EPA-650/2-73-005
August 1973
ENVIRONMENTAL PROTECTION TECHNOLOGY SERIES
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EPA-650/2-73-005
PROGRAM FOR REDUCTION
OF NOX FROM TANGENTIAL
COAL-FIRED BOILERS
PHASE I
by
C. E. Blakeslee and A. P. Selker
Combustion Engineering, Inc.
1000 Prospect Hill Road
Windsor, Connecticut 06095
Contract No. 68-02-0264
Program Element No. 1A2014
EPA Project Officer: David G. Lachapelle
Control Systems Laboratory
National Environmental Research Center
Research Triangle Park, North Carolina 27711
Prepared for
OFFICE OF RESEARCH AND DEVELOPMENT
U.S. ENVIRONMENTAL PROTECTION AGENCY
WASHINGTON, D. C. 20460
August 1973
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This report has been reviewed by the Environmental Protection Agency and
approved for publication. Approval does not signify that the contents
necessarily reflect the views and policies of the Agency, nor does men-
tion of trade names or commercial products constitute endorsement or
recommendation for use.
11
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FOREWORD
This report presents the findings of Phase I of a "Pilot Field Test Pro-
gram to Study Methods for Reduction of NOX Formation in Tangentially Coal
Fired Steam Generating Units" performed under the sponsorship of the Office
of Air Programs of the Environmental Protection Agency (Contract No. 62-02-
0264). Phase I of the program consisted of selecting a suitable utility
field steam generator to be modified for experimental studies to evaluate
NOX emissions control. This effort included the preparation of engineering
drawings, a detailed preliminary test program, a cost estimate and detailed
time schedule of the following program phases and a preliminary application
economic study indicating the cost range of each combustion technique as
applied to existing and new steam generators.
Mr. C. E. Blakeslee was the contractor's program coordinator, Mr. A. P.
Selker the contractor's principal investigator and Mr. David G. Lachapelle
the EPA Project Officer during this program phase.
We wish to acknowledge the cooperation of the Alabama Power Company and
in particular the assistance of the personnel of the Barry Station in con-
ducting the unit operating survey.
Finally we wish to express our appreciation to all Combustion Engineering,
Inc. personnel who participated in this program and in particular for the
technical contributions made by Messrs. W. A. Stevens, R. F. Swope, W. H.
Clayton, M. J. Hargrove, R. W. Robinson, R. W. Borio and P. R. Purrington
of Combustion Engineering, Inc.
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TABLE OF CONTENTS
I. Introduction Page
A. Purpose of Program 1
B. Scope of Program . . . 1
II.. Program Objectives 1
III. Results and Conclusions 3
IV. Recommendations 4
V. Discussion 4
Task I - Unit Selection 4
Task II - Detailed Test Programs 5
Task III - Engineering Drawings, Cost Estimates and Detailed
Time Schedules 11
Task IV - Combustion Technique Application Costs 11
VI. Attachments 18
Attachment I - Unit Operating Survey 21
Attachment II - Detailed Test Programs 43
Attachment III - Engineering Drawings 135
Attachment IV - Cost Estimates for Conducting Pilot Field
Test Programs 143
Attachment V - Combustion Technique Application Study .... 173
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I. INTRODUCTION
A. Purpose of Program
The purpose of this program was to investigate various means for
NOX emission control as applied to coal fired utility steam gen-
erators. While current coal firing combustion and control tech-
nology had minimized smoke, CO, hydrocarbon and solid combustible
emissions, proven techniques for the control of NOX had not been
fully developed and evaluated. Review of combustion process mod-
ifications which had been found effective in reducing NOX emissions
from oil and gas fired steam generators and recent staged combus-
tion simulations with coal firing indicated that gas recirculation
to the firing zone and/or staged combustion should be evaluated as
commercially feasible methods of NOX reduction. For these reasons
a program was developed to evaluate the feasibility of these as
well as other methods of NOv control on a commercially sized pilot
plant unit. This unit would be modified to incorporate the systems
to be studied for evaluation of potential operating and control
problems and the establishment of optimum methods for both tran-
sient and long term operation. This report presents the results
of program Phase I during which a suitable unit was selected, en-
gineering drawings and cost of modifications prepared, a prelimi-
nary test program written, and NOX control system costs for new
and existing units developed.
B. Scope of Program
Program Phase I was conducted as part of a projected five phase
program to identify, develop and recommend the most promising com-
bustion modification techniques for control of NOX, without objec-
tionable increases in related pollutants, from tangentially coal
fired utility steam generators. Phase I was accomplished in ac-
cordance with the following task identification.
Task I - Selection of a suitable tangentially coal fired unit
for emission control modification and testing.
Task II - Preparation of a detailed preliminary test program.
Task III - Preparation of engineering drawings, modification costs
and time schedule.
Task IV - Estimate modification cost ranges for each combustion
modification technique as applied to existing and new
boilers.
II. PROGRAM OBJECTIVES
The objective of Phase I was to select a tangentially coal fired steam
generator suitable for modification and performance of a test program
to be conducted in Phase IV and prepare all specified drawings, cost
estimates and schedules.
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Specifically, this objective is defined by the following Phase I tasks.
Task I - Selection of a Suitable Tangentially Coal Fired Steam Gen-
erator
The following criteria were considered in selection of the
test unit.
a. The unit is representative of current tangential coal
firing designs.
b. The size of the unit selected will be large enough to
minimize data extrapolation to larger current designs
while remaining small enough to minimize modification
costs and permit flexibility in conducting the experi-
mental program.
c. The unit location, transportation facilities and coal
handling and storage facilities shall permit testing
of various coals.
d. The utility involved will cooperate and participate in
making the unit available for modification and testing.
Task II - Preparation of the Detailed Test Program
The test program will be designed to investigate the ef-
fects of the combustion process variables and modifications
on NOX» SOX, carbon loss in the fly ash, CO and HC emission
levels.
The following variables were to be considered:
a. Process Variables
Excess Air
Unit Loading
Biased Firing
Coal Type
b. Combustion System Modifications
Flue Gas Recircul'ation to:
• Secondary Air Ducts
• Coal Pulverizers
• Combination of Above
Overfire Air
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Air Preheat Temperature
Water Injection to the Fuel Firing Zone
The test program will provide for evaluation of modified
operation with respect to unit transient and long term
operation.
Task III -Development of Engineering Drawings and Costs
The following drawings and documentation were to be developed:
a. All engineering drawings except detailed drawings re-
quired for modification, fabrication and installation.
b. Estimated purchased equipment, material, erection and
test costs to conduct the program.
c. Detailed time schedule for conducting the program.
Task IV - Combustion Technique Application Costs to New and Existing
Steam Generators
Based on the results of the Phase I evaluation and current
contractors knowledge, a cost range would be developed for
applying the NCty control techniques evaluated in this study
to new and existing steam generators.
III. RESULTS AND CONCLUSIONS
Task I
Alabama Power Company, Barry Station, Unit I was selected as a suitable
test unit for this program. The unit meets the requirements as defined
by Task I objectives and Alabama Power Company has expressed a willing-
ness to cooperate in this program.
Task II
Two preliminary test programs were developed utilizing statistical test
design methods where possible. This principle enabled the programs to
be designed for maximum information output for each test. The first test
program was designed to evaluate all combustion modifications listed under
Task II. The second test program was designed to evaluate specific process
variables with, the major emphasis on evaluating and optimizing biased and
overfire air firing. All necessary analytical measurements and sampling
techniques required to evaluate the effect of combustion modifications on
unit performance and emissions were identified and methods of measurement
developed.
Task III
Engineering drawings and cost estimates for the proposed unit modifica-
tions were completed. Cost estimates were developed for combined as
well as individual overfire air and gas recirculation systems. The re-
sults of the task indicate that the required systems can be designed
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and installed as proposed or as individual systems with allowances for
future additions.
Task IV
The combustion application technique study indicated that overfire air
is the least expensive system for controlling NOx emissions on new and
existing units with gas recirculation and water injection being more
expensive. In general, the cost of applying control techniques to
existing units is twice that of new units.
IV. RECOMMENDATIONS
1. The modification and test phases of the program should be undertaken
essentially as proposed. As a minimum, the program should evaluate
and optimize biased and overfire air firing.
2. The test program should be limited to the long term evaluation of one
instead of two additional coal types. This decision would be made
pending the results of the base coal and first additional coal test
results.
3. A baseline test program should be considered to establish unit opera-
tion and emission levels prior to modification.
4. Should the individual installation of any given portion of the pro-
posed control systems be considered such as overfire air, provisions
should be made in the system design for installation of the remain-
ing systems at a future date.
5. It is essential to the successful completion of this program that
the utility company involvement initiated during Phase I be contin-
ued and expanded in the follow-on program phases to include review
and approval of design modifications and test programs. Program
scheduling and installation of control systems must be coordinated
with planned unit outages.
V. DISCUSSION
Task I - UNIT SELECTION
To select a test unit meeting the criteria specified under Task I, Com-
bustion Engineering conducted a survey of utility companies using tan-
gential ly coal fired steam generators to determine their interest in
participating in the NOx control program. As a result of this survey,
seven (7) utility companies expressed a desire to cooperate with CE in
the program. These companies were subsequently reviewed to determine if
they had within their generating systems units meeting the remaining
criteria specified for the test unit.
Of several units found to be generally acceptable for the test program,
Alabama Power Co., Barry Station Unit No. 1 was finally selected.
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This unit is a natural circulation, balanced draft, steam generator,
firing coal through four elevations of tilting tangential fuel nozzles.
The superheat steam capacity at maximum continuous rating is 900,000 IBS/
HR main steam flow with a superheat outlet temperature and pressure of
1000 F and 1875 PSIG. Superheat and reheat temperatures are controlled
by fuel nozzle tilt and spray desuperheating. A side elevation of this
unit is shown in Figure 1.
The criteria upon which the selection was based are as follows.
1. The unit is representative of the tangentially coal fired steam
generators currently designed by CE which facilitates the trans-
fer of technology to existing and new boiler designs.
2. The unit, while representative of current utility boiler design,
is small enough (125 MW) to minimize modification costs and per-
mit a versatile experimental program. The control system instal-
lation can be coordinated with a planned outage for installation
of a hot electrostatic precipitator. This precipitator would
eliminate the need for additional dust removal equipment to
protect the gas recirculation system fan.
3. The unit location permits testing of various coals without in-
curring additional coal transportation costs. . Coals currently
being burned at the station include both local Alabama and
Illinois varieties. The station has existing facilities for
receiving and handling of both rail and barge coal deliveries.
4. Alabama Power Company had expressed their willingness to co-
operate and participate in this program by making the unit avail-
able for the required modifications and tests.
5. The results of a unit operating survey indicated that Barry 1 is
acceptable for the planned experimental NOx control study modi-
fications. A detailed report of this study is included in Sec-
tion VI. Briefly, unit operating flexibility, ash handling sys-
tems, fan capacities and normal operation NOx levels were found
to be acceptable for the purposes of this program. A plot of
NOx values versus excess air at various unit loadings is shown in
Figure 2.
Task II - DETAILED TEST PROGRAMS
The detailed test programs were developed using a statistical program
design approach. In this manner maximum program efficiency can be at-
tained by obtaining the maximum informational output from each test.
Using this approach the individual variables considered for evaluation
were first identified and then the minimum number of variable combina-
tions which must be tested to properly evaluate each variable was
established.
The individual variables identified for evaluation in one case were as
follows:
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ALABAMA POWER COMPANY
BARRY No. 1
/ia, i t J
r?:j /T1
FIGURE 1
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ALABAMA POWER COMPANY - BARRY NO. 1
NOX VS. PERCENT EXCESS AIR
O
UJ
o:
CQ
o
X
o
0.6-
0.5--
0.4--
0.3-.
0.2-
0.1--
4 Mill Operation
.0'
-400
3 Mill Operation •
Overfire Air Operation ?
LEGEND
Unit Load
A 142 MW
& 127 MW
0 113 MW
500
300
• 100
C\J
o
ro
o
Q-
0.
X
O
PERCENT EXCESS AIR
FIGURE 2
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Excess Air
Unit Loading
Air Preheat Temperature
Biased Firing
Gas Recirculation to:
a. Secondary Air Ducts
b. Coal Pulverizers
c. Combination of the above
Overfire Air
Water Injection to the Firing Zone
For the second case, the variables to be evaluated were:
Excess Air
Unit Loading
Biased Firing
Overfire Air
Based on these variables the detailed test programs were developed
and are presented in Section VI.
The degree to which each process variable or modification would be
applied and the process measurements necessary to evaluate unit
performance follow.
Process Modifications
A. Overfire Air System
The overfire air system was designed to introduce a maximum of
20 percent of full load combustion air above the fuel admission
nozzles through two additional compartments in each furnace cor-
ner located approximately eight feet above the fuel admission zone.
Overfire air can also be supplied to the furnace through the top
two compartments of the existing windbox when the upper eleva-
tion of fuel nozzles is not in use. The overfire air nozzles
will tilt +30° in the vertical plane independently of the main
fuel and aTr nozzles. Independent dampers for each overfire air
compartment will be provided as a means to study the influence
of location and velocity of overfire air introduction.
B. Gas Recirculation System
The gas recirculation system was designed to recirculate flue
gas to the secondary air duct and coal pulverizers either
separately or in combination. The system would provide for
a maximum of 40 percent recirculation at 80 percent unit
loading and permit substituting gas recirculation for hot
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air to the coal pulverizers while introducing tempering air
in the conventional manner. A gas recirculation temperature
range of 300 to 650F would be possible by varying the weight
ratio of flue gas taken from the air preheater gas inlet and
outlet.
C. Air Preheat System
The preheated air temperature entering the secondary air duct
can be varied by bypassing the air and/or gas side of the air
preheaters to provide the maximum system flexibility.
D. Mater Injection System
Water injection can be admitted into the furnace through two
elevations of atomizing spray nozzles located between the top
two and bottom two fuel nozzle elevations. A maximum injec-
tion rate of 50 pounds per million BTU fired can be used.
Process Variables
Excess air, unit load, and fuel and air distribution will be varied
within the current limitations of the existing equipment. These limits
were evaluated in the unit operating survey conducted in Task I and are
presented in Section VI.
Process Measurements
Operation of the unit as proposed in the experimental study will pro-
duce variations in unit operation and thermal performance. The fol-
lowing process measurements are required to properly assess the impact
of these changes on new unit design and the retrofitting of existing
units.
A. Furnace Absorption
Recirculating gases to the secondary air compartments and
staging of combustion air will effect changes in both peak
and average furnace waterwall temperatures and absorption
rates. The waterwall crown temperatures and absorption rates
must therefore be determined to evaluate th.e impact of varia-
tions in average and peak rates and absorption profiles on
unit design.
B. Furnace Corrosion Probes
Unit operation with staged combustion air may result in local
reducing atmospheres within the furnace envelope, resulting
in accelerated waterwall corrosion rates. To assess the im-
pact of this type of operation on waterwall wastage, furnace
corrosion probes will be utilized.
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C. Sensible Heat Leaving the Furnace
Variations in furnace heat absorption rates due to modifying
the combustion process will result in increasing or decreasing
the sensible heat leaving the furnace envelope and entering
the superheat and reheat sections of the unit. To determine
the sensible heat leaving the furnace, the exit gas tempera-
ture will be measured at the vertical furnace outlet plane
using water cooled probes with radiation shielded thermocou-
ples.
D. Superheat, Reheat and Economizer Section Absorptions
Variations in the gas temperature and gas flow leaving the
furnace envelope and entering the convective sections of the
unit will affect the total heat pickup of each section. To
assess the impact of modified operation on superheat, reheat
and economizer performance, the absorption rates for each
section will be determined.
Variation in absorption rates may require resurfacing when
retrofitting existing units for modified operation.
E. Air Heater Performance
Air and gas temperatures and gas side oxygen concentrations
entering and leaving the air heater are required to calculate
air heater performance, unit efficiency, heat losses and air
and gas flow rates.
F. Fuel and Ash Analysis
During each test, a representative fuel sample must be obtained
for later analysis. The fuel analyses are required to perform
combustion calculations necessary to determine excess air lev-
els and unit gas and air flow rates. Pulverized coal fineness
samples will be obtained to determine the effect, if any, on
furnace wall deposit characteristics, solid combustibles losses,
NOX levels and related emissions.
In addition, coal ash analyses are required to determine ash
properties such as base/acid ratios and ash deformation, soft-
ening and fluid temperatures necessary for evaluating the fur-
nace wall deposit characteristics of coal fuels. Furnace
bottom ash, fly ash and coal pulverizer rejects analyses are
also required to determine heat losses and material balances.
Specific instrumentation and methods to be used in measuring
these process variables and the flue gas emission constituents
are defined in the detailed test plan.
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Task III - ENGINEERING DRAWINGS. COST ESTIMATES AND DETAILED TIME
SCHEDULES
Engineering Drawings
Arrangement drawings were completed showing necessary duct arrange-
ments for the overfire air and gas recirculation systems, the overfire
air register arrangements and control system interfaces with the ex-
isting unit. The general arrangement drawings for the ductwork in-
dicate that the proposed control systems can be physically installed
within the existing station without serious structural interferences.
The modification ductwork final locations were determined by an exten-
sive design review and engineering field check of actual existing
equipment configurations and locations.
Cost Estimates
The cost of fabricating, installing and testing the overfire air and
gas recirculation systems were estimated both as a complete system and
as individually installed systems. These estimates do not include ad-
ditional fuel costs incurred during the test program as Alabama Power
Company has agreed to assume these costs.
Detailed Time Schedules
Due to difficulties encountered in establishing when authorization to
proceed with follow-on program phases would be received, it was not
possible to finalize a detailed time schedule for installation of the
control systems. Schedules based on elapsed time from start of contract
were prepared and are shown in Figures 3 and 4. These schedules must be
coordinated with a unit outage occurring in the tenth to twelfth program
month. Such an outage is currently available in the spring of 1974.
The drawings and cost estimates prepared under Task III are presented
in Section VI.
Task IV - COMBUSTION TECHNIQUE APPLICATION COSTS
Application Study Results
Based on the cost estimates developed under Task III and Combustion
Engineering, Inc.'s current knowledge, cost ranges were developed for
applying the NOx control techniques proposed in this program to new
and existing unit designs. These cost ranges are illustrated in
Figures 5 and 6.
Specifically, four possible methods of reducing NOx emission levels
from tangentially coal fired steam generators were evaluated and the
cost trends for each method estimated for both new and existing units.
The reduction methods considered included overfire air, gas recircula-
tion to the secondary air ducts, gas recirculation to the coal pulver-
izer/primary air system and furnace water injection. The cost trends
for these methods were projected over a unit size range of 125 to 750 MW.
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PROGRAM SCHEDULE
FOR EVALUATION OF OVERFIRE AIR, GAS RECIRCULATION, AIR
PREHEAT AND WATER INJECTION SYSTEMS AND EXISTING PROCESS VARIABLES
Phase
2
3
4
5
Task
1
2
3
4
5
1
2
1
2
1
Task Description
Prepare Design Drawings for
Fabrication & Erection of N0y
Control Systems
Purchase Equipment & Fabricate
Equipment
Install Test Instrumentation
Perform Baseline Tests
Perform Bias Firing Tests
Deliver Equipment and Modify
Unit
Final Test Preparation
Conduct Tests
Evaluate Results & Prepare
Final Report
Prepare Application Guidelines
for Minimizing NO.,
-cv,2;=™2^£i£!±22S£;£i£!£;£S
I
|Purch| Fabricate "|
1 •
| Test | RPT |
L Testl RP'tl
1 1
1 |
1 Test 1
I Evaluate | Report
1
ro
i
FIGURE 3
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PROGRAM SCHEDULE
FOR EVALUATION OF BIASED AND OVERFIRE AIR FIRING
AND EXISTING PROCESS VARIABLES
Phase
2
3
4
5
Task
1
2
3
4
5
1
2
1
2
1
.
Task Description
Prepare Design Drawings for
Fabrication & Erection of NOX
Control Systems
Purchase EouiDment & Fabricate
Equipment
Install Test Instrumentation
Perform Baseline Tests
Perform Bias Firing Tests
Deliver Equipment and Modify
Unit
Final Test Preparation
Conduct Tests
Evaluate Results & Preoare
Final Report
Prepare Application Guidelines
for Minimizing NOX
Program Month
•— CM CO «3- L0 tot^COO>OI~CVJCO**invO^CO
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COSTS OF NOX CONTROL METHODS
NEW COAL FIRED UNITS
(INCLUDED IN INITIAL DESIGN)
DIVIDED
FURNACES
DBOX GAS RECIRCULATION
RFIRE AIR
COMBINED
OVgRFIRE AIR AND WINDBOX
GAS RECIRCULATION
RECIRCULATION THRU
MILLS
WJALDBOX WATER INJECTION
200
300
400
500
600
700
800
UNIT SIZE
(MW)
FIGURE 5
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to
h
8
a:
o
UJ
O
O
a.
a
LU
COSTS OF NOX CONTROL METHODS
EXISTING COAL"FIRED UNITS
(HEATING SURFACE CHANGES NOT INCLUDED)
WINDBOX GAS RECIROULATION
OVERFIRE AIR
BINED
RFIRE AIR AND WINDBOX
RECIRCULATION
RECIRCULATION THRU MILLS
ER INJECTION INCLUDING FAN
$ DUCT CHANGES
ER INJECTION WITHOUT FAN
DUCT CHANGES
100
200
300
400
500
600
700
800
UNIT SIZE
(MW)
FIGURE 6
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The results of the study indicate that for any given unit size (450 MW
chosen for an example comparison) the lowest cost method is found to
be overfire air which results in a .14 to .50 $/KW additional unit cost
for a new or existing unit respectively.
This method incurs no loss in unit efficiency or increased operating
expenses.
Gas recirculation introduced either through the secondary air ducts or
the coal pulverizers and primary transport air system results in higher
equipment costs than overfire air and requires additional power for fan
operation.
Water injection introduced into the fuel firing zone of the unit is at-
tractive from the standpoint of low initial equipment costs, however,
losses in unit efficiency resulting in increased fuel costs and signi-
ficant water consumption make it the most expensive system to operate.
The use of either gas recirculation or water injection in existing
units could result in a 10 to 20 percent decrease in load capability
due to increased gas flow weights.
The following conclusions were drawn from this study.
1. The lowest cost method for reducing NOX emission levels on
new and existing units is the incorporation of an overfire
air system. No additional operating costs are involved.
2. Gas recirculation either to the windbox or coal pulverizers
is a promising control system but is significantly more costly
than overfire air and requires additional fan power. In ex-
isting units, the necessity to reduce unit capacity to main-
tain acceptable gas velocities imposes an additional penalty.
3. Gas recirculation to the coal pulverizers would cost approxi-
mately 15 percent less than windbox gas recirculation, however,
this method may require increased excess air to maintain ade-
quate combustion.
4. Water injection has initially low equipment costs, but due to
high operating costs resulting from losses in unit efficiency,
is the least desirable of the systems evaluated. This system
may also require reduced unit capacity.
5. In general, the cost of applying any of the control methods
studied to an existing unit is approximately twice that of a
new unit design.
Application Study Design
For the purpose of this study the following five modes of unit operation
were chosen as potentially effective means for the reduction of NOX emis-
sions.
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The quantities of overfire air, gas recirculation and water injection
selected for the economic evaluation, while reasonable, do not neces-
sarily represent commercially feasible operation or control methods
which would be recommended by Combustion Engineering, Inc.
1. Introducing 20 percent of the total combustion air over the
fuel firing zone as overfire air.
2. Introducing 30 percent flue gas recirculation through the
secondary air ducts and windbox compartments.
3. Combining the 20 percent overfire air and 30 percent flue
gas recirculation of 1 and 2.
4. Introducing 17 percent flue gas recirculation through the
transport air/coal pulverizer system.
5. Introducing water injection into the fuel firing zone at a
rate of 5 percent of total evaporation.
The economic comparisons of the five NOv emission control methods were
based on 1973 delivered and erected costs for the steam generators and
associated equipment.
The cost estimates presented for the revision of existing units were
based on studies performed on units within the 125 to 750 MW size range
including those costs generated under Phase I, Task 3, for the Barry
No. 1 unit. The cost estimates presented for incorporating control
methods in new unit designs were based on Combustion Engineering expe-
rience and current practice for overfire air and gas recirculation
systems.
As can be seen from Figures 5 and 6 the cost ranges for existing units
vary more widely than new units. This is due mainly to variations in
unit design and construction which either hinder or aid the installation
of a given control system. For example, an overfire air system may be
designed as a windbox extension unless existing structural requirements
and obstructions necessitate installation of a more costly system in-
cluding extensive ductwork and individual air injection ports. The
same condition exists for water injection systems when the need to
maintain unit capacity dictates changes in unit ducting. Except where
noted, all system costs are estimated on a +10 percent basis. The
cost range of the combined overfire air and windbox gas recirculation
system was arrived at as the sum of the cost ranges of the individual
systems. The cost ranges presented for existing units do not include
any changes to heating surface as these changes must be calculated on
an individual unit basis. Due to variations in existing designs,
heating surfaces may increase, decrease or remain unchanged for a
given control method.
At approximately 600 MW, single cell fired furnaces reach a practical
size limit and divided furnace designs are employed. Since a divided
tangentially fired furnace has double the firing corners of a single
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cell furnace, the costs of windboxes and ducts increase significantly
as shown on Figures 5 and 6. As shown, the costs of overfire air,
windbox gas recirculation and windbox water injection increase from
30 to 50 percent.
In addition to the increased capital costs resulting from including
an NOx control system in a unit design, the increased unit operating
costs must be considered. . The increased annual operating costs were
determined for a 100, 450 and 750 MW unit of new design and are shown
in Table 1. The equipment costs shown are determined from Figure 5.
Using the 450 MW unit as an example at a rate of .14 $/KW results in
an increase in unit capital cost of $63,000. The additional annual
fixed charges, fuel and fan power costs for each of the five NOv con-
trol methods studied and the criteria on which these costs are based
are also listed in Table 1.
Again using the 450 MW unit as an example the study indicates that
water injection is the most expensive system to operate at .332 mills/
KWHR due primarily to increased fuel costs resulting from losses in
unit efficiency. The least expensive control system to operate was
overfire air at .004 mills/KWHR with gas recirculation either alone
or in combination with overfire air ranging from .108 to .121 mills/
KWHR.
To put these operating costs in perspective, they can be compared to
"average" generating costs presented in Table 1 for various sizes of
unmodified units. '
Operating costs were developed only for a new unit design as it is
possible to assume that design parameters would remain unchanged from
a unit designed without NOx controls. However for existing units, gas
and air flow rate changes, increased draft losses and changes in unit
load capabilities would vary to such a degree that each unit would
have to be treated individually regardless of rating and costs would
vary to such a degree that they would not be useful to a general study.
VI. ATTACHMENTS
This section includes all material referenced in the preceding sections
of this report.
ATTACHMENT
I Unit Operating Survey
II Detailed Test Programs
III Engineering Drawings
IV Cost Estimates for Conducting Pilot
Field Test Programs
V Combustion Technique Application Study
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TABLE I
1973 OPERATING COSTS OF NOX CONTROL METHODS FOR
NEW COAL FIRED UNITS
SINGLE FURNACE
CONTROL METHOD
MW RATING
EQUIPMENT COSTS
ANNUAL FIXED CHARGE 103$
ADDITIONAL ANNUAL FUEL
COST
ADDITIONAL ANNUAL FAN
POWER COST
TOTAL ANNUAL COST
OPERATING COST MILLS/KWHR
OVERF IRE
AIR (20$)
103$
103$
103$
103$
103$
KWHR
100
31
5
...
— .
5
0.009
450
63
10
...
...
10
0.004
750
90
14
...
...
14
•0.003
WlNDBOX
FLUE GAS
RECIRC. (30$)
100
350
56
...
21
77
0.143
450
1185
190
...
95
285
0.117
750
1650
264
...
158
422
0.104
COMB i NAT ION
OF 1 AND
100
375
60
...
21
81
0.150
450
1248
200
95
295
0.121
2
750
1800
288
...
158
446
0.110
COAL MILL
FLUE GAS
REC
100
300
48
...
22
70
0.130
IRC. (17$)
450
1015
162
100
262
0.108
750
1425
228
...
166
394
0.097
WATER
INJECTION
100
160
26
147
13
186
0.344
450
560
90
660
58
808
0.332
750
825
132
1099
97
1328
0.327^
i
VO
i
BASED ON: A. DELIVERED AND ERECTED EQUIPMENT COSTS (+ 10$ ACCURACY). EXCLUDING CONTINGENCY AND INTEREST DURING CONSTRUCTION.
B. 5400 HR/YR AT RATED MW AND NET PLANT HEAT RATE OF 9400 BTU/KWHR.
C. 50^/106BTU COAL COST.
D. $250/HP FAN POWER COST, OR $40/HP PER YEAR.
E. ANNUAL FIXED CHARGE RATE OF 16$.
F. OPERATING COSTS ARE + 10$.
G. DOES NOT INCLUDE COST OF WATER PIPING IN PLANT OR COST OF MAKEUP WATER.
BASE UNIT OPERATING COSTS* FOR COAL FIRED POWER PLANTS EXCLUDING SOg REMOVAL SYSTEMS.
100 450 750
16.2 13.5 12.6
*|NCLUDES 1973 CAPITAL COSTS, LABOR, MAINTENANCE, FUEL COSTS +20$ CONTINGENCY +17$ INTEREST DURING CONSTRUCTION.
UNIT SIZE MW
OPERATING COST MILLS/KWHR
-------
-21-
SECTION VI
ATTACHMENT I
UNIT OPERATING SURVEY
-------
-23-
COMBUSTION ENGINEERING, INC.
FIELD TESTING AND
PERFORMANCE RESULTS
TEST REPORT 72-11
ENVIRONMENTAL PROTECTION AGENCY
PILOT FIELD TEST PROGRAM TO
STUDY METHODS FOR REDUCTIONS
OF NOx FORMATION IN TANGENTIALLY
COAL FIRED STEAM GENERATING UNITS
PHASE I - TASK I
UNIT OPERATING SURVEY
ALABAMA POWER CO.
BARRY STATION, UNIT #1
CONTRACT 6472
PROJECT 900126
A. P. SELKER
-------
-25-
TABLE OF CONTENTS
Page
Unit Description 27
Test Objectives 27
Conclusions 27
Discussion 28
Test Data Acquisition 28
Performance Calculations 28
Maximum Continuous Rating Evaluation 29
Peak Load Evaluation 29
Lower Three Mill Operation 29
FD & ID Fan Capacity Evaluation 30
Figures
Unit Side Elevation Figure 1 32
Draft Loss Vs. Unit Gas Weight 2 33
NOx Vs. Percent Excess Air 3 34
Combustion Characteristics 4 35
Tabulations
NOX Test Data Summary Sheet 1 36
Draft Loss Summary 2 37
Fuel Air Comp.Press. Vs. Comp. Damper Pos. 3 38
Board Data Summary 4.4A.4B 39, 40, 41
Coal Fuel Analysis 5 42
-------
-27-
UNIT DESCRIPTION
Barry Station, Unit #1 is a natural circulation, balanced draft boiler firing
coal through four elevations of tilting tangential fuel nozzles. The steam
capacity at maximum continuous rating (MCR) is 900,000 LBS/HR main steam flow
with a superheat outlet temperature and pressure of 1000 F and 1875 PSIG.
Superheat and reheat temperatures are controlled by fuel nozzle tilt and spray
desuperheating. A unit side elevation is shown on Figure 1.
TEST OBJECTIVES
The objectives of this test program were to:
1. Determine the acceptability of Barry #1 for modification to evaluate
overfire air and windbox gas recirculation as NOx controls for coal
firing.
2. Obtain NOx emission levels and all supporting data while varying the
following operating conditions.
A. Percent Oxygen
B. Overfire air through the top elevation of auxiliary and
fuel air compartments.
3. Obtain NOx emission levels and all supporting data while operating
at overfire air conditions for a twenty-four hour period.
4. Record operational difficulties and equipment limitations in ob-
taining and maintaining test conditions of Objectives 2 and 3.
5. Obtain draft loss data at all test conditions to assist in sizing
of the gas recirculation fan and associated ductwork.
CONCLUSIONS
1. The test program was performed while firing Illinois coal. The results
indicate that Barry #1 is acceptable for the planned experimental NOX
control study modifications as follows.
A. There were no unit operating difficulties encountered during the
test program which would limit the proposed unit modification
and experimental study.
B. The unit can be operated at peak load conditions for extended
periods of time using normal ash removal procedures indicating the
adequacy of present wall blowing, soot blowing and ash removal
facilities.
-------
-28-
C. Approximately 88 percent unit load can be carried with lower three
mill operation permitting overfire air to be introduced through the
top fuel and air compartments.
D. Operation with maximum excess air at the lower three mill, 88% MCR
condition indicates that 40% gas recirculation may be introduced
into the unit windbox at normal operating excess air without ex-
ceeding existing ID and FD fan capacities or superheat and reheat
temperature limits. The amount of recirculation acceptable from
a combustion standpoint will be established during the experimental
test program.
E. Operation at 6 percent excess air is possible at 100 and 88 percent
MCR without encountering unit slagging or flame instability indi-
cating that low excess air operation may be studied. Normal plant
operation at peak load conditions is 9.5 percent excess air.
2. NOX levels obtained during this program are sufficiently representative
of the levels obtained from current large furnace designs.
DISCUSSION
Test Data Acquisition
The flue gas samples for determination of the NOX emission levels and percent
oxygen were obtained at the economizer outlet duct. The flue gas samples were
drawn from an 8 point grid and blended to obtain an accurate average oxygen
and NOX reading.
The NOX levels were determined by the phenol-disulfonic acid procedure as
specified in ASTM Procedure D-1608. All NOX levels are reported in PPM/VOL
on a dry basis adjusted to 3 percent oxygen and as LB N02/10°BTU fired. A
summary of the NOX test data is tabulated on Sheet 1. Unit draft losses were
determined using both station data and test manometers. Draft loss data is
tabulated on Sheets 2 and 3 and the draft loss test points are shown on Fig-
ure 1. The fuel air compartment pressures versus compartment damper positions
shown on Sheet 3 were obtained in support of analytical effort to calculate
compartment flow rates based on damper positions. Station instrumentation
was used to obtain unit operating data which is tabulated on Sheet 4.
Coal samples were obtained during each day of testing. The samples were ob-
tained from each feeder and blended to form a composite sample. The analysis
of these samples are shown on Sheet 5. A plot of the excess air versus the
products of combustion, percent C02 and percent 02 as calculated from the
ultimate fuel analysis is shown on Figure 4.
Performance Calculations
Unit gas weights and efficiencies were calculated for each test condition
using operating board data and are tabulated on test data Sheet 1. The unit
efficiency was determined for each test by the heat balance losses method.
Unit gas weight was determined by dividing the total unit absorption (BTU/HR)
by the efficiency to obtain the unit heat input (BTU/HR) which was then
-------
-29-
multiplied by the wet products of combustion (LB/10°BTU fired - determined
from the fuel analysis - Figure 4) to obtain the pounds per hour of gas flow.
An evaluation of FD and ID fan capacity when recirculating flue gas to the
furnace are detailed in a later section of this report.
Maximum Continuous Rating Evaluation
Tests 1, 2 and 3 were conducted at 100 percent maximum continuous rating (MCR:
127 MW) to determine unit draft losses over the maximum possible range of
excess air and the NOv emission levels at these excess airs. As shown on
Figures 2 and 3 and the following table, the draft loss and NOx level in-
creased with increased excess air (gas weight).
1
2
3
UNIT DRAFT LOSS-"WG NOX PPM EXCESS AIR GAS WT.
FD FAN OUT-ID FAN IN (VOL) PERCENT 103LB/HR
23.8 433 26 1163.4
21.2 370 18 1112.2
13.5 220 6 978.3
MAIN STEAM FLOW
1Q3LB/HR
880
900
900
The range of excess air obtainable was limited to a maximum of 26 percent by
ID fan capacity and to a minimum of 6 percent by allowable superheat/reheat
outlet steam temperature differential.
Peak Load Evaluation
Test 4 was conducted at peak load (112 percent MCR: 142 MW) to determine
draft losses and NOX emission levels at the maximum possible unit loading.
UNIT DRAFT LOSS-"WG NOX PPM EXCESS AIR GAS WT.
FD FAN OUT-ID FAN IN (VOL) PERCENT 1Q3LB/HR
23.3 271 9.5 1106.8
MAIN STEAM FLOW
103LB/HR
975
The excess air was limited to 9.5 percent by ID fan capacity. The NOX level
of 271 PPM compares well with the levels obtained at 100 percent MCR opera-
tion as shown on Figure 3. Unit draft loss versus gas weight is shown on
Figure 2. Unit operation was observed for eight of approximately twenty-
four hours of continuous operation at peak load. No unit operating dif-
ficulties such as furnace slagging or ash removel problems were noted during
this period. The 112 percent MCR loading is normally carried in day to day
operation.
Lower Three Mill Operation
Tests 5, 6, 7 and 8 were conducted to determine the maximum unit loading ob-
tainable with the lower three coal elevations in service, the range of excess
air obtainable, unit draft loss and the effect of overfire air on NOX emission
-------
-30-
levels at normal operating excess air. A twenty-four hour evaluation of over-
fire air operation was not possible due to unit load demand. The results of
these tests are as follows:
TEST UNIT DRAFT LOSS-"WG NOx PPM EXCESS AIR GAS WT. MAIN STEAM FLOW
NO. FD FAN OUT-ID FAN IN (VOL) PERCENT 103LB/HR 103LB/HR
5 24 405 37.5 1091.3 760
6 18.5 268 17.5 917.8 770
*7 17.4 209 18 930.3 765
8 15.55 — 6 812.5 765
*0verfire Air Operation
A maximum unit loading of approximately 88 percent MCR was obtainable with
the lower three elevations of coal mills in operation.
The range of excess air at this loading was limited to a maximum of 37.5 per-
cen by ID fan capacity and to a minimum of 6.0 percent by allowable super-
heat/reheat outlet steam temperature differential. At normal operating excess
air (17.5 percent) opening the top elevation fuel and auxiliary dampers re-
duced the NOX levels by 22 percent.
FD & ID Fan Capacity Evaluation
The calculated gas weights for Test 6 indicate that at 88% unit loading, 40
percent gas recirculation can be introduced through the windbox compartments
without exceeding unit fan capacities. The gas weights used in this deter-
mination are as follows.
At normal operation with 17.5% excess air (Test 6) the following gas weights
and draft losses were determined.
GAS & AIR WEIGHTS
LOCATION DRAFT LOSS-"WG AP "WG X109LB/HR
Air from FD Fan Out. 4.25-1 957.6*
to Air Heater Air Out. , ,c
/. /o
Air from Air Heater 3.5 -^ 883.8
Air Outlet to Lower
Furnace
Gas from Lower Furnace
to Air Heater Gas Inlet 3.45n
Gas from Air Heater Gas
Inlet to ID Fan Inlet 7.3 -I
917.8
10.75
991.6*
*Air and gas weight assuming 8% air heater leakage. Air weight includes mill
tempering air and does not include hot air recirculation.
-------
-31-
Introducing 40% gas recirculation will increase the gas weight between the
lower furnace and the air heater gas inlet to 1.4 X 917.8 X 103 = 1284.9 X
103LB/HR.
The pressure drop in this section will therefore increase to:
AP = 3.45
= 6.76"WG
The air and gas weight between the air heater air outlet and the lower furnace
will increase to 1250.9 X 103LB/HR with a corresponding AP = 3.5 (1250.9/
883.8)2 = 6.86"W6.
The unit gas weights and draft losses at 40% gas recirculation are therefore
as follows.
LOCATION
Air from FD Fan Outlet
to Air Heater Air Outlet
Air from Air Heater Air
Outlet to Lower Furnace
Gas from Lower Furnace to
Air Heater Gas Inlet
Gas from Air Heater Gas
Inlet to ID Fan Inlet
DRAFT LOSS-"WG
GAS & AIR WEIGHTS
AP "WG X103LB/HR
11.25
14.06
957.6
1250.9
1284.9
991; 6
The total pressure drop from the lower furnace to the ID fan inlet increases
to 14.06 "WG which is within the ID fan capacity of 14.25 "WG established in
Test 5. The pressure drop is 9.75 "WG from the FD fan outlet to the lower
furnace at 73% FD fan loading. When extrapolated to 100% FD fan loading at
865 RPM the maximum allowable pressure drop increases to 11.9 "WG which is
greater than the total calculated head of 11.25 "WG.
The superheat and reheat outlet temperatures at maximum excess air were 992 F
and 927 F respectively without the use of desuperheat sprays and at a fuel
nozzle tilt of -2 degrees.
A. P. Selker
APSiREB
-------
-32-
DRAFT LOSS TEST POINT LOCATIONS
FIGURE 1
-------
-33-
DRAFT LOSS VS. UNIT GAS WEIGHT
o>
CO
CO
o
800
900 1000 1100
UNIT GAS WEIGHT - 1Q3LB/HR
1200
FIGURE 2
-------
-34-
NOV VS. PERCENT EXCESS AIR
500
400
CM
O
CO
O
2
ef.
D.
Q.
ox
300
200
100
**'
v^
Overfire Air Operation
LEGEND
Unit Load
A 142 m
& 127 m
O 112 MW
10 20 30
PERCENT EXCESS AIR
40
FIGURE 3
-------
-35-
COMBUSTION CHARACTERISTICS
CM
O
o
08
CVJ
O
O
a:
Moisture
Hydrogen
Carbon
Sufi fur
Nitrogen
Oxygen
Ash
ca
10
o
CO
o
o
o
oo
o
0 10 20
30 40 50 60 70
PERCENT EXCESS AIR
90 100 110 120
FIGURE 4
-------
NOX TEST DATA SUMMARY
TEST NO.
Purpose of Test
Date
Load MW
Main Steam Flow 103LB/HR
% 02 - Economizer Outlet
Fuel Elevations in Service
-r-
r— 4->
N -r-
N
O O
•Z. Q-
°F
°F
02 PPM BY VOL.
LB/IO^BTU FIRED
Unit Efficiency-%
Gas Weight 1Q3LB/HR
1
FULL
4/6/72
127
880
4.4
4
-14
100
30
100
30
100
100
30
100
30
100
995
947
433
.581
90,9
1,163.4
2
LOAD - %
4/6/72
127
900
3.2
4
0
100
30
100
30
100
100
30
100
30
100
985
945
370
,497
90.9
1,112.2
3_
02 VAR.
4/6/72
126
900
1.2
4
+5
50
30
60
30
80
80
30
80
30
80
950
900
220
.295
91.3
978.3
4_
MAX. LOAD
NORM. OPER.
4/7/72
142
975
1.8
4
-7
100
30
100
30
100
100
30
100
30
100
997
972
271
.364
91.5
1,106.8
8
MAX. 3 MILL LOAD - % 02 VAR.
& OVERFIRE AIR
4/11/72
112
760
5.8
3
-2
0
0
80
30
80
80
30
80
30
80
992
927
405
.544
91.2
1,091.3
4/12/72
112
770
3.1
3
+10
0
0
30
20
80
80
20
70
20
70
950
887
268
917.8
4/12/72
112
765
3.2
3
+10
100
20
80
20
80
80
20
70
20
70
965
907
209
281
91.4
930.3
4/12/72
112
765
1.2
3
+14
0
0
30
20
80
80
20
70
20
70
915
860
— — _
91 .9
812.5
I
LO
CTl
I
SHEET 1
-------
DRAFT LOSS SUMMARY
Test No.
Test Pt.*
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
Locati on**
"A" FD Fan Out-BD
"B" FD Fan Out-BD
"B" FD Fan Out-Test
"A" AH Air Out-BD
"B" AH Air Out-BD
"B" AH Air Out-Test
D Elev. Left Rear
Fuel Air Comp.-Test
A Elev. Left Rear
Fuel Air Comp.-Test
Left Mill Air Duct
at Windbox-Test
Mill Ar Duct
at B-Elev. Mill-Test
Upper Furn.-BD
Upper Furn.-Test
SH Cavity-BD
Econ. In.-BD
Econ. Out-Test
"A"
"B"
"A"
"B"
linn
AH Gas In-BD
AH Gas In-BD
AH Gas Out-BD
AH Gas Out-BD
B" AH Gas Out-Test
"A"
"B"
ID Fan Suction-BD
ID Fan Suction-BD
*Location Shown on Figure 1
**BD - Board Data
Test - Test Manometer
1
8.2
8.2
8.6
2.5
2.2
3.0
.3
.4
1.9
1.6
-.3
-.5
-1.5
-5.3
-5.6
-6.1
-6.2
-11.1
-1 1 .2
-12.4
-15.2
-16.0
2
6.5
6.5
6.9
1.8
1.5
1.4
-.3
-.3
1.1
.8
-.37
-.6
-1.5
-5.0
-5.3
-5.5
-5.7
-9.5
-10.2
-11.3
-14.5
-15.0
3
4.8
5.0
5.1
1.3
1.2
1.3
-.6
-.5
.2
-.2
-.4
-.6
-.2
-3.8
-4.2
-4.6
-4.7
-7.7
-8.4
-9.4
-11.9
-12.7
4
Pressure
8.0
7.4
8.2
2.1
2.1
2.1
-.3
0
1.2
.8
-.33
-.45
-1.3
-5.2
-5.9
-6.2
-6.2
-11.1
-11.2
-12.4
-15.2
-16.0
5
- In.
8.5
9.0
9.7
3.0
2.5
3.2
.6
.2
2.7
2.2
-.45
-.45
-1.3
-5.1
-5.4
-5.7
-5.8
-10.0
-11.8
-11.7
-15.0
-15.5
6
Wg
6.5
7.0
7.6
2.5
2.5
2.0
-.5
-.6
2.0
1.5
-.3 .
-.5
-1.4
-3.7
-4.4
-4.3
-4.6
-7.4
-8.2
-9.0
-11.5
-12.0
7
5.2
5.5
6.3
1.5
1.3
2.1
-.5
-.6
1.3
.8
-.4
-.5
-1.3
-4.0
-4.4
-4.5
-4.5
-7.7
-8.3
-9.4
-11.9
-12.2
8
5.1
5.5
5.6
2.0
1.8
1.9
-1.0
-.8
1.6
1.1
-.4
-.4
-1.2
-3.3
-3.6
-3.9
-4.1
-6.5
-7.3
-7.8
-9.8
-10.7
co
-«j
SHEET 2
-------
FUEL AIR COMP. PRESS. VS. COMPARTMENT DAMPER POS.
TEST 4
Fuel
Comp.
"A" ELEV.
•D" ELEV.
Damper Pos. - % Open
0
20
40
60
80
100
0
20
40
60
80
100
Comp. Press.-"Wg
-1.1
--.4
+ .4
+ .6
+1.2
+1.2
-1.1
-.7
+ .5
+ .8
+1.6
+1.6
Furn.
Press "Wg
Typical Fuel Compartment
and
Test Point Arrangement
TEST TAP
COMP.
DAMPER
co
00
I
COAL
NOZZLE
SHEET 3
-------
BOARD DATA SUMMARY
Test #
Date
Load-MW
Main .Steam Flow -
RH Flow -KH.B/HR
Coal Scale Reading-103LB/HR
RH Spray Valve Pos.% Open
% C02
Fuel Elev. In Serv.
Ignitor Elev. In Serv.
Fuel Nozzle-Tilt-Deg. From Horiz.
Steam & Hater Temp. - F
SHO R
L
LT SHO R
L
SH Desup. Out R
L
RHI
RHO
Feedwater
Econ. Out
R
L
Steam & Water Press.-PSIG
Feedwater
Drum
-SHO
RHI
RHO
1
4-6-72
127
880
800
98.5
20
14.6
4
0
-14
1000
990
835
845
805
815
640
955
940
455
490
2000
1960
1875
405
375
2
4-6-72
127
900
810
98.5
0
15.3
4
0
0
980
990
805
820
800
810
638
940
950
455
490
2000
1950
1850
405
375
3
4-6-72
126
900
810
98
0
15.8
4
0
+5
945
955
760
780
750
770
610
900
900
455
480
2000
1950
1850
405
375
4
4-7-72
142
975
860
115
0
16.1
4
0
-7
1000
995
825
810
815
800
665
980
965
468
495
2000
1970
1875
455
425
5
4-11-72
112
760
85.5
0
14.1
Lwr 3
0
-2
990
995
840
850
830
840
630
925
930
445
485
1990
1950
1875
348
321
6
4-12-72
112
770
87.0
0
15.5
Lwr 3
0
+10
945
955
795
795
790
790
600
880
895
445
475
2000
1950
1875
350
325
7
4-12-72
112
765
86
15
Lwr
5
0
2
3
0
+10
960
970
810
820
800
810
615
905
910
445
475
2000
1950
1875
350
325
8
4-12-72
112
765
84
16
Lwr
5
0
4
3
0
+14
905
925
770
770
760
760
575
855
865
445
470
2000
1950
1875
350
325
CO
10
SHEET 4
-------
BOARD DATA SUMMARY
Test # ] o ,
'2345678
Air & Gas Temp.-F
* «r 0 t JM JJ= "| "5 IK .25 ,,5 ,20
AH Gas In we !?? ?°* 505 490 485 490 485
-" "0 III g? - gg f»
Air & Gas Press.-"Wg
FD Fan Out A
B
AH Air Out A
B
Furn.
SH Cavity
Econ. In
Econ. Out A
B
AH Gas Diff. A
B
ID Fan In A
B
Pulv. Air In A
B
C
D
Exh. Air Out A
B
C
D
8.2
8.2
2f
.5
2/*
.2
-1.5
-5.3
-6.1
-6.2
5f\
.0
5.0+
•15.2
•16.0
-1.5
-1.5
-1 .3
-2.7
9 A
.0
12.0
9.8
10.8
6.5
6.5
1.8
1 .5
-.4
-1.5
-5.0
-5.5
-5.7
4.0
4.5
-14.5
-15.0
-1.6
-1.4
-1.5
-3.0
9.0
11.0
10.0
11.5
4.8
5.0
1.3
1.2
-.4
-.2
-3.8
-4.6
-4.7
3.1
3.7
-11.9
-12.7
-1.5
-1.3
-1.4
-2.8
8.5
11.8
9.3
10.8
7.0
7.3
2.1
2.1
-.37
-1.3
-5.2
-6.2
-6.2
4.9
5.0
-15.2
-16.0
-1.0
-.8
-1.0
-2.3
9.0
12.5
10.3
11.2
8.5
9.0
3.0
2.5
-.45
-1.3
-5.1
-5.7
-5.8
4.3
5.0
-15.0
-15.5
-.6
-1.0
-1.0
-2.2
0
10.5
9.5
10.0
6.5
7.0
2.5
2.5
-.3
-1.4
-3.7
-4.3
-4.6
3.1
3.6
-11.5
-12.0
-.5
-1.0
-1.0
-2.2
0
10.5
9.5
10.5
5.2
5.5
1 .5
1.3
-.4
-1.3
-4.0
-4.5
-4.5
3.2
3.8
-11.9
-12.2
-.6
-1 .0
-1.1
-2.4
n
\J
10.5
9.0
11.0
5 1
+J m I
5.5
2 0
k. • \J
1 .8
- 4
» T^
-1.2
-3.3
-3.9
-4.1
2.6
3 2
\s • (_
-9.8
-10.7
_ 5
• \J
-1 2
l • k.
-1.0
-2.4
Q
10.5
8.5
10.0
SHEET 4A
-------
BOARD DATA SUMMARY
Test #
FD & ID Fan Perf.
ID Fan Speed-RPM A
B
FD Fan Speed-RPM A
B
ID Fan Damper Pos.-% Open A
B
FD Fa.n Damper Pos.-% Open A
B
ID Fan % Loading A
120% Full Scale B
FD Fan % Loading
120% Full Scale
AH Air Recirc. Damper
Pos.-% Open
Mill Perf.
Mi 11 Amps
Mill Temp.
% Feeder Cap
120% Full Scale
Exh. Damper Pos-% Open
A
B
A
B
A
B
C
D
A
B
C
D
A
B
C
D
A
B
C
D
660
650
750
740
100
100
100
100
103
104
86
82
65
45
610
610
655
650
100
100
100
100
78
78
72
70
65
45
550
565
560
580
100
100
100
100
65
66
58
58
65
45
660
650
745
730
100
100
100
100
105
105
86
80
64
42
35
35
37
39
170
165
165
170
52
52
47
52
49
53
48
51
35
38
35
37
165
170
170
170
50
52
46
52
49
52
48
52
40
39
40
42
165
160
160
165
53
54
49
55
51
55
50
54
44
42
43
42
160
160
160
165
60
60
60
60
58
60
60
60
620
630
775
775
100
100
100
100
81
81
87
87
64
43
0
42
40
44
110
160
170
170
0
60
60
60
0
60
60
60
540
540
660
680
100
100
100
100
60
62
62
72
68
47
0
42
41
44
100
160
170
170
0
60
60
60
0
60
60
60
540
550
600
620
100
100
100
100
63
65
65
65
68
47
0
43
42
43
100
160
160
165
0
60
60
60
0
60
60
60
8
490
510
580
590
100
100
100
100
52
55
59
60
68
47
0
43
43
45
100
160
160
165
0
61
60
61
0
60
60
61
SHEET 4B
-------
-42-
FUEL ANALYSIS
Coal to Feeders
Sample No. 1
Date Sampled 4-6-72
Total Moisture 6.6
Volatile Matter
Fixed Carbon
Ash
Total
HHV, Btu/Lb 12300
Moisture 6.6
Hydrogen 3.8
Carbon 68.8
Sulfur 2.1
Nitrogen 1.4
Oxygen 4.7
Ash 12.6
Total TOO"
Ash Fusibility I.T. 1980°F
(Reducing Atm.) S.T. 2320°F
F.T. 2530°F
2
4-7-72
10.1
33.1
44.1
12.7
11280
3.2
4-11-72/4-12-72
7.5
27.2
49.7
15.6
100.0
11710
1.8
SHEET 5
-------
-43-
SECTION VI
ATTACHMENT II
DETAILED TEST PROGRAMS
Two preliminary detailed test programs
prepared for this contract are included
in this attachment. The first test
program is for the evaluation of over-
fire air, gas recirculation, air preheat
and water injection systems and existing
process variables. The second test pro-
gram is limited to evaluation of biased
firing, overfire air system and existing
process variables. Appendices A,B,C,D
and E attached to the first test program
apply to both test programs.
-------
-45-
PRELIMINARY TEST PROGRAM
CONTRACT NO. 68-02-0264
(C-E CONTRACT 6472)
PILOT FIELD TEST PROGRAM TO STUDY
METHODS FOR REDUCTION OF NOX FORMATION IN
TANGENTIALLY COAL FIRED STEAM GENERATING UNITS
PREPARED FOR
THE ENVIRONMENTAL PROTECTION AGENCY
RESEARCH TRIANGLE PARK,
NORTH CAROLINA 27711
JUNE 26,1972
COMBUSTION ENGINEERING, INC.
FIELD TESTING &
PERFORMANCE RESULTS
1000 PROSPECT HILL ROAD
WINDSOR, CONNECTICUT 06095
(203) 688-1911
-------
-47-
TABLE OF CONTENTS
Program Description Page 49
NOX Control Systems 49
Overfire Air System 49
Gas Recirculation System 49
Air Preheat System 49
Water Injection System 50
Existing Process Variables 50
Unit Performance Effects 50
Furnace Absorption 50
Furnace Corrosion Probes 50
Sensible Heat Leaving the Furnace 50
Superheat, Reheat & Economizer Section Absorption 50
Air Preheater Performance 51
Fuel and Ash Analysis 51
Test Program Design 51
Load Variation and Furnace Wall Deposits 51
Excess Air and Air Preheat Temperature Variation 52
Furnace Water Injection 52
Overfire Air Location, Rate, Velocity and Temperature 53
Overfire Air Tilt Variation 53
Flue Gas Recirculation Location and Rate 54
Flue Gas Recirculation Temperature 54
Overfire Air and Flue Gas Recirculation Ratio 55
Overfire Air and Gas Recirc. Oper. with Low Air 55
Preheat, Low excess Air and Furn. Water Inj.
Load Variation at Optimum Conditions 56
Effect of Long Term and Transient Operation 57
Effect of Coal Change 57
Test Instrumentation 57
Preliminary Test Program 50
Emission Level Determination Appendix A 63
Steam Generator Thermal Performance B 75
Coal and Ash Analysis C 92
Evaluation of Corrosion Potential D 93
Waterwall Absorption Measurement and Calculation E 97
Schematic-Overfire Air & Gas Recirculation Systems HO
-------
-49-
PROGRAM DESCRIPTION
The test program is designed to investigate the effects of various experi-
mental combustion process modifications on NOx emission levels from tan-
gential ly coal fired utility boilers. The program will be conducted on a
boiler specially modified to provide for oyerfire air, gas recirculation,
water injection and air preheat variation in addition to the normally
available process variables of excess air, unit loading and air/fuel distri-
bution. The effect of these variables on other emission levels (S02, CO,
carbon loss, hydrocarbons) will also be monitored. The emission control
instrumentation and sampling system are described in Appendix A.
Each combustion process modification will be evaluated separately at steady '
state operating conditions to establish individual process limitations with
respect to effectiveness in reducing NOx levels, safety, reliability and
the effect on unit heat transfer.
The individual process modifications will then be evaluated in various com-
binations to establish optimum methods of reducing NOX emission levels.
Once the acceptability of the optimized methods is established they will be
evaluated with respect to transient and long term operation.
The transient and long term phases of the test program will be repeated with
one or two additional coals in addition to the baseline coal to demonstrate
the applicability of the experimental results to a variety of coal types.
NOy CONTROL SYSTEMS
The following combustion process modifications will be possible with the
NOX control systems.
Overfire Air System
The overfire air system will provide for introducing a maximum of 20 percent
of the total combustion air above the fuel admission nozzles at full load.
The overfire air will enter the furnace tangentially through the top two
compartments of the existing windbox as well as two additional compartments
in each furnace corner located approximately eight feet above the fuel ad-
mission zone. The effect of overfire air will be evaluated at various angles
of introduction with respect to the fuel nozzles (+30°: vertical plane),
velocities and compartment combinations.
Gas Recirculation System
The gas recirculation system will permit recirculating flue gas to the second-
ary air duct and coal pulverizers either separately or in combination. The
system will provide for a maximum of 40% recirculation to the secondary air
duct at 80% unit load. The system will permit substituting gas recircula-
tion for hot air to the coal pulverizers while introducing tempering air in
the conventional manner.
Air Preheat System
The preheated air temperature entering the secondary air duct will be varied
by bypassing the air and/or gas side of the air preheaters to provide the
maximum system flexibility.
-------
-50-
Water Injection System
Water Injection will be admitted into the furnace through two elevations of
atomizing spray nozzles located between the top two and bottom two fuel
nozzle elevations. A maximum injection rate of 50 pounds per million BTU
fired will be used.
Existing Process Variables
Excess air, unit load, and fuel and air distribution will be varied within
the current limitations of the existing equipment.
UNIT PERFORMANCE EFFECTS
Operation of the unit as proposed in the experimental study will produce
variations in unit operation and thermal performance. The following process
measurements are required to properly assess the Impact of these changes on
new unit design and the retrofitfng of existing units.
Furnace Absorption
Recirculating gases to the secondary air compartments and staging of com-
bustion air will effect changes in both peak and average furnace absorption
rates. The waterwall absorption rates must therefore be determined to evaluate
the impact of variations in average and peak rate and absorption profiles on
unit design. Furnace waterwall absorptions will be calculated using chordal
drilled TG's as described in Appendix E.
Furnace Corrosion Probes
Unit operation with staged combustion air may result in local reducing atmos-
pheres within the furnace envelope, resulting in accelerated waterwall
corrosion rates. To assess the impact of this type of operation on water-
wall wastage, furnace corrosion probes will be utilized as described in
Appendix D.
Sensible Heat Leaving the Furnace
Variations in furnace heat absorption rates due to modifying the combustion
process will result in increasing or decreasing the sensible heat leaving the
furnace envelope and entering the superheat and reheat sections of the unit.
To determine the sensible heat leaving the furnace, the exit gas temperature
will be measured at the vertical furnace outlet plane using water cooled probes
as described in Appendix B.
Superheat, Reheat and Economizer Section Absorptions
Variations in the gas temperature and gas flow leaving the furnace envelope
and entering the convective sections of the unit will affect the total heat
pickup of each section. To assess the impact of modified operation on super-
heat, reheat and economizer performance, the absorption rates for each
section will be determined as described in Appendix B.
-------
-51-
Variation in absorption rates may require resurfacing when retrofitting
existing units for modified operation.
Air Heater Performance
Air and gas temperatures and gas side oxygen concentrations entering and
leaving the air heater are required to calculate air heater performance,
unit efficiency, heat losses and air and gas flow rates. These calculations
are detailed in Appendix B.
Fuel and Ash Analysis
During each test a representative fuel sample must be obtained for later
analysis. The fuel analyses are required to perform combustion calcula-
tions necessary to determine excess air levels and unit gas and air flow
rates. Pulverized coal fineness samples will be obtained to determine the
effect, if any, on furnace wall deposit characteristics.
In addition, coal ash analyses are required to determine ash properties
such as base/acid ratios and ash deformation, softening and fluid tempera-
tures necessary for evaluating the furnace wall deposit characteristics of
coal fuels. Furnace bottom ash, fly ash and coal pulverizer rejects analyses
are also required to determine heat losses and material balances. Analyses
procedures are specified in Appendix C.
TEST PROGRAM DESIGN
The test prograrr defining the proposed test sequence is as follows. Due to
the experimental nature of this program, it may be necessary to delete or
add tests as the individual combustion process modifications are evaluated.
With the exception of the long term and transient operation phases of the
program, testing will be conducted at steady state conditions. During each
test period, the unit will be allowed to stabilize at the desired test
condition after which the required data will be obtained. The stabilized
test condition will be maintained for a minimum of one hour.
A. Load Variation and Furnace Wall Deposits
The object of this evaluation is to determine:
1. The effect on the NOx emission levels of varying load and furnace
wall deposits.
2. The maximum allowable furnace wall deposits with respect to steam
temperature limits and ash removal system capacities.
-------
-52-
Percent Load
Max. Load L-l
3/4 Max. Load L-2
1/2 Max. Load L-3
Furnace Wall Deposits
Clean D-l
Moderate D-2
Heavy D-3
L-l
L-2
L-3
D-l
5
1
D-2
6
4
2
D-3
7
3
B. Excess Air and Air Preheat Temperature Variation
The object of this evaluation is to determine:
1. The effect on NOX emission levels of varying excess air and air
preheat temperature.
2. The range of excess air and air preheat temperature variation
achievable within the limitations imposed by fan capacities,
furnace wall deposits, steam temperatures, and flame stability.
Percent Excess Air
Normal Excess Air E-l
Minimum Excess Air E-2
Maximum Excess Air E-3
Air Preheat Temperature
Normal Air Preheat H-l
1/2 Minimum Air Preheat H-2
Minimum Air Preheat H-3
H-l
H-2
H-3
E-l
8
E-2
10
12
11
E-3
9
' iT
C. Furnace water Injection Through Existing Oil Guns
The object of this evaluation is to determine:
1. The effect of water injection on furnace gas temperature and NOX
emission levels.
2. The effect of location of water injection on NOX emission levels.
3. The maximum injection rate with respect to maximum steam outlet
temperatures, flame stability, and water source capacity.
-------
-53-
Location of Water Injection
Between Lower Two Fuel Nozzles
Between Upper Two Fuel Nozzles
Both Locations
Water Injection Rate
No Injection 1-1
1/2 Maximum Injection 1-2
Maximum Injection 1-3
W-l
W-2
W-3
1-1
1-2
1-3
W-l
14
15
W-2
16
W-3
18
17
D. Overfire Air Location, Rate, Velocity and Temperature
The object of this evaluation is to determine:
1. The effect on the NOX emission level of varying the velocity and
height above the fuel compartments at which the/overfire air is
admitted.
2. The effect on the NOX emission level of varying the overfire air rate.
3. The maximum overfire air rate with respect to steam temperatures, flame
stability and furnace wall deposits.
4. The effect of hot and cold overfire air on the NOX emission level.
Overfire Air Admisstion Points
Eight Feet Above Fuel Compartments Top 0-1
Bottom 0-2
Immediately Above Fuel Compartments Top 0-3
Bottom 0-4
Overfire Air Rate and Temperature
No Overfire Air A-l
1/2 Max. Hot Overfire Air A-2
Max. Hot Overfire Air A-3
Max. Cold Overfire Air A-4
A-l
A-2
A-3
A-4
0-1
19
20
0-2
21
0-1
0-2
23
22
24
0-2
25
0-3
0-4
26
0-1 0-3
0-2 0-4
28
29
Having established the optimum overfire air location, rate, velocity and
temperature, use this condition to perform the following tilt variation
tests. In the event that more than one optimum combination is noted,
the tilt variation test will be performed with each combination.
E. Qverfire Air Tilt Variation
The object of this evaluation is to determine:
1. The effect of tilting overfire air compartment nozzles on the NOX
emission level.
-------
-54-
2. If the overfire air compartment nozzles should tilt with the fuel
nozzles or remain fixed.
3. The maximum allowable minus and plus tilt with respect to steam
temperatures and furnace wall deposits.
Overfire Air Compartment Tilt
Horizontal Tilt P-l
Maximum Minus Tilt P-2
Maximum Plus Tilt P-3
Fuel Nozzle Tilt
Horizontal Tilt F-l
Maximum Minus Tilt F-2
Maximum Plus Tilt F-3
F. Flue Gas Recirculation Location and Rate
The object of this evaluation is to determine:
1. The effect of gas recirculation location and rate on the NOX emission
levels.
2. The most effective means of introducing gas recirculation.
3. The gas recirculation rate required to obtain the maximum reduction
in NOX emission level.
F-l
F-2
F-3
P-l
30
31
32
P-2
33
34
P-3
35
Location of Gas Recirculation
Primary/Auxiliary Air Compartments
Coal Transport Air
Auxiliary Air Compartments
G-l
6-2
6-3
Primary/Auxiliary and Coal Transport Air G-4
Auxiliary and Coal Transport Air G-5
Gas Recircualtion Rate
B-l
B-2
B-3
G-l
38
G-2
39
6-3
36
37
G-4
43
42
G-5
41
40
No. Gas Recirculation B-l
1/2 Max. Gas Recirculation B-2
Max. Gas Recirculation B-3
Having investigated the effect of location and rate of gas recirculation,
the effect of gas recirculation temperature will be studied in the following
tests.
G. Flue Gas Recirculation Temperature
The object of this evaluation is to determine:
1. The effect of the temperature of the recirculated gas on the NOX
emission level.
-------
-55-
2. The effect of the temperature on the available gas recirculation
rate with respect to fan capacities.
Location of Gas Recirculation
Primary/Auxiliary Air Compartments G-l
Auxiliary Air Compartments G-3
Gas Recirculatioii Temperature
Economizer Outlet Temperature T-l
Air Heater Outlet Temperature T-2
Econ. Out/AH Out Average Temp. T-3
l-l
T-2
T-3
G-l
44
45
46
G-3
47
Having established in the preceding tests the most effective overfire
air and gas recirculation conditions for reduction of the NOx emission
level, a combination of these overfire air and gas recirculation condi-
tions will be performed in the following tests.
H. Overfire Air and Flue Gas Recirculation Ratio
The object of this evaluation is to determine:
1. The most effective ratio of overfire air and gas recirculation with
respect to reducing the NOX emission level.
2. The effect on overall unit operation
Gas Recirculation Rate
No Gas Recirculation B-l
1/2 Max. Gas Recirculation B-2
Max. Gas Recirculation B-3
Overfire Air Rate
No Overfire Air
1/2 Max. Overfire
Max. Overfire Air
Air
A-l
A-2
A-3
A-l
A-2
A-3
B-l
48
B-2
51
50
B-3
52
49
I.
Having established the most desirable overfire air/gas recirculation
ratio, the boiler will be operated at this condition while the effect
of excess air, air preheat, and water injection is investigated.
Overfire Air and Gas Recirculation Operation with Low Air Preheat,
Low Excess Air and Furnace Injection
The object of this evaluation is to determine:
1. The minimum operating excess air which can be achieved with overfire
air and gas recirculation operation arid the effect on the NOX emission
level.
-------
-56-
2. The effect of low air preheat with gas recirculation and overfire
air operation on the NOX emission level.
3. The effect of furnace water injection with gas recirculation and
overfire air on the NOX emission level.
4. The effect of the above conditions on the overall unit operation.
Percent Excess Air
Normal Excess Air
Minimum Excess Air
Air Preheat
E-l
E-2
1-1
1-2
1-3
E-l
H-l
53
H-3
54
56
55
E-2
H-l
57
H-3
58
60
59
Normal Air Preheat H-l
Minimum Air Preheat H-3
Hater Injection Rate
No Injection 1-1
1/2 Max. Injection 1-2
Max. Injection 1-3
Having established optimum operating conditions for NOX reduction use
these conditions to perform the following load variation tests.
J. Load Variation At Optimum Conditions
The object of this evaluation is to determine:
1. The effect on the NOX emission level of operating at previously de-
termined optimum conditions for NOX reduction while varying load
and the degree of furnace wall deposits.
2. The effect on unit operation while operating at said conditions.
Percent Load
Max. Load L-l
3/4 Max. Load L-2
1/2 Max. Load L-3
Furnace Wall Deposits
Clean
Heavy
D-l
D-3
OC-1
D-l
D-3
L-l
63
64
L-2 «
62
65
L-3
61
66
Optimum Conditions
Optimum Conditions OC-1
-------
-57-
K. Effect of Long Term and Transient Operation
After the optimized modes of operation have been established they will be
evaluated with respect to their effect on long term and transient unit
operation. This evaluation will consist of operating for a one week
period at each condition during which time normal unit load changes, etc.
would be evaluated.
L. Effect of Coal Change
The long term and transient operation phase of the
for one or two additional coals to demonstrate the
results to a variety of coal types.
TEST INSTRUMENTATION
program will be repeated
applicability of the test
The following instrumentation and process measurements will be required in
support of the experimental program. These measurements will be obtained
in addition to the normally available plant operating instrumentation.
Measurement
Flue Gas Constituents
NOX
S02
CO & Hydrocarbons
Carbon Loss
Oxygen
Fuel Analysis
Ash Analysis
Flow Rates
Steam & Water
Feedwater Flow
RH & SH
Desuperheat Spray Flow
RH Flow
Instrument
Chemiluminescence Analy.
Ultraviolet Analy.
Infrared Analy.
Dust Collector
Paramagnetic Analyzer
ASTM Procedures
ASTM Procedures
Location of Measurements
Econ. Gas Outlet and
Precipitator Gas Outlet
Econ. Gas Outlet and
Precipitator Gas Outlet
Econ. Gas Outlet and
Precipitator Gas Outlet
Econ. Gas Outlet and
Precipitator Gas Outlet
Econ. Outlet Precipitator Out.
Air Heater Inlet & Outlet
Feeder Inlet Coal
Pulverizer Outlet Coal
Furn. Ash Pit
Fly Ash Leaving Econ.
Coal Pulverizer Rejects
Flow Orifice
Heat Balance (°F & PSIG)
Around Desuperheater
Heat Balance Around
Superheat Extractions
and Est. Turbine Gland
Seal Losses
Econ. Inlet
Desuperheaters
High Pressure
Heaters
-------
-58-
Measurement
Furn. Injection Water Flow
Coal Flow
Air & Gas
Total Air & Gas Wt.
Gas Recirculation
Overfire Air
Air Heater Leakage
Temperatures
Steam & Hater °F
Unit Absorption Rates
WW Absorption
Air & Gas °F
Instrument
Flow Orifice
Coal Scale Readings
Calculated
Pi tot Traverse &
Oxygen Determination
Pitot Traverse
Location of Measurements
Spray Nozzles
Coal Feeders
As Req'd For Unit
Absorption, Combustion
Char, and Efficiency
Determinations
As Req'd by
Ductwork Design
As Req'd by
Duct Work Design
Paramagnetic 02 Analyzer Air Heater Gas Inlet
& Outlet Ducts
Calibrated Stainless
Steel CR-C Well &
Button TC's
Calibrated Stainless
Steel Sheathed CR-C
Chorda! W.W. TC's
CR-C TC's
Water Cooled Probes
PL/PL-10% Rn TC's
Econ. Inlet
Econ. Outlet
SH Desup. In.
SH Desup. Out.
RH Desup. In.
RH Desup. Out.
Desup. Spray
SH Out.
RH Out.
HP Heater #5 Inlet Steam
" Condensate
FW In
FW Out
Waterwall Tubes
Air Heater Air In.
11 A1r Out..
" Gas In.
11 Gas Out.
Secondary Air Duct
Mill Air Duct
Gas Recirculation Duct
Furnace Outlet
Plane
-------
-59-
Measurement
Pressures
Steam & Water-PSIG
Unit Absorption Rates
Instrument
Location of Measurements
Pressure Gauges
and/or Transducers
Unit Draft Loss
Water Manometers
Econ. Inlet
Drum
LT SH Out.
SH Out.
RH In.
RH Out.
H.P. Heater #5 Shell
FD Fan Out,
AH Air In.
AH Air Out.
Windbox
Individual Air Comp.
Upper Furn.
Econ. Outlet
AH Gas In
AH Gas Out.
ID Fan In
Gas Recirculation Fan Outlet
Gas Recirculation Duct to Sec.
Air Duct Junction
Gas Recirculation Duct at
RH Mill
Temperature and
Pressure Logging
C-E Data Logger Thermocouples and
'F & PSI Capacity: 400 tempera- Pressure Transducers
tures,50 pressures as Req'd by Program
-------
PRELIMINARY TEST PROGRAM
Teat
Jpo.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
1$
16
17
18
1>
20
21
22
23
24
25
26
27
28
29
30
31
32
Gen.
j.o»d
1/2 faut.
1/2 Max.
1/2 Mai.
3/4 Max.
Max.
Mix.
Max.
Max.
Max.
Max.
Max.
Max.
Max.
Max.
Max.
Max.
Max.
Max.
Max.
Max.
Max.
Max.
Max.
Max.
Max.
Max.
Max.
Max.
Max.
Max.
Max.
Max.
iocesB
Air
2L_
20
20
20
20
20
20
20
20
Max.
Kin.
Hill.
Mia.
Max.
20
20
20
20
20
20
20
20
20
20
20
20
20
20
20
20
20
20
20
Howie
Tilt
iftKi
Hor.
Hor.
Uor.
HOT.
Uor.
Hor.
Bar.
Hor.
Hor.
Hor.
Hor.
Hor.
Hor.
Uor.
Hor.
Hor.
HOT.
Hor.
Her.
Hor.
Hor.
Uor.
Hor.
Hor.
Hor.
Hor.
Hor.
Uor.
Hor.
Hor.
Max.-
Max.«
Furnace
Wall
Condition
Clean
Mod.
Heavy
Mod.
Clean
Mod.
Heavy
Hod.
Mod.
Mod.
Mod.
Mod.
Mod.
Mad.
Mod.
Mod.
Mod.
Mod.
Mod.
Mod.
Mod.
Mod.
Mad.
Mod.
Mod.
Mod.
Mod.
Mod.
Mod.
Mod.
Mod.
Mod.
Air
Preheat
Te«p.-F
Nora.
Hon.
Hon.
Harm.
Nora.
Nora.
Nora.
Horm.
Non.
Norm.
Min.
1/2 Kin.
Mln.
Nora.
Nora.
Nora.
Non.
Nora.
Nora.
Nora.
Nora.
Norn.
Nan.
Norm.
Von.
Nora.
HOT».
Nora.
Nora.
Nora.
Nora.
Nan.
Loo. of
Water
IpJi
,
....
—
__
_-
___
—
_
— _
_
._
_
— —
Lover
Lover
Upper
Both
Both
_
—
—
—
—
—
-_
_
__
_
—
Water
Injection
Hate
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Max.
Max.
Max.
1/2 Max.
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Loc. of
Overflre
ii£_
_
_
—
—
—
__
...
— -
...
_
—
—
-
—
—
_
Top-Top
Top-Top
Top-Bot
iTop-Top
llop-Bot
top-Top
Top-Bot~
Top-Top
~Top-Bot~
Bet-Tej>
Bot-Top
"Bot-Botr
all
All
all
4
Orerfire
Air Hate
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Max.
Max.
Max.
1/2 Max.
Max.
Max.
Max.
Max.
1/2 Max.
Max.
4
Onrfire Orerflre Loc. of
Air Temp. Air Tilt Gas
F Peg. Red re.
— .— _ m
_ _^ ...
... — ...
_ ... _
_ __ __
.... ... ...
—
... ... — —
_ — —
-.- — «-
«» — — — _
_ ... _
— — —
- ._ -
__ — _
_ ... —
_ ... ^ --
Hot
Hot
Hot
Hot
Hot
Cold
Hot
Hot
Hot
Hot —
Cold
* HOT. —
Optima Condition HOT.
^
V
t Hor.
Cat Oa*
Becirc. Beclrc.
Bate Teap.-F
0
0
0
0
0
0
0
0
0
0
0 —
0 —
0
0 --
0
0 -
0
0
0
0
0
0
0
0
0
0
0
0 —
0
0
0
0
Purpoje
Load and Furnace Hall
* Condition Variation
Excess air and Air
• Preheat Temperature
Variation
- Hater Injection
O
I
Overfire Location,
—Bate and Temperature
Variation
I Omrfire Air Tilt
I~ Variation
FIGURE 1
-------
PRELIMINARY TEST PROGRAM
Teat
Jjo,.
33
34
35
36
37
38
39
to
41
42
43
44
45
46
47
48
49
50
51
52
$3
54
55
56
J7
58
59
60
61
62
63
64
65
66
Gen.
Load
Max.
Max.
Max.
Max.
Max.
Max.
Max.
Max.
Max.
Max.
Max.
Max.
Max.
Max.
Max.
Max.
Max.
Max.
Max.
Max.
Max.
Max.
Max.
Max.
Max.
Max.
Max.
Max.
1/2 Max.
3/4 Max.
Max.
Max.
3/4 Max.
1/2 Max.
Xxceu
air
— 2L_
20
20
20
20
20
20
20
20
20
20
20
20
20
20
20
20
20
20
20
20
20
20
20
20
Mlo.
Min.
Mio.
Mln.
Min.
Mia.
Mln.
Mio.
Mln.
Mln.
Motile
Tilt
"««,
Uor.
Max.*
Max.-
Hor.
HOT.
Uor.
Hor.
Hor.
Hor.
Hor.
Hor.
Hor.
Hor.
Hor.
Her.
Hor.
Hor.
Hor.
Hor.
Hor.
Hor.
Hor.
Hor.
Hor.
Hor.
Hor.
Hor.
Hor.
Hor.
Hor.
Hor.
Hor.
Hor.
Hor.
Furnace Air Loe. of Water Loc
Wall Preheat Water Injection Over
Condition Teap.-P Inj. Rate A
Mod. Morn. 0
Hod. Mom. 0
Mod. Hon. — 0
Mod. Norm. — 0 —
Mod. Nom. 0
Mod. Hon. 0 —
Mod. Nora. 0
Hod. Nora. — 0 —
Mod. Norn. 0
Mod. Nora. 0 —
Mod. Norn. — 0 —
Mod. Worm. — 0 —
Mod. Nora. — 0 —
Mod. Nora. — 0
Mod. Norn. — 0
Mod. Norn. 0 •}
Mod. Nona. 0 >
Mod. Nora. 0 Opt
Mod. Norn. — 0 I
Mod. Norn. 0 (
Mod. Nora. | 0
Mod. Mln. 0
Mod. Min. Max.
Mod. Min. ,jj 1/2 Max.
Mod. Nora. yp** 0
Mod. Min. 0
Mod. Mln. Max.
Hod. Min. 1/2 Max.
Clean 1
Clean
Clean
Heavy
Heavy
Heavy r 1 \
Loc. of Overfire Overfire Loc. of Gae Gaa
Iverflre Overfire Air Tamp. Air
Air
Tilt Gae Reciro. Retire.
Air Rate F Peg. R«ire. Rate Temp.-F Purpoae
f »
Optima Condition*
t «
_-_
— '
M
—
^_
__
—
i
Opt.
1
1
0
0
0
0
0
0
0
0
0
0
0
0
i Max.- -- 0
Max.- — 0
1 Max.* 0
— Aux. 0
— Aux. Max.
1 Overfire Air Tilt
~~ J Variatim
Econ. OutT
Bcon. Out.
Pri./Aux. Max. Econ. Out.
— Coal Max. Econ. Out.
lax, /Coal Max. Econ. Out.
Aux./Coal 1/2 Max. Econ. Chit.
— All Max.
Econ. Out.
All 1/2 Max. Econ. OuU
— Pri./Aux. Max.
— Pri./Aux. Max.
— Pri./Aux. Max.
— Aux. Max.
Econ. OutT
AH Out.
Average
AH Out. _j
0 1 A 4 0 \
Max. 1 1 1 Max.
Max. Opt. Opt. Opt. 1/2 tiax. Opt.
1/2 Max. i 1 I 1/2 Max.
1/2 Max. t f i Max. i.
t 1
\ 4 i
Optima Ratio
[
Optima Conditiona
1
1
•
f
i
' '
t
'
-
—
-
_
Ga* Recirculatlon
~ Location and 3at«
Variation
Qa* Recirculatlon
Temperature Variation
Overfire Air and Gaa
Becirculation Ratio
Overfire Air and Ga*
Reeireulation with
Low Kxecee Air, Low
Air Preheat Tempera-
ture and Vatar In-
jection
Load and Furnace Hall
- Condition Variation
at Optima Conditions
FIGURE 1A
-------
-63-
APPENDIX A
EMISSION LEVEL DETERMINATION
In order to evaluate the effect of combustion process modifications
on boiler emission levels the following instrumentation is proposed.
1. NOX: Chemiluminescence Analyzer
2. ^2'- Paramagnetic Analyzer
3. CO & HC: Nondispersive Infrared Analyzer
4. $02: Ultraviolet Analyzer
5. Carbon Loss: ASME Particulate Sampling Train
In addition to these methods of measurement, check methods for NOX
and S02 will be performed. These will consist of the PDS chemical analy-
sis for NOX (ASTM D1608) and the wet chemical titration method for S02-
The specifications for the above mentioned emission analyzers are as
follows.
NOX Analyzer
The NO - NOX Analyzer consists of one (1) control unit, one (1) ana-
lyzer unit and one (1) N02 to NO convector.
Range: Three ranges 0-100 PPM
0-1000 PPM
0 - 2000 PPM
Sensitivity: 1 PPM full scale
Reproducibility and accuracy: +_ 1 percent full scale
Zero Drift: 1 percent full scale in 24 hours
Span Drift: 2 percent full scale in 24 hours
S02 Analyzer
Range: 0-1000 PPM
0 - 2000 PPM
0 - 3000 PPM
Accuracy: ± 2 percent full scale
Reproducibility and accuracy: +_ 1 percent full scale
Zero and Span Drift: +_ 1 percent full scale in 24 hours
-------
-64-
APPENDIX A
CO & HC Analyzer
Range: 0 - 100, 0 - 1000 PPM
Accuracy: +_ 1 percent full scale
Zero and Span Drift: <1 percent full scale in 24 hours
Sensitivity: 1 percent full scale
Og Analyzer
Range: 0-10 percent, 0-25 percent 02
Accuracy: ±1.5 percent full scale
Sensitivity: 0.05 percent Q£
ASME Particulate Sampling Train
The particulate sampling train will consist of necessary sampling
probes as described in ASME Test Code PTC 21. Isokfnetic samples will be
obtained to determine the percent carbon loss in the fly ash.
Probe Locations
A stationary grid of gas sampling probes will be installed at each
of three locations as shown in Figure 1.
A. Economizer Outlet
B. Precipitator Outlet
C. Air Heater Outlet
FIGURE 1
The primary sampling location for the determination of NOX emission
levels versus unit operation is the economizer outlet. This location was
selected for the following reasons:
1. Elimination of possible air leaks through the precipitator.
2. Elimination of possible additional emissions resulting solely
from the electrostatic precipitator operation.
-------
-65-
APPENDIX A
Isokinetic dust samples will also be obtained at economizer outlet
duct to be analyzed for carbon loss.
The flue gas will be sampled at the precipitator outlet during
selected tests to determine if and how much the precipitator affects
the resulting emission levels.
Oxygen levels alone will be determined at the airheater inlet and
outlet and the economizer outlet in order to determine the unit
efficiency as discussed in Appendix B.
Each sampling grid will consist of four inserts per duct with three
depths of probes at each insert giving twenty-four points per duct.
Emission Sampling and Analysis Train
The proposed sampling and analysis train as shown on Figure 2 pro-
vides the proper flue gas conditioning to each meter to maintain con-
tinuous and simultaneous analysis of emission levels.
-------
U3 T3
C (D
n> ex
rox'
SO,
N0>
<>
<
I:
ii
'iA/VAAA/1
*AAAA/V/VVV\AAAA/VV>
HEATER
FILTER
BLENDER
'XAA/VXAJ
AAAA/WAAA/V '
;
!'
!>
:!
i;
!;
!l
< I HEATED
LINES
120F
-XI
'tXK
JX
FLOW
lETERd
1
J
1
3
J
VE
°2
CO
a
HC
NT
—tXF
CT»
I
-------
-67-
APPENDIX A
Calculations
The analyzers chosen to measure emission levels are directly read in
terms of parts per million parts on a volumetric basis. However, it is
also necessary to report emissions in terms of IBS per million BTU fired.
The following discussion describes the equations involved in a representa-
tive conversion when analyzed on a dry basis.
NOX Conversion PPM (Vol -Dry Basis) to LB N02/106BTU Fired
The values which are needed to make the conversion are:
1. NOX - PPM Dry Basis Value (NOX - PPM - D)
2. Perjcent Oxygen Reading Where NOX Sample is Taken (% 62)
3. Complete Fuel Analysis as Fired
a. Carbon % by Wt. (C)
b. Hydrogen % by Wt. (H)
c. Sulfur % by Wt. (S)
d. Moisture % by Wt. (M)
e. Oxygen % by Wt. (0)
f. Nitrogen % by Wt. (N)
g. Higher Heating Value of Fuel - BTU/LB (HHV)
For the purpose of simplicity in discussion, the abbreviations in
the brackets above will be used in the conversion analysis.
-------
-68-
APPENDIX A
VOLUME ADJUSTMENT ON N0y READINGS
The first step in the conversion involves a volume adjustment on the
measured NOX value. This adjustment is based on a- 3 percent by volume of
oxygen in the flue gas as related to the 21 percent by volume of oxygen in
the air. All of the N0y samples or readings must be adjusted in this manner
« • - —
in order to account for dilution.
Mathematically the adjustment takes the form:
21-3
(NCL-PPM-D)
2R%l02 )J
CALCULATING THE TOTAL MOLES OF DRY PRODUCTS OF COMBUSTION AT STOICHIOMETRIC
CONDITIONS
Calculating to obtain the moles of oxygen which are needed at stoichio-
metric conditions, we get:
1
(Stoles of 02
} Needed at
] Stoichiometrici
(^Combustion
12
(SI
32
- JOL
32
/100
Since all the oxygen reacts with the constituents of the fuel, it is no
longer present as free oxygen, therefore, we can use the moles of oxygen needed
at stoichiometric conditions to obtain the moles of nitrogen;entered into the
products with the oxygen. The ratio of nitrogen to oxygen in air by volume
is 79.05/20.95.
Therefore:
( Moles of N2 Entered
2. } Into the Products of
j Combustion with 02 at C
I Stoichiometric ConditionsX
79.05
20.95
Moles of 02 Needed
at Stoichiometric
Combustion
-------
-69-
APPENDIX A
Now we must calculate for the total moles of dry products at stoichiometric
conditions, this can be done by adding the moles of C02, SOg and N£ from the
«
combustion process to the results of equation 2.
(Total Moles of ) (Moles of N£ Entered
j Dry Products at ( _ J Into the Products of
j Stoichiometric ( ~ ] Combustion with Q£ at(
( Conditions ) I Stoichiometric Condi-
V- S \t
/100
MOLES OF AIR NEEDED TO PROVIDE A 3% EXCESS OF OXYGEN
Because the NOX-PPM value is adjusted to a base of 3% excess oxygen, we
must provide an excess of air, in terms of moles, to the dry products of comb-
ustion to obtain the total moles of dry products at 3% excess oxygen.
if: y = total moles of dry products of combustion at stoichiometric
combustion.
and: x = moles of air needed to provide a 3% excess of oxygen in
the flue gas.
then: .03(y + x) = .2095 x
Algebraically we obtain:
x = -03(y)
x .1795
| Total Moles of Dry
4. J Products of Combus- i 7 _ .
) tion at a 3% Excess f " " y
(of Oxygen
CONVERSION EQUATION
'The final step in the conversion NOX-PPM to Lbs. NOe/lO^BTU Fired is:
Lbs. N02/106BTU Fired = [-^ [N0,-PPM-D^ to 3% QJ [45]
In Terms of Units:
Where: Lbs. = (moles)(molecular wt.)
and: Moles Parts
106 Moles " 106 Parts
-------
Lb- Wh/106BTU - f^oles
-70-
APPENDIX A
of Dry Prods. /Lb Fuel) |
BTU/Lb Fuel 1
Moles NOx "1
Ob Moles of Dry Prods.
Molecular'
Wt. of j
N02
= Lbs. N02/106BTU
Example Calculation for dry values of NOX-PPM:
Known Values:
.1. NOx-PPM Dry Basis = 500 PPM
2. Percent Oxygen Reading Where NOX Sample is Taken = 4% 02
3. Complete Fuel Analysis as fired
a. Carbon % By Wt. = 43.5
b. Hydrogen % By Wt. = 3.2
c. Sulfur % By Wt, = 0.8
d. Moisture % By Wt. = 29.4
e. Oxygen % By Wt. = 11.8
f. Nitrogen % By Wt. = 0.8
g. Higher Heat Value = 7490Btu/Lb •
NOX-PPM Dry Adj. to 3% 02 =
21-3
21-(%02)
r_i8__i
21-4% 02J
529 PPM
(500)
-------
-71-
APPENDIX A
y = total moles of dry products @ stoichiometric conditions
y = .1908
x = moles of air needed to provide a 3% excess of oxygen.
.03y (.03)(.1908)
x " .1795 " .1795
x = .032
z = total moles of dry products at a 3% excess of oxygen.
z = x + y
z = .032 + .1908
z = .223
Lbs. N02/106BTU =[-R^r-| (NOx-PPMDry Adj> to 3% 02) (46)
(529)(46)
Lbs. N02/106BTU = Ufffl-
Lbs. N02/106BTU = .7259
EXPLANATION FOR RUNNING PROGRAM LBS HOX G.E. MARK I BASIC
1. Call Mark I computer and sign-on in the basic system.
2. Call Program LBSNOX
3. Input data in lines 10 thru 99 in the form.
-------
-72-
APPENDIX A
10 DATA N
20 DATA C, H2, S, M, 02, N2, H
30 DATA P1§ P2, P3, Pn
Where:
N - The number of dry adjusted NOX-PPM values to be converted
to Ibs N02/106BTU.
C = Carbon % By Wt.§ in fuel.
H2 = Hydrogen % By Wt., in fuel.
S = Sulfur % By Wt., in fuel.
M = Moisture % By Wt., in fuel.
02 = Oxygen % By Wt., in fuel.
N2 = Nitrogen % By Wt., in fuel.
H = Higher heating value of fuel in BTU/Lb.
P = NOX-PPM Dry (Adj. to 3% 02)
On the following page is a listing of the program LBSNOX and an example run,
-------
-73-
APPENDIX A
LBSNOX 8:47 20 THU 02/24/72
10 DATA
20 DATA
30 DATA
40 DATA
100 DIM
110
120
18
130
85.85* 10.8* 2. 41 5* . 02* .5* . 325* 18265 '
243* 169*274, 185* 198* 1 62* J61* 179*220
167* 201* 186* 1 77* 292*264* 263* 1 62* 161
P(50)
PRINT 'NOX-PPM"*".M32-LBS./10t 6 BTU"
READ N
READ C*H2* S*M*32*M2*H
140 LET Y1=(C79. 05/20. 95)*JD
100
RUN
LBSM3X
N0X-PPM
243
169
274
185
198
1.62
1 61
179
220
167
201
186
177
292
264
268
162
161
8:48 20 THU 02/24/72
M02-LBS./ 1 Ot 6 BTU
v-318919
.2218
.359604
»242798
. 25986
..212613
. 21 13
.234924
.288733
-219175
.263797
.244111
. 232299
.383228
.34643
.35173
.212613
. 21 13
-------
-75-
APPENDIX B
STEAM GENERATOR THERMAL PERFORMANCE
In order to evaluate overall steam generator thermal performance as
affected by the various methods of NOX reduction under consideration the
following test instrumentation will be installed.
Furnace Outlet Gas Temperature
Three 30 foot water cooled, aspiratedi platinum-platinum 10 percent
rhodium thermocouple probes in the vertical outlet plane.
Economizer Outlet. Air Heater Gas Inlet and Air Heater Gas Outlet
A'stationary grid of combination thermocouple and gas sampling probes
will be installed at each of the above locations. The gas samples will be
passed through a multipoint sampler and into a paramagnetic oxygen analyzer
for average 02 determination at each location. Each grid will consist
of four probes per duct (each probe three penetrations deep) for a total
of twenty-four probes.
Flows
Feedwater flow will be determined by differential measurement across
the flow orifice. Superheat and reheat spray flow and reheat flow will be
determined by heat balance.
Draft Losses
Static pressure measuring probes and inclined manometers will be used
to determine draft losses on all components.
Steam and Water Temperatures
Calibrated CR/C well and button thermocouples will be used to determine
fluid temperature entering and leaving each convection section.
-------
-76-
APPENDIX B
Steam and Water Pressures
Calibrated transducers or pressure gauges will be used to determine
fluid pressures entering and leaving each convection section.
Location of Test Points
1. Furnace Outlet Gas Temperature (3 probes)
2. Gas Temperature and Analysis
Gas leaving Econ. - 4 probes per duct (each probe three pene-
trations deep)
Gas entering AH - 4 probes per duct (each probe three pene-
trations deep)
Gas leaving AH - 4 probes per duct (each probe three pene-
trations deep)
3. Air Temperature entering AH - 4 probes per duct
4. Air and Gas Pressures - Manometer
Air Heater Air Inlet
Air Heater Air Outlet
Windbox
Individual Air Compartment
Upper Furnace
Economizer Outlet
Air Heater Gas Inlet
Air Heater Gas Outlet
ID Fan Inlet
Gas Recirculation Fan Duct at Secondary
Air Duct Junction
Gas Recirculation Duct at Mill Air Duct Junction
Gas Recirculation Fan Outlet
-------
-77-
APPENDIX B
5. Steam and Water Temperatures - Well or Button Thermocouples
Economizer Inlet - 1
Economizer Outlet - 2
SH DESH Inlet - 2
SH DESH Outlet - 2
SH Outlet - 2
RH before DESH - 2
RH after DESH - 2
RH Outlet - 2
DESH Spray - 1
FW entering HP Heater #5 - 1
FW leaving HP Heater #5-1
Steam to HP Heater #5 - 1
Drain from HP Heater #5 - 1
6. Steam and Water Pressures - Calibrated Transducers or Gages
Economizer Inlet
Drum
LTSH Outlet
SH Outlet
RH Inlet
RH Outlet
Spray Water Source
HP Heater #5 Shell
7. Flow Nozzle Measurements - Differential Manometers
FW Flow Nozzle
Calculations and Flows
Boiler Efficiency and Products of Combustion
Boiler test efficiency calculations will be performed as shown in
-------
-78-
APPENDIX B
Section B. Combustion calculations performed on a per million BTU
fired basis and air and gas flow calculations are shown in Section A.
Flows (Refer to flow schematic, Figure 1)
Feedwater Flow Rate
A general equation for the calculation of fluid flow rates is given
in the following reference text: "Fluid Meters - Their Theory and Ap-
plication", page 65, equation 112, ASME Research Committee on Fluid
Meters, Fifth Edition, 1959.
= 359.0
where W], fluid rate of flow LBS/HR
C, meter discharge coefficient
B = d/D = throat diameter/approach diameter
YI , compressibility factor
$1, specific weight of fluid, LB/FT3
hw, meter head differential, IN H20 @ 68°F
For the calculation of liquid flow rates at varying temperatures the
thermal expansion factor, FA, must be introduced into the above equation;
with Y] = 1 for liquids we have:
Wn = 359.0 . C Ffld2
X/l - B4
Superheat Spray Flow
ws =
hi - hz
Ws is superheat desuperheating spray flow, LBS/HR.
W-j is flow entering desuperheater, LBS/HR. This is feedwater flow
where there is no blowdown or steam extracted from the drum.
h-j is enthalpy of steam entering desuperheater, BTU/LB.
-------
-79-
APPENDIX B
\\2 is enthalpy of steam leaving desuperheater, BTU/LB.
hs is enthalpy of desuperheating water, BTU/LB.
Main Steam Flow
W2 =
W
W2 is main steam flow, LB/HR.
Reheat Flow
W4 = W3 + WRS
W4 is reheater steam flow, LBS/HR
W3 is steam flow entering reheat desuperheater, LBS/HR.
WRS is reheat desuperheating spray flow, LBS/HR (Calc. to follow).
A. w3 = w2 - WH - WL
W2 is main steam flow (previously calculated).
WH is final HP heater steam flow (calculation per Item B).
W|_ is HP turbine leakage (from manufacturer's data - figure 2)
LBS/HR.
B. HP Heater Extraction Steam
WH =
hn2 - hnl
C.
W-| is feedwater flow (previously calculated).
hn2 is enthalpy of feedwater leaving heater BTU/LB.
hi is enthalpy of feedwater entering heater BTU/LB.
h is enthalpy of steam entering heater BTU/LB.
hd is enthalpy of drain from heater BTU/LB.
Reheat Spray Flow {-if any)
WRS = W3
"3 - h
h ' h
RS
is
desuperheat spray flow LBS/HR.
-------
-80-
.APPENDIX B
Wg is steam flow entering desuperheater.
(13 is enthalpy steam entering desuperheater, BTU/LB.
h^ is enthalpy steam leaving desuperheater, BTU/LB.
hps is enthalpy desuperheating water, BTU/LB.
therefore
w4 = w3 + WRS
1/1(4 is reheater steam flow.
Wg is steam flow entering reheat desuperheater.
WR5 is reheat spray flow.
-------
FLOW SCHEMATIC
Main Steam Flow
Leakage
WL
LP Turbine
Cold Reheat Stgam
HP Heater Extraction Steam
DESH Water
Feedwater Inlet
-n 3>
I—I "O
CT> -O
cr m
m o
i—i
—• x
DO
#4 Heater
CO
I
Feedwater
Nozzle
Drain
-------
-82-
TURBINE GLAND SEAL LEAKAGE
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600
400
200
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-------
-83-
APPENDIX B
SECTION A
SAMPLE CALCULATION OF COMBUSTION CHARACTERISTICS
"AND GAS AND AIR FLOWS
1. ULTIMATE COAL ANALYSIS
Carbon - 61.3%
Hydrogen- 4.3%
Nitrogen- 1.5%
Oxygen - 7.1% HHV = 11,160 BTU/LB
Sulfur - 3.7%
Moisture- 7.5%
Ash - 14.6%
TOTAL 100.0%
2. THEORETICAL DRY AIR, TDA
r % 0 -
ma 11.54 (% C) + 34.34 (% H - ~8~) + 4.32 (% S)
IUH ~£ HHV X 105
Where: 11.54 = LBS. Air to Burn One Lb. C
34.34 = LBS Air to Burn One Lb. H
4.32 = LBS Air to Burr, One Lb. S
7.1
_I 11.54 (61.3) + 34.34 (4.3 - ~8~) + 4.32 (3.7)
X 10
4
11,160 XTOb
TDA = 753.20 LB/106BTU
3. MOISTURE IN AIR. MA
MA = .013 (TDA)
Where: .013 = Standard Specific Humidity
MA = .013 (753.20) = 9.79 LB/106BTU
4. THEORETICAL WET AIR, TWA
TWA = TDA + MA
TWA = 753.20 + 9.79 = 762.99 LB/106BTU
5. FUEL IN PRODUCTS. F
P 1100 - % Ash - % SCL)
r ~ HHV X 106
Where: % SCL = CL (HHV, Fuel/14,450)
F = OP?, -™.6 - .2) x 1Q4 = ?6>34 LB/1Q6BTU
Y in
* IU
,4
Sheet 1
-------
-84-
APPENDIX B
SECTION A
6. MOISTURE FROM FUEL. MF
MC - (% Moisture) + 9 (% H)
"r ~ HHV X 10b
In
IU
Where: 9 = LB Moisture Formed by Burning 1 LB Hydrogen
MF =
= 41<4°
7. GAS FLOWS ENTERING AIRHEATER AT 13.9% EXCESS AIR
A. - Dry Air. DA
DA =
1 +
% Excess Air
100
(TDA) (K)
DA =
Where: K = 1 - (% SCL/100)
13.9
1 + 100
(753.20) (.998) = 856.17 LB/106BTU
DA (Flow) = DA (Heat Input From Fuel)
DA (Flow) = 856.17 (2138.7) = 1831.4 X 103LB/HR
B. Moisture In Air, MA
MA = .013 (DA)
MA = .013 (856.17) = 11.13 LB/106BTU
C. Wet Air. WA
WA = DA + MA
WA = 856.17 + '11.13 = 867.30 LB/106BTU
WA (Flow) = WA (Heat Input From Fuel)
WA (Flow) = 867.30 (2138.7) = 1855.3 X 103 LB/HR
D. Wet Products. WP
WP = F + WA
WP = 76.34 + 867.30 = 943.64 LB/106BTU
WP (Flow) = WP (Heat Input From Fuel)
WP (Flow) = 943.64 (2138.7) = 2018.5 X 103 LB/HR
Sheet 2
-------
-85-
APPENDIX B
SECTION A
E. Dry Products , DP *
DP = WP - MA - MF
DP = 943.64 - 11.13 - 41.40 = 891.11 LB/106BTU
DP (Flow) = DP (Heat Input From Fuel)
DP (Flow) = 891.11 (2138.7) = 1906.2 X 103LB/HR
8. GAS FLOWS LEAVING AIRHEATER AT 22.6 % EXCESS AIR
A. Dry Air. DA
DA = [l + % Excess
[1 + % Excess Air I
100 J
(TDA)
DA =
1 + 22.6
100
(753.20)(.998) = 921.58 LB/10bBTU
DA (Flow) = DA (Heat Input From Fuel)
DA (Flow) = 921.58 (2138.7) = 1970.8 X 103 LB/HR
B. Moisture in Air, MA
MA = .013 (DA)
MA = .013 (921.58) = 11.98 LB/106BTU
C. Wet Air. WA
WA = DA + MA
WA = 921.58 + 11.98 = 933.56 LB/106BTU
WA (Flow) = WA (Heat Input From Fuel)
WA (Flow) = 933.56 (2138.7) = 1996.5 X 103LB/HR
D. Wet Products, WP
WP = F + WA
WP = 76.34 + 933.56 = 1009.90 LB/106BTU
WP (Flow) = WP (Heat Input From Fuel)
WP (Flow) = 1009.90 (2138.7) = 2159.9 X 103LB/HR
Sheet 3
-------
-86-
APPENDIX B
SECTION A
E. Dry Products. DP
DP = WP - MA - MF
DP = 1009.90 - 11.98 - 41.40 = 956.52 LB/106BTU
DP (Flow) = DP (Heat Input From Fuel)
DP (Flow) = 956.52 (2138.7) = 2045.7 X 103LB/HR
Sheet 4
-------
APPENDIX B
SECTION B
SAMPLE CALCULATION OF EFFICIENCY - HEAT LOSSES METHOD
DRY GAS LOSS, DGL
DGL = (DP Lvg. AH)(.24)(TGL - TAE) X 10"4
Where: .24 = Instantaneous Specific Heat of Dry Products
TQL = Temperature of Gas Lvg. AH
TAE = TemPerature of Air Ent. AH
DP Lvg. AH = Dry Products Lvg. AH
DGL = (956.52)(.24)(265 - 96) X 10'4
DGL = 3.88%
MOISTURE IN AIR LOSS, MAL
MAL = (.013)(DA Lvg. AH)(.46)(TG|_ - TA£) X 10"4
Where: .013 = Standard Specific Humidity
.46 = Instantaneous Specific Heat of Water Vapor
DA Lvg. AH = Dry Air in Products Lvg. AH
MAL = (.013)(921.58)(.46)(265 - 96) X 10'4
MAL = .09%
MOISTURE FROM FUEL LOSS, MFL
MFL = MF 1089 - TAE +
.46 (TGL) X 1
Where: I" 1089 - TAE + .46 (TQL)
M089 - 96 + .46 (265)1
MFL = 41.40
MFL = 4.62%
CARBON HEAT LOSS. CL
% Ash
CL =
100% - %Carbon in Fly Ash
Where: 14,450 = HHV of Carbon
-4
Accounts for Evaporating &
Superheating the Moisture In
& From the Fuel.
X 10-4
% Carbon in Fly Ash (14,450)
HHV, Fuel
CL =
14.6
100 - 1.4
CL = .27%
1.4 (14.450)
11160
Sheet 1
-------
APPENDIX B
SECTION B
5. RADIATION LOSS. RL
Determined From ABMA Curve.
RL = .22%
6. HEAT LOSS IN FLYASH, FAL
FAL = H (.22)(TGL - TAE)
Where: .22 = Specific Heat of Fly Ash
FAL = ™6 (.22)(265 - 96)
FAL = .05%
7. ASH PIT LOSS. APL
Determined using curves on figure 1 and 2.
0 Furnace Width, Feet -40.167
(2) Furnace Depth, Feet -40.167
0 Furnace Diagonal, Feet -57.0
0 Furnace Height, Feet -114.83
0 Distance Firing (£_ to Hopper Aperture Feet -49.66
0 Ratio®® -.87
0 Ashpit Aperture (Area), Feet -100.42
© Ratio®®®- -01 5
0 Curve Value of Radiation Thru Aperture (% Heat Loss) - .23
(JO). % Ash in Fuel, As Fired -14.6
(fj). HHV Fuel, as Fired, BTU/LB - 11160
©. @ (104)/QJ), Ash Fired/106BTU -13.08
@. % Ash Fired Going to Ashpit -0
@. Slagging or Dry Ash Bottom ? - Dry Ash
.©• Curve ValueSensible and Latent Heat of Ash (% Heat Loss) -0
(16): Total Ash Pit Loss =(1)+ (fs) = .23 + 0 = .23%
Sheet 2
-------
-89-
APPENDIX B
SECTION B
8. REJECT LOSS. RL
RL = LB/HR Rejected ( T^Tar.^^^ ) x ™*
Where: Total BTU/HR Input is Estimated UsingflJnit Absorption X l.ll]
pi = 3495 ( 565° _ ,_\ V 102
RL *™ * j A IU
RL = .92%
Sheet 3
-------
-90-
ASHPIT HEAT LOSS CORRELATION
( H. D. MUMPER )
1. Furnace Width, Feet
2. Furnace Depth, Feet
3. Furnace Diagonal, Feet
(Only one divided Furnace)
k. Furnace Height, Feet
5. Distance Firing r£to Hopper Aperture, Ft.
6. Ratio (5) / (3)
7. Ashpit Aperture: Width, Ft
Depth, Ft
Area Ft^
8. Ratio (?) / (3) (V
9. Curve Value of Radiation thru Aperture
( Heat Loss)
10. % Ash in Fuel, as Fired
11. HHV Fuel, as Fired, BTU/#
12
13
(10) x 10 / (11), Ash Fired/106BTU
Ash Fired going to Ashpit,
14. Slagging or "dry ash" bottom?
15. Curve Value Sensible & Latent Heat
of Ash, $ Heat Fired.
16. TOTAL ASH PIT LOSS = (9) + (15)
NOTE any special circumstances, such as;
a. Water spray nozzles above
surface of water pool and
whether they are angled up
toward aperture.
Lack of water sluice in ashpit.
Other.
b.
c.
20
•••••••••••••••••••I !•••••••••••••••••• •••••••••
•••••••••••••*•*•••) ••••••••••••••••••I .•••••••••
Appendix B - Section B
Figure 1
-------
-91-
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1.2
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••••••••••••••SaMBB•••••£•!••••••••••••••••••*•••••••••••••••••••••••<
D (Area Ashpit Aperture,Sq Ft)
n =
Appendix B - Section B
Figure 2
-------
-92-
APPENDIX C
COAL & ASH ANALYSES
Coal and ash sampling and analyses will be performed essentially in
accordance with the following ASTM procedures.
ASTM Specification Title
D-271-70 Sampling and Laboratory Analysis of Coal and Coke
D-2013-68 Samples, Coal, Preparing for Analysis
D-410-38 Sieve Analysis of Coal
D-311-30 Sieve Analysis of Crushed Bituminous Coal
D-2015-66 Gross Calorific Value of Solid Fuel by
the Adiabatic Bomb Calorimeter
D-409-71 Grindability of Coal by the Hardgrove-
Machine Method
D-1857-68 Fusibility of Coal Ash
D-2795-69 Analysis of Coal and Coke Ash
-------
-93-
APPENDIX D
EVALUATION OF CORROSION POTENTIAL
In order to evaluate whether operating a boiler with low excess air
or staged combustion will result in localized reducing atmospheres and
what effect these conditions will have on waterwall tube wastage the
follow instrumentation will be used. Basically the test involves exposing
a metal coupon held at WW metal temperatures to lower furnace conditions
for a finite time period. At the end of this time period the coupon will
be evaluated for weight loss and visual evidence of attack. Ash deposits
will also be collected using the probe and will be subjected to evaluation
in terms of corrosion potential as well as furnace slagging.
Alkali-metal sulfates have normally been recognized as the aggressive
compounds in water-wall tube wastage. The first step in the overall corrosion
mechanism involves transport of the alkalies to tube surfaces. Alkalies,
as they exist in coal mineral matter, are to a large degree sublimated
and carried to tube surfaces as a vapor where they condense. Here they
combine with sulfur oxides to form alkali sulfates. One possibility is
that with low excess air, iron pyrites may be deposited on tube surfaces
without undergoing significant oxidation. Oxidation of the pyrites would
then occur at the tube surface providing sufficient sulfur oxides to react
with alkalies forming either pyrosulfates or alkali-iron-trisulfates. In
addition the required high localized levels of $03 would be produced to
maintain stability of the alkali-iron-trisulfates.
Another possibility, although less likely than the previous mechanism,
is that free sulfur from deposited pyrites can attack iron directly. This
is not too likely because enamel deposits (alkalies) will usually shield the
tube from sulfur attack.
-------
-94-
APPENDIX D
The quantity and distribution of pyrites in the subject coal will
have an influence on the behavior of the sulfur in the furnace. Coal
containing pyrites that are not well disseminated throughout the coal would
be more likely to result in coarse particles reaching the tubes. In cases
such as this particular attention should be given to coal fineness and flame
impingement.
DESCRIPTION OF EQUIPMENT AND INSTRUMENTATION
The most reliable method of evaluating corrosive potential in a boiler
is by exposing a sample of tube metal for a finite period of time and
measuring the resulting weight loss. This can be accomplished by using a
probe to insert the metal coupon into the furnace and maintain it at the
desired temperature. Figure 1 depicts the type of probe and coupon that
will be used to obtain such information. This particular probe utilizes
air to keep the coupon at the desired temperature.
Typical instrumentation to automically maintain the desired temperature
would consist of an electronic controller , and a pneumatic
controller. The pneumatic controller operates as a switching device, using
solenoid valves, to regulate the amount of cooling air going to the probe.
The amount of air is based on a signal from the electronic controller which
is tied in to the sensing thermocouple at the probe coupon.
PROBE LOCATION IN FURNACE
The ideal location of the probe would be in the furnace fuel and air nozzle
zone located centrally from both a vertical and horizontal standpoint. One
probe should be installed in each of two furnace walls.
EVALUATION OF DATA
It is extremely important that the rate of weight loss measured during
the test period is not assumed to hold throughout much longer time periods.
Tube wastage is not usually linear with respect to time; a higher rate of
-------
-95-
APPENDIX D
wastage quite often occuring during periods of initial operation.
In order to interpret corrosion potential^ control case will be
utilized. The control case will involve exposure of a similar type of
metal coupon for the time period equal to the test period using the same
coal under conventional firing conditions.
Coupon weight losses from the two modes of boiler operation will be
compared in terms of weight loss as well as visual inspection. Deposits
collected from each case will be carefully analyzed to determine differences
in composition. Deposit compositions will be evaluated with respect to
coupon weight loss in each case and mechanisms of corrosion postulated if
applicable.
-------
ITEM No.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
No. ROD.
1
1
20
1
1
1
1
1
1
1
1
2
20
1
1
DESCRIPTION
PROBE BODY
END PLATE
CORROSION COUPONS
REAR PLATE
AIR QUENCHING PIPE
PIPE "T"
GAS SAMPLING FITTING
QUENCHING TUBE FITTING
PROBE COOLING INLET
GAS SAMPLING TUBE
GAS QUENCHING TUBE
SS SHEATHED TC
MACHINE SCREWS
FRONT PLATE
CLAMP
MATERIAL SPECIFICATIONS
1 1/2" DIA. x 6' LONG SCHEDULE 40 CARBON STEEL
1 1/2" DIA. x 1/4" 304 STOCK
1 1/2" x 3 1/4" x 3/16" THICK 192 CARBON ST.
1 1/2" ROUND PLATE x 1/8" THICK
1/4" PIPE
3/8" PIPE 459
3/8" PIPE To 1/8" TUBING
3/8" PIPE To 3/8" TUBING
1/2" PIPE NIPPLE 3" LONG
1/8" x .020 WALL 304 SS TUBE 7' LONG
3/8" x. 020 WALL 304 SS TUBE 7* LONG
1/16" DIA. x 7' LONG CR C TC
8-32 MACHINE SCREWS
1 1/2" O.D. x5/16" THICK CARBON STEEL
5/16" x 5/16" x 3/4" 304
NOTES:
A. HELIARC ALL POINTS MARKED *
B. DRILL 5/32" HOLE and HELIARC TUBE To PROBE
C. CUT QUENCHING TUBE END ON 45° ANGLE
D. SILVER SOLDER TC'S IN END PLATE
E. DRILL THRU SWAGELOC FITTING, ITEM No. 7 for
CLEARANCE of 1/8" TUBING
F. DRILL THRU SWAGELOCK FITTING ITEM No. 8 for
CLEARANCE of 3/8" TUBING
G. SILVER SOLDER TC'S To FRONT PLATE
NOTE:
PRELIMINARY DESIGN
PROBE ASSEMBLY
APPENDIX D-FIGURE 1
VO
-------
-97-
APPENDIX E
WATERWALL ABSORPTION MEASUREMENT AND CALCULATION
In order to determine waterwall absorption rates the following test instru-
mentation is required,
Chordal drilled thermocouples are installed as shown on Sheets 3 and 4 to
obtain waterwall absorption. The depth ofthe thermocouple below the surface of
the tube depends on the tube diameter. The following tabulation lists typical thermo-
couple junction depths:
Tube P.P. Pepth of TC
' 1 1/4" .048"
1 1/2" .P47"
1 3/4" .P46"
2" .P45"
2 1/4" .P44"
2 1/2" .P43"
Lists of properties of hot finished and cold drawn tubes are tabulated on
Sheets 5 thru 9.
CALCULATIPN OF HEAT FLUX FROM CHORPAL PRILLEP THERMOCOUPLE
FOR SUB-CRITICAL PRESSURE
The following is a description for determining the crown heat flux with
sub-critical pressure.
P0 = outside tube diameter, nominal
L = avg. wall thickness at metal surface
P.. = mean tube diameter = P-j + L
Pi = inside tube diameter = P0 - 2L
Pp = diameter of thermocouple location
K = metal conductivity
-------
-98-
APPENDIX E
1. Metal ATM
= (Q/A)D0L = metal temperature drop from crown to inside diameter.
But, since the thermocouple is not at the crown the measured temperature is
at some location, P. Therefore, P must be determined, either graphically
or by measurement. Then:
ATM = (Q/A)'DpL = metal temperature drop from thermocouple to inside
DMK diameter.
2. Film ATf (by Jens & Lottes)
ATf = 60 "6 °'25
ep/900
But;since (Q/A)" is the heat flux at the inside diameter and we are interested^
at the moment;in the heat flux at location P, the film temperature drop
becomes
25
ATf = 60 f7Dp/Di)(Q/A)'/lo6l °'
e(P/900)
where (Q/A)" = (Dp/Di)(Q/A) '
3. OverallAT
AT0 = T^
0= (Q/A)1 DpL- +6Q [7D ,D WQ/M, /106l0.25
AT' = thermocouple temperature - saturation temperature
This now tells us that for a given tube size, tube material and pressure
a (Q/A)1 will result in oneATo- Or, conversely, a measured thermocouple
temperature will yield one heat flux. In order to convert (Q/A)1, the
flux at the TC, to (Q/A), the flux at the crown, we assume radial heat flow
and decrease (Q/A)' by a ratio of diameters. Thus:
Q/A = (Dp/D0)(Q/A)'
-------
-99-
APPENDIX E
METHOD OF TEST SET-UP
The pattern for test instrumentation on the furace walls consists of a
-\
vertical column of thermocouples near the center of the front and right side
wall. Three horizontal rows of thermocouples are located in and slightly above
the burner zone at elevations of expected peak absorption. The center hori-
zontal row extends to the rear and left side walls also. Locations of the
chorda! thermocouples are shown on Sheet 2.
A method of calibrating the installed thermocouples has been devised to
check on the uniformity of the TC's. The unit is "bottled up" with all vents
closed (superheater, drum, etc.) and all air dampers shut and circulating pumps
running. Each thermocouple reading should then approach an average temperature.
Any TC which does not read within one or two degress of the average should be
adjusted.
PLOTTING TEST DATA
The absorption rates measured on the vertical column of thermocouples are
plotted on a graph vs. furnace elevation; using test average readings on oil and
gas fired units, and peak rates for coal fired units. A smoothly faired curve
is then drawn through these points giving a test vertical profile of the center
tube.
The test average absorption rates in the horizontal rows are averaged
and these averages are then plotted on the same graph as the vertical profile.
Another vertical profile is now drawn through these horizontal average rates
having a shape similar to the center tube vertical profile. This is now con-
sidered the average absorption profile for the furnace and assumes that the
horizontal averages form the same general contour as the test vertical profile
for the center tube. See Sheet 1.
-------
-100-
APPENDIX E
FURNACE HEAT ABSORPTION (Calculated & Measured)
The measured furnace absorption is compared to the calculated furnace
absorption to check on the validity of our test data with the idea in mind that
our horizontal strip averages will have to be adjusted if the measured does not
compare to our calculated.
The calculated furnace heat absorption is equal to the net heat input minus
the sensible heat in the gas at the furnace outlet, minus the radiant heat leaving
the furnace.
Qcalc = NHI - ^sensible heat ' ^radiation
^^e ^sensible heat usec' in tne a^ove equation is found from the furnace
outlet temperature.
The measured furnace heat absorption is found from the area under the
furnace absorption profile either by means of a planimeter or integration.
-------
-101-
TYPICAL FURNACE PROFILE
105^0"
95-0"
85'-On
75'-0
65-0
55-0"
45- O
35'-0'
25'-0"
AVERAGE FURNACE ABSORPTION
98-0 PROBES
CENTER TUBE
VERTICAL PROFILE
91 - 7 TOP ARCH
79 - 5 '/4 BOTTOM ARCH
FIRING ZONE
4|i_9« TOP HOPPER
t
20
40
60
80 100 120 140
FURNACE
ELEVATION
FT a IN
Q/A X 1000BTU/HR-FT2
APPENDIX E SHEET 1
-------
CHORDAL THERMOCOUPLE LOCATIONS ON THE FURNACE WATERWALLS
O 5' O 5' O 5' O 5' O 5' O 5' O
O5'O5'O5'O5'O
-38'-2"-
O
11'
O
11'
O
11'
O
O 5' O 5' O 5' O 5' O 5' O 5' O
0 O O O O O O
o o o o o o o
-28'-l
O
11'
O
11'
O
U-5'-4-5'-4»5'-4*5'»|
r T-fT i
—0 — 0—0—©—©
o
5'
o o o o o
o o o o o
4'-5"
O
123'-6'
105--2"
96'-9"
9V-6"
84'-6"
74'-6"
OFA 69'-6'
59'-7"
57'-5"
45'-7"
REAR (7)
LEFT SIDE (5)
FRONT (27)
15'-0"
RIGHT SIDE (25) (64 TOTAL)
APPENDIX E-SHEET 2
o
INJ
-------
-103-
CHORDAL DRILLED THERMOCOUPLE
DRILL .0625
.0625
APPENDIX E-SHEET 3
-------
-104-
THERMOCOUPLE INSTALLATION
k
IN.
SHEET 4
APPENDIX ,E
-------
-105-
PROPERTIES OF HOT FINISHED and COLD DRAWN TUBES 1-1/4"OD
C - Low Carbon Steel
F - Ferritic Alloy Steel
S - Stainless Steel
H.S. Sq. ft./lin. ft = 0.3270
Minimum
Tube Wall
Thickness
(Inch)
.110
.120
.125
.134 FS
.135 C
.148 FS
.150 C
.165 CFS
.180 CFS
.200 C
.203 FS
.220 CFS
.238 FS
*.240 C
.250 S
.260 FS
.280 C
.281 FS
.300 CFS
.313 S
.320 CFS
Avg.
I.D.
(Inch)
.9915
.9680
.9562
.9351
.9327
.9022
.8975
.8655
.8306
.7940
.7871
.7484
.7073
.7028
Hot Finish
(ID)4'97
.9584
.8500
.8006
.7164
.7075
.5995
.5842
.4879
.3975
.3177
.3177
.2368
.1789
.1732
Inside
Area
(Sq.Ft.)
.005361
.005110
.004987
.004769
.004745
.004439
.004393
.004086
.003762
.003438
.003379
.003054
.002729
.002693
*Ferritic tubing to be hot
finished except gages exceeding
.240 which will be cold drawn.
Avg.
I.D.
(Inch)
1.008
.9860
.9750
.9552
.9530
.9244
.9200
.8870
.8540
.8100
.8034
.7660
.7264
.7220
.7000
.6780
.6340
.6318
.5900
.5614
.5460
Cold Drawn
(ID)4'97
1.0403
.9324
.8817
.7962
.7872
.6765
, .6607
.5510
.4563
.3508
.3369
.2658
.2041
.1981
.1698
.1449
.1038
.1020
.07263
.05673
.04941
Inside
Area
(Sq.Ft.)
.005541
.005300
.005184
.004976
.004953
.004660
.004616
.004291
.003977
.003578
.003520
.003200
.002877
.002843
.002670
.002507
.002192
.002177
.001898
.001718
.001625
All Stainless Steel Tubing to
be Cold Drawn.
APPENDIX E SHEET 5
-------
-106-
PROPERTIES OF HOT FINISHED and COLD DRAWN TUBES 1-1/2"OD
C - Low Carbon Steel H.S. Sq. ft./Tin. ft = 0,3930
F - Ferritic Alloy Steel
S - Stainless Steel
Minimum
Tube Wall
Thickness
(Inch)
.110
.125
.134 FS
.135 C
.148 FS
.150 C
.165 CFS
.180 CFS
.188 S
.200 C
.203 FS
.220 CFS
.238 FS
.240 C
*.250 S
.260 CFS
.280 C
.281 FS
.300 CFS
.313 S
.320 CFS
.340 CFS
.360 CFS
.375 FS
.380 C
.400 CFS
Avg.
I.D.
(Inch)
1.241
1.206
1.185
1.182
1.152
1.147
1.115
1.080
1.071
1.044
1.037
.9984
.9573
.9528
.9300
.9072
Hot Finish
(ID)4'97
2.930
2.539
2.325
2.302
2.022
1.981
1.721
1.469
1.408
1.238
1.198
.9920
.8052
.7863
.6965
.6162
Inside
Area
(Sq.Ft.)
.008406
.007936
.007660
.007629
.007240
.007181
.006787
.006368
.006260
.005944
.005867
.005436
.004998
.004951
.004720
.004488
*A11 Ferritic tubing to be hot
finished except gages exceeding
.250 will be cold drawn.
Avg.
I.D.
(Inch)
1.258
1.225
1.2052
1.203
1.174
1.170
1.137
1.104
1.086
1.060
1.053
1.016
.9764
.9720
.9500
.9280
.8840
.8818
. .8400
.8114
. 7960
.7520
.7080
.6750
.6640
.6200
Cold Drawn
(ID)4'97
3.129
2.741
2.528
2.505
2.223
2.182
1.892
1.635
1.509
1.335
1.295
1.082
.8880
.8683
.7745
.6897
.5418
.5351
.4204
.3539
.3217
.2425
.1797
.1417
.1306
.09293
Inside
Area
(Sq.Ft.)
.008631
.008184
.007922
.007893
.007522
.007466
.007050
.006647
.006437
.006128
.006052
.005630
.005199
.005152
.004920
.004697
.004262
.004240
.003848
.003590
.003455
.003084
.002733
.002485
.002404
.002096
All Stainless Steel tubing will
be Cold Drawn.
APPENDIX E SHEET 6
-------
-107-
PROPERTIES OF HOT FINISHED and COLD DRAWN TUBES
C - Low Carbon Steel
F - Ferritic Alloy Steel
S - Stainless Steel
l-3/4"OD
H.S. Sq. ft./lin. ft = 0.458
Minimum
Tube Wall
Thickness
(Inch)
.110
.125
.134 FS
.135 C
.148 FS
.150 C
.165 CFS
.180 CFS
.188 S
.200 C
.203 FS
.220 CFS
.238 FS
.240 C
.250 S
.260 CFS
.280 C
.281 FS
.300 CFS
.313 S
.320 CFS
.340 CFS
.360 CFS
.380 C
.400 CFS
.420 CS
.438 FS
.440 C
Avg.
I.D.
(Inch)
1.491
1.456
1.435
1.432
1.402
1.397
1.365
1.330
1.321
1.294
1.287
1.248
1.207
1.202
1.180
1.157
1.111
1.109
Hot Finish
(ID)4'97
7.293
6.475
6.021
5.972
5.365
5.277
4.704
4.135
3.994
3.600
3.506
3.012
2.551
2.503
2.276
2.066
1.691
1.674
Inside
Area
(Sq.Ft.)
.01213
.01156
.01123
.01119
.01072
.01065
.01017
.009656
.009522
.009132
.009036
.008500
.007950
.007890
.007600
.007303
.006739
.006711
Ferritic tubing to be Hot
finished except gages exceeding
.281 which will be cold drawn.
Avg.
I.D.
(Inch)
1.505
1.472
1.452
1.450
1.421
1.417
1.383
1.350
1.332
1.306
1.299
1.261
1.221
1.217
1.196
1.172 v
1.128
1.126
1.084
1.055
1.039
.995
.950
.917
.906
.862
.817
.777
.773
Cold Drawn
(ID)4'97
7.647
6.842
6.393
6.345
5.741
5.653
5.023
4.450
4.166
3.769
3.674
3.173
2.704
2.656
2.438
2.208
1.822
1.805
1.493
1.305
1.212
.976
.778
.651
.613
.478
.367
.286
.278
Inside
Area
(Sq.Ft.)
.01236
.01182
.01150
.01147
.01102
.01095
.01044
.009946
.009686
.009302
.009208
.008681
.008139
.008080
.007800
.007501
.006944
.006917
.006408
.006072
.005894
.005401
.004930
.004591
.004480
.004052
.003645
.003298
.003260
All Stainless Steel Tubing to
be Cold Drawn.
APPENDIX E SHEET 7
-------
-108-
PROPERTIES OF HOT FINISHED and COLD DRAWN TUBES 2" OD
C - Low Carbon Steel H.S. Sq. ft./lin. ft = 0.5230
F - Ferritic Alloy Steel
S - Stainless Steel
Minimum
Tube Wall
Thickness
(Inch)
.110
.125
.134 FS
.135 C
.148 FS
.150 C
.165 CFS
.180 CFS
.188 S
.200 C
.203 FS
.220 CFS
.238 FS
.240 C
.250 S
.260 CFS
.280 C
.281 FS
.300 CFS
.313 S
.320 CFS
.340 CFS
*.360 CFS
*.375 FS
.380 C
*.400 CFS
.420 CS
.438 FS
.440 C
.460 C
.500 FS
.531
.563
.594
.625
Avg.
I.D.
(Inch)
1.741
1.706
1.685
1.682
1.652
1.647
1.615
1.580
1.571
1.544
1.537
1.498
1.457
1.452
0.430
1.407
1.361
1.359
1.316
1.286
1.270
1.224
1.179
1.145
1.133
Hot Finish
(ID)4'97
15.75
14.23
13.37
13.28
12.12
11.95
10.84
9.730
9.451
8.661
8.472
7:462
6.500
6.399
5.916
5.461
4.636
4.598
3.914
3.495
3.285
2.739
2.268
1.960
1.864
Inside
Area
(Sq.Ft.)
.01654
.01587
.01548
.01544
.01488
.01480
.01423
.01362
.01346
.01300
.01288
.01224
.01158
.01151
.01115
.01080
.01011
.01007
.009445
.009025
.008802
.008181
.007584
.007150
.007008
*Fem'tic tubing to be hot
finished except the following
gages and heavier will be cold
drawn :
C.S. -
C.M. -
T-22 -
360 T-ll - .
360 T-9 - .
375
400
360
Avg.
I.D.
(Inch)
1.755
1.722
1.702
1.700
1.671
1.667
1.633
1.600
1.582
1.556
1.549
1.511
1.471
1.467
1.446
1.422
1.378
1.376
1.334
1.305
1.289
1.245
1.200
1.167
1.156
1.112
1.067
1.027
1.023
.9788
.8900
.8211
.7501
.6813
.6125
Cold Drawn
(ID)4'97
16.40
14.91
14.07
13.98
12.84
12.67
11.46
10.35
9.793
9.000
8.811
7.794
6.822
6.721
6.252
5.769
4.928
4.888
4.188
3.756
3.539
2.973
2.482
2.159
2.058
1.694
1.384
1.145
1.120
.8989
.5603
.3756
.2395
.1485
. 08748
Inside
Area
(Sq.Ft.)
.01681
.01618
.01580
.01576
.01523
.01515
.01455
.01396
.01366
.01320
.01309
.01246
.01181
.01174
.01142
.01104
6
.01032
.009705
.009290
.009070
.008456
.007864
.007434
.007293
.006744
.006216
.005759
.005710
.005225
.004320
.003677
.003069
.002531
.002046
All Stainless Steel Tubing to be
Cold Drawn
APPENDIX E SHEET 8
-------
-109-
PROPERTIES OF HOT FINISHED and COLD DRAWN TUBES 2-l/2"OD
C - Low Carbon Steel H.S. Sq. ft./lin. ft = 0.655
F - Ferritic Alloy Steel
S - Stainless Steel
Minimum
Tube Wall
Thickness
(Inch)
.110
.125
.134 FS
.135 C
.148 FS
.150 C
.165 CFS
.180 CFS
.188 S
.200 C
.203 FS
.220 CFS
.238 FS
.240 C
.250 S
.260 CFS
.280 C
.281 FS
.300 CFS
.313 S
.320 CFS
.340 CFS
.360 CFS
.375 FS
.380 C
.400 CFS
.420 CS
.428 FS
.440 C
.460 C
.500 FS
Avg.
I.D.
(Inch)
2.241
2.206
2.185
2.182
2.152
2.147
2.115
2.080
2.071
2.044
2.037
1.998
1.957
1.952
1.930
1.907
1.861
1.859
1.816
1.786
1.770
1.724
1.679
1.645
1.633
1.588
1.542
Hot Finish
(ID)4'97
55.23
51.04
48.66
48.40
45.12
44.63
41.43
38.14
37.30
34.92
34.34
31.21
28.15
27.83
26.35
24.74
21.94
21.81
19.40
17.87
17.09
15.01
13.14
11.86
11.46
9.959.
8.616
Inside
Area
(Sq.Ft.)
.02740
.02654
.02604
.02598
.02526
.02515
.02441
.02361
.02340
.02278
.02263
.02178
.02089
.02079
.02030
.01983
.01890
.01885
.01798
.01740
.01709
.01622
.01537
.01475
.01455
.01375
.01297
Ferritic Tubing to be Hot-
Finished except gages exceeding
.420 which will be cold drawn.
Avg.
I.D.
(Inch)
2.255
2.222
2.202
2.200
2.171
2.167
2.133
2.100
2.082
2.056
2.049
2.011
1.971
1.967
1.946
1.922
1.878
1.876
1.834
1.805
1.789
1.745
1.700
1.667
1.656
1.612
1.567
1.527
1.523
1.478
1.390
Cold Drawn
(ID)4'97
57.00
52.94
50.61
50.36
47.16
46.68
43.23
39.97
38.32
35.95
35.37
32.25
29.19
28.86
27.40
25.77
22.94
22.81
20.37
18.83
18.03
15.92
14.00
12.69
12.28
10.73
9.339
8.214
8.096
6.989
5.137
Inside
Area
(Sq.Ft.)
.02775
.02694
.02645
.02640
.02571
.02561
.02483
. 02406
.02365
.02305
.02290
.02207
.02120
.02110
.02070
.02016
.01924
.01919
.01834
.01777
.01746
.01661
.01577
.01516
.01496
.01417
.01340
.01272
.01265
.01192
.01053
All Stainless Steel tubing
to be Cold Drawn.
APPENDIX E SHEET 9
-------
SCHEMATIC-OVERFIRE AIR 8 GAS RECIRCULATION SYSTEMS
ALABAMA POWER CO. BARRY STA. No. 1
GAS TO PRECIPITATOR •
GAS FROM PRECIPITATOR-
DAMPER
SLIDEGATE
GR /
FAN \
x
GAS RECIRCULATION
SEC
A
1
c
71 r
1
1 /
1
AIRHEATER
GAS BYPASS
1^71-
1 IXNI
^ GAS FROM
AIRHEATER
y
GAS TO
AIR-
HEATER
WRHEATE
ONOARY
IR DUCT
r
i
AIR FROM
AIRHEATER
1
i
.n
,J
GAS
RECIRC. TO
SECONDARY
AIR DUCT
'
U
•^^
^J
i
1 OVERFIR
\ /
w
R j
1
— DHEK
COLD
Ar
AIRHI
AIR B
O.A.
ID
:ATER
ypAss
E AIR DUC
O.A.
Ha-
ME1-
-G3-
-H3
J
i
r
i_
HOT AIR TO COAL MILLS
AIR TO
AIRHEATER
TEMPERING AIR TO MILLS
GAS RECIRCULATION TO COAl
T r
l~l O.A.
Jl
UPPER WINDBOX
LOWER WINDBOX
AIR TO FUEL
AIR COMPART.
c
.n .
i U
\
\
=1
. MILLS
... O.A.
ISH
"HEK
GAS RECIRCULATION AND 1
HOT AIR TO COAL MILLS _ |
/
I
o
..n.
10 FAN
COAL I
MILLS |
\
FD FAN
-------
-111-
TEST PROGRAM FOR THE EVALUATION
OF BIASED FIRING, OVERFIRE AIR, AND
EXISTING PROCESS VARIABLES
CONTRACT NO. 68-02-0264
(CE CONTRACT 6472)
PILOT FIELD TEST PROGRAM TO STUDY
METHODS FOR REDUCTION OF NOx FORMATION IN
TANGENTIALLY COAL FIRED STEAM GENERATING UNITS
PREPARED FOR
THE ENVIRONMENTAL PROTECTION AGENCY
RESEARCH TRIANGLE PARK,
NORTH CAROLINA 27711
APRIL 19, 1973
COMBUSTION ENGINEERING, INC.
FIELD TESTING &
PERFORMANCE RESULTS
1000 PROSPECT HILL ROAD
WINDSOR, CONNECTICUT 06095
(203) 688-1911
-------
-113-
TABLE OF CONTENTS
Page
Introduction 115
Program Objectives 117
Program Outline 120
Task I - Overfire Air System Design
and Program Scheduling 120
Task II - System Fabrication 121
Task III - Instrumentation Installation 122
Task IV - Baseline Tests - Load and
Excess Air Variation 123
Task V - Baseline Tests - Bias Firing 124
Task VI - Equipment Delivery and Installation 126
Task VII - Final Test Preparation 126
Task VIII- Unit Optimization Program 127
Task IX - Application 132
-------
-115-
INTRODUCTION
The emphasis on improved quality of our environment as a major national
goal is providing additional challenges in the design and operation
of fossil-fueled utility steam generators. Until recently, R&D
activity involved in steam generator design and operation has
traditionally been directed toward reducing equipment and operating
costs while improving reliability and availability of equipment.
Advances in combustion and control technology have minimized smoke,
CO, hydrocarbon and solid combustible emissions. The application
of electrostatic precipitators has greatly reduced particulate
emissions and more recently, wet scrubber systems for removal of
sulfur oxides, as well as particulate matter, provide an approach
to the control of most pollutants with the exception of NOX which
is not readily removed in a wet scrubbing system.
Modification of the combustion process has been found to be
effective in reducing NOX formation in oil and gas fired utility
steam generators. Recent work with coal fired steam generators
has demonstrated that overfire air simulation with tangential
firing has been effective in reducing NOX by as much as 50% of
uncontrolled values. The major problem.to be evaluated is the
applicability of overfire air as viable means for control of NOX
emissions with coal firing.
-------
-116-
For this reason, C-E proposed that a program be undertaken for the
evaluation of overffre air as a feasible method for reduction of
NOX emissions from coal firing utility boilers. A program of
this nature can be best conducted on a commercial size pilot
plant unit which will provide the basis for evaluating potential
operating and control problems and establishing the optimum
methods for NOX reduction. This approach is particularly valid
for tangential firing where there is considerable interaction
between the various fuel and air streams.
-------
-117-
PROGRAM OBJECTIVES
The objective of this program is to investigate the effectiveness
of employing overfire air as a method of reducing NOX emission
levels from tangentially coal fired steam generators.
Specifically, the factors to be considered in realizing this
objective are as follows:
1. The program will be conducted on the 125 MH Alabama Power
Company, Barry Station #1. This unit is large enough to
provide furnace characteristics representative of large
utility designs but of a size which will minimize
modification costs and permit a versatile test program.
In addition, Alabama Power Company has expressed a
willingness to cooperate in this program and the Barry
Station is located favorably for receiving various coals
and has the facilities for handling these coals.
2. The overfire air system will be designed to avoid
interference with the installation of further control
systems, such as gas recirculation to the secondary air
duct or coal pulverizers or air preheat variation, should
the results of this study indicate the necessity for
further NOX emission control effort with coal firing.
-------
-118-
3. Torproperly assess the effect of combustion modifications
on unit performance and emission level, baseline tests
will be conducted prior to modification to evaluate
operation with normal and biased firing techniques. This
test series will include investigation of the effects of
biased firing on flame stability, thermal performance and
long term corrosion.
4. The effect of NOV control methods on other gas constituents
-A
will be evaluated during all test phases. The following
constituents will be measured. NOX, SOX, CO, HC, 03 and
particulate samples for unburned combustible analysis.
In addition, selected gas samples will be obtained for
PNA analysis by EPA.
5. The overfire air test program will evaluate the various
optimized modes of overfire air operation with respect
to unit transient operation, long term corrosion effects,
steam generator performance and applicability to a range
of coal fuels. One additional coal will be evaluated
with consideration given to a second additional coal based on
program results and availability of this coal.
-------
-119-
6. Based on the result of the test program, conclusions and
recomnendatfons will be made pertaining to the application
of the technology developed during the program, to new
and existing boiler designs. In addition, properly founded
and projected recommendations for further NOX control effort
in coal firing will be developed.
-------
-120-
PRQGRAM OUTLINE
Task I - Overfire Air System Design and Program Scheduling
A. Drawings
The design, detailed fabrication and erection drawings for
installation of the overfire air system will be completed.
Specifically the overfire air system will be designed to:
1. Introduce a maximum of 20% of the total combustion
air above the fuel admission nozzles.
2. Provide for introducing the overfire air through the
top two compartments of the unit windbox as well as
two additional compartments in each furnace corner
located approximately eight feet above the fuel
admission zone.
3. Control the vertical angle and velocity of air admission.
4. The design shall make full consideration for future
addition of alternate NOX control methods such as air
preheat control and gas recirculation to the secondary
air compartments and coal pulverizers.
-------
-121-
B. Scheduling
An updated schedule for Tasks II through VI will be prepared
relative to date of contract approval and unit outage dates.
This schedule will define major milestones to be
accomplished in completing these tasks.
Task II- System Fabrication
A. Upon approval of the modification drawings defined under
Task I by EPA, the necessary equipment will be purchased,
and pre-fabrication of the overfire air ports, ductwork,
auxiliary equipment etc. necessary for modification of
the unit will be completed.
B. Instrumentation required for the baseline and optimization
test phases of the program will be fabricated, calibrated
as required, and prepared for shipment to the test unit
site. This effort will include such items as fabrication
of corrosion probes, probe control systems, and gas
temperature and sampling probes, calibration of
thermocouples, analyzers and transducers and packaging
of equipment for shipment.
-------
-122-
Task III - Instrumentation Installation
Instrumentation necessary to conduct the baseline and biased
firing test programs will be installed and calibrated. This
instrumentation will consist of the following:
Measurement
Flue Gas Constituents
NOX
S02
CO & Hydrocarbons
Carbon Loss
Oxygen
Fuel Analysis
Ash Analysis
Flow Rates
Steam & Hater
Feedwater Flow
RH & SH
Desuperheat Spray Flow
RH Flow
Coal Flow
Air & Gas
Total Air & Gas Wt.
Overfire Air
Air Heater Leakage
Instrument
Chemiluminescence Analy.
Wet Chemistry
Infrared Analy. and Flame
lonization Analy.
Dust Collector
Paramagnetic Analyzer
ASTM Procedures
ASTM Procedures
Flow Orifice
Heat Balance (°F & PSIG)
Around Desuperheater
Heat Balance Around
Superheat Extractions
and Est. Turbine Gland
Seal Losses
Coal Scale Readings
Calculated
Pi tot Traverse
Paramagnetic 02 Analyzer
-------
-123-
Temperatures
Steam & Hater °F
Unit Absorption Rates
WW Absorption^•
Air & Gas °F
Pressures
Steam & Water-PSIG
Unit Absorption Rates
Unit Draft Loss
Temperature and
Pressure Logging °F & PSI
Calibrated Stainless
Steel Sheathed CR-C Well &
Button TC's
Calibrated Stainless
Steel Sheathed CR-C
Chordal WW TC's
CR-C TC's
Water Cooled Probes
PL/PL-10% Rh TC's
Pressure Gauges
and/or Transducers
Water Manometers
C-E Data Logger
Capacity: 400 temperatures,
50 pressures
Task IV - Baseline Tests - Load and Excess Air Variation
A program will be conducted to establish the effect of unit load
wall slagging and excess air variation on baseline emission
levels, thermal performance, corrosion rates and operating
ranges. A baseline corrosion test of four week duration will
also be conducted at maximum load conditions.
1.) To be installed during Task VI
-------
-124-
There will be 14 tests run for the combination of conditions
shown in Table 1.
Table 1
D-l
D-2
D-3
L-l
L-2
L-3
L-l
L-2
L-3
L-l
L-2
L-3
E-l
5
1
8
13
11
E-2
6
4
2
9
E-3
7
3
10
14
12
Test Conditions
Percent Excess Air-Max. Unit Load
Normal Excess Air E-l
Minimum Excess Air E-2
Maximum Excess Air E-3
Furnace Wall Deposits
Clean
Moderate
Heavy
Percent Load
Max. Load
3/4 Max. Load
1/2 Max. Load
D-l
D-2
D-3
L-l
L-2
L-3
At the completion of test 14, the unit will be operated with
normal excess air and unit loading for a 4 week corrosion test
period. During the 4 week period maximum load will be carried
whenever possible.
Task V - Baseline Tests - Bias Firing
A test program will be conducted to establish the effect on
emission levels of operation with various fuel elevations out
of service. Specifically, this program will evaluate:
-------
-125-
1. Maximum emissions control throughout the normal load range.
2. Maximum emissions control at full load only.
3. Control of emissions to meet and maintain emissions standards
throughout the normal load range.
A corrosion test of four week duration will also be conducted
at the optimum biased firing condition. During the 4 week period,
unit loading will be varied similar to the loading schedule
followed during the baseline corrosion test program.
There will be 10 tests run at the conditions identified in
Table 2.
Table 2
B-l
B-2
B-3
B-4
L-l
6
5
4
3
L-2
7
2
L-3
8
9
10
1
Test Conditions
Firing Elevation Out of Service -
Dampers Open
Top Elevation B-l
Top Center Elevation B-2
Bottom Center Elevation B-3
Bottom Elevation B-4
Percent Load
Max. Load
3/4 Max. Load
1/2 Max. Load
L-l
L-2
L-3
-------
-126-
At the completion of test 10, the unit will be operated at
optimized conditions and normal unit loading for a 4 week
corrosion test period. Unit loading will be varied during
the test period on a schedule similar to that followed during
the baseline corrosion test period.
Task VI - Equipment Delivery and Installation
The equipment necessary for completing the overfire air
modification will be delivered to the test site and installed
on the test unit in accordance with the approved erection
drawings. Delivery and installation of equipment will be
coordinated with scheduled unit outages as defined by the
updated schedule to be prepared under Task I.
Task VII - Final Test Preparation
During the unit modification outage the following final
preparations will be made for conducting the overfire air
optimization test program defined in Task VIII.
1. The waterwall thermocouples will be installed as defined
in the detailed test program.
2. Thermocouples will be installed on the fuel, air and overfire
air nozzles to determine the effect of overfire air
optimization on nozzle temperatures and wastage rates.
-------
-127-
3. All Instrumentation and readouts will be checked for proper
Installation and operability.
4. The test program will be updated and reviewed with Alabama
Power Company and the EPA Project Officer for final approval.
5. The test unit will be inspected to assure proper operating
of all dampers, tilting mechanisms and their operators and
to establish acceptable operating condition of fuel nozzles,
air preheaters, pulverizers and soot blowing systems.
Task VIII - Unit Optimization Program
The experimental program updated and approved in Task VII will
be conducted in Task VIII and the data generated will be
analyzed, correlated and compared to data generated during
Task V. A comprehensive report will then be developed relating
the effectiveness of each method of emission control with
respect to unit thermal and operational performance.
The test program will investigate the effect of overfire air
location and introduction rates at various unit loadings and
operating conditions. Those methods which are found to be
optimum from the standpoint of both effectiveness in reducing
emission levels and unit operation will then be evaluated to
determine their acceptability for long term operation and their
applicability to alternate coal types.
-------
-128-
A. Unit Load and Excess Air Variation
The object of this evaluation is to determine baseline
operating characteristic of the modified unit and to compare
these with the unmodified unit test results. There will be
14 tests run (1 thru 14) at the conditions identified in
Table 3.
Table 3
D-l
D-2
D-3
L-l
L-2
L-3
L-l
L-2
L-3
L-l
L-2
L-3
E-l
5
1
8
13
11
E-2
6
4
2
9
E-3
7
3
10
14
12
Test Conditions
Percent Excess Air
Normal Excess Air E-l
Minimum Excess Air E-2
Maximum Excess Air E-3
Furnace Hall Deposits
Clean D-l
Moderate D-2
Heavy D-3
Percent Load
Max. Load L-l
3/4 Max. Load L-2
1/2 Max. Load L-3
B. Overfire Air Location, Rate and Velocity - Full Load
The object of this evaluation is to determine:
1. The effect on the NOX emission level of varying the
velocity and height above the fuel compartments at
which the overffre air is admitted.
-------
-129-
2. The effect on the NO^ emission level of varying the
overftre air rate.
3. The maximum overfire air rate with respect to steam
temperatures, flame stability and furnace wall
deposits.
There will be 9 tests run (tests 15 thru 23) at the
conditions identified in Table 4.
Table 4
A-l
A-2
A-3
0-1
15
16
0-2
17
0-1
0-2
19
18
0-2
20
0-3
0-4
21
0-1
0-2
23
22
0-3
0-4
Test Conditions
Overfire Air Admission Points
Eight Feet Above Fuel Compartments
(high)
Immediately Above Fuel Compartments
(low)
Overfire Air Rate and Temperature
No Overfire Air
1/2 Max. Overfire Air
Max. Overfire Air
A-l
A-2
A-3
Top
Bottom
Top
Bottom
0-1
0-2
0-3
0-4
-------
-130-
C. Qverfire Air Tilt Variation
Having established the optimum overfire air location, rate,
velocity and temperature, this condition will be used to
perform the tilt variation tests. In the event that more than
one optimum combination is noted, the tilt variation test will
be performed with each combination.
The object of this evaluation is to determine:
1. The effect of tilting overfire air compartment nozzles
on the NOX emission level.
2. If the overfire air compartment nozzles should tilt with
the fuel nozzles or remain fixed.
3. The maximum allowable minus and plus tilt with respect
to steam temperatures and furnace wall deposits.
There will be 6 tests run (tests 24 thru 29) at the conditions
identified in Table 5.
Table 5
F-l
F-2
F-3
P-l
24
25
26
P-2
27
28
P-3
29
Test Conditions
Overfire Air Compartment Tilt
Horizontal Tilt P-l
Maximum Minus Tilt P-2
Maximum Plus Tilt P-3
Fuel Nozzle Tilt
Horizontal Tilt .F-l
Maximum Minus Tilt F-2
Maximum Plus Tilt F-3
-------
-131-
D. Load Variation At Optimum Conditions
The object of this evaluation is to determine:
1. The effect on the NOX emission level of operating at
previously determined optimum conditions for NO*
reduction while varying load and the degree of furnace
wall deposits.
2. The effect on unit operation while operating at said
conditions.
There will be 6 tests run (tests 30 thru 35) at the
conditions identified in Table 6.
Table 6
OC-1
D-l
D-3
L-l
32
33
L-2
31
34
L-3 .
30
35
Test Conditions
Percent Load
Max. Load L-l
3/4 Max. Load L-2
1/2 Max. Load L-3
Furnace Wall Deposits
Clean D-l
Heavy D-3
Optimum Conditions
Optimum Conditions OC-1
E. Overfire Air Evaluation - Second Coal Type
The object of this part of the program is to evaluate the
objectives of test sections A, B, C and D on an alternate
-------
-132-
coal fuel. These sections will therefore be repeated to
whatever degree necessary to verify acceptable baseline
and optimum operation with the alternate coal.
F. Effect of Long Term and Transient Operation
After the optimized modes of operation have been established
for each coal, they will be evaluated with respect to their
effects on long term and transient operation. Each test
will be conducted for a 4 week period during-which unit
loading will be varied on a schedule similar to that followed
during the baseline and biased firing corrosion test programs.
Furnace corrosion probe studies will be conducted during each
test period.
Task IX - Application Guidelines
Based on the results of this study a program will be prepared
outlining the application of the technology developed to existing
and new design tangentially coal fired utility boilers.
The program will encompass the following three sub-tasks.
Sub-Task 1
Guidelines will be prepared for the application of the developed
technology to existing boilers. These guidelines will define
necessary procedures for applying the technology, the effect
on those emissions evaluated in the study and the effect on
unit performance.
-------
-133-
The equipment necessary for modification of existing and new unit
designs will be defined and the costs of these modifications wfll
be developed for 4 unit sizes between 125 and 1000 MW.
Sub-Task 2
The applicability of the modifications developed during this
study will be determined for all existing tangentially fired
units in the U.S. Those units for which the technology is deemed
inapplicable will be identified and the reasons discussed.
Sub-Task 3
The incorporation of the modifications developed in thfs study
into new unit designs will be evaluated with respect to degree
of applicability and costs.
The effect of these methods on emission control will be evaluated
as well as the cost effectiveness thereof, considering capital
costs, operating costs and equipment life.
-------
-135-
SECTION VI
ATTACHMENT III
ENGINEERING DRAWINGS
-------
I
GO
NOT1S
GENERAL ARRANGEMENT OF DUCTS
-------
©
r
r
co
CO
I
GENERAL ARRANGEMENT OF DUCTS
-------
CO
vo
I
GENERAL ARRANGEMENT OF DUCTS
-------
RE.GVSTE.R VJS.4-
*.\R REttSTER VA2.
I
o
OVERFIRE AIR REGISTER PLAN ARRANGEMENT
-------
OVERFIRE AIR REGISTER ARRANGEMENT
-------
-142-
u<-i\nin*>/,'"
TILTING TANGENTIAL FIRING WINDBOX ARRANGEMENT
-------
-143-
SECTION VI
ATTACHMENT IV
COST ESTIMATES
FOR CONDUCTING PILOT FIELD TEST PROGRAMS
-------
-145-
GOST ESTIMATES FOR CONDUCTING
PILOT FIELD TEST PROGRAMS
Cost estimates are presented using Optional Form 60 for the design
fabrication, erection and testing of NOx control systems for Barry
No. 1 unit of Alabama Power Company. The scope of work and cost of
each program are summarized below.
1. Evaluation of:
Overfire Air System
Gas Recirculation System
Air Preheat System
Water Injection System
Existing Process Variables $ 1,678,349
2. Same scope as item 1 performed in two stages.
a.) Initial installation and evaluation of:
Overfire Air System
Air Preheat System
Water Injection System
Existing Process Variables ($753,070)
b.) Later installation and evaluation of:
Gas Recirculation System
Combinations of above systems ($1,093,487)
Total $ 1,846,557
3. Evaluation of:
Overfire Air System
Existing Process Variables ($426,644)
(including options for metric
system and testing of third
coal type) ($34,300)
Total $ 460,944
-------
-U7-
CCNYKACT r-r.iCING PriCi'CSA
(RKSIUKCII AN I.) DM'HLOl'MIW)
', Y.I i. loi.n r i'.-r »'•: »lirn (!) wl'ni.'ttutn of \-ft\i or firiVinf. «|«u (iff I I'R 1-5.007-)) it required «nd
I 111) >u!«ii:»i..iii .\ir ihv f>piion»l Form }9 i» •uihotiicii hjr llif fonlfjcdnj nfTirvr.
!_.__——.—..
I NA.Mi 0." OilUO*
COMBUSTION ENGINEERING, INC.
j 1000 Prospect Mill Road
Windsor, Conn. 06095
«>'iVOI/.S| >.NO lOCAJtaXJI WMC« WOI:i! li IO »E fClifpilMIB
"indsor, Ct., Chattanooga. Tenn.,
St. Louis. Mo.. Mononcafiela. Pa.
IOIAI AMOUNT or KoroiAi
t 1,678,349.00
DETAIL fJKSCR.'PYiO:-: "O? COST i-l.r-.V.'-NYS'
Ullllf.'
CACt rA>.
I NO. OlAbtl
JUt'filti AND/OS KKVlCli 1
Equipment, material 5 labor to modify
existing boiler. Engineers 5 Technicians
to investigate Combustion Modification
Techniques for NOX Control by adding overjfin
covi iuuciiATioM HO. air Q 2&s
EPA-68-02-0264recirc.
1. OilitCT MATdiAl (Ilinin it F.\/,,bil A)
lit MS
AN3AKO COI/.«.\:BCIAI
fM
//..<« rt./
ror/i/. Dinner .M/OV-
ff.T COST
r^H
(')] cs;
°COST'
S/Stems
245,804
80,633
•^i-iZ^'J '508.293
Sec Attachment No. 1
ror,tt.
4. I A t,0r. OV|V'|-,,0 t$l<:j.»'_-—j..—_.«"' - "" "'_!_.'2t
XkAiCn li> COiT f.'J I
'"'•'" 'A1-':'^ : •' ">• .. r '•';•".' ; •'! 335
TOTAL irCCV/!.1. 77JTI.VC
s~. irfCLM lOUi'uirT (If i.'i'HI ihaif.t) (l:tiaitt tn EMIiil At
r. i**v;t (if iiirtti <>.„,(,i (r,;,-{ //,/.»/', „• Hti'.i COJTI llt,~ii:t »u f.\liibil At
>0.
TWIAI. rtlKKCT COXT AND nVI-KIIKAIt
II. GIN'.B/i «.i:a
; tr't'liJ («{«« 4 Vt •/ /M/ tln*t»i N«.
13.
1501.20:
60.04t
-4
IS.
T07V4/.. KTriMATFM COST
1561,25!
U. fl'l CSI'lOfll
117.094
ror/it
-;.'t> COIT *.vn
'Moy J970 '
i'OHM CO
r:-'H J-'. 0.006
50CO-101
-------
-148-
. . .V. ;>I.-,M«->' •> !• > niiU'J lof uic in <->nn?tiiuA »Slli ami in '.: Cr f.T« . OJk,t {_.f lyjMliJlGM
j Combustion Engineering, Inc. November 9, 1972
i
1 COST U SC.
{ la
! in
! la -
] la
} la
; Ib
; Ib
! ib
J 1C
1 Ic
-i Ic
j 1C
i 7a
i 9
EXMirfST A-f.UHPOXTlNG SCiiilDULG r.S>ff//>-. // ///rt/v ;/"W » «« 9
1
i
<
Misc. Material 3,500
'
!
'
1
»
EST COS) (1)
181.856 |
245.804
80,633
31,403
18,500
i
i. ti/.i ANY Excr.unvE .M-.txcY OF THE UNITFO STATCS GOVERNMENT Ptr.fOHMto ANT tEvirw or YOUB ACCOUNTS OK RCCOHUS IN CONNICTIOI: WITH AMY ot.«u
COVUNMtNT (KD/.l CONTRACT Oft SUZCONTf.ACT WHHIN THE PAST TWflVE MONTHS?
IS Y£S O NO f'//"- itfioli/f Moif.)
NAM: AKD /.ooccii or RCV;£V.-INC Office AKO iNumouAi • UIEPHONI- NUMBCf./nfif.uiiow
Atomic Energy commission. Chicaco Operations Office
II. WM VOv' HEO'.
G V£i C
/IKE ;nt u;s cr ANY GGvuNMf NT moraiY IN TH* PERFORMANCE OF THIS taocosco CONTEACT?
vj I>'O (If ft;, itfetiii// tn rtrtrtt tr itjiaratt f>"gi)
III. DC' VO'J (cQi::>r C,OV«NMtNf CONTRACT FINANCING TO PERFORM THIS r.lOPOStO CONTRACT?
(~~) YCS [X] NO (If jn. iHiiilifj,): Q ADVANCC PAYMENTS Q PROCRtiS PAY/A£NTS OR Q GUARANTf £0 IOANS
IV. C-O VC:i.i NOV/ i-:-.-
-------
-149-
Novcmbcr 9, 1972
ATTACHMENT NO. 1
EPA CONTRACT 68-02-0264
CE CONTRACT NO. 6472
OPTIONAL FORM 60
Combined Overfire Air § Gas Recirculation Systems
COST ELEMENT #3 DIRECT LABOR #4 LABOR OVERHEAD
DEPT. EST. MRS. RATE/HR. EST. COST OH RATE EST. COST
611 Eng. 15,000 5.35 80,125 90 72,125
631 Eng. 6,030 6.60 39,889 95 ' 37,898
631 Tech. 2,620 4.85 12,697 95 12,062
516 Eng.' 600 8.60 5,160 75 3,870
685 Eng. 130 7.55 985 160 1,570
685 Tech. 650 4.75 3,087 160 4,940
632 Service 800 6.55 5,250 111 5,830
641 Erection 1,680 8.15 13,652 108 14,740
Shop Labor 11,895 5.02 59,713 164 97,784
Metal Erect.
Labor 44,850 7.92 355,212 24 84,318
575,770 335,137
-------
-150-
Page 1
November 9, 1972
Attachment No. 2
EPA CONTRACT 68-02-0264
CE CONTRACT NO. 6472
Combined Overfire Air § Gas Recirculation Systems
Based on Estimated 1974 Costs
PHASE II
Task I Detail 5 Design
651 Eng. 40 hrs.
611 Eng. 15,000
Task II Purchase fi Fabricate
Raw Material fi Shop Fab.
Purchased Material
Insurance
516
152,250
238,130
181,856
1,000
152,766
420,986
Task III Install Instruments; Baseline Tests
631 Eng. 400 hrs.
631 Tech. 500 hrs.
6S3 Eng. 50 hrs.
6S5 Tech. 250 hrs.
632 Service 160 hrs.
Computer
Material
Freight
Field Expenses
Car Rental
Air Travel
5,160
4,725
983
3,087
2,216
2,000
1,000
400
5,100
2,000
900
27,571
Combined
PHASE III
Task I Deliver Equipment § Modify Unit
631 Eng. 150 hrs.
Material
Field Expenses
Car Rental
Air Travel
Freight
Erect. Equip. Rental,
Insurance
Field Labor
Metal 44,850 hrs.
Set., Insul. 5 Lag,
641 Erection Rep.
Tools, Material § Consumables
10600 hrs.
1.6SO hrs.
1,935
500
5,504
800
200
12,923
112,350
1,000
439,530
153,454
28,392
736,588
-------
-151-
Pagc 2.
Combined
PHASE III (Continued)
Task II Final Test Preparation § Schedule
631 Eng. 240 hrs.
651 Tech. 120 hrs.
Material
Freight
Field Expense.
Car Rental
; Air Travel
Combined
PHASE IV '
Task I Perform Unit Tests
631 Eng. 1280 hrs.
631 Tech. 2000 hrs.
632 Service 640 hrs.
Material
Field Expense
Car Rental
Air Travel
Task II Data Analysis
631 Eng. 2560 hrs.
516 Eng. 600 hrs.
683 Eng. 80 hrs.
683 Tech. 400 hrs.
Computer
Freight
Air Travel
PHASE V
Tasks I, II § III Application Guidelines
631 Eng. 1360 hrs.
Computer
Air Travel
TOTAL DIRECT COST & OVERHEAD
G$A @4%
TOTAL ESTIMATED COST
FEE @7-l/2%
GRAND TOTAL ESTIMATED COST 5 FEE
Attachment No. 2
3,096
1,134
500
200
1,100
400
400
16,512
18,900
8,864
1,500
20,400
6,400
5,280
33,024
9,030
1,572
4,940
10,000
500
500
17,544
1,000
500
6,830
77,856
59,566
19,044
$1,501,207
60,048
$1,561,255
117,094
$1,678,349"
-------
-153-
i .
CONTUACT PRICING PROPOSAL
(RKSKAKCII /«.V/.) DIll'KljOI'MKNTf
'Hit* lonn i>. it.r «>•: vlirn (i) iul>imttii>n nf t-ou P» pricing Oil* (»»r I'I'IX I-J.OOT-J) l\ ir<]ulr.
FAOt NO.
• •!••»•«
[NO.
SUlTUli AXD/OK ifKVlClt I
Equipment, material G labor to modify
existing boiler.engineers Q technicians
to investigate Combustion Modification
Techniques for NOX Control by adding OVER^I
•B
DLVAIL OKSCRJPTiOrj Of- COST El?;.-,«:NV5
c
EPA 68-02-0264
1. OU.-.CT MAKSIM til, milt til F.\Mtl A)
ff.l COST
f. WKlK-ll) r«,W MAUKIAl
11.) VOUC 47ANDASO COMV.tRClAl IK/AS
r /Awn
"5T7T63
TOt/.l
1ST COST'
1
J. »VA\lSIAl O\-»'II:A
ap_
rrl-
See Attachment No. 1
TOTAL IIIKf.fT LAKOK
<. UOO.IOVtVM.-'.O rV""// />«/wr/«,«/ .r CM' Ctnltr)'
See Attachment No. 1
. /-XDOR OVF.KIIF.M)
1ST
COM r
O.K. «»l£
•tc^'w-;-:/.f-i<*.'.•'••'>•'• ;:>''.; •.%
XkAltn CS1 COil I
t. SftCiAl Illi'-O tlutlnitinr ftl,l m't HI C»rtmntnl <*i/«/At/j*n/>
ilMi^te^S^ll^iiElSsI,
TOTHJ: jrccvx:. iY.tri.vc
f H COi? «l;:tl (tltiant »H Exhibit A)
f. T4AVU (If itintl »r HlHftnt Stttlfult)
bee txhibit A
v/orxi. rnxrat.
t. CONiO^TANfO ll,;it:,;\ -fur fill- UK)
•fOTAI. tOMULTAXTS
isr con
25.640
CSI COSl (*)
9. OIHIE Ul«H'.( COJIS
X;
54,330
17,840
673,587
-1
to.
roi.if. muter COST AND OCI-KIH^O
ii. cit;'.»/i«j;
12. SOYM'i.U
26.943
U.
TOrx/. KTTIMATEO COST
700,530
52.540
u.
rorxt cnv.\fx7X'o COST x.vo ML' OK PUOFIT
CO
OP.TJONAL
'•• 1070
>trv|r*ttij Admlnimralloi
-------
-154-
' I'Jm iiM • °*" t-r iui/AOiiON i
COMBUSTION ENGINEERING, INC. Oct. 25, 1972 |
cXl-ll;»!T A-SUHPOKTING SCiiEDULC (Specify. If wort tl>,ice h nttded, uie rti-cnt)
• COST U NC. I ITCM DESCRIPTION (Set foot not t ))
1 la
i la
i la.
i 1"
1 Ib
t Ib
1C
t 1C
1C
: ic
7a
9
9
» 9
insulation • iu,buu
Controls 7,'JKO
Instrumentation 2 ,'J^ii
Setting, Insulation ti Lagging Erection Equip. 13,000
Setting, Insulation 5 Lagging Erection Labor 43,068
Metal lircction Equip. Rental, Tools, Consumables. •. 26,435
Ductwork N 14,740
Cates fi Dampers 7^618
.Uoiler Modifications Tube Inserts . 697
Structural Steel 6^,998
Freight 9500 Car Rental 9200 Air Travel 6940
Insurance 1,340
Computer 13,000
Misc. Material 3,500
<
ESTCOSl (i)
1
21, lib :
83,103
30,053
25,640
17.840 1
1
1
.
1
HAS ANY acr.unvf MHNCY or nit UNITFO STAVCS GOVERNMENT ptr.roHMto ANT REVIEW Of voui ACCOUNTS oc RCCOKUS IN CONNICTIOII wini ANY 01—.-,
COVIXNMMM (CIMt CONTRACT OR SUZCONIfiACT WITHIN THE PAST IWilVE MONTHS?
El VIS O NO tV t«- Minify Mar.)
AMI) >.DOKCil /rfA» «»
Stt thtnnf /tr luilnitti*ii *m4 ffttmtM
2
-------
-155-
EPA Contract 68-02-0264
CE Contract 6472
Optional Form 60
Attachment No. 1
October 25, 1972
Cost Element
Dept.
611 Eng.
631 Eng.
631 Tech.
6S3 Eng.
683 .Tech.
516 Eng.
632 Service
641 Erector
Metal Erection
Shop
Est. Ho
8,800
5,440
2,420
125
625
560
760
1,040
16,525
5,587
#3 Direct Labor
Rate/Hr.
//4 Labor Overhead
Est. Cost
8,800
5,440
2,420
125
625
560
760 •
1,040
16,525
5,587
$5.10
6.30
4.60
7.20
4.55
8.20
6.25
7.75
7.54
4.74
$ 44,930
34,312
11,170
900
2,847
4,592
4,754
8,050
124,599
26,507
90
95
95
160
160
75
111
108
43
165
$262.661
O.H. Rate
90
95
95
160
160
75
111
108
43
165
Est. Cost
$ 40,430
32,600
10,610
1,440
4,560
3,444
5,278
8,694
53,578
43,551
.$204,185
-------
-156-
Attachment No. 2
October 25, 1972
1 of 3
EPA Contract 68-02-0264
CE Contract 6472
Overfire Air System Only
Based on Estimated 1973 Costs
Phase II
Task I - Detail & Design
631 Engineer (40 hrs.) $ 492
611 Engineer (8,800 hrs.) 85.360
$ 85,852
Task II - Purchase & Fabricate
Raw Material & Shop Fab. 100,110
Purchased Material 21,415
Freight 4,200
Insurance 340
126,065
Task III - Install Instruments .
baseline tests
631 Engineer (400 hrs.) 4,920
631 Technician (500 hrs.) 4,500
683 Engineer (50 hrs.) 935
683 Technician (250 hrs.) 2,963
Service Engineer (160 hrs.) 2,112
Computer 2,000
Material 1,000
Freight 400
Field Expenses 5,060
Car Rental 2,000
Air Travel 900
26,790
-------
-157-
Attachment No. 2
October 25, 1972
2 of . 3
Phase III
Task I - Deliver Equipment
& Modify Unit
G31 Engineer (160 hrs.) $ 1,968
Material 500
Field Expense 3,556
Car Rental 800
Air Travel 200
Freight 4,200
Erect. Equip. Rental, Tools,
Material, & Consumables 39,435
Insurance 1,000
Field Labor
Metal (16,525 hrs.) 178,177
Set. Insul. & Lag (3,600 hra) 43,668
641 Erection Rep. (1,040 hrs.) 16.744
Task II - Final Test Preparation
& Schedule
631 Engineer (240 hrs.) 2,952
631 Technician (120 hrs.) 1,080
Material 500
Freight • 200
Field Expense 1,100
Car Rental 400
Air Travel • 400
$290,248
6,632
Phase IV
Task I - Perform Unit Tests
631 Engineer (1,200 hrs.) 14,760
631 Technician (1,800 hrs.) 16,200
Service Engineer (600 hrs.) 7,920
Material 1,500
Field Expenses 18,975
Car Rental 6,000
Air Travel 4.440
•69,795
-------
-158-
Attachmcnt No. 2
October 25, 1972
3 of 3
Tn.sk II - Dnta Analysis
631 Engineer (2,400 hrs.)
516 Engineer (560 hrs.)
6S3 Engineer (75 hrs.)
6S3 Technician (375 hrs.)
Computer
Freight
Air Travel
$ 29,520
8,036
1,405
4,444
10,000
500
500
$ 54,405
Phase V
Tasks I, II, III -
Application Guidelines
631 Engineer (1,000 hrs.)
Computer
Air Travel
.12,300
1,000
500
13,800
Total Direct Cost & Overhead
G & A @ 4%
Total Estimated Cost
Fee @ 7 1/2%
Grand Total Estimated Cost & Fee
$673,587
26,943
700,530
52.540
$753.070
-------
-159-
i- CGriYKACT f-P.iClKG P.1CPCSAL "-ir.'. »:«/;/*
1 < I . i ocucJ y i
jK*mc. »...!.«.
COMBUSTION ENGINEERING, INC.
1000 Prospect Hill Road
•. Windsor, Conn. 06095
aw&VHA) A.S.I IOCA>P.N;M vyiiCRt wot < 15 TO nt nslQMZp
Windsor, Ct. , uiattanooga, Venn.,
t <;r touts. Mo.. Mononeahela, Pa.
i DETAIL FJiCSCaiPTiO.'j
f c«mr«ciinf, dlTiccf.
t*ACC KO* j NO. (/^ f AO{«
l^i^ni'^r^^ial'T Labor to modify
existing Boiler, Engineers 5 Technicians 1
investigate Combustion Modification Techn
for NOX Control by adding Flue Gas Recirc
IOTAI AMOUNi or cr.oroiM covt ioucuMir.H HO.
t 1.093,487.00 EPA 68-02-0264
or- CO;T E'.?;.\i->r;s
1. O.UCT MAUCIM (llt'iiit UK F.vliibil A)
a. CU'ClIM!;) PAK1J
i h. SUuCOUTH/.ttCfl ITCMi '
I. KIIUR.-I'I; f<>w M/.USIAI
j f;> VOUS »TAN3AKO COMttCilClAl IT((AS
j r.i; iN-.iOn-iMOi«l U/j-IJfCai M/ •/*/•• //../» <•>!)
| TOTAL niKF.C.T MATfMIAI.
tr.i COST ff ;
150,370
167,075
48,463
TOT/.I lErtu.
1ST COST' £HCE»
' /'/ '.' J . '.' ; 1
• .' ' ••';• " |
••'.":••• .|
•'-•••• ' •!
*• '•'-.- >•"•'!
W". ">-.! 374,9081
». MA-.UIAI niy-n:*o> r»...v V..YJ *-«=;
J. PISECT IA1C'- fSfrsi'/y)
CSTIMATtO RAYf/
MOUKi HOUR
Sec Attachment No. 1
7'0r/!/. niKlifT LATiOK
t, lAtO.". O'.'t'1-..O fSlnti/y l)i/-jrlniiHt »r Cut Ceutrr)'
tiT
CO.M r*;
• * '
.. * ,. s
• i
... .. >/ i
''.'!
""."-'' .' '1 ••— —
.. . • "
. ..v- •••.•<;••-. •>.. .>..;•;.:•:•>'••.! ...... •• - .: -131:7 403 1
*••'... • ; .s .- | • * l. .••••••- i *• : " | «?.} / , H^ ^ f
O.K. RAi'c XkASCn
Sec Attachment No. 1
TOTAL LAtlOK OW.miF.AI) >'.
tsi con rs; -.-'•'•:. : j
•:...-. ••'',:?:•:• '.;
•:'- '" •.:'•.: •'••.•'.!
'.,:. . . • '
y.y^V^.^rr^-N.lC::/"; » .i->;.: .v-<-'V;; •'. 191 ,038
5. STtCiAl Itli"O ( /.if/»ii/.'i.v /i././ irj'* \-.!|
•;'!-s' ••:.': '.-v |
^-,. -;=..-:
••V: ';.': •.'.:•!: •'•/!
:•. liTCi/.l Uiui'MidT (If iH'Hl ihaigt) (HtMiit »n H-Mliil A)
7. I«.»v;i (If itiritt thurftt (fiirt t/tl.li't ••• allntl'tj Xtlittfull)
it. TkVKjVO.'l/.'ICN
i. PLS rul..'. 0:1 !ur.;:<.7f:.CE
J
t. COMOi-A>lfr. tl,:rurf*it- rttt /
TOTAL TKAVVL
TOTAL C.OSWl.TAXrS
ISf CO! I f f )
20,953
22,272
.••'•'"..•''.' :">
• ".'••' > *' . . * *
-. ;;- '•;.''..:••••,• /.-I A-I ood
CSTCOM r«y
VV.V^: .'i •''.'.
9. OtrtlC Ul»»°.i COiH ttl,~ti;t •« P.\liilt!l At
ic. ro-i.ii. DIRECT COST AND OVI-KHI!.AI>
•,i.
1 4. ft I OS I'iOfll
TOTAI.KfriMATF.lt COST
" - ' ' ; • • .*. ' '
.-'•':• ' ' *
', ;/.'•• :•» . 1
11.480 '
978,074
39.123
1017,197
76 ''OO'
»i. ror/it tnv.'it.i7-;.'o coiT /i.vo «!i< OK j»«»wr 11095 , 4871
•
OM'I'iONAL IXXiM 60
to
ique
onl
:
I
!
1
i
I
1970
r;--a MC
&OCO-101
-------
-160-
::.I'A Coiuract oS-02-0264 -
.;. R. i;. Swone
Contract Admi nistrator
Cor.ibusti on Engineering, Inc.
SluHAIUU
November (J , 197:
w/Cl'li.-.'.Ii A— oUrTCRTli^G SCiicDULG (Specify. If inn re sfnicc if needed. ;/jr re resit)
cos: i\ NO. ; ITEM DESCRIPTION
la 'Insulation
la Gas Rocirc. I:an
(Set /oaliio.'t }) | CST COL; /";/
21,850 I
73.VJ2 [
Ja 'Gas Rccirc. I- an Motor • 42, 'J98
3 a Controls
20.940 159.370
Ib (.Setting. Insulation § Lagging Erection Equip. 25,000
•.N iSottintr. Insulation § Laccint? Erection Labor . 88,130
Ib I.Metal liroction Equip. Rental, Tools, Consumables 53,945 167,075
Ic iPuctwovk
Ic 'Gates 'i Dampers
ic Structural Steel
/a freight 9113 Car Rental bOOO Air
9 Insurance
9 IComputer
9 i.Misc. Material
i
t
20,274
16,948
11,241 48,465
1'ravel 5840 20,955 ,
1,650
8,600
1,250 11,480
(
•
i
.
i
! j
t
1
^ i. it/-: ANY E*:ai:iv£ .\r.t.\cY or nit UNITFO MAVCJ GOVERNMENT rtr.rof.MO ANY REVIEW or voua ACCOUNTS oc RECORDS IN coNNiCTioi: WUH AUV OT *- •
; COVtkNMiNT IK'.i/.i CONTRACT OR SU2CONTRACT WITHIN THE PAST TWELVE MONTHS?
i S Y£s D N0 (If )». iJtitlify Mtu-.)
NX.MC A/>'l) X.DOvCii Of SCV;£-V.INC O'flCt At;0 INJIVIDUAl ' UltPMONt NJMOCr./lk'fNiiON
i ATOMIC ENERGY COMMISSION, CHICAGO OPERATIONS OFFICE
. ii. v/kL VOii JEO'JKE Tut UU£ Of ANY COVi KNMfN? rKOrtBlY IN THf. ?f.S?O(i/.UNCE Or THIS K8OPOS£0 CONTRACT?
1 j Y£i [XJ i>'O (If f>i. iJtntif) vn rtrrnr er ttparatt )>"$')
a. oc vo'j r.cCri.'ur oovuN/.\tui CONTACT TINANCING TO PERFORM MIS PROPOSED COKKUCT?
(~~1 YCS PS NO f If yu. Minify.) ! (~] ADVANCE PAYMENTS Q MOCSCSS PAYWZNTS OR Q CUARANTf SO LOANi
1 IV. 00 Y::L« sov/ KV»io ANY CONTRACT fOr. n? |
[Xj VIS P| NO llf /.«. r;fl*in tn rtfirn tr itfuriilt p*ft) . ;
-------
-161-
EPA CONTRACT 6S-02-0264
CE CONTRACT NO. 6472
Gas Recirculation System Only
OPTIONAL FORM 60
November 9, 1972
Attachment No. 1
COST ELEMENT
DEPT.
611 Eng.
651 Eng.
651 Tech.
516 Eng.
6S5 Eng.
6S5 Tech.
652 Service
641 Erection
Shop Labor
#3 DIRECT
EST. HRS.
6,200
3,940
1,340
490
65
300
560
1,240
6,308
or 30,305
LABOR
RATE/HR.
5.35
6.60
4.85
8.60
7.55
4.75
6.55
8.15
5.05
7.92
EST. COST
33,120
26,066
6,483
4,214
492
1,425
3,676
10,076
31,855
240,016
#4 LABOR OVERHEAD
357.423
OH RATE
90
95
95
75
160
160
111
108
164
24
EST. COST
29,810
24,760
6,160
3,161
785
2,280
4,080
10,880
52,149
56,973
191,038
-------
-162-
Page 1
November 9, 1972
Attachment No. 2
EPA CONTRACT 6S-02-0264
CE CONTRACT NO. 6472
Gas Rocirculation System Only. Based on Estimated 1974 Costs.
PHASE II
Task I Detail 5 Design
631 Eng. 40 hrs.
611 Eng. 6200 hrs.
Task II Purchase $ Fabricate
Raw Material $ Shop Fab.
Purchased Material
Insurance
Task III Install Instrucments, Baseline Tests
Gas Rccirc.
PHASE III
Task I Deliver Equipment § Modify Unit
651 Eng. 80 hrs.
Material
Field Expenses '
Car Rental
Air.Travel
Freight
Erect. Equip., Tools, Material § Consumables
Insurance
Field Labor
50505 hrs.
7000 hrs.
Metal
S.I.L.
641 Erector 1240 hrs.
Task II Final Test Preparation § Schedule
651 Eng.
651 Tech
Material
Freight
Field Expense
Car Rental
Air Travel
120 hrs.
60 hrs.
516
62,930
132,467
159,370
630
1,032
500
3,872
200
200
8,513
78,945
1,000
296,989
88,150
20,956
1,548
547
250
100
550
200
200
63,446
292,467
500,337
3,395
-------
-163-
Page 2
Gas Recirc.
PHASE IV
Task I Perform Unit Tests
Attachment No. 2
1120 hrs.
1280"hrs.
Eng. 560 hrs.
631 Eng.
651 Tech.
632 Serv.
Material
Field Expenses
Car Rental
Air Travel
Task II Data Analysis
631 Eng.
516 Eng.
6S3 Eng.
6S3 Tech.
Computer
Freight
Air Travel
2080 hrs.
490 hrs.
65 hrs.
300 hrs.
Gas Recirc.
PHASE V
Tasks I, II §' III Application Guidelines
631 Eng. 500 hrs.
Computer
Air Travel
TOTAL DIRECT COST & OVERHEAD
G&A @4%
TOTAL ESTIMATED COST
FEE @7-l/2?5
GRAND TOTAL ESTIMATED COST & FEE
14,448
12,096
7,756
500
17,850
5,600
4,440
26,832
7,375
1,277
3,705
8,100
500
500
6,450
500
500
62,690
48,289
7,450
$ 978,074
39,125
$1,071,197
76.290
$1.093.487
-------
-165-
CONTKACT PRICING PROPOSAL
(RESEARCH AHD DE11:U>PMEN7V
Hud);'i Hurem
Approval ;\'o.
29-ROIH:
Thi, foim h fcf UM whco ft) mbai'iiim «f von M prktea *>« (M« FPR l-t.SO?-)) ft nqulnd t*t
fti) i«h«citiitian for the eptioml Form 19 It tMkoiiMd by th» (onir*ctln| offim.
PACCKO.
NCI. (A tAO»
MAMI or ootaoi
COMBUSTION ENGINEERING, INC
1000 Prospect Hill Road
Windsor, Connecticut 06095
wmitt Mo;-< or- CC:T £t%..*:>ji
EPA 68-02-0264
I. DUCT MATIMAI (lltmhl M f.rkiHt A)
.'o r**rs
I. Olllllt-fi; »»W MATltlAl
HI VOUI tUN3A«OCO'U-.IKUl ITIMS
M-.ciM\niOM.u llAMirm (At titrr th*m mt)
TOTAL
fM COST (!)
37,082
21,245
8.809
TOTAI
t$T COST'
;*••*'•••• •. —•
rrr^~'"' 6T,136
>. MAtlt'At tUl
%.VI
tins-
IHCI'
. tMtKI UtO
See Attach, fl
niairr LAHOR
See Attach. No. Iron/. MBOA
CtTIMATtD
HOUli
r/.vr/
HOW
cos>
OH.
ikAM- isi con t-:>
TOT/II. irccM/. n.«n.vc
ft. iff cm >om>Mirn nj •'•••ni «*..-i..:»/ (l:t~in< •» E>
10.
rov.if. n/RCCT corr *.v/j nri-c
II.
8.2%
7,^75
66,800
30.078
13.
TOTAL KtTIMATF.0 COST 196,878
14. KI o* riorn
29,766
is.
tSTMATiito COST ASK HF.k UK PKDFIT +26 j 64^4. __
OP.TiONAL i'OMM CO
•Mty 1970
"tV-ii-iol Ser»i>:«ii Aiimlnintrul-011
-------
-166-
ThU pmpoul it li.b nitttU for Hit <• connection vith and IB ftlponn to fDmcrflv KFP. m.)
EPA Contract 68-02-0264
•nd rrfleni our twit rtrfmiiti «i of ifiii ilttr, ia •crutilanec whh the Innrvnloni 10 OStrori «nd (hi Footnom which follow.
TTWJ NAMt AND irtU
R. F. Swope •
Contract Administrator
1 SKUUTUB
'
MAJW c* r«M
COMBUSTION ENGINEERING, INC.
OATI « EMISSION
April 19, 1973
COST El NC.
EXHIBIT A-SUPPORTING SCHEDULE (Specify. If mart tpatt it needed, utt rtvcnt)
fTTM OESCHIPTION (Sri feetnett ))
ESTCOSl (S)
la
Insulation
1,995
la
Controls
2,152
la
Instrumentation
32,935
37,082
Ib
Setting, Insulation & Lagging
Erection Equip.
2,359
Ib
Setting, Insulation & Lagging
Erect-inn Labor
ft 4Rfi
Ib
Metal Erection Kqiiip. Tten-hal f Tnnl ) f>nj,tt,)fOK Till JAMt Cil SIMIIAI WOitr. CAlliS tU?. VI lie!
O «* Quo', ff/'jn. iV/Mh/V./:
V. DOCS ''tlS COSI MJMMAftV CONFORM Wild trtl COST tHNCIPUS Sfl FO«TM IN AOfrKt IECUUJIONS?
Sit Kittnt ftr Imttrurthfi tmi Fittiulti
OF
O
-------
-167-
Optional Form 60
Attachment No. 1
April 19, 1973
OVERFIRE AIR SYSTEM ONLY
Cost Element
Dept. Est.
611 Eng. 2
631 Eng.
631 Tech.
Shop 2
Cost Element
Dept. Est.
Estimated
1973 Costs
#3 Direct Labor
Hours
,030
240
520
,513
Rate/Hr.
$5.10
6.20
4.45
4.66
Estimated
Est. Cost
$10,353
1,494
2,308
11,700
$25,855
1974 Costs
#3 Direct Labor
Hours
631 Eng. 5,320
631 Tech. 1,880
683 Eng. 470
683 Tech. 1,170
516 Eng. 500
632 Service 660
641 Erector 256
Metal Erection6,520
1973 Estimated
Total
Rate/Hr.
$6.50
4.65
7.30
4.70
8.50
6.70
7.90
7.49
Costs
Est. Cost
$34,536
8,730
3,430
5,485
4,250
4,432
2,022
48,835
$111,720
25,855
$137,575
#4 Labor Overhead
O.K. Rate Est. Cost
104
89.5
89.5
166
$10,759
1,338
2,060
19,414
$33,571
#4 Labor Overhead
O.K. Rate Est. Cost
89.
89.
159
159
68
110
112
29
$30,900
7,814
5,454
8,730
2,900
4,874
2,266
14,279
$77,279
33,571
$110,788
-------
-168-
Optional Form 60
Attachment No. 2
April 19, 1973
OVERFIRE AIR SYSTEM ONLY
Based on Estimated 1973 Costs
The figures following for Tasks I, II and III are based on estimated
1973 costs. Task II fabrication costs, are in effect until 8/74.
All other tasks are based on estimated 1974 costs.
Task I - Detail & Design
631 Engineer (80 hrs.)
611 Engineer (2,030 hrs.)
$ 944
21,112
$22,056
Task II - Purchase & Fabricate
631 Engineer (40 hrs.)
631 Technician (280 hrs.)
Raw Material & Shop Fab.
Purchased Material
Insurance
$ 472
2,352
39,923
37,082
175
$80,004
Task III - Install Test Equipment
631 Engineer (120 hrs.)
631 Technician (240 hrs.)
Material
Freight
Field Expenses
Car Rental
Air Travel
$ 1,416
2,016
1,000
400
2,200
750
600
$ 8,382
Task IV - Baseline Tests (Load & Ex. Air)
631 Engineer (480 hrs.) $ 5,904
631 Technician (280 hrs.) 2,464
683 Engineer (75 hrs.) 1,418
683 Technician (210 hrs.) 2,551
Service Engineer (80 hrs.) 1,128
Computer 1,000
Field Expenses 3,400
Car Rental 2,500
Air Travel 800
$21,165
-------
-169-
Task V - Baseline Tests (Bias Firing)
631 Engineer (480 hrs.) $ 5,904
631 Technicians (280 hrs.) 2,464
683 Engineer (75 hrs.) 1,418
683 Technicians (210 hrs) 2,551
Service Engineer (80 hrs.) 1,128
Computer 1,000
Field Expenses 3,400
Car Rental 2,500
Air Travel 1,200
$21,565
Task VI - Deliver Equipment & Modify Unit
Material $ 500
Freight 1,526
Erect. Equip. Rental, Tools,
Material & Consumables 12,759
Insurance 1,000
Field Labor
Metal (6,520 hrs.) 63,114
Set. Insul. & Lag. (674 hrs.) .8,486
641 Erection Rep. (256 hrs.) 4,288
$91,673
Task VII - Final Test Preparation & Schedule
631 Engineer (40 hrs.)
631 Technician (120 hrs.)
Material
Freight
Field Expense
Car Rental
Air Travel
$ 492
1,056
500
200
1,000
750
400
$ 4,398
Task VIII - Perform Unit Tests & Analyze Data
631 Engineer (3,280 hrs.)
631 Technician (1,200 hrs.)
683 Engineer (320 hrs.)
683 Technician (750 hrs.)
516 Engineer (500 hrs.)
Service Engineer (500 hrs.)
Material
Field Expenses
Car Rental
Air Travel
$40,344
10,560
6,048
9,113
7,150
7,050
1,500
11,500
7,000
3,000
$103,265
-------
-170-
Task IX - Application Guidelines
631 Engineer (1040 hrs.)
Computer
Air Travel
Field Expense
Total Direct Cost & Overhead
G&A @ 8.2%
Total Estimated Cost
Fee @ 7.5%
Grand Total Estimated Cost & Fee
$12,792
600
600
300
$14,292
$366,805
30,078
396,878
29,766
$426,644
-------
-171-
Optional Form 60
Attachment No. 3
April 19, 1973
Cost Element
OVERFIRE AIR SYSTEM ONLY
Metric System Option
#3 Direct Labor
#4 Labor Overhead
Dept.
Est. Hours Rate/Hr. Est. Cost O.K. Rate Est. Cost
611 Eng.
631 Eng.
516 Eng.
600
300
50
$5.10*
6.50**
8.50**
$3,060
1,950
425
104
89.5
68
$5,435
$3,180
1,740
290
$5,210
* 1973 Estimated Costs;Task I
**1974 Estimated Costs;Task VIII 300 hours,Task IX 50 hours
Total Direct Cost & Overhead
G&A @ 8.2%
Total Estimated Cost
Fee § 7.5%
Grand Total Estimated Cost & Fee
$10,645
873
$11,518
864
$12,382
Combustion Engineering will use International Systems of Units
(SI) per ASTM E-370-70, Metric Practice Guide. Arrangement and
shop detail drawings will utilize a dual dimensioning system,
i.e., U.S. customary units and SI units.
-------
-172-
OVERFIRE AIR SYSTEM ONLY
1974 Costs
Cost for each additional type of coal tested.
Optional Form 60
Attachment No. 4
April 19, 1973
Cost Element
Dept.
631 Eng.
631 Tech.
1160
520
#3 Direct Labor
#4 Labor Overhead
Est. Hours Rate/Hr. Est. Cost O.K. Rate Est. Cost
$6.50
4.65
$7,530
2,416
$9,946
89.5
89.5
$6,738
2,160
$8,898
Total Direct Cost & Overhead
G&A @ 8.2%
Total Estimated Cost
Fee @ 7.5%
Grand Total Estimated Cost & Fee Per Test
$18,844
1,545
$20,389
1,529
$21,918
-------
-173-
.SECTION VI
ATTACHMENT V
COMBUSTION TECHNIQUE APPLICATION STUDY
-------
-175-
NOX Emission Control Technique
Cost Ranges for Existing and New
Steam Generators
PILOT FIELD TEST PROGRAM TO STUDY
METHODS FOR REDUCTION OF NOX FORMATION IN
TANGENTIALLY COAL FIRED STEAM GENERATING UNITS
PREPARED FOR
THE ENVIRONMENTAL PROTECTION AGENCY
RESEARCH TRIANGLE PARK
NORTH CAROLINA 27711
April 4, 1973
Combustion Engineering, Inc.
1000 Prospect Hill Road
Windsor, Connecticut 06095
(203) 588-1911
-------
-177-
Table of Contents
1.0 Summary . Page 179
2.0 Conclusions 179
3.0 Discussion 180
3.1 Control Method Selection 180
3.2 Economic Evaluation 181
3.3 Detailed System Design Evaluation 181
3.3.1 New Units 182
3.3.2 Existing Units 183
Gas Recirculation and Figure 1A 185
Overfire Air Duct System " IB 186
1C 187
Costs of NOX Control Methods
New Coal Fired Units Figure 2 188
Costs of NOX Control Methods
Existing Coal Fired Units Figure 3 189
-------
-179-
1.0 SUMMARY
This report has been prepared in accordance with the requirements of
Phase I, Task 4 of EPA Contract 68-02-0264. The design and economic
evaluations expressed are based on Combustion Engineering, Inc.'s
current knowledge and the cost estimates generated for the modification
of Alabama Power Company, Barry Station No. 1 developed under Phase 1,
Task 3 of Contract 68-02-0264.
Specifically, this report evaluates four possible methods of reducing
NOX emission levels from tangentially coal fired steam generators and
estimates the cost trends for each method on both new and existing units.
The reduction methods considered include overfire air, gas recirculation
to the secondary air ducts and coal pulverizer/primary air system and
furnace water injection. The cost trends for these methods are projected
over a unit size range of 125 to 750 MW. Figures 1A, IB and 1C illustrate
the application of the gas recirculation and overfire air systems on
an existing unit.
The results of the study indicate that for any given unit size (450 MW
chosen for an example comparison) the lowest cost method is found to be
overfire air which results in a .14 to .50 $/KW additional unit cost
for a new or existing unit respectively.
This method incurs no loss in unit efficiency or increased operating
expenses.
Gas recirculation introduced either through the secondary air ducts or the
coal pulverizers and primary transport air system results in higher
equipment costs than overfire air and requires additional power for fan
operation.
Water injection introduced into the fuel firing zone of the unit is
attractive from the standpoint of lower initial equipment costs, however,
losses in unit efficiency resulting in increased fuel costs and significant
water consumption make it the most expensive system to operate.
The use of either gas recirculation or water injection in existing units
could result in a 10 to 20 percent decrease in load capability due to
increased gas flow weights.
This represents a significant increase in unit capital .cost per MW
in addition to the cost of the modification. For example, a unit
originally costing 300 $/KW operating at 80 percent load is actually
costing 375 $/KW. Therefore, when modifying existing units gas recircu-
lation rates greater than 15 percent do not seem practical.
2.6 CONCLUSIONS
1. The lowest cost method for reducing NO emission levels on new and
existing units is the incorporation of an overfire air system.
No additional operating costs are involved.
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2. Gas Recirculation either to the windbox or coal pulverizers is
a promising control system but is significantly more costly
than overfire air and requires additional fan power. In existing
units, the necessity to reduce unit capacity to maintain acceptable
gas velocities imposes an additional penalty.
3. Gas recirculation to the coal pulverizers would cost approximately
15% less than windbox gas recirculation, however, this method
may require increased excess air to maintain adequate combustion.
4. Water injection has initially low equipment costs, but due to
high operating costs resulting from losses in unit efficiency,
is the least desirable of the systems evaluated. This system
may also require reduced unit capacity.
5. In general, the cost of applying any of the control methods studied
to an existing unit is approximately twice that of a new unit design.
3.0 DISCUSSION
3.1 Control Method Selection
The following five modes of unit operation were chosen as potentially
effective means for reduction of NOX emissions from coal fired utility
boilers.
The quantities of overfire air, gas recirculation and water injection
selected for the economic evaluation, while reasonable, do not necessarily
represent commercially feasible operation or control methods which would
be recommended by Combustion Engineering, Inc.
1. Introducing 20 percent of the total combustion air over
the fuel firing zone as overfire air.
2. Introducing 30 percent flue gas recirculation through
the secondary air ducts and windbox compartments.
3. Combining the 20 percent overfire air and 30 percent
flue gas recirculation of 1 and 2.
4. Introducing 17 percent flue gas recirculation through
the transport air/coal pulverizer system.
5. Introducing water injection into the fuel firing zone at
a rate of 5 percent of total evaporation.
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3.2 Economic Evaluation
Economic comparisons of the five NO emission control methods are
based on 1973 delivered and erected costs for the steam generators
and associated equipment.
The cost estimates presented for the revision of existing units are
based on studies performed on units within the 125 to 750 MW size range
including those costs generated under Phase I, Task 3 for the Barry No. 1
unit. The cost estimates presented for incorporating control methods
in new unit designs are based on Combustion Engineering experience
and current practice for overfire air and gas recirculation systems.
These cost ranges are shown on Figures 2 and 3.
As can be seen from these figures the cost ranges for existing units
vary more widely than new units. This is due mainly to variations
in unit design and construction which either hinder or aid the installa-
tion of a given control system. For example, an overfire air system
may be designed as a windbox extension unless existing structural
requirements and obstructions necessitate installation of a more
costly system including extensive ductwork and individual air
injection ports. The same condition exists for water injection systems
when the need to maintain unit capacity dictates changes in unit
ducting. Except where noted all system costs are estimated on a +_ 10 percent
basis. The cost range of the combined overfire air and windbox gas
recirculation system was arrived at as the sum of the cost ranges of
the individual systems. The cost ranges presented for existing
units do not include any changes to heating surface as these changes
must be calculated on an individual unit basis. Due to variations
in existing designs, heating surfaces may increase, decrease or remain
unchanged for a given control method.
At approximately 600 MW, single cell fired furnaces reach a practical
size limit and divided furnace designs are employed. Since a divided
tangentially fired furnace has double the firing corners of a single
cell furnace, the costs of windboxes and ducts increase significantly
as shown on figures 2 and 3. As shown, the costs of overfire air,
windbox gas recirculation and windbox water injection increase from
30 to 50%.
3.3. DETAILED SYSTEM DESIGN EVALUATION
For the purpose of illustrating the effects on unit design of Incorporating
the NO control systems, a base unit is chosen. This ba.se unit is then
evaluated with respect to control system requirements both, as a new and an
existing design.
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3.3.1 - New Units
3.3.1 - 1. Overfire Air System
This system provides for the introduction of 20 percent of the total
combustion air through overfire air compartments which are designed
as windbox compartment extensions. An extra 1.5 inches WG static head
is included in the forced draft fan selection for flow distribution
thereby increasing fan size. No other design changes from the base
unit are required and the boiler efficiency is unchanged.
3.3.1 - 2. Flue Gas Recirculation Through the Secondary Air Duct and
Windbox Compartments
The addition of 30 percent flue gas recirculation to the combustion
air'in the secondary air ducting and windbox will result in increasing
duct, windbox and unit convective pass size. Superheat and reheater
heating surface will decrease while economizer heating surface increases.
Additional gas recirculation ductwork, gas recirculation fans and dust
collectors for fan protection must be provided. The unit efficiency
remains unchanged, however, an additional auxiliary power requirement
will be incurred to operate the gas recirculation fans.
3.3.1 - 3. Combination Overfire Air and Secondary Air Duct Gas Recirculation
The combination of Methods 1 and 2 results in a combination of the changes
noted for the individual methods. No additional changes should be required.
3.3.1 - 4. Flue Gas Recirculation to the Transport Air/Coal Pulverizer
System
Introduction of recirculated flue gas in place of air to the coal
pulverizers will permit approximately 17 percent of the total gas weight
to be recirculated at maximum continuous unit rating. Tempering is provided
by having the gas fan inlet ducts drawing suction at both the hot and cold gas
sides of the air preheater.
This control method requires that larger windboxes, additional gas recircu-
lation ductwork, gas recirculation fans and dust collectors for fan pro-
tection be provided.
The boiler efficiency remains unchanged from the base unit, however, an
additional auxiliary power requirement has been incurred to operate the
gas recirculation fans. The gas recirculation fans would replace the
primary air fans and the forced draft fan size would, therefore, have
to be increased to provide the necessary combustion air. Coal pulverizer
design and performance would remain unchanged.
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3.3.1 - 5. Hater Injection to the Firing Zone
Injection of spray water into the unit firing zone at a rate of 5 percent
of boiler steam capacity will result in increased excess air requirements
to insure proper fuel combustion, and a decrease in boiler efficiency
of approximately 5 percent due to the increased excess air requirement
and higher moisture losses. This injection rate is equivalent to 0.5
pounds of water per pound of coal fired and would be introduced through
individual water nozzles located in the air compartments between each
coal nozzle.
Due to the reduced unit efficiency, water injection and increased excess
air, the flue gas mass flow increases by approximately 13 percent.
With the furnace size remaining the same as the base unit, a larger
convection pass results with decreased superheater and reheater heating
surface and increased economizer heating surface.
The air preheater size will also increase due to the increased gas flow
weight.
3.3.2 - Existing Units
3.3.2 - 1. Overfire Air System
This system provides for the introduction of 20 percent of the total
combustion air through overfire air compartments. Depending on unit
design these compartments can be fabricated as a windbox extension or
they might require more extensive ducting and separate compartments
due to structural requirements and interferences. Therefore, as shown
on Figure 2,the costs for installing an overfire air system on existing
units have considerably wider variation than for new unit designs. No
other design changes from the base unit are required and efficiency
remains unchanged.
3.3.2 - 2. Flue Gas Recirculation Through the Secondary Air Duct and
Windbox Compartment?
The addition of 30 percent gas recirculation to the combustion air in
the secondary air ducting and windbox will require the addition of a
complete gas recirculation system including fans, motors, dust collectors
for fan protection and ductwork in addition to enlarging windboxes.
Assuming that the convective pass velocities cannot exceed the original
units, 30 percent gas recirculation would restrict maximum unit loading
to 80 percent. Depending on unit design,convective pass heating surfaces
may have to be added or removed if fuel nozzle tilt and desuperheater
spray quantities are not adequate to maintain required steam temperatures.
The unit efficiency remains unchanged, however, an additional auxiliary
power requirement will be incurred to operate the gas recirculation fans.
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3.3.2 - 3. Combination Overfire Air and Secondary Air Duct Gas
Recireulation
The combination of Methods 1 and 2 results in a combination of the
changes noted for the individual methods. No additional changes should
be required.
3.3.2 - 4. Flue Gas Recirculation to the Transport Air/Coal Pulverizer
System
Introduction of recirculated flue gas in place of air to the coal pulver-
izers will permit approximately 17 percent of the total gas weight to be
recirculated at maximum continuous rating. Tempering is provided by having
the gas fan inlet ducts drawing suction at both the hot and cold sides of
the air preheater. This control method requires that more ductwork, gas
recirculation fans and dust collectors for fan protection be added to
the existing unit. The gas fans replace primary air fans and the forced
draft fans on some units would, therefore, have to be larger. Coal
pulverizer design and performance would remain unchanged.
However, to operate with the same convective pass velocities as the base
unit with 17 percent gas recirculation .maximum unit load would be restricted
to 85 percent of the base unit maximum load. At this reduced rating,
existing fan capacities should be sufficient. Depending on unit design,
convective pass heating surfaces may have to be added or removed if fuel
nozzle tilt and desuperheat spray quantities are not adequate to maintain
required steam temperatures.
The unit efficiency remains unchanged, however, an additional auxiliary power
requirement will be incurred to operate the gas recirculation fans.
3.3.2 - 5. Hater Injection to the Firing Zone
Injection of spray water into the unit firing zone at a rate of 5 percent
of boiler steam capacity will result in increased excess air requirements
to insure proper fuel combustion and a decrease in boiler efficiency of
approximately 5 percent due to the increased excess air requirement and
higher moisture losses. This injection rate is equivalent to 0.5 pounds
of water per pound of coal fired and would be introduced through individual
water nozzles located in the air compartments between each coal nozzle.
Due to the lower boiler efficiency, the water injected and the higher
excess air, the flue gas mass flow rate increases by 13 percent. Therefore,
to operate with base unit convective gas velocities and the 5 percent water
injection,load would be restricted to 90 percent of the base maximum
continuous rating. At this reduced rating, the existing fans should have
sufficient capacities.
Depending on unit design, convective pass heating surface might have
to be added or removed if fuel nozzle tilt and desuperheater spray quantities
are not sufficient to maintain required steam temperatures.
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GENERAL NOTES
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-188-
COSTS OF NOXCONTROL METHODS
NEW COAL FIRED UNITS
(INCLUDED IN INITIAL DESIGN)
DBOX GAS RECIRCULATION
RFIRE AIR
COMBINED
OVSRFIRE AIR AND WINDBOX
GAS RECIRCULATION
RECIRCULATION THRU
MILLS
UUALDBOX WATER INJECTION
200
300
400
500
600
700
800
UNIT SIZE
(MW)
FIGURE 2
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COSTS OF NOX CONTROL METHODS
EXISTING COAL FIRED UNITS
(HEATING SURFACE CHANGES NOT INCLUDED)
100
WINDBOX GAS RECIRCULATION
:RFIRE AIR
200
300
400
500
600
700
UNIT SIZE
(MW)
CON BINED
OVE1RFIRE AIR AND WINDBOX
RECIRCULATION
RECIRCULATION THRU MILLS
ER INJECTION INCLUDING FAN
$ DUCT CHANGES
iR INJECTION WITHOUT FAN
1DUCT CHANGES
800
FIGURE 3
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BIBLIOGRAPHIC DATA 1- Report No. 2.
SHEET EPA-650/2-73-005
4. Title and Subtitle
Program for Reduction of NOx from Tangential
Coal- Fired Boilers --Phase I
7. Author(s)
C.E. Blakeslee and A. P. Selker
9. Performing Organization Name and Address
Combustion Engineering, Inc.
1000 Prospect Hill Road
Windsor, Connecticut 06095
12. Sponsoring Organization Name and Address
EPA, Office of Research and Development
NERC-RTP, Control Systems Laboratory
Research Triangle Park, North Carolina 27711
3. Recipient's Accession No.
5. Report Dale
August 1973
6.
8. Performing Organization Rept.
No.
10. Project/Task/Worlc Unit No.
11. Contract/Grant No.
68-02-0264
13. Type of Report & Period
Covered
Phase I
14.
IS. Supplementary Notes
16. AbStractsThe report gives reSults of Phase I of a study to develop a pilot field-test
program to evaluate combustion modification techniques to reduce NOx emissions
from tangentially coal-fired steam-generating units. Alabama Power Co. (Barry
Station, unit I) is to be the test unit. The report includes details of the preliminary
test program, including analytical measurement and sampling techniques, engineering
drawings, cost estimates, and schedules. Phase n will require 24 months. Overfire
air is the least expensive technique for controlling NOx, incurring no loss in unit
efficiency or increased operating expenses. Flue gas re circulation is significantly
more costly, requires additional fan power, and (in existing units) could result in a
10-20% decrease in load capability due to increased gas flow weights. Water injection
into the fuel-firing zone has the lowest initial equipment cost; however, losses in unit
efficiency (resulting in increased fuel costs and significant water consumption) make
it the most expensive system to operate.
17. Key Words and Document Analysis. 17o. Descriptors
Air Pollution Coal
Nitrogen Oxides
Abatement
Combustion Control
Flue Gases
Circulation
Water Injection
Combustion Chambers
Economic Analysis
17b. Identificrs/Opcn-Ended Terms
NOx Reduction Air Pollution Control
Tangential Firing Stationary Sources
Combustion Modifications
Overfire Air
Flue Gas Recirculation
The cost of applying controls to existing
units generally is twice that of new units.
17c. COSAT1 Field/Group
21B
18. Availability Statement
Unlimited
19. Security Class (This
Report)
UNCLASSIFIED
20. Security Class (This
Page
UNCLASSIFIED
21. No. of Pages
195
22. Price
FORM NTIS-35 IREV. 3-72)
190
USCOMM-DC 14932-P72
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