Efficient Generation: Combustion Turbine Electric Generating Units
Technical Support Document (TSD)
New Source Performance Standards for Greenhouse Gas Emissions from New, Modified, and
Reconstructed Fossil Fuel-Fired Electric Generating Units; Emissions Guidelines for Greenhouse Gas
Emissions from Existing Fossil Fuel-Fired Electric Generating Units; and Repeal of the Affordable
Clean Energy Rule Proposal
Docket ID No. EPA-HQ-OAR-2023-0072
U.S. Environmental Protection Agency
Office of Air and Radiation
May 2023
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Table of Contents
Introduction 3
Types of Combustion Turbines 3
Design Efficiencies of Combustion Turbines 4
Factors Impacting Combustion Turbine Efficiency 4
Fuel type 4
EGU cooling system 4
EGUgeographic location and ambient conditions 4
EGU duty cycle & load generation flexibility requirements 5
Other factors 5
Potential Efficiency Gains at Simple Cycle EGUs 6
Steam Injection 8
Pressure Gain Combustion 9
Potential Efficiency Gains in Combined Cycle EGUs 10
Advances in Combined Cycle Operation 10
HRSG Configurations 12
Potential Efficiency Gains in the Bottoming (Rankine) Cycle 13
Heat Recovery Steam Generation Design Optimization 15
Intercooled Combined Cycle 16
Blowdown Heat Recovery 16
Design and Operating and Maintenance Practices 16
Once-Through (Benson®) HRSG Technology 18
The Use of Supercritical Steam Conditions 19
The Use of Alternate Working Fluid 21
The Use of Thermoelectric Materials 23
Combined Cycle Startup Times 25
Purge Credit 26
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Introduction
Multiple design and operation and maintenance (O&M) parameters influence the efficiency of a
stationary combustion turbine electric generating unit (EGU). This technical support document describes
these factors for both simple and combined cycle combustion turbines. It describes designs and O&M
practices that can improve the efficiency of combustion turbines, which reduces fuel consumption and
therefore emissions of greenhouse gases (GHGs).
The following is a summary of some of the design parameters that impact the carbon dioxide (CO2)
emission rates of combustion turbine EGUs. This summary is not intended to be a comprehensive list of
all design parameters that influence the CO2 emission rates.
As the thermal efficiency of a combustion turbine increases, less fuel is burned per gross megawatt hour
(MWh) of electricity produced by the turbine-generator and there is a corresponding decrease in CO2
and other air emissions. Efficiency is reported as the percentage of the energy in the fuel that is
converted to electricity.1 Heat rate is another common way to express efficiency. Heat rate is expressed
as the amount of British thermal units (Btu) or kilojoules (kJ) required to generate a kilowatt-hour
(kWh) of electricity. Lower heat rates are associated with more efficient power generation. Efficiency
improvements can be expressed in different formats; they may be reported as an absolute change in
overall efficiency (e.g., a change from 40 percent to 42 percent represents a 2 percent absolute increase).
They may also be presented as the relative change in efficiency (e.g., a change from 40 percent to 42
percent results in a 5 percent reduction in fuel use). The relative change in efficiency is the most
consistent approach because it corresponds to the same change in heat rate. For most combustion turbine
EGUs, as heat rates are reduced there are corresponding reductions in fuel extraction-related
environmental impacts as well as associated thermal impacts on cooling water ecosystems.2
The electric energy output for an EGU can be expressed as either "gross output" or "net output." The
gross output of an EGU is the total amount of electricity generated at the generator terminal. The net
output of an EGU is the gross output minus the total amount of auxiliary (i.e., parasitic) electricity used
to operate the EGU (e.g., electricity to power fuel handling equipment, pumps, fans, pollution control
equipment, and other onsite electricity needs), and thus is a measure of the electricity delivered to the
transmission grid for distribution and sale to customers.
Types of Combustion Turbines
Combined cycle EGUs are power plants using both a combustion turbine engine (i.e., the "topping" or
Brayton cycle) and a steam turbine (i.e., the "bottoming" or Rankine cycle) to generate electricity. First,
fuel is burned in a combustion turbine engine and the high-temperature exhaust is recovered by a heat
recovery steam generator (HRSG) to create additional thermal output (e.g., steam). Next, the steam is
used as the working fluid in a Rankine cycle and expanded through a steam turbine to produce
additional power.3 Combined cycle units have significantly higher efficiencies compared to simple cycle
combustion turbines—combustion turbine engines where the high-temperature exhaust is not recovered.
1 For example, a 40 percent efficient combustion turbine converts 40 percent of the energy in the fuel to useful output.
2 Combined cycle EGUs using dry cooling or simple cycle EGUs do not have cooling water ecosystem impacts.
3 https://www.ge.com/gas-power/resources/education/combined-cycle-power-plants
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Design Efficiencies of Combustion Turbines
EGU efficiency generally increases with size. Larger EGUs also tend to be more efficient because they
are usually newer and use advanced technologies and economy of scale allows the use of higher cost
improvements to be more economic, but these are not inherent differences in efficiencies. For combined
cycle turbines, as equipment size increases above approximately 2,000 MMBtu/h, the differences in
these losses start to taper off.
Factors Impacting Combustion Turbine Efficiency
Multiple factors can influence the efficiency of a combustion turbine. Factors include, but are not
limited to, fuel type, ambient conditions, and pollution control equipment.
Fuel type
Combustion turbines tend to me most efficient when burning natural gas. When burning other fuels,
such as distillate oil or hydrogen, design efficiencies decrease.
EGU cooling system
Reducing the condenser temperature improves the efficiency of a steam turbine converting the thermal
energy in the steam to electricity. Once-through cooling systems can achieve a lower condenser
temperature and have an efficiency advantage over recirculating cooling systems (e.g., cooling towers)
and dry systems. However, once-though cooling systems typically have larger water-related ecological
concerns than recirculating cooling systems. The International Energy Agency4 (IEA) estimates that
similar EGUs using the Rankine cycle with once-through cooling systems that use sea water and river
water would have 2.4 percent and 1.5 percent lower heat rates (i.e., more efficient), respectively, than an
identical EGU using a recirculating cooling system. Conversely, an identical EGU using a dry cooling
system would have a 5 percent higher (i.e., less efficient) heat rate. Where the efficiency of once-
through cooling systems is impacted by the cooling water temperature, the efficiency on recirculating
cooling systems is influenced by the wet bulb temperature (i.e., the air temperature accounting for the
relative humidity) and dry cooling systems are impacted by the actual temperature of the air (i.e., dry
bulb temperature). Also, geographic location influences the type of cooling system that can be used
(e.g., EGUs in locations with limited water availability rarely, if ever, use once-through cooling and
might elect to use dry cooling).
EGU geographic location and ambient conditions
Ambient temperatures and elevation at the site of a facility may potentially have an impact on EGU
efficiency. Cooler ambient temperatures theoretically could increase the overall combustion turbine
efficiency by decreasing the powered required by the combustion turbine engine compressor. In
addition, the efficiency of Rankine cycle of combined cycle combustion turbines can increase at lower
temperatures from increasing the draft pressure of the HRSG flue gases and the condenser vacuum and
by increasing the efficiency of the cooling system. However, higher ambient temperatures potentially
lower the amount of fuel required to increase the temperature of the combustion air and reduce radiative
losses. The IEA5 estimates that net heat rate of a Rankine cycle increases by 0.15 percent for each 1
degree Celsius (° C) increase in ambient temperature.
4 Coal Industry Advisory Board to the International Energy Agency, "Power Generation from Coal," (Paris, 2010).
Available at: https://www.iea.org/reports/power-generation-from-coal-2010.
5 Coal Industry Advisory Board to the International Energy Agency, "Power Generation from Coal," (Paris, 2010). Available
at: https://www.iea.org/reports/power-generation-from-coal-2010.
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EGU duty cycle & load generation flexibility requirements
Operating an EGU as a base load unit is more efficient than operating an EGU as a load cycling unit at a
lower duty cycle to respond to fluctuations in customer electricity demand.
Other factors
Pollution control devices require electricity to operate and increase the auxiliary (i.e., parasitic) loads.
This reduces the net efficiencies of EGUs. The auxiliary load requirements for nitrogen oxide (NOx)
controls are each typically 0.5 percent of the gross output of the facility.
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Potential Efficiency Gains at Simple Cycle EGUs
Simple cycle designs have been iterated over the years to improve efficiency, increase capacity, and
reduce emissions. Efficiency improvements include increased firing temperatures, increasing
compression ratios, and the addition of intercooling. According to Gas Turbine World, the design net
efficiency of new simple cycle turbines can range from 32 to 40 percent. These are design efficiencies at
specified conditions, and both power output and efficiency are impacted by ambient conditions. A
combustion turbine operates on a fixed volumetric flow of air to the compressor at a given inlet guide
vane position. 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 combustion turbine and
less is available to rotate the generator to produce electricity. At lower temperatures the opposite
occurs—output and efficiency increase compared to design specifications. For every °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.6' 7 Humidity also impacts the output and heat rate of a combustion turbine. As
humidity increases, the density of the air decreases which reduces the mass flow through the
compressor. Higher humidity also results in a reduction in compressor efficiency, increasing the heat
rate.8
One approach owners/operators of combustion turbines can take to reduce the capacity losses and
increased heat rates due to higher ambient temperatures is precooling the combustion turbine inlet air.9'
10 Owners/operators employ inlet air cooling techniques that generally fall into two categories:
evaporative cooling and chilling systems. Evaporative cooling works by adding liquid water to the
combustion air.11 As the water evaporates, it cools the combustion air. Chilling systems use mechanical
or adsorption chillers to reduce combustion air temperature.12 One common type of cooling is inlet
6 Farouk, N., Sheng, L., & Hayat, Q. (2013). Effect of ambient temperature on the performance of gas turbines power plant.
IJCSI International Journal of Computer Science Issues, 10(1,3), 439-442. https://www.ijcsi.org/papers/IJCSI-10-l-3-439-
442.pdf.
7 Higher air pressure (at a constant temperature) results in a relatively slight decrease in the heat rate. Enge, Jason (August 2,
2022). Ambient Factors Conditions and Combustion Turbine Performance. Fossil Consulting Services, Inc.
https://www.fossilconsulting.com/2022/08/02/ambient-factors-conditions-and-combustion-turbine-performance/.
8 Enge, Jason (August 2, 2022). Ambient Factors Conditions and Combustion Turbine Performance. Fossil Consulting
Services, Inc. https://www.fossilconsulting.eom/2022/08/02/ambient-factors-conditions-and-combustion-turbine-
performance/
9 Pre-cooling of combustion turbine inlet air can either be cooled using an evaporative or a chilling system. Evaporative
cooling adds liquid water to the inlet 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 inlet air. Chilling systems can cool the inlet air below the dew point temperature but
can have significant auxiliary loads. Compressed air injection is an alternate way to recover capacity that is lost due to high
ambient temperatures.
10 GTW (2021). 2021 GTWHandbook. Volume 36. Page 79. Pequot.
11 Water used in combustion turbines must be of high quality (e.g. demineralized water) to prevent deposits and corrosion
from occurring in the turbine engine.
12 United States Environmental Protection Agency (EPA) (2022). Available and Emerging Technologies for Reducing
Greenhouse Gas Emissions from Combustion Turbine Electric Generating Units. EPA Office of Air and Radiation. April 21,
2022. Accessed at https://www.epa.gov/system/files/documents/2022-04/epa_ghg-controls-for-combustion-turbine-
egus_draft-april-2022.pdf.
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fogging, an evaporative cooling system where fine water particles (typically less than 20 microns) are
sprayed into the inlet combustion turbine air, leading to lower inlet air temperatures and higher
efficiencies.13 Wet compression is a system like inlet fogging but with higher efficiency. In wet
compression, an excess of fog is sprayed into the inlet air so that fog still exists after the air is fully
saturated. Some of the excess fog droplets are not evaporated until they are carried into the compressor,
which provides additional cooling and results in further power increases of the combustion turbine
14
engine.
General Electric (GE) has proprietary intercooling technology called "SPRINT" or "SPray
INTercooling" that is paired with an LM6000 combustion turbine. The SPRINT™ technology uses
demineralized water that is atomized with high-pressure compressed air and sprayed into the inlet of the
low-pressure compressor and high-pressure compressor. This results in a higher mass flow through the
compressor and increased power output. Moreover, this technology can result in high incremental output
and improved efficiency as ambient temperatures rise.15 The design output and efficiencies for three
different LM6000 combustion turbines with and without SPRINT technology are outlined in Figure 1.
Figure 1: Comparison of LM6000 Combustion Turbines With and Without SPRINT™
Technology
Combustion turbine
ISO IS:ise Lontl (M\Y)
FITioienov (%)
LM6000 PC
46.6
40.0%
LM6000 PC Sprint
51.1
39.8%
LM6000 PG
56
39.1%
LM6000 PG Sprint
57.2
38.7%
LM6000 PF
44.7
41.4%
LM6000 PF Sprint
50.0
41.4%
In addition to reducing the impacts of higher ambient temperatures, water injection into the combustor
also provides NOx control. NOx emissions from the combustor have been shown to increase
exponentially with increasing temperatures. Thus, water injected into the combustor flame area to lower
the temperature and, consequently, reduce NOx emissions.16 Water injection is estimated to result in a
60 to 80 percent reduction of NOx emissions for a diffusion flame design combustion turbine.17' 18
13 Meher-Homji, C., Mee, T. (2000). Gas Turbine Power Augmentation by Fogging of Inlet Air. Proceedings of the 28th
turbomachinery Symposium (2000), Texas A&M. Accessed at
https://oaktrust.library.tamu.edu/bitstream/handle/1969. l/163382/Vol28010.pdf?sequence=l&isAllowed=y.
14 Savic, S., Hemminger, B., Mee, T. (2013). High Fogging Application forAlstom Gas Turbines. Proceedings of PowerGen.
November 2013. Accessed at http://www.meefog.com/wp-content/uploads/High-Fogging-Alsotom-Mee_-2013-2.pdf.
15 GE (n.d.) SPRINT * SPray INTercooling for power augmentation. Accessed at https://www.ge.com/gas-
power/services/gas-turbines/upgrades/sprint.
16 In general, the additional of liquid water or steam will not increase emissions of carbon monoxide or unburned
hydrocarbons. However, at higher injection rates emissions of carbon monoxide and unburned hydrocarbons can increase.
17 EPA (2002). CAM Technical Guidance Document. B. 17 Water or Steam Injection. Accessed at
https://www3.epa.gov/ttnchiel/mkb/documents/B_17a.pdf.
18 Water injection is not used for NOx control in combustion turbines using lean premixed combustion (i.e., dry low NOx)
systems.
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Additionally, experimental results have shown that water and steam injections can lower exhaust gas
temperatures to reduce NOx emissions by 70 percent and 57 percent, respectively.19
Steam Injection
Steam inject is like water injection, except that steam is injected into the combustion chamber instead of
water. The advantage of steam injection over water injection is that it improves the efficiency, increases
the output, and reduces the NOx emissions of the combustion turbine. Multiple vendors offer different
variations of steam injection. The basic process uses a relatively low-cost HRSGto produce steam, but
instead of recovering the energy by expanding the steam through a steam turbine, the steam is injected
into the combustion chamber and the energy is extracted by the combustion turbine engine. Combustion
turbines using steam injection have characteristics of both simple cycle and combined cycle units. For
example, on one hand, when compared to standard simple cycle combustion turbines, they are more
efficient but more complex with higher capital costs. On the other hand, compared to combined cycle
combustion turbines, they are simpler and have shorter construction times, lower capital costs, but have
lower efficiencies. 20'21
A steam injection gas turbine cycle (STIG) is the steam injection process used in GE combustion
turbines. For STIG cycles, the steam source is specifically provided by the HRSGto increase both cycle
efficiency and power output.22 One study modeled the performance of a GE Frame 6b simple cycle unit
that was retrofitted with a STIG cycle, and results suggest that efficiency can be increased from 30
percent to 40 percent and that power output can be increased from 38 to 50 MW.23 The relative
improvements suggested by this study are similar to estimates from GE. GE advertises that its LM2500
aeroderivative combustion turbine can improve power output by 25 percent when outfitted with a STIG
cycle.24 STIG uses a constant pressure HRSG and operation is limited to near full load when thermal
load is relatively constant. The exhaust temperature drops at partial loads and the HRSG cannot maintain
a balanced heat transfer.
Mitsubishi Power's Smart-AHAT (Advanced Humid Air Turbine) is a steam injection system that
achieves near-zero water makeup using an integrated water recovery system. The system is potentially
less complex and more flexible than combined cycle systems, with efficiencies significantly higher than
conventional simple cycle plants. The HRSG involved in the system is a conventional single-pressure
unit that produces the steam required for the combustion turbine's steam injection. An important benefit
of the Smart-AHAT system is water preservation. Without a water recovery system (WRS), large
amounts of water in the form of steam would be lost to the atmosphere through the HRSG stack. Smart-
19 Kotob, M. R., Lu, T., Wahid, S. S. (2021). Experimental comparison between steam and water tilt-angle injection effects
on NOxreduction from the gaseous flame. Royal Society of Chemistry. https://doi.org/10.1039/DlRA03541J.
20 Bahrami, S., et al (2015). Performance Comparison between Steam Injected Gas Turbine and Combined Cycle during
Frequency Drops. Energies 2015, Volume 8. https://doi.org/10.3390/en8087582.
21 Mitsubishi Power. Smart-AHAT (Advanced Humid Air Turbine. Accessed at
https://power.mhi.com/products/gasturbines/technology/smart-ahat.
22 Bouam, A., Aissani, S., Kadi, R. (2019). Gas Turbine Performances Improvement using Steam Injection in the Combustion
Chamber under Sahara Conditions. Oil and Gas Science and Technology. Institut Francais du Petrole (IFP), 2008, 63 (2),
pp.251-261. 10.2516/ogst:2007076.
23 Wang, F. J., Chiou, J. S. (2002). Performance improvement for a simple cycle gas turbine GENSET - a retrofitting
example. Applied Thermal Engineering 22 (2002) 1105-1115. Accessed at
https ://citeseerx. ist.psu. edu/viewdoc/download?doi= 10.1.1.583.9680&rep=rep 1 &type=pdf.
24 GE Power & Water. Accessed at https://www.ge.eom/gas-power/products/gas-turbines/.product-spec-table.
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AHAT uses a direct, spray-type heat exchanger to reduce the HRSG exhaust gas temperature below the
water dew point of the flue gas and causes condensation of the water vapor. Some condensate is
recirculated to the spray nozzles of the heat exchanger while the rest is treated and returned as feed
water for the HRSG steam production.
The Cheng Cycle provides uses a variable-pressure HRSG and the operating range is from idle to full
load.25 Performance measurements indicate that implementing a Cheng Cycle system on a combustion
turbine can provide up to a 26 percent efficiency improvement compared to the base turbine engine.26
Pressure Gain Combustion
Pressure gain combustion (PGC) has the potential to increase combustion turbine EGU efficiency and
reduce emissions. Estimates for higher efficiencies could reach 4 to 6 percent for simple cycle systems
and 2 to 4 percent in combined cycle systems. In conventional combustion turbines, engines undergo
steady, subsonic combustion that results in a total pressure loss. In PGC, multiple physical phenomena,
such as resonant pulsed combustion, constant volume combustion, and detonation can be used to create
a rise in effective pressure across the combustor while consuming an equal quantity of fuel.27 The U.S.
Department of Energy (DOE) assessed the inclusion of PGC in combined cycle power plants. The study
found that a PGC-integrated system produced 3.09 percent more power at the same fuel flow rate and
reduced the cost of electricity (COE) by 0.58 percent.28 One key advantage of PGC technology is that it
can be compounded with other combustion turbine technology improvements such as compressor
efficiency. Applications of PGC hold promise toward the Advanced Turbine Program's efficiency
goals.29 The DOE's integrated PGC system achieved a net lower heating value (LHV) efficiency of
64.56 percent, while a PGC system that included other combustion turbine technology improvements
achieved a LHV efficiency of 66.68 percent.
25 Ganapathy, V., Heil, B., Rentz, J. (1988). Heat Recovery Steam Generator for Cheng Cycle Application. Industrial Power
Conference, PWR, Vol. 4. Accessed at http://v_ganapathy.tripod.com/cheng.pdf.
26 Digumarthi, R., Chang, C. (1984). Cheng-Cycle Implementation on a Small Gas Turbine Engine. Journal of Engineering
for Gas Turbines and Power. Volume 106, Issue 3. https://doi.org/10.1115/L3239626.
27 DOE NETL. Pressure Gain Combustion. Accessed at https://netl.doe.gov/node/7553.
28 DOE (2016). Combined Cycle Power Generation Employing Pressure Gain Combustion. Accessed at
https://www.osti.gov/servlets/purl/1356814.
29 Neumann, Nicolai, & Peitsch, Deiter (2019). Potentials for Pressure Gain Combustion in Advanced Gas Turbine Cycles.
Accessed at https://www.mdpi.eom/2076-3417/9/16/3211.
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Potential Efficiency Gains in Combined Cycle EGUs
Advances in Combined Cycle Operation
While many configurations of HRSGs are available to improve the efficiency of the bottoming steam
cycle, several improvements have been made to other parts of the combined cycle. These include
improvements to the combustion turbine engine, turbine cooling, compressors, condensers, and more.
Improved performance in industry standard combined cycles has resulted from years of iterative
industry innovation.
GE provides an example of the evolution of more efficient combustion turbine technology with its 7HA
and 9HA designs, which operate at 60 hertz (Hz) and 50 Hz, respectively. These combustion turbines
represent current "H-class" technology and feature firing temperatures greater than 1,430 °C. The H-
class is an evolution of GE combustion turbines that began with the E-class and F-class combustion
turbine. In general, the firing temperature has increased from the E-class (earliest iteration) to the H-
class and the resulting combined cycled efficiency has increased as well. In addition, the H-class
combustion turbine includes completely air-cooled hot gas paths due to advanced turbine cooling,
sealing, materials, and coating. Within the 7/9HA combustion turbines, the 7/9HA.02 has increased
power output compared to the 7/9HA.01 because of increased compressor inlet and turbine exit annulus
areas, with an increased pressure ratio to maintain flow. It should be noted that the HA products can
ramp to full plant load in less than 30 minutes, ensure ramping capability in emissions compliance of
greater than 15 percent load per minute, and include fuel flexibility to operate on both gaseous and
liquid fuels.30 It should also be noted that a third generation 7HA combustion turbine, the 7HA.03, has
been designed to be even more efficient, and the first two GE 7HA.03 combustion turbines have recently
begun operating at the Dania Beach Clean Energy Center (DBEC) in Broward County, Florida.31
Combustion turbine combined cycle design specifications are outlined for the 7/9HA family in Figure 2.
Figure 2: Design Specifications at ISO Conditions for the GE 7/9 HA Combustion turbine
Family32
Model
No. & Type
Net Plant
Net Ileal Kate
Net Plant
Net Plant
Combustion
Output (k\\)
(lit ukWh)
KITiciencv
KITiciencv
turbine
(I.IIV)
(IIIIV)
9HA.01
1 x 9HA.01
680,000
5,356
63.7%
57.4%
(50 Hz)
9HA.01
2 x 9HA.01
1,363,000
5,345
63.8%
57.5%
(50 Hz)
9HA.02
1 x 9HA.02
838,000
5,320
64.1%
57.7%
(50 Hz)
9HA.02
2 x 9HA.02
1,680,000
5,306
64.3%
57.9%
30 Vandervort, C., Leach, D., Scholz, M. (2016). Advancements in H Class Gas Turbines for Combined Cycle Power Plants
for High Efficiency, Enhanced Operational Capability, and Broad Fuel Flexibility.8th International Gas Turbine Conference.
12-13 Oct. 2016. Brussels, Belgium. https://etn.global/wp-content/uploads/2018/09/ADVANCEMENTS-IN-H-CLASS-
GAS-TURBINES-FOR-COMBINED-CYCLE-POWER-PLANTS-FOR-HIGH-EFFICIENCY-ENHANCED-
OPERATIONAL-CAPABILITY-AND-BROAD-FUEL-FLEXIBILITY.pdf.
31 Patel, S. (2022). GE Debuts First 7HA. 03 Gas Turbines at 1.3-GWPlant in Florida. Power Magazine. Accessed at
https://www.powermag.com/ge-debuts-first-7ha-03-gas-turbines-at-l-3-gw-plant-in-florida/
32 GTW (2021). 2021 GTWHandbook. Volume 36. Page 82-90. Pequot.
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(50 Hz)
7HA.01
(60 Hz)
1 x 7HA.01
438,000
5,481
62.3%
56.1%
7HA.01
(60 Hz)
2 x 7HA.01
880,000
5,453
62.6%
56.4%
7HA.02
(60 Hz)
1 x 7HA.02
573,000
5,381
63.4%
57.1%
7HA.02
(60 Hz)
2 x 7HA.02
1,148,000
5,365
63.6%
57.3%
7HA.03
(60 Hz)
1 x 7HA.03
640,000
5,342
63.9%
57.6%
7HA.03
(60 Hz)
2 x 7HA.03
1,282,000
5,331
>64.0%
>57.6%
Notice that small increases in net plant efficiency occur by collocating two combustion turbines at one
combined cycle plant.
Another advanced combustion turbine operating within the combined cycle class is the Siemens HL
combustion turbine. The "HL" terminology indicates that the current technology is an intermediate
between the H-class technology and the L-class technology of the future that will be capable of 65
percent efficiency (LHV) when employed in a combined cycle plant. The HL combustion turbine
evolved from the H-class turbine with some notable improvements. Namely, the turbine inlet
temperature of the HL is about 100 °C higher than that of the H-class. This has a large impact on the
increase in efficiency. Additionally, a new combustion system called "Advanced Combustion system for
high Efficiency" (ACE), is employed to reduce the increase in NOx emissions resulting from the
increase in inlet temperature. Moreover, the number of compressor stages is reduced from 13 to 12 while
simultaneously increasing the pressure ratio for increased performance and reduced complexity. Turbine
blade internal cooling features were added to accommodate the higher temperatures, which also reduces
dependency on cooling air consumption. Lastly, internally cooled free-standing blades are employed in
stage 4 of the turbine, as opposed to uncooled blades in stage 4 for the H-class turbine, resulting in
higher power output and exhaust temperatures. Exhaust temperatures of the HL-class combustion
turbine are designed to be approximately 680 °C compared to 630 °C for Siemen's H-class combustion
turbine.33
Additionally, the DOE's Advanced Turbines Program is supporting the development of advanced
turbine technologies, which includes combined cycle. The program's goal is to reach 65 percent
efficiency (LHV) for combined cycle technology by conducting research on hot section components and
technology, including but not limited to materials, advanced cooling, leakage control, advanced
aerodynamics, and altogether new turbine design concepts. Most notable, the program hopes to develop
combustors that operate at higher temperatures with lower NOx emissions.34 Specifically, the goal is to
increase the firing temperature of combustion turbines in combined cycle plants to 3,100 °F.35
33 Modern Power Systems (2018). Siemens HL: the bridge to 65%+ efficiency. Accessed at
https://www.modernpowersystems.com/features/featuresiemens-hl-the-bridge-to-65-efficiency-6045386/.
34 U.S. Department of Energy (DOE) (2021). Advanced Turbines. Accessed at https://netl.doe.gov/sites/default/files/2021-
10/Program-108 .pdf.
35 DOE National Energy Technology Laboratory (NETL). Advanced Combustion Turbines. Accessed at
https://netl.doe.gov/carbon-management/turbines/act.
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Furthermore, it should also be noted that the DOE cited combined cycle36 efficiency goals of 67 percent
(LHV) and "long-term" goals of 70 percent efficiency (LHV) in its 2022 fiscal year congressional
budget request.37 Combined cycle power plants employing Siemens HL-class technology are currently
rated at >63 percent combined cycle efficiency compared to 61 percent for those plants employing Pi-
cks s technology.38
HRSG Configurations
The design of a HRSG can impact how long it takes to start producing steam and generating power.
Currently, 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. 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, which is not used on all combined cycle EGUs, is
the fuel preheater. The fuel preheater preheats the fuel used for the combustion turbine engine.
While a HRSG has no moving parts, thermal inertia and rapid heating can stress the components and
shorten the operating life of the unit.39 The high-pressure drum is the most vulnerable component when
subjected to rapid heating; therefore, the drum is typically heated slowly with designated hold points
during startup.40 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. Also, an auxiliary boiler can maintain the HRSG temperature, reducing the time required for an
HRSG to begin producing steam. However, the use of an auxiliary boiler decreases the overall
efficiency of the combined cycle EGU.
For HRSGs, there are currently three main configurations found in industry: two-pressure non-reheat
(2PNR), three-pressure non-reheat (3PNR), and three-pressure reheat (3PRH). The two-pressure (2P)
versus three-pressure (3P) designations refer to the number of steam pressures in the steam cycle. A 2P
steam cycle employs two steam turbines—a low pressure (LP) steam turbine and a high pressure (HP)
steam turbine. Similarly, a 3P steam cycle employs three steam turbines where one is an LP turbine, one
36 Efficiency using LHV for combined cycles using natural gas.
37 DOE (2022). Department of Energy FY 2022 Congressional Budget Request. DOE/CF-0174, Volume 3 Part 2, Page 199.
Accessed at https://www.energy.gov/sites/default/files/2021 -06/doe-fy2022-budget-volume-3.2_0.pdf.
38 Gas Turbine World (2021). 2021 GTWHandbook. Volume 36. Page 82-90. Pequot.
39 Pasha, A. (1992). Combined Cycle Power Plant Start-up Effects and Constraints of the HRSG. Proceedings of ASME
Turbo Expo, 1992. Power of Land, Sea, and Air. https://doi.org/10.1115/92-GT-376.
40 Pasha, A. (1992). Combined Cycle Power Plant Start-up Effects and Constraints of the HRSG. Proceedings of ASME
Turbo Expo, 1992. Power of Land, Sea, and Air. https://doi.org/10.1115/92-GT-376.
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is a HP turbine, and the third, located between the LP and HP turbines, is an intermediate (IP) pressure
turbine. A 2P or 3P cycle can also employ reheating as a method to increase steam turbine efficiency.
With reheating, steam is routed back to the HRSG to be reheated prior to further expansion through
subsequent lower pressure turbines.
A HRSG can also include duct burners, sometimes called supplemental firing. Supplemental firing is the
mixing of additional fuel to turbine exhaust—which still contains available oxygen to support additional
combustion. The combustion of this supplemental fuel increases the useful thermal output of the HRSG
and is typically only done during periods of high electric demand. While the use of duct burners can
increase output during critical periods, they reduce the overall efficiency of the combined cycle EGU.
Since the additional fuel is only using the bottoming Rankine cycle, incremental efficiencies are on the
order of a simple cycle combustion turbine. Typically, duct burners are categorized as either small or
large based on duct size, spacing, and design constraints. Small duct burners are intended to make up
capacity that is lost during periods of high ambient temperatures. Small duct burners only impact
efficiency while operating. In contrast, combined cycle designs with large duct burners oversize the
steam turbine relative to the output that can be provided by the combustion turbine engine. The use of
large duct burners provides significant additional capacity. However, since the steam turbine is more
often operating at partial load and is less efficient, the combined cycle efficiency is impacted even when
the duct burners are not operating.
An alternative to the use of duct burners is complementary firing. Complementary firing combines a
relatively small combustion turbine(s)41 with a larger combined cycle facility. The small turbine is
generally used during periods when the steam turbine is not operating at capacity (e.g., during periods of
high ambient temperatures that often correspond to periods of peak electric demand). The exhaust from
the smaller turbine is sent to the HRSG of the combined cycle EGU. In essence, the smaller combustion
turbine is a combined cycle EGU that is used for peaking applications. The benefits of complementary
firing are that the incremental electricity is generated more efficiently than by using duct burners or from
a standalone simple cycle turbine and the exhaust from the small combustion turbine is routed through
the post-combustion control technology of the larger combined cycle EGU. An additional advantage of
complimentary firing compared to the use of duct burners is that because most of the incremental
electricity is generated by the turbine engine, there is potentially less demand placed on the Rankine
cycle portion of the larger combined cycle EGU. Drawbacks of complimentary firing compared to the
use of duct burners are higher capital costs, less fuel flexibility (duct burners can burn a variety of fuels),
and more limited part-load performance.42
Potential Efficiency Gains in the Bottoming (Rankine) Cycle
The primary differences between a 2PNR, 3PNR, and 3PRH HRSGs are efficiencies and construction
costs.43 The complexity and costs increase with the number of steam pressures. However, increasing the
number of steam pressures allows more energy to be extracted from the exhaust gas, improving overall
efficiency. A reheat cycle adds additional complexity and capital costs but increases the efficiency of the
41 The complimentary fired combustion turbine engines would be sized such that the turbine exhaust could be accommodated
by the HRSG. This generally limits the size of the complimentary turbine engine(s) to less than 10% of the output of the
primary turbine engine(s).
42 In order to achieve part-load capabilities with complimentary firing multiple smaller turbines would be required.
43 GTW (2021). 2021 GTWHandbook. Volume 36. Pages 27-28. Pequot.
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Rankine cycle by increasing the average temperature of the heat addition within the process.44 These
capital costs can at least be partially offset by reductions in fuel costs. For 2P and 3P HRSGs without
reheat cycles, the efficiencies are approximately 20 and 26 percent, respectively. A 3P HRSG with a
reheat cycle improves the efficiency of thermal energy to electrical output to approximately 30 percent.
According to Gas Turbine World, all aeroderivative and frame combined cycles with base load ratings
of less than 500 MMBtu/h use 2P HRSGs. Meanwhile, 3P HRSGs without a reheat cycle are used for
frame combined cycle EGUs up to 2,000 MMBtu/h, and 3P HRSGs with a reheat cycle are used for
frame combined cycle EGUs with base load ratings of greater than 2,000 MMBtu/h. From a practical
standpoint, the use of a reheat cycle is limited to combustion turbine engines with exhaust temperatures
greater than 593 °C and for steam turbines greater than 60 MW.45 However, 3P HRSGs have been
applied to aeroderivative combined cycle EGUs and could be adopted on smaller frame combined cycle
EGUs as well.46
Several studies have compared various HRSG configurations for combined cycle EGUs. One study
directly compared 2PNR, 3PNR, and 3PRH steam cycles. It concluded that increasing the number of
pressure cycles leads to an increase in efficiency of the entire cycle. Additionally, the study concluded
that although increasing steam generation pressure levels requires a larger upfront investment, it
ultimately yields a higher return, and the net present value (NPV) of the higher-pressure level plants
(i.e., 3PRH) increases. The study concluded that the estimated NPV of a 3PNR or 3PRH plant increases
by 0.03 and 7 percent, respectively, when compared to the NPV of a 2PNR plant.47 Figure 3 shows the
costs and efficiencies with more complex HRSG configurations compared to one with a 2PNR HRSG.
Figure 3: Relative Efficiencies and Costs of Combined Cycle with Various HRSG Configurations
1 IRS(; ( <)nfi»ur;ilion
Com hined
Cycle \el
KITiciency
Increase in
Com hined Cycle
KITiciency kel:i(i\e
l<> 2I>\R
Com hined Cycle
Cost (S/k\\ )
Incrc.ise in
Combined Cycle
Cost UehiliM'lo
2I»\R
2PNR
56.06%
-
520.1
-
3PNR
56.22%
0.29%
530.5
2.0%
3PRH
57.15%
1.9%
540.6
3.9%
It should also be noted that single-pressure HRSG technology is available as well. While they are the
lowest-cost and simplest HRSG design, they are also the least efficient and infrequently used in new
combined cycle EGUs. The thermal efficiency of a single-pressure, no-reheat HRSG system is estimated
to be 3.7 percent less than that of a comparable 2PNR system.48 One study estimated the efficiencies and
electricity costs of single-, dual-, and triple-pressure HRSGs. It found that when compared to single-
pressure HRSGs, dual-pressure and triple-pressure HRSGs resulted in combined cycle efficiencies
44 Rashidi, M. M., Aghagoli, A., Ali, M., Thermodynamic Analysis of a Steam Power Plant with Double Reheat and Feed
Water Heaters. Advances in Mechanical Engineering. Volume 2014, Article ID 940818, 11 pages.
https://doi.org/10.1155%2F2014%2F940818
45 Chase, D.L. and P.T. Kehoe, GE Combined-Cycle Product Line and Performance. GE Power Systems. GER-3574G.
Accessed at: https://hi.dcsmodule.eom/js/htmledit/kindeditor/attached/20220402/20220402143103_85047.pdf
46 https://www.ijert.org/off-design-performance-analysis-of-a-triple-pressure-reheat-heat-recovery-steam-generator
47 Mansouri, M. T., Ahmadi, P., Kaviri, A. G., Jaafar, M. N. M. (June 2012). Exergetic and economic evaluation of the effect
of HRSG configurations on the performance of combined cycle power plants. Energy Conversion and Management. Volume
58. Pages 47-58. https://doi.Org/10.1016/j.enconman.2011.12.020.
48 Chase, D.L. and P.T. Kehoe, GE Combined-Cycle Product Line and Performance. GE Power Systems. GER-3574G
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increasing by 4.5 and 7.2 percent, respectively. Moreover, the study estimated the cost of electricity
from combined cycles utilizing single-pressure, dual-pressure, and triple-pressure HRSGs to be
$48.13/MWh, $46.39/MWh, and $45.79/MWh, respectively. According to this study, utilizing a dual-
pressure HRSG may result in a 3.6 percent electricity cost reduction compared to single-pressure HRSG
utilization, and utilizing a triple-pressure HRSG may result in a 4.9 percent electricity cost reduction
compared to single-pressure HRSG utilization.49 Figure 4 shows the costs and efficiencies with more
complex configurations compared to one with a single-pressure HRSG.
Figure 4: Relative Efficiencies and COE with Various HRSG Configurations
HRSG
CC Net
Increase in
Total Capital
Increase in
COE
Decrease in
Configuration
Efficiency
Combined
Requirement
TCR
($/MWh)
COE
Cycle
(TCR)
relative to 1-
Relative to
Efficiency
(million $)
pressure
1-pressure
Relative to 1-
pressure
1-pressure
50%
-
116.1
-
48.13
-
2-pressure
52.25%
4.5%
119.3
2.76%
46.39
3.62%
3-pressure
53.6%
7.2%
129.9
11.89%
45.79
4.86%
Heat Recovery Steam Generation Design Optimization
For a given HRSG design, parameters can be thermodynamically optimized to achieve the maximum
overall efficiency. Optimization of HRSG performance can identify a best-case scenario for which
similar-designed HRSGs could be operated. Examples of design parameters include, but are not limited
to, the pinch point temperature difference, inlet gas temperature, exit gas temperature, pressure within
the turbine(s), mass flow rate, heat transfer area, pipe/tube/steam materials, condenser and cooling tower
heat transfer surface area, steam turbine exhaust annulus area, external insulation to extract additional
useful thermal output while maintaining the flue gas above the flue gas temperature, etc. Studies have
both thermodynamically and economically optimized HRSG performance and development.
One study thermodynamically optimized the parameters within HRSGs for single-, double-, and triple-
pressure turbine use. The results indicate that single-, double-, and triple-pressure HRSGs can increase
combined cycle power output by 0.05, 0.28, and 0.29 percent, respectively, for every 10-bar inlet
pressure increase. Furthermore, it found that the net combined cycle power output will decrease by 0.54,
0.21, and 0.17 percent for every 10 °C evaporator pinch point temperature difference.50 The results
suggest that a significant performance increase can result from choosing optimum operating conditions for a
given HRSG. Additionally, the findings suggest that single-pressure HRSGs are most susceptible to efficiency
decrement for suboptimum operation, and triple-pressure HRSGs have the most potential for improvement
through optimization.
49 Zhao, Y., Chen, H., Waters, M., Mavris, D. N. (2003). Modeling and Cost Optimization of Combined Cycle Heat Recovery
Generator Systems. Proceedings of ASME Turbo Expo, 2003. Power of Land, Sea, and Air. https://doi.org/10.1115/GT2003-
38568.
511 Raliim, M. A. (September 2012). Combined Cycle Power Plant Performance Analyses Based on the Single-Pressure and
Multipressure Heat Recovery Steam Generator. Journal Of Energy Engineering. Volume 138, Issue 3.
https://doi.org/10.1061/(ASCE)EY. 1943-7897.0000063.
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In addition, 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 occurs before the fuel is fed into the
combustion chamber of the combustion turbine and can be carried out by using the heat of the exhaust
gases of the combustion turbine. Heating fuel gas from a base temperature of 0 °C to a temperature of
450°C increases combustion turbine efficiency from 35.05 to 35.39 percent.51
Intercooled Combined Cycle
Intercooling is a concept that is being used in the latest combustion turbine systems. In simple cycle
systems, intercooling is used to improve the overall efficiency and reduce the compression work by
cooling the hot gases to atmospheric temperature. The energy of the hot water at the intercooler outlet is
lost to the atmosphere. In a combined cycle combustion turbine this energy could be used to heat the
feed water to the HRSG. In a combined cycle plant, the feed water entering the HRSG must have a
higher temperature than the dew of the acid vapor of sulfur. The application of the intercooler as the
feed water heater of the HRSG increases the overall efficiency of the combined cycle as it reduces the
compression work in the upper cycle. An increase of feed-water temperature from 20 °C to 60°C could
increase the overall efficiency by approximately 2 percent.52
Blowdown Heat Recovery
In combined cycle combustion turbines, the concentration of impurities in the steam flow must be
controlled to prevent corrosion of the steam turbine blades.53 A portion of saturated water is
continuously drained through boiler blowdown where it is discharged to the outside environment
through a steam vent or drain flow. This process wastes energy and decreases the efficiency and net
generated power of the cycle. Waste heat from the boiler blowdown stream can be recovered with a heat
exchanger, a flash tank, or a combination of both.54 In a flash tank, the pressure can be lowered to allow
a portion of the blowdown to be converted into low-pressure steam, which can be used in the cycle again
as a heat source to preheat the feed water. The recovery of the wasted heat contributes to an increase in
net power and energy efficiency of the Rankine cycle, as well as a reduction in annual water usage.55
The usage of a flash tank could increase the net power and the energy efficiency of the Rankine cycle by
0.23%, respectively. Since about one-third of the output from a combined cycle is from the Rankine
cycle, blowdown heat recovery could increase the output of the combined cycle EGU by 0.24 percent
and the absolute efficiency by 0.077 percent.
Design and Operating and Maintenance Practices
51 Marin, G. et al. (2020). Study of the effect offuel temperature on gas turbine performance. Accessed at https://www.e3s-
conferences.org/articles/e3sconf/abs/2020/38/e3sconf_hsted2020_01033/e3sconf_hsted2020_01033.html.
52 Shukla, P., et al (2010). A Heat Recovery Study: Application of Intercooler As A Feed-Water Heater of Heat Recovery
Steam Generator. Accessed at https://asmedigitalcollection.asme.org/IMECE/proceedings-
abstract/IMECE2010/44298/611/357134.
53 Saedi, Ali, et al (2022). Feasibility study and 3E analysis of blowdown heat recovery in a combined cycle power plant for
utilization in Organic Rankine Cycle and greenhouse heating. Accessed at
https://www.sciencedirect.com/science/article/pii/S0360544222019600.
54 DOE (2012). Recover Heat from Boiler Blowdown. https://www.energy.gov/eere/amo/articles/recover-heat-boiler-
blowdown#:~:text=Heat%20can%20be%20recovered%20from,occur%20with%20high%2Dpressure%20boilers.
55 Vandani, Amin, et al (2015). Exergy analysis and evolutionary optimization of boiler blowdown heat
recovery in steam power plants. Accessed at https://www.sciencedirect.com/science/article/pii/S0196890415008535.
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While several state-of-the-art turbines and design alterations exist for new combined cycle turbines to
maximize efficiency, efficiency can also be gained for existing combined cycle turbines by proper
maintenance and reparations/reinstallation of various working components. All major manufacturers
offer packages for plants to uprate, and these include improvements to seals, vanes, blades, and other
materials within a plant. GE offers improved wire brush seals which can act as an alternative to both
labyrinth seals for compressor shafts and high-pressure packing seals. Replacing the labyrinth and/or
high-pressure seals can result in output increases of 1 and 0.3 percent, respectively, and heat rate
increases of 0.5 and 0.2 percent, respectively. Moreover, advanced materials can reduce the need to cool
turbine blades, or steam cooling of turbine blades can be used to recover the steam in a closed loop.
Other options resulting in improvements for the power generation process include advanced coatings of
turbine blades and combustor components, replacement of combustion liners, replacement of turbine
vanes/blades, and inlet-air fogging.56 Figure 5 outlines the capacity and heat rate impacts and the
corresponding capital costs for various turbine upgrades.
Figure 5: Comparison of various turbine upgrade options57
Combustion Turbine
I pontile Option
M\\ Incrc.isc (%)
1 lout Rsite 1 in piict (%)
Csipitiil Cost (S/kWV*
Comprehensive Upgrade59
10-20
1-5
150-250
High-Flow Inlet Guide
Vanes
4.5
1
<100
Hot Section Coatings
5-15
0.5-1
50-100
Compressor Coatings
0.5-3
0.5-3
50
Inlet-Air Fogging
5-15
1-5
50-100
Supercharging Plus
Fogging
15-20
4
200
Proper cleaning of HRSG components can also have worthwhile impacts on turbine performance as it
can maintain low pressure drop across the HRSG. Various contaminants, most notably ammonium
bisulfate, can accumulate in the HRSG and can produce pressure losses. In one case study on HRSG
cleaning, GE removed 14 tons of debris, resulting in a reduced turbine back pressure of 8 inches water
column. The combined annual fuel savings and additional power output are believed to have netted the
facility $500,000/year in avoided costs/additional revenue.60 Similarly, plant condensers should be
regularly cleaned. Airborne dust and debris can accumulate and degrade condenser performance.61 Note
56 Andover Technology Partners (2018). Improving Heat Rate on Combined Cycle Power Plants. Accessed at
https://www.andovertechnology.eom/wp-content/uploads/2021/03/C_18_EDF_FINAL.pdf.
57 Andover Technology Partners (2018). Improving Heat Rate on Combined Cycle Power Plants. Accessed at
https://www.andovertechnology.eom/wp-content/uploads/2021/03/C_18_EDF_FINAL.pdf.
58 Costs shown in 2002 dollars.
59 May include "replacement of combustion liners, transition pieces, 1st stage turbine vanes, and 2nd stage vanes and blades
with [GE] Frame 7EA parts."
60 GE (2017). When is 28,000 pound pile of rust a good thing?. Accessed at https://www.ge.com/content/dam/gepower-
new/global/en_US/downloads/gas-new-site/services/hrsg-services/pressurewave-case-study.pdf.
61 Andover Technology Partners (2018). Improving Heat Rate on Combined Cycle Power Plants. Accessed at
https://www.andovertechnology.eom/wp-content/uploads/2021/03/C_18_EDF_FINAL.pdf.
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that turbine overhauls can range from $2 to $12 million for 200-MW turbines but could provide heat rate
improvements of 100 to 300 Btu/kWh, which represents approximately 1 to 3 percent of the steam cycle.
Additionally, proper O&M practices can reduce heat rates by approximately 30 to 70 Btu/kWh (-0.3 to
0.7 percent of the steam cycle) for a cost of $30,000 annually, and feed pump rebuilds can improve the
steam cycle heat rates by 0.25 to 0.5 percent for costs of $250,000 to $350,000.62'63
As it relates to the steam system, there are several operational practices that can reduce the heat losses
within the system. Some of these methods are outlined as follows64:
• Minimize air-in leakage
• Clean HRSG heat transfer surfaces
• Improve water treatment to minimize HRSG blowdown
• Recover energy from HRSG blowdown
• Add/restore HRSG and steam plant insulation
• Optimize deaerator vent rate
• Repair steam leaks
• Minimize vented steam
• Ensure that steam system piping, valves, fittings, and vessels are well insulated
• Implement an effective team-trap maintenance program
• Isolate steam from unused lines
• Optimize condensate recovery
• Clean combustion turbine flow path components
Once-Through (Benson®) HRSG Technology
The use of a once-through (i.e., Benson®) HRSG 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 traditional HRSG. Instead, the feedwater is 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.
The Benson Technology is touted as "a proven process for large-scale steam generation in power plants
with the heart of this process being the once-through principle. Combined with sliding pressure
operation, this allows for highly efficient, flexible, and reliable power plant operation".65
62 Costs given in 2008 dollars.
63 Sargent & Lundy (2009). Coal-Fired Power Plant Heat Rate Reductions. SL-009597. Final Report. Accessed at
https://www.epa.gov/sites/default/files/2015-08/documents/coalfired.pdf.
64 Andover Technology Partners (2018). Improving Heat Rate on Combined Cycle Power Plants. Accessed at
https://www.andovertechnology.eom/wp-content/uploads/2021/03/C_18_EDF_FINAL.pdf.
65 https://www.siemens-energy.com/global/en/offerings/power-generation/power-plants/benson-technology.html;
https://assets.siemens-energy.eom/siemens/assets/api/uuid:b5c2c3b8-eb59-430b-8065-ba09d3 leb37b/flyer-benson-hrsg-
210920.pdf; and https://assets.siemens-energy.eom/siemens/assets/api/uuid:ef5fb27a-d2e0-4222-a0d0-2cd24146a937/neW"
benson-evaporator.pdf
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Advantages of the Benson Once-Through HRSG56:65
• It retains all the virtues of the proven natural circulation principle of drum-type boilers (i.e., flow
stability and uniform temperature distribution), yet at the same time replaces the high-pressure
drum with thin-walled components to improve operating flexibility.
• Significant shortening of plant startup time by allowing unrestricted combustion turbine startup.
• Increase of efficiency during startup by minimizing combustion turbine operation in part loads.
• Reduction of gaseous and liquid emissions through shorter startup process and elimination of
drum blowdown.
• Reduced consumption of chemicals through advanced feedwater treatment.
• Improved efficiency at high ambient temperatures due to adjustable evaporating point.
• Capability for higher steam parameters (pressure and temperature) because there are no
limitations through natural circulation.
Drum-type HRSG
BENSON® Once-Through
Drum
Su perheater
• Thick-walled
HP drum limits
operating
flexibility due
to high thermal
stresses
• Natural
circulation
principle
Evaporator
• Eliminates HP
drum, thereby
enhancing
operating
flexibility
• Maintains
natural
circulation flow
characteristics
Superheater
Evaporator
The BENSON® system - Elimination of thick-walled components
Figure 6: From Siemens "BENSON® Oncf-Through Heat Recovery Steam Generator"
BROCHURE, PG. 3 (2006)
The Use of Supercritical Steam Conditions
66 https://www.siemens-energy.com/global/en/offerings/power-generatioii/power-plants/benson-teclmology.html |
https://assets.siemens-energy.eom/siemens/assets/api/uuid:b5c2c3b8-eb59-430b-8065-ba09d3 leb37b/flyer-benson-hrsg-
210920.pdf: and https://assets.siemens-energy.com/siemens/assets/api/uuid:ef5fb27a-d2e0-4222-a0d0-2cd24146a937/new-
benson-evaporator.pdf
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Combined cycle EGUs typically have HRSGs that operate at subcritical steam conditions. 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). In contrast to a subcritical steam
generator, a supercritical steam generator operates at pressures above the critical pressure—3,200 psi
(22 MPa). Combustion turbine engines larger than approximately 200 MW typically have exhaust
temperatures high enough to support the use of supercritical steam conditions. However, the steam
turbine in combined cycle configurations where one turbine engine is paired with a steam turbine (1-1
configuration) is smaller than typical EGUs using supercritical steam conditions. Steam turbine sizes in
combined cycle configurations where two or three large turbines are paired with a single steam turbine
(2-1 or 3-1 configuration) are as large as typical EGUs using supercritical steam conditions.
Thermodynamic modeling has been applied to assess the potential of using supercritical steam as the
working fluid in the HRSG. One study suggests that using a supercritical steam once-through HRSG
will increase steam power by 5 percent when compared to using a subcritical steam HRSG. Since the
steam turbine typically makes up approximately one-third of the overall output of a combined cycle
EGU, if a combined cycle EGU were designed to use supercritical steam conditions in the high-pressure
portion of the steam turbine, it would reduce overall fuel use by 2 percent.67 Another study analyzed the
improvement of a 3PRH combined cycle EGU when using supercritical steam as opposed to subcritical
steam. It indicates that if using supercritical steam as the working fluid for the HP turbine, it is possible
to obtain a plant efficiency of 64.45 percent and capacity of 1.214 GW power output, compared to 63.08
percent and 1.19 GW when using subcritical steam. Additionally, the economic analysis predicts that
plants can return up to an additional $14 million per year when considering the difference between the
annual revenue from electricity sales and annual fuel costs when using supercritical steam.68
Another study compared the use of 2P and 3P cycles using subcritical and supercritical steam conditions
with and without steam reheat. The results followed the patterns such that efficiency increased from 2P
to 3P, from non-reheat to reheat, and from subcritical to supercritical. The analyses were conducted on a
Siemens V94.3 combined cycle gas combustion turbine, and the findings are outlined in Figure 7.69
Figure 7: Result of Thermodynamic Analysis of Siemens V94.3 Combined Cycle Gas
Combustion Turbine Efficiencies1691
IIRSC Cycle
1 IIMVessure (b:ir)''
Not LI IV Com hi nod
Cycle KITiciencv (%)
Uoliilno Combined
Cvclo KITicicncy
Incroiiso (%)
2PNR
80
53.6
-
2PRH
140
54.0
0.75
3PNR
100
54.1
0.93
3PRH
140
54.6
1.87
67 Alobaid, Falah & Strohle, Jochen & Epple, Bernd & Kim, Hyun-Gee (2009). Dynamic simulation of a supercritical once-
through heat recovery steam generator during load changes and start-up procedures. Applied Energy, Elsevier, vol. 86(7-8),
pages 1274-1282, July. https://ideas.repec.Org/a/eee/appene/v86y2009i7-8pl274-1282.html.
68 Marcin Jamroz, Marian Piwowarski, Pawel Ziemia'nski, and Gabriel Pawlak (2021). Technical and Economic Analysis of
the Supercritical Combined Gas-Steam Cycle. Energies 2021, 14, 2985. https://www.mdpi.com/1996-1073/14/ll/2985
69 Bolland, Olav (1990). A Comparative Evaluation of Advanced Combined Cycle Alternatives. American Society of
Mechanical Engineers (ASME). https://doi.org/10.1115/90-GT-335.
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2PRH - Supercritical
250
54.6
1.87
3PRH - Supercritical
260
55.1
2.80
a Pressures are provided as "reasonable" choices for each HRSG cycle type
While combined cycle efficiencies are routinely above 55 percent on a higher heating value (HHV)
basis, the result of the Bolland (1990) study still carries important implications for the comparisons of
2PNR, 3PNR, and 3PRH HRSGs. Additionally, it's useful to compare the three HRSG types with
subcritical and supercritical steam as the working fluid. As shown in Figure 3, the use of supercritical
steam appears to be an important option for increasing efficiency, with the efficiency of a dual-pressure
supercritical reheat HRSG being equal to that of a triple-pressure reheat.
The Use of Alternate Working Fluid
In addition, alternate working fluids—such as organic fluids, supercritical CO2 (SCO2), or
ammonia/water mixtures 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.70 While the use of SCO2 as the working fluid in a
Rankine cycle is of most interest for nuclear and coal-fired EGUs, it also has the potential to improve
the overall efficiency of combined cycle EGUs.71 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 reheat cycle 72 However, a HRSG using SCO2 has the potential to
improve the efficiency of combined cycle EGUs compared to triple-pressure steam with a reheat cycle
as well.73
The potential of SCO2 has been assessed in multiple studies. One study found that SCO2 potentially has
the advantages of being more compact and higher efficiency compared to steam-based combined cycle
technology. Additionally, when including O&M costs, calculations demonstrated that SCO2 can provide
levelized cost of electricity (LCOE)74 advantages as well. When comparing different steam turbine
70 The Kalina Cycle® is another cycle that has the potential for efficiency gains compared to a water-based Rankine cycle.
See http://www.kalinapower.com/technologyA
71 Patel, S. (2021b, October 27). The POWER interview: Pioneering STEP supercritical carbon dioxide demonstration ready
for 2022 commissioning. Power, https://www.powermag.com/the-power-interview-pioneering-step-supercritical-carbon-
dioxide-demonstration-readying-for-2022-commissioning/?oly_enc_id=3025B2625790F2W.
72 Using the design HRSG efficiencies listed in Gas Turbine World and the efficiency of the design efficiency of the Echogen
supercritical EPS100 heat recovery system (24 percent net, https://www.echogen.com/our-solution/product-series/epslOO/),
the median decrease in design heat rates for replacing dual pressure HRSG with supercritical CO2 HRSG is 7 percent.
73 Thanganadar, D., Asfand, F., & Patchigolla, K. (2019). Thermal performance and economic analysis of supercritical
carbon dioxide cycles in combined cycle power plant. Applied Energy, 255(1), 113836.
https://doi.org/10.1016/j.apenergy.2019.113836i
74 Levelized cost of electricity (LCOE) is defined as the price at which the generated electricity should be sold for the system
to break even at the end of its lifetime. LCOE is a good indicator of cost-effectiveness, because it can be calculated without
requiring for assumptions about the price at which the electricity can be sold to the grid or to an end user, as is the case when
calculating the payback period or the net present value. LCOE is an indicator that can be used to compare different
technologies, without any framework conditions affecting the assessment. With the use of LCOE, the financial viability in
specific conditions can be indicated by just comparing directly the LCOE with the price at which electricity could be sold.
PapapetrouM., Kosmadakis G. (2022). Salinity Gradient Heat Engines,
https://www.sciencedirect.com/topics/engineering/levelized-cost-of-electricity.
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models, the LCOE decreased by an average of 15 percent when using SCO2 versus subcritical steam.75
Another study modeled the performance of SCO2 steam use versus 2PNR and 3PRH alternative HRSG
use. It found that when compared to steam for bottoming cycles for 2PNR, SCO2 as a working fluid has
significantly reduced exergy losses at pressures above 200 bar, resulting in better performance.
However, when compared to 3PRH, assuming high SCO2 expander and pump isentropic efficiencies at
95 percent, the maximum pressure of the SCO2 cycle needs to exceed 300 bar to outperform 3PRH steam
cycles.76
The DOE's National Energy Technology Laboratory (NETL) is working on improvements to a SCO2
power cycle.77 One pilot power plant was recently completed that uses SCO2 technology.78 In 2018,
Southwest Research started building a Supercritical Transformational Electric Power (STEP) pilot plant,
which will use SCO2 technology with a design capacity of 10 MWe. It is estimated that replacing water
with SCO2 increases the efficiency by up to 10 percent. Additionally, STEP turbomachinery can be one-
tenth the size of a conventional power plant's components, providing potential to lower environmental
footprint and construction costs of new facilities.79 NETL conducted a study on the use of SCO2 in coal-
fired power plants that indicates a SCO2 power cycle can achieve higher efficiencies than a pulverized
coal (PC)/Rankine systems using supercritical steam conditions with no increase of cost of electricity.80
Another report by Echogen compared the use of SCO2 as the Rankine Cycle working fluid to that of a
steam-based Rankine Cycle system. Echogen claims its EPS 100 has up to 40 percent lower install cost
per kilowatt than that of a comparable dual-pressure steam system utilizing GT-PRO/PEACE. The
install cost largely results from the smaller installation footprint and simplicity of the SCO2 system. The
lower install costs contribute to a 10 to 20 percent lower LCOE of the EPS 100 system compared to that
of traditional dual-pressure HRSGs.81 In Canada, Siemens Energy and TC Energy agreed to build a
waste-heat-to-power facility using the EPS 100 technology. Commissioned in 2022, the facility captures
waste heat from a combustion turbine and converts it into power using a SCO2 power cycle.82
Ammonia/water mixtures can be utilized as a working fluid through the Kalina cycle. Depending on the
application, the Kalina cycle can improve power plant efficiency by 10 to 50 percent over the Rankine
75 Held, T (2015). Supercritical CO2 for Gas Turbine Combined Cycle Power Plants. Echogen Power Systems. Power Gen
International, December 8-10, Las Vegas, Nevada.
https://www.echogen.eom/_CE/pagecontent/Documents/Papers/Supercritical%20C02%20Cycles%20for%20Gas%20Turbin
e%20Combined%20Cycle%20Power%20Plants.pdf.
76 Huck, Pierre, Freund, Sebastian, Lehar, Matthew, & Peter, Maxwell (2016, March 28-31). Performance comparison of
supercritical C02 versus steam bottoming cycles for gas turbine combined cycle applications. GE Global Research. The 5th
International Symposium - Supercritical C02 Power Cycles,
http://sco2symposium.com/papers2016/SystemConcepts/092paper.pdf.
77 https://netl.doe.gov/project-information?p=FE0028979
78 https://www.swri.org/press-release/step-10-megawatt-supercritical-carbon-dioxide-pilot-plant-building
79 Southwest Research Institute (SwRI) (2022). Supercritical Transformational Electric Power Pilot Plant.
https://www.swri.org/industry/advanced-power-systems/supercritical-transformational-electric-power-pilot-plant.
80 NETL (2019). Supercritical Carbon Dioxide (Sco2) Cycle As An Efficiency Improvement Opportunity For Air-Fired Coal
Combustion. Accessed at https://www.osti.gov/servlets/purl/1511695.
81 Persichilli, M., Kacludis, A., Zdankiewicz, E., Held, T. (April 2012). Supercritical CO2 Power Cycle Developments and
Commercialization: Why SCO2 can Displace Steam. Echogen Power Systems LLC. Accessed at
https://www.echogen.com/_CE/pagecontent/Documents/Papers/why-sco2-can-displace-steam.pdf.
82 Power Magazine (2021). First Commercial Deployment of Supercritical C02 Power Cycle Taking Shape in Alberta.
Accessed at https://www.powermag.com/first-commercial-deployment-of-supercritical-co2-power-cycle-taking-shape-in-
alberta/.
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cycle.83 As plant operating temperatures are lowered, the Kalina cycle experiences a higher increase in
relative gain in comparison to the Rankine cycle. Advantages for the Kalina cycle include lower upfront
capital costs, lower demand for cooling water and cooling infrastructure, minimal maintenance
downtime, and minimal required supervision. A study found that the use of ammonia water instead of a
steam only cycle increased the efficiency of the system from 57.5 percent to 62.5 percent, while the cost
of electricity marginally increased from $0.06718/kWh to $0.06723/kWh.84 A study on a system with
intercooling, a triple-pressure reheat HRSG, and ammonia/water cycle at each pressure level produced a
minimum cost of electricity production of 0.06723 $/kWh. The same system obtained a 62.5 percent
maximum value of efficiency, a second law efficiency of 60.7 percent, and a maximum work output of
1,789.39 kJ/kg of air.
The Use of Thermoelectric Materials
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 (Bi2Te3), 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.85'86 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.
Currently, optimizing thermoelectric generation (TEG) power output and efficiency very dependent on
thermoelectric (TE) material properties and dimensions. Currently, TE materials are based on the use of
tellurium and germanium, which are expensive elements. Consequently, development of polymer,
silicide, oxide, and tetrahedrite TE materials are being explored. Challenges of commercial TEG are
mainly the materials development and systems engineering.87
However, the potential of TEG utility has been studied and shown promising results. On a study of a
ship's waste heat recovery, it was concluded that a TEG-organic Rankine cycle (ORC) method increased
the waste heat utilization rate while reducing power generation costs. Results show that for a TEG/O RC
bottoming cycle ratio of 0.615, the output power, thermal efficiency, and generation costs of the TEG-
ORC combined cycle experimental system were estimated to be 134.50 W, 6.93 percent, and 0.461
83 Kalina Power (2015). Technology: Kalina Cycle. Accessed at http://www.kalinapower.com/technology/.
84 Maheshwari, M., Singh, O. (2020). Thermo-economic analysis of combined cycle configurations with intercooling and
reheating. Accessed at https://www.sciencedirect.com/science/article/pii/S0360544220311567.
85 Electricity can also be generated from electrochemical reactions at different temperatures and pressures, See
https://jtecenergy.com/technology/. In addition, thermogalvanic cells use temperature differences to generate an electric
current. (See e.g., Yuan)
86 Yuan Yang, et al. (2014). Charging-free electrochemical system for harvesting low grade thermal energy.
https://www.pnas.0rg/c0ntent/l 11/48/1701L
87 LeBlanc, S. (2014). Thermoelectric generators: Linking material properties and systems engineering for waste heat
recover applications. Sustainable Materials and Technologies. Volumes 1-2, Pages 25-35.
https://doi.0rg/lO.lOl6/j.susmat.2Oi4.ll.OO2.
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$/kWh, respectively.88 Another study showed the promise of bismuth-telluride-based thermoelectric
micro-generators ([j,-TEGs) when it found that a power output of 5.5 [j,W per thermocouple can be
generated under a temperature difference of only 5 K.89 The findings of these studies are indicative of
TEGs potential to increase energy efficiency of combustion turbines.
88 Kiu, C., Ye, W., Li, H., Liu, J., Zhao, C., Mao, Z., & Pan, X. (2020). Experimental study on cascade utilization of ship's
waste heat based on TEG-ORC combined cycle. International Journal of Energy Research, https://doi.org/10.1002/er.6083.
89 Oualid, S. E., Kosior, F., Dauscher, A., Candolfi, C., Span, G., Mehmedovic, E., Paris, J., & Lenoir, B. (2020). Innovative
design of bismuth-telluride-based thermoelectric micro-generators with high output power. Energy & Environmental
Science. Issue 10. https://pubs.rsc.org/en/content/articlelanding/2020/EE/D0EE02579H .
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Combined Cycle Startup Times
Improving startup time of combined cycle EGUs makes combined cycle EGUs a more dependable
power source for load-following supply, and research/practice suggests several ways to improve
combined cycle startup times. Combustion turbines operating as EGUs in a combined cycle system have
historically been designed to operate for extended periods of time at steady loads. Since these combined
cycle EGUs were not intended to start and stop on a regular basis, they had relatively long startup times
depending on unit-specific factors and whether startup was initiated from a cold, warm, or hot state.
During the past decade, the demands placed on this conventional mode of steady, base load operation
have changed. The latest combined cycle EGUs are designed with advanced technology and features to
be more flexible and respond faster to increased demand for reliable electricity, support increased
generation from intermittent sources {i.e., renewables), capitalize on financial incentives to improve
dispatch or supply non-spinning reserves, operate at higher efficiencies, and emit less pollution. As a
result, advanced fast-start, combined cycle EGUs incorporate multiple techniques that allow the EGU to
start and stop faster, cycle output faster, and maintain higher part-load efficiencies than previous
designs.
Several combustion turbine manufacturers market complete combined cycle systems that can ramp up to
full load from a cold start in less than an hour, depending on unit-specific factors. Advanced combustion
turbines, when isolated from the HRSG and steam turbine, can reach full load at full speed as a simple
cycle {i.e., Brayton) unit in less than 20 minutes.90 When adhering to some of the following fast-start
techniques, the HRSG, steam turbine, and balance of plant equipment can reach safe operating
temperatures and pressures and begin generating additional electricity within 30 to 45 minutes of
ignition of the combustion turbine. Techniques that can be used to reduce startup times for combined
cycle systems are discussed below.
Slower startup times of combined cycle EGUs are largely attributed HRSGs needing a slower and more
gradual startup to reduce thermal stress in the HRSG thick-walled components, such as steam drums.
During startup, a temperature gradient will exist between the inside and outside of a steam drum, leading
to damage of the steam drum if not properly managed.91 However, because the slow startup of the full
combined cycle is limited by the HRSG, the combustion turbine can startup and begin producing power
if the combustion turbine exhaust gas is properly managed.
One option is to employ a bypass damper to reduce the amount of exhaust gas passing through the
HRSG as it warms up. The damper blocks the natural draft of cooler, ambient air back through the
HRSG stack. Another practice to maintain temperature is to insulate the HRSG stack.92 Keeping critical
elements of the HRSG in a warm or hot state following shutdown is an important technique for reducing
startup times. Reducing the exhaust gas passing through the HRSG allows for the steam turbine to ramp
up to full power without jeopardizing the thick-walled components within the HRSG.93
90 Gulen, S.C. (2013). Gas Turbine Combined Cycle Fast Start: The Physics Behind the Concept. Accessed at
http://www.mcilvainecompany.com/Decision_Tree/subscriber/Tree/DescriptionTextLinks/Physics.pdf.
91 Power Magazine (2013). Fast-Start HRSG Life-Cycle Optimization. June 1, 2013. Accessed at
https://www.powermag.com/fast-start-hrsg-life-cycle
92 Eddington, et al. (2017). Fast start combined cycles: how fast is fast?. Accessed at https://www.power-
eng.com/emissions/fast-start-combined-cycles-how-fast-is-fast/#gref.
93 Kim, T. S., Lee, D. K., Ro, S. T. (2000). Analysis of thermal stress evolution in the steam drum during start-up of a heat
recovery steam generator. Applied Thermal Engineering. https://doi.org/10.1016/S1359-4311(99)00081-2.
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Additionally, a bypass stack allows the exhaust energy from the combustion turbine to be decoupled
from the heat recovery unit and steam turbine generator. The bypass allows the combustion turbine
engine—the fastest-starting component of a combined cycle system—to operate independent of the
HRSG and come to partial or full load as a simple cycle EGU at a faster ramp rate. Documented start
times range from approximately 10 minutes94 for a hot start to approximately 15 to 20 minutes for a
warm start and to approximately 20 to 25 minutes for a cold start.95 The HRSG, steam turbine generator,
and balance of plant piping and equipment can then be slowly brought to temperature while the
combustion turbine engine operates at high load.96 The use of preheaters to gradually warm major steam
lines can add significant time to startup procedures.97
During a conventional startup, combined cycle turbines hold at low load for an extended time to
gradually warm the HRSG and steam turbine generator components and prevent thermal stresses that
can reduce the lifespan of the equipment. The elimination of this long hold is key to a fast start and may
be possible with a bypass stack and a modulated damper that can control the amount of exhaust heat and
flow that control the steam production rate and temperatures that reach the HRSG.98 Fast-start, advanced
class combined cycle designs may include a HRSG capable of tolerating rapid changes in temperature
and flow of high-temperature exhaust generated by rapidly ramping the turbine.
Additionally, the startup time of a HRSG is largely dependent on how warm the system is already {i.e.,
warm start vs. cold start). Maintaining warm conditions for the HRSG after shut down can result in
faster startup times when ramping back up. One option to do this is with cascaded latent heat storage
(CLHS), which can deploy stored thermal energy to keep the HRSG warm.99 Note that startup times to
reach full load can be significantly faster for hot startups compared to cold startups. One estimate
indicates that the duration of startup for cold, warm, and hot combined cycle plants averages around
147.5, 117.5, and 50 minutes, respectively.100 Thus, there is incentive to keep the HRSG warm when
feasible.
Purge Credit
This technique involves an EGU receiving credit for a mandatory purging of the fuel systems during
shutdown and adding isolation valves in the fuel supply system. This purge of residual fuel from the
combustion system with fresh, ambient air is necessary to remove excess combustible fuels in the unit
94 Pasha, A. (1992). Combined Cycle Power Plant Start-up Effects and Constraints of the HRSG. Proceedings of ASME
Turbo Expo, 1992. Power of Land, Sea, and Air. https://doi.org/10.1115/92-GT-376.
95 GE (2016). Startup time reduction for Combined Cycle Power Plants. Accessed at https://etn.global/wp-
content/uploads/2018/09/Startup_time_reduction_for_Combined_Cycle_Power_Plants.pdf.
96 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.
97 Eddington, et al. (2017). Fast start combined cycles: how fast is fast?. Accessed at https://www.power-
eng.com/emissions/fast-start-combined-cycles-how-fast-is-fast/#gref.
98 Gulen, S.C. (2013). Gas Turbine Combined Cycle Fast Start: The Physics Behind the Concept. Accessed at
http://www.mcilvainecompany.com/Decision_Tree/subscriber/Tree/DescriptionTextLinks/Physics.pdf.
99 Li, D., Hu, Y., Li, D., Wang, J. (2019). Combined-cycle gas turbine power plant integration with cascaded latent heat
thermal storage for fast dynamic responses. Energy Conversion and Management.
https://doi.Org/10.1016/j.enconman.2018.12.082.
100 Decoussemaeker, P., Nagasayanam, A., Bauver, W. P., Rigoni, L., Cinquegrani, L., Epis, G., Donghi, M. (2016). Startup
Time Reduction for Combined Cycle Power Plants. The Future of Gas Turbine Technology. 8th International Gas Turbine
Conference. Accessed at https://etn.global/wp-content/uploads/2018/09/STARTUP-TIME-REDUCTION-FOR-
COMBINED-CYCLE-POWER-PLANTS.pdf.
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and lower the risk of fire. During a conventional combined cycle startup, this purge takes place prior to
ignition, which increases start times, reduces efficiency by decreasing the temperature of the HRSG, and
increases thermal fatigue on the units. Generating purge credits during shutdown allows fast-start EGUs
to start up without a purge.
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