Combustion Turbine NOx Control Technology Memo
Final, Rev. 1
January 2022
Project 13527-002
Eastern Research Group, Inc.
Prepared by
Sargent & Lund\
55 East Monroe Street • Chicago, IL 60603 USA • 312-269-2000
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Combustion Turbine NOx Control
Technologies Memo
Sargent S Lundy
Project No. 13527-002
January 2022
LEGAL NOTICE
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This work was funded by U.S. Environmental Protection Agency (EPA) through Eastern Research Group, Inc. (ERG) as a
contractor and reviewed by ERG and EPA personnel.
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Combustion Turbine NOx Control
Technologies Memo
Project No. 13527-002
January 2022
Sargent S Lundy
Purpose
This report summarizes the available nitrogen oxides (NOx) control technologies available for natural gas
combustion turbines, including natural gas combined cycle (NGCC) and simple cycle facilities. These
technologies are generally divided into two categories: combustion controls and post-combustion
controls. Combustion controls reduce the amount of NOx generated in the turbine combustion process
and include water injection and dry and ultra-low NOx (ULN and DLN) systems. Post-combustion
controls remove NOx from the exhaust gas and includes selective catalytic reduction (SCR).
The following sections provide a brief background of NOx emissions, description of the technologies, a
summary of its applicability in various combustion turbines, a typical range of performance, and a cost
summary for a sample combustion turbine facility.
NOx Background
There are two mechanisms by which NOx is formed in turbine combustors; fuel NOx and thermal NOx.
Fuel NOx is formed by the reaction of nitrogen bound in the fuel with oxygen in the combustion air.
Natural gas typically does not have a high nitrogen composition; thus, fuel NOx is not the dominant
source of NOx in natural gas fired facilities. Thermal NOx formed by a series of chemical reactions in
which oxygen and nitrogen present in the combustion air dissociate and subsequently react to form NOx.
The major contributing chemical reactions occur in the high temperature area of the gas turbine
combustor and NOx formation increases with spikes in temperature and residence time.
There are several compounds that NOx represents, but NO and NO2 are the most prevalent compounds
found in combustion turbine exhaust. The use of duct firing in combined cycle facilities also adds to the
total amount of NOx emissions generated. The majority of emissions from combustion turbines at full
load are in the form of NO, however, NO is converted to NO2 in the atmosphere to form ozone (O3).
Additionally, the use of oxidation catalyst for carbon monoxide (CO) control can increase the NO2 ratio, by
oxidizing NO to NO2.
Water & Steam Injection
Description
Water and steam injection have been used since the 1970's as a means of controlling NOx emission from
combustion turbines. Inside the combustion turbine, fuel rich zones that create high flame temperatures
are the result of the simultaneous mixing of fuel and air and their subsequent combustion. Injecting water
or steam into the flame area of the combustor provides a heat sink that lowers the combustion zone
temperature and reduces thermal NOx formation. As noted earlier in the report, as the combustion zone
temperature decreases, NOx production decreases exponentially. Water used in this process must be of
high quality (e.g. demineralized water) to prevent deposits and corrosion from occurring in the turbine.
While many combined cycle facilities may have existing demineralized water treatment on site, existing
simple cycle facilities often do not. In those cases, there is the option to build or rent new water treatment
equipment or have high quality water delivered to site.
Water is more efficient for reducing the flame temperature than steam, as the energy required to vaporize
the water creates a larger heat sink. Generally, the steam flow required is 1.5-2 times the amount of
water required for given NOx reduction. Water and steam injection systems are designed to a specific
"water-to-fuel ratio" (WFR) which has a direct impact on the controlled NOx emission rate and is generally
controlled by the turbine inlet temperature and ambient temperature.
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Combustion Turbine NOx Control
Technologies Memo
Project No. 13527-002
January 2022
Sargent S Lundy
As combustion turbine designs are developed with higher firing temperatures to increase thermal
efficiencies, higher water injection rates are required to control NOx emissions. However, points are
reached where the amount of water and steam injected begins to create several design issues that must
be considered. As water is injected at higher rates to further reduce NOx emissions, the thermodynamic
efficiency of the combustion turbine will decrease, seen as an increase in heat rate, due to the energy
required to turn the water into steam; however, depending on the overall mass flow being added, there is
a potential to break even on total power generated. In addition, higher water and steam injection rates
can cause an increase in the dynamic pressure activity in the combustor which can cause wear and tear
within the combustion turbine. As the addition of water and steam creates thermodynamic inefficiencies
in the combustion process, higher levels of carbon monoxide production are commonly seen. The rate of
carbon monoxide production increases as the amount of water and steam injected increases. Overall,
water and steam injection create a dichotomy due to the need for facilities to inject higher water and
steam rates to meet lower NOx emission limits, exacerbating the problems associated with increased
injection.
Applicability and Typical Performance
Water injection is a well-established technology and modern technology can offer NOx emissions of
below 42 ppm (0.05 Ib/mmbtu), with the lowest practical emissions of 25 ppm (0.03 lb/mmbtu).1
Compared to other NOx emission control technologies, water injection may have a lower capital cost, but
higher variable costs. This makes water injection especially attractive for peaking combustion turbines or
other units that operate infrequently. It is most often applied to smaller frame turbines (e.g. GE LM series
of aeroderivatives), rather than the modern large-frame heavy duty turbines (>200 MW) that have been
installed since 2010; generally water injection has been superseded by other technology for combustion
based NOx control on heavy-duty turbines (see DLN section). The high variable cost is partly due to the
quality of water that is required for injection, which not every plant has excess capacity to meet, especially
simple cycle facilities, thus facilities with water limitations would not be well suited for water injection.
While there may be scenarios where water and steam injection would be more attractive than other
control technologies, injection can be added to both new combined cycle and simple cycle facilities, as
well as retrofitting existing units. This control method is one of the most historically used technologies to
reduce NOx emissions. In addition, water and steam injection can be combined with post combustion
control technologies such as SCR systems to further reduce NOx emissions.
Dry Low NOx (DLN) And Ultra-Low NOx (ULN) Burners
Description
DLN combustor technology premixes air and a lean fuel mixture prior to injection into the combustion
turbine that significantly reduces peak flame temperature and thermal NOx formation. Conventional
combustors are diffusion controlled where fuel and air are injected separately. Combustion occurs locally
at stoichiometric interfaces resulting in hot spots that produce high levels of NOx. In contrast, DLN
combustors generally operate in a premixed mode where air and fuel are mixed before entering the
1 GE Power Generation, Schorr, M. M., & Chalfin, J. (1999, September). Gas Turbine NOx Emissions
Approaching Zero - Is it Worth the Price? (GER 4172). General Electric Power Systems.
https://www.ge.com/content/dam/gepower-new/global/en_US/downloads/gas-new-
site/resources/reference/ger-4172-gas-turbine-nox-emissions-approaching-zero-worth-price.pdf
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Combustion Turbine NOx Control
Technologies Memo
Project No. 13527-002
January 2022
Sargent S Lundy
combustor. The underlying principle is to supply the combustion zone with a completely homogenous,
lean mixture of fuel and air. DLN combustor technology generally consists of hybrid combustion,
combining diffusion flame (for low loads) plus DLN flame combustor technology (for high loads). Due to
the flame instability limitations of the DLN combustor below approximately 50 percent of rated load, the
turbine is typically operated in a conventional diffusion flame mode until the load reaches approximately
50 percent. As a result, NOx levels rise when operating under low load conditions. For a given turbine,
the DLN combustor volume is typically twice that of a conventional combustor. ULN technology is a
further development of DLN technology that uses similar combustor designs to achieve enhanced fuel/air
mixing that allow for even further reduction in NOx emissions.
Applicability and Typical Performance
DLN and ULN systems are an attractive option for most combustion turbines due to the lower fuel
nitrogen content in natural gas. They offer the potential for substantial reduction of NOx from turbines, as
well as improved performance when compared to water injection. Depending on the frame size, these
systems can achieve baseline NOx emissions of 9-15 ppm (0.01 - 0.018 Ib/mmbtu) for DLN and as low
as 5 ppm (0.006 Ib/mmbtu) for ULN. However, the combustor design for DLN and ULN systems is
typically larger than conventional types, and space may not be available in older turbines for the upgrade.
DLN combustors also can be limited in wider operating ranges than conventional combustors. Gas
facilities that are expected to cycle on a regular my experience spikes in NOx emissions due to the nature
of how the technology performs at lower loads.
DLN / ULN capital costs vary with the size of the turbine and the specifics of the particular turbine being
retrofitted. Baseline NOx level will also significantly affect the estimate of cost per ton of NOx reduced.
DLN and ULN technologies are applicable to both combined cycle and simple cycle units, and are a
developing technology that is being included in new facilities design to help meet ultra-low emission
requirements along with being an attractive option for existing facilities that have the available space to
accommodate the upgraded combustors. Similar to water and steam injection systems, DLN and ULN
can be used in combination with post combustion technologies such as SCR to meet even lower emission
rates at the stack.
Selective Catalytic Reduction (SCR)
Description
Selective catalytic reduction (SCR) is the most widely used treatment for a gas turbine and typically
required on new installations as part of the Best Available Control Technology (BACT) evaluation results.
SCR is a process in which ammonia reacts with NOx in the presence of a catalyst to reduce the NOx to
nitrogen and water. The catalyst enhances the reactions between NOx and ammonia, according to the
following reactions, but must be within a specific temperature window:
2 NO + 2 NHs + 1/2 02 -» 2 N2 + 3 H2O
2 NO2 + 4 NH3 + O2 —> 3 N2 + 6 H2O
Note that for high NOx reduction, ammonia is typically injected at higher than a 1.0 stoichiometric ratio of
ammonia-to-NOx removed; this results in ammonia slip. Systems design is therefore balanced to ensure
NOx reduction is maximized while ammonia slip is minimized.
For an SCR system, multiple reagents may be used, including anhydrous ammonia, aqueous ammonia
(19% and 29%), and ammonia generated from urea conversion. This process requires additional
equipment to store, vaporize, dilute, and mix the reagent prior to being injected into the system through
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Combustion Turbine NOx Control
Technologies Memo
Project No. 13527-002
January 2022
Sargent S Lundy
the ammonia injection grid (AIG). The SCR reactor is located downstream of the combustion turbine
itself, and in the case of a combined cycle facility with a heat recovery steam generator (HRSG), it is
located within the tube banks at an appropriate temperature region. The typical temperature window for
this process is roughly 600-750°F. The most widely used SCR catalyst is formulated with titanium oxide
(TiCh) as a base substance and vanadium pentoxide (V2O5) as the active component. Other compounds,
such as tungsten oxide and silicon oxide, are added for strength or thermal resistance. Unlike with coal-
fired applications, the catalyst used is typically stacked vertically with gas flow horizontally through the
catalyst face, has a much smaller pitch due to the limited particulate and plugging concerns, and does not
deactivate as rapidly due to minimal catalyst poisons in the flue gas.
Applicability and Typical Performance
SCR systems are used throughout the power industry as a NOx control technology and developments in
catalyst technologies have allowed for broader implementation of the process. Almost all new
combustion turbine facilities, whether simple cycle or combined cycle, require an SCR system in
conjunction with a combustion technology (DLN or water/steam injection) in order to meet stringent NOx
emission rates. Based on data from the Clean Air Market Database (CAMD), 80% of combined cycle
facilities implement an SCR system compared to 10% of simple cycle units. A combination of SCR with
combustion control technologies can achieve levels as low as 2 ppm (0.002 Ib/mmtbu) of NOx with 2-5
ppm of ammonia slip, which is currently considered Lowest Available Emission Rate (LAER) for combined
cycle units.
Typically, SCR systems are installed in combined cycle applications downstream of the high-pressure
steam tubes section due to temperature impacts on the reaction process. However, developments in low
and high temperature SCR systems have made installations of SCR systems more widely possible. High
temperature catalyst (>800°F), which includes more precious metal composition, can be used on simple
cycle systems downstream of the turbine; however, in most applications, a reactor is built with tempering
air to utilize typical catalyst temperature composition.
Existing combined cycle facilities with SCR units in place that are looking to further reduce NOx emissions
need to understand available space inside their reactor for extra catalyst volume or activity. For combined
cycle facilities originally built without SCR, if extra space in the HRSG was not dedicated for the future
AIG and catalyst, it may be impossible to retrofit the facility with SCR. Simple cycles units looking to add
an SCR unit would see high costs as well due to either the use of a high temperature system that can be
placed immediately downstream of the combustion turbine, or a larger SCR reactor that would require
tempering air. Either way, duct or stack expansion is required to make an appropriate reactor with
decreased flue gas velocity through the catalyst.
As noted above, temperatures of the flue gas and in the SCR play a major role in performance.
Temperature requirements dictate the location of where an SCR system is placed within the duct path in
order to maintain efficiency of the reactions. Facilities that expect to operate at or near full load will have
constant temperatures along the flue gas path, however, cycling units will experience large temperature
swings of the flue gas decreasing the reaction kinetics inside the SCR. Below the catalyst design
temperature window (typically around 50-60% load), ammonia injection must cease, which may alter the
facility's ability to meet NOx emissions rate at low load. As such, the SCR system design temperature
typically dictates the minimum emission compliance load.
Other impacts to the existing facility operation with retrofitting an SCR would be impact to the overall
turbine backpressure. Adding a new catalyst bed can add around 4 in.w.c. of pressure drop to the
system, causing backpressure to the combustion turbine. This results in a nominal increase to the
performance and heat rate of the turbine.
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Combustion Turbine NOx Control
Technologies Memo
Project No. 13527-002
January 2022
Sargent S Lundy
Combustion Turbine Emission Control Summary
The following table provides a qualitative summary of the technologies described in the above sections
when reviewing its applicability towards new and existing facilities.
Table 1 - Control Technology Considerations
Control Technology
New Facilities
Existing Facilities (Retrofit)
Water/Steam Injection
- Common system installed
historically on small frame
turbines.
- Requires high quality water for
injection. Facility must have
available water treatment system.
- Due to higher operating costs /
lower capital, attractive option for
peaking or cycling operation.
- Can be used in conjunction with
SCR.
- Can be retrofitted to majority of
existing facilities (combined or
simple cycle).
- Similar water considerations.
- Similar operational
considerations.
Dry / Ultra Low NOx
- Common system installed in new
facilities.
- Can be used in conjunction with
SCR.
- Can be retrofitted to majority of
existing facilities, however,
turbine must have available
space for new combustors as
they are larger than
conventional type.
Selective Catalytic Reduction
- Common system installed in new
facilities, especially in HRSGs.
- Can be used in conjunction with
Water/Steam Injection or DLN /
ULN systems to achieve BACT or
LAER limits.
- Hard to retrofit on NGCC if
extra HRSG space was not
provided initially.
- Requires separate reactor for
simple cycle applications that
are very costly.
Sample Unit Cost Estimate Summary
To further evaluate the NOx reduction technologies described in the above sections, order of magnitude
costs were developed for two potential configurations: a sample simple cycle peaker SCR retrofit and a
sample NGCC SCR retrofit. The following section provides a cost summary of the technologies when
retrofitting an SCR system outlined in Table 2 below. Project costs account for direct costs of a complete
NOx control system along with general conditions, and project indirect costs. The cost estimate is based
largely on Sargent & Lundy LLC experience on similar projects. Detailed engineering has not been
performed, and specific site characteristics other than those listed in Table 2 were not taken into
consideration. The estimate includes but is not limited to the following scope;
• Direct Costs
o Material / Equipment and Labor
¦ Civil / Structural / Architectural
¦ Mechanical Equipment, Piping, Valves, Insulation
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Combustion Turbine NOx Control
Technologies Memo
Project No. 13527-002
January 2022
Sargent S Lundy
¦ Electrical equipment
¦ Instrumentation and controls
• General Conditions
o Additional labor costs, site overhead and other construction indirects
• Indirect Costs
o Engineering, construction management support, startup/commissioning, contingency.
Operating and maintenance (O&M) costs are also provided in Table 3. Costs are based on fixed costs
associated with labor and variable costs associated with utilities, water, reagents, and catalysts as
required for operation of the specific control system on an annual basis along with any performance
impacts to the plant output. The capacity factor of the facility is accounted for in the order of magnitude
cost.
Table 2 - Sample Unit Information
Parameter
Units
Example 1
Example 2
Facility Type
Simple Cycle
Combustion Turbine
Natural Gas
Combined Cycle
Output
MW
50 MW Turbine
90 MW Turbine
NOx Emissions
Ib/mmbtu
0.15
0.05
ppmvd @
15% 02
-40
-13
Capacity Factor
%
15 (during ozone
season)
65
Existing NOx Control
Water Injection
Steam Injection
Table 3 - Example 1 Order of Magnitude Cost Summary
Reference Case1
Control Technology
Project Cost2
Annual O&M Cost3
Example 1
SCR System
$16,000,000
$70,000
DLN/ULN
$2,500,000
$60,000
Water Injection
$5,000,000
$100,000
Example 2
SCR System
$6,200,000
$300,000
Notes:
1 - Costs based on a retrofit of the sample unit described in Table 2.
2 - Project Costs are overnight total project costs, including all project indirects. All costs are provided in 2021 dollars,
reference project cost information used as the basis was adjusted to 2021 dollars using on an escalation factor of 2.5% based
on the industry trends over the last ten years (2010 - 2020) excluding the current market conditions.
3 - O&M costs consider loss of power sales due to additional turbine back pressure along with aux power consumption,
reagent, and catalyst costs.
As shown in Table 3 above, an SCR system is expected to have the highest project cost of the three
evaluated technologies for simple cycle, with the DLN and Water Injection system capital costs being
much lower. Cost for the simple cycle SCR factors in a new stack, reactor casing, tempering air system,
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Combustion Turbine NOx Control
Technologies Memo
Project No. 13527-002
January 2022
Sargent S Lundy
and a reagent injection system, accounting for large capital items that are not necessary for DLN and
water injection. The cost for a NGCC SCR is much smaller, due to only including catalyst, AIG, and an
ammonia system; it is assumed that there is already additional space reserved within the HRSG for the
catalyst and AIG itself and that the flue gas velocity and temperatures are already appropriate for SCR
operation.
Table 4 below summarizes additional considerations when evaluating the capital and operating costs of
NOx reduction technologies that may have a large impact on the overall project.
Table 4 - Capital and Operating Cost Considerations
Control Technology
Capital Cost
Operating and Maintenance
Cost
Water / Steam Injection
May require an upgrade to the
water treatment system. Cost can
increase if a new water treatment
system is required.
Requires high quality water for
injection and continued
inspection and maintenance.
Dry / Ultra Low NOx
New combustors that must replace
existing conventional type. More
expensive than conventional
combustors.
General maintenance similar to
conventional combustors.
Selective Catalytic Reduction
Moderate incremental cost for
including in initial NGCC HRSG
design. High cost for simple cycle
systems to provide a separate
reactor.
Reagent supply, catalyst
replacement, and general
maintenance. Catalyst and
reactor pressure drop can
decrease turbine output.
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