Electric Power
Research Institute
&EPA
May 1995
EPRI/EPA1995 Joint Symposium
on Stationary Combustion
NOX Control
Book 1: Tuesday, May 16,1995
Sessions 1,2,3
Sponsored by
Electric Power Research Institute
Generation Group
Air Quality Control Program
U.S. Environmental Protection Agency
Air and Energy Engineering Research Laboratory
Combustion Research Branch
May 16-19, 1995
Hyatt Regency Crown Center
Kansas City, Missouri
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EPRI/EPA1995 Joint Symposium on Stationary
Combustion NOX Control
Book 1: Tuesday, May 16,1995
Sessions 1,2,3
May 16-19, 1995
Hyatt Regency Crown Center
Kansas City, Missouri
Prepared by
ELECTRIC POWER RESEARCH INSTITUTE
Co-Chairs
A. Facchiano, EPRI
A. Miller, EPA
Sponsored by
Electric Power Research Institute
Generation Group
U.S. Environmental Protection Agency
Air and Energy Engineering Research Laboratory
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Session 1
Plenary
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EPA Regulatory Update on Group 2 Phase n
P. Psirigotis
US EPA
Paper unavailable at time of printing. Please check the late paper
table in the registration area for a copy or contact the speaker
directly.
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Status of EPA Regulatory Development Program for Revised NQx
New Source Performance Standards for Utility and Nonutility
Units - Performance and Costs of Control Options
A. Miller
US EPA
Paper unavailable at time of printing. Please check the late paper
table in the registration area for a copy or contact the speaker
directly.
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Phase II Positioning, Evaluating Phase II
Alternatives Before the Regulations Are Issued
Presented at EPRI's Joint Symposium
on Stationary Combustion NOX Control,
May 16-19,1995
William A. Rosenquist
Project Manager, Sargent & Lundy
Tony Facchiano
Project Manager Environment Control Systems Business Unit
Electric Power Research Institute
Joe LeDuc
Software Developer, Sargent & Lundy
Richard Rhudy
Project Manager, Environmental Control Systems Business Unit
Electric Power Research Institute
ABSTRACT
Analyzing air emission reduction compliance options in today's business climate requires an in-depth look at all
alternatives in order to satisfy the diversity of interests of all involved parties. The need to provide low cost power
to the grid while meeting emission reduction regulations, presents a wide array of financial and managerial decision
scenarios. Although, the Draft Phase IINOX regulations won't be published for some time, long term strategies can
be evaluated now with a software tool like the CAT Workstation . The CAT Workstation™ can help the long
range planners/compliance teams begin to sort out and evaluate options. This paper will present some examples of
evaluating some of these options, such as the impact meeting lower future limits after reaching the initial limits
proposed, or a determination of the cost effectiveness of emission averaging versus the risks imposed. The CAT
Workstation™ can evaluate multiple-overlapping emission averaging bubbles. Furthermore, some technologies
reduce more than one pollutant and thus the need to evaluate the total environmental value that a technology offers
is important.
Many of the older Phase II units may be subject to significant BOP impact costs due to the addition of SO2 and/or
NOX Reduction Technologies. The CAT Workstation™ was designed to levelize the costs of operating technologies
so that comparison of those capital cost intensive technologies can be made to those competing technologies that
have higher O&M costs but low initial costs. The CAT Workstation™ can help the Compliance Team decide if
these modifications or other more cost effective solutions should be implemented. Additional options may include
shutdown, or over control of larger Units? By using the emission bubble feature and setting different limits, the
program will develop the least-cost approach for meeting each lower limit. Therefore, one can model a given system
to analyze the impact of future regulations.
S&L/EPRI-NOxMay95
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INTRODUCTION
Reducing air emissions for fossil power plants, as mandated by the U.S. Environmental Protection Agency (EPA) under
Title I and Title IV of the 1990 Clean Air Act Amendments (CAAA), can be accomplished by one of several selected
technologies. However, the decision on how to most cost-effectively reach these new emission limits on a specific
utility system involves an extensive and time consuming analysis. As an addition to the Clean Air Technology (CAT)
Workstation™, cofunded by Sargent & Lundy (S&L) and the Electric Power Research Institute (EPRI), a tool has been
developed which aids utilities in the analysis of system-wide NOX and/or SO2 air emission control strategies and cost
optimization.
The CAT Workstation™ enables the user to develop least-cost emission reduction strategies for each emission reduction
technology considered at every unit. In addition, input data from EPRI technology support programs can be used to
provide performance and cost data to the CAT Workstation if such data is otherwise unavailable.
The application of CAT's Mixed-Integer Linear Programming (MILP) allows quick determination of the least-cost
emission compliance plan while considering all possible unit/technology/fuel combinations for the time periods
specified.
The user can conduct rapid sensitivity runs on such input variables as emission reduction technology performance and
associated capital and operating cost, fuel cost, and several different escalation factors. In areas where targeted
emission limits have not been set or when speculating on future (CAAA Phase II) reduction requirements, the program
can be used to develop the estimated compliance strategies and costs to meet various emission limits under
consideration by Federal or local agencies. Thus allowing the long range planning and compliance strategy
development now to minimize any "surprises" due to possible future regulations..
The use of the CAT Workstation™ does not change the compliance planning process but provides a powerful software
tool to compliment the utility's planning process. The elapsed time and man-hours required to identify the possible
unit/technology/fuel solutions for each unit is greatly reduced. Therefore, utilities may focus their efforts on the impact
of the most promising candidate technologies and investigate the pros and cons of emission banking and trading
allowances, with respect to developing an overall compliance strategy.
Version 2.0 of the CAT Workstation was released in November 1994 by EPRI's software distribution center. Over
65 copies have been released to EPRI members and are in various stages of using the software.
CAT WORKSTATION
The CAT Workstation is a tool used to determine the most economical and reasonable methods of system-wide SO2
and/or NOX emission reduction strategies. It allows both actual and theoretical technologies to be evaluated and
enables users to create detailed configurations of unit/technology/fuel combinations for each unit as needed. Many
power plant units and strategies can be evaluated at once while considering all necessary dependencies. Period-
dependent variables are factored into all evaluations, including economic parameters, unit capacity factors, emission
constraints, and projected emission allowance values. The Workstation™ then outputs a ranked list of optimal
technology-fuel combinations for each unit by time period, along with the number of allowances to buy or sell in each
period. The program also provides an emission bubbling (or emission averaging) capability which allows the user to
evaluate the cost effectiveness of adding emission reduction technologies to older, low capacity factor units versus a
greater incremental emission reduction at larger, higher capacity factor units.
The technical objectives of the CAT Workstation™ are to take maximum advantage of existing EPRI R&D results and
information on SO2 and NOX reduction technologies and to aid the utility industry in determining the best emission
reduction strategies by:
S&L/EPRI-NOxMay95
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consolidating existing, relevant information from previous EPRI R&D projects into a single computer-based
source (i.e., the CAT Workstation™)
providing a means for utility users to quickly identify the appropriate emission reduction technologies for their
specific requirements through a technical screening and then to evaluate these selected technologies on an
economic basis
providing an effective means of technology transfer through an easy-to-learn, easy-to-use graphical user
interface to the workstation software
After the unit/technology/fuel combinations have been identified and the emission limits established, a selected number
of the lowest cost scenarios are identified by the CAT Workstation using the MILP process. MTLP is a mathematical
optimization method that uses linear programming techniques for solution variables that are restricted to integer values.
This involves an iterative search algorithm that has been refined by mathematicians over the past several decades.
Large problems (e.g., many units, technology, fuel options, and/or time periods), which ordinarily take hours or days to
solve on the computer by explicit enumeration, can be solved in minutes.
The intended function of using an MILP formulation for the CAT economic analysis is to minimize the system-wide
life-cycle cost of compliance, subject to the constraints of allowable emissions per period and other restrictions. The
output of this formulation includes the optimal technology-fuel combination for each unit and period, and the number
of allowances to buy or sell in each period.
The user can have the program identify up to the top 50 least-cost scenarios, which help identify a set of technologies
that may be more practical to retrofit, yet within 1 or 2% of the initial least-cost scenario.
Hardware and Software Requirements
The CAT Workstation™ will operate on any PC capable of running the Microsoft Windows 3.1 operating system in the
enhanced mode. The following list is considered the minimum hardware configuration:
• a minimum 486DX/33 with math co-processor, Pentium, P-5,60 or better is recommended
• at least 8 MB RAM
• a 4 MB RAM driver or greater
• a hard drive with 10 MB available
• Microsoft Windows-compatible Super-VGA color monitor
• Microsoft Windows-compatible pointing device (mouse)
• Microsoft Windows-compatible printer
S&L/EPRI-NOxMay95
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COMPLIANCE PLANNING - PROJECT SETUP
The simplest method of demonstrating the setup of the CAT Workstation™ for compliance planning is to walk-through
a project. The emission reduction study process begins with the collection of the data necessary to complete the
analysis.
The data required for the Workstation is the same that compliance teams are and have been gathering in the past with
regards to information on their units, fuels, system economics, and technologies being considered for each unit. Utility-
specific data is entered into the Workstation through the following database management screens:
• Project Setup
• Utility Economic Database
• Fuel Database
• Unit Database
• Evaluation Inputs determination
• Technology Costs
• Emission Bubbles to be considered
hi the Project Setup screen the users identifies the units, fuels, and technologies applicable to the proposed project.
Figure 1 illustrates the project setup screen for the case study.
The utility Economic screen identifies basic financial data for the user's system such as base year, discount rate,
escalation rates, allowance prices if any, and CAAA periods. Figure 2 illustrates the utility economic database input
screen. Four load profile input boxes have been added for the purpose of modeling the unit operating characteristics
such as seasonal peaking demands and lower load operation in the off-peak season.
Fuel information is incorporated into the database through the fuel screen, where user-defined coal, oil, or gas fuels or
fuel blends can be created. The CAT Workstation will generate the appropriate fuel blend properties and costs by
using a weighted average of the base fuel information. If the actual fuel blend properties are known, they can be
entered. The fuel database input screen is shown in Figure 3.
Due to the large quantity of information, several input screens are utilized. There are three screens for the unit
information entries for unit capacity factor, heat rate, and basic data such as unit size and boiler efficiency. Figures 4, 5,
and 6 illustrate the input screens for a unit of the case study.
The unit load or capacity factor data, shown in Figure 5, can be entered as either a unit average for each load
profile/time period combination or a plot of capacity factor versus time of day. Typically, a utility would use an
average value for initial screening runs and proceed with more precise data, if available or necessary, when the field of
alternatives has been narrowed and final optimization is taking place.
The same methodology may also be used for the unit heat rate data. The unit heat rate can be entered as either a yearly
average type value or as a function of unit load. The new screen is shown in Figure 6.
The emission bubble screen is used to identify the emission limit constraints for the system and is based on the
compliance team's review of pending regulations. This function allows a utility to identify the pollutant, units, and time
period included in the emission bubble. Multiple emission bubbles can be created to properly define the utility's
S&L/EPRI-NOxMav95
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emissions requirements. For this example, a combined SO2 /NOX bubble has been created. Figures 8 and 9 illustrate
the input screens and database for the emission bubbles database.
The evaluation input screen is used to establish the various unit/technology/fuel combinations to be analyzed in the
proposed study. The CAT Workstation can accommodate any number of combinations. Figure 10 illustrates the
evaluation input screen.
The final data entry involves the costs (Capital and O&M) and performance for each technology at each unit. This
screen captures all the applicable technology information that is usually developed by outside studies. This data can
now be gathered and consolidated in one area for analysis on a total life-cycle least-cost basis specific to the utility's
system characteristics. Figure 10 illustrates the Evaluation input screen.
After the databases are input into the CAT Workstation™ and the base analysis is performed, the tool becomes quite
effective in assisting a utility in determining the most prudent technology choices. This is particularly true when
analyzing the banking and trading of allowances. Sensitivity runs, which help identify the boundary limits of given
technologies, can be performed to bracket risk for both current and future regulatory needs. Judgments concerning the
suitability of including low capacity factor units in the analysis can also be easily tested and confirmed. Examples of
the types of sensitivity analyses to perform would be to change fuel cost escalation, change the discount rate, vary
capital costs for technologies, and emission reduction performance.
Figures 11 and 12 show the results of one economic analysis and identify the least-cost technology/fuel combination for
each unit and shows the emission rate for each unit after control. Additional data is available through using the drop-
down menu for Reports and choosing the Economic Analysis Reports.
COMPLIANCE PLANNING EMISSION LIMIT EVALUATION
Although the system used in the case study consists of multiple coal fired fossil units, CAT is also capable of handling
oil and gas fired units. One of the first things a compliance team should determine is the "mix" of technologies needed
to achieve lower emission limits. For example, if the system meets phase I limits today how does it achieve phase II
and beyond proposed limits in the most cost-effective way? The first step of the case study involved running several
iterations of the CAT model with the NOX emission target varying from 0.25 to 0.5 Ib/mmBtu and place all the units in
the emission bubble. In this example, six iterations of the computation were performed. The costs for the six cases are
illustrated on Figure 13.
This data is important since it identifies the estimated least-cost technologies for various emission limits under
consideration by the regulatory agencies. It is anticipated that this data would be used to demonstrate the cost of
compliance once emission limits are established. Other features of CAT allow the user to investigate what-if scenarios
with regards to banking and/or trading allowances. For this case study, obtaining system NOX emissions below 0.25
Ib/mmBtu becomes quite costly. It should be noted that for this case study the baseline unit NOX emission rates are
relatively low and therefore, the cost of emission reduction for the other utility systems may be much higher. This
information is useful to the utility internally as well as externally. It may be useful in working with the regulatory
bodies who will ultimately determine the NOX permit requirements for the system.
One of the points on this chart illustrates the effect of over-control by a deep reduction technology on only one unit.
This is the triangular point, and shows that the present value costs of this technology are higher than the true least-cost
to obtain an emission rate of 0.5 Ib/mmBtu and the system average is nowhere near the first target bubble limit.
Also shown on this chart is an overlay of some of the second, third, and fourth least-cost options at an emission limit.
These are the circular points just above the optimized curve. Some of these alternatives may either be :
S&L/EPRI-NOxMay95
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• more practical to install
• allow for add-on technologies for future emission reductions
• provide additional emission reduction for very little cost and also provide a slight degree of margin
• indicate that a unit with a turbine overall outage coming up to be "cost-effective"
While there is a lot shown on this chart it illustrates the type of system analysis that can be performed.
Although not demonstrated as part of this case study, the next logical step in the system-wide compliance analysis
would be to evaluate the pros and cons of emission banking, trading, and purchasing options.
The case study shows that the command and control of each unit has a higher initial cost and impact on outage
schedules for retrofits. On the other hand, if bubbling is allowed, then there is a reduction in initial capital cost
expenditures, and the funds can be spent on the higher capacity factor units. Although bubbling initially has a lower
cost, there may be an added administrative burden. Sensitivity runs should be performed to determine the impact of
losing one of these larger units with emission control equipment and using banked allowances or generating higher
levels of NOX removal on other units.
While this is only one of many analyses that should be performed to develop a compliance strategy, it does illustrate the
economic advantage of emission bubbling believed achievable on all systems. The bubbling concept is shown to be
more cost effective since fewer units are modified. This also has an impact on outage planning so that fewer units need
to be taken off-line or planned outages extended for emission reduction modifications. As shown in Figure 14, Unit 1's
cost per ton of NOX reduced is not in proportion to the other units, since Unit 1 is one of the smaller, older units in the
system and is dispatched on a less arduous basis. Therefore, capital expenditures on older units, primarily used for
seasonal peaking duty, could perhaps be eliminated. Furthermore, some states still require Prevention of Significant
Deterioration (PSD) permits, if LNB's are added to a unit. This is over and above the CAAA provision for exemption.
COMPLIANCE PLANNING OTHER ISSUES
There is a wide range of questions and concerns facing the Compliance Planning Teams, some of which are
geographically unique to just a few systems, others which are more universal. This section lists some of these issues that
have been addressed by having used the Workstation on compliance studies and/or answered questions from users on
how to setup the Workstation™ to handle a specific case.
1. What technologies need to be installed to achieve one emission limit for five months of the year (i.e. ; ozone
season) and then meet another limit for the remaining seven months. What if the largest unit has a forced outage
during this "ozone" season, how do the rest of the units need to be operated to maintain the seasonal emission limit.
2. If the use of a technology on one unit to control one pollutant increases the other pollutant slightly, what's the more
cost-effective strategy? Should the utility control another unit's emission rate, or install an additional technology at
the first unit?
3. If future emission reductions are required, will the technologies installed today be effective are need to be
replaced? Thus from a system standpoint, is there a more appropriate technology to install now to position the
utility for the future?
4. Many older units will most likely incurred significant BOP costs associated with adding certain technologies. In
these cases, some low capital cost modifications may be more appropriate for these older units. One then needs to
consider what happens when these units are brought on line in an emergency or to sell power on a spot basis.
S&L/EPRI-NOxMay95
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5. Is seasonal fuel switching to a cheaper foel, which causes some load restrictions, but lowers emissions for that
seasonal period, a cost effective approach?
6. Emission averaging may present significant cost savings but are they enough to offset the administration
requirements and other risks?
These are just some of the many questions/issues facing Compliance Planning Teams in system evaluation. All of these
can and have been evaluated by using the CAT Workstation™ in concert with the other compliance planning tools. In
essence the Workstation is a multi-dimensional "spreadsheet" which was specifically developed to assist in selecting
the right unit/technology/fuel combination to meet a specified emission target literally from millions of alternatives.
SUMMARY
This paper demonstrates only some of the many capabilities of the Workstation Used now, the utility planner can
develop a model of the system which will compliment other resources used. The Workstation™ can will assist in
developing such plans as:
• Emission Compliance
Title I and "Beyond" (NOx)
Title IV Phase 2 (SOX and NOx)
• Title V Operating Permit preparation and submittal
• Impact of system expansion plans on air emissions
• Outage scheduling to implement emission reduction technologies
Incorporating such features as an economic optimization engine, unique-unit operating characteristics, emission
evaluation, and simulating banking and trading, can help the utility planner evaluate options, even though some
emission limits have not yet been established. The current schedule for issuing these limits may not allow sufficient
time for evaluating options before an emission reduction technology is required.
While the purpose of this paper is to demonstrate the NOX enhancement to CAT, another valuable aspect of CAT is the
simultaneous SO2/NOX evaluation capability. When reducing a pollutant, implementing one technology may have a
positive or negative impact on the emission of another pollutant and the corresponding compliance plan. This valuable
capability will be demonstrated in future case studies.
EPRJ and S&L have entered into a strategic alliance to provide the CAT Workstation™ to EPRI member utilities for
the planning and implementation of emission reduction strategies. The Workstation™ also incorporates an integrated,
interactive set of software tools that educates the users on selected emission technologies while assisting in the
development of a compliance strategy. The usefulness of the CAT Workstation™ exceeds the initial identification and
evaluation of compliance strategies. The CAT Workstation™ allows rapid, inexpensive, and
flexible reevaluations of compliance strategies in the face of changing economic factors and system planning
considerations.
ACKNOWLEDGMENTS
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The authors wish to acknowledge Tony Maurer, John Kalanik, Dale Sopocy, and Thomas Tokarski for their
contributions to the Workstation™ design and development. The authors also wish to acknowledge Dennis Ward for
his original concept for the economic analysis function and for his expertise regarding CAAA implementation
considerations. The economic analysis function was developed and tested with the assistance of Raj Gaikwad, Walter
Rymarczyk, Dan Reuben, and a special thanks to the following host utilities who have participated in Beta testing:
Beta-tested the Version 1.0 software and provided valuable insight into the practical uses of the CAT
Workstation™: The Cincinnati Gas & Electric Company, Duke Power Company, New York State Electric & Gas
Corporation, Rochester Gas & Electric Corporation, and Wisconsin Electric Power Company. Also, a special
thanks is extended to the six host utilities who beta-tested the NOX Enhanced Version 1.5 leading to Version 2.0:
Cincinnati Gas & Electric, Centerior Energy, Northern Indiana Public Service Company, Sierra Pacific Power
Corporation, South Carolina Electric & Gas Company, and Wisconsin Electric Power Company.
S&L/EPRI-NOxMav95
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FIGURES
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CAT Workstation: NOX CASE
Me jnput £valuate Analysis Reports Jools guidelines Help
^ Project Setup
* <* NOx Case
The lists alright identify the Units, Fuels
and Technologies applicable to the
current project.
To view detailed data on a specific Unit,
Fuel, or Technology, double-click on the
tern r> the list.
The capabilty to add to, or delete from, the lists.
at right is also available. First click on the Unit,
Fuel, or Technology then click on the Add
icon or Delete icon to add or delete,
respectively, a Unit, Fuel, or Technology.
To select Project Setup or
Project Description click
on the buttons to the right,
Project Setup
Project Description
Mode: Input
: Unifl MEDCFT/F
Unite MEDCF.W/F;
Unit3HICFWF
Unlt4HICFT/F
CVG Blend 80/20 ~
Coal A -
coal C_PRB
Gas
Orimulslon
Technologies
SNCR .
SNCR+ Induct SCR
WetFQD
Double Cickto View Selected Fuel Data
Figure # 1 Project Setup screen
CAT Workstation: NOX CASE
File Input Evaluate Analysis Reports lools Guidelines Help
s
m
Mode:.lnput '
' \
Economic Information
NOx Case
• "
Project Economic Data
BaseS Year
1995
Present Value Year
1995
Discount Rate
955 %/yr
Q Appfestoafl
variables on screen.
Levefeed Fixed Charge Rate
V2AS~~%f^~~
UFCR Book Life
20 years
SO2 Allowance Buy Price '
135.00 ' Wton
NOx Allowance &jy Price
~ 200 .00 Won :'
Period Economic Data
Project Duration (read only)
End^e«r(Dec31)
^^~»03
LoadProflel
153 days
LosrfProfBe2 .
".'"9S-. days
LoadProffleS
"' sb days' T|
LoadProfBe4
.—_—,....„„.. —,--.--
CepSal Cost Esc.
....... 74.30"%jyr
Repl. Power Cost Esc.
" : ' 3.00 "
OSMCostEsc.
S02 Alowance Price Esc.
NOx AUowancB Price Esc.
;7'~"~"'35o"~%/yr"""
Figure # 2 Economic data
10
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CAT Workstation: NOX CASE
File Input Evaluate Analysis Reports Jools Guidelines Help
A t>
m
Mode: Input
i
Fuel Information
C/G Blend 80/20
Click on an Available Fuel
belowto view the associated
Available Fuels j
1 O'G Blend 80/20 ml
Coal A ~
Coal C_PRB -J
Gas
OrtmulsJon
' • , : "..'-. 2
Selected Fuel Compo I
"Component Name
Gas"
CoalA
*~n
"20.00~~
30.00 ,
To select a property
or blend fuels cfck oh
the buttons to the __: . „
: PerbdPFcSSiies- |;Edt Fuel Blends -|
Fuel Properties
FuelName :0OG Bend 80*20 T"
Fuel Type [Jj CoaMJgnfte ,
Fuel Cost v Q
}1 SS43 VMBtU
**#_ Zii...:.D
13,380 Btu/lb
SuHwCortert Q
Fixed Carbon Cortert
30.40 %byO
_.. .---^
Carbo)i_Coritent ^
61.34 :%by
Oxycjon Content * ;}Hytfc"og©o Content'/
5.04 %by : I
AshContent
7.94 % by |
Chtoriie Content
•," 0.80 %by |) 4.00 % by j| 0.06 % by
Nlro^n Cortent .
^0.84 % by
H20 Cortent Votatfe Matter Content
850 % by 1
1920 %by •';..
^|J| AppSes to aBvarmWes on screen.
Figure # 3 Fuel Information
CAT Workstation: NOX CASE
File input Evaluate Analysis Reports Tools Guidelines Help
:f:FS| Mode: Input
"IS
Unit Information
Unit 1 MEDCF T/F
Available Units
Un*2MEpCFVWF
IW3HCFWF
All Evaluation Data entered should
represent the base unit configurator).
Unit Evaluation Data
UrAName IWMMEDCFfS
Unit Location S| Indiana
Boiler Tvpe JJ| T-Fired
Bo9er Ef f fciency Q
^--- ,.^-— -j
Gross KWCapaciy {J[j|
330,000 KW ^li
AuxilDary Power Q
31,350 WV 1
Repi. Capacity Charge.
- 2¥"$*W-~y
Kept. Energy Charge ; ~
0.0170 $*S**1
Unit Start-Up Year
1972
I
;*l
*i
m
F1
2
Q
1
Cfck on the radio buttons
below to set the Unit Loading
& Net Plant Heat Rate curves.
Set Average IW Loadng
-J 51 %
Set Net Ptent Heat Rate
'J - ;10^50 Ku*Wh
Emissions Start Year Q
1^5 = ; "HI
.ss^iJ!*—,-^—,!!
. 20 years
Change Period
^--•Y=j-j-j
1996-1997 j
TechnotogySwfch Q
if.- .'-"'YES .
Select the period to bejpn
cons'idertVig emissions or
of the project.
Figure # 4 Basic Unit Information
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CAT Workstation: NOX CASE
File jnput Evaluate Analysis Reports Jools Guidelines Help
WmMffi?.
Mode: input;
Unit Information
MEDCFT/F
UnS Capafty Factor (%) vs.Tfrn* of Day
Figure # 5 Daily Unit Loading Profile
CAT Workstation: NOX CASE
File input Evaluate Analysis Reports Tools Guidelines Help
UnS2MHXFW)F
UnlSHCFWiF
Uni4HICFTJF -
,, Unit Information
flL.Unit'1 MEDCFT/F
Figure # 6 Unit Heat Rate versus Load
S&LEPRI-NOxMa^?
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CAT Workstation: INPUT TEST TRAI
—-^^ '""•••"'""•^^^"^^^"^^^^^••^•aMMK^l^M^^M^^^Bi^^MB^^^^^^^^^^^WH^^^B^^^^M
File Input Evaluate Analysis Reports Jools Guidelines Help
lip
Mode: Input
Emission Bubbles
Double clck on a bubbte poDiiant to edl emission bubble data
Bubble Units
Un4 1 1sEDCF T/F
Unft 2 KffiOCFVWF
Un*3HICFV\flF
Unt 4 HCF Tf
^—
*
Change Period
-rvrj-j r-^-_^.-. -^
26o'6-2d03^j
Allowable Emissions J
J "' N/ATbns/yf
Allowable Emission Rate J
a
n
a
Absolute Emission Values
.are needed to support
Allowance Trading.
Click onthe Abowabte
Emisstons check box to
view and edl Alowance
Tradiig frrformaSon.
Figure # 1 Creating Emission "BUBBLES" for NOx Emission Rates
CAT Workstation: INPUT TEST TRAI
File Input Evaluate Analysis Reports lools Guidelines Help
i
Mode; Input
Emission Bubbles
SO2&NOxL
qiT-1
Bubbles
Double clck on a bubbte pollutant to edi emission, bubble data.
Bubble Pollutants
Bubble Units
S02 Bubble Data
UnilMEDCFtF
Un«2hEDCFWlF
Un»3HCFW)F
LWt4rtCFTjF
Change Period
2000-2003
S Vtapcjferfod B»^ Amount El
I '" TJQOO~ toni/yr 1
Allowable
jf "
lns/yf ~" :
Atowabfe Emission Rate
End Atowances Held
•-1SXMO tons
SeKBuy Price Ratto
1.00
Aiowance Aojustment
5 ;
Figure # 8 Creating Emission "BUBBLES" SO2 Emission Rates
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CAT Workstation: NOX CASE
Hie Input Evaluate Analysis Reports Tools Guidelines Help
i Create Evaluation Inptits
4»Unit3HICFVWF
1. Select a Unit •+-• Cfck onthe Add fconto create the Evaluation Input.
2. Selectthe TechnologiesancfFuelsto be- S, Cfck on ExisWng^Evaluaiion Inputs andthe
considered as Evaluation Inputs for the selected UnlDeJete :
3. Selectthe Source'Project Initialization for • kx«todefete Evaluationkipiis.
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14
-------
CAT Workstation: NOX CASE
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Emission Rate for NO,
S&L/EPRl-NOxMay95
15
-------
Possible Seasonal Emission Limits
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JFM'AMJ JASON D
Figure # 12 SAMPLE DUAL-YEARLY Target Emission Rates
NOX/CAT Informed Compliance Analysis
Example from one utility study
120
80
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16
-------
Session 2
Coal Combustion
-------
LOW-NOX BURNER AND SNCR RETROFIT EXPERIENCE
AT NEW ENGLAND POWER SALEM HARBOR STATION
G. Quartucy
Fossil Energy Research Corp.
23342 C South Pointe
Laguna Hills, California 92653
A. Sload, G. Fynan, R. Afonso
New England Power Company
25 Research Drive
Westborough, Massachusetts 01582
Abstract
New England Power has recently installed Riley-Stoker low-NOx burners (LNB) and Nalco Fuel
Tech urea-based selective non-catalytic NOX reduction (SNCR) systems on Units 1 and 3 at its
Salem Harbor generating station. In addition, Unit 3 was also retrofit with a two-level overfire
air (OFA) system. These two coal-fired units are front wall-fired with unequal burner spacing
and have uncontrolled full-load NOX emissions of nominally 750 ppm (1.1 Ib/MMBtu). Unit 1 is
rated at 86 MW and has 12 burners, while Unit 3 is rated at 155 MW and has 16 burners. NOX
reduction performance of the LNB, OF A and SNCR systems has been characterized both
independently and in combination during the test programs while firing low-sulfur coals.
Unit 1 tests showed that the LNBs provided NOX reductions of approximately 50 percent at loads
above 60 MW using narrow angle coal spreaders. Corresponding ash carbon at these NOX levels
varied between 16 and 35 percent. The SNCR system provided an additional 40 percent NOX
reduction from the LNB baseline at a molar N/NO ratio of 1.2. The corresponding NH3 slip
levels were less than 10 ppm.
On Unit 3, LNB tests showed that NOX reductions of nominally 10 percent were achieved with
the burners alone, using wide angle coal spreaders. The use of OF A, at design levels, provided
additional NOX reductions ranging from 42 percent at full load to 4 percent a minimum load
relative to the LNB baseline. Ash carbon levels doubled to levels above 30 percent when the
OFA system was operated at design conditions at loads above 110 MW. The SNCR system
provided NOX reductions of 33 percent relative to the LNB/OFA baseline of 0.55 Ib/MMBtu, at a
molar N/NO ratio of 1.3. Ammonia slip for these conditions was less than 5 ppm.
-------
Background
Under an agreement with the Massachusetts Department of Environmental Protection (DEP),
New England Power (NEP) is required to reduce NOX emissions from the coal-fired units at their
Salem Harbor Generating Station (Units 1, 2 and 3). The agreement limits NOX emissions to a
daily average of 0.33 Ib/MMBtu from these units. This represents a nominal 70 percent
reduction from their baseline NOX emissions levels of approximately 1.1 Ib/MMBtu.
To achieve this NOX emissions goal, NEP has chosen to retrofit these units with urea-based
Selective Non-Catalytic Reduction (SNCR) systems supplied by Nalco-Fuel Tech. Subsequent
to the SNCR demonstrations, Unit 1 has been retrofit with low-NOx burners (LNB) supplied by
Riley Stoker. Unit 3 has also been retrofit with Riley Stoker Low NOX burners and a Riley
Stoker overfire air (OFA) system. The Unit 3 LNBs and OFA were installed together as an
integrated NOX control system.
Unit Descriptions
Salem Harbor Units 1, 2 and 3 are front wall-fired B&W boilers. Units 1 and 2 are currently
rated at 87 MW gross for normal claim capacity operation, while Unit 3 is rated at 155 MW.
These units currently operate with capacity factors of about 80 percent. The units are balanced
draft designs, utilizing dual FD and ID fans. Units 1, 2 and 3 were retrofit with new electrostatic
precipitators in 1984.
Units 1 and 2 each have 12 burners arranged in three elevations of four burners each. Unit 3 has
16 burners, arranged in four elevations of four burners each. On all three units, the vertical
burner spacing is uneven. Spacing between the upper two and lower two burner elevations is
less than the spacing between the two center burner elevations.
The Riley Model 90 Controlled Combustion Venturi (CCV) burners retrofit to Salem Harbor
Units 1 and 3 are designed to fire either pulverized coal or No. 6 fuel oil. When firing
pulverized coal, NOX emissions are reduced by delaying the fuel/air mixing. This delay is
achieved through the use of a venturi coal nozzle and a low swirl spreader design. Together,
these result in gradual fuel air mixing, which reduces peak flame temperatures and subsequently,
NOX emissions. The Unit 1 LNBs were installed with narrow angle (i.e., 15 degree) coal
spreaders, while the Unit 3 LNBs were fitted with wide angle (i.e., 30 degree) coal spreaders
during the testing. The Unit 3 OFA system includes 8 dual elevation ports. The upper elevation
of ports is designed to supply two-thirds of the total overfire air, while the lower ports supply
one-third of the overfire air. The dampers for each OFA port elevation can be independently
controlled to vary the amount of OFA.
SNCR System Description
The SNCR process is conceptually simple. An aqueous solution of urea (or ammonia) is
injected into, and mixed with, the flue gas at the correct temperature. Once the mixing is
complete, the reagent reacts selectively to remove NOX. In practical applications, however, the
SNCR process can be complicated. Non-uniformities in velocity, temperature, and NO and CO
-------
concentrations at the injection point pose difficult questions because of the inherent sensitivity of
SNCR processes to these parameters. The physical location of the effective process temperature
range within the boiler changes, depending on operating factors such as load, fuel type, and
length of time operating with a particular fuel. These factors often lead to multiple injection
levels. All of these issues are compounded when dealing with a power plant that is required to
operate in a cycling mode, as is the case with the Salem Harbor units.
The urea injection systems installed on Salem Harbor Units 1-3 each include a circulation
module, a metering module and four distribution modules. Each distribution module controls a
single injection level. The NOXOUT HP (a 50 percent urea solution developed by NFT) is
delivered by truck to two chemical storage tanks which supply the urea for all three units. Prior
to injection, the urea is diluted with additional water, and transported to the desired injection
levels. Figure 1 shows the location of each injection level in the furnaces.
Test Program
Figure 2 presents a time line illustrating the schedule followed for the NOX retrofit test program
at Salem Harbor. This shows that the testing began with the evaluation of the SNCR system
installed on Unit 2 in January 1993. Unit 2 testing continued through June. Testing on Unit 1
was performed between August and November 1993. A limited amount of testing was
performed on Unit 3 in October, prior to the scheduled LNB/OFA retrofit outage. Testing of the
Unit 3 LNB/OFA systems began immediately, while the final optimization of the LNB, OFA
and SNCR systems was performed in September 1994. The Unit 1 LNB testing began in
November 1994 and was completed in March 1995.
Measurement Techniques
Measurement of gas composition and temperature were required for this project. Table 1
summarizes the species measured and the technique used.
Test Coals
A key element of these test programs was the evaluation of a variety of low-sulfur compliance
coals. Table 2 provides analyses of the coals fired during the test periods reviewed in this paper.
The initial testing at Salem Harbor, which started in 1993, was performed using the then
standard Alpine coal. The Alpine coal is a domestic medium-sulfur, low volatile coal.
Subsequent testing was performed using a variety of low sulfur coals. These coals have included
a domestic coal (Mingo Logan) as well as two South American coals (Gusare and Cerrejon).
The data show that the heating values for all coals varied between 12500 and 13000 Btu/lb.
Among other differences, the South American low-sulfur coals have FC/VM ratios which are
lower than the other test coals. The Alpine coal had a FC/VM ratio of 3.46 while the low sulfur
Mingo Logan coal had a FC/VM ratio of 1.85. In comparison, the South American coals had
FC/VM ratios of nominally 1.5.
-------
Table 1
Measurement Techniques
Species
Technique
Measurement Principle
NO/NOX
N2O
02
CO
CO2
S02
NH3
SO3
Ash Carbon
Temperature
Continuous
Continuous
Continuous
Continuous
Continuous
Continuous
Batch
Batch
Batch
Chemiluminescent
Non-Dispersive Infrared
Fuel Cell
Non-Dispersive Infrared
Non-Dispersive Infrared
Ultraviolet
Direct Nesslerization
Ion Chromatography
Elemental Analysis
High Velocity Thermocouple
Test Results
Parametric testing has been performed on each unit to evaluate the impact of the retrofit NOX
control equipment on unit emissions and operation. The parametric testing was performed at a
minimum of three loads across the operating load range.
For the LNB systems installed on Units 1 and 3, the following process parameters were
evaluated:
• Secondary Air Register Settings (swirl and flow)
• Coal Spreader Position
• Windbox/Furnace Differential Pressure
• Excess O2 Level
In addition, the effect of OFA flow rate was evaluated on Unit 3.
For the SNCR systems, the parametric testing included evaluation of the following process
parameters:
• Injection Location
• Reagent Flow Rate
• Dilution Water How Rate
• Atomization Pressure
Test results for Units 1 and 3 are summarized in the following sections.
-------
Table 2
Salem Harbor Coal Analyses Summary
Coal
Unit(s)
Proximate Analysis
% Moisture
%Ash
% Volatile
% Fixed Carbon
Total, %
Alpine
U
G us are
1
Mingo
Logan
3
Gusare
1,3
Cerrejon
3
7.46
10.36
18.42
63.76
100.00
6.75
7.02
34.72
51.51
100.00
6.97
7.56
30.03
55.44
100.00
7.74
6.06
34.30
51.90
100.00
9.47
4.14
35.24
51.15
100.00
Ultimate Analysis
% Carbon
% Hydrogen
% Nitrogen
% Sulfur
% Oxygen
% Ash
% Moisture
Total, %
HHV, Btu/lb
73.42
4.07
1.25
1.36
2.08
10.36
7.46
100.00
12,963
71.52
6.40
1.21
0.59
6.51
7.02
6.75
100.00
12,893
71.79
4.68
1.35
1.07
6.58
7.56
6.97
100.00
12,891
72.32
4.83
1.39
0.61
6.06
7.06
7.74
100.00
12,774
71.06
4.77
1.38
0.48
8.70
4.14
9.47
100.00
12,590
Ash Analysis
SiO2
A1A
FeA
CaO
MgO
NajO
K2O
TiO2
MnO2
PA
S03
52.53
26.96
12.11
1.53
0.69
0.35
2.36
1.39
0.01
0.39
0.74
53.54
22.89
5.91
4.32
3.50
0.35
1.62
0.94
0.00
0.11
5.75
51.35
26.81
11.71
1.32
0.94
0.47
2.49
1.34
0.05
0.20
1.57
61.22
21.80
5.28
2.80
1.80
0.45
2.18
0.92
0.10
0.17
3.24
51.97
21.08
6.68
7.85
2.18
0.78
1.62
0.87
0.10
0.19
6.63
Calculated Values
Base/Acid Ratio
Silica Ratio
FC/VM Ratio
Slagging Index
Fouling Index
0.21
78.6
3.46
0.29 (low)
0.07 (low)
0.20
79.6
1.48
0.13 (low)
0.07 (low)
0.23
78.2
1.85
0.23 (low)
0.10 (low)
0.15
86.1
1.51
0.09 (low)
0.07 (low)
0.26
75.7
1.45
0.12 (tow)
0.20 (low-
mod)
-------
Salem Harbor Unit 1
The pre-LNB retrofit tests on Salem Harbor Unit 1 were performed using both the Alpine and
Carbozoulia coals. The post-retrofit tests were performed while firing a low-sulfur, Gusare coal.
NOX emissions are plotted versus O2 level in Figure 3. Both pre- and post-retrofit data are
shown. The data show that the unit's NOX emissions were more sensitive to O2 level when firing
the South American coals. The pre-retrofit data showed full-load NOX emissions to be 1.10
Ib/MMBtu when firing the Alpine coal and 0.93 Ib/MMBtu at a nominal O2 level of 4.85% when
firing the Gusare coal. Following the LNB retrofit, NOX emissions were 0.46 Ib/MMBtu when
firing Gusare coal. The O2 level for this full load test was 4.4 percent. These data show that the
LNBs lowered NOX emissions by nominally 50% relative to the pre-retrofit tests performed
using the Gusare coal.
Figure 4 shows the effect of O2 concentration on LOI levels. Pre-retrofit data were only taken
while firing the Alpine coal. These data show that the LOI was 7.4% at a nominal O2 of 4.2%.
No LOI data were obtained when firing the Gusare coal, since the primary focus of the testing at
that time was SNCR system optimization. However, testing performed by plant personnel prior
to the retrofit showed that LOI levels were nominally 15% while firing Gusare coal.
Post-retrofit tests, performed while firing the Gusare coal, showed that full-load LOI levels were
19.9% at a nominal O2 of 4.4%. These data show that firing the low sulfur South American
coals resulted in a doubling in LOI levels, from 7.4 to 15%, with the original burners. The
retrofit low NOX burners increased LOI levels from 15% to 19% at full load.
Figure 5 shows NOX emissions plotted versus load (MW) at nominal O2 levels. When firing the
Alpine coal, the 86 MW data show that baseline NOX emissions averaged 1.10 Ib/MMBtu at a
nominal O2 level of 4.2%. At 67 MW, NOX emissions averaged 0.94 Ib/MMBtu while NOX
emissions averaged 0.93 Ib/MMBtu at 38 MW. The corresponding O2 levels for the reduced
load tests were 4.8% at 65 MW and 9.8% at 38 MW. These NOX emissions are somewhat higher
than expected for a unit of this size, primarily due to the high furnace heat release rate and the
unequal vertical burner spacing. This results in NOX emissions characteristics similar to those of
a cell-fired unit. When firing the Gusare coal, NOX emissions decreased somewhat. At full load,
NOX emissions averaged 1.0 Ib/MMBtu at a nominal O2 level of 5.2%. When firing the Gusare
coal, NOX emissions decreased nearly linearly with load to 0.72 Ib/MMBtu at minimum load.
Following the LNB retrofit, a series of parametric tests were performed to optimize their
performance. This work included varying the air register swirl settings, the spreader position,
and the windbox to furnace differential pressure. The primary goal of all changes was to reduce
LOI emissions, since NOX emissions with the retrofit narrow-angle coal spreaders were
satisfactory. The swirl settings were set with the outer burners having more swirl than the center
burner, while the spreaders were set at the same position at each burner. These burner settings
were selected to provide balanced O2 levels at the furnace exit.
Figure 5 also shows NOX emissions plotted versus load for the post-retrofit testing. These tests
were performed while firing the low-sulfur Gusare coal. The data show that post-retrofit full
load (e.g., 88 MW) NOX emissions averaged 0.46 Ib/MMBtu at an average O2 level of 4.4%.
-------
NOX emissions also averaged 0.46 Ib/MMBtu at 65 MW and were 0.45 Ib/MMBtu at 30 MW.
This shows that the low NOX burners reduced NOX emissions from 37 % to 54 % over the load
range relative to the pre-retrofit conditions while firing low-sulfur South American coals.
CO emissions were below 50 ppm during all test conditions performed at nominal O2 levels, for
all coals.
The SNCR evaluation began with a series of parametric tests, both before and after the LNB
retrofit. The results of these tests showed that the optimum injection level changed with load as
shown below:
Load. MW Injection Levels
Pre-Retrofit Post-Retrofit
88 72 88-60 2U, 2L
72 - 60 60 - 40 2L, 1
60-40 40-30 1, 1R
These injection levels were ultimately used during both portions of the testing. The solution flow
and atomizing air pressures were set to their full load optimum, since it is not possible to vary
them automatically as a function of load. The full load SNCR settings were selected as the
optimum because of the unit's high capacity factor.
Figure 6 shows NOX emissions as a function of Normalized Stoichiometric Ratio (NSR) for
Salem Harbor Unit 1. The NSR is defined as follows:
- mo^es N injected
moles initial NOX
(1)
NSR is used so that the effect of urea flow, taken at different operating conditions, can be
compared on a normalized (i.e., non-dimensional) basis. Data are presented for full-load
operation, both before and after the LNB retrofit. These data show that the minimum achievable
NOX emissions varied from 0.54 Ib/MMBtu at an NSR of 2.0 prior to the retrofit while firing the
Alpine coal to 0.39 Ib/MMBtu at an NSR of 2.2 when firing the Gusare coal. The post-retrofit
SNCR performance while firing the Gusare coal showed that NOX emissions of 0.28 Ib/MMBtu
could be maintained at an NSR of 1.2. Note that the initial NOX levels for this work varied from
1.10 Ib/MMBtu when firing the Alpine coal before the LNB retrofit to 0.46 Ib/MMBtu when
firing the Gusare coal with the low-NOx burners. The corresponding NOX reductions ranged
from 64% when firing the Alpine coal (pre-retrofit) to 39% when firing the Gusare coal
(post-retrofit).
The corresponding NH3 slip data are plotted versus NSR in Figure 7. These data show that the
highest NH3 emissions were measured pre-retrofit when firing the Gusare coal. This is most
likely due to changes in the injection zone temperatures, resulting from changes in coal type.
-------
The low-volatile Alpine coal would be expected to continue burning higher in the furnace
relative to the high volatile South American coals. This would result in higher injection zone
temperatures when firing the Alpine coal. The pre-retrofit NH3 slip levels measured at an NSR
of about 1.5 ranged from 18 ppm to 48 ppm for the different operating conditions considered.
When firing the Gusare coal following the LNB retrofit, the full-load NH3 slip levels ranged
from 3 ppm to 9 ppm over the range of NSRs evaluated.
Salem Harbor Unit 3
After the initial shake down period, a series of parametric tests were performed. For the
LNB/OFA system installed on Unit 3, the testing was performed in two parts. The initial testing
characterized the performance of the LNB system alone, while both the LNB and OFA were
characterized during the final testing. It must be noted that the Unit 3 LNB/OFA system was
designed and installed as an integrated system. Thus, tests performed with the OFA system off
were intentionally run in an off-design condition in an attempt to quantify the sensitivity of the
LNB and OFA systems separately.
Figure 8 shows NOX emissions plotted versus O2 level for the following full load operating
conditions:
Pre-retrofit ; Mingo Logan coal
Pre-retrofit ; Alpine coal
Post-retrofit; Gusare coal
Post-retrofit; Cerrejon coal
Post-retrofit; Mingo Logan coal
All post-retrofit data were taken with the OFA dampers closed. The effect of O2 level on NOX
emissions is presented in Figure 8 for these five operating conditions. These data show that the
Unit 3 NOX emissions are very sensitive to O2 level. The NOX sensitivity varied between 0.10
and 0.083 Ib/MMBtu (74 and 61 ppm) NO^percent O2 before the LNB retrofit. Following the
LNB retrofit, this NOX sensitivity was 0.105 Ib/MMBtu (77 ppm) NO^percent O2 when firing
the Gusare coal. These NOX emission levels are all quite high for a wall-fired unit, and are likely
due to the unequal vertical burner spacing of this unit, which result in NOX emissions similar to
those of a cell-fired unit.
The effect of O2 on LOI is shown in Figure 9. These full load data show that the LOI levels
were nominally 8% for the pre-retrofit tests when firing either the Alpine or Mingo Logan coals
at nominal O2 levels between 3.5 and 4.0 percent. The post-retrofit data show that the LOI level
remained relatively unchanged (e.g., about 8% LOI at a nominal O2 of 3.7%) when firing the
Mingo Logan coal. LOI levels for both the Cerrejon and Gusare coals were significantly
higher; 16.1% and 16.3%, respectively, when operating at nominal O2 levels.
Figure 10 shows NOX emissions plotted versus load while operating at nominal O2 levels. Data
are presented for the five operating conditions listed previously. These data also shown that the
retrofit LNBs had little impact on NOX emissions as a function of load. This is most easily seen
by comparing the pre- and post-retrofit data obtained while firing the Mingo Logan coal. These
-------
data show that the maximum NOX reduction, due to the LNBs alone, was less than 5% at full
load and nominally 8 % at minimum load. Note that the South American coals (e.g., Gusare and
Cerrejon) provided NOX emissions of about 0.8 Ib/MMBtu at full load, compared to 0.92
Ib/MMBtu when firing the Mingo Logan coal. Minimum load NOX emissions were similar when
firing both the South American and domestic low-sulfur coals.
The subsequent tests evaluated the performance of the retrofit LNB/OFA system. The effect of
OFA flow on NOX emissions is illustrated in Figure 11. These data are presented for full load
operation while firing the Mingo Logan, Gusare and Cerrejon low-sulfur coals. These data show
that the highest NOX emission levels were measured when firing the Mingo Logan coal; NOX
emissions were 0.51 Ib/MMBtu at nominal O2 levels. NOX emissions varied from 0.48
Ib/MMBtu with the Gusare coal to 0.39 Ib/MMBtu with the Cerrejon coal. The data show that
use of 3/3 OFA at full load provided NOX reductions between 39 and 52 percent, relative to the
LNB baseline, depending on the coal fired. Note that the 3/3 OFA setting is equivalent to
nominally 21% OFA at full load. Also note that the no OFA case corresponds to about 5%
OFA. This occurs because the OFA dampers deliberately do not seal tightly, thereby allowing
cooling air flow across the dampers at all times.
Figure 12 illustrates the effect of OFA flow on LOI levels for full load operations at nominal O2
levels. The data show that the highest LOI levels were measured when firing the South
American coals. At maximum OFA flow, these LOI levels ranged from 31.5% with the
Cerrejon coal to 40.3% with the Gusare coal. When firing the Mingo Logan coal, LOI levels
were 16.2% with maximum OFA. This is less than half of the equivalent levels measured when
firing the low-sulfur South American coals. The impact of OFA on LOI levels varied with coal
type. This sensitivity ranged from 1.3% LOI increase/percent OFA increase for the Gusare coal
to 0.6% LOI/% OFA for the Mingo Logan coal.
Figure 13 illustrates the relationship between LOI levels and NOX emissions for the post-retrofit
testing. These data include the data from previous figures reviewing the effects of both O2 level
and OFA on NOX emissions and LOI. The data show that LOI levels were more sensitive to
changes in NOX emissions when firing the South American coals. This difference hi
performance is most likely due to the different combustion characteristics of these coals relative
to the domestic low-sulfur coals.
Figures 14 and 15 illustrate the performance of the SNCR system installed on Unit 3. Figure 14
shows NOX emissions plotted as a function of NSR for both pre- and post-retrofit work. Note
that the pre-retrofit data were taken at an intermediate load of 115 MW. This was necessary
because unit mill problems precluded full load operation while firing 100% coal. These data
show that it was necessary to operate at NSRs in excess of 3.0 to reduce NOX emissions below
0.4 Ib/MMBtu. The full-load post-retrofit testing showed that NOX emissions below 0.3
Ib/MMBtu could be achieved when operating at an NSR of 1.3. This is equivalent to a NOX
reduction of 33% from the LNB/OFA baseline. The improvement in SNCR performance is
mostly due to: (1) the lower initial NOX levels encountered following the LNB/OFA retrofit and,
(2) better balanced furnace conditions following the LNB/OFA retrofit. Minimum load testing
showed that NOX emissions of 0.31 Ib/MMBtu could be achieved when operating at an NSR
of 1.1.
-------
NH3 emissions are plotted versus NSR in Figure 15. The data show that full load NH3 emissions
were less than 5 ppm over the range of NSRs evaluated. At intermediate load, the NH3 slip was
31 ppm at an NSR of 1.3 for tests performed prior to the LNB/OFA retrofit. As NSR increased
to 2.5 and higher, NH3 emissions exceeded 60 ppm. These NH3 levels could cause operating
problems, such as heat transfer equipment fouling, visible plumes, ash contamination, etc., if
they were maintained for any length of time. Minimum load NH3 slip levels were nominally 30
ppm for tests performed at operating conditions which provided NOX emissions compliance.
CONCLUSIONS
Based on the results presented in this paper, the following conclusions can be drawn:
• The retrofit of low-NOx burners incorporating narrow angle (i.e., 15 degree) coal spreaders
to Unit 1 provided NOX reductions varying from 37 to 54% over the operating load range.
LOI levels with these burners were in excess of 20% at full load and nominal O2 levels when
firing the Gusare coal
• The SNCR system installed on Unit 1 provided full load NOX reductions of nominally 40
percent at an NSR of 1.2, relative to the LNB baseline. The corresponding NH3 slip levels
were less than 10 ppm.
• Unit 1 has been able to meet the Massachusetts DEP NOX emissions limit of 0.33 Ib/MMBtu
across the operating load range during the controlled parametric tests described previously.
• The retrofit of low-NOx burners utilizing wide angle (i.e., 30 degree) coal spreaders to Salem
Harbor 3 provided NOX reductions of less than 10 percent. The use of OF A, at design levels,
provided additional NOX reductions ranging from 42 percent at full load to 4 percent at
minimum load. Ash carbon levels doubled, to levels above 30%, when the OFA system was
operated at design conditions for loads in excess of 110 MW while firing low-sulfur South
American coals.
• The Unit 3 SNCR system provided full load NOX reductions of 33% relative to the
LNB/OFA baseline at an NSR of 1.3. Ammonia slip for these conditions was less than 5
ppm.
• Unit 3 has been able to meet the Massachusetts DEP NOX emissions limit of 0.33 Ib/MMBtu
at both full and minimum loads during controlled parametric testing.
-------
SNCR
Injection 2U
Levels -.
OFA Ports
(Unit 3 Only)
Burners
-1R
(Unit 1
Only)
Gaseous Emissions
Measurement
Boiler Side View
* Not used on Units 1 and 3
Figure 1
Locations of SNCR Injectors, Salem Harbor Units 1 and 3
-------
ACTIVITY
Unit!
SNCR Installation
SNCR Testing
LNB Installation
LNB Testing
LNB/SNCR Testing
Unit 2
SNCR Installation
SNCR Testing
Unit 3
SNCR Installation
SNCR Testing
LNB/OFA Installation
LNB/OFA Testing
LNB/OFA/SNCR Testing
Oct
1992
Nov
flMlIf-:
Dec
fati'f-''*';
Jan
' ',', '*'
Feb
,-
.n.h^.f.
Dec
''/' '
'"'j
ACTIVITY
Unitl
SNCR Installation
SNCR Testing
LNB Installation
LNB Testing
LNB/SNCR Testing
Unit 2
SNCR Installation
SNCR Testing
Unit 3
SNCR Installation
SNCR Testing
LNB/OFA Installation
LNB/OFA Testing
LNB/OFA/SNCR Testing
Jan
Feb
Mar
¥• j?1-1"^ , ';:
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Apr
f*A$>.£
M
*$.
ay
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Figure 2
Salem Harbor NOX Test Program Schedule
-------
ZJ
s
1.2
1.0
0.8
§ 0.6
i§ 0.4
x
O
z 0.2
0.0
3.0
4.0 5.0
Economizer Exit C>2, % dry
6.0
Pre-Retrofit
n Alpine
O Gusare
Post-Retrofit
O Gusare
Figure 3
NOX Emissions versus O2 Level. Salem Harbor 1, Full Load Operation
30
25
^ 20
o~-
$ 15
§ 10
5
3.0
4.0 5.0
Economizer Exit 62, % dry
6.0
Pre-Retrofit
D Alpine
Post-Retrofit
O Gusare
Figure 4
Effect of O2 Concentration on LOI Levels. Salem Harbor 1, Full Load Operation
-------
1.2
1.0
13
s
0.8
CO
§ 0.6
"co
CO
"E
LLI
X
O
0.4
0.2
0.0
0
15
• * *
30
45
Load, MW
60
75
Pre- Retrofit
D Alpine
O Gusare
Post-Retrofit
O Gusare
90
Figure 5
NOX Emissions versus Load. Salem Harbor 1, Nominal O2 Levels
-------
0.5 1.0 1.5 2.0
Normalized Stoichiometric Ratio (NSR)
Figure 6
NOX Emissions versus NSR. Salem Harbor 1,
Full Load Operation at Nominal O2 Levels
Pre-Retrofit
D Alpine
O Gusare
Post-Retrofit
O Gusare
2.5
o
E
Q.
Q.
o
"w
CO
E
HI
CO
Pre-Retrofit
d Alpine
^ Gusare
Post-Retrofit
O Gusare
Normalized Stoichiometric Ratio (NSR)
Figure?
Effect of NSR Variation on NH3 Slip. Salem Harbor 1,
Full Load Operation at Nominal O2 Levels
-------
V)
c
g
"en
05
"e
LU
X
O
1.2
1.1 h
1.0
0.9
0.8
0.7
0.6
2.0
30
25
20
15
10
5
0
_
0)
2.5 3.0 3.5 4.0 4.5
Economizer Exit C>2, % dry
5.0
Figure 8
NOX Emissions Sensitivity to O2 Level. Salem Harbor 3,
Full Load Operation, OFA Dampers Closed
2.0 2.5 3.0 3.5 4.0 4.5
Economizer Exit C>2, % dry
Figure 9
LOI Sensitivity to 02 Level. Salem Harbor 3,
Full Load Operation, OFA Dampers Closed
5.0
Pre-Retrofit
D Alpine
O Mingo Logan
Post-Retrofit
• Gusare
A Cerrejon
* Mingo Logan
Pre-Retrofit
Q Alpine
O Mingo Logan
Post-Retrofit
• Gusare
A Cerrejon
* Mingo Logan
-------
1.2
1.0
0.8
CD
« 0.6
c
g
"w
CO
E
LU
X
Q 0.4
0.2
0.0
60
80
100
120
140
Pre-Retrofit
D Alpine
O Mingo Logan
Post-Retrofit
• Gusare
A Cerrejon
* Mingo Logan
160
Load, MW
Figure 10
NOX Emissions Variation with Load. Salem Harbor 3,
Full Load Operation, OFA Dampers Closed
-------
o
E
LJJ
X
O
1.0
0.8
0.6
0.4
0.2
0.0
0
50
40
30
o>
0)
O 20
10
0
n
o
o
Gusare
Cerrejon
Mingo Logan
10 15
Overfire Air Flow, %
20
25
Figure 11
Effect of OFA on NOX Emissions. Salem Harbor 3,
Full Load Operation, Nominal O2 Levels
D
O
O
Gusare
Cerrejon
Mingo Logan
0
10
15
20
25
Overfire Air Flow, %
Figure 12
Effect of OFA on LOI Levels. Salem Harbor 3,
Full Load Operation, Nominal O2 Levels
-------
50
40
30
-------
0.0
1.0 2.0 3.0
Normalized Stoichiometric Ratio (NSR)
Figure 14
NOX Emissions Versus NSR, Salem Harbor 3
Pre-Retrofit
115MW
Post-Retrofit
153MW
E
Q.
Q.
-------
AN EVOLUTION OF NOZZLE DESIGN
THE LOW NOX BURNER EXPERIENCE AT THE
BALDWIN POWER STATION
David W. Forney
Illinois Power Company
500 South 27th Street
Decatur, Illinois 62526
Donald G. Murray
Rolls Royce Industrial Power, Inc.
International Combustion Division
2847 Paces Ferry Road, Suite 400
Atlanta, Georgia 30339
Peter R. Beal
Rolls-Royce Industrial Power, Inc.
International Combustion Division
Sinfin Lane, Derby, England
Abstract
Illinois Power Company (IPC) installed low NOx burners on Baldwin
Unit 3 in the Spring of 1994. Although the NOx reduction
performance of these burners has been outstanding (See Figure 1),
IPC suffered catastrophic nozzle failure in the first 8 weeks of
operation. The nozzles were then modified and later, replaced.
Within 1 week of operation, 2 of the new nozzles also failed.
This paper traces the development of the original nozzle, the
influences of other nozzle failures on its design, the
determination of the cause of the original and subsequent
failures, and the current state of the nozzles.
ILLINOIS POWER BALDWIN UNIT 3
IN-SERVICE DATE APRIL, 1994
UNIT SIZE 600 MWN
PERFORMANCE DATA
BASELINE GUARANTEE POST
CONVERSION
NOx Ib/Mbtu 0.74 0.40 0.31
UBC % 2.0 4.0 2.0
CO PPM 30 150 30
FIGURE 1
-------
Introduction
Illinois Power Company (IPC) has five coal fired plants (10
operating units) that are affected by the Clean Air Act
Amendments of 1990. Of these units, three (Baldwin 3, Vermilion
2 and Hennepin 2) are Phase I, Group I boilers. IPC's original
strategy was to retrofit all of these units with low NOx burners.
Recognizing the need to be more cost effective, IPC reanalyzed
its system and determined that the system average could be
maintained without retrofitting Hennepin 2 (a 240 MW, twin
furnace design). Vermilion Unit 2 was retrofit with low NOx
burners in the Spring of 1993. Subsequently, a switch in the
compliance plan from FGD to allowances made it prudent to convert
the Vermilion plant to natural gas operation. As a result, IPC's
entire NOx compliance plan depends on the successful operation of
the low NOx burners on Baldwin Unit 3.
The outage for the installation of the low NOx burners for
Baldwin Unit 3 began in March of 1994 and continued until early
May. In addition to the low NOx burners the units' reheater was
replaced, additional superheater surface was added and the
control system was replaced with a Westinghouse Distributed
Control System. Although these projects were basically
unrelated, good communications among the principals resulted in a
cohesive outage plan and execution. For example, the operation
of the secondary air dampers was incorporated into the burner
management system and the amount of surface to be added to the
superheater was increased further due to the tendency of low NOx
burners to reduce steam temperatures.
The low NOx burner system installation was competitively bid as a
turn key project. Bids were solicited with guarantees of both
0.45 and 0.40 pounds NOx per million BTU. After analysis of
these bids the Contract was awarded to International Combustion
Limited (ICL).
International Combustion
International Combustion (1C) is part of the Rolls-Royce
Industrial Power Group. 1C is a boiler OEM, having installed
capacity worldwide in a wide variety of fuels including oil, gas
and coal firing, since its' founding in the early 1920's. 1C
provides a turnkey capability in the design, manufacture and
installation of fossil fired utility steam generators, heat
recovery steam generators, low NOx retrofit systems, specialist
combustion systems, rehabilitation, repair and maintenance of
steam generators. 1C is also a manufacturer of high integrity
pressure vessels and fabrications.
-------
The Combustion Systems
Business Unit is mainly
concerned with the low NOx
emission burners. With the
advent of the 1990 Clean Air
Act Amendments in the USA,
considerable work has been
carried out by 1C in
retrofitting utility boilers
with low NOx equipment. Since
1992, 15,825MW of low NOx
equipment has either been
installed or is on order.
These projects have either
been undertaken on a turnkey
basis or a design, supply and
advise contract.
Low NOx Burner Design Basis
Baldwin Low NOx System
The Baldwin low NOx conversion
consists of 2 levels of
separated overfire air (SOFA)
along with a complete burner
box retrofit of coal and air
nozzles (See Figure 2).
o?*
CSMPiHTMENT
All low NOx burners supplied
by 1C are designed in
accordance with standard 1C
design procedures for both
coal and auxiliary (secondary)
air nozzles. The original
Baldwin auxiliary air nozzle
free area was used as the
basis for the single 1C outer
coal nozzle. Care was taken
that the exit velocities for
both inner and outer nozzles
were within the specified
ranges at full load
conditions. 1C supplied the
inner and outer coal nozzles,
with the existing seal plates
and coal pipes being re-used.
During installation the seal
plate was modified with
extension guides to enable it
to operate over the full tilt
range. Due to the original
seal's design, it was still
possible for it to disengage
at full (30 degree) tilt, and
therefore a 20 degree tilt
limit was imposed.
MtLLGflOUP'F -
UIU. GROUP'S1 -
MILL GROUP 13' —
WU-GROUP? -
WU.GROUP-A- -
ONSETS*
" COMPARTMENT
" CCMPARTMEKT
WTEHWEDIATE SA
COMPARTMENT
COALBURNcR
" COMPARTMENT
COAL BURNER
' COMPARTMENT
INTERMEDIATE SA
" COMPARTMENT
COAL BURNER
' COMPARTMENT
INTERMEDIATE S*
- COMPARTMENT
(WITHOB.BUHNE3)
COAL BURNER
COMPARTMENT
FIGURE 2
-------
Along with this, the coal pipes have been resupported and a new
tilt linkage and drive system installed by 1C. This pipe support
work was undertaken to remove the main tilt binding experienced
on this boiler, restoring full burner tilt control.
The original Baldwin coal nozzles, fitted in the spring of 1994,
were based upon the successful low NOx burners, operational at
Fiddlers Ferry Power Station in the UK since 1985. The Baldwin
nozzles, however, are significantly larger than any others
produced by 1C. The design had been modified following
operational experiences at other power plants. These
modifications were undertaken to prevent inversion of primary air
to secondary air pressure differential across the seal plate.
Earlier experience in the USA had shown that this pressure
inversion could lead to a leakage of pulverised fuel into the
outer nozzle which may ignite and cause nozzle failure.
Investigation of this phenomenon at Baldwin revealed that several
factors were involved, including cut backs in the unit windbox
division plates. The method used to prevent this inversion was
to insert an internal steel restriction strip (baffle bar) in the
outer nozzle (See figure 3) . This causes a back pressure in the
fuel secondary air stream, ensuring that the secondary air was at
a higher pressure than the primary air, adjacent to the seal
plate.
ORIGINAL 1C COAL NOZZLE
WITH BAFFLE BARS INSTALLED
FIGURE 3
-------
Initial Unit Operation
Upon completion of the outage the unit was successfully returned
to service. To facilitate operator training and familiarization
with the new control system, the unit was operated without
overfire air for a period of 4 weeks. During this time the NOx
emissions levels averaged above 0.50 Ibs./mmbtu. Once the
operators became comfortable with the new unit control system,
the unit was turned over to ICL for optimization. It immediately
became apparent that NOx emissions levels would not be a problem.
With the overfire air system in service, NOx levels were easily
below the limit of 0.45 and the guarantee of 0.40, sometimes
reaching as low as 0.26 for hourly averages. LOI levels in the
flyash did not increase over baseline levels, staying between 2.0
and 3.0 percent. It appeared that the Baldwin Unit 3 retrofit
would be a textbook example of a low NOx retrofit, with an on-
time outage, excellent performance and a guick and easy
optimization. Unfortunately, this was not to be the case.
It became apparent during the early unit operation, through the
use on an in-furnace camera, that strong flame attachment had
been achieved on the inner nozzle, indicating a highly reactive
coal.
Nozzle Failures
On May 27, the first indications of problems occurred. The
permissives for the igniters on Right Front burner E ceased to
function. Upon investigation, it was determined that one of the
nozzles had significantly deteriorated and the heat had destroyed
the flame scanners. On June 1, the unit was removed from service
for a tube leak and the nozzle replaced. On June 13, the Left
Front burner C nozzle failed. This failure was much more severe,
burning through the windbox and destroying most of the corner.
The unit was forced from service for 1 week, returning to service
on June 19. During this time 1C supplied replacement parts and
worked with Illinois Power to effect the guick return to service.
Investigation
During the outage the following interim measures were taken:
1. The nozzle flares were removed.
2. The primary air control devices were recalibrated, and
3. The D mill primary air was placed on maximum constant value.
These actions were carried out to ensure the safe and reliable
operation of the unit while 1C engineering and R & D investigated
the probable causes of the failures, and made recommendations to
modify the nozzle to prevent reoccurrence of the situation.
-------
The engineering assessment revealed that:
1. The primary air flow control ramp had not been considered in
the initial design.
2. The primary air flows were unbalanced between mill to mill
as well as between corners.
3. At minimum load conditions the mean primary air exit
velocity was marginal, and
4. At extreme tilts (20 degrees) there were some recirculating
flows evident within the nozzle (See figure 4).
VELOCITY VECTORS WITH FLARE REMOVED
FIGURE 4
Fluid_model work by R & D revealed that a rib in the coal pipes,
that in some cases was installed with the rib on the bottom, had
disadvantages with respect to primary air flows and coal
distribution within the pipe. Further the model revealed that at
minimum load there was a possible primary air flow variation,
within the nozzle, of up to 30%.
-------
Subsequent Operation
Following the units return to service, the furnace camera was
used extensively to monitor the nozzles in service. Some flame
attachment was still observed on the inner nozzles. As ash
accumulated on these inner nozzles, it was removed periodically
by rodding out the burners, with the unit on line. Although
there were no further fires, the overall condition of the nozzles
began to deteriorate, with D elevation being removed from general
service. It was apparent that the nozzles that had coal pipes
with ribs on the bottom were more prone to nozzle pluggage.
Throughout these problems, NOx performance and LOI levels
continued to be excellent with NOx emissions as low as 0.28
Ibs./mmbtu and LOI's below 2%.
Design Basis for New Burners
An extensive design investigation was carried out by 1C on the
Baldwin nozzles, using the resources within R & D and
Engineering, combined with on-site work. The burner
configuration was extensively scrutinized, using computational
fluid dynamics (CFD) and isothermal modeling techniques. This
was carried out to ensure that there was no significant internal
recirculation with the nozzle at all tilt angles.
From this work the new nozzle design has emerged (See figure 5) :
FIGURE 5
-------
1. Exit velocities are now based upon the minimum primary air
flows,
2. inner nozzle internal flow splitters have been extended to
improve coal flow distribution at extreme (20 degree) tilt
angles,
3. nozzle flare sections are now only on the top and bottom
(not the sides), and
4. the outer nozzle profile has been modified to provide a
single opening adjacent to the inner nozzle, eliminating the
restriction strip.
These nozzles were installed in Baldwin 3 and placed in service
on January 16, 1995.
Current Operation
Current observations of the coal nozzles show that there is flame
attachment on the top burner elevations, though this attachment
is sporadic. NOx levels, and all other guarantees, are being met
throughout the load range. Within 1 week of installation,
however, 2 nozzles on D elevation developed damage. All other
burners have been visually inspected and no damage has been
found. The two nozzles concerned were replaced and no apparent
repeat of the damage has occurred. These two nozzles failures
have been attributed to a short period of operation in which the
D mill was operated without its normal primary air ramp. This
led to an overpressurization of the primary air side of the
nozzle, leading to fuel spillage and nozzle failure.
-------
Session 3
Coal Combustion
-------
1 -
Advanced Tangential Low
NOx Systems - Development and Results
J W Allen - Special Combustion Projects Manager
P R Beal Business Development Manager - Combustion Systems
April, 1995
Rolls-Royce Industrial Power Group
International Combustion Ltd
Derby, UK
-------
- 2 -
1. INTRODUCTION
The development of low NOx combustion systems has identified the near burner flame
conditions as critical in determining the eventual NOx emission levels, hi this paper the
development of this criterion, hi respect of tangentially coal (T) fired power generation
boilers, is discussed together with their commercial application. The potential ultra low
NOx performance of these techniques requires a deeper understanding of coal
characteristics in addition to the standard properties involving volatile release rates, the
behaviour of particulate clouds and their burning velocities. Aerodynamic properties
including fuel air mixing, velocity and particulate distribution are all of fundamental
importance and can be studied by means of isothermal physical modelling and
computational fluid dynamics (CFD).
Amalgamation of these various aspects into burner and combustion system design can be
considered as NOx control by flame management and can be applied to conventional
systems as well as to the development of advanced low NOx burner technology. Low
NOx equipment based on this technology is known as the EnviroNOx™ system.
2. T' FIRED BOILERS nENVTRONOx™ Tt
Burner systems in T' or comer fired boilers comprise basically of columns of alternate
coal and air nozzles situated in the corners of a rectangular cross section furnace. The
fuel and air is directed towards an imaginary firing circle in the centre of the furnace, the
resultant mixing producing a 'central fireball' which provides combustion stability for the
complete burner system. Because of the larger fuel air mixing paths and greater flame
surface exposure to the cooler boiler walls, T' or corner fired boilers are lower NOx
emitters than similarly sized wall or opposed fired units (I).
The first attempts at NOx reduction in T' firing were based on air staging techniques
which aimed to reduce the main burner stoichiometry by reducing the corresponding air
flow which was added separately at the top of each column to complete combustion. This
overfire air (OFA) technology was limited because of the danger of creating reducing
conditions adjacent to the boiler walls in the burner region and the consequent corrosion
of pressure parts.
-------
- 3 -
Offsetting some of the main burner combustion air to create an oxygen rich atmosphere
close to the walls enabled lower stoichiometry to be achieved in the main burner zone.
These techniques have been described in several papers (2, 3).
3. APPLICATION OF AIR STAGING FOR NOx REDUCTION IN "T FIRING
An OF A/offset air system was installed on the Niagara Mohawk Power Corporation's
Dunkirk 1 & 2 boilers. These 100 MW boilers incorporate four coal nozzles in each
corner of the furnace. OFA was introduced via two compartments close coupled to the
corner burner column (CCOFA) (EnviroNOx™ C).
Isothermal modelling was carried out to ensure the required mixing of the OFA was
achieved within the boiler (4). The scale model is shown in Figure 1.
Additional to the air staging a modification to the coal nozzle was also included aimed at
bringing the flame front close to the nozzle mouth which is in fact the first stage of
converting the nozzles into actual burners with control over the near burner flame region.
The use of enhanced flame stabilisation also offered control of NOx at lower firing rates
which is not always readily achievable in air staged low NOx systems.
The NOx guarantee figures for the Dunkirk low NOx conversions are given below in
Table 1, together with actual performance achieved for CO levels and SH & RH
temperatures.
-------
- 4
Table 1
PHASE 1 NOx GUARANTEES & ACTUAL PERFORMANCE FOR DUNKIRK UNITS 1 & 2
LoadMW
NOx Guarantee, #/Mbtu
CO Performance, ppm
SH Temperature °F
RH Temperature °F
UNIT
#1
96
0.32
<32
1000
1000
70
0.32
<30
1009
974
46
0.32
<36
996
943
UNIT
#2
96
0.32
<62
996
1005
80
0.32
<22
1007
1001
33
0.37
<67
1007
970
NOx guarantees were met at all loads, for both boilers, with reductions from baseline being
in the range 33-41%. CO emissions achieved were well below the guarantee level.
Guarantees were also provided for UBC, Boiler Efficiency and SH & RH temperatures:
• All UBC guarantees were met. Indeed there was no significant increase in UBC over the
load range against baseline.
• Boiler Efficiency guarantees were met with increases being achieved over the entire load
range. However, it should be noted that Niagara Mohawk also replaced sections of
waterwall, cold casing and installed new combustion control and burner management
systems during the NOx outage.
• All superheat and reheat temperature guarantees were met throughout the load range.
In this "EnviroNOx™ C" system the advantages of enhanced flame front control were seen
throughout the range of guarantees. These advances in flame management were the basis of
development of a "T" fired coal burner rather than coal nozzle, based on principles
established during the development and application of wall fired low NOx burners. The "T"
fired burner is known as the FAN (flame attached nozzle) burner and is offered in the
"EnviroNOx™ FAN" low NOx burner system. 4.8.
-------
- 5 -
4. DEVELOPMENT AND APPLICATION OF A T' FIRED BURNER WITH
ROPEMASTER™
a) Flame Attached Nozzle (F.A.N.)
The work on air staging and enhanced flame stability systems suggested lower NOx
emissions may be available by replacing the coal nozzles on T' fired boilers by purpose
designed coal burners.
Low NOx wall firing technology had developed burner flame attachment to control the
near burner reactions ie the rapid release of volatiles and hence fuel H2 into a low O2
concentration atmosphere and the application of this technique gave rise to the
development of the flame attached nozzle (FAN) burner for T' firing.
A similar mode of flame retention is used in the FAN burner design to that already
proven in low NOx wall firing i.e. the use of flame retention wedges and flares. The
material used in this critical region of the burner is a cast IN 657 alloy which has
achieved service life of over 4 years in a 500 MW front wall fired UK installation
confirming that early flame ignition does not damage correctly designed burners.
Therefore the flame retention design principle is secure.
b) RopeMaster™ Development
In order to exercise the necessary control on fuel flow to achieve low NOx operation it is
essential to have a good fuel air distribution within the FAN burner nozzle. However
pulverised coal levels to travel through coal pipework hi a series of "ropes" rather than as
a uniformly dispersed stream and therefore a reliable pulverised coal dispersal device is
required close to the burner as illustrated in Figure 5.
The form and location of this dispersal device known as the RopeMaster™ was decided
following isothermal solids flow modelling work achieving before and after distributions
as indicated in Figures 8 and 9.
-------
6 -
RopeMasters™ located at the entry to the burner cannot affect the coal distribution from
the mill to the burner but have been applied to conventional T fired boiler systems in
which coal mal-distribution was thought to be occurring within the coal nozzles. A
particular demonstration of RopeMasters™ in a T' fired boiler has shown that
improvements in performance can be achieved by the correct installation of the
RopeMaster™
A set of 16 RopeMasters™ were installed on the boiler at the burner inlets. Pre and post-
retrofit testing confirmed a 60% reduction in LOI.
The boiler concerned has only two coal elevations, resulting a relatively shallow fireball.
The shallowness of the fireball may be partly responsible for the relatively high pre-
Ropemaster™ installation LOI levels (in excess of 10%). Work is in progress to evaluate
the impact of Ropemasters™ on deeper fireball units.
The RopeMaster™ may also have further potential for improving coal distribution
throughout the coal feeding system from mill to burner in coal fired boilers.
c) Mark I FAN plus RopeMaster™ - site demonstration
Following a period of intensive isothermal and CFD modelling work and full scale
thermal testing in the International Combustion test facility at Derby in the UK the Mark I
FAN configuration was finalised with results as indicated in Figure 3. (FAN burners
have been applied to three units at Georgia Power's Yates site (5) together with various
air staging configurations as indicated in Figure 4. For comparison purposes, Yates 6 a
non-FAN air staged system is included in Figure 4.) A typical FAN nozzle arrangement
is shown hi Figure 5.
The installation on the 125 MW Yates 4 unit utilising FAN burners only was a final
development exercise based on the Mark I version of the FAN burner. No modifications
to the corner box air and coal nozzle configuration were made other than the installation
of 16 FANs to replace the existing coal buckets.
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7 -
The NOx performance of the Mark I FAN burner nozzles is shown in Figure 6, which
illustrates the NOx variation with excess air at 100% MCR. Contrary to most T fired
boilers the FAN burner maintains lower NOx levels at lower loads, 0.40 lbs/106 Btu was
achieved at 38% MCR with 6.5% excess O2.
The baseline 100% MCR NOx for Yates 4 was 0.61 lbs/10 6 Btu. The FAN burners
achieved 0.44 lbs/10 6 Btu a 28% reduction. Baseline and post retrofit carbon in ash
figures were 2.8% and 3.8% respectively.
d) Mark II FAN plus RopeMaster™ - Commercialisation
The change from a Mark I to Mark II burner design derived from the perceived propensity
for ash build-up in the region of flame attachment to occur in the Yates 4 furnace, the
Mark II burner, based on aerodynamic rather than mechanical flame attachment
eliminated this tendency.
As in the Mark I FAN development, extensive use of CFD, isothermal and full scale
thermal test rig trials was made.
Yates 5 is a sister unit to Yates 4 and has been equipped with close coupled OFA
(CCOFA) and offset air in addition to the Mark II FAN burner. Yates 5 represents the
first stage of FAN technology commercialisation. With this system a 48% reduction in
NOx was achieved at 100% MCR (from 0.65 lbs/106 Btu to 0.34 lbs/106 Btu) with an
increase in carbon in ash from 2.6% to 4.6%. CO levels after conversion were measured
at 13 ppm.
The identical 350 MW Yates units 6 and 7 low NOx retrofit projects provided the
opportunity to compare FAN burner and conventional nozzle performance.
Yates 6 was retrofitted with an International Combustion EnviroNOx™ T2 (offset air
plus two levels of separated overfire air (SOFA)) in early 1993. Following the exercise of
Georgia Powers's option to purchase an identical EnviroNOx™ T2 system for Yates 7, a
further decision was made to upgrade the EnviroNOx™ T2 system by adding Flame
Attached Nozzles (FANs).
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8 -
This upgrade provided Georgia Power and International Combustion with an opportunity
to evaluate the impact of FANs on an already advanced low NOx system.
Over 50% NOx reduction was achieved in the Yates 7 (FAN burner) unit at 100% MCR
compared to a 40% reduction from the air staged only Yates 6 plant. The results are
plotted in Figure 7 which show the NOx variation with load. The FAN equipped Unit 7
achieved 0.24 - 0.28 lbs/106 Btu NOx at low to medium loads.
With FAN burner installations at the Yates plant unburnt carbon was kept below the 6%
guarantee level without the necessity to improve mill performance as may be required on
such conventional T fired low NOx systems. Reheat temperatures were kept within an
acceptable range.
5. LONG TERM DEVELOPMENT AND COMMERCIALISATION OF
ADVANCED FAN BURNER TECHNOLOGY
International Combustion's long term target is the development of FAN based combustion
systems capable of operating under commercial conditions with NOx levels at or below
0.1 Ibs/MMbtu and on a wide range of coals and boiler designs. Progress to date is
encouraging but not without problems.
For instance, as the commercial application of FAN burner technology has developed,
potential problems of ash deposition within the flame attachment area of the burner have
been identified. A deeper understanding of the characteristics of the various coals fired
and the local nozzle aerodynamics are leading to an elimination of the problem and the
evolution of the Mark III universal FAN burner.
Work on the Mark II FAN is already under way based on CFD modelling and full scale
thermal test work confirming NOx levels around the 0.1 lbs/106 Btu level on the
combustion test rig, approximately 50% those on the Mark I/TI versions tested under
similar conditions. Factors which are influencing this improved performance are
attention to scarf plate seal design, flow properties within the burner nozzle flame
attachment zone plus further attention to the ignition and burning characteristics of the
air/pulverised coal mixture within this critical area. This has been shown to be a function
of local fuel/air ratio, coal volatiles, coal ash content and system temperature.
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- 9 -
The FAN burner technology has also been successfully demonstrated in a co-firing
system using 10% of the total fuel heat input from natural gas fired adjacent to the FAN
burner. This work was carried out with the Mark II burner design on behalf of Sydgas
and Helsingborg Energi in Sweden.
The combustion of this small quantity of natural gas was used to enhance the near burner
conditions required for NOx reduction ie high initial temperature coupled with low O2
concentration. This advanced co-firing system is to be installed in 1995 on a 60 MW
boiler targeted at a 0.1 lbs/106 Btu NOx emission level. (6)
During the Helsingborg development, a series of coals were fired both with and without
gas enhancement. With the low volatile coals, gas firing was required to achieve flame
attachment and low NOx operation. This contrasts with the 1C front wall burner design
which has been demonstrated to handle USA low volatile coals, down to 20% volatile
matter, without support fuel, in the low NOx mode. This is possible because of swirl
incorporated into the fuel secondary air which is not part of the T fired FAN burner
system.
The Helsingborg gas enhanced FAN burner showed a NOx reduction of 40% compared
with a datum burner configuration under the test conditions. Approximately _ of the
NOx reduction was achieved via the FAN burner and _ from the natural gas
enhancement.
Other factors which have to be considered in the development of a universal FAN burner
technology are the characteristics of the actual coals to be fired. A considerable data base
of the characteristics of world-wide coals has been built up by International Combustion
based on Thermo and Gravimetric Analysis (TGA) and Drop Tube Furnace (DTP)
techniques.
TGA as well as producing the basic proximate and ultimate coal analyses also
fingerprints coals in terms of their comparative reactivity which enables potentially
"difficult" coals to be recognised. DTP takes this a stage further by examining coals
under "flame conditions" identifying the actual rather than standard volatile matter
indicated by proximate analysis. DTP also enables the NOx producing tendencies of the
various coals to be compared.
-------
10 -
Properties such as the coal Nitrogen content and the Fuel Ratio (which is the ratio of
Fixed Carbon to Volatile Matter) are used as NOx indicators in a proprietary NOx factor
calculation.
Development work continues on FANs and their associated systems. The target of a 0.1
lb/106 Btu NOx emission level has already been achieved at full scale on the International
Combustion thermal test rig. Commercialisation at or below this level is now judged to
be an achievable target.
6. CONCLUSIONS
hi the T fired system, air staging with flame attachment has been shown to achieve very
low NOx emissions with control of unburnt carbon and CO emission levels.
Enhanced flame performance from the FAN nozzle which converts the T' fired coal
nozzle into a burner, further improves the performance and ensures that low NOx
performance is maintained throughout the load range.
The concept of flame management requires a deeper understanding of coal characteristics
in terms of reactivity, ignition and burning velocities plus the behaviour of the particulate
flow in addition to the basic coal properties. Thermogravimetric and drop tube furnace
technologies can be used for these evaluations.
Isothermal model work and computational fluid dynamics have been used successfully to
ensure that mixing patterns in air staged low NOx systems are acceptable and to study
particulate and velocity distribution in burner systems.
Advanced air staging and flame management techniques have been demonstrated
commercially as being capable of achieving satisfactory low NOx combustion in the T'
fired boiler.
Continued development of the FAN burner concept has potential for further reduction in
NOx levels with an extended range of coals. The burner can also be used in co-firing
systems with natural gas to enhance the NOx control aspects of the near burner region of
the flame.
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- 11 -
7. REFERENCES
1. RE Thompson. EPRI Report No. FP1109-SR. Palo Alto, California, USA.
July, 1979.
2. J W Allen. The Reduction in NOx Emissions from Corner Fired Power
Generation Boilers. European Seminar on Coal Combustion, London, UK.
February, 1992
3. J W Allen. The Proving and Potential of Advanced Corner Firing Technology.
EPRi/EPA Joint Symposium on Stationary Combustion NOx Control. Miami,
Florida, USA. May, 1993.
4. P G Hawksworth. Isothermal Model Tests to Determine Boiler Flow
Distributions - Dunkirk 1 & 2. International Combustion Technical Report No:
25751. September, 1993.
5. PR Beal, W W Wilhoit. Advanced Tangential Low NOx Burner. Development
and Results. PowerGen'94, Orlando, Florida, USA. 7-9 December, 1994.
6. J W Allen. Investigation into the Potential for NOx Emission Reduction using
Natural Gas - Pulverised Coal Co-firing at Helsingborg. International
Combustion. Internal Report No: 26148. November, 1994.
8. ACKNOWLEDGEMENTS
The invaluable co-operation and permission to publish operational data from the
following is gratefully acknowledged.
Niagara Mohawk Power Co - Mr M J Rhode
Southern Company Services and Georgia Power Co Mr W Holland
Thanks are also due to the Directors of International Combustion Ltd for permission to
publish this paper, and to colleagues for their contribution to this paper and the
combustion developments recorded in it.
-------
Dunkirk 1 and 2 - ISO Thermal
Furnace Model
INDUSTRIAL
POWER GROUP
INTERNATIONAL COMBUSTION
Figure 1
-------
INDUSTRIAL
POWER GROUP
Nox emissions for FAN burner nozzle
500
450
400
350
300
Nox (vpm)
adjusted to 3% O2 250
200
150
100
150
0
0
20
40 _ 60 80
Burner output - MMBTu/hr
100
- 0.70
0.60
0.50
0.40
0.30
0.20
0.10
0.00
Nox
(Ib/Million BTu)
120
INTERNATIONAL COMBUSTION
Figure 3
-------
INDUSTRIAL
POWER GROUP
Plant Yates - corner box schematics
post retrofit
Boiler Unit
YATES 4
YATES 5
YATES 6
YATES 7
EnviroNOx
System
FANS only
CCOFA +
FANS*
Offset
SOFA II +
Offset
SOFA II +
FANS +
Offset
CORNER
BOX
CONFIGURATION
FAN
FAN
FAN
FAN
FAN
FAN
FAN
FAN
OFA
OFA
OFA
OFA
OFA
OFA
OFA
OFA
FAN
FAN
FAN
FAN
FAN
DATE IN SERVICE
APR 1993
APR 1994
DEC 1992
MAY 1994
UvlTERNOTIONAL COMBUSTION
figure 4
-------
INDUSTRIAL
POWER GROUP
Flame attached nozzle
(FAN) burner
FLAME ATTACHMENT
NOZZLE
CONNECTING
LINK
FLAME ATTACHMENT
NOZZLE
LOCATING
PIN
OUTER SA
NOZZLE
PF DISPERSAL
DEVICE
SCARF PLATE
INTERNATIONAL COMBUSTION
Figure 5
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INDUSTRIAL
POWER GROUP
Yates #4
Nox vs O at full load
NOx
(Ib/MMBtu)
0.70
0.60
0.50
0.40
0.30
0.20
0.10
0.00
FAN Burner 11793
0.00
0.50 1.00
1.50 2.00 2.50
0
3.00
.3.50 4.00
4.50
5.00
IHTEF»NATIONA.1_ COMBUSTION
Figure 6
-------
INDUSTRIAL
POWER GROUP
Georgia Power Plant Yates
Unit 6 and 7 - Nox comparison
36
Unit 7 (prelim)
Unit 6 PGTs
Unit 6 baseline
100
INTERNATIONAL COMBUSTION
Figure 7
-------
Pulverized coal distribution at nozzle
discharge without RopeMaster™
INDUSTRIAL
POWER GROUP
INTERNATIONAL COMBUSTION
Figures
-------
INDUSTRIAL
POWER GROUP
Pulverized coal distribution at nozzle
discharge with RopeMaster™
JTERNATIONAL COMBUSTION
Figure 9
-------
PERFORMANCE OF A CONTROLLED FLOW/ SPLIT FLAME
LOW-NOx BURNER SYSTEM ON A TANGENTIALLY FIRED BOILER
E. L. Morris, Jr., P.E.
Wisconsin Electric Power Company
231 W.Michigan St.
Milwaukee, Wisconsin 53201
T. W. Sweeney
Foster Wheeler Energy Corporation
Perryville Corporate Park
Clinton, New Jersey 08809-4000
Abstract
Topic presented is the performance of a controlled flow, split flame, low NOx burner system
installed on a tangentially-fired furnace, identifying specifically the results of both short term
optimization testing and long term emission monitoring. This installation was the first time
application of the controlled-flow, split-flame (CF/SF) low-NOx burner design used on wall fired
boilers, to a boiler having a tangential firing design. Installation of this low NOx burner system to
the furnace occurred without the modification of waterwalls, or addition of separated overfire air.
Technical benefit achieved is reduction of fuel NOx production on a per burner basis in a
tangentially-fired boiler, with the burners operating at near stoichiometric conditions.
Combination of optimized burners along with vertical secondary air staging was found to provide
the desired emission reduction over the entire boiler load range. Ash LOI and unit efficiency
values were found to remain consistent with pre conversion, baseline data values.
Introduction
A first time demonstration project involving retrofit low NOx burners was undertaken beginning
in 1992 on the 310 MW, Unit 7 boiler at Wisconsin Electric's Oak Creek Power Plant, which is
located 20 miles south of Milwaukee on Lake Michigan. This demonstration project has been a
joint effort between Foster Wheeler Energy Corporation (FWEC) and the Wisconsin Electric
Power Company (WEPCo).
The Unit 7 boiler at Oak Creek Power Plant is designated as a Phase I unit under the 1990
Amendments to the Clean Air Act. The goal was to reduce NOx emissions on this unit to less
than 0.45 Ib./MBtu by January 1, 1995, with minimal impact on LOI and unit efficiency. Baseline
-------
readings taken prior to conversion in 1992 indicated that a 30 to 40 percent reduction in NOx
emissions would be needed across the entire load range to achieve this goal.
The objective of the demonstration project was to achieve the required emission reduction and to
confirm the adaptability of wall-fired low-NOx burner technology to a tangentially fired furnace
by developing a commercially offered tangential low NOx burner (TLNB) system. To accomplish
this objective, all of the original burners were replaced with retrofit burners of a prototype design
in the Spring of 1992. A production burner system was developed based upon the experience
gained from eighteen months of operational testing of the prototype TLN burners, and was
installed to replace the prototype burners on Unit 7 during a scheduled turbine overhaul outage in
the spring of 1994. Table I provides a chronology of project phases.
TABLE I
CHRONOLOGY OF PROJECT PHASES
Test Phase Activity Time Period
Baseline Testing a. Obtain baseline data Dec. 1991 -Jan. 1992
Prototype TLNB a. Original Burner Removal and Prototype Feb. 7 - May 29, 1992
TLN Burners Installed
b. Testing Prototype TLN Burners Alone July - Aug. 1992
c. Testing Prototype TLN Burners W/SAS* Sept. - Oct. 1992
^Secondary Air Staging created through
ndary Air Staging created through
idle top burners )
d. Duplication of above prototype tests on Nov. - Dec. 1992
state sulfur compliance coal
TLNB System *. Removal of Prototype TLNB & Nov. 29, 1993 -
Installation of Production TLNB System Mar. 7, 1994
b. TLNB System initial optimization period Mar. 7 - June 1, 1994
c. TLNB System final optimization period Oct. - Dec. 1994
d. TLNB System installed on Oak Creek Jan. - April 1995
Unit 8.
Unit Description
Oak Creek Unit 7 has a four corner, tangentially-fired, pulverized coal furnace of controlled
circulation design. Manufactured by Combustion Engineering Corp. in 1965 as a pressurized
furnace, the unit was converted to balanced draft in 1970. The boiler is rated at 2 x 10 Ibs/hr.
evaporation at 2,620 psig, with steam conditions of 1050/1000 °F for the superheat/reheat
temperatures. Twenty pulverized coal burners, on five levels, are supplied by five CE model RPS
683 bowl mills of a pressurized-exhauster design. Auxiliary start-up and coal ignition fuel was
switched during the subject burner retrofit from two levels of oil to five levels of gas.
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TLN Burner Description
The windbox is partitioned with division plates. Flow is regulated for each partitioned burner lane
by a secondary air damper and proportioned into three zones to create staging at the burner. The
controlled flow is measured by flow elements installed in the primary and secondary air systems.
The flow to the secondary air staging level and burners is shown schematically in Figure l.The tip
of the burner has a tilting split flame design. Arrangement of a single burner cell is shown in
Figures 1 and 2.
Figure 1
TYPICAL SECONDARY AIR SYSTEM
FOR A TLN BURNER MODULE
SECONDARY AIR
STAGING DAMPER
—, SECONDARY AIR FLOW
SECONDARY AIR
STAGING NOZZLES
ADJUSTABLE
AIR NOZZLE
TLN BURNER
ADJUSTABLE
AIR NOZZLE
BURNERS?
DIVISION PLATES
SECONDARY AIR
DAMPER
PROPORTIONING DAMPER
L WINDBOX FLOOR PLATES
-------
Figure 2
TYPICAL CORNER ARRANGEMENT OF TLN BURNER MODULE
OUTER SLEEVE W/
ANTI-ROPING BARS
INNER SLEEVE —
SCROLL
COAL& PRIMARY AIR
INLET
WINDBOX
BUR HER55
WINDBOX FLOOR PLATES
I- ADJUSTABLE AIR NO22LE
ADJUSTABLE
COAL NOZZLE
IKJH
L- ADJUSTABLE AIR NOZZLE
VIEW FROM FURNACE
WINDBOX FLOOR PLATES
Figure 3
TANGENTIALLY FIRED LOW NOx BURNER (TLN)
MODULE ARRANGEMENT
SECONDARY AIR PITCH NOZZLES
CAST TRANSITION PIECE
TILTING SPLIT FLAME NOZZLE
INNER SLEEVE
SCROLL
VIEW A
FROM FURNACE
DIVISION PLATES
-------
Performance
Initial Comparison
Table II shows a comparison of the baseline operating data with the prototype TLNB system.
This is provided for comparison of unit operating data to show that there was little or no change
from the acceptable baseline, pre conversion test data, when operating on the midwestem
bituminous coal fired during the testing of the prototype TLN burners.
TABLE n
BOILER PERFORMANCE COMPARATIVE DATA ON MIDWESTERN BITUMINOUS COAL
Parameter
Load(MW)
FW Flow (KPPH)
SH Spray (KPPH)
RH Spray (KPPH)
Throttle Press. (psig)
MS Temp.(°F)
RH Temp. (°F)
NOX (Ib/106 Btu)
Unburned Carbon(%)
CO (ppm)
BASELINE VERSUS PROTOTYPE TLNB
Baseline
300
1816
53
40
2402
1061
1013
0.68
9.19 @ 4.2% O2
20-40
TLNB
300
1824
42
46
2404
1043
1003
0.38
8.0 @ 3.5% O2
20-40
Performance Following 1992 Coal Change
Coal was switched in the fall of 1992 from midwestern bituminous (1.6 percent sulfur, 6.8 percent
ash, and HHV of 13,850 Btu/lb.) to a western bituminous coal (0.6 percent sulfur, 13 percent ash,
and HHV of 13,000 Btu/lb.). This was to comply with a state fuel sulfur limit. Volatiles and fixed
carbon for both coals were similar.
A change in performance was seen on all four furnaces at Oak Creek. On Oak Creek 8, the
"sister" unit to Oak Creek Unit 7, which had not been modified to a low NOx burner system, it
was noted that the spray requirements were diminished. Inability to repeatedly obtain desired
reheat and superheat temperatures on Unit 7 was observed. Ash deposits on the furnace walls
were noted to be drier and less adherent to the walls. The sheets of dry ash were also noted to be
"self shedding." A problem in the prototype burner tilts restricted effective temperature control.
Performance of Production TLN Burner System
Burner Tilts. Improvements in the coal nozzle tilt design permitted the production burners to
achieve the design steam temperatures by means of controlled burner nozzle tilt.
Ask Deposits. The ash deposit pattern in the furnace was noted to have changed from the
baseline, pre conversion pattern. The furnace walls were notably cleaner, and with the stable low
NOx burner ignition point being closer to the burners, there is a feeling that more heat is being
-------
absorbed by the waterwalls. Flyash LOI was similar to values on the non-converted sister unit,
Oak Creek Unit 8, and averaged in the range of 3 to 5 percent LOI.
Ash Characteristics. The original higher excess oxygen carried on the pre conversion furnace of
4.2% O2 provided a much more radiant fire, and the ash on the walls from the midwestern coal
was noted to glaze and become more adherent to the tubes than the drier western coal ash.
Steam Temperatures. Selective soot blowing of the rear convective superheat elements, along
with the furnace exit aperture reheat bundles, was found to enable design steam temperatures of
1050 0F/1000 °F (superheat/reheat) to be maintained at full load. Temperatures are not a problem
at low load. Soot blowing in the furnace was found to reduce steam temperatures.
Exit Oxygen and Furnace Temperature Profiles. The furnace exit oxygen and steam
temperature profiles across the furnace are more even following the balancing of air flows to each
burner. Evidence of a more uniform gas flow was confirmed by the lack of a higher ash wear area
that had typically been observed during outages on the pre-conversion furnace.
Flame Stability. Balancing of air flows to each burner also resulted in more stable flames at low
load and eliminated what is referred to as "cold corners", which were burners on the pre-
conversion unit that had an ignition point farther from the corner.
Emission Test Results
Short Term, Single Point Test Results
Table III shows the best repeatable results obtained for the short term, single load point
optimization testing. Single point tests were each two hours in length with the a test variable
controlled. A test matrix was followed to determine the effects of altering the test variable. All
end of day tests were repeated on the following day of testing to ascertain that conditions could
be repeated. A total of 152 tests were conducted on 70 non-consecutive test dates to define the
response of the new burner system to variations in adjustable parameters.
TABLEm
OAK CREEK UNIT 7 TLN BURNER DEMONSTRATION RESULTS SUMMARY
NOX (Ib/MBtu) EMISSIONS VERSUS LOAD (MW) COMPARISON
NO* Emissions Ib./MBtu
Test Phase Low Load Medium Load Full Load
(Dates) (125 MW) (230-260 MW) (260-300 MW)
Baseline (pre conversion) 0.67 0.61 0.68
(12/91 - 1/92)
Production TLNB - 0.31 0.28 0.35
(3/94 - 12/94)
-------
Long Term Emission Test Results
Table IV displays the unit CEM hourly averages at each 10 megawatt load point along the daily
load curve of Oak Creek Unit 7 for the period of January 1, 1995 to March 15, 1995. The data
for this 74 day period was obtained from certified stack CEM data. For comparison, the rolling
hourly average for the unit during the first two months of 1995 was 0.364 Ibs.NOx/mmBtu.
Table IV
WEPCO
Oak Creek Unit?
Jan - Mar 1995
NOx vs Load
hourly data averaged over 10 MW intervals
0.65
•+~f
m
^
CO
0.60 -
0.55 -
0.50 -
0.45 -
<* 0.40 -
0.35 -
0.30 -
0.25 -
0.20
95% regression
confidence
interval
2nd order
"regression
l ( i I I i i
125 150 175 200 225 250 275 300 325
Load, MW
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Conclusion
The goals of the demonstration project have been achieved. A production burner system was
developed and unit performance has been acceptable while achieving low NOx emissions. Final
tuning of boiler controls is in progress. Conversion of the similar Oak Creek Unit 8 tangentially
fired furnace to an identical low NOx burner system has been accomplished and that unit is going
into service in mid - April 1995.
References
1. Eskinazi, D., 1993, "Commercially Available Retrofit Combustion NOx Controls", "Retrofit
NOy Controls For Coal-Fired Utility Boilers ," Vol. TR-102071, Electric Power Research
Institute, Palo Alto, Calif. , pp. 5-1 to 5-51.
2. Morris, E. L., and Sweeney, T. W., "Development Of A Tangentially Fired, Controlled Flow,
Split Flame Low-NOx Burner System On A Coal Fired Utility Boiler," Presented at Electric
Power Research Institute, "Workshop On NOx Controls for Utility Boilers", Scottsdale, AZ ,
May 1994.
3. Morris, E. L., and Sweeney, T. W., "Application Of Controlled Flow, Split Flame Low-NOx
Burners On A Tangentially Fired Boiler," Presented at the ASME Joint International Power
Generation Conference in Phoenix, AZ , October 1994.
4. Vatsky, J. ,1993, "Attaining The Clean Air Act NOX Requirements On Wall-Fired &
Tangentially-Fired Steam Generators," Presented to representatives of EPA, and DOE, Oak
Creek, WL, January 21, 1993.
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LOW NOx FIRING TECHNOLOGY OF MITSUBISHI HEAVY INDUSTRIES
Shozo Kaneko; Kimishiro Tokuda; Susumu Sato;
Tadashi Gengo; Koichi Sakamoto
Mitsubishi Heavy Industries, Ltd.
3-1, Minatomirai 3-Chome, Nishi-Ku, Yokohama 220 Japan
Abstract
This paper presents super low NOx combustion technologies successfully developed by MHI
(Mitsubishi Heavy industries, Ltd.) and its use in practice.
PM (Pollution Minimum) burners directly reduce NOx from the burners themselves and MACT
(Mitsubishi Advanced Combustion Technology) system, an in-fumace NOx removal system,
reduces NOx generated from the main burners within the boiler. These firing systems are
applicable to coal, oil, gas and also to other exotic fuels like Orimulsion or CWM(Coal Water
Mixture) . MRS (Mitsubishi Rotary Separator) mills minimizes unbumt carbon with its reliable
ultra-fine grinding of coal and hence contribute to low NOx.
These technologies have been applied in various combinztions to 227 boilers for both new
installation and retrofit jobs. Large 1,000 MWe oil or gas fired boilers and 700 MWe coal fired
boilers have been put into commercial use, and a 1,000 MWe coal fired boiler is under
commissioning. The technologies have been applied to small sized boilers for industrial use as
well. All the delivered systems have been working both domestic and overseas to the
customers' satisfaction.
Introduction
Reduction of NOx emission has been and will be a very important issue from the viewpoint of
environment preservation. The worldwide tendency is toward reducing NOx emission from
thermal power stations as well as other sources. Fig. 1 shows the Japanese governmental
regulation on NOx emission applied to new large plants. It was first enforced in 1973, amended
four times and has become severer with every amendment. Due to the keen interest of the
population around the power plants, emission levels severer than governmental regulation are
actually applied. Corresponding with such tendency, MHI has continuously developed new low
NOx firing technologies.
The latest Mitsubishi Low NOx System is shown in Fig. 2 as a whole set. Each system can be
supplied individually or in combinations according to the required NOx level. Based on results
from our test furnaces and abundant experiences in the field, NOx level of PM burners are, 20
to 40 ppm for gas, 75 to 100 ppm for oil and 100 to 200 ppm for coal. MACT combined with PM
burners can still further reduce it to 10 to 20 ppm for gas, 45 to 60 ppm for oil and 60 to 150
ppm for coal. MRS mills, which contributes to the reduction of unburnt carbon in fly ash, can
reduce NOx to 60 to 100 ppm for coal in combination with PM and MACT with same unburnt
carbon level as for a fixed separator mill. This is summarized in Fig. 3.
Concept of PM Burner
As pure diffusion combustion has its limits in application of low NOx oil firing, a NOx reduction
theory based on theory of premixed combustion and concept of offset firing was considered.
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Fig. 4 shows the principle of NOx reduction of the PM burner. It forms a fuel-rich flame and a
fuel-lean flame. In case of gas firing where flame is formed as a premixed flame, NOx of the
two flames are obtained at "C-j" and "02" Overall NOx becomes "C" as a mean value for PM
burners which is substantially lower than NOx "B" by conventional burners at same overall
excess air "X". For liquid fuels, diffusion combustion occurs in the fuel-rich zone to produce
stable combustion. The overall NOx, therefore, becomes "C"" as the mean value. It is also
much lower than "A" of conventional burners.
When firing coal, NOx changes according to ratio of primary air/coal. Dividing flame into two
types contributes to achieving low NOx in a similar manner as the oil or gas fired PM burner.
The PM burner is applicable to both circular and opposed (or front) fired boilers. Structure of
the burner nozzles and burner configuration are designed to have shapes which fully realize the
ability of NOx reduction. Furthermore, they can be arranged exactly to fit existing boilers in
case of retrofit jobs, considering the NOx level requirement and furnace designed.
Typical configuration of PM burners for the circular corner firing is shown in Fig. 5. For oil PM
burners, specially designed atomizers produce two oil spray patterns, inner sprays for fuel-rich
flame named 'Cone' (concentrated) and outer sprays for fuel-lean flame named 'Weak'.
Separate gas recirculation SGR, depending on various conditions like NOx, steam temperature
control, etc., is injected above and below the oil burner ports if required. The inner spray ignites
simultaneously with mixing of fuel and air and forms the diffusion flame. On the other hand,
ignition of the outer spray is delayed and takes place after mixing with air from auxiliary air
ports. This process is like premixed combustion. In this manner, two types of flames are formed
and NOx is suppressed according to the PM principle.
Coal PM burners are equipped with separators at burner inlet as shown in Fig. 6.The separator
divides coal and air mixture in the coal pipe into two different ratio of primary air/coal. The
Cone nozzle is provided with a unique flame holder at its outlet to stabilize the Cone flame,
which in combination with the lower air to coal ratio in the Cone burner, show remarkable
changes in burner characteristics, especially ignition stability, heat flux distribution and furnace
heat absorption, from older comer fired burners. Gas recirculation is used only for occasions
where the range of coal quality requires it.
Concept of MACT
We conducted series of experiments in our laboratory to develop optimum MACT configuration,
which utilizes the entire furnace volume as the reducing zone, to confirmed the NOx reducing
mechanism described by the following chemical reactions;
CmHn + O2 -* Cm'Hn'* + CO + H2O
NO + Cm'Hn1*-* Cm"Hn" + N2 + CO + H2O * : Radicals
NO + Cm'Hn'*^ Cm"Hn" + NHi + CO + H2O NHi : Compound of N & H
Two sequential reactions, NOx reducing reaction and bum-out reaction occur in the two
reaction zones above the main burners as shown in Fig. 7. A part of fuel extracted from main
fuel is injected from UB (Upper Burner) with recirculation gas and used as a NOx reducing
agent by supplying hydrocarbons into a reducing atmosphere. A part of air named AA
(Additional Air) is extracted from main air and used to bum out remaining unburnt combustibles.
Buming-out of the unburnt is completed between the AA and the furnace outlet.
Further efforts were made to apply MACT to coal firing, where usage of upper burner fuel is
more complicated. If one uses coal for upper fuel, the system becomes complex and more
prone to having high unburnt, and if one uses oil or gas, the economy is the question. So we
developed Advanced MACT system, the concept of which is shown in the right side figure of
Fig. 7. In Advanced MACT there is no UB because we found out that the hydrocarbons carried
over from the main burner zone has good reactivity in the reducing zone. It almost can get the
same NOx reduction effect as UB-MACT by controlling the amount of air in the main burner
zone and the reducing zone by over-fire air and the AA.
-------
Concept of MRS mill
The characteristics of the MRS mill is shown in Fig. 8. It is equipped with a forced rotating
separator instead of a fixed conventional cyclone separator. Pulverized coal carried up to the
upper part of the mill is classified by centrifugal and impinging forces generated by rotating
vanes and the fines are led to burners. Coarse particles separated from fines fall back onto a
grinding table and re-ground. Fineness can be properly adjusted for different coals by adjusting
rotating speed of the vane.
Fig. 9 shows the relation between the amount of particles through 200 mesh and residue on
100 mesh. Residue on 100 mesh that affects unburnt carbon is extremely reduced by MRS.
Same principle can be applied to tube mills to achieve extremely good fmess with substantially
lower power than normal tube mills, which is attractive from viewpoint of maintenance (Fig. 10).
Field application and demonstration ofPM, MACTand MRS
As the result of various combustion and pulverizing tests conducted in our test facilities and in
the field, we achieved remarkable reduction in NOx and unburnt carbon.
Experiences with utility boilers are show in Fig. 11. NOx could be reduced to about or less than
half of conventional burners, and we are still on the way to drastically improve the technology
by refining and simplifying the systems or by totally new ideas to realize the concept.
Fig. 12 is a trend chart of a 600 MW oil and coal mixed firing boiler equipped with the MACT.
NOx was dramatically changed to half when the UB-MACT was use. Fig. 13 also shows NOx of
the boiler. Excellent low NOx was achieved with the MACT. As the boiler is equipped with the
oil firing PM burners as well as the MACT, very low NOx was obtained solely by the PM
burners even when the MACT is out of use.
MHTs experiences in low NOx firing with large capacity coal fired boilers equipped with PM,
Advanced MACT(A-MACT) and MRS are presented in Fig. 13. The data plotted on the figure
are from boilers which are supercritical sliding pressure operation boilers ranging in size from
500MW to 1000MW, firing various kinds of coals and have high load changing capability
corresponding to middle load use like DSS (Daily Start-and-Stop) operation. They show
excellent operation capability since commercial operation. They achieved quite low excess air
operation(about 15% ) over a wide load range and it contributed to low NOx performance as
well as high efficiency. NOx was very low as shown for mainly Australian coal and we can
summarize that we achieved the following. (Unburnt carbon is 2 to 3% in flyash or even less.)
(1) Stable ignition by PM allowed very low excess air in main burner zone.
(2) Optimum air supply ratio to OFA/AA maximized NOx reducing effect by A-MACT.
(3) High fineness obtained by MRS contributed not only to low unburnt carbon, but also to
low excess air and low NOx.
(4) The latest design philosophy applied to the 10OOMW unit reduced the NOx as much as
15% from previous units.
CUF(Circular U-shaped Firing) System
CUF systems have the following features, which make it a very attractive circular firing system.
1. Firing with longer flame path assures low unburnt carbon.
2. Ignition stability is substantially improved and excess air in the primary combustion zone can
be reduced more than a conventional circular firing system(CCF) which results in lower NOx.
3. Because of the high stability of ignition, application to very low volatile coal firing, even
anthracite is possible.
Fig.14 shows the basic principle of the CUF system. The relatively high radiation heat flux and
the U-shaped flame path ensures longer residence time in the same sized furnace compared to
the traditional circular corner firing most manufacturers apply, giving the CUF the advantages
mentioned above. Fig.15 shows the comparison of test result in a test furnace for CCF and
CUF showing substantial quantitative differences. Fig16. shows the low load capability of the
-------
CUF system compared to other systems. Fig, 17 is an actual application to an industrial boiler.
Conclusions
As described above, we have developed a series of NOx reducing technologies and already
put quite a number of them into commercial use with customers' satisfaction. These
technologies have been used not only by MHI alone, but also by licensed manufacturers
throughout the world. The concept and technology has been refined year by year and the NOx
level achieved to date are exteremely low. We are developing still better technology for the PM
and MACT concept to get the best performance out of these innovative firing systems. We
hope our low NOx technologies will contribute to the environmental protection in the United
States and other parts of the world.
-------
1000
a
a.
x
O
10
Private
Voluntary 1W 2nd 3rd 4th(Only for Small Facilities) 5th Governmental
Regulation 1111 1 Re9ulation
^mmm
wm^mm
30
tj_20
°».
-_-
"\
"V-
180
MMMH
130
=t
480
1i
1(
|
0
r-i
30
[CC
(0
AL)
IL)
[GAS]
400
|
300
20(
13(
6C
3 (c
)
%Ex.
02)
(4%Ex.p?)
)
(£
i%Ex.
02)
'70 '71 '72 '73 '74 '75 '76 '77 '78 79 '80 '81 '82 '83 '84 '85 '86 '87 '88 '89 '90
Year
Fig.1 NOx Governmental Regulation for New Large Plants in Japan
-------
Fig.2 Mitsubishi deNOx System
a.
^f^-f-^^^fff^^f^'-'-f-^Get .Low NOx Burmr it SCR Siiii
100h
•72 '73 '74 '75 '76 '77 '78 '79 '80 '81 '82 '83 '84 '85 '86 '87 '88 '89 '90 '91
Year
Fig.3 History of MHI1 s Low NOx Technology
-------
IF AIR SUPPLY IS
REDUCED
THIS LEVEL,
UNBURNED COMBUSTIBLE
WILL BE FORMED
O
^
i
PREMIXED COMBUSTION
DIFFUSED COMBUSTION
THEORETICAL!
AIR RATIO \l
TOTAL OPERATING
XEXCESS AIR (X)
FUEL-RICH
10
EXCESS AIR
FUEL-LEAN
Primary Air/Coal Ratio
t
Conventional Flame
C0 3—4 C2 7—8
Primary Air/Coal Ratio (kg/kg Coal)
Oil and Gas
Coal
Fig.4 NOx Reducing Principle of PM Burner
-------
Windbox Damper
Fuel Oil
I Auxiliary Compartment
SGR Compartment
Fig.5 Oil PM Burner for Corner Firing
-------
Oil
Aux.1
SGR
Cone
SGR
Weak
Aux.2
OH
Front View
Sectional Side View
Separator
Fig.6 Coal PM Burner and Separator
-------
AA —
UB —
OFA —
y
Main ^ —
Burner |
Furnace
Outlet p-—-""
^\
x'" "X
/ \
/ Combustion \
Completion !
\ Zone /
\ /
+• /' Active \ -*
/ Hydrocarbon \
I Existing /
*• \ DeNOx Zone / "+
^ — . ; **
>- -<
>- ^^ ~~ Main X -<-
/ Burner \
>t Completed ^-*-
\ Combustion /
— AA —
— OFA —
/
_ Main I
Burner
Furnace
Outlet ^^"
_^\
/ \
/ Combustion ^
| Completion /
\ Zone /
v s
+- ^ -^ -<-
f DeNOx \
I Promoting j
\ Zone /
•**> /-*
-^ /"'IWaln^^N ^<-
»x Burner \
"*j Burning & 1 "*
\ Activation /
*x^ ^
MACT System
Advanced MACT System
Fig.7 Concept of A-MACT
-------
Pulverized Coal
to Burner
Mitsubishi
Rotary Separator •<
L,
\
Primary
Fig.8 Structure of MRS Mill
CO
OJ
O
O
c
O
OJ
3
XJ
to
0)
4
3
2
1
0
Conventional Mill
"MRS Pulverizer"
95
Thru 200 Mesh (%)
Fig.9 Coal Fineness Obtained by MRS Mill
-------
MRS
1ry Air
^J Pulverized Pulverized £
Coal Coal
Mill Drum
£/
$»> ....... . .-. .-.-^Rv^-.-.-.^-^v.v.-.-^
(ftffAfitffffttfMNffMefffftffffffffffl
Tu*u?yA'u\'j\.. .i.iX.'.'.'.'.^-^.MjA.'.^j'j'j'.'.'-'-'w.'j
VX-fofli^^
J=
30
c
o
+3
D.
E
iCoai\
Bit. A
Anth. B
Anth. c
Anth. D
Bit. E
Conv.
o
A
X
iMRS
•
A
•
+
80 90
#200 Pass (%)
100
Fig.10 MRS Tube Mill
-------
Low NOx Conversion (Coal Fired Corner Firing)
E
o.
Q.
fO
-O
O
\p
Fuel : Heavy oil (N = 0.18%)
C
O
in
i/i
X
O
150
100
50
• ^ Conventional burner
25
_L
50 75
Boiler load (%)
100
400
200
Before
Modification
After
Modification
Fig.11 Low NOx Performance of PM Burner
-------
160
140
E 120
a
a
-------
140
120
»p
-------
New low NOx CUF system
Conventional system
SSS^Good
AA
nozzle
NOx decomposition
Fig.14 Burner Arrangement in CUF
and Corner Firing Systems
-------
140
120
1100
Q.
CD
to
CM
O
c
CD
O
O
O
X
o
80
60
40
20
0
NOx
03
O
CO
i_
J3
c.
Z)
Conventional boiler
Coal
02
AA ratio
Daido coal
4%
25%
NOx
Low NOx CUF boiler
Coal
02
AA ratio
Daido coal
4%
40%
10
8
to
ro
6 ^
c
o
-O
T3
CO
-Q
ID
0
Fig.15 Comparison of NOx and Unburned Carbon
between CUF and Circuler Corner Firing
-------
100 -
90
I 80
70
00
•S 60
o 50
T3
-------
1995 EPRI/EPA Joint Symposium on Stationary Combustion NOX Control
Impact of Secondary Air Distribution on
NOX Generation Rate in large Utility Boilers
Tennessee Valley Authority
L. Fuller, R. Trammel, E. Harshbarger, M. Kaler, P. Tingle
Radian Corporation
T. Rizk, T. Kosvic
Abstract
NOX generation rate in a boiler is a function of the fuel type, the fuel combustion mechanism and
the quantity and distribution of air supplied to the combustion chamber. This paper addresses the
latter issue. Secondary air flow bias is typically caused by air heater fouling, approach duct
geometry, and windbox geometry. Bias in the secondary air distribution creates fuel rich regions
along side fuel lean regions in the boiler. .This results hi incomplete combustion, high NOX
generation rate in the fuel lean regions, excessive slag and corrosion. This paper presents the
results of a study conducted at the TVA Shawnee Fossil Plant on the impact of the secondary air
flow bias on boiler performance and NOX generation rate. The study utilized an integrated approach
using field test data, physical model tests, and numerical simulations using the Radian Furnace
Simulation Model. Limited by the unit forced draft fan capacity, the study focused on low cost
modifications resulting in improved boiler performance with minor fan pressure losses. The
numerical simulations produced modest reduction in NOX generation rate.
INTRODUCTION
The coal boiler secondary air flow distribution at the burners and the windbox pressure
losses are controlled by the air heater fouling, the approach duct geometry, the windbox
geometry, and the burner register settings. Extreme register settings could divert flow
from one burner to the other, with large associated pressure losses. Biases in the
secondary air flow distribution have been linked to reduction in the combustion
performance efficiency, increased NOX generation rate and increased slag in the
combustion chamber. Given the physical plant confining space, construction costs,
and fan capacity limitations, a well designed windbox would provide nearly uniform air
flow distribution at the burners. The registers are then used to optimize the secondary
air flow velocity into the combustion chamber. Optimal secondary air inlet velocity is
dictated by the coal composition and the operating load. Previous studies (B&W, 1991)
-------
of this problem have shown that NOX generation rate can be reduced by as much as
20% with an optimized windbox.
The Shawnee Steam Plant (SHF) Units 1-9 are coal burning, 150 MW, front wall,
concentric firing boilers. Each unit is divided into two sections. Each section has 4
rows of burners. Each row consists of two burners. A schematic representation of a
typical SHF unit is shown in Figure 1. The air is supplied to each side of each unit via
an axial flow, fixed blade forced draft fan. Each fan was designed to deliver 208,000
cfm at 10.8" SP (Figure 2). Currently, each fan is operated in the range of 240,000 cfm
to 300,000 cfm. The secondary air flow bias in the windbox is due to duct geometry
downstream of the air heater, air heater fouling, and windbox geometry. Due to the
variable extent of fouling and localized variations in duct layout, each side of each unit
exhibits different duct bias. However, common geometric denominator includes flow
separation and biasing due to a sudden drop and a sudden lateral change in direction,
and a 26 inch I-beam obstructing the flow field. The result is adverse magnification of
the airflow bias. This maldistribution manifests itself in low air flow rate at burner levels
B and C. This bias is suspected to be the root cause of low combustion performance at
levels B and C producing slag [burner eyebrows] and water wall corrosion.
Repeated attempts were made to improve the windbox air flow distribution in these
units. The first modification to the windbox on all the units was implemented in 1972.
The modification consisted of a set of vanes in the windbox of each unit. The vanes
were intended to redistribute the flow field in the windbox, near the burners. Since,
additional vanes were installed in the windboxes of these units without successful
resolution to the flow distribution problem. These vanes adversely impacted the
windbox head pressure losses, adding 2 inch w.g. to the total windbox pressure losses.
The result of the reduced windbox pressure head is reduced combustion performance
and increased likelihood of windbox fires.
The above mentioned vanes were intended to resolve the flow maldistribution
downstream of the windbox duct; i.e., attempting to restore a disturbed fiow field.
However, significant savings are obtained by preventing the flow field from being
disturbed. This is accomplished by placing vanes in the approach duct, and guiding the
air into the appropriate burner levels. This approach is the basis of the problem
resolution strategy.
The recommended windbox optimization strategy is constrained by minimum physical
changes to windbox geometry, low construction costs, physical space, and fan capacity.
SOLUTION APPROACH
The problem resolution strategy consist of
1) assessment of previous SHF secondary air flow distribution studies,
2) development of optimal windbox vane design using physical model techniques,
-------
Figure 1
SHF Burner and Boiler Layout
West Secondary
Air Inlet Duct
1
A O
B O
O
O
O O
O O
East Secondary
Air Inlet Duct
-------
Figure 2
TVA Shawnee Steam Plant
Forced Draft Axial Fan Performance Curve
14 PITT
205,000 CFM
10.8" SP
497 BHP
1,100,000 Ibs Steam
155,500 CFM
8.2" SP
1,000,000 Ibs Steam
143,500 CFM
6.95" SP
363 BHP
Current Plant
Operating Range
120
160
200
240
280
320
360
CEM, 1000s
American Standard Industrial Division
#900 SISW Series B2 US Fan
with Inlet Boxes, Louvre Control
707 RPM
345' Elevation
-------
3) evaluation of NOX generation and slag and corrosion potential using the Radian
Furnace Simulation Model.
The objective of this work is to improve the windbox air flow distribution to achieve the
following goals:
i) minimize fan pressure losses;
ii) optimize secondary air flow rate to each burner;
iii) reduce NOx emissions;
iv) reduce slag and corrosion in the combustion chamber.
Assessment of field data
The SHF data consisted of a series of hot air velocity traverses taken at the entrance to
the windbox. A summary of the resulting relative volumetric flow rates to each burner
level are presented in Table 1 for boiler units 3, 4, 8, and 9. The data shows that burner
levels A and D receive an average of 63% of the total air flow, with burner level C
receiving less than 16% of the total air flow as shown in Table 1. The low air flow to
levels B and C is due primarily to flow separation around the I-beam.
The proposed design was developed with careful attention to the available fan head,
and the system losses. Figure 3 shows the system curve of the plant forced draft fans.
These are fixed blade, axial fans. The fan test block was based on 208,000 cfm at
10.8 in w.g. static pressure, with 497 BMP at 140 degrees F. The operators logs
indicated that these fans are operating in the range of 240,000 to 300,000 CFM at 8.5
to 2.3 in. w.g. static pressure. The air heater pressure losses are about 3 to 5 in. w.g.
Prior to 1972, the windbox pressure losses were about 0.4 in. w.g. Installation of
various vanes and shrouds increased the windbox pressure loss by up to an additional
2 in. w.g. Thus, little to no pressure head remained at the secondary air registers
resulting in low velocity head available to drive the flame away from the burners. This
condition is conducive to slag at the burner wall (eyebrows) and windbox fires.
The new vane distribution system is intended to reduce windbox pressure losses
and thus aid the coal combustion performance. Improved combustion efficiency at, or
perhaps lower, mean combustion temperature should reduce NOx generation rate,
combustibles in the convection pass, and reduced slag and corrosion.
Physical model setup
A Plexiglas 1:15.8 cold flow physical scale model of the Shawnee Unit 2 boiler and
secondary air flow system was constructed at the TVA Engineering Laboratory. Air was
supplied from a bi-axial fan with maximum capacity of 125 cfs. The fan air flow was
determined from a differential pressure nozzle calibrated at 60 degrees Fahrenheit.
The actual model air flow rate was corrected to the ambient temperature using the ideal
gas law. The model tests were completed at model flow rates above 30 cfs with a
model Reynolds number above 50,000 [well into the fully turbulent regime]. The
-------
i
TABLE 1
Secondary air flow distribution at four SHF units
All tests at Full Load (138 MW-150 MW), Secondary air temperature ranges from 620 F-650 F
Hot air volumetric flow rate (cfm) data was collected at Shawnee Steam Plant for Units 3,4,8,9
Units ! 7-12-72
Burner : Flow rate
level fraction
A
B
C
D
Sum
Units
Burner
level
A
1.45
0.81
0.65
1.09
7-18-72
Flow rate
fraction
1.72
B 0.90
C 0.47
D 0.91
Sum
West side
111532
62097
49948
83622
307198
West side
75250
39250
20625
39625
174750
East side
112059
63447
46914
85661
308080
East side
41250
25750
18375
37875
123250
1.45
0.82
0.61
1.11
1.34
0.84
0.60
1.23
Unit 4
Burner
level
A
B
C
D
Sum
Unit 9
Burner
level
A
B
C
D
Sum
1-3-73
Flow rate
fraction
1.45
0.94
0.63
0.99
7-24-73
Flow rate
fraction
1.23
0.79
0.76
1.22
West side
1 1 4025
73675
49378
77698
314776
West side
43250
28000
26625
43125
141000
East side
105388
71001
55716
84706
316811
East side
70750
36000
23250
39250
169250
1.33
0.90
0.70
1.07
1.67
0.85
0.55
0.93
-------
burners were modeled using a modified form of the Thring-Newby criteria. The model
results were extrapolated to the prototype conditions using Euler's scaling criteria.
The maximum and minimum velocities, and the coefficient of variance are computed for
each case. Computed values are normalized to the mean mass flow rate in the inlet
duct. The final design velocities and variances are normalized to the mean air
volumetric flow rate in each burner level. The system pressure losses are measured for
each case and evaluated in light of available fan capacity.
Numerical Model Setup
The Radian Furnace Simulation Model (FSM) is a full capability, three dimensional,
Computational Fluid Dynamics (CFD) model. The model solves the fluid flow, heat and
mass transfer equations using the Control Volume method implemented in the
PHOENICS code developed by and distributed by CHAM Limited. The Radian FSM
solves an additional set of coal combustion and chemical equilibrium equations
compiled and implemented by Radian Corporation. The code accurately predicts the
furnace flow field, thermal profile, combustion kinetics, NOX generation rate, and boiler
wall slag and corrosion. The FSM has been successfully applied to radiant type, front
wall and rear wall coal furnaces as well as CE tangential fired units. The model predicts
the following boiler parameters and operating conditions:
• furnace temperature profile
• furnace flow field velocity profile
• furnace coal combustion rate profile
• furnace NOX generation profile
• unbumed carbon at the furnace exit
• O2 at the furnace exit
• furnace exit gas temperatures
• furnace slag potential
• furnace tube corrosion potential.
The Radian FSM was adapted to a the west side section of SHF Unit 6. The results of
the simulation are directly applicable to the other units. The model consists of 18X24
cells in the lateral domain, with 47 cells in the vertical domain. The model input allows
for burner to burner variation in coal feed rates, primary air mass flow to coal mass flow
ratios, and secondary air distribution. The secondary air to each burner is input from
the physical model test results for the original windbox layout and the new segregated
windbox design. The numerical analysis evaluates the impact of load, secondary air
bias and orientation on NOX generation rate, slag and corrosion. The simulated boiler
scenarios are designed to evaluate the impact of
1) reducing load,
2) reducing excess oxygen,
3) improving secondary air register bias.
-------
4) and modifying the swirl generators to carry the combustion gases up the wall.
Each computer run provides the following information:
1) flow velocity profiles at various planes in the furnace,
2) thermal profiles at these planes,
3) average flue gas exit flow rate,
4) average NOx concentration at the furnace exit,
5) average excess oxygen at the furnace exit,
6) slag indices for each of the furnace walls,
7) high temperature corrosion indices at each of the furnace walls,
8) low temperature corrosion indices at each of the furnace walls.
RESULTS
Physical Model Validation
The physical model base case constitutes a windbox without any flow distribution
devices. For each test, the air flow distribution was measured at
1) the approach duct,
2) the inlet to the windbox,
3) upstream of the burners,
4) and the entrance to the convection pass.
The impact of the air flow bias in the approach duct was simulated using flow deflectors
located in the approach duct. The deflectors created a severe disturbance in the air
flow profile. The level by level air flow rate was measured in the model and
extrapolated to the prototype conditions assuming volumetric air flow rate of 300,000
cfm on each side of the boiler, with average air temperature of 630 degrees F. The
results of that test are shown in Table 2. The results shown in Table 2 correlate well
with the data collected at the plant. Both data sets indicate flow bias toward burner
level A, and to a lesser extent burner level D. Burner levels B and C are negatively
biased.
Vane Design Development
The design development precluded duct or windbox skin modifications. Vanes
presented optimal, low cost flow redistribution devices. Preliminary testing program
covered an extensive list of alternative vane designs. The detailed analysis was
focused on a vane design consisting of three (3) vanes extending from within the
approach duct to downstream of the inner burners as shown in Figure 3. The test
results are summarized in Table 3. The vanes segregate each burner level from the
neighboring levels. The vanes are spaced in the approach duct so as to ensure nearly
uniform volumetric air flow rate to each burner level. The burner to burner variation can
-------
BLE2
Shawnee Windbox Velocity profile data analysis
No Vanes, beam as of 1/23/95 with flow disturbed
Date: February 22, 1995
Pressure differential (in.w.g.):
Windbox to combustion chamber =
Left inlet to combustion chamber =
1 right inlet to combustion chamber =
left inlet to windbox =
right inlet to windbox =
Flow rates
1
48649
44595
45000
36486
2
29595
36892
30811
27973
3
38235
39706
33088
25735
4
43015
39338
46691
34191
Level
A
B
C
D
1.19
1.20
1.11
0.00
0.08
Coefficient of Variance=
Burner
level
A
B
C
D
Sum
- '
Flow
fraction
1.30
0.74
0.76
1.19
-
West side
97838
55735
57054
89373
300000
Normalized values
1
1.30
1.19
1.20
0.97
18.5%
2
0.79
0.98
0.82
0.75
NOTE: Plant flow rate 300,000 cfm each duct, temp=630 deg.
3
1.02
1.06
0.88
0.69
East side
118641
47142
53925
80282
299990
4
1.15
1.05
1.25
0.91
1.58
0.63
0.72
1.07
Level
A
B
C
D
-------
TABLES
Shawnee air flow distribution (cfm) predicted with the physical model
Proposed flow divider vanes extending from the inlet duct to the burners
1
Simulation Date: February 9, 1995
Pressure differential (in.w.g.):
Windbox to combustion chamber =
Left inlet to combustion chamber =
right inlet to combustion chamber =
left inlet to windbox =
right inlet to windbox =
level
A
B
C
D
Aif flow rates
i
37079
38571
42737
38839
2
37921
36429
32263
36161
3
36181
30789
38646
38258
1.26
1.53
1.59
0.28
0.34
Average additional windbox pressure
loss due to vanes =
Burner to burner flow distribution
4
38819
44211
36354
36742
Coefficient of Variance=
Normalized values
1
0.99
1.03
1.14
1.04
8.7%
2
1.01
0.97
0.86
0.96
NOTE: Plant flow rate 300,000 cfm each duct, temp=630 deg.
3
0.96
0.82
1.03
1.02
0.27
4
1.04
1.18
0.97
0.98
Level
A
B
C
D
-------
\
V
A
Secondary Air
Inlet Duct
Figure 3
Burner Box Turning Vane Arrangement
Shawnee Steam Plant
Recommended Vane Arrangement
O
0
O
O
O
O
O
West Side
97.5"
8'9"
51 '0"
14'3"
O O
Level A
O O
Level B
O O
Level C
O O
Level D
Burner 1 Burner 2
Burner 3 Burner 4
East Side
-------
be further reduced by installing porous plates or well designed, multiple level air
registers.
The burner box side to side air flow is nearly symmetric in spite of side to side
differences in windbox entrance. This was demonstrated with paraffin wax smoke
injected into the flow field on each side. The smoke entering from each side expands
into the furnace on that side. Negligible amount of smoke was observed at the opposite
windbox or furnace side. This observation indicated that, although the right to left side
air flow bias might impact each side of the furnace, it does not significantly impact the
opposite side. On each side of the windbox, the vanes are to be located in the duct
such that uniform volumetric air flow rate reaches each level. The variances between
the burners in Level A segment are functions of the first vane and the roof of the
approach duct. Due to the severe change in direction in the upper portion of the
segment (inner radius influence), burners A1 and A4 are subjected to lower air flow
rates than burners 2 and 3. A porous plate between A1 and A2 is designed to further
distribute the flow field. New burners or new registers would make up for this
remaining, but reduced bias. The I-beam located on each side of the furnace
significantly distorts the flow field approaching level C. The new design ensures
adequate air supply to this level.
The recommended vanes reduce the available system pressure by less than 0.3 in.
w.g. Given that the existing vanes and shrouds reduce available pressure by 1.8 in
w.g., the net gain with this system is about 1.5 in. w.g. Consequently, the forced draft
fans should have the capacity to maintain adequate windbox to combustion chamber
pressure differential. At 300,000 cfm, the available windbox total head should be
approximately 1.5 in. w.g.
NOx and Index Computations
The numerical simulation scenarios are presented in Table 4. The simulation results
are shown in Boiler Diagrams 1 through 5. Diagrams 1 and 2 constitute the baseline
conditions at full load and minimum load respectively. Slag and corrosion are observed
near the burner region in both cases, although less severe for the minimum load
scenario. While at full load, additional slag and corrosion potential corresponds to the
reduced secondary air supply to the right side of the boiler. A comparison of diagrams
1 and 3 suggests that slag and corrosion potential on the sides of the boiler are
successfully minimized with improved burner to burner bias. Reducing the excess
oxygen adversely impacts the lower left side of the furnace as shown in Diagrams 1 and
4. Finally, a change in the swirl orientation of the inner burners to counter clockwise
(e.g. flue gas travels up the wall) appeared to have minimal impact on slag and
corrosion rates as shown in Diagrams 1 and 5.
The final NOX results of these simulations are not available at this writing. The NOX and
index computation results will be presented at the symposium.
-------
TABLE 4
SHF Furnace Simulation Model Scenarios (4/12/95)
Case Number
Coal A (kpph)
Coal B (kpph)
Coal C (kpph)
Coal D (kpph)
Load (MW)
Primary air ratio
%O2, dry
Secondary air bias
Al
Bl
Cl
Dl
Average
A2
B2
C2
D2
Average
Swirl
intensity (omega)
Orientation
Baseline
full load
1
22.5
22.5
22.5
22.5
150
1.8
4.0%
78%
85%
89%
81%
83%
122%
113%
109%
124%
117%
14
CW
Baseline
minimum load
2
15
15
0
0
50
1.8
5.0%
78%
85%
82%
122%
113%
118%
14
CW
Secondary air
reduced bias*
3
22.5
22.5
22.5
22.5
150
1.8
4.0%
103%
118%
97%
98%
104%
97%
82%
103%
102%
96%
14
CW
Low O2
full load
4
22.5
22.5
22.5
22.5
1-50
1.8
2.0%
78%
85%
89%
81%
83%
122%
113%
109%
124%
117%
14
CW
* The secondary air bias listed here results from the proposed vane design
Secondary air
up the wall
5
22.5
22.5
22.5
22.5
150
1.8
4.0%
78%
85%
89%
81%
83%
122%
113%
109%
124%
117%
14
up the wall
-------
Diagram 1
SHF Slag and Corrosion Potential
Baseline, Full Load
REAR
RIGHT
FRONT
LEFT
III
III
lh
^^^^"^^ V. IJ
®
(40) *//»
0 SLh
(20
6B i)
v-_X
SB")
©
©
(6A)
^v^/
(SA)
©
©
(M)
©
(259)
O
©
OsL/«
0
N?
N
s
&
I
)
\
±
©
v — s
(25^
©^^
" ^JL/i
o
©° *^
o
0 0
0 0
0 0
0 0
© /^ /
r x <
d i^r
Q
^~~s
©
©
©
©
©
©
BB)
120)
-!2^^
Vi6y^*'*«»*
159
©
©
©
Moderate Slag
Extensive Slag
Moderate Low Temperature Corrosion Potential
L Extensive Low Temperature Corrosion Potential
/i Moderate High Temperature Corrosion Potential
H Extensive High Temperature Corrosion Potential
-------
Diagram 2
SHF Slag and Corrosion Potential
Baseline, Minimum Load
REAR
RIGHT
FRONT
LEFT
Ih
,33/J
Ih
©
©
©
5 Moderate Slag
S Extensive Slag
/ Moderate Low Temperature Corrosion Potential
L Extensive Low Temperature Corrosion Potential
h Moderate High Temperature Corrosion Potential
H Extensive High Temperature Corrosion Potential
-------
Diagram 3
SHF Slag and Corrosion Potential
Secondary Air Reduced Bias, Full Load
REAR
RIGHT
FRONT
LEFT
(34B) //'
III
//I
//I
/I
^^^)
®
0*9
(ig
Gy
(es)
MBj
©
©
^B)
©
(SA)
UA)
(SA)
HA)
(26^
© *"»
O
© °^ff
o
\@
__^y
\26A
(25^
(24^ ^ slh
0
©° *M
Q
(ny ^r
9 0
0 0
9 9
9 9
i
/ * 1
d MI
©
©
©
©
©
©^•^
USB)
14El)
I30)
12B
nsd
U40
J30
.129
* Moderate Slag
S Extensive Slag
/ Moderate Low Temperature Corrosion Potential
L Extensive Low Temperature Corrosion Potential
h Moderate High Temperature Corrosion Potential
H Extensive High Temperature Corrosion Potential
-------
Diagram 4
SHF Slag and Corrosion Potential
Low Excess C>2, Full Load
REAR
RIGHT
FRONT
LEFT
/I
^^®
QcT)
(7c) slh
0 SLH
©
6EM
©
©
©
®
©
QA)
©
(SA)
UA)
(26H
©
O
© °»**
o
\sf
1 >
(26^
(25^
O
©° *w
o
(nj) ^r
• 0
0 0
9 0
9 0
d ii/i
©
©
©
©
©
16B
v — x
©
©
13H
v_7
12H
^~-^
©
J4Q
(J3Q
U2a
s Moderate Slag
5 Extensive Slag
/ Moderate Low Temperature Corrosion Potential
L Extensive Low Temperature Corrosion Potential
h Moderate High Temperature Corrosion Potential
H Extensive High Temperature Corrosion Potential
-------
Diagram 5
SHF Slag and Corrosion Potential
Secondary Air Up the Wall, Full Load
REAR
Ih
Ih
Ih
Ih
/I
RIGHT
FRONT
LEFT
©
©
©
©
s Moderate Slag
S Extensive Slag
/ Moderate Low Temperature Corrosion Potential
L Extensive Low Temperature Corrosion Potential
h Moderate High Temperature Corrosion Potential
H Extensive High Temperature Corrosion Potential
-------
CONCLUSION
The study illustrates the usefulness and flexibility of an integrated approach utilizing
field data, numerical modeling, and physical modeling to solve complex boiler systems
engineering problems. The study yielded a low cost, efficient design to reduce the
windbox bias. The reduction in windbox bias is expected to significantly reduce NOX
generation rate and improve boiler performance.
ACKNOWLEDGMENTS
The authors gratefully acknowledge the TVA Technology Advancements Division and
the TVA Shawnee Fossil Plant Staff for their keen insight and helpful guidance
throughout this work.
REFERENCES
Babcock & Wilcox, "Engineering Study to Determine What Primary Superheater
Modifications Will Reduce PSH Tube Erosion and Determine Metallurgy Requirement,"
B&W No. ES-0709, March 1991.
Beer, J. M., and N. A. Chigier, Combustion Aerodynamics. London: Applied Science
Publishers Ltd., 1972.
Idelchik, 1986, Handbook of Hydraulic Resistance. Hemisphere Publishing Corporation.
Pankhurst, R. C., Dimensionless Analysis and Scale Factors. London: Chapman and
Hall, 1964.
Putnam, A. A., and E. W. Ungar, "Basic Principles of Combustion-Model Research,"
ASME Journal of Engineering for Power. October 1959, pp 183-388.
Rhine, J. M., and R. J. Tucker, Modelling of Gas-Fired Furnaces and Boilers. British
Gas Technical Monograph, New York: McGraw-Hill Book Company, 1991.
Spalding, D. B., "The Art of Partial Modelling," Ninth International Symposium on
Combustion. New York: Academic Press, 1963, pp 833-843.
Thring, M. W., and M. P. Newby, "Combustion Length of Enclosed Turbulent Jet
Flames," Fourth International Symposium on Combustion. Baltimore: Williams and
Wilkins, 1953, pp 789-796.
White, F. M. Fluid Mechanics. McGraw-Hill Book Company, New York, 1979.
-------
RI-JET BURNER FOR REDUCING NOX EMISSIONS IN
TANGENTIALLY FIRED BOILERS
K. Savolainen
Imatran Voima Oy
Research and Development
Rajatorpantie 8, Vantaa
01019 IVO
P Dernjatin
IVO International Ltd
Rajatorpantie 8, Vantaa
01019 IVO
Abstract
A new type of low-NOx burner has been developed for NOX reduction of tangentially fired
boilers. The basic idea of the RI-JET (Rapid Ignition) low-NOx burner is to create a high-
temperature reducing flame near the burner tip. In order to promote rapid ignition and to
form a reducing zone near the burner, the RI-JET burner is equipped with a flame stabilizer
in the coal nozzle, an axial swirler in the secondary air nozzle and a guide sleeve between the
secondary and tertiary air nozzles. By now, this new low-NOx combustion technology has
been applied in two power stations, where the NOX reductions achieved by RI-JET burners
and an over-fire air system varied between 50 and 75% and, at the same time, unburned
carbon was below 5%. The flame was stable over the normal load range 50-100%, and the
flame stability was independent of the burner zone stoichiometric ratio. Low NOX and UBC
values were therefore achieved also when operating the boiler at low load.
Introduction
A new-generation low-NOx burner, the RI-JET burner, for tangentially fired boilers has been
developed in IVO Internationl Ltd, and an international patent application has been filed under
the Patent Corporation Treaty. The basic idea of the RI-JET (Rapid Ignition) low-NOx burner
is to create a substoichiometric zone very close to the burner tip, and the two-stage combustion is
carried out by means of a single burner. This single burner staging technique combined with
staging in the main vortex with OFA is very effective in lowering NOX emissions, combining the
advantages of swirl-stabilized burners and tangentially stabilized combustion. With a typical jet
flame it is difficult to control NOX emissions and unbumed carbon because of delayed ignition
(normally 1-2 meters from the burner tip) and uncontrolled combustion air mixing in the primary
combustion zone.
-------
Basic features of the RI-JET burner
The RI-JET burner is equipped with a flame stabilizer, which promotes rapid ignition of the
pulverized fuel; hence it is possible to allow a high-temperature reducing zone to be formed near
the burner. Combustion air is divided into secondary and tertiary air streams; the secondary air
has a swirling motion in order to bring hot combustion gases from the flame to enable the rapid
ignition, and the tertiary air is separated from the primary combustion zone by a guide sleeve to
form a reducing flame. Nonuniform pulverized coal distribution in the coal pipe has an adverse
effect on the NOX level and unbumed carbon. To correct this the RI-JET burner is equipped with
a venturi, which forces coal particles into the middle of the coal pipe. After the venturi, the
particles are concentrated near the flame stabilizer, thus enhancing the ignition and flame stability
by using specially designed pulverized coal concentrator technology. When enhancing the
ignition, the carbon residue in the fly ash will remain < 5% also in substoiciometric combustion
conditions.
For each boiler, before starting the detailed burner design, the furnace thermal behavior
(temperature, oxygen, CO, NOX, residence times, slagging etc.) is analyzed using the special
ARDEMUS boiler model and the steam performance using process simulator SOLVO. The
burner zone height and location of over-fire air ports are decided on the basis of these analyses.
For detailed burner design IVO IN has developed a single burner combustion model.
Modifications made
Naantali Power Plant
The Naantali Power Plant is owned by IMATRAN VOTMA O Y, which is the biggest power
producer in Finland (4000 MWC). The Naantali Power Plant is situated in the southern part of
Finland, and consists of three identical units, whose total fuel input is 3 * 125 MWC. The Sulzer-
type boilers produce 420 t/h steam each and the turbine has a high-pressure and a low-pressure
part (HP 180 bar, 530 UC; LP 42 bar, 540 °C). The boiler is supplied with coal, from three coal
mills and the burners are located at the corners (tangential^ fired). All the coal burned is imported
mainly from Poland and Russia.
Because strict requirements were set for NOX emissions, the low-NOx investments were started in
unit 2. This modification only applied to two-stage combustion, and with this system it was
difficult to achieve the official emission limit 180 mgNO2/MJ (540 mgN02/m3n). As a
consequence of unit 2 results, more advanced technology was needed. The next modification was
carried out for unit 3, including 12 RI-JET low-NOx burners with four OFA nozzles without any
changes in the windbox. The old burners were equipped with a tilting system delivered by
Combustion Engineer but the new RI-JET burners are vertically fixed. The old coal mills were
equipped with rotating nozzle rings for reducing the amount of primary air; coal fineness was not
improved. Guarantees for Naantali included NOX value below 170 mgN02/MJ (510 mgNO2/m3n)
and unburned carbon in fly ash below 5%.
-------
Detmarovice Power Plant
CEZ operates 12 000 MWe and is the biggest electricity producing company in the Czech
Republic. The company owns mostly brown coal -fired power plants, but Detmarovice is the
largest hard coal -fired power plant in the Czech Republic (4 * 540 MWf). The boilers are of the
Benson type, producing 650 t/h of high-pressure steam (HP 180 bar, 540 °C; LP 36 bar, 540 °C).
The boiler is tangentially fired and it is supplied with coal from four coal mills.
Retrofitting started in the summer of 1994 from unit 1 and because of the good results unit 2 will
also be modified by IVO IN during the summer of 1995. Unit 1 was retrofitted with 16 RI-JET2
burners and an OFA system in the summer of 1994. IVO IN decided that modifications to the
windboxes, mills and existing burner openings (plug-in design) were unnecessary. During the
design process it was obvious that fineness of the coal particles was poor after the milling process
but enhanced ignition was supposed to compensate it. At the moment, the official emission limit
to NOX emissions in the Czech Republic is 230 mgN02/MJ, but in the future it is expected to be
at the Central European level, 150 mgNCb/MJ. IVO IN guaranteed the following values in
Detmarovice: NOX emission 150 mgNO2/MJ and unburned carbon in fly ash below 3.5%.
Coal quality
The NOX formation depends on the chemical and physical properties of the combusted coal. The
most important factors affecting NOX formation are the fuel ratio (fixed carbon/volatile matter)
and the coal nitrogen content; the higher the fuel ratio and the nitrogen content are, the higher the
NOX emission (1) is. From the physical properties the most important one is the coal particle size
after the milling process. A small particle size gives high nitrogen volatile yield and high flame
temperature, promoting NOX reduction. At the Detmarovice Power Plant especially one mill was
in a very bad condition, giving 3-4% of coal particles bigger than 500 u,m. The following table
gives the properties of burned coal at the Naantali and Detmarovice power plants.
Table 1
Coal properties in actual cases
Naantali Detmarovice
Volatile content (dry,%)
Fixed carbon (dry,%)
Ash (dry,%)
FR-ratio (-)
N (dry,%)
Fineness (< 74 |.im)
Fineness (> 200 urn)
33
51
16
1.5
1.1
55
5-10
24
54
22
2.3
0.9
45
5-15
-------
NOX and UBC test results
In both projects NOX and UBC guarantees were achieved easily and the summary of the main
results is presented in Figure 1. NOX reduction achieved by RI-JET burners only was 50% and
with two-stage combustion it was 70-75%, depending on the coal mill combinations. At Naantali
unit 3, NOX reduction was 50% with two-stage combustion; this lower value was due to the
lower initial NOX value. When comparing the performance of different low-NOx combustion
systems, theNOx reduction itself is not important, but the final NOX emission level.
The flame was stable over the normal load range 50-100% and the stability was also independent
of the burner zone stoichiometric ratio. The guaranteed NOxand UBC values were therefore
achieved also when operating the boiler at low load. At the Detmarovice Power Plant there were
no changes in the slagging behaviour after the modification. At the beginning of the Naantali
project, some ash buildup was observed in the burner zone. However, after some modifications
to the burner cooling system the ash buildup was eliminated.
The extremely low UBC level in the case of Naantali is explained by the high reactive coal (FR =
1.5) and the high-temperature stable flame. The stabilizing technology also compensates low coal
fineness, as seen from the Detmarovice results.
450
400
350
300
"5
^250
O
E
150
100
50
0
Dctmarovice
FR=2.3
N = 0.9 %
Naantali
FR=1.5
N=l.l
Guarantee
values
3 uppermost mills
3 lowest mills
0.5
1.5 2 2.5
Unhurried carbon (%)
3.5
Figure 1
NOx and UBC results before and after low-NOx modifications
The most important parameter affecting coal combustion phenomena is the coal/air (C/A) ratio,
which is determined as the coal mass flow (kg/s) per primary air amount (kg/s) of one mill. If the
-------
amount of primary air is very high (low C/A value), coal particles are far from each other,
resulting in poor heat transfer and low combustion rate. In the other case (high C/A value) there
is lack of oxygen, suppressing the flame. In industrial applications the C/A value typically varies
between 0.3 and 0.5. For NOX reduction and the combustion rate (UBC control) there is an
optimum limit for the C/A value, and when the C/A value is too low it is difficult to achieve a
reducing flame in the primary combustion zone (Figure 2). We also found correlation between
the C/A value and the boiler efficiency: the higher the C/A value is, the lower the boiler end
temperature is.
x low C/A
• medium C/A
o medium C/A
» high C/A
0.80
0.90 1.00 1.10
Burner zone stoichiomctric ratio
1.20
Figure 2
C/A-value and stoichiometric ratio vs. NOX emission at the Naantali power station
During commissioning it was observed that when lowering the amount of primary air (higher C/A
value) the flame became more stable and highly luminous, resulting in a high flame temperature.
This means that the combustion rate is accelerated, and the final effects can be seen in Figure 3.
With a high C/A value the amount of unbumed carbon is not very sensitive to the burner zone
stoichiometric ratio.
-------
0.80
low C/A
medium C/A
medium C/A
high C/A
0.90 1-00 1.10
Burner zone stoichiometric ratio
1.20
Figure 3
C/A-value and stoichiometric ratio vs. UBC at the Naantali power plant
Steam performance
Changing the ignition point near the burner tip has an effect on the boiler steam performance,
decreasing the amount of reheat steam injections, and on the boiler efficiency, lowering the flue
gas temperature before FGD. At the Naantali Power Plant, the flue gas temperature before FGD
decreased 5 °C after the low-NOx modification and the amount of reheat steam injections reduced
15 t/h. At the same time there was no change in the reheat steam temperature. In the case of
"Detmarovice the reheat steam injections decreased from 20 t/h to 0 t/h when operating at full
load and at the same time there was no change in the reheat steam temperature, increasing the
electric efficiency from 37.9% to 38.1%. At partial load, the reheat steam injections were 0 t/h
and the reheat steam temperature decreased 15 °C, lowering the electric efficiency from 37.8% to
37.7%. The effect of two-stage combustion on the steam performance was very small compared
with the change in ignition behavior.
Summary
In the case of swirl burners and wall-fired boilers, very lowNOx emissions have been achieved
with high-temperature reducing flames, which is possible using the flame stabilizing technique.
Now this principle has also been applied to tangentially fired boilers. This technology, combined
with the over-fire air system, has potential for high NOX reduction and still low unbumed carbon
in fly ash. Instead of the burner zone stoichiometric ratio, the C/A value and coal quality also
have a remarkable influence on NOX emissions and unbumed carbon. In the future more attention
will be given to coal mill performance and coal quality.
-------
Burners with controlled aerodynamics in the primary combustion zone have a capability to
achieve 50 - 75% NOX reduction.
REFERENCES
1. T. Uemura et al. 1991. Update 91 on Design and Application of Low-NOx Combustion
Technologies for Coal-Fired Utility Boilers. EPRI/EPA 's Joint NOX Control Symposium,
1991.
-------
Low NOX MODIFICATIONS ON
FRONT-FIRED PULVERIZED COAL FUEL BURNERS
Brad Owens and Michael Hitchko
Public Service of New Hampshire
A Northeast Utilities Company
1000 Elm Street
Manchester, NH 03105
R. Gifford Broderick
RJM Corporation
Ten Roberts Lane
Ridgefield, Connecticut 06877
Abstract
Burner optimizations and modifications were performed on Public Service of New
Hampshire's Schiller Units 4, 5, and 6. These are Foster-Wheeler 50 MWg pulverized coal
and No. 6 fuel oil-fired boilers with six burners each. Burner optimizations consisted of fuel
flow, primary air, secondary air testing and balancing. Burner modifications consisted of the
addition of circumferentially and radially staged flame stabilizers, circumferentially-staged
coal spreaders, and modifications to the existing pulverized coal pipe. NOX emissions on
Unit 6 of .41 Ib/mmBtu were achieved at optimized burner settings at full load with all
burners in service and without the use of overfire air or bias firing. This represented a 50%
NOx reduction from the average pre-modification baseline NOX emissions of .81 Ib/mmBtu
prior to the optimizations and burner modification program. NOX emissions as low as
.38 Ib/mmBtu were achieved with the use of overfire air. There was essentially no
quantifiable change in LOIs (baseline LOIs averaged 40%). Furnace excess O2 as low as
1.2% was achieved with CO emissions of less than 200 ppm. Total installed costs including
the overfire air system were approximately $7/kW.
Background
Public Service of New Hampshire's Schiller Station is located in the City of Portsmith, New
Hampshire on the Piscataqua River separating the States of Maine and New Hampshire.
Schiller Station Units 4, 5, and 6 are natural circulation Foster Wheeler Corporation boilers
(Figure 1) designed for 425,000 Ib/hr of steam at 1,285 psig at 950°F superheat. The
boilers were built in the 1950's and designed for firing coal and No. 6 fuel oil. Coal was
fired on Unit 4 briefly. In the early 1980's, the units were refurbished to burn 1% sulfur
bituminous coal and No. 6 fuel oil. Six Combustion Engineering (CE) RO-type coal and oil
-------
burners were installed, arranged in two rows of three burners per row. Two CE pulverizers
sized for the capability to operate at approximately 45 MWg were added. In the late 1980's,
the burners on all three units were modified in an attempt to reduce LOIs and eliminate
windbox fires. The Unit 4 burners were replaced with a design similar to the CE RO
burner, however, with a reduced coal pipe length and diameter, reduced burner throat size,
and the addition of coal spreaders. The Unit 5 burners were modified to a reduced length
and diameter coal pipe and the addition of coal spreaders. The Unit 6 burners were replaced
with a design similar to the original CE RO burners, however, with a reduced length and
diameter coal pipe, reduced throat diameter, and narrower throat exit angle.
Title I of the 1990 Clean Air Act required that the Schiller Station Units 4, 5, and 6 make a
significant reduction in the emission of nitrous oxide (NOx). Regulations imposed by the
State of New Hampshire instituted NOX limits of .5 Ib/mmBtu. Public Service of New
Hampshire performed baseline NOX emission testing on these units and at optimized burner
setting, baseline NOx emissions ranged between .8 and 1.0 Ib/mmBtu. Public Service of
New Hampshire's assessment of the cost of retrofitting these units with low NOX burners was
prohibitively high. In an attempt to reduce the capital cost requirement of bringing these
three units into compliance, Public Service of New Hampshire and RJM Corporation jointly
funded a NOx reduction program to achieve NOX compliance through burner optimizations
and minor burner modifications.
NOX Reduction Program
The NOX reduction program stretched over two years for all three units to suit the Schiller
Station normal maintenance outage schedule of 24 months for each unit. The initial NOX
reduction program was conducted on Unit 5, including testing with two different design coal
spreaders. These results were published in a paper entitled "Modifications of Front-Fired
Pulverized Coal Burners"l given at the May 1994 EPRI NOX Conference in Scottsdale,
Arizona. Unit 5 achieved a 40% NOx reduction. In order to improve on the NOX emission
results achieved on Unit 5, the flame stabilizer diameter was reduced and an alternate design
coal spreader was designed for Unit 4. A 45% NOX reduction was achieved on Unit 4 from
the original baseline NOX emissions. Further improvements were incorporated into the
Unit 6 conversion, including placement of the flame stabilizer at the end of the coal pipe.
This resulted in a 50% reduction of NOX emissions from the original baseline NOX emissions
of .81 Ib/mmBtu. The NOX reduction program on each unit consisted of two phases, an
optimization phase and a burner modification phase. There were slight differences in the
program for each unit since the burner configurations were different, and an attempt was
made on each subsequent unit to improve performance.
The NOx Optimization phase consisted of testing and balancing the secondary airflow,
primary dirty airflow and coal flow. The Burner Modification phase consisted of
Computational Fluid Dynamics (CFD) modeling of the baseline and modified burner,
modifications to the coal pipe, and the addition of circumferential and radial staged flame
stabilizers and circumferentially staged coal spreaders. In the case of Unit 6 the burner
throat diameter was enlarged and the exit angle was modified back to the original design.
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NOX Optimization Phase
The objective was to balance secondary airflow, dirty airflow and coal flow within ±5% of
the mean. The secondary air was measured utilizing RJM Corporation's proprietary Air
Distribution Analysis (ADA) methodology. The ADA has the ability to measure the burner
secondary air perimeter loadings while determining the average airflow through the burner.
The back plate rings on Unit 5 and shrouds installed on Units 4 and 6 outside the air register
vanes were adjusted to achieve a secondary air balance within ±5%. The dirty air and coal
flow was measured by a reverse impact pilot tube and rotorprobe. Balancing was achieved
by changes to the coal line orifice plates on Units 5 and 6. Adjustable orifice pulverized coal
trim dampers were installed in the burner line coal pipes on Unit 4 for balancing. The
baseline and final primary airflow, secondary airflow, and coal flow distribution deviations
are identified in Table 1.
Table 1
Total % Deviations from the Mean
Unit 4 Unit 5 Unit 6
Baseline Final Baseline Final
Primary Dirty Air 7.9 2.1 15.9 6.30
Secondary Air 20.17 8.19 11.9 8.50
Coal Flow 51.0 10.4 37.9 26.9
Burner Modification Program
RJM Corporation used Fluent CFD and NOX software on a Sun Spare 10 computer to model
parametric burner changes. The objectives of this portion of the project were to predict the
percentage reduction in NOX with the addition of a flame stabilizer and to determine whether
the combustion in the internal recirculation vortex of the burner approximated stoichiometric
proportions. The baseline burner geometry (burner as modified in 1990) for Unit 5 is shown
in Figure 2. The model predicted NOx emissions of the baseline burner of .33 Ib/mmBtu.
The model inputs were altered to reflect the addition of the staged coal flame stabilizer. The
model predicted NOx emissions for the modified burner of .1 Ib/mmBtu or a 70% NOx
reduction. Because of the various modeling assumptions involved (coal volatilization and
burnout characteristics, coal sizing and distribution, coal composition, turbulence modeling,
combustion rate constants, etc.) the absolute levels of NOX predicted are only approximate.
Nevertheless, the computed results are useful in comparing trends and in quantifying the
relative effectiveness of the two burner designs. Subsequent to completion of the program,
additional CFD modeling determined the assumption for coal distribution exiting the coal
pipe was incorrect and had a significant effect on model results.
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The radially and circumferentially staged flame stabilizer (patent pending) is a low
enhancement of the patented conventional radially staged flame stabilizer which has already
been installed on over 2000 MW of coal-fired utility boilers. The design of the flame
stabilizer was established utilizing an axisymmetric three-dimensional model. Figure 3 shows
the staged, flame stabilizer design. The design maintains the primary air (15%) to secondary
(85%) airflow split, and radially and circumferentially stages the secondary airflow to
maximize the cyanide NOX reduction reaction. The primary air was conveyed in the
centrally located coal pipe. The secondary air comprised an outer zone around the flame
stabilizer, unstaged and staged zones within the flame stabilizer, and an inner ignition zone.
The secondary airflow characteristics were evaluated for design of the flame stabilizer at the
flame stabilizer face exit plane diameter.
The flame stabilizer vanes were set to achieve the circumferentially staged zones by varying
the vane exit angles and the number of blades in each zone. The staged section had twelve
vanes and the unstaged section had four. The more axial flow angle of the unstaged zone
and reduced blockage from fewer vanes permitted an increased secondary flow for the
unstaged zone. The design ratio of 1.35 was achieved at a five degree flow exit angle
difference.
An evaluation was made of the swirl number for the secondary airflow. Swirl number is a
measure of the tangential-to-axial momentum of the secondary air exiting the plane of the
flame stabilizer. The swirl number determines the size of the internal recirculation zone.
For optimum combustion and low NOX emissions, a swirl number less than 1.0 is desirable
when integrated for the flow. Lower swirl numbers (< .5) may cause burner instability and
ignition problems. Higher values (> 1.5) create overswirl, which results in an oversized
recirculation zone creating a hotter, more turbulent flame and the potential of gas
recirculation into the register. Table 2 below is a summary of the final aerodynamic analysis
results for each unit.
Table 2
Aerodynamic Ananysis
(Per Burner)
Unit 4 UnitS Unit 6
Coal Flow Ib/sec 2.2 2.2 2.2
Primary Airflow Ib/sec 3.9 3.9 3.9
Secondary Airflow Ib/sec 22.4 22.4 22.4
Burner Throat Diameter - Inches 28 28 30
Flame Stabilizer Exit Plane Diameter-Inches 31 40 30
Flame Stabilizer Diameter - Inches 24 27 24
Air Register Vane Setting - % Open 80 80 80
Integrated Swirl Number .69 .90 .66
Burner Secondary Air Draft Loss - Inches w.c. 5.52 2.88 6 33
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The staged flame stabilizer was mounted upstream of the coal pipe discharge except on
Unit 6 where it was mounted on the end of the new, extended coal pipe. New coal spreaders
were fabricated which provided separation of the individual coal jets to coincide with the
staged sections of the flame stabilizer. The coal pipe was extended eleven inches (18 inches
on Unit 6) to the beginning of the burner throat. Figures 4, 5, and 6 show the modified
burner with the new, staged flame stabilizer and coal spreader for Units 4, 5, and 6,
respectively.
Public Service of New Hampshire installed an overfire air system in six (6) existing
observation doors one elevation (10 feet) above the upper burner level. Four (4) front-wall
ports and two (2) side-wall ports near the rear of the furnace were utilized. On Units 4 and
6 two (2) rear wall ports were utilized instead of the side wall ports. Overfire air was taken
from the top of the windbox. Each port was equipped with butterfly dampers.
Test Results
Baseline NOX emissions were obtained on each unit by Public Service of New Hampshire
prior to the NOx reduction program. This data was taken at optimized settings and included
some testing with the boiler observation doors above the burners open.
Final NOx optimization testing was performed on each unit after the fuel and air were
balanced and after the installation of the burner modifications. The baseline and final NOx
versus CO emissions results for each unit at optimized conditions without overfire air is
listed in Table 3 below. On Unit 5, 34 MWg was the highest load achievable on coal firing.
Table 3
Unit 4 Unit 5 Unit 6
Load MWg 46 34 50
Baseline NOX Emissions - Ib/mmBtu .99 .84 .81
Baseline CO Emissions - ppr^ 19 11 60
Baseline O2 - % 4.7 4.9 1.3
Modified NOX Emissions Ib/mmBtu .53 .49 .39
Modified CO Emissions ppmv 3 20 38
Modified O2 - % 1.8 1.5 1.5
NOX Reduction 45% 40% 50%
Test results on Unit 6 with a smaller diameter, staged flame stabilizer located at the end of
the coal pipe yielded significantly improved results over Units 4 and 5. Boiler operational
adjustments for each unit provided similar results. With the reduced NOX emission values on
Unit 6, adjustments such as excess oxygen and overfire air had less of an impact than on
Units 4 and 5. The following summarizes operational test results on Unit 6.
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Boiler Load
Testing was conducted at the 2 mill maximum load of 50 MWg, and the 2 mill minimum
load of 37 MWg. This was both with and without overfire air. At 50 MWg, average NOx
emissions were .41 Ib/mmBtu reducing to .36 Ib/mmBtu at 37 MWg. Opening the overfire
air dampers reduced average NOX at the full load condition to .40 Ib/mmBtu and
.33 Ib/mmBtu at the 37 MWg condition. At the 1 mill minimum load of 21 MWg with the
upper burners firing coal and the center lower burner on oil, NOX emissions were
.37 Ib/mmBtu. This was without overfire air. Figure 7 is a plot of NOX emissions versus
boiler load at 37 MWg and 50 MWg at optimized burner settings.
Furnace Excess O2
Throughout the boiler and burner optimization testing, data was taken at various excess
furnace O2 levels both with and without overfire air. Figure 8 is a plot of NOX emissions
versus furnace excess O2 for the optimized burner settings. This is plotted at 50 MWg and
37 MWg with and without overfire air. At 50 MWg furnace excess O2 ranged between
1.2% and 2.8% O2 without overfire air. NOX emissions at 1.5% O2 were .39 Ib/mmBtu.
With the overfire air ports open at 50 MWg, furnace excess O2 ranged between 2.3% and
2.8% O2. Reducing excess O2 from 2.8% to 1.2% resulted in a 21% NOX reduction.
Figure 9 is a plot of furnace excess O2 versus CO emissions for the optimized data at both 50
MWg and 37 MWg with and without overfire air. CO emissions at 50 MWg ranged between
0 ppm and 250 ppm at O2 levels of 2.75% and 1.2%, respectively, without overfire air. At
60 ppm of CO emissions, furnace excess O2 without overfire air would have been 1.5%
versus 2.6% with the overfire air ports open, or a 1.1% O2 reduction.
Overfire Air
Various combinations of overfire air ports and percent openings were tested to determine the
effect of the overfire air system. The amount of overfire air was calculated from the
decrease in the windbox-to-furnace differential pressure. Opening the four front ports to
50% open yielded approximately 4% overfire airflow, resulting in a negligible NOX
reduction. Opening the four front ports to 100% open yielded 8.2% overfire airflow, with a
4.7% reduction of NOX emission. Closing the four front ports and opening the two rear
ports to 100% yielded approximately 4% overfire airflow, however, a 3.7% NOX reduction
was realized. Opening the six overfire air ports to 100% resulted in 9.7% overfire air
yielding an 8.1% reduction of NOX emissions. The rear ports, although only adding 1.5%
additional overfire airflow, resulted in an additional 3.4% of NOX reduction. Figure 10 is a
plot of NOx reduction versus the amount of overfire air. This data is with the six dampers
100% open.
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Loss on Ignition
Loss on Ignition (LOI) averaged approximately 40% on the units prior to the NOx reduction
program. Contributing to the cause of the high LOIs were the high moisture content of the
coal (12%), operating the pulverizers above their maximum rating, and insufficient grinding
of the coal due to high pulverizer amps with less than 70% passing through 50 Mesh. Post
NOX reduction program LOIs were essentially unchanged averaging within ±5% of the pre-
modification average.
Summary
reductions on Unit 6 of 50% were achieved from the pre-NOx reduction program
optimized baseline conditions. This resulted in NOx emission levels of .41 Ib/mmBtu
without overfire air. Figure 1 1 is a plot of NOX versus CO emissions at 50 MWg for both
the baseline and modified burner. NOX reductions of 54% were achieved with the use of
overfire air ducted into existing observation doors. Furnace excess oxygen levels of 1.5%
were achieved without overfire air with CO emissions of 60 ppmv. LOIs averaged
approximately 40% with the modified burners. This was within ±5% of the premodified
burner average LOIs.
Installed Costs
The complete installed costs for each unit are identified below. The costs include direct and
indirect expenses, exempt and non-exempt labor, materials, and outside purchases. The total
cost includes the burner optimizations and modifications, secondary air shrouds, removing
windbox partition plates, air register repairs, refractory throat repairs or in the case of Unit 5
and 6 replacement of the burner throats, the overfire air system, and testing.
• Unit 4 $6.81/kW
• Unit 5 $6.25/kW
• Unit 6 $7.62/kW
References
1. Owens, B., Hitchko, M., and Broderick, R. G., "Modifications on Front-Fired
Pulverized Coal Fuel Burners", presented at the Members Only EPRI NOX
Conference, Scottsdale, AZ (May 1994).
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Northeast Utilities
(PSNH) Schiller Unit #5
Boiler Cross Section Side View
T T T T T I
Figure 1
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Northeast Utilities (PSNH) Schiller Unit #5
Burner Cross Section (Mod 1 and Mod 2 Coal Spreaders)
Rich/lean
zones
Stabilizing
zones
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stoicnometry
axial flow
coal spreader
Figure 2
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Staged Flame Stabilizer
Figure 3
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NORTHEAST UTILITIES - SCHILLER UNIT 6
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NORTHEAST UTILITIES - SCHILLER UNIT 6
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NORTHEAST UTILITIES - SCHILLER UNIT 6
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NORTHEAST UTILITIES - SCHILLER UNIT 6
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NORTHEAST UTILITIES - SCHILLER UNIT 6
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Non-OEM Experience with NOx Reduction Applications
K. S. Birchett
L. Chung, P.E.
R. E. Caldwell
M. L. Crisler, P.E.
Phoenix Combustion, Inc.
Ashtabula, OH 44004
Abstract
Heightened global environmental awareness and mandated deadlines for emission compliance
required by the Clean Air Act, demand operators to increase controls on boiler emissions.
For decades, the utility boiler industry has been dominated by the large OEM's. In the past,
boiler owners would approach the company that originally designed the boiler or burner
system to design a burner system to reduce emissions. It was commonly believed that the
boiler manufacturer had the greatest expertise in the area of NOX reduction. Current
experience demonstrates that boiler owners are accepting new approaches to reducing NOX
from non-OEM designers and suppliers. This paper outlines new approaches being applied by
boiler operators to reduce NOX emissions .
Several steps are imperative for a successful NOX reduction program and each step of this
process will be described with examples presented. Concepts that will be examined are:
• Practical designing concerns of theoretical Low NOX combustion
• Reviewing scope requirements required to. reduce emissions
• Teaming with the Customer to facilitate retrofit design and installation
The emphasis of this paper is not directed at the theory of how the components reduce NOX ,
but how to effectively apply proven technology that reduced NOX emissions.
Theory as Applied to Reality
The theoretical effects of NOX reduction through controlled combustion is well documented.
Scores of papers are written each year discussing NOX reduction methods demonstrated in test
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boilers or highly controlled scale models. This work is invaluable in determining which
techniques have the greatest relative impact in reducing NOX emissions. Designers use these
results as the foundations for a NOX reduction application. The true measure of success of
NOX research is in the bridge spanning theory and real world applications. We find that it is
the methodology of applying the theory to the real world that differentiates between a supplier
of Low NOX burner components and a designer of engineered systems that reduce NOX.
A successful NOX reduction retrofit begins with a review of the combustion basics.
Considerable improvements to combustion performance and improved emissions can be
realized by controlling and balancing the air and fuel. The boiler demands a relatively fixed
quantity of energy to produce steam at the desired outlet conditions. The combustion system
views the boiler from a gross level for total air and total fuel. The fuel and secondary air are
assumed to be balanced. Many of these assumptions are built in to the boiler control logic.
Greater successes in NOX reduction applications are achieved by eliminating assumptions
from the design and replacing them with actual field measurements. It is this process that
leads to maintaining or increasing boiler efficiency while reducing NOX emissions.
Design Analysis
The initial design step of a combustion modification to reduce emissions is to perform the
combustion calculations and compare the design to actual operating data. This review
examines the boiler heat release, Primary Air flows, fuel flows, Secondary Air flows, overfire
air flows, coal conduit velocities and the relative velocity of the remaining air streams.
During the design analysis, the boiler excess air and Primary Air to fuel ratios and fuel
properties can be adjusted. If conflicts or design errors exist between the original design and
the current operating conditions, they can be identified and made part of the retrofit early in
the design process. This analysis tends to highlight the unique features of each boiler. The
design can be adapted to meet the unique features of each application, rather than use a "one
size fits all" approach.
System modeling is an additional tool that is used to verify design changes. Several
computational fluid dynamic (CFD) modeling software packages are available for DOS and
UNIX based systems. The CFD application used in the design process allows designers to
economically examine design in a timely manner. Opinions vary as to the value of the
absolute results generated by CFD modeling, however the use of the relative results produced
in modeling is widely accepted. A parametric study using CFD modeling generates a good
cause and effect relationship unique to the current design application. Using these general
relationships allows prioritization of design guidelines. This system adds confidence in
applying common design features to the unique requirements of each retrofit application.
Mechanical Design
Design verification is of little value if, mechanically, the equipment can not operate as
designed. The air registers, burners and OFA systems must be robust in design. If an air
register or OFA damper cannot be adjusted during all normal boiler operations, or if it is not
reliable for long term operations, its value is limited.
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Because of the harsh environment in which the burner registers operate, designing a burner
register that operates reliably over the long term has been a challenge. Burner register air
flow control dampers are often known to bind during operation, thus, its functionality is lost.
Burner register air flow control designs can be categorized as one of three approaches:
• A daisy-chain, linkage style register with adjustable register vanes
• A sliding shroud register
• A parallel, four-bar linkage with adjustable register vanes
Two inherent problems in the daisy-chain linkage design are the mechanism's susceptibility to
binding, and the resulting non-uniform air flow circumferentially about the air register due to
cumulative linkage hysteresis. To prevent binding, individual linkage hysteresis must be
increased to unacceptable levels, while adjusting each linkage to provide uniform damper
position accelerates binding. Adjustable vane style registers, however, provide superior air
flow control and repeatability relative to the sliding shroud style registers. Due to the
mechanical simplicity of the sliding shroud register, the problems of binding with long term
Legend
A. Register Main Body
B. Outer Register Doors
C. Inner Register
D. Inner Register Inlet Opening
E. Outer Register Outlet Cone
F. Inner Register Outlet Cone
G. Burner Inner Barrel
H. Burner Outer Barrel
I. Burner Tip Casting
J. Burner Tip Wedge
(fuel-lean section)
K. Centering Ring
L. Centering Ring Jack Bolt
Figure 1 ATLAS Air Register Isometric Cutaway View
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operations are greatly reduced. The sliding shroud registers do not provide air flow control
with the accuracy found in the adjustable vane design. With these two designs, one must
trade-off mechanical reliability for air flow control accuracy. Our experience has shown that
the parallel, four-bar linkage is not susceptible to the same linkage binding problems as the
daisy-chain linkage mechanism.
The four-bar linkage applies equal control movement and force to each register vane so that
air flow is circumferentially uniform and control is repeatable. The parallel, four-bar
mechanism is designed so that all moving parts are self-centering. This design feature allows
the control mechanism to accommodate thermal growth and thermal cycles.
Our experience has shown the parallel, four-bar linkage mechanism to be a reliable design in
long term operation. Air registers using this mechanism have been in continuous service for
over eight years without a mechanical failure or operational problem. This type of field
success is critical to the Operations and Maintenance groups. The knowledge that the NOX
reduction equipment will not be a constant maintenance item builds acceptance with the staff
that will operate and maintain the equipment.
Fundamentally, our design philosophy is that each application is unique. By differentiating
which of the existing components can effectively be adapted to the low NOX design and
which components must be replaced, the scope of the project can be considerably reduced.
Not only does this represent a competitive edge in terms of project cost, it also maximizes
continuity between the original system and the proposed retrofit. We find it advantageous to
maintain existing coal conduit routing, windbox structure, electrical routing, and any high
energy piping systems when possible.
Instrumentation & Control
After the analytical and mechanical design are complete, the equipment must be accurately
controlled to maximize NOX reductions. As mentioned earlier, one of the major goals of our
design is to remove assumptions concerning air flow distribution. The air register control
logic does not directly effect air flow demand, but acts as a distributor of combustion air.
Because this system only distributes air flow, a relative burner to burner flow measurement is
adequate for most control schemes. Depending on the application, the air register flow
indication can be a local differential pressure gauge or a differential pressure transmitter.
These air flow signals provide the operator with the information required to balance secondary
air flows on a burner by burner basis. The actual flow balancing is accomplished through a
manual or electronic damper positioner. If desired, the air register flows can be automatically
controlled, balancing all air register flows to within a fixed tolerance. While not all
applications require automatic control of the flow control surfaces, optimum NOX reduction
occurs with the more advanced control schemes.
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Defining the True Scope of Work
Our experience shows that limiting the scope of the project to supplying air registers, burners
and overfire air systems is short sighted and generates an incomplete scope of work. The
above items are components that comprise only a part of the retrofit equation. The design
parameter commonly assumed to be operating within the requirements of the new burner
system is the fuel delivery system. For most coal NOX reduction projects, the equipment
designer will state the required fuel distribution and fuel fineness to the user. As part of the
NOX reduction project, it must be verified that the fuel handling and delivery system is
adequate to supply the fuel within the burner fuel specification. Therefore, we believe that
pulverizer performance is an integral parameter in the success of the NOX reduction project.
We have adopted the philosophy that includes an examination of the fuel supply system as
part of the NOX reduction project offering. This examination includes an inspection or review
of the pulverizer internals, the pulverizer control logic, current operating practices and
equipment maintenance, as applicable. The examination results are reported to the Customer
as recommendations, which will assure that the fuel delivery system meets design
specifications. Identifying the operating condition of the pulverizers early in the NOX
reduction project allows all parties ample time to review the fuel delivery system and
logically plan for corrections. A mill performance correction plan can be part of the NOX
reduction scope or left to other parties; regardless of where the responsibility lies, mill
performance should be addressed.
In many cases the NOX reduction project is implemented in conjunction with other capital
projects. Upgrading the existing combustion control and/or burner management system to a
distributed control platform is not uncommon. This work might not be included under the
NOX reduction package, but we believe that we can provide valuable information to the logic
design of the controls upgrade. Our experience is that joint coordination meetings with the
NOX reduction project team, controls upgrade team and plant operations team brings together
all aspects of the changes. The goals of the coordination meeting are that all control
interconnections are identified, design and fabrication schedules coordinated, instrument
compatibility verified, and an acceptable control philosophy generated.
Finally, an issue that must be identified in the project's scope of work is the calibration of
existing measurement and control equipment. Items included in this category are Primary Air
flow measurement, Secondary Air flow measurement, excess oxygen probes, flow balancing
dampers and fan inlet vanes, as appropriate. Depending on plant instrumentation
maintenance, control loops using these devices can operate with instrumentation grossly
miscalibrated. Even though the system is considered to be in working condition, the resulting
performance can be poor. We request calibrating the major flow signals relative to a flow
traverse, verifying the excess oxygen measurement relative to HVT traverse and verifying
damper position demand versus actual final damper position. By requesting these calibrations,
assumptions and design requirements can be verified. The costs associated with these
calibrations are offset by the time costs saved in controls fine tuning, burner fine tuning, and
increased controllability. In addition, we have found that the Operations staff have a greater
confidence and sense of ownership in the new systems.
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Project Teaming Atmosphere
In many industries, "project teaming" is the buzz word for the 1990's. The success of a
comprehensive NOX reduction project is dependent upon the teamwork of all parties involved.
A retrofit on an existing unit is more difficult than an original design in that the degrees of
design freedom in terms of space, orientation and operation are limited. Design information
must be obtained, generated and distributed in a time compressed manner, which requires the
designer, fabricator, installer, the customer's operations and maintenance work well together.
The customer's responsibility in this team is to:
• Clearly define their project requirements
• Identify the time frames for the project
• Locate existing equipment drawings and specifications
• Collect past operating data, equipment history and personnel experience
This information, when supplied by the customer, reduces material delivery concerns, provides
continuity between the old and new system and decreases contact interpretation issues.
The customer can be better prepared for NOX reduction projects by taking advantage of
planned outages to verify drawing dimensions for future NOX reduction projects. Many
questions regarding field dimensions and routing can be answered prior to initial retrofit
design. The installation of NOX reduction equipment on a retrofit requires accurate detail
information of the equipment in place. By our experience, we recommend that drawing
dimensions be verified on site, including burner windbox internals, fuel delivery systems and
routing and spacing for auxiliary equipment.
The system designer can be better prepared for NOX reduction projects by taking advantage of
the operating experiences of the plant personnel with the existing equipment. Many questions
regarding undocumented daily operating practices that plant personnel use can be vital to the
overall design. Items such as actual excess air versus load, mill start-up sequences, soot
blowing cycles, unique firing sequences and load versus burner elevation in service, etc. often
indicate operating parameters that are not reflected in the original design. These unique
operating practices often require special attention in field verification and design.
Our view to the retrofit process is that a pact has been established between a Low NOX
System supplier and a boiler operator. The system supplier designs components with specific
operating conditions. Subsequently, if the equipment is not operated in the intended manner,
the system simply will not work as expected. The customer, specifically the operations and
maintenance staffs, must share ownership in the new operating methods. For this to take
place, the system supplier must properly convey the operations requirements to the customer
and the customer must properly convey the operations limitations. Each party has valuable
information which could determine the success of the project.
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Results
When these philosophies have been implemented on previous Low NOX applications, the
successes have been measured not only in terms of emissions reductions, but also in terms of
reducing customer trauma Our approach to the NOX retrofit process has allowed us to
document the following specific improvements in each of the areas discussed:
• Practical Design
- Air register mechanical reliability, eight years without a mechanical or operational
failure
- Low NOX air register and burner reduced NOX by 30 to 40% from baseline
emissions
- CFD verified OFA designs reduced NOX by 30 to 45% from baseline emissions
• Scope Identification
- Mill balancing reduced NOX by 10 to 20% from baseline emissions
- Identifying scope provided a smooth tie-in from the burner retrofit to DCS and
BMS issues •
• Teaming Approach
- Field changes result in less than 2.5% of the contract value
- Contract milestones have been maintained
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