800
1760
750
1650
700
1540
Oxy + CO2 Venting
650
1430
600
1320
550
1210
500
1100
450
990
400
35%
40%
45%
50%
55%
60%
65%
70%
CO2 Emissions, lb/MWh, gross
Coal Gasification Integrated
with Supercritical CO2 Brayton
Cycles
in a turbine to drive a generator. The
turbine exhaust, still at high temperature
(>700°C or 1300°F), is directed to a large
heat exchanger (recuperator), then cooled
further to condense out the water vapor.
The remaining flow, essentially all CO2, is
raised up to high pressure (165 bar or 2400
psi), then preheated in the recuperator prior
to reintroduction to the burner.
CO2 Emissions, kg/MWh, gross
gine used in the F-35 “Joint Strike Fighter”
operates at 1982°C (3600°F).17 The technical feasibility of a firing temperature approaching 1700°C (3100°F) thus has been
established. The timeline for commercial
deployment of HTCTs optimized for IGCC
operation is uncertain but appears about a
decade away, given the current TRL4-5.
880
80%
75%
Net Thermal Efficiency, HHV Basis
USC
USC + CHP
IGCC
IGCC + HTCT
IG + SCO2
Figure 10 – CO2 emission intensity of the SCO2 Brayton gasification process with venting
11
October 2015
Insert Photo
Coal Gasification Integrated
with Solid Oxide Fuel Cells
Fuel cells have long held the promise of
higher-efficiency power generation based on
natural gas, hydrogen fuel produced via the
electrolysis of water, and other gaseous fuels.
Combining a coal gasifier with a fuel cell
offers similar opportunity. In 2011, DOE’s
National Energy Technology Laboratory
(NETL) issued an analysis of the projected
performance of integrated gasification fuel
cell (IGFC) power plants, in which solid oxide fuel cell (SOFC) technology essentially
replaces the combustion turbine in IGCC
designs.19
Figure 11 is a simplified IGFC process
diagram. As with a conventional IGCC
plant, the coal is converted to syngas, which
is cooled to a level the SOFC can tolerate.
The fuel cell can be thought of as a dry cell
battery—but one in which the chemical
ingredients are continuously refreshed rather
than depleted as energy is produced. In the
case of an SOFC, the ingredients are syngas,
which is fed to the anode side of the cell,
and oxygen, which is supplied by blowing
air into the cathode side of the cell. This
enables an electrochemical reaction that produces heat and induces direct current, which
is converted to grid-compliant alternating
current via an inverter.
The chemical reaction in the SOFC does
not fully consume the syngas. Any remaining CO and H2 are mixed with hot air
leaving the cathode and then combusted in
a burner. The HRSG applies the combustion exhaust from the burner to raise steam,
which is mixed with steam produced in the
syngas cooler to drive a steam turbine. The
SOFC can operate at atmospheric pressure,
in which case the auxiliary power required
to blow the air through the cathode is rather
modest, or at elevated pressure, which
increases gross energy output. Pressurized
SOFCs can employ an electric compressor as shown in Figure 11 or draw on an
expander driven by combustion exhaust to
push the air into the cathode.
NETL’s IGFC study considered two different types of gasifiers: a conventional gasifier
producing syngas with 6% methane (CH4)
by volume and a catalytic gasifier producing
800
1760
1650
Atmospheric Pressure SOFC
700
1540
Catalytic Gasifier + Atmospheric Pressure SOFC
650
1430
Pressurized SOFC
600
1320
550
1210
500
1100
Catalytic Gasifier + Pressurized SOFC
450
990
400
35%
40%
45%
50%
55%
60%
65%
70%
880
80%
75%
Net Thermal Efficiency, HHV Basis
USC
USC + CHP
IGCC
IGCC + HTCT
IG + SCO2
IGFC
CO2 Emissions, lb/MWh, gross
CO2 Emissions, kg/MWh, gross
750
GAS
CLEANUP
SYNGAS
COOLER
GASIFIER
COAL
O2
INVERTER
GEN
GEN
SOFC
COND
BURNER
AIR
HRSG
STACK
Figure 11 – Simplified process diagram of an
IGFC power plant with pressurized SOFC
enriched syngas with 30% CH4 by volume.
IGFC designs with the SOFC operating at
atmospheric pressure and at 19.7 bara (285
psia) also were considered. NETL results
from these four options are presented in
Figure 12, demonstrating the performance
benefits of SOFCs. EPA’s standard could be
achieved using a conventional gasifier with
an SOFC operating at atmospheric pressure. More stringent standards could be met
by using a pressurized SOFC or catalytic
gasifier. An IGFC plant design operating on
CH4-enriched syngas and at elevated pressure would have a CO2 emission intensity of
430 kg/MWh (946 lb/MWh).
IGFC technology is at TRL4, largely because SOFCs are still at an early stage in the
development cycle. A recent peer review of
DOE’s SOFC R&D program indicated that
the largest high-temperature SOFC module
constructed to date has a rated capacity of
60 kW of power and has operated for only
1600 hours.20 According to EPRI’s analysis,
megawatt-scale modules are not expected
until after 2020.
Figure 12 – CO2 emission intensities of several IGFC cycles
Low-Carbon Coal Technology Assessment
12
October 2015
Insert Photo
Coal Gasification Integrated
with Triple Cycles
GAS
CLEANUP
University of Tokyo professor Dr. Shozo
Kaneko, among others, has promoted the
concept of integrating SOFCs with conventional combined-cycle plant configurations
to create “triple-cycle” plants that could be
fueled by natural gas, coal-derived syngas,
or other sources.21 A simplified diagram of
Dr. Kaneko’s integrated gasification triplecycle (IGTC) plant is shown in Figure 13.
The potential thermal efficiency advantage
of IGTC over IGFC designs is that hotter
turbine inlet temperatures can be achieved
by having the SOFC feed a combustion
turbine.
GASIFIER
COAL
O2
GEN
INVERTER
COND
HRSG
Figure 13 – Simplified process diagram of an IGTC plant
ficient to achieve the EPA standard. Room
for improvement in IGTC performance—to
achieve even lower limits—appears to exist
through design optimization and perhaps
eventually through the achievement of a
1700°C (3100°F) turbine firing temperature. SOFC technology remains the limiting
factor.
750
1650
700
1540
650
1430
Pressurized SOFC + 1500C Combustion Turbine
600
1320
550
1210
500
1100
450
990
400
45%
50%
55%
60%
65%
70%
75%
880
80%
IGFC
IGTC
Net Thermal Efficiency, HHV Basis
USC
USC + CHP
IGCC
IGCC + HTCT
IG + SCO2
Figure 14 – CO2 emission intensity of IGTC design
Low-Carbon Coal Technology Assessment
13
CO2 Emissions, lb/MWh, gross
Figure 14 suggests that the triple-cycle
design has a higher CO2 emission intensity
than the IGFC plant with a pressurized
SOFC. However, this is an artifact of both
1760
40%
STACK
GEN
800
35%
GEN
SOFC
To conduct an initial assessment of this
design, EPRI developed a simplified IGTC
model and simulated performance based on
a conventional coal gasifier, a pressurized
SOFC, and a G-class turbine with a 1500°C
(2732°F) firing temperature. Results shown
in Figure 14 indicate a possible net thermal
efficiency of greater than 51% (HHV basis)
and CO2 emission intensity of approximately 527 kg/MWh gross (1159 lb/MWh), suf-
CO2 Emissions, kg/MWh, gross
SYNGAS
COOLER
underlying design assumptions and the EPA
standard’s basis on gross power output. The
pressurized IGFC configuration represented
in Figure 11 employs an electric compressor
to deliver air to the cathode, increasing gross
output and thus artificially reducing gross
emission intensity. The IGTC configuration
simulated by EPRI instead pressurizes the
SOFC via an air compressor with a direct
mechanical connection to the expander in
the combustion turbine, improving thermal
efficiency. Consequently, IGTC plants are
expected to be better performers relative to
CO2 emission standards based on net power
output.
Conclusions & Next Steps
Yes, technology has been identified that
would enable new coal power plants to
operate so efficiently that a CO2 emission standard of 636 kg/MWh (1400 lb/
MWh) could be met without partial CCS.
However, among all of the options firing
sub-bituminous coal considered in EPRI’s
analysis and shown in Figure 14, none with
potential to meet the standard are commercially available, economically viable, and
suitable for broad deployment.
October 2015
Insert Photo
Technologies capable of achieving EPA’s
standard are highlighted in red in Table 2.
State-of-the-art USC technology operating
in a CHP configuration can meet the target,
but only at power plant sites near a refinery
or other thermal host large enough to utilize
at least 14% of the steam exiting the intermediate-pressure turbine. CHP plants based
on advanced USC steam conditions (760°C;
1400°F) represent a possible future option
with potential for meeting EPA’s standard
as well as the limits of 500 kg/MWh (1100
lb/MWh) and lower proposed or existing
in U.S. states and nations such as the UK
and Canada. Relatively small advanced USC
plants, thus requiring smaller thermal hosts,
have wider possible applicability.
IGCC plants may be capable of achieving
EPA’s standard, depending on choice of
gasifier technology and only if fueled by
high-quality bituminous coal. Coal gasification integrated with higher-temperature
combustion turbines, fuel cell technologies,
or novel generation cycles opens up multiple
possible future pathways for achieving emission intensities well below EPA’s limit, but
without partial CCS. While not investigated
in EPRI’s recent study, applying gasificationbased technologies in cogeneration mode
could result in even lower emissions, assuming suitable thermal hosts could be found.
To help expand the available options for
generating electricity with coal while achieving CO2 emission standards, additional
public-private R&D investment is needed to
accelerate the commercialization of SOFC
technologies, higher-temperature turbines
capable of operating on coal-derived syngas,
and SCO2 Brayton cycles. National R&D
programs in the United States, Japan, and
elsewhere are making progress. Greater
resources and increased collaboration are
recommended due to the challenges that
Low-Carbon Coal Technology Assessment
Table 2 - Technologies Considered in EPRI’s Analysis, Relative to EPA’s Standard
CO2 Emission Intensity,
kg/MWh, gross
Efficiency, %
290BAR/593C/621C6
789
38.4
USC
276BAR/593C/616C
777
39.5
USC
276BAR/649C/671C
754
40.8
USC
276BAR/704C/727C
735
42.0
USC
290BAR/593C/621C + High-Quality Coal
734
41.2
USC
352BAR/680C/700C
723
42.7
USC
276BAR/760C/760C
721
42.8
USC
352BAR/680C/700C/700C
715
43.4
Technology
Details
USC
8
8
8
8
7
8
7
USC+CHP
290BAR/593C/621C + 14% Steam Extraction
636
46.5
USC+CHP
276BAR/760C/760C + 12.5% Steam Extraction
636
49.0
USC+CHP
276BAR/760C/760C + 25% Steam Extraction
568
55.2
USC+CHP
276BAR/760C/760C + 50% Steam Extraction
465
68.0
IGCC
Siemens/2XGE7FB13
743
38.2
IGCC
E-Gas/GE7FB14
702
38.7
IGCC
Shell/3XGE7FB13
676
40.0
IGCC
Shell/3XGE7FB + High-Quality Coal
627
41.9
IGCC + HTCT
Shell + 1700C Combustion Turbine
567
47.6
IG+SCO2
Oxy + CO2 Venting
603
42.0
603
43.7
13
IGFC
Atmospheric Pressure SOFC19
IGFC
Catalytic Gasifier + Atmospheric Pressure SOFC
501
54.0
IGFC
Pressurized SOFC
498
51.5
IGFC
Catalytic Gasifier + Pressurized SOFC
430
61.4
IGTC
Pressurized SOFC + 1500C Combustion Turbine
527
51.3
19
19
19
are facing CCS deployment. In addition,
a study of existing and potential future
thermal hosts capable of accommodating large volumes of steam in the United
States and other countries is recommended.
14
This would help determine the extent to
which the CHP option may be available for
building new coal-fired power plants and
achieving CO2 emission standards without
the need for partial CCS.
October 2015
Insert Photo
References
1. U.S. EPA. “Standards of Performance for Greenhouse Gas
Emissions from New, Modified, and Reconstructed Stationary
Sources: Electric Utility Generating Units,” 40 CFR Parts 60,
70, 71, and 98, August 3, 2015. See http://www.epa.gov/airquality/cpp/cps-final-rule.pdf.
2. Program on Technology Innovation: Integrated Generation Technology Options 2012. EPRI, Palo Alto, CA: 2013. 1026656.
3. Program on Technology Innovation: Proceedings of the 2014 NSF/
EPRI Power Plant Dry Cooling Science and Technology Innovation
Program Kickoff Meeting: Washington, D.C., April 15-16, 2014.
EPRI, Palo Alto, CA: 2015 3002004334.
4. Progress Report on Advanced Ultra-Supercritical Technology Development. EPRI, Palo Alto, CA: 2013. 3002001343.
5. Silvestri, G.J. Jr. “Eddystone Station 325 MW Generating Unit
1 – A Brief History.” ASME Mechanical Engineering Heritage Site
Report H226, 2003.
6. An Engineering and Economic Assessment of Post-Combustion CO2
Capture for 1100°F Ultra-Supercritical Pulverized Coal Power
Plant Applications. EPRI, Palo Alto, CA: 2010. 1017515.
7. Engineering and Economic Evaluation of 1300°F Series UltraSupercritical Pulverized Coal Power Plants: Phase 1. EPRI, Palo
Alto, CA: 2008. 1015699.
9. Program on Technology Innovation: Carbon Capture. EPRI, Palo
Alto, CA: 2015. 3002004897.
10. International Energy Agency Greenhouse Gas (IEAGHG) R&D
Programme. Mineralisation – Carbonation and Enhanced Weathering. IEAGHG Report 2013/TR6, July 2013.
Appendix
TRL
12. Fontaine, P., and Naessen, P. “Fresh air firing: HRSG guarantees
steam supplies to French refinery,” Cogeneration & On-site Power,
Vol 7, No. 5, 2006.
13. IGCC Design Considerations for CO2 Capture. EPRI, Palo Alto,
CA: 2009. 1015690.
14. Engineering and Economic Evaluations of Integrated-Gasification
Combined-Cycle Plant Designs with Carbon Dioxide Capture.
EPRI, Palo Alto, CA: 2011. 1022034.
15. CoalFleet Integrated Gasification Combined Cycle Research and
Development Roadmap: 2011 Update. EPRI, Palo Alto, CA:
2011. 1022035.
16. Tsukagoshi, K., et al. “Operating Status of Uprating Gas Turbines and Future Trend of Gas Turbine Development.” Mitsubishi Heavy Industries Technical Review, Vol. 44, No. 4, 2007.
17. Langston, L. “Fahrenheit 3,600,” Mech. Engineering, April 2007.
18. Performance and Economic Evaluation of Supercritical CO2
Power Cycle Coal Gasification Plant. EPRI, Palo Alto, CA: 2014.
3002003734.
19. U.S. DOE. “Analysis of Integrated Gasification Fuel Cell Plant
Configurations.” DOE/NETL-2011-1482, 2011.
8. Advanced Ultra-Supercritical Steam Cycle Optimization. EPRI,
Palo Alto, CA: 2014. 3002001788.
Technology Readiness
Levels (TRLs)
TRLs are a useful
mechanism for estimating
where technology development projects are in their
maturation and for defining
and prioritizing next steps
toward commercialization.
EPRI uses the TRL definitions shown at right.
11. Intergovernmental Panel on Climate Change (IPCC). Special
Report on Carbon Dioxide Capture and Storage. Prepared by
IPCC Working Group III, 2005.
20. ASM International. “Overview Report, Clean Coal Research
Program Solid Oxide Fuel Cells Program FY2014 Peer Review
Meeting,” April 2014. See http://www.netl.doe.gov/File%20
Library/Research/Coal/Peer%20Reviews/2014/SOFC-FY2014Peer-Review-Overview-Report_Final.pdf
21. Kaneko, S. “Solid Oxide Fuel Cell – Gas Turbine – Steam Turbine: Triple Combined Cycle.” Presentation at EPRI CoalFleet
for Tomorrow Workshop, Indianapolis, June 2013.
Description
TRL1: Exploratory Research
Exploratory research transitioning basic science into laboratory application.
TRL2: Concepts Formulated
Technology concepts and/or application formulated.
TRL3: Proof of Concept Validated
TRL4: Subsystem Validation
TRL5: System Validated
TRL6: Early Demonstration
TRL7: Demonstration
TRL8: Early Commercial Deployment
TRL9: Commercialization
Low-Carbon Coal Technology Assessment
Proof of concept validation.
Subsystem or component validation in laboratory environment to simulate service conditions.
Early system validation demonstrated in laboratory or limited field application.
Early field demonstration and system refinements completed.
Complete system demonstration in an operational environment.
Early commercial deployment (Serial Nos. 1, 2, etc.).
Wide-scale commercial deployment.
15
October 2015
The Electric Power Research Institute, Inc. (EPRI, www.epri.com) conducts
research and development relating to the generation, delivery and use
of electricity for the benefit of the public. An independent, nonprofit
Contact
Jeffrey Phillips
Senior Program Manager, Advanced Generation
704.595.2738
jphillip@epri.com
organization, EPRI brings together its scientists and engineers as well as
experts from academia and industry to help address challenges in electricity, including reliability, efficiency, health, safety and the environment.
EPRI also provides technology, policy and economic analyses to drive
long-range research and development planning, and supports research in
emerging technologies. EPRI’s members represent more than 90 percent
of the electricity generated and delivered in the United States, and international participation extends to 40 countries. EPRI’s principal offices
and laboratories are located in Palo Alto, Calif.; Charlotte, N.C.; Knoxville, Tenn.; and Lenox, Mass.
Together . . . Shaping the Future of Electricity
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October 2015
Electric Power Research Institute
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