p.1 

OAR Box 1781 

Prepped by Ollie Stewart 

Document Number: 

31)11-1-23 

Docket Number: 

A-90-37 

Printed 10/29/2008 10:46:19 AM Sheet 31 of 142 
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<NOTE changes to the lO/STntecommendation are give in italics> 

NESCAUM STATIONARY SOURCE COMMTTTEE 

RECOMMENDATION ON EMISSION LIMITS FOR COMBUSTION TURBINES 

Draft 

April 1991 

Applicability: Smple or combined cycle combustion turbines, operating more than 2500 

hrs/yr. A recommendation on simple cycle turbines operating less than 2500 hours is 

available from NESCAUM. 

All emission limits in ppmv reflect dry basis, corrected to 15% oxygen and ISO conditions. 

I. Nitrogen Oxide Emission Limits 

A. 1 MMBtu/hr to 1(X) MMBtu/hr (note 1) 

Gas use 30 ppmv (note 2) 

Oil use 50 ppmv (note 2) 

B. Greater than 100 MMBtu/hr (note 1) 

Gas or oil as primary fuel 9 ppmv (notes 2 and 3) 

Limits different from these may be considered if an applicant proposes an 

advanced or innnovative combustion technology 

Gas primary fuel with oil back-up fuel in use 

9 ppm for gas (notes 2 and 3) 

18 ppm for oil (notes 2 and 3) 

25 ppmv without an SCR system 

It is possible that higher NOx limits for oil will be considered with 

corresponding decreases in NH3 slip. 

II. Carbon Monoxide Emission Limits 

A. Less than 100 MMBtu/hr 50 ppmv 

B. 100 to 400 MMBtu/hr 25 ppmv 

C. Greater than 400 MMBtu/hr 10 ppmv 

With high levels of water or steam injection, states may require oxidation catalysts 

to attain these emission limits. 

IU. Ammonia Emission Limit 

Ammonia emissions or "slip" from an advanced nitrogen oxide control system 

should be maintained below 10 ppmv unless this emission limit is shown to be 

inappropriate. 

Committee Draft 1 4/16/91 
P.3 

effective as steam for NOx control and results in relatively higher CO emissions, for the 

same water to fuel ratio and, therefore, the use of water injection must be justified. 

This guideline includes a recommendation for higher CO limits for smaller turbines. 

For example, the smaller frame combustion turbines (<10 MW) which can meet the NOx 

guideline by water (steam) injection would be recommended to meet a 50 ppmvd CO limit 

for economic reasons and avoid a CO catalyst. However, aircraft derivative turbines 

generally require a CO catalyst whether or not SCR fuel gas treatment is used. Intermediate 

size machines (10-40 MW) are being recommended to meet an intermediate CO limit 

<which has been deemed feasible based on ?what evidence>. (ref-NJ turbine guidelines?> 

V. Ammonia Use (1.2.8) 

The Stationary Source Committee is concerned about releases of ammonia from 

NOx control systems for two reasons. First, individual state permitting programs may 

require an analysis of ammonia use and the potential for releases. Second, if an agency 

determines that a project requires a PSD permit, then the June 1986 North County PSD 

remand in Region 9 (6) requires that the toxic effects of ammonia be included in the review. 

These hazards can be largely avoided by the use ofaquaeous ammonia. 

There are two basic processes.thermal and catalytic, for using ammonia injection to 

control nitrogen oxide emissions from lean bum combustion equipment such as gas 

turbines. The thermal process (SNCR) is effective only at temperatures greater than 

approximately 1400°F although enhancers are being developed to allow operation at turbine 

exhaust temperatures. This is higher than normal gas turbine exhaust temperatures of 

approximately 1000°F and is achievable only by reheating the gas turbine exhaust in a 

device such as a duct burner. The catalytic process, SCR, operates in an optimum 

temperature window of approximately 650-850°F, a range which is normally achieved by 

cooling gas turbine exhaust in a heat recovery boiler. Catalysts are being developed to 

allow SCR operation at variable exhaust temperatures.(ref.?) 

In either process, some unreacted ammonia passes through to the atmosphere. This 

unreacted ammonia is commonly referred to as ammonia "slip." Typically, the amount of 

ammonia slip can vary from nearly "0" (dry basis corrected to 15% oxygen), in a well 

controlled stable system with moderate conversion efficiency (less than 90%), to 30 ppmv 

or more in systems requiring very high conversion efficiencies or in poorly controlled or 

highly variable systems. Since at this time, the SCR process is much more prevalent and is 

readily adaptable to gas turbine exhaust conditions, the focus here is on ammonia slip from 

SCR controlled gas turbine emissions. 

In the SCR process, the overall chemical reaction requires a theoretical molar ratio 

of NH3:NC>2 of 1:1, although the reaction is complex because of the varying oxidation 

numbers of the different oxidized species of nitrogen present in the exhaust gas being 

treated. However, as is the case in many chemical reactions, the law of mass action 

requires an excess of the reagent, NH3, to drive the reaction if high conversion efficiency is 

desired. Also, operating the SCR ammonia injection system at its theoretical limit is not 

practical due to imperfect mixing, local variations of concentrations in the reactor, and other 

factors. In practice, some amount of unreacted ammonia slip must be tolerated in the 

exhaust gas. Catalyst manufacturers wish to operate at 20% excess ammonia, which 

corresponds to approximately 30 ppmv slip. Some of the factors that influence the amount 

of slip are: 

1. control system lag and imperfect operation of instrumentation, continuous emission 

monitor problems, etc. 

Committee Draft 6 4/16/91 
P.4 

»A 

2. high temperature "hotspots" favoring oxidation of NH3 

3. low temperature areas resulting in incomplete or slow reactions 

4. variations in NH3 and NOx concentration across the duct 

5. incomplete mixing of ammonia widi the exhaust gas 

6. conversion of nitrogen to ammonia 

7. variations in the quantity of exhaust gas due to load changes and sluggishness in 

achieving a new equilibrium set point in the control system. 

In many gas turbine applications, the trade-off for the reduction in NOx emissions 

may be the substitution of an equivalent amount of ammonia emissions. For example, a 

typical water-injected turbine may reduce NOx to 50 ppmv and an add-on SCR unit would 

reduce NOx to 9 ppmv. However, the exhaust gas may contain 10 ppmv ofNHj. 

As of August 1988, diree SCR controlled gas turbines in New Jersey have been 

permitted for maximum allowable ammonia emissions of 20-30 ppmv. An odor threshold 

for ammonia of 20 ppmv is supported by a review of the literature( 10,11). High 

conversion efficiencies (greater than 90%) and variable exhaust conditions typically result 

in ammonia slips of 20-30 ppmv. At a lower conversion efficiency (less than 90%) and 

stable operation, a 10 ppmv slip appears is an achievable objective for SCR systems. In 

situations involving high conversion efficiencies, variable loads, or poorly responding 

control systems, an add-on ammonia decomposition catalyst may be needed to meet this 

limit. This recommendation states that ammonia slip from an advanced nitrogen oxide 

control system should be maintained below 10 ppmv unless this emission limit is shown to 

be inappropriate. Japanese and European SCR projects are reportedly achieving 5 ppm. 

(ref) 

VI. Cost of Controls 

As of August 1988, gas turbine installations using SCR systems have been 

approved in the northeast for an industry standard small gas turbine (the GE LM-2500, a 

21 MW unit) and a industry standard large turbine (the GE Frame 6, a 55 MW unit). 

<should this be changed to the list developed by McVay and Seidmanfor AWMA?> These 

permits indicate that, in some cases, the cost-effectiveness for advanced NOx control 

systems is considered "reasonable" compared to other NOx controls being considered by 

the agencies. 

The NESCAUM Stationary Source Committee developed a BACT Guideline, 

which was approved by the NESCAUM Board of Directors on October 11,1988 (3). The 

purpose of this document is to promote consistent agency analysis of control technologies 

during BACT reviews. It is also intended to provide prospective applicants with guidance 

on conducting a BACT analysis. The document includes a discussion of cost calculations. 

For all turbine projects, an analysis of the cost of control options using a basis of dollars 

per ton of pollutant controlled should be conducted for each pollutant subject to BACT. 

This should be calculated using the total cost of the control technology system(s) divided 

by the total amount of controlled emissions, not just the incremental cost of any advanced 

emission control systems. A copy of the BACT Guideline is available from NESCAUM. 

Combustion turbine emission control alternatives which should be considered (not 

necessarily in this order) are: 

1. Low NOx combustor 

2. Increased steam injection with CO catalyst 

3. SCR 

4. Dual function catalyst (NOx and CO). 

Committee Draft 7 4/16/91 
P.5 

VII. Advanced Combustion Control 

Since October 1988, there have been advances in combustion control and for some 

turbines N0X exhaust concentrations of approximately 12 ppmvd at 15% oxygen are 

reported to be achievable with bw N0X combustors and steam or water injection. Also, 

SCR use on gas turbines has increased. All new or significantly modified projects with 

heat input over 100 million BTU's per hour should include a control technology analysis to 

consider turbines with advanced combustion control technology, water injection and SCR. 

The NESCAUM states do not mandate tail gas treatment processes which involve 

ammonia injection if low emissions can be achieved by other means such as combustion 

control. One reason is that anhydrous ammonia is classified as a hazardous substance in 

some states. Unless significant emission reductions are achieved, the NESCAUM states 

are reluctant to mandate any technology which may present risk of catastrophic accident 

even if an acceptable risk management program can be incorporated. These processes 

result in unreacted ammonia (slip) which offset the N0X reduction. Therefore, the 

NESCAUM states may consider 15 ppm N0X without SCR to be equivalent to 9 ppm N0X 

and 10 ppm ammonia (slip) with SCR, assuming natural gas is used as the primary fuel. 

Nevertheless, if the project is affected by the PSD regulations or is greater than 100 million 

BTU per hour heat input, a thorough evaluation of SCR, low N0X combustion, and other 

available methods capable of achieving N0X emissions lower than 25 ppm, should be 

evaluated in permit applications. 

The Committee is aware that several combustion gas turbine manufacturers are 

presently developing dry or wet (water or steam injection) low N0X combustors. These 

machines may be able to achieve an N0X emission level of 25 ppmv or less, for natural gas 

fuel, without installing an SCR system. For example, the NJDEP recently permitted two 

General Electric utility peaking turbines at 25 ppmv with natural gas fuel and water 

injection. These were the Frame 6 (40 MW) and Frame 7 (75 MW) size machines. 

General Electric is also developing a new combustor for the Frame 7 turbine capable of 

achieving 25 ppmv N0X without water injection and 11-13 ppmv N0X with water 

injection. 

The Committee is also aware of the following examples. The Pratt & Whitney 

division of United Technologies Inc. is developing a dry low N0X combustor for its model 

FT-8 (50 MW) gas turbine, that may be capable of achieving 25 ppmv with natural gas. 

Siemens Kraftworks Union model V84 (150 MW) is presently guaranteed at 25 ppmv N0X 

with a dry low combustor firing natural gas. Turbines will be available soon that are 

expected to achieve 10 ppmv. 

<ABB - Reggie to supply info; Bill K to get guarantees being offered> 

VIII. Conclusion 

The NESCAUM states are receiving and reviewing many applications for gas 

turbines which could represent large increases in NOx emissions. The Stationary Source 

Committee believes that turbines will be a significant new source of NOx emissions in the 

region. Their significance, combined with the need to identify control technologies for use 

in the a "top-down" BACT process, leads the Committee to recommend very stringent 

emission limits for these sources. The five technical and policy issues discussed above -

appropriate cutpoints for stringent NOx controls, intermittent oil use and catalyst life, 

ammonia use, cost of controls, and low NOx burners - can be resolved through appropriate 

design and operation of NOx control systems. In addition, advances in combustion 

controls may lead to low NOx levels without the use of catalysts. In order to meet the 

goals of the Clean Air Act of 1990, the NESCAUM region will need to achieve stringent 

Committee Draft 8 4/16/91 
P.6 

c. 

N0X controls on gas turbines and other stationary sources. Therefore, the states expect to 

follow the development of new control technologies and the ability to further lower 

permitted NOx emissions. 

Vm. Bibliography 

1. Champagne, D.L. January-February, 1988. SCR Cost Effective for Small Gas 

Turbines. Cogeneration. p.26-29. 

2. Heck, R.M. et al. 1987. Catalytic Air Pollution Controls-Commercial Development of 

Selective Catalytic Reduction for NOx. Technical Paper No. 87-52.3, Englehard 

Industries. Air Pollution Control Association. 

3. Northeast States for Coordinated Air Use Management October 1988. BACT 

Guideline. 

4. Potter, J. Craig. December 1987. U.S. Environmental Protection Agency, memo from 

J. Craig Potter to Regional Administrators I.- X. Improving New Source Review 

Implementation. 

5. Suyama, K. 1985. Operating Experience on SCR System for Steam Generators. 

Mitsubishi Heavy Industries, Ltd., Nagasaki Shipyard and Engine Works, 1-1 AkunouraMachi, Nagasaki, Japan,. 

6. Thomas, Lee M., Administrator, U.S. Environmental Protection Agency. June 1986. 

Remand to US EPA Region X. of PSD Appeal No*. 85-2. North County Resource 

Recovery Associates. 

7. U.S. Environmental Protection Agency. July 1987. New Source Performance 

Standards for Gas Turbines, Title 40 Code of Federal Regulations Part 60, Subpart GG, 

and Appendix A. 

8. Winkler, D.G. September 12,1985. Selective Catalytic Reduction and CO Oxidizer 

Process. ICS Cogeneration Workshop Series. Johnson Matthey, Inc. 

9. Yasuyuki Nakabayashi and Ribiya Abe. April 1986. Current Status of SCR in Japan. 

Research and Engineering Office, Thermal Power Development, Electric Power 

Development Company, Ltd., Tokyo, Japan 100. 

10. Documentation of the Threshold Limit Values and Biological Exposure Indices, 5th 

Edition, American Conference of Governmental Industrial Hygienists, Inc. 

11. Journal of Applied Toxicology. 1983 Vol 3, Number 6. P. 272-292 

<Any other updates to the bibliography? > 

This recommendation was approved by the NESCAUM Board of Directors on ? The 

recommendation will be reviewed every two years and revised where appropriate. 

turbrecmd-rev-91b 

Committee Draft 9 4/16/91